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PARKES SHIRE COUNCIL: DISTRIBUTED ENERGY PLAN

 

 

 

Final report

For Parkes Shire Council

Authors

Jay Rutovitz, Ed Langham, Nicky Ison, Chris Dunstan

Institute for Sustainable Futures

UTS 2011

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan i

Disclaimer

While all due care and attention has been taken to establish the accuracy of the material published, UTS/ISF and the authors disclaim liability for any loss that may arise from any person acting in reliance upon the contents of this document.

Acknowledgements

The authors would like to acknowledge Chris Cooper, who has contributed a great deal through the DCODE model, and the help given by Brad Byrnes and Andrew Francis of Parkes Shire Council.

Please cite this report as: Rutovitz, J., Langham, E., Ison, N., and Dunstan, C. 2011. Parkes Shire Council: Distributed Energy Plan. Prepared for Parkes Shire Council by the Institute for Sustainable Futures, University of Technology, Sydney.

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan ii

TABLE OF CONTENTS

ABBREVIATIONS ....................................................................................................................... V 

EXECUTIVE SUMMARY .............................................................................................................. 6 

1  INTRODUCTION ................................................................................................................ 13 

2  PARKES – CURRENT SITUATION AND COST PROJECTION FOR BUSINESS AS USUAL ............. 14 

2.1  Projected changes from the Water Factory project ................................................ 15 

3  ENERGY PRICES AND PROJECTED INCREASES .................................................................. 16 

3.1  Methodology ........................................................................................................... 18 

4  NETWORK CONSTRAINTS / POTENTIAL COST SAVINGS ....................................................... 21 

5  SUPPLY OPTIONS ............................................................................................................. 23 

5.1  Contractual arrangements for self generation: “contractual net metering” ............. 23 

5.2  Co-generation/Trigeneration ................................................................................... 23 

5.3  Gas engines at major pumps .................................................................................. 26 

5.4  Wind ....................................................................................................................... 27 

5.5  Solar PV (with varying level of FIT) ........................................................................ 28 

5.6  Solar CST ............................................................................................................... 29 

5.7  Bioenergy ............................................................................................................... 31 

6  EFFICIENCY / LOAD MANAGEMENT OPTIONS ...................................................................... 32 

6.1  Buildings ................................................................................................................. 32 

6.2  Pumps .................................................................................................................... 32 

6.3  Solar pool heating ................................................................................................... 33 

6.4  Water efficiency ...................................................................................................... 33 

6.5  Demand side response ........................................................................................... 33 

7  SCOPING EXERCISE OUTCOMES ....................................................................................... 35 

7.1  Greenhouse implications for PSC .......................................................................... 39 

8  BUSINESS CASE .............................................................................................................. 40 

8.1  Options for further investigation (outcomes from scoping workshop) ..................... 40 

8.2  Business case parameters ..................................................................................... 40 

8.3  Solar pool heating ................................................................................................... 41 

8.4  PV with and without feed in tariffs .......................................................................... 42 

8.5  Gas engines at High Street combined with DSR .................................................... 45 

8.6  Demand Side Response with major water pumps .................................................. 49 

8.7  Wind turbine at Back Yamma pump site ................................................................ 49 

8.8  Concentrating solar thermal ................................................................................... 51 

9  BUSINESS CASE SUMMARY RESULTS ................................................................................ 54 

9.1  Energy expenditure ................................................................................................ 56 

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan iii

9.2  Greenhouse emissions ........................................................................................... 57 

10  COMMUNITY BENEFIT ................................................................................................... 58 

11  DISTRIBUTED ENERGY PLAN – RECOMMENDATIONS AND NEXT STEPS ............................ 59 

REFERENCES ..................................................................................................................... 61 

LIST OF TABLES AND FIGURES TABLE 1: PROJECTED ELECTRICITY PRICES FOR PARKES SHIRE COUNCIL (NOMINAL DOLLARS) .. 17 

TABLE 2: PRICE COMPONENTS APPLIED TO PROJECTED GAS PRICES FOR PSC .......................... 20 

TABLE 3: ENERGY OPTIONS SUMMARY (COSTS INDICATIVE ONLY) ............................................. 37 

TABLE 4 RISKS AND BENEFITS OF DIFFERENT TECHNOLOGIES – SCOPING ASSESSMENT ............ 38 

TABLE 5: POOL HEATING – DETAILS AND OUTCOMES ................................................................ 42 

TABLE 6: SOLAR PV – DETAILS AND OUTCOMES WITH AND WITHOUT FEED IN TARIFF, ................ 43 

TABLE 7 PV POTENTIAL SITES ................................................................................................. 45 

TABLE 8: 160KWE GAS ENGINE – DETAILS AND OUTCOMES ...................................................... 47 

TABLE 9: 2 X 160KWE GAS ENGINES – DETAILS AND OUTCOMES ............................................... 48 

TABLE 10: SMALL WIND TURBINE AT BACK YAMMA PUMP SITE – DETAILS AND OUTCOMES .......... 51 

TABLE 11: CONCENTRATING SOLAR THERMAL AT WATER FACTORY – DETAILS AND OUTCOMES 53 

TABLE 12 ENERGY OPTIONS – BUSINESS CASE OUTCOMES DETAILS.......................................... 55 

FIGURE 1: ELECTRICITY COST BY TYPE AND NUMBERS OF SITES ............................................... 14 

FIGURE 2: CURRENT VARIABLE CHARGES FOR PSC ELECTRICITY ............................................. 16 

FIGURE 3: PSC HIGH ELECTRICITY TARIFF PROJECTED BREAKDOWN - LOW AND HIGH CARBON

SCENARIOS (NOMINAL DOLLARS).............................................................................................. 17 

FIGURE 4: PSC LOW ELECTRICITY TARIFF PROJECTED BREAKDOWN - LOW AND HIGH CARBON

SCENARIOS (NOMINAL DOLLARS).............................................................................................. 17 

FIGURE 5: GAS PRICE PROJECTIONS FOR PARKES SHIRE COUNCIL ($NOMINAL) ........................ 18 

FIGURE 6 - POSSIBLE TRIGENERATION CONFIGURATION AT COUNCIL BUILDING CLUSTER .......... 25 

FIGURE 7 WIND RESOURCES AROUND PARKES ........................................................................ 27 

FIGURE 8: SOLAR RESOURCE AROUND PARKES ....................................................................... 29 

FIGURE 9 SCHEMATIC DIAGRAMS OF THE FOUR CONCENTRATING SOLAR THERMAL SYSTEMS. .... 30 

FIGURE 10: EXISTING DEFUNCT SOLAR POOL HEATING INFRASTRUCTURE ................................. 33 

FIGURE 11: ENERGY OPTIONS FOR PSC ($/ MWH, HIGH AND LOW TARIFF) ............................... 36 

FIGURE 12: GREENHOUSE EMISSIONS REDUCTION FROM SELECTED ENERGY OPTIONS .............. 39 

FIGURE 13: POOL HEATING – NPV, LIFETIME BENEFIT, AND SIMPLE PAYBACK AT A RANGE OF

CAPITAL COSTS ....................................................................................................................... 41 

FIGURE 14: PV INSTALLATIONS COMPARED (WITH AND WITHOUT FIT, DIFFERENT CAPITAL COSTS, AND AS SMALL-SCALE AND LARGE-SCALE UNITS) ..................................................................... 43 

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan iv

FIGURE 15: PV WITHOUT A FEED IN TARIFF: NPV, LIFETIME BENEFIT, AND SIMPLE PAYBACK AT A

RANGE OF CAPITAL COSTS ....................................................................................................... 44 

FIGURE 16: 160 KWE GAS ENGINE AT HIGH ST: NPV, LIFETIME BENEFIT, AND SIMPLE PAYBACK AT

A RANGE OF CAPITAL COSTS .................................................................................................... 46 

FIGURE 17: 2 X 160 KWE GAS ENGINES AT HIGH ST: NPV, LIFETIME BENEFIT, AND SIMPLE

PAYBACK AT A RANGE OF CAPITAL COSTS................................................................................. 48 

FIGURE 18 WIND: NPV, LIFETIME BENEFIT, AND SIMPLE PAYBACK AT A RANGE OF CAPITAL COSTS

.............................................................................................................................................. 50 

FIGURE 19: CONCENTRATING SOLAR THERMAL: NPV, LIFETIME BENEFIT, AND SIMPLE PAYBACK

AT A RANGE OF CAPITAL COSTS ............................................................................................... 52 

FIGURE 20 ENERGY OPTIONS COMPARED: INTERNAL RATE OF RETURN AND SIMPLE PAYBACK ... 54 

FIGURE 21 PSC ENERGY EXPENDITURE – BAU AND COST EFFECTIVE ENERGY OPTIONS ........... 56 

FIGURE 22 PSC ENERGY EXPENDITURE – BAU AND MARGINAL ENERGY OPTIONS ..................... 56 

FIGURE 23 PSC GREENHOUSE EMISSIONS – BAU AND COST EFFECTIVE ENERGY OPTIONS ....... 57 

FIGURE 24 PSC GREENHOUSE EMISSIONS – BAU AND MARGINAL ENERGY OPTIONS ................. 57 

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan v

Abbreviations

c/kWh cents per kilowatt hour

CBD Central business district

CHP Combined Heat and Power

CPI Consumer Price Index

CST Concentrating Solar Thermal

DCODE Description and Costs of Distributed Energy

DSR Demand Side Response

FiT Feed-in Tariff

ESS Energy Savings Scheme

GGAS Greenhouse Gas Abatement Scheme

GWh Gigawatt hour

HV High Voltage

ISF Institute for Sustainable Futures

kVA Kilovolt ampere

kW Kilowatt

kWe kilowatts electrical generation capacity

kWh Kilowatt hour

LGA Local Government Area

LGC Large Generation Certificate (formerly known as a REC)

LRET Large-scale Renewable Energy Target (formerly part of the RET)

MW Megawatt

MWh Megawatt hour

PSC Parkes Shire Council

REC Renewable Energy Certificate

RET Renewable Energy Target

SRES Small-scale Renewable Energy Scheme (formerly part of the RET)

STCs Small-scale Technology Certificate (formerly known as a REC)

SWEP Sustainable Water and Energy Plan

SGU Small Generation Unit – renewable energy generator that gains support under the Small Scale Renewable Energy Scheme (SRES)

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan 6

Executive Summary

Parkes Shire Council (PSC) is investigating the options to reduce energy use and generate local energy from renewable or low carbon sources, with the aim of delivering significant financial and environmental benefits. To this end, PSC commissioned the Institute for Sustainable Futures to produce a Distributed Energy Plan to form part of PSC’s Sustainable Water and Energy Plan (SWEP).

ISF undertook a high level assessment of the energy options by assigning indicative costs and comparing them with projected increases in NSW electricity prices, and assessing risks and benefits in the Parkes context. Six options were selected for further investigation in consultation with PSC.

Implementing the proposed Distributed Energy Plan could provide significant economic, social and environmental benefit to both PSC and the wider Parkes community, enabling PSC to invest more in other essential community services and programs. It will directly reduce council’s own emissions and costs, and increase the profile of sustainable and low carbon technologies. An important element of the plan is to ensure that the Parkes community is informed about the energy actions implemented, enabling businesses, organisations and residents to learn from the Council’s experience. There may be potential in the future to facilitate community implementation of distributed energy, for example by arranging or facilitating bulk purchase co-operatives, so that residents can gain access to the same cost effective solutions as PSC itself.

The context Parkes Shire Council spent $1.3 million on electricity in 2010, used 9,600 MWh of electricity, which resulted in 10 thousand tonnes of greenhouse gases. Pumps account for by far the greatest proportion (83% of electricity, and 72% of the cost). Street lighting is the next largest use, followed closely by buildings. Unless PSC takes action, bills are likely to reach at least $2.6 million by 2020, as electricity prices are expected to double in the next ten years.

PSC has two electricity tariffs, a high one for buildings, and a lower which covers the major pump sites. The current variable component of the two tariffs is shown in Figure E1 below, along with the projection to 2020. Pump sites also pay a fixed capacity charge according to the size of the load1. The high tariff has currently has an average rate of just over 20 c/kWh, while the low tariff average rate is only 10 c/kWh, so the economics of energy options depends strongly on whether they offset electricity at high or low tariff sites.

Figure E1 Electricity prices to 2020 – high and low tariff, medium projection

1 Both tariffs comprise peak, off peak, and shoulder times of day, and the values shown are the averages of actual use at each rate.

0

10

20

30

40

50

2009/10 2014/15 2019/20 2009/10 2014/15 2019/20Electricity Price (c/kWh)

HIGH  TARIFF                                    LOW TARIFF

Carbon price

Current environmental schemes

Network Charges

Energy 

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan 7

8.9% reduction

6.2% reduction

5.7% reduction

4.1% reduction

3.5% reduction

2.3% reduction

1.6% reduction

0.5% reduction

0.1% reduction

9,000 9,200 9,400 9,600 9,800 10,000 10,200 10,400

Solar thermal generation

Leak control

CBD trigeneration

Solar PV no FIT (300 kW)

Gas engines at major pumps

Wind

Trigeneration (PSC only)

Commercial energy efficiency

Solar PV 60c FIT (10 kW)

Business as usual

Tonnes CO2 per year

Energy options and scoping exercise outcomes The options listed below were investigated in the initial scoping exercise. Six options were selected in consultation with PSC staff and Councillors for further investigation and development of a business case. Two options were not included in the business case because they were clearly economic and PSC was going to pursue them in any case, and three options were not taken further because they were unlikely to be effective under current or expected conditions.

