Prepared for the Energy Efficiency and Conservation Authority
DISTRIBUTED GENERATION
A STUDY OF ALTERNATIVE ENERGY SUPPLY
OPTIONS FOR REMOTE COMMUNITIES
Prepared by
EMPOWER CONSULTANTS LTD
April 2008
A study of alternative energy supply options for remote communities
EECA has commissioned a report investigating how small scale electricity
generation (from 7 - 400kW) and energy management can provide an alternative
to traditional electricity lines supply in remote locations in New Zealand. The
report was prepared by Empower Consultants Ltd, John Duncan, independent
consultant, and Alpine Energy Ltd.
The report examines the potential for small scale generation and energy
management in five remote sites in South Canterbury. Technical information and
economic costs and benefits for a variety of options in each location are
presented.
The report illustrates that - with the right set of conditions - small scale
generation can be a viable alternative option for lines companies in the following
applications:
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It can replace an existing remote lines supply, particularly where:
o The line length is relatively long and dedicated to only one or two
consumers;
o The line is due for upgrade or replacement;
o Demand on the line is highly seasonal in nature (such as a holiday
home or woolshed);
o There is access to a high quality renewable resource; and
o The existing line is not capable of electricity export.
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It can improve the economic viability of an existing remote lines supply
by providing an additional revenue stream. This is where the existing line
provides access to an untapped high quality renewable resource and is
capable of exporting electricity to the wider network.
•
It can defer new investment in an existing remote line that needs
upgrading, for example, if demand on the line is increasing. This is likely
to be favoured where there is access to a high quality renewable resource.
•
It can also defer new investment in parts of a rural network
suffering unacceptable supply reliability due to seasonal demands.
Diesel only based systems are favoured in this application.
The report investigates small scale generation systems consisting of different
combinations of renewable and diesel generation plant. Where systems employ
renewable plant, backup diesel plant may be used to ensure a reliable supply of
electricity. In such cases, though, the diesel plant will only be operated for a
relatively short period of time.
The report also illustrates how energy efficiency and the use of alternative energy
sources (such as LPG or wood) can provide a means of reducing electricity
demand at a remote site. This can help reduce the size and capital cost of a small
scale generation system, where this is being considered, or may help defer new
investment where required for an existing lines supply. The report concludes that
the cost and convenience of some energy efficiency and alternative energy
sources does need to be considered carefully.
A Study Of Alternative Energy Supply Options For Remote Communities
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A STUDY OF ALTERNATIVE ENERGY SUPPLY OPTIONS FOR REMOTE
COMMUNITIES
EXECUTIVE SUMMARY
ƒ This study is part of EECA’s distributed generation cost-benefit analysis project which is aimed at improving
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understanding of the benefits and costs of distributed generation.
In this study, the electricity consumption and demand at four remote communities in South Canterbury are
analysed in order to establish the potential for distributed generation when considering both technical and
economic factors. The four sites are:
- Black Forest Station.
- Lochaber Station.
- Lilybank Station
- Stony Creek
Also studied is the use of distributed generation to provide voltage support in situations where short-term
seasonal demands could be more effectively met by the application of distributed generation.
All four sites are engaged in sheep farming. Two of the sites – Black Forest and Lilybank - also have tourist
facilities. At Lilybank, there are plans to undertake a major expansion of these facilities. Stony Creek is
essentially a woolshed with some accommodation for shearing gangs.
All four sites are reliant on electricity as the primary energy source to meet household and tourist
accommodation energy needs together with some use associated with farming activities.
In three of the four sites, opportunities exist to reduce electricity consumption by using woodfuel for heating,
LPG for cooking, solar water heaters and in one case, ground-source heat pumps. As noted above, the fourth
site - Stony Creek - comprises a shearing shed and is only used rarely with low power consumption and as a
consequence, energy management measures are unlikely to be cost-effective.
Lochaber and Lilybank Stations have good hydro-generation potential and this is evaluated. At Black Forest
where no hydro potential has been identified, wind-solar-diesel hybrid generation options are evaluated. At
Stony Creek where no hydro potential exists, it is concluded that wind-solar options are very unlikely to be
feasible owing to the high capital cost and the low electricity consumption: therefore diesel generation only is
evaluated.
An economic analysis is carried out using the national economic cost-benefit analysis methodology outlined in
the Treasury’s Cost Benefit Primer. Key results are as follows:
At Lilybank, both hydro generation and energy management measures show positive net present value
(NPV) primarily because these measures avoid the cost of upgrading/replacing the existing power
supply line which otherwise will be required once the proposed tourist facility expansion has been
completed.
In the cases of Black Forest and Lochaber, no line upgrades are required and the impact of the
reduction in maintenance costs that would result from disconnection of the line is outweighed by the
cost of the distributed generation plant.
However, at Lochaber where hydro generation may be possible and the existing line can be used to
export electricity from the distributed generation plant, a positive NPV is achieved.
At Stony Creek, when line maintenance costs are taken into account, a positive NPV is achieved when
using diesel owing to the low power consumption.
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A financial analysis carried out on the voltage support case study demonstrates that distributed generation
can provide a solution in situations where a lines company is faced with excessive voltage drop in rural
feeders owing to relatively infrequent seasonal power demand – such as for irrigation – and would otherwise
be faced with substantial line upgrade costs with no prospect of an adequate financial return on the
investment.
Conclusions are as follows:
The best opportunities for distributed generation exist where hydro-generation is possible and the
existing supply line is suitable for surplus power to be exported back to the grid.
In situations where long lengths of supply line in remote areas have to be replaced to meet increased
power demand or owing to storm damage, the economics of distributed generation will also improve
particularly where hydro-generation is possible. Other renewable energy resources, such as wind, may
also prove feasible where the resource is good.
In situations where a line supplies a consumer that uses only small amounts of electricity, distributed
generation can become favourable even with diesel generation compared with retaining the distribution
line.
Where infrequent periods of high demand occur and are resulting in unacceptable voltage drops,
distributed generation can provide a lines company with a cost-effective solution.
The adoption of energy management measures to reduce power demand and consumption is essential
where high capital cost distributed generation is proposed such as wind and solar PV generation.
Energy management can also offer the potential to avoid or reduce investment in upgraded power lines
or distributed generation.
In the case of new connections where the lines company is entitled to charge the consumer for the cost
of the new supply, distributed generation can provide an opportunity for significant cost-benefit to the
consumer. This will depend on a number of factors including, for example, the length of a new supply
line and the availability of adequate renewable energy resources.
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CONTENTS
1.
2.
3.
4.
INTRODUCTION
METHODOLOGY
CASE STUDIES – DESCRIPTIONS
3.1
Black Forest Station
3.1.1
Description
3.1.2
Electricity Supply
3.1.3
Electricity Consumption and Demand
3.2
Stony Creek
3.2.1
Description
3.2.2
Electricity Supply
3.2.3
Electricity Consumption and Demand
3.3
Lochaber Station
3.3.1
Description
3.3.2
Electricity Supply
3.3.3
Electricity Consumption and Demand
3.4
Lilybank Station
3.3.1
Description
3.3.2
Electricity Supply
3.3.3
Electricity Consumption and Demand
3.5
Voltage Support
CASE STUDIES – ANALYSIS
4.1
Electricity Demand
4.1.1
Demand estimates
4.1.2
Demand analysis
4.2
Electricity Supply Options
4.2.1
Available options
4.2.2
Continuation of existing supply
4.2.3
Distributed generation
4.3
Black Forest Station
4.3.1
Resources
4.3.2
Distributed generation options
4.4
Stony Creek
4.5
Lochaber Station
4.5.1
Resources
4.5.2
Distributed generation options
4.6
Lilybank Station
4.6.1
Resources
4.6.2
Distributed generation options
4.7
Voltage Support
4.7.1
Description
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4.8
5.0
6.0
7.0
Local Environmental Impacts
4.8.1
Air emissions
4.8.2
Water use
4.8.3
Noise
ECONOMIC ANALYSIS
5.1
Methodology
5.2
Assumptions and Costs
5.2.1
Value of avoided grid generation
5.2.2
Energy demand
5.2.3
Carbon dioxide emissions
5.2.4
Distribution system costs
5.2.5
Transmission costs
5.2.6
Fuel costs
5.2.7
Line losses
5.2.8
Value of Lost Load
5.3
Key Results
5.4
Sensitivity Analysis
COMMERCIAL CONSIDERATIONS – A LINES COMPANY PERSPECTIVE
6.1
The History
6.2
Regulation
6.3
Distributed Generation
6.3.1
The barriers
6.3.2
The opportunities
6.4
Conclusions
CONCLUSIONS
APPENDIX A
Outline of Methods Used and Assumptions made when allocating
Energy Use by Category at Each Site
APPENDIX B
Estimates of Impact of Energy Management Measures
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1.0
INTRODUCTION
This study is part of EECA’s distributed generation cost-benefit analysis project which “aims to improve
understanding of the ‘whole of economy’ benefits and costs of distributed generation”. This contributes to the New
Zealand Energy Efficiency and Conservation Strategy which includes an objective to:
Raise awareness of the benefits and costs of distributed generation – A programme will be established to raise
the awareness of the benefits of distributed generation, in particular small-scale generation, for end use by
consumers and local government, from late 2007. The programme will include providing information on potential
for distributed generation and advice to local government.
(New Zealand Energy Efficiency and Conservation Strategy, page 70)
The objective of this study is to:
Develop specific case studies looking at costs and benefits of DE in remote locations. This will provide
information for lines companies, electricity retailers and consumers in remote communities.
The study was carried out by Empower Consultants Ltd (ECL) in association with John Duncan, independent
consultant, and Alpine Energy Ltd (AEL), the electricity lines company supplying electricity to urban and rural
areas in South Canterbury.
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2.0
METHODOLOGY
In consultation with EECA, four remote communities were selected as case studies for this project. The sites were
initially identified by AEL as representative of many communities in rural South Canterbury. All sites are currently
supplied with electricity through lines owned and operated by AEL. The location of the four case study sites are
shown in Figure 1 over1.
For each site, the size and characteristics of the existing and projected electricity load in terms of consumption
and demand patterns was established with AEL using available or estimated data.
Energy demand and supply options were then identified using local knowledge and any available secondary data.
Supply and generation models were set up based on the available energy resources and current and projected
electricity use patterns. In each case, further models were developed assuming improved energy efficiency and
fuel switching.
The models were then evaluated in terms of installation and set-up costs and operating and maintenance costs.
The evaluations included:
1.
The cost of energy as delivered to the consumer based on an appropriate economic return on investment
and recovery of operating and maintenance costs. As well as the direct costs associated with distribution
systems and generating equipment, this will include:
ƒ the cost of alternative fuels where switching has taken place;
ƒ line losses where applicable.
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Changes in greenhouse gas emissions at the national level.
3.
Local environmental impacts in terms of air emissions and water use.
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Potential system vulnerability – ie ability to withstand severe weather conditions.
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Operational and economic impacts on the distribution system- these may be positive or negative.
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Operational issues such as access to remotely located plant.
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Assessment of behavioural issues and demand response to new technologies.
8.
Economic analysis of net benefits and costs from a national perspective using
Analysis Primer as a guideline.
3.0
CASE STUDIES - DESCRIPTIONS
Treasury’s Cost Benefit
Five case studies are analysed, these being located in South Canterbury and are supplied with electricity by AEL.
These include four sites - three high country stations and one remote shearing shed, located where shown in
Figure 1 - and a voltage support model. The four sites are described below.
All maps included as figures in this report contain data sourced from Land Information New Zealand (LINZ). LINZ gives no
warranty in relation to the data (including accuracy, reliability, completeness or suitability) and accepts no liability (including
without limitation, liability in negligence) for any loss, damage or costs relating any use of the data. Crown Copyright
Reserved.
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3.1
Black Forest Station
3.1.1
Description
Black Forest station is located alongside Lake Benmore (Figure 2) and is primarily a sheep station comprising a
house (six to eight occupants) and shearers’ quarters. In addition, there are three holiday cottages each capable
of accommodating up to 10 people. The holiday cottages are occupied mainly during the period December to
May.