Options investigated further and business case developed

Gas engines at major pumps [investigated for High Street]

Demand side response [investigated further]

Wind energy [investigated for remote pump sites]

Solar PV [investigated for buildings, without a feed in tariff]

Solar pool heating [investigated for Olympic Pool]

Concentrating solar thermal [investigated for the Water Factory site]

Options not investigated further, because PSC will pursue as clearly cost effective

Water use and leak reduction

Building energy efficiency

Options not investigated further, as unlikely to prove economic in current conditions, or significant obstacles for implementation

Cogeneration/ trigeneration in Council buildings only, and on a CBD scale. CBD scale cogeneration very difficult to implement, and economics of Council buildings cogeneration unlikely to prove positive.

Pump efficiency was not investigated because PSC has already carried out significant pump upgrades. PSC to keep under review.

Bioenergy not investigated further because unlikely to be economic in the Parkes region because of extensive use of no till farming.

The energy supply and efficiency options described could reduce Parkes Shire Council annual greenhouse emissions by more than 30% per year. Some are zero emission options (energy efficiency, leak control, solar PV, solar thermal generation, and wind energy), while trigeneration and gas engines reduce emissions by about 30% for each unit of electricity displaced. The potential reduction in greenhouse gas emissions achieved by the outlined energy supply options are shown below. The emissions reduction is directly proportional to the amount of electricity displaced,

Figure E2 Greenhouse

emissions reduction from

selected energy options

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan 8

Table E1 Risks and benefits of different technologies POTENTIAL RISKS BENEFIT

Leak control Savings may be reduced by rebound effect if water use was cost limited

VERY LOW Reduces energy use and improves environmental indicators for water

HIGH

Solar pool heating

Savings may not be as high as anticipated

LOW Very cost effective, but relatively small scale

HIGH

(LIMITED

SCALE)

Energy efficiency (buildings)

Savings may not be as high as anticipated

LOW Generally increases comfort and reduces cost

HIGH

(LIMITED

SCALE)

Gas engines at major pump sites

Profitability hinges strongly on a large number of variables that could vary significantly from estimates provided

LOW-MODERATE

Relatively large volume of electricity offset compared to PV

MODERATE

CBD trigeneration

Very significant investment in facilitation without certainty of project go-ahead

HIGH Potentially more cost-effective than small-scale cogeneration.

HIGH

Wind Possible Community opposition, or planning issues re siting wind turbines, Wind monitoring may show output to be lower than expected. REC price fluctuations

MODERATE Large potential to offset electricity use. Zero emission technology.

MODERATE

Solar thermal generation

Technology not well established, leading to delays and/ or price increases

MODERATE

- HIGH Large potential to offset electricity use. Zero emission technology

MODERATE

Solar PV with 60c/kWh FIT

Availability finished, so limited to small scale

VERY LOW Economic return guaranteed by FIT Zero emission technology

MODERATE

PSC only Trigeneration

Relatively high cost of feasibility, design and capital investment for potentially low utilisation Value undercut if very cost effective options like solar water heating and building efficiency are undertaken, and site load is offset by large scale solar PV as currently planned by PSC

MODERATE Improve efficiency of energy supply and use (reduce emissions)

MODERATE

Solar PV without FIT (at $4.5/ Watt)

Capital cost from tender may be higher than expected, but known prior to expenditure.

LOW

Modular technology, can be sited to correspond with PSC usage

HIGH

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan 9

Business case ISF produced a twenty five year cash flow for the selected options, which forms the basis for the Distributed Energy Plan. The Net Present Value (NPV) , the Internal Rate of Return (IRR), the Lifetime Benefit with no discounting applied to the future savings, and the simple payback are calculated (the simple payback is the number of years until energy cost savings repay the capital sum). The calculations assume that repayment is made over 10 years, with an interest rate on borrowing of 8.1%, and a discount rate of 7% used for the NPV calculation.

The economics of the all options selected for business case are highly dependent on the projection for the energy prices, as these determine the avoided costs. These are relatively certain until 2015, but become increasingly hard to predict after that.

Figure E2 shows the options selected for analysis in the business case, at the scale designed to use all or most generation on site, and using the best guess of the capital cost. PV is assumed to be installed at sites using the high electricity tariff, while Solar CST, wind energy, and gas engines are assumed to be at sites using the low tariff. Table E2 gives detailed outcomes from the listed options.

Solar pool heating has an excellent rate of return, although the scale of the option is small, so the savings are small compared to PSC total energy expenditure. PV without a FIT, at a capital cost of $4,500 per kW, also has an excellent rate of return, as does PV with a 60-cent FiT.

The gas engine at 160 kW has a reasonable rate of return, but a slightly negative positive net present value. The outcome is heavily dependent upon a number of variables which require further investigation. The other three options (gas engines at 320 kW), solar thermal and wind all have positive rates of return, but negative net present values. The economics in these cases warrant further review, with investment decisions deferred until more accurate cost and output information is available. In each case, the business case could improve (or worsen) once actual costs are obtained.

Figure E2 Energy options: Internal Rate of Return and simple payback

5 years10 years15 years20 years

0%

10%

20%

30%

40%

Pool heating

PV no FIT

PV 60c FIT

Gas Engine 160

 kW

Wind

Gas Engine 320

 kW

Solar CST

Energy options compared

IRR Simple payback

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan 10

Table E2 Energy options – business case results

TE

CH

NO

LO

GY

Po

ol h

eati

ng

PV

no

FIT

PV

60c

FIT

Gas

En

gin

e 16

0 kW

Gas

En

gin

e 32

0 kW

Win

d

So

lar

CS

T

Year of installation

2012 2012 2011 2012 2012 2014 2016

Cost per kW assumed ($’000)

n/a  $4.5  $6.0  $1.7  $1.7  $7.0  $7.5 

Installed capacity (kW) n/a  330 kW  10 kW  160 kW  320 kW  100 kW  300 kW 

Total capital expenditure ($’000)

$54  $854  $39  $279  $548  $700  $2,250 

Net Present Value (NPV) ($’000)

$154  $1,074  $34  ‐$14  ‐$99.1  ‐$96.1  ‐$656.7 

IRR 27.6%  16.7%  16.4%  7.0%  6.0%  6.2%  4.4% 

Lifetime benefit (no discount) ($’000)

$429  $3,538  $105  $507  $566  $491  $583 

Simple payback 3  6  5  15  15  13  15 

1st year of positive return Year 3  Year 2  Year 2  Year 11  Year 11  Year 11  Year 11 

Greenhouse savings per year

46 tonnes 

486 tonnes 

15 tonnes 

367 tonnes 

367 tonnes 

240 tonnes 

928 tonnes 

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan 11

Energy expenditure PSC energy expenditure is set to rise steeply over the next twenty years. The energy options modelled are not sufficient to offset the price rises, but could mitigate them.

The effect of the combined energy options on PSC energy expenditure are shown in Figure E2. The most cost effective options are pool heating, demand side response PV at $4500 per kW, the smaller gas engine, and wind turbines. This package of options is virtually cost neutral cost until 2021. After that there are significant cost savings, amounting to $500,000 per year by 2030.

The effect of including solar CST in the package and an “all options” scenario, in which solar CST, the second gas engine, and an additional 100 kW of PV at a lower support level are included, are shown in Figure E2. Solar CST increases the energy expenditure considerably during the period to 2020, but from 2023 PSC is better off. After 2026 savings are about $600,000 per year.

Figure E2 PSC energy expenditure (nominal $) – BAU and distributed energy options

Greenhouse emissions

All of the options modelled reduce PSC emissions, but the scale of reduction varies considerably, from 29 tonnes in the case of 20 kW PV installed with a 60-cent FIT, to nearly 640 tonnes savings per year for 300 kW of solar CST. Figure E2 shows the effect of the different options on PSC’s business as usual carbon emissions. Pool heating and DSR demand side response are included in all options. Implementation of all options has the greatest effect, with a reduction of nearly 18%. Installation of 300 kW of PV alone reduces emissions by just over 4%. Implementing pool heating, 300 kW of PV, a single gas engine, and wind energy reduces emissions by 10%.

Figure E3 PSC greenhouse emissions – BAU and energy options

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

Annual eemissions

Business as usual

All options

DSR, Pool ht, PV, Gas, Solar CST

$1.0 m

$1.5 m

$2.0 m

$2.5 m

$3.0 m

$3.5 m

$4.0 m

$4.5 m

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029Annual energy expenditure 

Business as usual

All options

DSR, Pool ht, PV, Gas, Solar CST

DSR, Pool ht, PV, Gas, Wind –  most cost effective options

DSR, Pool ht, PV, Gas, Wind: most cost effective options

Annual energy expenditure

Annual emissions

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan 12

Distributed energy plan – recommendations and next steps ISF recommends that Parkes Shire Council implement the most cost effective package of options as soon as possible, and obtain further information on the options with positive returns but internal rates of return less than 10. The recommended Distributed Energy Plan is given below.

The most cost effective package of options from the business plan includes: Demand Side Response using PSC pump sites, solar pool heating, and PV at multiple sites at up to 100 kW per site (actual capacity to be determined by what is used at the site).

The next options for consideration are installation of 150 – 300 kW gas engine/s at the High Street pump site, 2 x 50 kW wind turbines at Back Yamma pump site, and a 300 kW of concentrating solar thermal facility at the new Water Factory site.

The Plan has the potential to reduce PSC’s long term energy expenditure and greenhouse gas emissions by 18%, equivalent to $700,000 and 2 million tonnes of CO2 per year.

Parkes Shire Council Distributed Energy Plan

ACTION TARGET

DATE

1) Implement the planned program of leak control, and investigate further opportunities to reduce water use.

2011

2) Investigate & implement a program of building energy efficiency options

2011

3) Obtain quotations & implement solar pool heating 2011

4) Commence negotiations for a Demand Side Response scheme 2011/12

5) Install 10 kW PV systems at the agreed 60 cent FIT site 2011

6) Install 290 kW on buildings provided suitable prices are obtained. 2011/12

7) Install public display for implemented Distributed Energy options, 2012

8) Initiate discussions with Essential Energy about the potential to offset street lighting or other PSC energy costs under a ‘contractual net metering’ arrangement, and the potential for PSC energy measures to be eligible for Network Support Payments.

2011

9) Install 150 kW gas engine at High Street pump site, conditional on the outcomes for capital cost, gas price, and network payments.

2012/13

10) Install 100 kW wind at Back Yamma Pump site, depending on the outcome of wind monitoring, capital cost, and annual energy output.

2012/13

11) Install solar CST at the Water Factory site, dependent on the further costing, and availability of equipment with suitable warranties.

2016/17

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan 13

1 Introduction

Parkes Shire Council (PSC) is investigating the options to reduce energy use and generate local energy from renewable or low carbon sources. This reflect PSC’s wish to reduce long term operating costs and future proof against energy price rises, and is part of their commitment to sustainability and addressing climate change, The aim is to deliver significant financial and environmental benefits by reducing the Council’s dependence on increasingly high cost grid electricity, which is almost entirely fossil fuel generated. To this end, PSC commissioned the Institute for Sustainable Futures to produce a Distributed Energy Plan to form part of PSC’s Sustainable Water and Energy Plan (SWEP).

Stage 1 of developing a Distributed Energy Plan for PSC was a high-level options assessment to determine the most suitable energy options for Parkes. The study assigned indicative costs to the options, compared them with projected increases in NSW electricity prices, and qualitatively assessed the risks and benefits of each in the Parkes context. The outcomes of the scoping exercise, revised with the information from subsequent research, are shown in Section 7, and the original scoping report is available from PSC.

During Stage 2, ISF held a workshop with PSC staff and Councillors to select options for further investigation. The comparative costs and the risks and benefits of the distributed energy options were presented, and six options were selected for further investigation. The outcomes of the workshop are presented in Section 8.1. ISF also met with other stakeholders to gain insight to the potential for or limitations associated with different options.

Stage 3 of the plan development included further research on the costs and practicality of the selected options and construction of a high-level business case, including a cash flow model and calculation of the returns on investment. The business case for each option is presented in Section 8. The effect of combined options on PSC’s energy expenditure and greenhouse emissions was compared to the business-as-usual (electricity from the grid) case, and is presented in Section 9.

The business case, combined with the risk and benefit matrix, is the basis for the Distributed Energy Recommendations and Next Steps provided in Section 11.

Guide to this report

Sections 2, 3, and 4 give the background for the development of the Distributed Energy Plan, namely PSC’s current and prospective energy use, projected energy prices to 2020, and the constraints and opportunities associated with the electricity network.

Sections 5 and 6 outline the energy supply, efficiency and load management options considered in the scoping report and the business case.

Section 7 gives the outcomes of the scoping report, adjusted to reflect the additional research undertaken during Stage 3.

Sections 8 and 9 gives the outcomes of the business case for those options selected for additional investigation.

Section 10 outlines the potential benefits to the community from pursuing the Distributed Energy Options, and different ownership models that could be considered.

Section 11 gives the recommendations and next steps to deliver the Distributed Energy Plan.

Institute for Sustainable Futures, UTS April 2011

Parkes Shire Council: Distributed Energy Plan 14

2 Parkes – current situation and cost projection for business as usual

Parkes Shire Council spent $1.3 million on electricity in 2009/2010, and used 9,600 MWh.

Figure 1: Electricity cost by type and numbers of sites

Pumps use by far the greatest proportion, consuming 83% of the Parkes Shire Council electricity, and accounting for 72% of the cost. Street lighting is the next largest category of use (7% of the energy use, 12% of the cost), closely followed by buildings (6% of the energy use, 9% of the cost).

As discussed in the previous section, electricity prices are set to double in the next ten yearsa. This is likely to have the effect of increasing PSC annual electricity bill by $1.3 million per year by 2020, even if usage remains constant. If the estimated use at the Water Factory is included, bills increase by $1.4 millionb.

The largest buildings account for most of the building energy use, with just four of the twenty seven buildings using 87% of building energy total, and accounting for 80% of the cost. Likewise, the three largest pumps consume 70% of pump energy.

Looking at the energy use from a spatial perspective, 27% of electricity use (2 GWh per year) and 26% of costs occur within Parkes centrec.

a Energy prices are set to double in nominal terms, or increase by 80% in real terms (2009/10 dollars). b In real terms (2009/10 dollars) energy bills increase by $0.8 million, including the Water Factory. c Assuming one third of street lighting occurs within Parkes.

Pumps (20), $976,738

Street lighting, $160,623

Buildings (27), $110,212

Pools (6), $44,511

Water treatment (4), $14,502

Sewage treatment (4), $2,947

Park/ carpark/ lighting (52),

$35,140

Dams (3), $5,667

Total cost $1.3 million, total energy 9.6 GWh. Average annual data for 2008/9 and 2009/10.

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Parkes Shire Council: Distributed Energy Plan 15

2.1 Projected changes from the Water Factory project Parkes Shire Council is at an advanced concept planning stage for new water and sewage treatment facilities, which will have significant effects on current energy use. The three components of the Water Factory project are:

- New water treatment facilities, with expanded capacity from current 8 ML/day to either 22 or 28 ML/day;

- New sewage treatment facility, with 3 ML/ day capacity, changing to aerated digestion (currently using anaerobic), with an associated increase in energy use.

- New 8 km recycled water main, to supply irrigation water to public spaces within Parkes.

It is not clear whether all of these options will go ahead, and what scale of plant will be constructed. The potential impacts on energy use are twofold.

Firstly, energy use in water treatment and sewage is expected to increase six fold, to $100,000 at current energy prices1, compared to $17,500 currently. This is equivalent to a 6% increase in overall energy consumption, and a 7% increase in energy costs.

For the business as usual modelling, it is assumed that the additional water treatment comes on line over two years, in 2015 and 2016, increasing electricity consumption by 85 MWh per year. It is assumed that the additional sewage treatment comes on line over two years in 2016 and 2017, and that the eventual sewage treatment consumption is equivalent to the major equipment running at 40% capacitya, bringing the total electricity consumption at the water factory to 674 MWh by 2017. The major equipment is 168 kW in total.

Secondly, the installation of a recycled water main has the potential to reduce the overall water consumption, thereby reducing the pumping load. While the potential to reduce raw water requirements and therefore pumping costs is referred to several times in the Water Factory Draft Implementation plan, the reduction in raw water consumption is not quantified. Balancing the increase in costs would require a reduction in the region of 10 to 15% in raw water requirements.b However, it is hard to calculate how much of this would avoid growth in demand for water, for example for irrigation, rather than actually reducing consumption.

a The major equipment totals 168 kW, made up of 88 kW aeration, 60 kW sludge pumps, 12 kW of mixer booms, and an 8 kW decanter. b Assuming that costs are reduced proportionately at 9 of the largest 10 pumps, excluding the High St pump).

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Parkes Shire Council: Distributed Energy Plan 16

3 Energy prices and projected increases

Electricity prices PSC electricity prices in nominal dollars are projected to more than double between now and 2020, according to the calculations done for this report. The increases result from agreed and projected increases in network charges, the expected increase in the cost of the Renewable Energy Target as the target level increases, and the likely imposition of a carbon charge.

Parkes Shire Council currently purchases electricity on two tariffs, one that has lower usage changes and a daily demand charge2, and one with higher usage charges, but no fixed demand charge3. The variable charges associated with each one are shown below in Figure 2. There is a significant difference between the variable charges in the two tariffs.

The lower tariff is applied to the large pumps, with a fixed demand charge per day irrespective of usage. Note that only the variable charges are shown here, as these would be offset by either efficiency or on-site generation. If PSC is able to reduce maximum demand at its sites, demand charges could also be reduced. If there are cases where sites are able cease to have Essential Energy (formerly Country Energy) accounts altogether, demand charges are eliminated.

Figure 2: Current variable charges for PSC electricity

Table 1 shows the projected rise in electricity prices for both PSC electricity tariffs. For the both tariffs, the price of electricity in 2020 is projected to be 2.3 times higher than the current electricity price under a high carbon price scenario, and 2.2 times higher under a low carbon price scenario.

Figure 3 shows the breakdown of the high tariff over time. It indicates that the increase in network charges account for by far the largest component of PSC’s high tariff price rise, at 65% and 70% respectively. In 2019/20, a carbon price is projected to account for 9% of the electricity price under a low carbon scenario, rising to 12% with a high carbon price scenario.

Figure 4 shows the contribution by component to the increasing cost of PSC’s low electricity tariff. Network costs account for 39-44% of the cost increase.

0

5

10

15

20

25

Low tariff High tariff

Electricity Price (c/kWh)

NSW ESS

NSW GGAS

Renewable Energy Target

Market Participation

Energy 

Network Charges

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Parkes Shire Council: Distributed Energy Plan 17

Table 1: Projected electricity prices for Parkes Shire Council (nominal dollars)

 Price Increase Scenario 

Electricity Cost ‐ 2009/10 (c/kWh) 

Electricity Cost ‐ 2014/15 (c/kWh) 

Electricity Cost ‐ 2019/20 (c/kWh) 

High tariff  Low   20.09  31.01  43.76

   Medium   20.09  31.28  44.57

   High   20.09  31.55  45.38

Low tariff  Low   10.29  15.73  22.39

   Medium   10.29  16.00  23.20

   High   10.29  16.27  24.01

Figure 3: PSC High Electricity Tariff Projected Breakdown - low and high carbon scenarios (nominal dollars)

Figure 4: PSC Low Electricity Tariff Projected Breakdown - low and high carbon scenarios (nominal dollars)

0

10

20

30

40

50

Low High Low High Low High

Electricity Price (c/kWh)

2009/10                                              2014/15                                          2019/20

Carbon Price 

NSW Solar Bonuses

NSW ESS

NSW GGAS

Renewable Energy TargetMarket Participation

Energy 

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Parkes Shire Council: Distributed Energy Plan 18

Gas prices Gas prices were forecast for two different tariff levels reflecting the scale of usage. The low tariff was constructed to reflect the usage associate with small gas engines around the 300kWe scale. The high tariff was based on residential type small usage tariff, as is currently paid at the Parkes Shire Council pool for water heating. A range of different price projections were applied to these starting tariff levels, resulting in four different scenarios:

1. Low tariff: Low price increase projection

2. Low tariff: Medium price increase scenario

3. Low tariff: High price increase scenario

4. High tariff: Medium price increase scenario only

The final gas contract prices under each of the four tariff scenarios are shown in Figure 5 for the period 2010-2050. All low tariff scenarios start from $10/GJ and increase to between $36/GJ (low projection) and $42/GJ (high projection) by 2050. Note that the steepest increase occurs between 2010 and 2020, reflecting the anticipated price impact of Liquefied Natural Gas (LNG) exports on the east coast gas wholesale market.

Figure 5: Gas price projections for Parkes Shire Council ($nominal)

3.1 Methodology

Electricity prices The projection of electricity prices to 2019/20 for PSC was calculated using the methodology described below. A more detailed description of ISF’s NSW electricity price modelling can be found in Ison and Rutovitz (2011)4.

The percentage price rises in this report are given in nominal dollars, as this was deemed most useful for PSC. The 2009/10 value for the ‘high’ and ‘low’ tariffs are PSC’s current electricity tariffs, with a weighting applied for the peak, shoulder, and off-peak usage for the pump sites (low tariff), and for the major buildings (high tariff). The weightings used are: low tariff, 15% peak, 35% shoulder, 55% off-peak, and high tariff, 20% peak, 54% shoulder, 26% off peak.a

a These were derived from major buildings and major pump usage in the 2004/ 5 accounts.

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Parkes Shire Council: Distributed Energy Plan 19

The current tariffs were then broken down into the following components:

Network charges

Energy

Market participation

Environmental Obligations including the federal Renewable Energy Target, the NSW Greenhouse Gas Abatement Scheme (GGAS), NSW Solar Bonuses and the NSW Energy Savings Scheme (ESS)

Electricity price reports for NSW 2010-2020 were analysed to calculate the likely increase in different components of the electricity price, and a carbon price component was added.

The increase in variable network cost was calculated from Essential Energy’s Annual Network Prices Report 2010-115 and their Statement of expected Price Trends6. The former report provides a low voltage customer network price for 2010/11, while the latter report provides the increase in network price from 2011/12 - 2013/14.

Projecting network cost increases from 2013 to 2020 required making an assumption about the annual increases. An annual 5% increase was used based on MMA (2008)7. This may underestimate the price increase, as other NSW network businesses are expecting to maintain the same expenditure in the planning horizon, which is likely result in similar annual increases in network charges.

ISF has assumed the energy price component will remain constant in real terms between 2009 and 2020. This assumption is supported by MMA’s (2008)8 wholesale electricity price scenario for NSW, which indicates price fluctuations less than or corresponding with CPI. Note however, that there is a significant likelihood that wholesale electricity costs could rise sharply over the next few years as a number of long term coal supply contracts are due for renegotiation between suppliers and major NSW coal fired power stations.

With the exception of the solar bonuses component, the projections of the environmental obligations price components from 2010/11 to 2014/15 were taken from Energy Australia’s schedule of pass-through costs for 160MWh+ NSW customers9. The NSW ESS target is set to increase between 2009 and 2014, and then is capped at 5% of retail sales until 2020. It is therefore assumed that the NSW ESS continues at the same level from 2014/15–2019/20. For REC prices from 2016/17 to 2019/20, ROAM Consulting’s projection of Australia wide REC was used, specifically the scenario for a medium REC price and medium Small Renewable Energy Scheme penetration10. For the year 2015/16 the two data sources were integrated by taking the average value of the previous year from the Energy Australia source and the following year from ROAM Consulting.  

The impact on PSC’s electricity tariffs due to the NSW Solar Bonus scheme has been calculated using NSW Department of Industry and Investment data11.  However, it should be noted that the NSW Government has stated that costs of the Solar Bonus Scheme would not be passed on to electricity consumers, so this cost may not eventuate12.  

Finally, the carbon price component projection was calculated from MMA’s 2008 electricity sector modelling report. MMA modelled five carbon price scenarios, ISF has used the outputs of their high and low scenarios – ‘Garnaut 25%’ and ‘CPRS 5%’ in our electricity price modelling. MMA provides a unit cost increase of electricity in 2019/20 above a baseline scenario associated with a carbon price. This cost was then backcast over the period 2012/13 when a CPRS or Carbon price is proposed to be introduced to 2019/20 to provide an annual carbon unit cost for PSC.

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Parkes Shire Council: Distributed Energy Plan 20

These individual components were then combined to give a total predicted electricity price increase to 2014/15 and 2019/20 for PSC’s high and low tariffs.

Projections after 2020 are very speculative, as many things could change in NSW electricity distribution before then, and prices may be highly influenced by action on climate change. It has been assumed that electricity prices rise by 1% in real terms between 2020 and 2030, and remain constant in real terms after 2030. From 2010 to 2020 the projected increase is 6% per year in real terms. The 1% annual rise projected could be a result of many factors, including a rising carbon price, a greater penetration of gas generation or renewable energy in the mix, or an increase in coal generation costs reflecting renegotiation of long term supply contracts to NSW power stations in response to rising world coal prices.

Gas prices Similar to electricity, gas price projections were constructed by breaking down the tariff into components and forecasting increases on each independently. The components include:

The wholesale price at the Sydney city node (i.e. gas cost including transmission), which was applied as either the lower projection in Treasury modelling by MMA (2008) or the higher projection from Macquarie Research (in IPART 2010). Both projections include an estimation of the impact of Liquefied Natural Gas (LNG) exports on the east coast gas wholesale market.

A ‘distribution and scale mark-up’, reflecting the additional gas delivery and service charge cost for smaller scale operations. All low tariff (small gas engine) scenarios were based around a 2011 final delivered contract price of $10/GJ, which is considered a reasonable negotiated price for a 300kWe gas engine. The high tariff scenario was based on a starting delivered contract price of $15.8/GJ, which is the current PSC gas tariff for pool heating.

A carbon price corresponding to a 5% (low) or 25% (high) national emissions cap scenario based on previous ISF work (Ison & Rutovitz, 2011)13.

Different assumptions around price increases associated with the above components were applied to the four different tariff scenarios. Table 2 below summarises how the gas price increases were applied to each scenario to result in the gas prices seen above in Figure 5.

Table 2: Price components applied to projected gas prices for PSC

 Price Scenario 

Distribution & scale markup 

Wholesale price (city node) 

Carbon price Nominal Escalation 

Low tariff (engines) 

Low  Starting price 

$10/GJ MMA (2008)*  CPRS‐5% cap 

2.3% p.a. inflation 

   Medium  Starting price 

$10/GJ Average of Low 

and High Average of Low 

and High 2.3% p.a. inflation 

  High  Starting price 

$10/GJ Macquarie 

Research in IPART (2010) 

CPRS‐25% cap 2.3% p.a. inflation 

High tariff (pool) 

Medium  

Starting price $15.8/GJ 

(current pool heating tariff) 

Average of Low and High 

Average of Low and High 

2.3% p.a. inflation 

Notes: * All MMA figures were increased by $0.50/GJ to match starting 2010 wholesale prices at $5/GJ for both city node projection sources.

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Parkes Shire Council: Distributed Energy Plan 21

4 Network constraints / potential cost savings

The current increase in energy prices Australia wide is strongly driven by investment in electricity poles, wires and substations. While part of this investment is for replacement of ageing assets, a large portion is required to meet higher reliability standards and to cater for the growth in electricity demand at peak times. This presents a specific opportunity, as the present supply of electricity to Parkes depends on transmission across the Essential Energy network. Further, the sub-transmission line between Parkes and Forbes requires strengthening over the next five years due to a demand growth-related capacity constraint. It is possible that Parkes Shire Council (PSC), through a coordinated local generation and demand reduction program, could potentially play a significant role in assisting or driving the deferral of investment in the upgrade of the sub-transmission network.