The station is remote and the access roads and power line are subject to alpine weather conditions that make line
access and maintenance expensive and difficult at times and makes the line vulnerable to damage from bad
weather. Year-round access is difficult and by 4WD vehicles only via a low saddle through the Hakataramea
Pass.
3.1.2
Electricity supply
The station is supplied through a 63 km 22 kV single phase line from the Tekapo substation. The station is at the
end of the line which supplies 12 other consumers through 26 transformers, although the last 5 km section
supplies only Black Forest.
Load growth is not expected in the area supplied and AEL have no plans to upgrade the supply. 72 of the 342
poles are scheduled for replacement in 2009 as part of lifecycle maintenance.
3.1.3
Electricity consumption and demand
Using data obtained by AEL from the electricity retailer, quarterly2 consumption for 2007 is shown in Figure 3 and
annual consumptions for the period 2004 to 2007 are shown in Figure 4.
Electricity consumption during 2007 was significantly higher than in the previous three years. There is no obvious
explanation for this - such as additional buildings. Given that a similar situation has occurred at Lochaber Station,
climatic conditions may have had some influence.
No records are available in respect to maximum demand as only energy used (kWh) is metered. However, given
the combined rating of 45 kVA for the three transformers supplying the station, AEL have estimated the maximum
as being around 30 kVA. An analysis of the likely demand of the station indicates that this estimate is reasonable.
While electricity charges are invoiced on a monthly basis, meter readings are taken quarterly with intervening month
charges being estimates.
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Figure 3: Black Forest Station - Quarterly Electricity Consumption
during 2007
(sources: AEL and Contact Energy Ltd)
25000
CONSUMPTION KWH
20000
15000
10000
5000
0
JAN-MAR
APR-JUN
JUL-SEP
OCT-DEC
QUARTER
Figure 4:
Black Forest Station - Annual Electricity Consumption:
2004 to 2007
(sources: AEL and Contact Energy Ltd)
80000
CONSUMPTION KWH
70000
60000
50000
40000
30000
20000
10000
0
2004
2005
2006
2007
YEAR
3.2
Stony Creek
3.2.1
Description
Stony Creek comprises a woolshed and shearers’ quarters and is only occupied intermittently. Stony Creek is
located approximately 7 km to the northwest of Black Forest (Figure 5). Access is by means of FWD vehicles
using a track from Haldon Station.
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3.2.2
Electricity supply
The station is supplied by a 7.5 km single phase 22 kV spur line off the line supplying Black Forest. No load
growth is expected.
3.2.3
Electricity consumption and demand
Based on data obtained by AEL from the electricity retailer, quarterly consumption for 2007 is shown in Figure 6
and annual consumption for the years 2004 to 2007 in Figure 7. It is noted that while there has been a large
increase in annual consumption from 2004 to 2007, the increase is small in real terms – i.e. less than 400 kWh.
Figure 6: Stony Creek - Quarterly Electricity Consumption
during 2007
(sources: AEL and Contact Energy Ltd)
400
CONSUMPTION KWH
350
300
250
200
150
100
50
0
JAN-MAR
APR-JUN
JUL-SEP
OCT-DEC
QUARTER
Figure 7:
Stony Creek - Annual Electricity Consumption:
2004 to 2007
(sources: AEL and Contact Energy Ltd)
1200
CONSUMPTION KWH
1000
800
600
400
200
0
2004
2005
2006
2007
YEAR
No maximum demand data is available. Given that activities are likely to be limited to shearing and possibly
accommodation for shearing gangs, it is considered unlikely that demand is likely to exceed 5 to 10 kVA.
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3.3
Lochaber Station
3.3.1
Description
Lochaber station is located in rugged hill country approximately 20 km from Fairlie (Figure 8) and is a sheep
station comprising two house (six occupants total) and a woolshed with shearers’ quarters.
As with Black Forest, the station is remote and the power line is subject to alpine weather conditions that make
line access and maintenance difficult at times, expensive and vulnerable to damage from bad weather.
3.3.2
Electricity supply
The station is supplied through a 23 km 11 kV three phase line from the Fairlie substation. Four other stations are
supplied off this line through 15 transformers. Lochaber is the last station on the line with the next station (Blue
Mountains) located about 2 km from Lochaber.
Load growth is not expected in the area supplied and AEL have no plans to upgrade the supply which was
constructed in 1958. In 2000, major maintenance was carried out on the line and 81 poles were replaced.
3.3.3
Electricity consumption and demand
Based on data obtained by AEL from the electricity retailer, quarterly consumption for 2007 is shown in Figure 9.
Figure 9:
Lochaber Station - Quarterly Electricity Consumption
during 2007
(sources: AEL and Contact Energy Ltd)
30000
CONSUMPTION KWH
25000
20000
15000
10000
5000
0
JAN-MAR
APR-JUN
JUL-SEP
QUARTER
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As can be seen from Figure 9, there is a clear maximum in the quarter ending 30 September, most likely being
due to shearing taking place during this period. Unlike Black Forest, there is no holiday accommodation.
No maximum demand data is available. Given that activities are likely to be limited to shearing and possibly
accommodation for shearing gangs, it is considered unlikely that demand is likely to exceed 5 to 7 kVA.
Annual consumption for the years 2004 to 2007 is shown in Figure 10. Annual consumption increased in 2007 by
about the same proportion as was the case at Black Forest.
Figure 10:
Lochaber - Annual Electricity Consumption:
2004 to 2007
(sources: AEL and Contact Energy Ltd)
70000
CONSUMPTION KWH
60000
50000
40000
30000
20000
10000
0
2004
2005
2006
2007
YEAR
3.4
Lilybank Station
3.4.1
Description
Lilybank Station is a high country station at the head of Lake Tekapo. It is both a working sheep station and a
luxury tourist lodge with plans for further development including more accommodation and an 18 hole golf course.
At present, there are nine guest cottages with a further 12 planned together with expanded restaurant facilities.
The lodge is approximately 50 km from Tekapo village (Figure 11). Access can be difficult requiring several river
crossings.
3.4.2
Electricity supply
The lodge is supplied with electricity by means of a 35 km 22kV single phase overhead power line, requiring a mid
point voltage regulator to maintain supply quality. The braided river valley is prone to high flood conditions which
can at times threaten the overhead line structures. Four other stations are connected to the line. Lilybank is
located at the end of the line, 8 km from the next closest connection (Mt. Gerald Station).
The supply is already under some stress and at times of high demand, lodge staff have to manually switch off
load.
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FIGURE 11: LILYBANK STATION
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The proposed expansion of the facility will require replacement of much of the line with a three-phase supply
costing in the order of $1.4 to $1.6 million according to AEL. In addition, the lodge owners would like to install
substantial irrigation for the proposed golf course, the implications of which in terms of power supply requirements
are yet to be determined.
3.4.3
Electricity consumption and demand
Based on data obtained by AEL from the electricity retailer, electricity consumption in 2007 was approximately
212,000 kWh. Accurate quarterly consumption data was not available as according to meter records, actual
readings apparently have been taken at intervals of about nine months with intermediate month charges being
estimates. In some cases, the actual readings resulted in significant adjustment to correct for the previously
estimated readings.
Annual consumption data for previous years was not made available.
No recorded data is available in respect to maximum demand. It is estimated that this will be in the order of 65 to
70 kVA which is close to the rating of the transformer (75 kVA).
3.5
Voltage Support
Much of the electricity distribution system in rural South Canterbury was developed in the 1950s and 1960s and
was designed to supply a farming community that was predominantly engaged in arable and sheep farming. In
recent years, there has been significant conversion to dairy farming, a characteristic of which has been an
increased electricity demand associated with milk production and with irrigation.
While in most cases, the demand can be met from the system with some relatively minor investment, an
increasing problem has been the irrigation equipment demand during dry periods which has given rise to
excessive voltage drop particularly towards the end of long feeder lines. A further difficulty is that this situation
only occurs during very dry spells of no more that three months duration that historically have only occurred about
every three years.
For a lines company, demands of this kind are particularly troublesome as often the investment required to
upgrade a feeder line to meet such an infrequent demand far outweighs the increase in revenue that will be
achieved.
Distributed generation can provide a solution and AEL have carried out a study based on the use of a 400 kW
diesel generator set to avoid upgrading 14 km of line. The data used in this study has been updated in terms of
input costs and the results are discussed in the analysis section of this report.
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CASE STUDIES - ANALYSIS
4.1
Electricity Demand
4.1.1
Demand estimates
In order to gain an understanding of how electricity is currently used, electricity use for each of the three sheep
stations has been estimated for each different utilisation category, ie
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Farm accommodation.
Guest accommodation (Black Forest and Lilybank).
General farm use.
It is understood that all three stations have limited fuel supplies for cooking and heating in the event of electricity
supply loss during bad weather but as no information on historic usage is available, no allowance is made in the
demand estimates.
The estimates were made using the consumption profiles provided and (limited) information3 provided by the AEL
representative based in Tekapo. In the case of accommodation, the following methods were adopted:
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Space heating consumption - ALF 3.1 software4 using Tekapo as the climate reference point.
Hot water consumption – based on the number of occupants and estimated use for showers plus other
general uses.
Appliances and general power – based on data in Sustainable Building Sourcebook5 published by the
Waitakere City Council.
In one case – Lilybank Station – significant changes are planned for the near future which will increase electricity
demand and in this case, future demand projections have been made based on existing use. From discussions
with the Farm Manager at Lilybank, it is understood that the lodge facility will be a year-round operation and this
has been factored into the demand projections.
In the case of Stony Creek, it is understood that electricity is mainly used for farming activities but during shearing,
the building may also be used for shearer accommodation.
Little information is available on general farming electricity consumption. The farms are mainly involved in sheep
farming which is not as energy intensive as dairy farming. Typical uses include water pumping for stock drinking
water, shearing activities and general workshop purposes. Electricity demand during shearing includes power for
clippers and wool presses together with lighting – and possibly for shearing gang accommodation.
Table 1 sets out the results of the above analysis, details of which are provided in Appendices A and B. It is
stressed that the utilisation splits shown in Table 1 are based on very limited information and are a “best fit” using
the electricity consumption figures available and making allowances for varying occupancies that are understood
to occur (e.g. holiday periods and seasonal labour requirements). The figures in Table 1 are therefore indicative
only. The main purpose for deriving these figures is to provide a basis for investigating the potential energy
management measures discussed in Section 4.1.2 that follows.
This included number of buildings and occupants and in the case of guest accommodation, the months when the
accommodation is used.
4 ALF3- The Annual Loss Factor Method, 3rd edition, developed and owned by BRANZ
5 Kanuka-Fuchs,R. (c2005) “Household Appliances” in Sustainable Building Sourcebook, Waitakere City Council.
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Table 1: Breakdown of Electricity Consumption by Usage
BLACK FOREST
Farm staff accommodation
Holiday cottages
General farming activities
TOTAL
STONY CREEK
Shearing shed
TOTAL
LOCHABER
Farm staff accommodation (two houses)
General farming activities (shearing shed)
TOTAL
LILYBANK –existing
Lodge activities
Staff (farm and lodge) accommodation
General farming activities (shearing shed)
TOTAL
LILYBANK –future
Lodge activities
Staff (farm and lodge) accommodation
General farming activities (shearing shed)
4.1.2
Annual Consumption (2007) – kWh
Estimated maximum demand
kVA
38,000
25,000
8,150
71,150
15
10
7
30
1018
1,018
7
7
49,900
9,000
58,900
12
8
20
86,000
100,000
26,000
212,000
25
30
10
65
154,800
94,000
30,550
279,350
40
30
10
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Demand analysis
Based on the consumption figures and information from AEL, the three stations sites are relatively high users of
electricity with electricity being the major source of household energy. Other than some use of a coal range6 at
Lochaber, it is assumed that all household energy needs are met by electricity. In practice, it is possible and even
likely that wood stoves are used as well as electric heaters. It is appreciated that all sites are subject to low winter
temperatures which undoubtedly contribute to the high consumption figures.