It is ISF’s current understanding that the preferred network augmentation option to overcome the constraint is to duplicate the 12km stretch of sub-transmission line between Parkes and Forbes, at an approximate cost of $300,000 per kilometre. Thus it is estimated that the preferred network option would cost in the order of $3.6 million, which under a business-as-usual network development approach would be invested in approximately 2012/13 (timeframe to be confirmed with Essential Energy as plans progress). This investment is being driven by an underlying demand growth in the Parkes area of 0.4 MVA per annum, and potentially a large mining load increase of between 3 and 5 MVA.

Thus if PSC through its generation or efficiency actions or through agreements with other partners (e.g. a concurrent load management agreement with Rio Tinto or large energy users in the CBD) can reduce demand on the network by at least the annual growth rate, then Essential Energy could potentially defer its network investment. Due to the avoided cost of capital (servicing loans and paying dividends) and of asset depreciation, this is worth approximately 10 per cent of the investment value for each year demand growth can be offset.

Thus the potential benefit of PSC’s plans to the Essential Energy network could be worth up to $360,000 per year of network investment deferral. If only the underlying Parkes growth of 0.4 MVA (400 kVA) were required to achieve this deferral, the value of this capacity can be calculated as:

$360,000 / 400 kVA = $900 per kVA per year of deferral (best case)

If the mining proposal goes ahead and additional mining demand of up to 5 MVA (5,000 kVA) was required to achieve this deferral in addition to the underlying Parkes growth of 0.4 MVA (400 kVA), the value of this capacity can be calculated as:

$360,000 / 5,400 kVA = $67 per kVA per year of deferral (worst case)

It can be seen from the above that the magnitude of these capacity values for “network support” vary greatly depending on the outcome and timing of mining proposal and associated network implications. It would be relatively easy for direct PSC actions to offset the underlying load growth of 0.4 MVA per annum for one or more years; however partners are likely to be required to offset the larger 3-5 MVA network load increase in demand if the mining proposal goes ahead.

Given that $67 per kVA is not a significantly large value, it is likely that network support would only have the potential to significantly bolster the PSC business case for distributed energy options if there are one or more years of 0.4MVA deferral possible prior to the mine becoming operational.

The technology options that are likely to be able to achieve this deferral are energy efficiency and load management that reduces demand at the network peak time, or

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Parkes Shire Council: Distributed Energy Plan 22

‘controllable’ distributed generation such as gas-based generation technologies or concentrating solar thermal with storage. Intermittent renewable options such as wind or solar power alone are unlikely to be able to be credited with sufficient reliability to guarantee security of supply.

A midpoint value of $500 per kVA is included as an offset in the cost estimates for each technology that would be credited as reliable capacity or standby generation.

For the Council to obtain a share of these avoided network infrastructure costs would require discussions with Essential Energy and likely a response to a public Request For Proposals regarding cost-effective non-network solutions to the Parkes-Forbes sub-transmission capacity constraint.

Note that it is important that Essential Energy are not disadvantaged financially if they were to support distributed energy options for managing demand on their network in this way. Foregone sales as a result of PSC activities could potentially be claimed through the “D-Factor” regulatory mechanism.

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Parkes Shire Council: Distributed Energy Plan 23

5 Supply options

5.1 Contractual arrangements for self generation: “contractual net metering”

Parkes has high electricity use spread over 113 sites, with the majority of electricity used at pump sites.

If Parkes installs electricity generation, it may offset its own consumption, export to the grid, or a combination of both. Offsetting its own consumption is much more economic, as it effectively earns the retail tariff of 10 – 20 c/kWh, rather than the wholesale (export) tariff of 3 – 5 c/kWh, with a small additional component for the costs of the avoided electricity transmission network because the generator is “embedded” within the distribution network.

This means siting generation equipment where the power is consumed is preferable. However, installing large scale equipment at one or two large sites is not only cheaper than multiple smaller installations, it may be the only practicable option. With the exception of solar PV, which is modular and may be installed at any scale, it is unlikely to be possible to substitute large numbers of small installations of wind, solar thermal generation, or gas generators, for one or two large installations.

If an “aggregated net metering” solution could be negotiated with Essential Energy (formerly Country Energy), whereby energy produced can offset the retail costs at the council’s other numerous sites, the actual physical location of these generators would not matter.

However, this would require innovative arrangements with Essential Energy, which would be a matter for negotiation. Such an arrangement would benefit the profitability of most of the supply options. Initial discussions with Essential Energy indicated that such arrangements would be unlikely, and would certainly take a long time to negotiate.

The options investigated for the business case have been sized to maximise on site use of electricity, and cash flows have been constructed assuming that power exported to the grid will attract the equivalent of the wholesale price only, namely 4 c/kWh.

However, should these or similar arrangements become possible, the economics of several of the energy options would be significantly better. It is recommended that PSC keeps a close watch on the development of this issue.

5.2 Co-generation/Trigeneration

Council buildings only ‘Combined heat and power’ (CHP) systems are highly efficient small (generally) gas-fired power plants that can be located in or on buildings. They not only generate electricity but also use waste heat from the engine operation to produce hot water for water or space heating, or convert the waste heat to chilled water (through “absorption chillers”) for air-conditioning. If an engine is operated to meet electricity and heating needs, the system is referred to as ‘cogeneration’. If in addition to the servicing of heating needs the waste engine heat is also used for the production of chilled water for cooling, the system is known as ‘trigeneration’.

The first scale of CHP for exploration is in the pool area precinct. Based on the available data and originally assuming the need to cater to peak cooling requirements, the load for the council facilities alone was assumed to support a trigeneration system in the order of

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Parkes Shire Council: Distributed Energy Plan 24

200 kWe (kilowatts electrical generation capacity).a While the system was originally sized on the assumption that all (i.e. peak) cooling needs would be required to be supplied by the trigeneration system as there was thought to be no existing electrical centrifugal chillers (trigeneration would be replacing split wall unit HVAC). However, the site visit revealed that centrifugal electric chillers are in place and thus a smaller trigeneration system with better utilisation could be supported. An appropriate system size might thus be closer to 50 kWe, (with hot water pipework under the roadway as a conduit already exists, and an absorption chiller located adjacent the current chilling plant).

The appropriate system would be trigeneration, with the waste heat being used to:

Heat the swimming pool, replacing mains gas from AGL, which currently costs PSC approximately $16,800 per annum. It is assumed that the majority of the gas demand for this application would occur in October-December and April. It is acknowledged that the pool is closed for approximately 5 months per year, from Easter (~April) to October each year.

Provide water heating to the pool shower facility, replacing bottled gas from Origin Energy costing approximately $800 per annum; and potentially to the FDC Centre if it is sufficiently close to the shower block, replacing mains gas of around $650 per annum (extension of this pipework may not be cost effective with such small gas offsets).

Provide space cooling (and heating if run in winter) to the council pool entry and facilities building (not currently cooled), Council Administration Centre, Library and Cultural Centre which would provide an offset in the order of 10-15 per cent of the $90,000 per annum combined electricity bill.b Extending supply of chilled water to other nearby non-council buildings may improve the cost-effectiveness of this option if sufficient and complementary and sufficiently large cooling demand exists in these facilities.

A schematic example of such a system is shown in Figure 6.

Anticipated operating conditions of this kind of system would be to run the trigeneration from 5am – 8pm on weekdays, enough hours per day on weekends to support the pool heating demand, and only during the months of the year the pool is open. This operation would cover both the pool and council building opening hours. It is also possible that there may be sufficient winter heating load in the Council Buildings to warrant partial operation of the system during winter weekdays.

The electricity generated by the system, if operating at an average capacity factor of 45 per cent, would equate to be approximately 200,000 kWh, or around 45 to 50 per cent of the Council’s building energy consumption that would be remaining after the cooling load offset attributable to the trigeneration waste heat. Ideally, if a favourable arrangement could be negotiated with Essential Energy, the energy produced by the trigeneration system would be fed into the grid, after being wired to offset consumption at the Library and Council Administration buildings. Physically connecting other facilities served by hot and/or chilled water pipework to offset retail electricity charges may be expensive and impractical due to the small electricity consumption at these sites.

A system of this small size would face few technical difficulties in connecting to Essential Energy’s Low Voltage (LV) electrical network. The location of Essential Energy connection

a Note that the system as originally conceived would need to be modular (i.e. constitute a series of smaller engines rather than a single large engine) to allow smaller engines to operate at higher loading or be switched off. b This is an estimate only and is not based on electricity end-use data.

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Parkes Shire Council: Distributed Energy Plan 25

points into the low voltage distribution network are not yet known and would need to be clarified in discussions with Essential Energy if this option was to be investigated.

Figure 6 - Possible trigeneration configuration at Council Building Cluster

As will be seen in the DCODE outputs in Section 7, the small scale of this operation would likely result in relatively high delivered cost of electricity. However, this option would likely be more viable in the future if the council decides there is sufficient demand to open the existing pool year-round or to construct an indoor pool on the same site, as raised in the Swimming Pools strategy.

However, this option would only make sense if solar pool heating was not adopted or was not sufficient for a new winter pool heating demand, if building efficiency was not improved, and if solar PV was not already offsetting much of the Admin and Library building retail electricity costs.

Co-generation/Trigeneration (including other CBD partners) It was identified by ISF in the Inception Meeting that the small electrical and heating/cooling loads at the pool precinct may result in a poor system utilisation and resulting high costs of supply. To improve the financial viability of trigeneration it may be possible to increase the scale of the operation, to supply heating, cooling and electrical services to a range of large energy users in the Parkes CBD area. This would achieve some economies of scale in terms of trigeneration plant equipment and bulk gas purchasing power and achieve greater emissions reductions, but would also substantially increase logistical challenges, development timeframes, and institutional barriers to realising the project. The actual proportion of heating, cooling and electrical energy supplied by the system to council facilities would be very small, yet would require significant council investment in facilitation and potentially operation if it were to make financial sense for the council. This approach may be more suitable if the council’s primary driver for trigeneration was to reduce

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Parkes Shire Council: Distributed Energy Plan 26

greenhouse emissions in its broader Local Government Area (LGA), rather than saving money and buffering against electricity price increases in its own operations.

While almost no data is available on the loads of other major buildings in the CBD, it is estimated that a centralised system in the order of 1-2MW may be supported if the system was linked to Coles, Target, Woolworths, the Council’s pool precinct, Big W, and other major users in between these routes. It appears that a system of this scale may be able to be housed on PSC property to the south of Target, or near the Woolworths car park. However, the hot and/or chilled water pipe runs for this configuration would be substantial (650-750m to connect Coles, Target and the pool complex and another 300-350m to connect Big W) which implies high capital cost and thermal losses. A trigeneration system of this size may also likely be required to connect to the High Voltage (HV) network. The locations of Essential Energy’s potential HV connection points are not known.

5.3 Gas engines at major pumps Reciprocating gas engines could be used at the three major pump sites, which between them use more than 70% of PSC electricity. The most efficient use would be to drive the pumps directly using the gas engines, but this would require excessive customisation as the pumps are already in situ. Calculations are therefore on the bases that the engines would generate electricity to run the existing pump motors.

These engines could also be used as standby generators to export electricity at peak times, which would attract income from direct sales, and could attract payment from deferring the need for network expansion. PSC is relatively flexible in its pumping times, which are currently set to maximise use during off-peak periods.

Installation at the three major pump sites would not require any innovative arrangements with Essential Energy regarding net metering, as the gas engines would drive Council pumps, either mechanically, or through the existing electric motors. With grid parallel operation, electricity could also be exported at peak times, when it is profitable to do so.

The major constraint regarding gas engines is the availability of mains gas supply to the pump sites. The gas transmission line running along the Newell Hwy is operated by the APA Group, who are a gas wholesaler and only deal with extremely large end users, if at all. APA’s response to ISF’s inquiry was that it is not feasible for a generator of the scale Parkes Shire Council is investigating to connect to the transmission pipeline directly, which is the closest gas supply point. This response appears to be rooted in the requirement for pressure regulation infrastructure that would be prohibitive for a project of this size.

The High St pump is 30m from a local low-pressure gas distribution line, but Back Yamma is 12km from the nearest distribution network at Forbes, and Back Yamma is 13.5km from the Parkes gas distribution network. At a unit cost for 63mm plastic gas pipe of $34.50 per metre (Rawlinson 2011), these distances would represent over $400,000 in pipe costs alone, before counting civil works and land use arrangements, which are generally more dominant in the total cost breakdown. Thus even if PSC could do the civil works itself as no marginal cost, and a 50% cheaper pipework could be obtained at large volumes, this would still increase total capital costs of a 300kWe engine and ancillaries by over 50 percent. Given the positive but relatively marginal economics of a gas engine at the High St pump, it is unlikely that installation of gas engines at sites remote from the gas network would be economic.

Further, ISF’s original high-level analysis of compressed natural gas or diesel/biodiesel on site suggested that these options would likely also not be an economically viable alternative for the more remote pump sites. If a cost-effective gas transportation and storage option at little more than the $10/GJ range (or equivalent) modelled for High St could be obtained then this may alter the economic feasibility. However this is considered unlikely, and points towards renewable energy options at these remote sites being more viable.

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Parkes Shire Council: Distributed Energy Plan 27

Water Factory Site

5.4 Wind Wind speed is the key determinant of the energy output from wind turbines, and therefore the economic return. However, the wind speed required for an economic wind farm in Australia is quite different to the wind speed needed for economic self generation, as in this case the electricity generation is displacing retail electricity.

An accurate calculation of the expected output from wind turbines at a particular site requires wind monitoring, so that the expected time at each wind speed can be correlated to the wind turbine output characteristics. However, an initial indicative calculation has been made using the annual average wind speed, which is available on the Renewable Energy Atlas for every site in Australia14, and data from the Bureau of Meteorology weather stations. As can be seen in Figure 5, the average wind speed in the Parkes area is 6 –6.6 m/s.