Based on the assumption that electricity is predominantly used for space heating, opportunities to reduce
electricity consumption include:
ƒ Use of wood burners for space heating.
ƒ Installation of solar hot water panels.
ƒ Use of LPG for cooking.
ƒ Use of compact fluorescent lamps (CFL).
ƒ Ground source heat pumps7.
The use of wet-backs on wood burner stoves was considered as either an alternative to or in conjunction with
solar water heating. However, given uncertainties as to the acceptability of this option particularly during summer,
it was decided to assume solar hot water heating for the analysis.
Each of these identified options are analysed using the following assumptions:
(1)
(2)
Wood burner fuel consumption – 0.1 m3/100kWh of heat output8.
The use of solar water heating will reduce electricity consumption for hot water production by 75%9.
No information has been available on utilisation or coal consumption.
Given the very low temperatures likely in winter, the use of air-source heat pumps is not regarded as feasible.
8 East Harbour Management Service (2006) Microgeneration Potential in New Zealand - A Study of Small-scale Energy
Generation Potential. p 37.Report for the Parliamentary Commissioner for the Environment. Wellington.
9 ibid. Page 50
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(3)
(4)
(5)
(6)
(7)
(7)
(8)
(9)
LPG stoves have an efficiency of 50%10.
Use of CFLs will reduce lighting power consumption by 60%.
Wood fuel cost - $40 per cubic metre – this assumes that the wood will be cut from pine or similar
varieties on the property. The cost therefore represents labour plus allowance for fuel used.
LPG cost - $2.14 per kg. This is made up of $1.95 per kg for gas at Timaru or Fairlie plus $0.15 per kg
for 45 kg cylinder hire plus $0.04 for transport to farm. (Source: Nova LPG).
Diesel cost - $1.97 per litre. This is made up of $1.94 per litre for supply in drum plus $0.03 per litre for
transport to farm. (Source: BP New Zealand on 9 May 2008).
Wood burner – a cost of $2,750 installed is assumed8.
Solar water heater – costs of $7,500 to $8,000 are assumed based on information from suppliers. This
allows for a closed-loop system with glycol in the primary system to prevent freezing.
Ground source heat pumps – based on a discussion with Warmfloor Heating Systems, a figure of
$68,000 is assumed to provide heat pump and heated floors in all new and existing guest
accommodation units11 at Lilybank.
It is understood that with the exception of guest accommodation at Lilybank, the farm houses and accommodation
at the stations were built some years ago and insulation would not have been provided to walls, roof/ceiling or
floor. For the purposes of the analysis, it is assumed that given the widely known advantages of ceiling insulation
and relative ease of installation, this will have been retro-fitted.
In the case of Lilybank, it is assumed that existing guest accommodation will have been insulated to at least a
reasonable standard while new accommodation will be insulated as currently required by the New Zealand
Building Code.
Table 2 shows estimated energy savings while Table 3 sets out estimates of the costs of substitute fuels and
equipment. No estimates are provided in the case of Stony Creek given the limited use of this site and the nature
of the activities carried out. The figures for Lilybank assume that the proposed additions have been completed. A
breakdown of the impact of each electricity reduction measure is provided in Appendix B.
From Smith K et al (2000) Greenhouse Gases from Small-Scale Combustion Devices in Developing Countries: Phase IIA.
p 25. EPA/600/R-00/052. USEPA.
11 In the case of the 12 new units, this is the additional cost of heat pump floor heating over the cost of electric floor heating
that would otherwise be installed.
10
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Table 2:
Breakdown of estimated electricity consumption before and after implementation of
energy management measures (following proposed additions at Lilybank)
Existing
Annual
Consumption (2007) –
kWh
Consumption
following
Measures
Current
Estimated
maximum demand
kVA
Estimated maximum
following EM Measures
kVA
38,000
25,000
8,150
71,150
9,500
6,400
8,150
24,050
15
10
7
30
4
4
7
15
EM
BLACK FOREST
Farm staff accommodation
Holiday cottages
General farming activities
TOTALS
LOCHABER
Farm staff accommodation
General farming activities
TOTALS
LILYBANK
Guest accommodation.
49,900
9,000
58,900
9,942
9,000
18,942
12
7
20
3
7
10
154,800
127,6001
51,9002
50
251
152
Farm staff accommodation
General farming activities
TOTALS
94,000
30,550
279,350
14,100
30,500
172,2001
96,5002
15
10
75
8
10
401
352
Note 1: Without heat pumps
Note 2: With heat pumps
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A Study Of Alternative Energy Supply Options For Remote Communities
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Table 3:
SITE
BLACK FOREST
CONSUMPTION
FOLLOWING ENERGY
MANAGEMENT
kWh/year
Energy Management Measures – Substitute Fuel and Capital Costs Estimates
MAX DEMAND –
FOLLOWING ENERGY
MANAGEMENT
kVA
SUBSTITUTE FUELS
$ per annum
EQUIPMENT COSTS
WOODFUEL
LPG
SOLAR
WATER
HEATING
GROUND
SOURCE
HEAT
PUMPS
WOOD
STOVES
LPG
STOVES
CFLs
TOTAL
$60,350
24,050
15
$1,441
$2,026
$39,000
$13,750
$7,500
$100
LOCHABER
18,942
10
$523
$731
$15,000
$5,500
$3,000
$50
$23,550
LILYBANK1
172,2352
96,5003
$300
$121,0502
$189,0503
40
Notes:
(1) The estimates for Lilybank include allowance for proposed additions.
(2) Without heat pumps.
(3) With heat pumps
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$2,000
$4,378
$106,500
$68,0003
$8,250
$6,000
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4.2
Electricity Supply Options
4.2.1
Available options
Available options that will be considered include continuation of the existing supply arrangement and distributed
generation.
4.2.2
Continuation of existing supply
In the cases of Black Forest, Lochaber and Stony Creek, the existing electricity supply is regarded by AEL as
adequate to meet consumer needs for the foreseeable future.
In the case of Lilybank, the existing supply is already under stress and will not be capable of meeting the
electricity requirements of the expanded facility based on current utilisation. If future needs are to be met, one
option will be to replace the existing single phase 22 kV supply line with a three phase 22 kV line.
According to AEL, the likely cost of this option is in the order of $1.4 to $1.6 million. However, based on analysis
of existing and proposed consumption patterns, if energy management measures were to be implemented12, it
could be possible to reduce the maximum demand even after expansion to within the capacity of the existing
supply.
4.2.2
Distributed generation
In addition to diesel, the potential renewable energy resources that could be used for distributed generation
identified as available in the case study sites are:
ƒ Hydro-power.
ƒ Wind.
ƒ Solar.
ƒ Biomass (woodfuel).
While a biomass resource exist in the form of woodfuel, it is assumed that the use of this resource will be limited
to space heating and as noted above, this use is included as part of the energy management measures. The use
of woodfuel for electricity generation is not considered to be a practical option at this stage given the complexity –
and cost - of the technology.
Similarly, the generation of biogas to provide a fuel that could be used for electricity generation or directly as heat
source for space heating, hot water or cooking is not considered to be a feasible option at this stage on the
grounds that an adequate year-round supply of a suitable “feedstock” such as animal waste or soft biomass does
not exist.
The resources identified at each site are discussed below. It is important to note that for the purposes of the
analyses, assumptions are made in respect to the availability and quality of the identified renewable energy
resources. Before any decision to select and install plant could be made, appropriate site investigation and testing
would be essential.
This assumes that all the identified energy management measures are implemented and it is acknowledged that some of
the measures may not be acceptable to Lilybank.
12
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4.3
Black Forest
4.3.1
Resources
From discussions with AEL staff familiar with the locality, it is regarded as unlikely that the local streams have
reliable hydro generation potential13. Other possible resources include wind, solar and biomass in the form of
woodfuel.
As would be expected, no specific data on wind and solar radiation is available for Black Forest station. In the
case of wind, in a study undertaken by SKM14 for EECA in 2006, two models were referred to, one indicating an
average wind speed at sea level of over 8 m/s in the general vicinity of Black Forest while the other suggests a
wind speed of less than 6 m/s.
Another source consulted was the NASA Surface Meteorology and Solar Energy website15 which gave an
average windspeed of 6.43 m/s for latitude 45S, longitude 170W. Given the topography, all figures need to be
treated with caution.
Both sources give similar figures for solar radiation, i.e. around 1,300 kWh/m2/year.
The station is well provided with trees.
4.3.2
Distributed generation options
As noted above, there are no obvious sources for hydro-generation identified at Black Forest. Therefore the
selected distributed generation for this site is hybrid wind-solar with diesel back-up.
The 22 kV single-phase supply is not ideal for export unless generator output is small – i.e. say less than 10 kW.
This is because the generator would be liable to become overloaded with negative phase sequence currents
which would create over-heating of the generator. Generally if a generator is needed to operate in this mode, then
the output would need to be limited to 10-20% of its normal output capacity to avoid thermally damaging the
generator or the generator would need to be designed to withstand higher heating from the negative phase
sequence currents. For the purpose of this analysis, therefore, the generation plant will only supply Black Forest
Station.
Three options are analysed:
(a)
Option 1 – diesel as stand-by only
In this option, the wind–solar plant is sized to supply the entire load as shown in Table 4 (assuming energy
management measures in place). The diesel generator will only be used when the wind-solar plant is partly or
wholly out of services.
Assuming an average wind speed of 5.5 m/s a standard, domestic 7.5 kW wind turbine on a 30m guyed lattice
tower will produce an average daily power output of 35.7 kWh which equates to an annual output of 13,035 kWh
(refer Figure 12).
As noted in the paragraph above, this assessment cannot be regarded as definitive and is made for case study analysis
purposes only.
14 SKM (2006) Renewable Energy Assessment – Canterbury Region. Final Report for EECA, page 42, Sinclair Knight Mertz,
Auckland
15 http://eosweb.larc.nasa.gov/sse
13
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Based on a single turbine producing 13,035 kWh annually, two turbines will be required to meet the needs of the
Black Forest without significant reliance on a diesel generator set.
This is arguably conservative – i.e. low: if the wind speed on the site was 6.5 m/s, instead of the 5.5 m/s used
above, one turbine would produce 20,100 kWh per annum, ie just short of the 23,000 kWh/year required.
To improve overall reliability, a solar PV system should be installed to add generation capacity during low wind
periods together with inverter and battery systems. 3 kW maximum would be an appropriate size for the solar PV
array because it will provide a meaningful contribution to system performance at reasonable cost. Such an array
will consist of 15 x 200W modules, in a single string, providing a 450 VDC supply, which is inverted into a 230
VAC 50 Hz supply. Annual output will be 3,500 kWh based on an average output of 10 kWh/day.
If it is assumed that the diesel generator operates for a total of 168 hours a year (24 hours for seven days), diesel
fuel consumption will be approximately 840 litres/year.
Figure 12:
Power output from 7.5 kW wind turbine
(source: Bergey Windpower Co)
WindCad Turbine Performance Model
BWC 7500 Battery Charging Version
Prepared For:
Site Location:
Data Source:
Date:
Black Forest
Lake Benmore
(b)
7.5 kW
14/03/2008
Inputs:
MS Excel, V.97 PC
Results:
Ave. Wind (m/s) =
Weibull K =
Site Altitude (m) =
Wind Shear Exp. =
5.50
2
700
0.143
Anem. Height (m) =
Tower Height (m) =
Turbulence Factor =
Perf. Safety Margin =
30
30
8.0%
5.0%
Hub Average Wind Speed (m/s) =
Air Density Factor =
Average Output Power (kW) =
Daily Energy Output (kWh) =
Annual Energy Output (kWh) =
Monthly Energy Output =
Percent Operating Time =
5.50
-6%
1.57
35.7
13,035
1,086
72.6%
Option 2 – diesel used to meet maximum demands
In this option, the wind – solar plant is sized to supply part of the load with the diesel generator used during
maximum demand periods as well as in a standby role. One 7.5 kW wind turbine will be installed plus 3 kW peak
solar PV which will produce in the order of 16,500 kWh/year.
Based on the annual estimated consumption of 24,050 kWh/year, a balance of 7,000 kWh will need to be supplied
by the diesel generator together with meeting standby requirements. The diesel fuel consumption will increase to
approximately 2,700 litres/year.
(c)
Option 3 – high wind resource
The wind resource used above may be conservative – ie low. If an average wind speed of 8 m/s is assumed,
then, after allowing for maintenance, it is estimated using Bergey data that a single wind turbine will produce
20,787 kWh. The balance of just over 3,200 kWh will be supplied by the diesel generator requiring about 1,250
litres/year of diesel. Battery capacity will be larger than in Option 1 and 2 by about 50%.
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4.4
Stony Creek
Given the relatively low annual electricity consumption of 1,018 kWh, it is judged that the installation of a
renewable energy distributed generation plant is not feasible in economic terms. The distributed generation option
selected for analysis is a 7.5 kVA diesel generator.
4.5
Lochaber
4.5.1
Resources
There are three streams in the vicinity offering some hydro generation potential, including either the Orari River or
its tributaries, the Hewson River and the Phantom River. While no hydrological data is available for the Hewson or
Phantom River, some data16 is available for the Orari River measured at the gorge a few kilometres downstream.
Flow data was as follows:
ƒ Mean annual flow – 9.56 m3/s
ƒ Median flow – 6.6 m3/s
ƒ Flows above 2.5 m3/s 95% of the time.
According to Waugh and Scarf (2006)15, there is a high water yield from the Ben McLeod Range located above
Lochaber, the area drained by the Phantom and Hewson Rivers, both of which flow into the Orari River in the
vicinity of Lochaber. For the purposes of this study therefore, it will be assumed that flows of 1.25 m3/s are
available for hydro generation at Lochaber. It is stressed that (a) there is no specific hydrological data for the
streams that flow through or close to the station and (b) there has been no site visit to determine the degree of
difficulty that might be involved in a micro-hydro development owing to local site conditions.
As with Black Forest Station, no specific wind or solar data is available. For the purpose of the study, similar
figures to those established for Black Forest can be assumed.
The station is well provided with trees.
4.5.2
Distributed generation options
Based on the flow rates discussed above, up to 75 kW of hydro generation potential could exist. Furthermore, the
11 kV three-phase supply would permit export of surplus power generated as the problem referred to in 4.3.2
above in respect of single phase supply will not apply .
Two options are analysed:
(a)
Option 1 – local supply only.
In this option, the hydro-generation system will supply Lochaber and Blue Mountain stations, the second station
being included to increase the overall “mass” of the system. A diesel generator will be required for when the hydro
plant is partly or wholly out of services owing to breakdown, routine maintenance or low water flow.
Blue Mountains Station is understood to be very similar to Lochaber and for the purpose of this analysis, the
consumption and demand for the combined system are assumed to be double those of Lochaber.
Given the much lower capital cost associated with hydro, the benefit of taking measures to reduce electricity is
less than is the case with wind and solar – and diesel given the high cost of diesel fuel.
16
Waugh J and Frank Skarf (c2006) Hydrology of the Orari River. Downloaded from www.landcare.co.nz.
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Two cases will therefore be considered, without (Case 1) and with (Case 2) energy management measures using
consumption and demand figures shown in Table 4. For Case 1, a 30 kVA hydro installation is assumed while for
Case 2 a 20 kVA installation is assumed.
(b)
Option 2 – export
In this option, the hydro-generation system will primarily supply Lochaber and will export all surplus through the
existing 11 kV line. No diesel generator will be provided on the assumption that the 11 kV supply will provide the
necessary standby provision.
For both cases 1 and 2, a 50 kW micro-hydro generator is proposed and therefore capital costs will be identical.
More power will be exported in Case 2.
4.6
Lilybank Station
4.6.1
Resources
There are three rivers in the vicinity with reasonable hydro generation potential, the best prospect being identified
as Station Stream. The manager of Lilybank lodge has made data from a recent hydrological study available
which indicate that the generation potential is between 50 and 60 kW.
As with Black Forest station, no specific wind or solar data is available. For the purpose of the study, similar
figures to those established for Black Forest will be assumed.
The station is well provided with trees.
4.6.2
Distributed Generation Options
There are good prospects for hydro-generation at Lilybank Lodge with hydrological data for Station Stream
indicating that around 55 kW of generation is feasible. Two other rivers in the vicinity may also have generation
potential.
Unlike Lochaber Station, the export of surplus generation will not possible without replacement of the existing
single phase 22 kV supply for the reasons stated in 4.3.2.
Three options are considered:
(a)
Option 1 – connected to AEL system with no distributed generation
Three cases are analysed: without energy management (Case 1), with energy management (Case 2) and with
energy management including ground source heat pumps (Case 3) using the consumption and demand figures
shown in Table 2.
Case 1 will necessitate replacement of most of the AEL line from Tekapo with a three-phase 11 kV supply. Cases
2 and 3 will not require line replacement as the estimated maximum demand is within the capacity of the existing
AEL line.
(b)
Option 2 – isolated system with distributed generation.
In this option, the AEL line will be disconnected and Lilybank will be supplied primarily by the hydro-generation
plant. A diesel generator will be required as back-up for situations where the hydro plant is not available.
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Again, three cases will be analysed: without and with energy management measures. Given that the maximum
demand in Case 1 is estimated at 75 kVA, the hydro plant will not be able to meet demand at all times and the
diesel will need to operate during these periods of high demand. In Cases 2 and 3, the diesel generator will have
only a stand-by role.
(c)
Option 3 – remains connected to AEL system with distributed generation
In this option, the hydro-generation system will be the primary supply but the existing AEL line will remain in place
and will be available to assist in meeting maximum demand as and when required.
Three cases are considered as previously. In Case 1, a diesel generator will be provided to cater for the situation
when the hydro system is down for servicing as during these periods, the AEL supply will not be able to meet
demand. In Cases 2 and 3, the maximum demand will be within the capacity of the line and a diesel generator will
not be required.
4.7
Voltage Support
4.7.1
General description
As noted previously, this case study is based on an earlier study by AEL17, the objective of which being to avoid
uneconomic investment in line upgrades supplying areas where consumption is highly seasonal and subject to
wide annual variations.
The study assumes that a 400 kW diesel generator is connected to a remote part of the system supplied through
the Waimate substation. The generator is assumed to operate for a total of 350 hours over two months which in
AEL’s experience will meet the voltage support requirements. Tables 6 and 7 set out capital and cost (including
savings) data and assumptions for two options: diesel generator hire and diesel generator purchase.
Because the main benefits are financial – rather than economic – and accrue to the lines company rather than to
the economy, a financial analysis is carried out and the results discussed in section 6, “Commercial
Considerations – A Lines Company Perspective”.
4.8
Local Environmental Impacts
4.8.1
Air Emissions
In all cases, the use of diesel generators will result in diesel exhaust emissions that currently do not occur at the
case study sites. However, diesel utilisation is small in all cases and relatively infrequent. The isolated nature of
all sites means that any impact on people’s health is unlikely to be significant.
4.8.2
Water Use
Lochaber and Lilybank Stations both have micro-hydro generation potential. Given that micro-hydro typically
involves minimal civil works, the impact is generally small in the immediate vicinity of the plant. Furthermore, the
impact on downstream water uses can be expected to be small. However, under the provisions of the Resource
Management Act, an environmental impact assessment is required and as part of this, these and other impacts
would be examined.
The results of the study were presented at the EEA APEX Southern Summit, Christchurch 29 March 2007 by Richard
Kingsford, Network Engineer, Alpine Energy Ltd Is DG a real network alternative?
17
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4.8.3
Noise
In the context of this study, wind turbines and diesel generator plant both generate noise. In the case of wind
turbines, the usual solution is to locate the turbine an adequate distance from accommodation as the noise can be
a nuisance; there are no simple means of “silencing” as such.Diesel generators are generally provided with
silencers, the level of attenuation depending on the application.
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Table 4 : Supply Options – Capacities and Estimated Outputs
ANNUAL
CONSUMPTION kWh
MAX DEMAND
kVA
RE3 PLANT MAX
RATING kVA
DIESEL PLANT
RATING kVA
RE PLANT OUTPUT
kWh/yr
DIESEL PLANT
OUTPUT kWh/yr
POWER
EXPORTED
kWh/yr
POWER
IMPORTED
kWh/yr
Option 1- 2 x wind turbines
24,050
15
18
25
21,520
2,520
0
0
Option 2- 1 x wind turbines(diesel standby only)
24,050
15
11
25
16,535
7,500
0
0
Option 3- 1 x wind turbines- high wind
24,050
15
7.5
25
20,787
3,260
0
0
STONY CREEK
1,020
7.5
1,020
0
0
Case1 - no energy management
117,800
30
35
35
114,650
3,150
0
0
Case2 – energy management
37,900
20
25
25
37,600
300
0
0
Case1 - no energy management
58,900
20
50
0
378,000
0
318,000
3,390
Case2 – energy management
18,942
10
50
0
378,000
0
359,000
1,000
Case1 - no energy management
279,350
75
Case2 – energy management
172,240
40
172,240
Case3 – energy management- heat pumps
96,500
35
96,500
Case1 - no energy management
279,350
75
55
75
260,360
19,000
0
Case2 – energy management
172,240
40
45
45
167,740
4,500
0
0
Case3 – energy management- heat pumps
96,500
35
40
40
92,300
4,200
0
0
0
BLACK FOREST:
7.5
LOCHABER)
Option 1- local supply incl Blue Mountains:
Option 2- connected system with export:
LILYBANK:
Option 1- connected with no DG:
279,350
Option 2- isolated DG system:
0
Option 3- connected DG system:
Case1 - no energy management
279,350
75
55
25
258,860
1,500
Case2 – energy management
172,240
40
45
0
165,600
0
Case3 – energy management- heat pumps
96,500
35
40
0
92,790
0
Notes:
(1) For the detailed derivation of the above costs, please refer to appendix 2.
(2) The Lochaber plant will supply both Lochaber and Blue Mountain Stations in the isolated system case.
(3) RE – renewable energy generation plant (wind, solar or hydro)
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19,000
6,620
0
3,710
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Table 5:
Supply Options – Capital and Operating Cost Estimates
CAPITAL COSTS
ANNUAL OPERATING COSTS1
GENERATION
ENERGY MANAGEMENT
TOTAL
FUEL
O+M
TOTAL
Option 1- 2 x wind turbines (diesel for standby only)
$225,000
$60,350
$285,350
$5,303
$5,500
$10,803
Option 2- 1 x wind turbines(diesel to meet maximum demands)
$190,000
$60,350
$250,350
$8,865
$5,750
$14,615
Option 3 – 1 x wind turbine – high wind
$145,000
$60,350
$205,350
$6,073
$6,500
$12,573
STONY CREEK
$10,0001
$10,000
$400
$250
$650
BLACK FOREST:
LOCHABER
Option 1- local supply including Blue Mountains:
Case1 – no energy management
$201,000
$0
$201,000
$2,069
$5,500
$7,659
Case2 - energy management
$170,000
$47,100
$217,100
$2,802
$5,250
$8,052
Option 2- export:
Case1 – no energy management
$310,000
$0
$310,000
$0
$5,000
$5,000
Case2 - energy management
$310,000
$23,600
$333,600
$1,776
$5,000
$6,776
LILYBANK:
Option 1- connected with no distributed generation
Case1 – no energy management
Note 1 –
Case2 - energy management
$121,050
$6,378
Case3 – energy management- heat pumps
Option 2- isolated distributed generation system:
$189,050
$6,378
$5,000
$11,378
$6,378
$17,967
Case1 – no energy management
$360,000
$0
$360,000
$12,467
$5,500
Case2 - energy management
$265,000
$121,050
$416,050
$9,333
$5,500
$14,833
Case3 – energy management- heat pumps
Option 3- connected to AEL with distributed generation:
$275,000
$189,050
$464,050
$9,136
$10,500
$19,636
Case1 – no energy management
$350,000
$0
$350,000
$985
$5,500
$6,485
Case2 - energy management
$265,000
$79,050
$386,050
$6,378
$5,000
$11,378
Case3 – energy management- heat pumps
$245,000
$189,050
$434,050
$6,378
$10,000
$16,378
in the economic analysis, allowance for periodic maintenance has been made as follows: diesel gensets – between $5,000 and $10,000 at 10 years; hydro turbines - $20,000 at 5 years: heat pumps - $30,000 at 15 years;
batteries between $17,500 and $25,000 at 7 to 8 years; wind turbines – between $3,000 and $5,000 at 5 years.