The capacity factora of a wind farm is a measure of how much electricity output there will be from a given set of turbines. Commercial wind developers in Australia generally look for sites with capacity factors of about 35%. For comparison Germany, with 24 GW of wind power and alone accounting for more than a quarter of the world’s capacity, has an average capacity factor of 16%15. An indicative capacity factor of 20% was derived for Parkes using both academic resources16 and an engineering model17.

Figure 7 Wind resources around Parkes

This map was produced using the Renewable Energy Atlas of Australia, a product of the Australian Government Department of the Environment, Water, Heritage and the Arts. www.environment.gov.au/renewable/atlas

Large turbines, of the order of 2 MW, are significantly cheaper than small turbines. However, unless contractual net metering could be negotiated with Essential Energy, the output from the turbine should match what can be used on site reasonably well, so that the generation offsets retail electricity. The capital cost has been modified considerably from the initial a The capacity factor of a generator is the actual energy output divided by the energy output if the generator was operating 24 hours per day, 365 days per year. So a generator with a 25% capacity factor could generate 25% of the time at full power, or 50% of the time at half power

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Parkes Shire Council: Distributed Energy Plan 28

options assessment, as discussions with Essential Energy indicated that it would be extremely difficult, and perhaps not possible, to negotiate contractual net metering.

The two potential locations for wind turbines are therefore the site of the proposed Water Factory, and adjacent to the Back Yamma pump site. Ideally a turbine of approximately 150 – 250 kW would be installed at Back Yamma, and perhaps 75kW at the Water Factory, as this would match the power demands of the two sites respectively.

The most suitable turbine for low wind speeds in this power range was found to be the Endurance 50 kW model. This turbine is actually oversized for its nameplate capacity of 50 kW, and the annual energy output was calculated as 130 – 150 MWh per year using Bureau of Meteorology data for Parkes and Forbes18. This corresponds to a capacity factor of 26%, and reflects the fact that the turbine would generally have power output significantly greater than 50kW under optimal conditions.

Wind energy generation is eligible for Large Scale Certificates (LGCs, formerly called Renewable Energy Certificates), which may be created for every MWh of renewable energy generated. The likely installation size for Parkes, and considered here, would be above the threshold for a Small Generation Unit. LGCs are traded, so the price is variable. In the last year, REC prices have fluctuated between $30 per REC and $45 per REC.

The calculations in this report assume a market price of $35 per LGC, and a capital cost of $7000 per kW, and installation of 2 x 50kW turbines.

5.5 Solar PV (with varying level of FIT) The solar resource around Parkes is extremely good, as shown in Figure 6. Solar photovoltaic (PV) panels are a highly modular technology, and could potentially be installed on most of PSC sites.

Solar PV receives support in a number of ways:

Small-scale Technology Certificates (STCs, formerly known as Renewable Energy Certificates). Installations must be classified as a ‘Small Generation Units’, which have a maximum size of 100kW. The price for STCs is fixed at $40 per MWh, and they are ‘deemed’, which means they are available at installation of the system, rather than annually after actual generation. This amounts to up front capital support of $829 per kW.

Feed in Tariff a gross feed-in tariff (FIT) is available under the NSW Solar Bonus Scheme. This was originally set at 60 cents for each kWh generated, for a period of 6 years, but has been reduced to 20 cents per kWh. The most recent media release from the NSW Government indicates that is unlikely that the FIT scheme will continue at all due to the large number of applications in the pipeline, exceeding the government’s planned target for the scheme19.

Parkes Shire Council is installing two 10 KW solar PV systems at their sites, which were approved when the 60 c/kWh FIT was still available.

While the 20 c/kWh FIT is currently available, it is very likely that the cap of 300 MW installed under the scheme will be reached before PSC would be able to install any more PV generation, so this option is not presented. In this case only the SGU support would be available for PV installations, in the form of STCs.

If PSC chose to install more than 100kW on any one building, for example the Administration Centre, the installation would not qualify as a Small Generation Unit. In this case the

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Parkes Shire Council: Distributed Energy Plan 29

installation scheme would come under the Large-scale Renewable Energy Scheme, and would generate LGCs each year.

The levelised cost of PV with a 60 cents FIT and STCs, and with no FIT and STCs, are shown in Figure 11. The business case is given in Section 0, as well as the implications of larger installations which would not be eligible for Small Generation Unit status.

Figure 8: Solar resource around Parkes

This map was produced using the Renewable Energy Atlas of Australia, a product of the Australian Government Department of the Environment, Water, Heritage and the Arts. www.environment.gov.au/renewable/atlas

5.6 Solar CST Concentrating Solar Thermal power (CST) is a technology that is attracting increasing interest worldwide. CST power works by using mirrors to focus and intensify the sun’s rays, in order to heat a fluid. This heated fluid is then used drive a turbine to generate electricity, either directly or through a heat exchange process. Concentrating solar thermal systems are most attractive when combined with heat storage technologies.20 The ability to incorporate thermal storage is a significant advantage of CST power stations relative to PV power stations, as it allows production of electricity after the sun goes down.

The solar resource around Parkes is extremely good, as shown in Figure 6. Unlike solar PV, CST requires direct sunlight to work, which means it is the number of sunshine days or more specifically the direct normal radiation that is the key variable. However, since the Parkes area has a high number of sunshine days, CST is an attractive technology.

As shown in Figure 7, there are currently four main concentrating solar thermal power technologies: parabolic trough collectors, linear Fresnel reflector systems, power towers or central receiver systems and dish/engine systems.21 As CST technologies are currently quite new commercially, and the majority of projects operational or in development worldwide are large scale – 30+MW, the biggest challenge to installing a CST system will be finding a commercially available system of the appropriate scale for PSC’s needs.

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Parkes Shire Council: Distributed Energy Plan 30

Figure 9 Schematic diagrams of the four concentrating solar thermal systems.

ISF has only been able to locate one technology provider, Albiasa Solar, who have a commercially available small-scale, parabolic trough CST technology22. The scale of the Albiasa Solar system (1-1.5MW) is still slightly larger than PSC’s energy needs, but Albiasa say that smaller systems are available, due to the modularity of the technology. The system uses Organic Rankin Cycle turbine technology, includes energy storage and is modular, so could be scaled up or down if appropriate. Based on communication with Albiasa Solar ISF has included levelised costs in the option summary of $7500 per kW23.

The technology has quite a large footprint – the area required for a 1.5MW system would be approximately 2 hectares.

There is one Australian company – Lloyd Energy Systems developing a central receiver or power tower CST technology. They are currently in the research and development phase with a pilot project located at Lake Cargelligo. Lloyd Energy Systems predict they will start talking to the market and have indicative costs and scales in 2012.

CST technologies are new in the Australian context, particularly at the 1.5MW scale, and there is only one operational CST power plant here24. There are risks associated with early adoption of new technology, including potential time delays, financial overruns and regulatory barriers.

Nonetheless, PSC would be pioneers if they pursued a CST project and would attract significant media profile and interest from those in the energy industry across Australia and potentially world-wide. These types of pioneering projects can also produce ancillary benefits such as increased tourism to the area.

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Parkes Shire Council: Distributed Energy Plan 31

CST is eligible for Large-scale Generation Certificates (LGCs, formerly called Renewable Energy Certificates), which may be created for every MWh of renewable energy generated. LGCs are traded, so the price is variable. In the last year, REC prices have fluctuated between $30 and $45 per REC.

5.7 Bioenergy While biomasses, including crop residues can be a good fuel for cogeneration and trigeneration systems, this is not a recommended option for Parkes. The farmland in the Parkes area predominantly uses no-till cultivation methods. For wider sustainability reasons, including minimising soil erosion and increasing water and nutrient retention, removal of crop residue to use as a biomass feedstock is not recommended beyond approximately 25%25. At this level of collection, bioenergy becomes is likely to be economically and logistically difficult.

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6 Efficiency / load management options

6.1 Buildings A high-level benchmarking exercise comparing the Parkes Council Administration Building and the Library/Cultural Centre with State Average office buildings revealed the following (unofficial) NABERS Energy ratings:

State Average Office Building: 2.5 stars

Administration Building: 4.5 stars (402 MJ/m2)

Library/Cultural Centre: 5 stars (326 MJ/m2)

While this analysis has limitations, particularly in the sense that the operational parameters of the Library/Cultural Centre may not match those of regular office buildings, the process generally indicates that the level of energy efficiency in the council buildings is above average. Given this information, it is considered unlikely that very significant (>30-40%) gains in efficiency are likely to be achievable to yield cost savings for the Council. However, a walk-through observation of the Council Administration building and Library facility revealed that there were in fact numerous opportunities for efficiency improvements, from disconnection of unused appliances, such as additional refrigerators, closer management of air conditioning temperature regulation, fluorescent lighting fitting and lighting switch zoning retrofits. This is in addition to any staff behavioural changes that can routinely result in further savings.

Based on the above, it is not unreasonable to expect that a 10 to 20 percent improvement could be achieved through a dedicated energy auditing process and construction of an office Energy Management Plan. This has been represented in Figure 11, which compares the costs and potential magnitude of the range of possible PSC distributed energy initiatives.

6.2 Pumps Pumps consume nearly 90% of PSC electricity, so any energy efficiency improvements in pumping will have significant returns.

Parkes Shire Council has a policy of replacing pumps with Best Available Technology in their normal replacement cycle, and of considering the energy performance of the equipment. For example, they have already undertaken one of the major energy improvements, by installing variable speed drives on their major pumps. While it is important that PSC continues to improve their pumps as more efficient equipment becomes available, it is unlikely that a step change in energy use could be achieved at this stage.

It is worth noting that Planet Footprint provide a service comparing the energy intensity of Parkes Shire Council’s overall operations relative to other councils that operate water infrastructure. This data is not yet available as more data still needs to be provided by the Council, however based on the Council’s approach and understanding of energy consumption, and their good building energy efficiency, it is anticipated that the Planet Footprint benchmarking would put Parkes above average.

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Parkes Shire Council: Distributed Energy Plan 33

6.3 Solar pool heating Pool heating is currently supplied by gas at the Parkes Olympic Pool, and costs just under $17,000 per year. A solar pool heater, at a capital cost of $40,000 to $70,000, could supply approximately 70% of the pool heating26. This should achieve a payback of 3.5 to 5 years.

Parkes Olympic Pool has previously had a solar pool heater on the roof of the adjacent Hall roof, which was disconnected at the end of its life and not replaced. A new heater could be installed on the same roof and potentially expanded onto other nearby unutilised roof area.

Figure 10: Existing defunct solar pool heating infrastructure

6.4 Water efficiency It is estimated that reducing leakage could reduce raw water requirements by approximately 10 %27. This would in turn reduce pumping requirements for water, which accounts for nearly 90% of PSC electricity consumption.

In order to make an approximation of the potential energy savings, it has been assumed that this would reduce the energy of the largest nine pumps, excluding the pump located in the centre of Parkes at High Street, by 10%. This results in an overall reduction in pump energy use of 8%. It is expected that grant funding would be available for this program, so that the cost to PSC would be negligible.

6.5 Demand side response During 2007 Parkes Shire Council participated in a Demand Side Response (DSR) trial under contract with Energy Response Pty Ltd. As explained in the PSC Councillor briefing note:

Demand Side Response is when grid energy users reduce their electricity demand for short periods of time in response to high wholesale spot prices, supply shortfalls, or network stress. In return the participating energy users (e.g. Council) receive financial rewards. DSR is viewed as "energy not consumed" and is measured in megawatt hours.

(PSC Memo entitled ‘(DI) Update on Demand Side Response’)

PSC was called upon 10 times during the month of June 2007 to switch off water pumps at up to five locations to achieve a specified level of demand reduction, to which Country Energy (now Essential Energy) assigned a market value. PSC was remunerated by Energy Response to the value of approximately $19,500 for these services. Costs associated with

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Parkes Shire Council: Distributed Energy Plan 34

performing the DSR were in the order of $1,000 in the form of wages associated with changed pump operating regimes.

ISF has yet to hear back from Energy Response with details of the trial, including payment rates and actual levels of demand reduction for which it was credited. ISF will forward this information to PSC when it is received.

For the purposes of this report, ISF has assumed that DSR could be utilised at all of its main pump sites up to a level of the largest single pump capacity, for a period of up to 3 hours at a time. There is no capital cost associated with turning off these pumps; however there is some operating cost associated with overtime wages. It is understood that the processes underpinning overtime requirements are currently being reviewed by PSC.

DSR can also be achieved by using ‘on demand’ generation, such as gas engines. Thus demand response has been included in the detailed business case for gas generation at High Street. Depending on the engine capacity installed, varying degrees of additional DSR can be achieved, bolstering the business case for these options.

The business case model is set up with DSR as a component of gas engines, and as a standalone option associated with adjusting pumping regimes. As the rates are unknown, the value associated with the DSR is likely to change. The model provided with this report is set up with sufficient flexibility for PSC to change these inputs when more information comes to hand.

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Parkes Shire Council: Distributed Energy Plan 35

7 Scoping exercise outcomes

Figure 11 show the main options for energy cost reduction for PSC, compared to the current and projected electricity prices for PSC’s low and high tariffs.

The white line shows the final levelised costs of electricity from different supply or efficiency options, after support mechanisms are taken into account. Support mechanisms are shown by the dashed overlay, and explain why the final cost is less, in most cases, than the cost of capital, overheads, etc. In the case of trigeneration and gas engines at pump sites, this includes a network support payment, which is not an assured income, as it would have to be negotiated with Essential Energy.

The red lines on the graph represent projected grid electricity prices now, at 2015, and at 2020. PSC has two tariffs for electricity, one for buildings and most other uses with a usage charge of 20.5 c/kWha (referred to as the high tariff), and one which covers the large pump sites with a weighted usage charge of 10.7 c/kWh (referred to as the low tariff)b. The large pumps, on the low tariff, consume approximately 75% of PSC electricity.

The economics of different options are strongly dependent on whether they can be installed at sites using the high tariff or the low tariff. In general, only PV is suitable to be installed at high tariff sites, as these are generally the buildings.