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Table 6: Voltage Support - Costs
Option
1 - Hire of generator
2 – Purchase generator
Generator
purchase
Generator
hire
(annual)
$36,000
$150,000
Installation
cost
$20,000
$20,000
Power
generated
kWh/year
140,000
140,000
Diesel
consumption
litres/year
37,838
37,838
Diesel
cost
(annual)
$54,108
$54,108
Maintenance
(annual)
$3,750
$7,500
TOTAL
COSTS
$20,000
$170,000
Notes:
(1) Diesel generator purchase and hire costs based in information from a cross-section of equipment suppliers.
(2) Diesel cost based on $1.43 plus $0.03 for delivery based in information from BP New Zealand (price as of 9 May 2008).
(3) Maintenance cost based on 5% of capital for purchase and 2.5% for hire.
Table 7: Voltage Support – Cost savings
Sale to Retailer
(annual)
$8,400
Reduction in Transpower Demand
charges
(annual)
$24,000
Notes:
(1) Sales to retailer based on $0.06 per kWh.
(2) Transpower demand charge based on $60 per kW per annum.
(3) Deferred cost based on 14 km at $46,000 per km.
Source of all cost saving data: Alpine Energy Ltd.
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ANNUAL
SAVINGS
DEFERRED LINE UPGRADE COST
$32,400
$644,000
CAPITAL
TOTAL OPERATING COSTS
(ANNUAL)
$93,858
$61,608
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5.0
ECONOMIC ANALYSIS
The different distributed generation case studies described in the earlier sections of the report are evaluated and
compared using the national economic cost-benefit analysis methodology outlined in Treasury’s Cost Benefit
Primer.
5.1
Methodology
The national economic analysis excludes all internal transfers such as taxation and payments between the
commercial entities involved in the projects. Economic costs and benefits throughout the project life are in real
2008 New Zealand dollars and currency exchange rates are assumed to remain at present levels. Possible
effects of currency fluctuations on the costs of imported items such as oil and wind turbines are covered in the
general sensitivity analysis for capital and operating costs. A real discount rate of 5% is used in accordance with
the recommendations included in the New Zealand Energy Strategy.
Primary economic benefits arising from the installation of the distributed generation plant are:
• Avoided costs of electricity distribution to the DG sites. At Lochaber and Black Forest, these primarily
are the costs of maintaining the existing section of line made redundant by the disconnection of the
distributed generation site from the distribution network. In the case of Lilybank, the avoided costs will
include upgrading 29 km of the existing spur line from single to three phase which would be required to
meet the increasing electricity demand at Lilybank.
• Avoided costs of electricity generated for the transmission grid and supplied through the Alpine Energy
network to the distributed generation sites. In most cases examined this equates to the electricity
consumed at the sites if they had continued to be supplied by the grid and which is matched by the
output from the distributed generation plant. Where Lochaber remains connected to the grid and can
export surplus generation back into the Alpine Energy network, the avoided grid electricity is equivalent
to the full output of the distributed generation plant plus any savings from the associated energy
management measures at the site.
• Benefits arising from increased reliability of electricity supply. Distribution networks are subject to
unplanned outages which are exacerbated in remote locations because of the length of the lines, difficult
access for maintenance and severe weather events such as snowfalls in South Canterbury. The
installation of distributed generation plant at remote locations can circumvent these outages and
increase the reliability of electricity supply. The value of this increased reliability has been factored into
the economic analysis using value of lost load.
• The reduction in greenhouse gas emissions arising from the installation of distributed generation plant.
Plant proposed for the sites primarily utilizes hydro, wind and photovoltaic technology which have zero
emissions with comparatively low levels of electricity output from the supplementary diesel generators.
Electricity generated for the grid and replaced by the distributed generation plant will have a higher
carbon emission factor. The marginal grid generation replaced primarily consists of output from thermal
plant, although the proportion of thermal plant in the marginal mix is likely to fall in the future as more
renewables generating capacity is constructed.
The costs of the project relate to the distributed generation plant, in particular:
• The capital costs of the hydro, diesel, wind, PV and energy management plant installed at the distributed
generation sites and described in detail in Section 4 of the report. For the purposes of the analysis,
these are assumed to occur in the first year of the project.
• Operating costs of the distributed generation and energy management plant, assumed to occur from the
second year of the project life and expressed in real 2008 dollars throughout the project life. These
include the routine costs of servicing the plant, its periodic replacement where necessary and the costs
of fuel used to operate the diesel generators and thermal space heaters.
• Carbon emissions from the fuels used to operate the generating and energy management plant,
including an estimate of the emissions made from vehicles during the delivery of fuel to the sites.
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5.2
Assumptions and Costs
A number of key assumptions have been made whilst evaluating the various cases:
5.2.1
Value of avoided grid generation
Over the long run wholesale prices for electricity tend to follow the long run marginal cost of new power stations.
Long run marginal cost is the projected cost of electricity from the next most economic power station option and is
the conventional means of valuing avoided cost of electricity generated for the grid. As the next most economic
power station is successively selected as new generating capacity is built, projected LRMC will progressively
increase over time. Estimates of LRMC can vary significantly as they include projections of power station load
factor and costs of capital, operations, maintenance, fuel and carbon emissions, and are also sensitive to discount
rate as capital costs are a significant element. Data developed by various sources18, indicates that LRMC, net of
carbon charge, will rise from a current level of some 7 c/kWh to 10 c/kWh in 2030 (refer Figure 13).
Figure 13: Assumed Long Run Marginal Cost of Electricity Generation
(net of carbon charge)
Base Case
12
c/kWh
11
10
9
8
7
6
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
5
5.2.2
Energy demand
In each case analysed, it is assumed that the energy consumed at each distributed generation site will be the
same regardless of whether the distributed generation project is put in place or the site continues to draw its
electricity from the grid. There is a possibility that electricity use will increase with the installation of the distributed
generation plant as the marginal cost of electricity will be near zero. Also, it is possible that the temperature of the
house space heating will increase with the use of firewood and LPG rather than electricity. However, there is no
known data to corroborate these assumptions and any estimate of the resultant benefits to the consumer would
be speculative. In any event, it is most likely that any additional consumer surplus arising from higher energy
consumption will be relatively small compared to the benefit arising from reduced energy costs19.
Such benefits therefore are not included in this analysis, which will tend to underestimate net benefits somewhat.
18
from CAE (2008) An Analysis of the Effect of Renewables Targets in the Electricity Sector on the New Zealand Gas
Industry, New Zealand Centre for Advanced Engineering, February 2008 as derived from the Electricity Commission. These
data are generally consistent with LRMC shown in the MED’s “Energy Outlook” and costs of generation estimated by Infratil
in its “Update, March 2008”
19 Refer Charles River Associates (2004) Increasing the Direct Use of Natural Gas in New Zealand
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It is assumed that the there will be no net benefit or otherwise arising from greater productivity at the farms after
the installation of the distributed generation plant. The change in energy supply is unlikely to have a material
impact on the farming or other activities carried out at the different sites.
5.2.3
Carbon dioxide emissions
Ministry for the Environment emission factors of 69.5 and 60.4 kt CO2/PJ are used for determining carbon dioxide
emissions from the diesel and LPG consumed at the distributed generation sites. Additional emissions from the
transportation of these fuels to the remote distributed generation sites are included in the analysis but these are
small in comparison with those emitted during the combustion of the fuel. The increase will depend on the
distance travelled and the type of vehicle used but is most likely to add less than 1% to the MfE emission factors
given the distance inland to the generation sites. It is assumed that the emissions resulting from the use of
firewood are negligible, with a programme of replanting suitable trees undertaken to ensure a sustainable supply
of fuel is maintained.
Like the determination of LRMC, there is considerable uncertainty regarding the reduction of carbon emissions
due to reduced demand for electricity supplied from the grid. A study by the Ministry for the Environment20
indicates that an emission factor of 0.6 tonne CO2/MWh is appropriate in the short term but future emission levels
depend on the impact of the carbon emissions trading scheme on the mix of generation capacity in the future. In
the event that policies in the immediate future do not influence supply-side investments, the appropriate emission
factor should average 0.5 tonne CO2/MWh for ten year projects. If the emission policies are successful, the
average emissions factor should be reduced to 0.2 tonnes CO2/MWh, reflecting the greater investment in
renewable generation.
It is to be anticipated that a higher price of carbon dioxide will be associated with the lower emission factor and
vice versa. For the purposes of this analysis, this inter-relationship is taken to be consistent with the MfE study:
$15 per tonne CO2 at the 0.5 tonne CO2/MWh emission factor and $50 per tonne CO2 at the 0.2 tonne CO2/MWh
emission factor.
5.2.4
Distribution system costs
Electricity distribution lines are static assets with an expected life span in excess of 50 years. Although regular
inspection and maintenance programmes are put in place by lines companies, the need for significant
maintenance expenditure is irregular and dependent in part on weather events. However, on average, it is
estimated that the annual cost of maintaining rural distribution lines is 2% of capital costs, which typically is
$50,000 per kilometre. An annual charge of $1,000 per kilometre per year is used to value the line maintenance
cost savings when sections of line are made redundant by the disconnection of distributed generation sites.
Lilybank differs from the other cases in that it requires the installation of a new three phase line to meet the
expanding load at the site. The installation of the distributed generation plant at Lilybank will avoid the installation
of the three phase line regardless of whether the site remains connected to the grid or not. To supply the
increased load to Lilybank, a total of 29 kilometres of line must be upgraded at a cost21 of $50,000 per kilometre.
As there is no requirement to upgrade the lines to the other sites to meet increasing demand, the avoided costs in
these cases are limited to the savings of $1,000 per kilometre per year on the maintenance of the redundant
sections of line.
Carbon abatement effects of electricity demand reductions, Ministry for the Environment, 2007
Power line installation costs used in this report are based on information from AEL which is in turn based on recent actual
supply line installation costs. These have increased substantially in recent months owing to high international prices for
ferrous and non-ferrous metals.
20
21
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5.2.5
Transmission Costs
A potential benefit of distributed generation is the avoidance or deferral of expenditure on the transmission system
due to the removal of transmission capacity constraints through the appropriate siting of the distributed generation
plant. There is no evidence to indicate that any such benefit will arise through the reduction of demand at the
sites under investigation nor is it likely there will be an appreciable reduction in routine transmission costs
because of the very small electricity demand at each site. It is therefore assumed that there will be no reduction
in transmission costs in any of the cases.
5.2.6
Fuel Costs
The economic costs of diesel and LPG delivered to the sites are assumed to be the prices prevailing in Timaru in
mid-May 2008 with an allowance made for delivery to the remote locations22. These can be adjusted with oil price
to assess the sensitivity of the projects to these costs.
Reported costs of firewood vary considerably, ranging from less than $1/GJ for forest residues to over $20/GJ for
retailed firewood. It is assumed that firewood will be available at each of the sites and a small plantation can be
established to provide a sustainable supply of wood and farm equipment is available to fell, split and store the
wood. Costs of plantation wood have been estimated at $4 to 8/GJ23 and for this analysis a cost of $7/GJ or
$40/m3 has been assumed.