Building energy efficiency, solar pool heating, and leak control are cost effective even at 2010 electricity prices, at all tariffs.

The use of solar PV (at $4,500 per kW capital cost), gas engines at major pump sites, and CBD trigeneration looks cost effective by 2020 with all tariffs, and at current prices where sites are on the high tariff (essentially buildings). However, the cost of the trigeneration is highly dependent on the associated costs for reticulation, etc., which are currently very uncertain, and could make this option uneconomic.

The option for PV without feed in tariff has been analysed using a capital cost of $4,500 per kW, as discussions with one supplier indicated this may be possible for larger scale or multiple installations, while PV with the 60 cent FIT uses a capital cost of $6,000 per kW.

Wind, concentrating solar thermal and PSC trigeneration become economic by 2015 with the high PSC electricity tariff.

Table 3 shows the indicative scale, capital cost, proportion of PSC energy supplied, and the levelised cost per MWh of each option. Table 4 gives a qualitative assessment of the risks and benefits of each.

Figure 11 and Table 4 have been updated since the original options assessment in the light of additional research, and also the decision to size technologies for on-site generation only as favourable export arrangements for electricity did not appear to be possible in the short to medium term. This increased the levelised cost of wind and concentrating thermal considerably. The modelled capital cost for PV without a FIT has been reduced by 25%, from $6/watt to $4.5/watt in the light of discussions between PSC and solar PV suppliers. These factors combined mean that the order of economic performance of the included options is significantly different to what was presented in the original scoping report.

a This is the weighted average of the peak, off peak, and shoulder rates for Council buildings. b Weightings use the 2004/2005 data on peak, off-peak, and shoulder usage for the major sites.

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Figure 11: Energy options for PSC ($/ MWh, high and low tariff)

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Table 3: Energy options summary (costs indicative only)

Potential scale Capital cost (indicative)

Potential reduction in PSC

electricity

Levelised cost per MWh

Leak control Not applicable Unknown 8% Very low

Energy efficiency in council buildings

50 MWh/a $16,000 1% $0.02

Gas engines at High St pump site

320 kW $ 0.55 million 14% (no export) $0.21

CBD trigeneration

1-2 MW (note only 50 kW treated as

PSC)

$0.3 million (PSC portion) (1) 4% $0.16

Wind 100 kW $700,000 2% $0.27

Solar thermal generation

300 kW $2.2 million 10% $0.23

Solar PV 60c/kWh FIT

10kW $39,500 0.15% $0.20

PSC Trigeneration

50 kW $0.5 million (1) 2% $0.22

Solar PV without FIT (at $4.5/Watt)

300 kW $3 million 4.4% $0.21

Note: (1) Costs for trigeneration are very uncertain as limited building energy data is available for sizing, costs of hot/ chilled water reticulation are not clear, and the most appropriate operating regime would need to be modelled in detail.

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Parkes Shire Council: Distributed Energy Plan 38

Table 4 Risks and benefits of different technologies – scoping assessment

POTENTIAL RISKS BENEFIT

Leak control Savings may be reduced by rebound effect if water use was cost limited

VERY LOW Reduces energy use and improves environmental indicators for water

HIGH

Solar pool heating

Savings may not be as high as anticipated

LOW Very cost effective, but relatively small scale

HIGH

(LIMITED

SCALE)

Energy efficiency (council buildings)

Savings may not be as high as anticipated

LOW Generally increases comfort, and reduces cost, relatively small scale

HIGH

(LIMITED

SCALE)

Gas engines at major pump sites

Profitability hinges strongly on a large number of variables that could vary significantly from estimates provided Gas price increase higher than anticipated

LOW-MODERATE

Relatively large volume of electricity offset compared to PV

MODERATE

CBD trigeneration

Very significant investment in facilitation without certainty of project go-ahead

HIGH Potentially more cost-effective than small-scale PSC-only operation

HIGH

Wind Possible Community opposition, or planning issues re siting wind turbines, Wind monitoring may show output to be lower than expected. REC price fluctuations

MODERATE Large potential to offset electricity use. Zero emission technology.

MODERATE

Solar thermal generation

Technology not well established, leading to delays and/ or price increases

MODERATE

- HIGH Large potential to offset electricity use. Zero emission technology

MODERATE

Solar PV with 60c/kWh FIT

Availability finished, so limited to small scale

VERY LOW Economic return guaranteed by FIT Zero emission technology

MODERATE

PSC only Trigeneration

Relatively high cost of feasibility, design and capital investment for potentially low utilisation Value undercut if very cost effective options like solar water heating and building efficiency are undertaken, and site load is offset by large scale solar PV as currently planned by PSC

MODERATE Improve efficiency of energy supply and use (reduce emissions)

MODERATE

Solar PV without FIT (at $4.5/ Watt)

Capital cost from tender may be higher than expected, but know prior to expenditure.

LOW

Modular technology, can be sited to correspond with PSC usage

HIGH

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Parkes Shire Council: Distributed Energy Plan 39

7.1 Greenhouse implications for PSC The energy supply and efficiency options described can reduce Parkes Shire Council greenhouse emissions by up to 40% per year.

The emissions in tonnes (t) CO2 per kWh for each option are as follows:

- Zero emission: energy efficiency, leak control, solar PV, solar thermal generation, and wind energy,

- About 0.3 t CO2 per MWh for trigeneration, and 7

- About 0.3 t CO2 per MWh for gas engines.

The reduction in greenhouse gas emissions achieved by the outlined energy supply options are shown in Figure 12a. The emissions reduction is directly proportional to the amount of electricity displaced, and therefore the scale of the project. This means that fitting a gas engine at pump could reduce emissions more than installing a wind turbine, even though the per kWh emissions from wind are zero, and the per kWh emission from the gas engine are probably in the region of 0.7 t CO2 per MWh,

Both the solar technologies and wind energy could be scaled up to achieve greater reductions, but this is only likely to be economic if generation can be used to offset PSC’s own usage, rather than just to export to the grid.

Figure 12: Greenhouse emissions reduction from selected energy options

a Note that the axis for greenhouse emissions starts at 9,000 tonnes.

8.9% reduction

6.2% reduction

5.7% reduction

4.1% reduction

3.5% reduction

2.3% reduction

1.6% reduction

0.5% reduction

0.1% reduction

9,000 9,200 9,400 9,600 9,800 10,000 10,200 10,400 10,600

Solar thermal generation

Leak control

CBD trigeneration

Solar PV no FIT (300 kW)

Gas engines at major pumps

Wind

Trigeneration (PSC only)

Commercial energy efficiency

Solar PV 60c FIT (10 kW)

Business as usual

Tonnes CO2 per year

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Parkes Shire Council: Distributed Energy Plan 40

8 Business case

8.1 Options for further investigation (outcomes from scoping workshop)

ISF presented the outcomes from the scoping study at a workshop for PSC staff and Councillors on February 9th 2011 at which there was detailed discussion of the risks and benefits associated with each options.

In the light of discussions with Essential Energy which indicated that contractual net meteringa would not be available in the foreseeable future, it was decided that generators should be sized in order to use all, or nearly all, of the generation on site.

The options selected for further investigations after the workshop and the discussion with Essential Energy were:

Solar pool heating;

Solar PV, both with and without feed in tariffs,

Gas engines at High Street pump station, with sufficient investigation of the cost of gas piping to determine whether gas engines are likely to be economic at the two large pump stations remote from the gas supply,

The use of demand side response in conjunction with gas engines, in which loads are switched off in return for payment at times when the network is severely challenged,

Small wind turbines at either the Water Factory site or the remote pump sites (conditional on the wind speed), and

Concentrating solar thermal at the Water Factory site.

In addition, the workshop supported a decision to implement energy efficiency programs for the Council buildings, and the leak control program on the water network, as the paybacks on these measures were extremely short.

8.2 Business case parameters For each option, a 25-year cash flow was constructed, assuming that repayment is made over 10 years, with an interest rate on borrowing of 8.1%. The Net Present Value (NPV) using a discount rate of 7%, the Internal Rate of Return (IRR), and the Lifetime Benefit with no discounting applied to the future savings, are calculated for each option. In addition the simple payback is calculated, namely the number of years until energy cost savings repay the capital sum (this does not take into account interest rates). The results are given below, and all options are compared in Section 9.

Nominal dollars are used for the energy price projection, in order to get a more accurate calculation of the cash flow, as repayments are effectively in nominal dollars.

a In which output greater than on-site use would be ‘netted off’ against other PSC sites, obtaining close to the retail price for electricity.

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Parkes Shire Council: Distributed Energy Plan 41

8.3 Solar pool heating Installation of solar pool heating was found to be an extremely cost effective measure, with simple payback of only three years.

The net present value, lifetime benefit with no discounting of future years savings, and the simple payback for installing a pool heater at a range of capital costs from $40,000 to $70,000 are shown in Figure 13.

The indicative cost of installing a pool heater is $40,000 - $70,000, and across the whole range the NPV is positive. The lifetime benefit of the measure, with no discounting, is $429,000.

The return on investment is very good for this measure, with an internal rate of return greater than 27%, although the magnitude of savings are small relative to PSCs energy use.

Figure 13: Pool heating – NPV, Lifetime Benefit, and simple payback at a range of capital costs

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$0

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efit

Capital cost 

Pool heating; Capital cost $54k

Lifetime benefit, no discount Net Present Value Simple payback

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Parkes Shire Council: Distributed Energy Plan 42

Table 5: Pool heating – details and outcomes

TECHNOLOGY Pool heating

Description Installation of pool heater at Parkes

Olympic pool

Year of installation 2012

Cost per kW assumed $55,000 

Total capital expenditure $54,000 

Net Present Value (NPV) $154,187 

Internal Rate of Return (IRR) 27.6% 

Lifetime benefit (no discount) $429,419 

Simple payback 3 years 

1st year of positive return Year 3 

8.4 PV with and without feed in tariffs PV is suitable for installation on buildings, and may therefore be installed on PSC sites which are subject to the high tariff for electricity. This means the avoided energy costs are based on 24 c/kWh rather than 13 c/kWh, the rate at the low tariff sites (see Section 3 for an explanation of the high and low tariffs).

The main factors which affect the economics of solar PV are capital cost and the support available, which are both undergoing change. Three options are presented here, which are designed to reflect the PV options over the next few years.

PV in receipt of the 60 cents feed in tariff, with capital cost of $6000 per kW.

PV without any feed in tariff, classified as a Small Generation Unit (upper limit 100 kW), with variable capital cost, and

PV without any feed in tariff, of any size, classified as a Large Generation Unit.

PSC has secured agreements to install two 10 kW solar PV systems under the 60 cent/ kWh feed in tariff at two sites, the Henry Parkes Centre and the Parkes Olympic Pool. The capital cost for these installations is likely to be $6000 per kW. The economics of these sites is very good, with an internal rate of return of 16%.

The 60 cent feed in tariff is no longer available, so additional installations will not attract a feed in tariff.

One supplier has indicated that for larger or multiple installations, they could install solar PV for $4500 per kW, although this is not a firm quotation. ISF has examined the effect of progressively lower capital costs, and has used the $4500 per kW offer in the analysis below.

Installations less than 100 kW are classified as Small Generation Units, which mean they get Small-scale Technology Credits (STCs) rather than Large-scale Technology Credits (LGCs).

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Parkes Shire Council: Distributed Energy Plan 43

STCs are priced at $40, and do not fluctuate with the market. More importantly, they are ‘deemed’ at the point of installation, so are in effect an up-front capital support. Once the installation is larger than 100 kW, it is classified as a solar power station, and falls under the large-scale scheme, which means the support is in the form of LGCs, which are created each year and fluctuate with the market. Installations only receive LGCs until 2030.

Figure 14: PV installations compared (with and without FIT, different capital costs, and as Small-scale and Large-scale units)

Table 6: Solar PV – details and outcomes with and without feed in tariff,

TECHNOLOGY PV 60c FIT PV no FIT < 100 kW

PV no FIT > 100 kW

Description 10 kW 290 kW (as six installations)

101 kW

Year of installation 2011 2012 2012

Cost per kW assumed $6,000  $4,500  $4,500 

Total capital expenditure $38,812  $750,476  $454,500 

Net Present Value (NPV) $34,396  $1,074,016  $177,242 

Internal Rate of Return (IRR) 16.4%  16.7%  10.8% 

Lifetime benefit (no discount) $105,244  $3,537,868  $889,035 

Simple payback 5  6  9 

1st year of positive return Year 2  Year 2  Year 11 

Table 6 show the economics of the three types of PV installations. The most cost effective is PV with a capital cost of $4500 per kW, without a feed in tariff, sized under 100kW so that it is eligible for Small Generation Unit status. The IRR for this installation is 16.9%, and it has

4 years

8 years

12 years

0%

10%

20%

30%

No FIT, $4500/kW 60c FIT, $6000/kW No FIT, $4500/kW, large installation

PV installations compared

IRR Simple payback

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Parkes Shire Council: Distributed Energy Plan 44

a lifetime benefit (undiscounted) of $3.3 million, compared to a capital expenditure of $0.75 million. The 60 cent feed in tariff installation is also very cost effective, with an internal rate of return of 16.5%. Even the larger installation, without the Small Generation Unit status, has an IRR of 11% with capital cost of $4500. All of these calculations assume that the generation from the PV offsets electricity that would otherwise be purchased at the high tariff rates.

The PV with the 60 cents FIT (at $6000 per kW), and the PV without the FIT (at $4500 per kW) which is classified as a small generation unit both have positive returns from the second year onwards.

More details of the PV without FIT are given below.

PV without a feed in tariff (<100 kW at each installation) The effect of capital cost on the simple payback, net present value, and undiscounted lifetime benefit are shown in Figure 15. The Net Present Value is positive at all the capital costs shown, and the undiscounted lifetime benefit ranges from $2.4 million to $3.5 million for a capital investment of $750 thousand. Simple payback is between five and ten years.