5.2.7
Line Losses
The avoided grid generation resulting from the use of distributed generation will be amplified by the electricity
losses from the transmission and distribution networks which would have occurred without the distributed
generation plant in place. For the purposes of this analysis these losses are assumed to be the averages
reported by the MED24: 3.4% for transmission losses and 6.3% losses over the distribution network. These are
applied in all cases except where Lochaber remains connected and exports electricity from distributed generation
back into the distribution network. In this case the transmission losses are added to the avoided grid generation
but not the distribution losses as the exported distributed generation output will be subject to losses in the
distribution network.
5.2.8
Value of Lost Load
Value of lost load is a measure of the value that consumers place on the reliability of electricity supply and the
cost of supply interruptions to consumers. A value of $21/kWh for lost load is used by the Electricity Commission
as part of the Grid Investment Test25, although this relates to core transmission outages which would involve
commercial and industrial consumers, which are likely to place a significantly higher value on interruptions than
the residential or farming activities carried out in the locations under investigation. Some studies, however,
indicate that the value of lost load to residential users is the same or higher than for commercial and industrial
users26. This is discussed in the Sensitivity Analysis in Section 5.4.
22 Diesel Price advised by BP New Zealand: 197 c/l = 194c/l (diesel in drums) + 3c/l freight
LPG Price advised by Nova LPG: $2.14/kg = $1.95 (gas) + $0.15 (cylinder) + $0.04 (delivery)
23 East Harbour Management (2002) Availabilities and Costs of Renewable Sources of Energy for Generating Electricity and
Heat, East Harbour Management Services Ltd
24 MED (2007) Energy Data Tables September 2007: Transmission and Distribution Network Statistics for Year End March
2006 Ministry of Economic Development
25 Refer CAE (2004) Assessment of Value of Lost Load for the Electricity Commission, Centre for Advanced Engineering,
September 2004
25 See SEO Economisch Onderzoek (2006), Guaranteeing that the lights always come on –how much is this really worth?,
Michiel de Nooij
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Table 8: Loss of Supply 2002 - 2006
Lochaber
2002/03
2003/04
Reason
Unplanned
Unplanned
Planned
Unplanned
Unplanned
Unplanned
Cause
Switching
?
Equip Mtce
Digger
Bird
Snow Storm
Lilybank
Time Off
Minutes
15
1040
240
8
40
330
kW h*
0.75
52.00
12.00
0.40
2.00
16.50
2004/05
2005/06
2006/07
Unplanned
33kV Fault
Unplanned
33kV Fault
Unplanned Snow Storm
Unplanned Replace Pole
Total
Annual Average
* Average Load: 3.00 kW h
66
287
14400
420
16846
3369
3.30
14.35
720.00
21.00
842
168
Black Forest & Stony Creek
Time Off
Minutes
Cause
W ind
80
Time Off
Minutes
80
105
kW h*
4.00
5.25
Reason
Unplanned
Pole
170
8.50
Tpow Mtce
OC - Fuses
?
?
480
80
20
600
735
1920
120
420
15
82
2880
24.00
4.00
1.00
30.00
36.75
96.00
6.00
21.00
0.75
4.10
144.00
Unplanned
Unplanned
?
Planned
Unplanned
Unplanned
Pole
Xarm
?
Tpow Mtce
?
?
170
15
60
480
20
600
8.50
0.75
3.00
24.00
1.00
30.00
Unplanned
Unplanned
Unplanned
Tek Sub LA
Tek Sub LA
Snow Storm
15
82
10080
0.75
4.10
504.00
7707
1541
385
77
11602
2320
580
116
Reason
Unplanned
?
Cause
W ind
?
Unplanned
Planned
Unplanned
Unplanned
Unplanned
Unplanned
Unplanned
Unplanned
Planned
Unplanned
Unplanned
Unplanned
Tx Fault
Pole Mtce
Tek Sub LA
Tek Sub LA
Snow Storm
This analysis assumes a cost of $5 per kWh interrupted for the three remote locations and an average demand of
3kW at each site. These factors are applied to the average loss of supply at the three sites derived from AEL’s
records for the last five years summarized in Table 8. The effect of a higher value of lost load is investigated in
the sensitivity analysis.
5.3
Key Results
The key results from the economic analysis are summarised below and Tables 9 and 10.
•
•
•
•
•
All the Lilybank options show strong positive net present values. This is primarily because the avoided
costs of upgrading 29 km of distribution line to three-phase is much higher than the capital of the
distributed generation plant installed.
Where loads are disconnected and short sections of distribution line are made redundant, the avoided
costs of grid electricity and savings in line maintenance are insufficient to offset the cost of the
distributed generation plant. This is the case when Lochaber and Black Forest are disconnected from
the network and the generating plant, in particular the diesel units, operate at relatively low load factors
to meet only the load at the generation site. Importantly, the savings in line maintenance are small when
only short sections of line are made redundant. This same conclusion can be drawn for situations where
several disconnected loads are linked together as the lines connecting the loads must still be
maintained.
Project economics improve markedly when grid connection is retained and surplus electricity from the
distributed generation plant is exported back to the distribution network. This is illustrated at Lochaber
where the hydro plant capacity can be maximized and can operate at a much higher load factor than
when disconnected and therefore increases the amount of grid generation avoided. When connected,
Lochaber returns a positive NPV at 5% compared with the strongly negative NPV when disconnected.
However, this option is not available at all locations as there is a three phase line at Lochaber which
allows electricity to be exported back out. For example, the benefits of remaining connected at Lilybank
with distributed generation plant installed are not clear-cut as the connection serves primarily to reduce
standby diesel generation.
Where suitable rivers are available, hydro technology is to be preferred to wind/photovoltaic because of
its significantly lower capital costs and the potential for higher operating load factors. This is illustrated
at the Black Forest site which returned substantially negative net present values even at high levels of
assumed wind availability.
The maximum greenhouse gas emission reductions are achieved where distributed generation output
can be exported to the grid. As noted, this maximizes the amount of grid generation avoided.
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•
•
•
The benefits of using thermal fuels as a means of reducing the size of the distributed generation plant
installed depend on particular circumstances. In most cases examined net present value is reduced
slightly with thermal heating and carbon dioxide emissions increased, except where diesel standby could
be eliminated. Smaller generating plant can be used in conjunction with thermal heating but operate at
lower load factors and the reduction in generating plant capital is insufficient to offset the costs of the
thermal heating units. The use of heat pumps reduced net present value in all cases.
In two cases the use of thermal energy management plant improved project economics. At Lochaber,
with the line connected and surplus electricity sent from the site, the use of thermal heating directly
increased the grid generation avoided without reducing the hydro load factor and improved project net
present value. However, like the other cases noted above, the improvement in net present value is
small. A more significant benefit is obtained at Lilybank when the site remains connected to the network
and upgrading of the distribution line is offset by the installation of the thermal heating plant only with no
distributed generation capacity built. In this case, the additional cost of the generating plant is not offset
by the increase in the grid electricity avoided.
The replacement of the distribution line to the shearing shed at Stony Creek with a portable diesel
generator during the shearing season gives a positive net present value. This shows that innovative low
cost solutions are available but require an understanding of the particular circumstances of the load and
supply options.
This analysis indicates that the economics of replacing grid connection with isolated generation plant depend very
much on circumstances. Distributed generation can provide substantial net benefits in situations where extensive
upgrades have to be made to distribution lines to meet growing demand or where output from the distributed
generation plant can be exported back to the grid. On the other hand, in locations where there is limited growth
and consumer loads are separated by relatively small distances, it is more economic to maintain electricity supply
from the grid.
Table 9:
Economic Analysis: Lochaber, Black Forest and Stony Creek
Lochaber
Grid Option
Energy Management
Heat Pump
NPV @ 5.0% $
IRR
Plant Load Factor
Hydro
Diesel
Wind/PV
Plant Capital Costs
Avoided Line Costs
Line upgrade km
Redundant Line Maintenance km
Fuel Requirements
Diesel litre
LPG kg
Woodfuel m3
Avoided Grid Generation kWh
DG Output
Remote Demand
Fuel Substitution
Losses
less Imports from grid
Value of Lost Load $ pa
Emissions t CO2
Grid Emissions Avoided
Diesel Emissions
LPG Emissions
Net Reduction
Remote
No
Yes
No
No
-153,653 -177,192
Negative Negative
Connected
No
Yes
No
No
41,884
42,934
6.5%
6.4%
43.6%
1.4%
21.5%
0.1%
86.3%
201,000
217,100
310,000
2.50
2.50
1,050
91
683
26
117,800
Black Forest
Remote
Yes
Yes
Yes
No
No
No
-285,249 -306,105 -237,511
Negative Negative Negative
Stony
Creek
Remote
No
No
94,720
68.7%
86.3%
333,600
341
26
1.2%
13.7%
285,350
3.6%
17.5%
250,350
1.2%
31.0%
205,350
10,000
5.00
5.00
5.00
7.50
840
1,031
36
2,648
1,031
36
1,231
1,031
36
339
378,000
378,000
71,150
71,150
71,150
1,018
7,054
7,054
7,054
101
117,800
11,679
11,679
12,852
39,958
14,211
129,479
842
129,479
842
390,852
842
432,169
842
78,204
580
78,204
580
78,204
580
1,119
0
25.9
2.8
0.0
23.1
25.9
0.2
2.1
23.6
78.2
0.0
0.0
78.2
86.4
0.0
1.0
85.4
15.6
2.3
3.1
10.3
15.6
7.1
3.1
5.4
15.6
3.3
3.1
9.2
0.2
0.9
0.0
-0.7
Carbon Emissions: 0.2 tonne CO2/MWh, $50 per tonne CO2
Increasing the discount rate from 5% to 10% will reduce net present values. However, only in the case where
Lochaber remains connected to the network will a positive net present switch to negative as the internal rate of
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return is 6.5%. Also, the impact of the higher discount rate is most pronounced in this case because of the high
load factor of the hydro plant and the relatively large amount of grid generation avoided over the project life.
Table 10:
Lilybank
Connected Connected
Remote
Remote
Remote Connected
Yes
Yes
No
Yes
Yes
No
No
Yes
No
No
Yes
No
1,386,624 1,337,471 1,247,693 1,244,553 1,122,430 1,302,835
Positive
Positive
Positive
Positive
Positive
Positive
Grid Option
Energy Management
Heat Pump
NPV @ 5.0% $
IRR
Plant Load Factor
Hydro
Diesel
Wind/PV
Plant Capital Costs
Avoided Line Costs
Line upgrade km
Redundant Line Maintenance km
Fuel Requirements
Diesel litre
LPG kg
Woodfuel m3
Avoided Grid Generation kWh
DG Output
Remote Demand
Fuel Substitution
Losses
less Imports from grid
0
Value of Lost Load $ pa
Emissions t CO2
Grid Emissions Avoided
Diesel Emissions
LPG Emissions
Net Reduction
Economic Analysis: Lilybank27
Connected Connected
Yes
Yes
No
Yes
1,223,226 1,102,161
Positive
Positive
54.0%
2.9%
42.6%
1.1%
26.3%
1.2%
53.7%
0.7%
42.0%
26.5%
121,050
189,050
360,000
416,050
464,050
350,000
386,050
434,050
29.0
29.0
29.0
8.00
29.0
8.00
29.0
8.00
29.0
29.0
29.0
6,329
2,046
50
1,500
2,046
50
1,400
2,046
50
500
2,046
50
2,046
50
2,046
50
279,348
279,348
279,348
279,348
279,348
279,348
107,113
10,619
182,849
18,128
27,695
27,695
27,695
117,732
385
200,977
385
307,043
385
307,043
385
307,043
385
25,813
18,986
286,175
385
27,038
6,624
299,762
385
27,327
3,711
302,964
385
23.5
0.0
6.2
17.3
40.2
0.0
6.2
34.0
61.4
17.0
0.0
44.4
61.4
4.0
6.2
51.2
61.4
3.8
6.2
51.4
57.2
1.3
0.0
55.9
60.0
0.0
6.2
53.7
60.6
0.0
6.2
54.4
Carbon Emissions: 0.2 tonne CO2/MWh, $50 per tonne CO2
5.4
Sensitivity Analysis
To identify the factors having the greatest influence on project economics, Table 11 shows the change in net
present value when the principal benefits and costs to each of the distributed generation projects investigated,
such as capital, operating and fuel costs, were altered by 25%. Value of lost load had been increased 100% to
$10/kWh, conservatively corresponding to half the value applied for the transmission grid investment test, and the
carbon emission cost is adjusted to $15 per tonne CO2 which corresponds to a marginal grid generation emission
factor of 0.5 tonne CO2/MWh.