There is potential to install 290 kW at the sites listed in Table 7.

. These calculations is based on ensuring that all or nearly all of the generation is used on site, and keeps installations small enough to be eligible for Small Generation Unit status to optimise the return. Should it become possible to use generation to offset PSC usage off site, for example for street lighting, the potential scale for installation would increase significantly.

Figure 15: PV without a feed in tariff: NPV, Lifetime Benefit, and Simple payback at a range of capital costs

2 years

4 years

6 years

8 years

10 years

$0

$500,000

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

$3,500,000

$4,000,000

$4,500,000

$5,000,000

$4,000 $4,500 $5,000 $5,500 $6,000 $6,500

NPV and Lifetim

e cost/ ben

efit

Capital cost per kW

PV no FIT (330kW); Capital cost $854k

Lifetime benefit, no discount Net Present Value Simple payback

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Parkes Shire Council: Distributed Energy Plan 45

Table 7 PV potential sites

POTENTIAL SITES Current annual  usage 

(MWh) Potential system size 

(kW) 

ADMIN CENTRE, PARKES  247  99 (note 1) 

LIBRARY & CULTURAL CENTRE  137  95  

HENRY PARKES CENTRE  73  50 

AIRPORT  58  40 

THORNBURY STREET, PARKES  49  35 

RURAL FIRE SERVICE STATION  11  5 

HARRISON PARK‐ CANTEEN  8  5 

TOTAL POTENTIAL  528  290 

Note 1: the potential size at the Admin centre has been restricted to 100kW so that the system is eligible for Small Generation Unit status. If the only concern were generating for onsite use the potential size would be 175 kW,

8.5 Gas engines at High Street combined with DSR The installation of gas engines at High St is considered an appropriate match to offset the relatively high and constant pumping load. Eugowra and Back Yamma pumping sites were not included in the business case as the additional costs associated with piping mains gas to remote locations or transporting and storing compressed gas were considered to make the business case unviable.

The business case for gas engine(s) at High St is highly dependent on a number of cost/benefit inputs that change the overall economics substantially. These inputs include:

The gas contract price that can be negotiated at the 150-300kW engine scale and the escalation of the gas price into the future.

Increases in electricity prices (this applies to all options).

The size, ensuing utilisation (‘capacity factor’) and efficiency of the engine selected. This links back to a decision about whether to size larger, operate the engine at higher load and sell excess power into the grid, or size smaller and only offset the retail price.

The extent to which any demand on the Essential Energy network capacity charges can be avoided if using only one engine (by ensuring pumps are not run when the engine is offline).

The ability to attract funding for alleviating network and generation constraints, in the form of Network Support Payments and Demand Side Response contracts respectively.

Using medium gas and energy price projections, a starting gas contract price of $10/GJ, specifications and costs of off-the-shelf 160kWe engines, the business case was found to be marginal, hovering around the ‘break even point’, or roughly equivalent to purchasing mains

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Parkes Shire Council: Distributed Energy Plan 46

electricity. While this depends heavily on the range factors outlined above, with the exception of future electricity and gas prices, these would be known prior the point of project commitment.

This analysis presents two different scales of installation: 1 x 160kWe and 2 x 160kWe engines. This is because one engine of this size approximately corresponds to the average and peak demand at the site, and would achieve high utilisation. The installation of a second engine would allow PSC to offset any extreme high demand periods when both pumps are required simultaneously, thus avoiding large demand charges, gaining additional revenue from Demand Side Response or Network Support, and bringing reliability benefits, but would have poor utilisation.a

The net present value, lifetime benefit with no discounting of future years’ savings, and the simple payback for installing a single, 160kWe gas engine at a range of capital costs from $1,000 to $3,000 per kW are shown in Figure 16. Analysis is undertaken for an engine with a capital cost of $1745 per kW.

Figure 16: 160 kWe gas engine at High St: NPV, Lifetime Benefit, and Simple payback at a range of capital costs

The indicative cost of installing a 160kWe engine is about $280,000 and it has a slightly negative NPV in the order of -$14,000 at this capital cost. The lifetime benefit of the

a It would be far more capital efficient (~30% cheaper) to install a single 300kWe engine, but such an engine would need to run at less than 50% capacity factor for the cast majority of the time if offsetting pump loads only. If run at a higher capacity factor and was only credited with a wholesale export energy price of ~4c/kWh, the cost of gas would be higher than the electricity sale price and the engine would run at a loss for this marginal generation.

2 years

6 years

10 years

14 years

18 years

‐$400,000

‐$200,000

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,000 $1,400 $1,800 $2,200 $2,600 $3,000

NPV and Lifetim

e cost/ ben

efit

Capital cost per kW

Gas Engine 160 kW (160kW); Capital cost $279k

Lifetime benefit, no discount Net Present Value Simple payback

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Parkes Shire Council: Distributed Energy Plan 47

measure, with no discounting, is $0.5 million.a The return on investment is low but reasonable for this option, with an internal rate of return of 7%, offsetting around 14% of PSC’s annual energy usage. The details and results of this option are shown in Table 8.

Table 8: 160kwe Gas Engine – details and outcomes

TECHNOLOGY Gas Engines – 160 kW

Description 160kWe gas engine at High St pump

Year of installation 2012

Cost per kW assumed $1,745

Total capital expenditure $279,135

Net Present Value (NPV) ‐$14,128 

Internal Rate of Return (IRR) 7.0% 

Lifetime benefit (no discount) $507,327 

Simple payback 15 years

1st year of positive return Year 11

The net present value, lifetime benefit with no discounting of future years’ savings, and the simple payback for installing two 160kWe gas engines at a range of capital costs are shown in Figure 17. A slightly lower capital cost, of $1713 per kW, is used as there are some economies of scale associated with piping gas from the local distribution network.

The indicative cost of installing two 160kWe engines is about $550,000 and has a negative NPV of -$99,000 at this capital cost, due to the lower utilisation on the second engine. These figures include an income stream from Demand Side Response on a capacity of 170kW of capacity.b This equates to around $8,000 per year if DSR is worth $4,000 per MWh and is required for 12 hours per year (PSC will be advised of updated DSR figures from Energy Response when this information is provided to ISF). The lifetime benefit of the measure, with no discounting, is $0.5 million.c

The return on investment is lower for this option, with an internal rate of return of 6%, while offsetting roughly the same amount of PSC’s annual energy usage as the single engine option described above. The details and results of this option are shown in Table 9 below.

Thus unless electricity price rises are at the steeper end of projections and gas prices are at the lower end it is unlikely that relatively small-scale gas engines will be a significant cost saving option for the Council. However, gas engines could still be an important source of cost-effective or cost neutral carbon abatement, and bring reliability benefits for pump operation at times of power outage.

a See the Excel business case model provided to PSC for the full range of critical assumptions used. b Based on 320 kW capacity less the 150kW of existing site demand to account for the impact above “business as usual”. c See the Excel business case model provided to PSC for the full range of critical assumptions used.

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Parkes Shire Council: Distributed Energy Plan 48

Figure 17: 2 x 160 kWe gas engines at High St: NPV, Lifetime Benefit, and Simple payback at a range of capital costs

Table 9: 2 x 160kwe Gas Engines – details and outcomes

TECHNOLOGY Gas Engines – 320 kW

Description 2 x 160kWe gas engines at High St pump

Year of installation 2012

Cost per kW assumed $1,713

Total capital expenditure $548,135 

Net Present Value (NPV) ‐$99,121 

Internal Rate of Return (IRR) 6.0% 

Lifetime benefit (no discount) $565,799 

Simple payback 15 years

1st year of positive return Year 11

2 years

6 years

10 years

14 years

18 years

22 years

26 years

‐$1,000,000

‐$500,000

$0

$500,000

$1,000,000

$1,500,000

$1,000 $1,500 $2,000 $2,500 $3,000 $3,500

NPV and Lifetim

e cost/ ben

efit

Capital cost per kW

Gas Engine 320 kW (320kW); Capital cost $548k

Lifetime benefit, no discount Net Present Value Simple payback

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Parkes Shire Council: Distributed Energy Plan 49

Avoided Network Costs

If the gas engine/s were part of a larger coordinated effort to reduce energy demand or generate electricity in the local area, to the extent that the impending Parkes-Forbes network constraint (refer to Section 4 above) could be deferred by one year, this could result in a once off Network Support Payment (NSP) in the first year in the order of $150,000 for 320kW of local generation capacity. This is a different potential revenue stream to Demand Side Response payments, which generally operate on the basis of the wholesale energy market fluctuations as opposed to network pricing.

Obtaining a $500/kVA/yr NSP would significantly improve the business case, raising the Internal Rate of Return from 7% to 9%, and the NPV to around $116,000.

However, this revenue stream is dependent upon the sufficient demand reduction and local generation capacity being found to alleviate the constraint and would only reap this level of reward if network upgrades are required. This is considered relatively unlikely in the context of the potential new mining development, which would effectively neutralise avoided costs resulting from PSC Distributed Energy Options.

Other Opportunities

Other factors that could result in an improved business case for gas engines include a situation whereby an agreement could be reached with the retailer or network electricity business to offset the Council’s unmetered retail street lighting costs, thereby making larger and more cost-effective engine scales more attractive.

8.6 Demand Side Response with major water pumps With significant water pumping demands, PSC has a potentially large Demand Side Response (DSR) resource that it can utilise in tapping a revenue stream to help to fund other sustainable energy projects. If done strategically, this could be achieved without compromising security of water supply, particularly if done in combination with the installation of gas engines. If one of the two pumps at each of the major sites was turned off upon request, this would constitute around 700 kW of DSR. If we were to assume a smaller value in the order of 600 kW, this would translate to annual net income of about $28,000 assuming a market rate of $4,000 per MWh and that DSR was called upon for 12 hours per year. These values are, however, subject to change and ISF is awaiting clarification from Energy Response.

The above assumes annual wage increases of $1,000 to cover the additional cost of managing equipment start-up and shutdown, as was reported during the 2007 DSR trial.

This pumping DSR could be packaged with gas generation at High St when attempting to negotiate Network Support Payments.

8.7 Wind turbine at Back Yamma pump site The installation of a small wind turbine at Back Yamma Pump site is one of the few options to offset electricity consumption at this site, because of its distance from the gas distribution network.

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Parkes Shire Council: Distributed Energy Plan 50

The maximum size for a turbine designed to match the pump demand, and therefore use all or most of the electricity on site, is 200 - 250 kWa. Unfortunately there is a gap in the market between turbines around 100 kW and turbines of 600 kW, with most development on turbines of 2 MW or larger.

The installed cost per kW of small turbines is very much greater than for larger turbines, with sizes less than 500 kW costing upwards of $5000 per kW, compared to 2 MW turbines at around $2000 per kW.

The turbine considered most suitable for low wind speeds and the size range, and available from an Australian installer, is the Endurance 50kW b model, so this business case is based on installing two of these turbines.

There is some uncertainty about the energy output because a verified power curve is currently only available for the 60 Hz model, and a 50Hz model would be installed in Australia, Preliminary information supplied by the manufacturer indicates the output of the 50 Hz model may be up to 13% greater, resulting in a capacity factor of 30% rather than the 26% for the 60 Hz model. This business case uses the estimate based on the verified power curve, but this should be reviewed when a verified power curve for the 50 Hz model becomes available.

Figure 18 Wind: NPV, Lifetime Benefit, and Simple payback at a range of capital costs

The net present value, lifetime benefit with no discounting of future years savings, and the simple payback for installing two 50 kW wind turbines with capital costs from $6,000 to $8,000 per kW are shown in Figure 18.

a There are two 250 kW pumps, but pumping generally only utilises one of them. b Endurance E-3120,50 kW nameplate capacity

4 years

8 years

12 years

16 years

‐$400,000

‐$200,000

$0

$200,000

$400,000

$600,000

$800,000

$1,000,000

$6,000 $6,400 $6,800 $7,200 $7,600 $8,000

NPV and Lifetim

e cost/ ben

efit

Capital cost per kW

Wind (100kW); Capital cost $700k

Lifetime benefit, no discount Net Present Value Simple payback

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Parkes Shire Council: Distributed Energy Plan 51

The indicative capital cost of installing the two turbines is $700,000. The net present value of the investment is negative at the expected cost of $7,000 per kW, although the internal rate of return is still positive, at 6.2%. The undiscounted lifetime benefit is $490,600.

The capacity factor measures the output of the turbine, and results from a combination of the wind speed and the characteristics of the turbine. The return at various capacity factors and capital costs was calculated. With capital cost of $7000 per kW and capacity factor of 30% (which was indicated by the unverified power curve), the IRR would be 8%.

If this option is pursued, wind monitoring would need to be undertaken for twelve months at the site, at an approximate cost of $20,000. The expected energy output, and the corresponding financial return, could be predicted with much more confidence at that stage, and the decision taken on whether to proceed.

Table 10: Small wind turbine at Back Yamma pump site – details and outcomes

TECHNOLOGY Wind

Description Installation of 100 kW (2 x 50kW turbines)

at Back Yamma Pump site

Year of installation 2014

Cost per kW assumed $7,000 

Total capital expenditure $700,000 

Net Present Value (NPV) ‐$96,115 

Internal Rate of Return (IRR) 6.2% 

Lifetime benefit (no discount) $490,614 

Simple payback 13 years 

1st year of positive return Year 11 

8.8 Concentrating solar thermal Installation of a Concentrating Solar Thermal (CST) generator at the site of the Water Factory could potentially supply most of the electricity generation there.

The average load at the Water Factory is expected to be around 84 kW, assuming that the average load would be equal to 40% of the theoretical peak load. Expected energy use would be in the region of 670 MWh per year.

CST plants are not available at a full range of sizes, and matching the output to site use would require a very small system. The analysis here is based on the Albiasa CST plant, which is expected to be available at the 1 MW size, and be sufficiently modular to scale downwards. 300 kW has been modelled, as it is considered unlikely that the technology would be available for smaller sizes. The system includes four hours storage, so it is assumed the output will be evenly spread across 12 hours per day.