With the exception of the carbon emissions, each variation is symmetric in that a change in input value from a
25% increase to a 25% decrease will change net present value by the same amount, but in the opposite direction.
In the case of value of lost load, a 100% reduction will reduce the assumed benefit to zero. The sensitivity of the
projects to the principal variables is illustrated in Figure 14.
The relative impacts on net present value of increasing the various benefits and costs reflect their relative
contribution to the overall project cash flow and depend on the circumstance and configuration of each project:
• Avoided lines maintenance and upgrades costs are the primary benefit to the distribution generation
projects, significantly in locations such as Lilybank and Stony Creek which show a positive net present
value in the base case. In contrast, Black Forest and Lochaber (when disconnected) have a lesser
contribution from and sensitivity to avoided lines costs and have significantly negative net present
values.
27
As cash flows are positive throughout in this case it is not possible to provide a finite IRR
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Table 11:
Sensitivity Analysis: Changes in NPV
Basis
Change
Grid Option
Energy Management
Heat Pump
Base Case
NPV @ 5.0% $
IRR
Change In NPV
LRMC c/kWh
Crude Oil US$/bbl
Woodfuel Price $/m3
Generator Capex $/kW
Energy Management Capex
O&M Costs
Lilybank Line Upgrade $/km
Avoided Lines Mntce $/km/year
Value of Lost Load $/kWh
Emissions: $/t CO2
Grid Option
Energy Management
Heat Pump
Base Case
NPV @ 5.0% $
IRR
Change In NPV
LRMC c/kWh
Crude Oil US$/bbl
Woodfuel Price $/m3
Generator Capex $/kW
Energy Management Capex
O&M Costs
Lilybank Line Upgrade $/km
Avoided Lines Mntce $/km/year
Value of Lost Load $/kWh
Emissions: $/t CO2
Lochaber
Remote
No
No
Connected
No
No
Yes
No
-153,653
Negative
-177,192
Negative
41,884
6.5%
33,135
-3,523
0
-50,250
0
-28,872
0
7,789
10,497
-2,805
33,135
-3,750
-3,257
-42,500
-11,775
-28,872
0
7,789
10,497
-3,024
100,024
0
0
-77,500
0
-26,854
0
0
10,497
-12,177
Connected Connected
Yes
Yes
No
Yes
Remote
No
No
25%
25%
25%
25%
25%
25%
25%
25%
100%
15.00
Yes
No
42,934
6.4%
Yes
No
Stony
Creek
Remote
No
No
-237,511
Negative
94,720
68.7%
Black Forest
Remote
Yes
Yes
No
No
-285,249
Negative
-306,105
Negative
110,597
20,013
20,013
20,013
286
-1,723
-8,021
-14,087
-9,333
-1,139
-3,257
-4,486
-4,486
-4,486
0
-77,500
-56,250
-47,500
-36,250
-2,500
-5,900
-15,088
-15,087
-15,088
0
-26,854
-26,512
-28,640
-32,018
-743
0
0
0
0
0
0
19,216
19,216
19,216
28,823
10,497
8,918
8,918
8,918
0
-13,013
-89
2,026
368
362
Lilybank
Remote
Remote Connected Connected Connected
Yes
Yes
No
Yes
Yes
No
Yes
No
No
Yes
1,386,624
Positive
1,337,471
Positive
1,247,693
Positive
1,244,553
Positive
1,122,430
Positive
1,302,835
Positive
1,223,226
Positive
1,102,161
Positive
30,129
-10,322
-6,231
0
-30,263
0
362,500
0
5,924
-961
51,433
-10,322
-6,231
0
-47,263
-19,185
362,500
0
5,924
-3,554
78,576
-21,236
0
-90,000
0
-33,366
362,500
24,596
5,924
-2,160
78,576
-15,356
-6,231
-73,750
-30,263
-30,889
362,500
24,596
5,924
-5,104
78,576
-15,020
-6,231
-68,750
-47,262
-50,075
362,500
24,596
5,924
-5,221
73,236
-1,678
0
-87,500
0
-29,651
362,500
0
5,924
-8,331
76,713
-10,322
-6,231
-66,250
-30,263
-26,854
362,500
0
5,924
-6,632
77,532
-10,322
-6,231
-61,250
-47,263
-46,040
362,500
0
5,924
-6,732
25%
25%
25%
25%
25%
25%
25%
25%
100%
15.00
Figure 14:
Change in NPV with 25% Increase in Input Benefit/Cost28
(excludes options with heat pumps and without energy management)
400,000
350,000
300,000
Change in NPV $
250,000
Avoided Lines Costs
Electricity LRMC
Value of Lost Load
Carbon Emissions
Woodfuel
Crude Oil
Energy Management Capex
O&M Costs
Generator Capex
200,000
150,000
100,000
50,000
0
-50,000
Lochaber Remote
Lochaber
Connected
Black Forest
Lilybank Without Lilybank With DG
DG
Stony Creek
-100,000
Value of Lost Load varied by 100%. Options with heat pumps and without energy management equipment show similar
sensitivity patterns to those illustrated in the figure.
28
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•
•
•
•
Avoided generation costs for grid electricity are significant but of secondary importance, except in the
sub-economic projects. This generalization does not apply when Lochaber remains connected and
exports hydro generation back into the distribution network as the hydro plant can operate at a high load
factor and its capacity maximized.
Value of lost load is likely to make a relatively minor contribution to project benefits. Increasing the value
to $21/kWh, equivalent to commercial and industrial users, will effectively triple the sensitivity shown in
Table 11 and improve project economics, but its contribution to project benefit will remain relatively small
compared to avoided lines and grid generation. The principal cost sensitivity in most cases is the capital
cost of the distributed generation plant because of the relatively low load factors of the hydro and,
particularly, the diesel plant. Plant operating costs and the capital costs of the thermal energy
management equipment are significant but smaller than the generator capital costs. In most cases the
impact of the price of oil and fuelwood is relatively small29.
The impact of carbon emissions and pricing is relatively small and is positive or negative depending on
the amount of standby diesel consumed relative to grid generation avoided. With the exception of Stony
Creek, the principal change in carbon emissions arises from the reduction in grid generation. However,
it is assumed that a reduction of carbon price from $50 to $15 per tonne CO2 will be associated with an
increase in the marginal grid electricity emission factor from 0.2 to 0.5 tonne CO2/MWh, resulting in a
relatively small net cost of emissions per kWh of grid electricity displaced.
Best and worst case scenarios were developed by combining all the changes in net present value for
increases in benefits and reductions in costs for the best case and vice versa for the worst case.
Because all projects investigated either have a strong positive or negative base case net present value,
the net present value does not change between positive and negative, even at discount rates as high as
20%.The exception is the case where electricity is exported from Lochaber with no benefit from avoided
line maintenance costs. The base case for this project gives an internal rate of return of 6.4% but at
discount rates above 15.5% the net present values of the best and worst case scenarios are both
negative.
Figure 15: Best and Worst Case Scenarios
(25% variation in costs and benefits in combination)
2.0
Net Present Value $ million
1.5
Best Case NPV
Base Case NPV
Worst Case NPV
1.0
0.5
0.0
Lochaber
Remote
Lochaber
Connected
Black Forest
Remote
Lilybank
Without DG
Lilybank With
DG
Stony Creek
Remote
-0.5
The impact of crude oil price has been estimated for diesel and LPG. It has not been estimated for grid electricity LRMC
as that is beyond the scope of this project.
29
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Of all the costs and benefits discussed above, the cost of line maintenance or upgrading is the one most defined
by the specific circumstances of the distributed generation site under investigation. All others share a common or
generic cost or technology characteristic.
Also, the projects investigated illustrate the high level of sensitivity project economics have to avoided lines costs.
To provide some indication of the magnitude of avoided lines costs necessary to make a project economically
viable, the hypothetical breakeven lines lengths and unit maintenance costs for each of the projects have been
calculated.
•
•
•
In the circumstances encountered at Lochaber and Black Forest, the length of line made redundant
would have to be four to seven times longer than is actually possible if the projects were to be
economically viable. Alternatively, the annual avoided cost of maintenance would have to be higher by
similar factors than the assumed $1,000/km per annum. Because of the very small electricity demand at
Stony Creek, the minimum breakeven length of line is significantly less than the 7.5 km which can be
disconnected.
The Lilybank project is economically viable in the all the cases investigated, primarily because the
capital cost of upgrading the 29 km of line to three phase is higher than the capital costs of the
distributed generation plant installed. At a cost of $50,000/km, the length of line to be upgraded can be
reduced to between 1.3 and 7.0 kilometres and the project still remain viable, depending on the
technology used. This reinforces the conclusion that opportunities for distributed generation are greatest
where there is a need to spend capital on lines to meet increasing electricity demand as opposed to
situations where demand is static and only lines maintenance costs can be avoided.
These breakeven lines lengths have been calculated at a 5% discount rate. At a 10% discount rate, the
breakeven lines length will be 20 to 50% higher, depending on the cost structure of the case.
Table 12:
Breakeven Lines Lengths and Costs
Lochaber
Grid Option
Energy Management
Heat Pump
Base Case
Avoided Lines Mntce km
Maintenance Cost $/km/year
Breakeven Lines Length/Cost
Avoided Lines Mntce km
Maintenance Cost $/km/year
Grid Option
Energy Management
Heat Pump
Base Case
Avoided Lines Upgrade km
Upgrade Cost $/km
Breakeven Lines Length/Cost
Avoided Lines Upgrade km
Upgrade Cost $/km
Remote
No
No
Yes
No
Connected
No
No
Yes
No
Black Forest
Remote
Yes
Yes
No
No
Yes
No
Stony
Creek
Remote
No
No
2.5
1,000
2.5
1,000
5.0
1,000
5.0
1,000
5.0
1,000
7.5
1,000
14.8
5,932
16.7
6,687
23.6
4,711
24.9
4,983
20.5
4,090
1.3
178
Connected Connected
Yes
Yes
No
Yes
Remote
No
No
Lilybank
Remote
Remote Connected Connected Connected
Yes
Yes
No
Yes
Yes
No
Yes
No
No
Yes
29.0
50,000
29.0
50,000
29.0
50,000
29.0
50,000
29.0
50,000
29.0
50,000
29.0
50,000
29.0
50,000
1.3
2,185
2.3
3,880
4.0
6,976
4.1
7,084
6.6
11,296
2.9
5,075
4.5
7,820
7.0
11,994
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6.0
COMMERCIAL CONSIDERATIONS – A LINES COMPANY PERSPECTIVE
While the previous section provides an economic analysis from a national cost benefit point of view, it is also
important to examine the benefits or negatives of distributed generation from the perspective of the electricity lines
companies who, together with the end user, are those most directly affected.
6.1
The History
The AEL distribution system is typical of many other predominantly rural electricity distribution networks which
were constructed in the 1950s and 1960s as part of the then government’s rural development policies which
aimed to encourage economic growth in rural New Zealand. The policies have resulted in long rural feeder lines to
remote farming areas, presenting operational and maintenance challenges to lines companies, particularly during
bad weather. In some cases, a long feeder line may only serve one or two consumers that use very little electricity
– such as a holiday home or a woolshed.
6.2
Regulation
Regulation of electricity lines companies such as AEL is administered by the Commerce Commission with the
objective of ensuring that lines companies provide an efficient and reliable supply at the lowest possible cost to
consumers.
The price thresholds methodology prescribed by the Commerce Commission prevents price increases above the
Consumer Price Index and the overall return on investment has to be based on asset valuation using the
optimised deprival valuation (ODV) methodology. The rationale for the use of ODV is that it prevents the cost of
unnecessary or extravagant investment being passed on to consumers. The downside for a lines company is that
it cannot obtain an adequate return on long feeder lines with very low utilisation.
Some relief from the lines companies’ point of view was in sight when under Section 62 of the Electricity Act 1992,
from 2013, lines companies would have no longer been obliged to supply electricity to all places supplied as at 1
April 1993. However, it is understood that this provision is likely to be revoked by the Government30.
6.3
Distributed Generation
6.3.1
The Barriers
The development of wind, solar and micro hydro generation technologies as well as bio-diesel fuels, has created
an opportunity for lines companies to evaluate these technologies and the impact of encouraging generation at
the customer’s premises as an alternative to the standard response of provision of an interconnected
transmission-distribution top down network hierarchy of supply.
While this may seem a conflict of interest for lines companies to consider an alternative which potentially
bypasses or strands their own infrastructure, there may be circumstances where this provides benefits to both the
lines company and the customer.
There is sufficient development in off-grid technologies for existing customers to disconnect from the distribution
network and to install and operate their own “stand-alone” electricity generation plant. However, from a customer’s
point of view connection to the distribution network provides considerable convenience and in most cases the
most economic solution given that as demonstrated in the Black Forest Station case study, the capital cost of
distributed generator can be very high – particularly where a convenient micro-hydro resource does not exist.
Minister of Energy (2008) Review Of Section 62 Of The Electricity Act 1992 (2013 Review) Cabinet paper, released May
2008.
30
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An exception may occur in situations where a customer is faced with significant new network connection costs
involving several kilometres of feeder line which, at a cost between $30,000 and $40,000 per kilometre in the case
of relatively isolated properties, could mean that may be a cost-benefit in installing distributed generation plant.
Also, the costs of renewable energy generation technologies tend to be very sensitive to coincident maximum
demand and to avoid excessive capital cost, it is necessary for customers to change the way in which electricity is
used in the household or on the farm. Such measures could include the use of wood burners for heating and
possibly hot water, solar water heaters and LPG cooking equipment.
6.3.2
The Opportunities
While the barriers may make alternative supply of electricity less attractive, as the cost of energy rises and the
technology costs reduce, these barriers are expected to become less significant.
Furthermore, distribution system costs are increasing. The cost of upgrading the distribution network, particularly
for rural growth, is increasingly more expensive owing to shortages of metals causing the international price to
rapidly increase. Under regulatory price controls, these costs cannot be readily passed on, particularly where the
growth is occurring at the ends of long, sparsely populated rural feeders, where the rate of investment return are
already low. Similarly, the ODV Handbook31 approach of valuing network assets for regulatory disclosure imposes
historical cost categories which are out-of-date and therefore artificially lower than the actual build costs driven
upwards from increases in labour and materials prices. This results in pressure on new investment decisions
particularly when these may result in sub-optimal rates of return.
Distributed generation may provide an opportunity for lines companies to mitigate these costs where, for example,
there are long sections of distribution network to a customers who have a limited seasonal supply need (i.e. a
woolshed) as in the Stony Creek case study. While lines charges are averaged across the network, the ability to
study an alternative supply option may provide a network efficiency opportunity by removing an underperforming
asset.
In practice, remote rural lines have created connection opportunities as farming practices adopt new electricity
dependant technologies that offer advantages over previous systems - for example, tourist lodges with electric
underfloor or heat pump heating as discussed in the Lilybank case study.
Therefore, removal of sections of distribution network to make an immediate saving in today’s terms, can lead to
forfeiting future potential new connection opportunities which would improve remote lines economics.
Hence from a distribution perspective, the most efficient cost of providing the additional growth requires careful
consideration of the opportunities provided by alternative energy systems ahead of the typical response of
upgrading 40km of overhead distribution network.
6.4
Conclusions
While the economics of alternative energy supplies may appear unattractive in many cases when compared with
the lifecycle costs of upgrading and return on infrastructure development, there may be a case under certain
circumstances where alternative supplies provide a more economic decision as new technologies mature.
There also needs to be a change in mindset where the alternative supply technology instead of comprising
equipment funded by the individual, could become an additional tool in the lines company infrastructure stable
and provided (subject to a reasonable rate of return) as a utility asset, The customer may be responsible for the
Commerce Commission (2004) Handbook for Optimised Deprival Valuation of System Fixed Assets of Electricity Lines
Businesses, 30 August 2004
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fuel source to enable a higher penetration of the technology into the distribution network while being shielded from
the high capital cost. In situations where the customer remains connected to the network, the lines company
would manage the utility nature of the infrastructure or consider contracting the dispatch of the embedded
generation at peak times to support the wider needs of the distribution network.
This appears to be where alternative energy supplies could provide the greatest opportunity for both consumers
and lines companies. Rather than disconnect customers from the grid connection, which is traditional thinking,
there may be opportunity in retaining the connection to support the existing network and delay further capital
expenditure for an immediate upgrade. Based on the Lochaber case study, in situations where a micro-hydro
resource exists and the existing feeder is suitable for power export, such a solution could have potential. The
Lilybank case study is another example where while the existing feeder line is not suitable to enable export of
power, the installation of distributed generation could at least delay the need to upgrade the supply.
Similarly, energy management measures to reduce coincident demand also provide a means to delay upgrade
expenditure in situations where load growth is placing stress on existing supplies.
In the case of the AEL distribution system, irrigation and dairying demand is occurring in remote network locations
where existing capacity is being quickly exhausted. However the seasonal nature of the agricultural sector means
that the load may be dispatched intermittently based on the unique weather pattern of each season. As
demonstrated in the “Voltage Support” case study, the installation of distributed generation in a load growth area
can provide demand support as well as improve supply quality at the end of a long rural feeder and thereby avoid
distribution feeder upgrade in situations where electricity consumption is irregular and may be insufficient to
provide an adequate return on investment.
Using the data provided in Section 4 and set out in Tables 6 and 7, a financial analysis using a discount factor of
5% and assuming a project life of 10 years results in net present values as follows:
Option 1:
Option 2:
Generator hire:
Generator purchase:
$74,360
$199,385
Over time, as connected load matures, then the load centre can be reviewed based on the pattern of load cycles
against varying agricultural cycles to determine which supply system is the most effective. This may result in a
new supply point being established nearer the new load centre as a more capital efficient result. This could use
the deferred capital from not upgrading the original feeder capacity which would become stranded and its
increase in value optimized down on the company’s balance sheet once the new substation was established. The
new substation could be sized based on known growth trends and also retain the alternative energy supply
equipment for peak demand reduction as a demand response tool to alleviate times of transmission constraint.
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7.0
CONCLUSIONS
1.
In the localities supplied with electricity through AEL’s distribution system, even where consumers can be
described as “remote”, the likelihood is that the supply line to the consumer also supplies a number of
other consumers separated by a few kilometres. The cost of operating and maintaining supply lines on a
“per-customer” basis is therefore relatively small and in situations where the consumer uses significant
amounts of electricity, the incentive to change to distributed generation is likely to be small from both the
lines company’s and consumer’s points of view. This is particularly the case in situations where there is
no potential for micro-hydro generation given the relatively high installation cost of small-scale wind and
solar photovoltaic generation systems.
Where a reliable hydro generation resource exists and where this resource can be developed at low cost
and without adverse environmental impacts, the economics can improve where the existing supply line is
suitable for export of surplus power back into the grid via the distribution network.
In situations where an existing supply line requires replacement owing to increased power demand,
storm damage or general deterioration, then the use of distributed generation to avoid or defer the cost of
line replacement may be justifiable on economic grounds particularly where there is a good hydro
generation resource. The Lilybank Station analysis provides a good example of the potential benefits.
A similar situation could occur in the case where a new supply line is required – such as to a new “lifestyle” residence. In such circumstances, the lines company is entitled to charge the consumer the cost of
the new supply line and the use of distributed generation could become economic, particularly if there is
a good hydro generation resource or a good wind resource
Where a customer using very little electricity – such as a holiday home or a woolshed - is supplied by a
dedicated line several kilometres long, distributed generation even using a diesel generator may be
justifiable on economic grounds, at least from the lines company’s perspective. The Stony Creek case
study demonstrates that because the economics are dictated largely by the balance of the lines cost
avoided (ie distance x cost per km) and the amount of electricity delivered (ie balance between the cost
of distributed generation and and grid avoided generation), there are situations where distributed
generation can be justified. In this respect, the “breakeven line lengths” set out in Table 12 are also
relevant. A downside of situations where diesel is used is the resultant increase in CO2 emissions.
Similarly, diesel generation can provide an solution where a lines company is experiencing unacceptable
voltage drops in parts of the rural network owing to seasonal demands which otherwise would require
expensive upgrades of feeder lines.
The adoption of energy management measures such as solar water heating, wood burners and heat
pumps to reduce electricity demand can provide benefits to both consumers and lines companies in
situations where the existing supply is under stress during periods of high demand. However, the capital
costs involved and in the case of wood burners, the relative inconvenience present barriers that would
need carefully assessment. The use of LPG for cooking may also be seen as inconvenient given the
need to refill cylinders at a filling station over 20 kilometres away. The high capital cost of the
technologies involved, such as solar water heating where low winter temperatures require the use of
closed-loop systems, may also be a barrier.
2.
3.
4.
5.
6.
7.
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APPENDIX A
Outline of Methods Used and Assumptions Made when
Allocating Energy Use by Category at Each Site
A.1
Space Heating
For each site, notional building areas were estimated based on numbers of occupants. Buildings were assumed to
be provided with roof insulation except in the case of Lilybank Station guest accommodation where wall insulation
was also assumed.
ALF3 software (see earlier reference) was used to estimate space heating energy consumption using Tekapo as
the climate reference point. Allowance was made in the case of Black Forest Station holiday accommodation for
low or zero occupancy in winter.
Electric heating is assumed and is understood to be the case at all sites. At Lilybank Station, this is in the form of
under-floor heating.
A.2
Hot Water
Hot water consumption was estimated assuming each occupant takes one shower a day of 7 minutes duration
with a water flow of 10 litres/minute. The number of occupants varies considerably through the year and
allowances were made for lower occupancy during “off-seasons”. An allowance was made for general hot water
usage plus system losses.
A.3
Lighting and Power
Electricity use for lighting and general power (cooking, laundry, dishwashing, TV) was estimated using data in
Kanuka-Fuchs,R. (c2005) “Household Appliances” in Sustainable Building Sourcebook, Waitakere City Council.
A.4
General Farm Use
In the absence of any data, the balance remaining at each site after deducting the estimated accommodation
consumption from the metered total was attributed to general farm use.
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APPENDIX B
Estimates of Impact of Energy Management Measures.
Breakdowns of the estimates of the impact of energy management measures set out in Table 2 are shown below:
Table B.1:
Impact of Energy Management Measures by Category
Estimated Electricity Consumption - kWh/ye
SPACE HEATING
HOT WATER
COOKING
OTHER
TOTALS
BLACK FOREST:
Without EM Measures
With EM Measures
TOTAL REDUCTION FOR SITE
37000
4000
33000
11000
4000
7000
7000
1000
6000
8000
6900
1100
63000
15900
47100
LOCHABER:
Without EM Measures
With EM Measures
TOTAL REDUCTION FOR SITE
29000
2000
27000
10500
2000
8500
2400
400
2000
8000
4500
3500
49900
9900
40000
113000
38000
75000
41800
14000
27800
58000
1100
56900
131900
15000
5000
10000
37800
LILYBANK (post – expansion):
Guest accommodation
Without EM Measures
With EM Measures (heat pumps)
Reduction in electricity consumption
Farm staff accommodation
Without EM Measures
With EM Measures
Reduction in electricity consumption
TOTAL REDUCTION FOR SITE
154800
52000
102800
14200
14200
5000
16000
8000
8000
8000
Notes:
(1) Annual consumption is based on 2007 data and excludes “general farm use”.
(2) The “Other” category includes potential savings from use of CFL lighting, use of “cold” wash and reduced usage of dishwashers.
Empower
94000
14100
79900
182700