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Parkes Shire Council: Distributed Energy Plan 52

The CST will generate more than can be used on site, even with the storage option, so export electricity has been included in the calculations. The base calculation uses a figure of 0.4c/kWh. Should arrangements to offset PSC’s offsite usage or street lighting become possible, the business case should be revised as the economics would be significantly better.

The net present value, lifetime benefit with no discounting of future years savings, and the simple payback for installing 300 kW of CSP at the Water Factory Site with capital costs from $5,000 to $10,000 per kW are shown in Figure 19.

The indicative capital cost of installing the CSP is $2.2 million. The net present value of the investment is negative at -$656,000 at a capital cost of $7,500 per kW, although the internal rate of return is still positive, at 4.4%. The undiscounted lifetime benefit is just under $0.6 million.

The analysis assumes the CST plant would come on line in 2016. This is to match the Water Factory construction, but it should also be noted it is unlikely to be possible to install earlier, as the new wave of CST technology is in relatively early stages of commercialisation. The highest risk associated with the technology is its relatively early stage of development, although this also brings reputational benefits for PSC as an innovator.

The economic return is affected strongly by the capital cost, and the export price for electricity. If PSC could reach an agreement to offset street lighting, for example, at 13 c/kWh, and the capital cost fell to $6000 per kW, the IRR would rise to 11%.

Figure 19: Concentrating Solar Thermal: NPV, Lifetime Benefit, and Simple payback at a range of capital costs

4 years

8 years

12 years

16 years

20 years

24 years

‐$2,000,000

‐$1,500,000

‐$1,000,000

‐$500,000

$0

$500,000

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

$5,000 $6,000 $7,000 $8,000 $9,000 $10,000

NPV and Lifetim

e cost/ ben

efit

Capital cost per kW

Solar CST (300kW); Capital cost $2250k

Lifetime benefit, no discount Net Present Value Simple payback

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Parkes Shire Council: Distributed Energy Plan 53

Table 11: Concentrating Solar Thermal at Water Factory – details and outcomes

TECHNOLOGY Concentrating Solar Thermal (CST)

Description 300 kW of CST at the Water Factory site,

4 hours storage

Year of installation 2016

Cost per kW assumed $7,500 

Total capital expenditure $2,250,000 

Net Present Value (NPV) ‐$656,716 

Internal Rate of Return (IRR) 4.4% 

Lifetime benefit (no discount) $582,727 

Simple payback 15 years 

1st year of positive return Year 11 

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Parkes Shire Council: Distributed Energy Plan 54

9 Business case summary results

The economics of the all options selected for business case are highly dependent on the projection for the energy prices, as these determine the avoided costs. These are relatively certain until 2014/15, but become increasingly hard to predict after that date.

Figure 20 shows the options selected for analysis in the business case, at the scale designed to use all or most generation on site, and using the best guess of the capital cost. PV is assumed to be at sites using the high electricity tariff, while Solar CST, wind energy, and gas engines are assumed to be at sites using the low tariff. Table 12 gives detailed outcomes from the listed options.

Solar pool heating has an excellent rate of return, although the scale of the option is small, so the savings are small compared to PSC total energy expenditure. PV without a FIT, at a capital cost of $4,500 per kW, also has an excellent rate of return, as does PV with a 60 cent FIT.

The gas engine at 160 kW has a reasonable rate of return, but is heavily dependent upon a number of variables which require further investigation. The other three options (gas engines at 320 kW), solar thermal and wind all have positive rates of return, but negative net present values. The economics in these cases warrant further review, with investment decisions deferred until more accurate cost and output information is available. In each case, the business case could improve (or worsen) once actual costs are obtained.

Figure 20 Energy options compared: Internal Rate of Return and simple payback

5 years10 years15 years20 years

0%

10%

20%

30%

40%

Pool heating

PV no FIT

PV 60c FIT

Gas Engine 160 kW

Wind

Gas Engine 320 kW

Solar CST

Energy options compared

IRR Simple payback

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Parkes Shire Council: Distributed Energy Plan 55

Table 12 Energy options – business case outcomes details

TE

CH

NO

LO

GY

Po

ol h

eati

ng

PV

no

FIT

PV

60c

FIT

Gas

En

gin

e 16

0 kW

Gas

En

gin

e 32

0 kW

Win

d

So

lar

CS

T

Year of installation

2012 2012 2011 2012 2012 2014 2016

Cost per kW assumed ($’000)

n/a  $4.5  $6.0  $1.7  $1.7  $7.0  $7.5 

Installed capacity (kW) n/a  330 kW  10 kW   160 kW  320 kW  100 kW   300 kW 

Total capital expenditure ($’000)

$54  $854  $39  $279  $548  $700  $2,250 

Net Present Value (NPV) ($’000)

$154  $1,074  $34  ‐$14  ‐$99  ‐$96  ‐$657 

IRR 27.6%  16.7%  16.4%  7.0%  6.0%  6.2%  4.4% 

Lifetime benefit (no discount) ($’000)

$429  $3,538  $105  $507  $566  $491  $583 

Simple payback 3  6  5  15  15  13  15 

1st year of positive return Year 3  Year 2  Year 2  Year 11  Year 11  Year 11  Year 11 

Greenhouse savings per year

46 tonnes 

427 tonnes 

15 tonnes 

367 tonnes 

367 tonnes 

240 tonnes 

928 tonnes 

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Parkes Shire Council: Distributed Energy Plan 56

9.1 Energy expenditure PSC energy expenditure is set to rise steeply over the next twenty years. The energy options modelled are not sufficient to offset the price rises, but could mitigate them.

Different combinations of PV without a feed in tariff, a single gas engine, and wind energy are shown in the top graph in Figure 21. These packages of options are virtually cost neutral cost until 2021. After that there are significant cost savings, amounting to $500,000 per year by 2030 for the combination of PV, the smaller gas engine, wind turbines, and demand side response.

The inclusions of solar CST in the package is shown in

Figure 22, as well as the inclusion of “all options”, in which wind, solar CST, the second gas engine, and an additional 100 kW of PV at a lower support level are included.

Solar CST increases the energy expenditure considerably during the period to 2020, but from 2021 PSC is better off. After 2025 savings are about $1.5 million per year.

Figure 21 PSC energy expenditure – BAU and cost effective energy options

Figure 22 PSC energy expenditure – BAU and marginal energy options

$1.0 m

$1.5 m

$2.0 m

$2.5 m

$3.0 m

$3.5 m

$4.0 m

$4.5 m

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

Annual expen

diture on energy

Annual energy expenditure

Business as usual

All options

DSR, Pool ht, PV, Gas, Solar CST

DSR, Pool ht, PV, Gas, Wind

$1.0 m

$1.5 m

$2.0 m

$2.5 m

$3.0 m

$3.5 m

$4.0 m

$4.5 m

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

Annual expenditure on energy

Annual energy expenditure

Business as usualPV no FITGas Engine 160 kWDSR, Pool ht, PV, GasDSR, Pool ht, PV, Gas, Wind

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Parkes Shire Council: Distributed Energy Plan 57

9.2 Greenhouse emissions All of the options modelled reduce PSC emissions, but the scale of reduction varies considerably, from 15 tonnes in the case of 10 kW PV installed with a 60-cent FIT, to nearly 640 tonnes savings per year for 300 kW of solar CST. The greenhouse reduction for each option is shown in Table 12.

The graphs in Figure 23 and Figure 24 show the effect of the different groups of options on PSC’s business as usual carbon emissions. Pool heating and demand side response are included in all options as they are so highly cost effective.

Implementation of all options, shown in Figure 24, has the greatest effect, with a reduction of nearly 18%. Installation of 300 kW of PV alone reduces emissions by just over 4%. Implementing pool heating, 300 kW of PV, a single gas engine, and wind energy reduces emissions by 10%.

Figure 23 PSC greenhouse emissions – BAU and cost effective energy options

Figure 24 PSC greenhouse emissions – BAU and marginal energy options

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

Annual eem

issions

Annual carbon emissions

PV no FIT

DSR, Pool ht, PV, Gas

DSR, Pool ht, PV, Gas, Wind

Gas Engine 160 kW

Business as usual

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

2011

2013

2015

2017

2019

2021

2023

2025

2027

2029

Annual eem

issions

Annual carbon emissions

Business as usualAll optionsSolar CSTDSR, Pool ht, PV, Solar CSP Wind

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Parkes Shire Council: Distributed Energy Plan 58

10 Community benefit

Implementing the proposed Distributed Energy Plan could provide significant economic, social and environmental benefit to both PSC and the wider Parkes community. Parkes Shire Council would be an implementation model for triple bottom line sustainability.

The Distributed Energy Plan is one way PSC is addressing climate change, and will have both direct and indirect effects. It will directly reduce council’s own emissions (and costs), while also helping to normalise and increase the profile of sustainable and low carbon technologies in its Local Government Area.

An important element of the plan is to ensure that the Parkes community is informed about the Plan and the energy actions implemented. Information on measures undertaken and greenhouse and economic savings should be presented in a clear and simple manner, ideally via real time monitoring displays on the sites themselves, with a centralised display at public PSC offices.

Visible sustainable energy projects such as the solar PV installations and potentially wind and concentrating solar thermal systems will increase public awareness of the viability of and need for a transition to a low carbon energy system. Specifically, it is envisaged that the projects developing from this plan will be used as field trip sites for primary, secondary and professional sustainable energy education, thus providing direct educational benefits to the Parkes community. The implementation of this plan will also enable other businesses and organisations in the Parkes community interested in investing in sustainable energy projects to learn from the council’s experience.

PSC has an opportunity to maximise indirect benefits by ensuring the community has accessible information on PSC actions. There is potential in the future to facilitate community implementation of distributed energy options, for example by arranging or facilitating bulk purchase co-operatives for PV, so that residents can gain access to the same cost effective solutions as PSC itself.

Finally, by reducing the amount of money that council pays on energy, this plan will enable PSC to invest more in other essential community services and programs.

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Parkes Shire Council: Distributed Energy Plan 59

11 Distributed energy plan – recommendations and next steps

ISF recommends that Parkes Shire Council implement the most cost effective package of options as soon as possible, and obtain further information on the options with positive returns but internal rates of return less than 10%, in order to better inform the decision on whether to proceed. The recommended Distributed Energy Plan is given below.

The planned program of leak reduction and building energy efficiency are not included in the business plan. These are the most cost effective options, and should be implemented as soon as possible. Investigation should be undertaken to identify further water use reduction opportunities, and to implement a specific efficiency program at PSC buildings.

The most cost effective package of options from the business plan includes: Demand Side Response using PSC pump sites, solar pool heating, and PV at multiple sites at up to 100 kW per site (actual capacity to be determined by what is used at the site).

The next options for consideration are installation of 150 – 300 kW gas engine/s at the High Street pump site, 2 x 50 kW wind turbines at Back Yamma pump site, and a 300 kW of concentrating solar thermal facility at the new Water Factory site.

The Plan has the potential to reduce PSC’s long term energy expenditure and greenhouse gas emissions by 18%, equivalent to $700,000 and 2 million tonnes of CO2 per year.

Parkes Shire Council Distributed Energy Plan

ACTION TARGET DATE

12) Implement the planned program of leak control, and investigate further opportunities to reduce water use.

2011

13) Investigate & implement building energy efficiency options 2011

14) Obtain quotations & implement solar pool heating 2011

15) Commence negotiations to implement a Demand Side Response scheme

2011

a) Undertake internal assessment to identify any operating issues relating to DSR

2011

b) Talk further to Demand Side Response aggregator such as Energy Response about joining with other councils in a combined effort to form a block of more than 1MW of demand response (noting that ISF has initiated discussions with Orange and Bathurst Councils).

2011

16) Install 2 x 10 kW PV systems at the agreed 60 cent FIT sites 2011

17) Install 290 kW on buildings provided suitable prices are obtained. 2012 / 13

a) Obtain tender for installation of 100 kW – 300 kW, at multiple sites, with thresholds for price levels.

2011

b) Review decision on capacity to install in the light of capital cost 2011

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Parkes Shire Council: Distributed Energy Plan 60

ACTION TARGET DATE

18) Install public display for implemented Distributed Energy options, to raise awareness and give Parkes community real time on distributed energy performance and effectiveness.

2012

a) Investigate technologies with a view to installing real time display for PV systems and information on solar pool heating and energy efficiency measures.

2011

19) Initiate discussions with Essential Energy about the potential to offset street lighting or other PSC energy costs under a ‘contractual net metering’ arrangement, and provide Network Support to alleviate impending constraints. If these arrangements could be put in place, it would significantly improve the economics of the Distributed Energy Options.

2011

20) Install 150 kW gas engine at High Street pump site, conditional on the outcomes for capital cost, gas price, and network payments.

2012/ 13

a) Confirm with Jemena gas distribution that there is sufficient pressure in the gas pipeline (~10-35kPa pressure required).

2011

b) Obtain formal quotations and engage in discussions with design engineers and engine suppliers about whether a modular or single engine approach (1 x vs. 2 x ~150kW vs. 1 x ~300kWe) is most appropriate.a

2011

c) Enter into discussions with gas retailer such as AGL regarding potential contract gas price for engines of the appropriate scale.

2011

21) Install 100 kW wind at Back Yamma Pump site, depending on the outcome of wind monitoring, capital cost, and annual energy output c.

2012/ 13

a) Undertake wind monitoring for 12 months at Back Yamma pump site.

2011/ 12

b) Obtain verified power data and calculated energy output from turbine installers.

2012

c) Make a decision on installation based on the outcome of wind monitoring and power output calculations.

2012/ 13

22) Install solar CST at the Water Factory site, dependent on the further costing, and availability of equipment with suitable warranties. Sizing to be determined dependent on the outcomes of discussions regarding offsetting PSC street lighting with export electricity.

2016/ 17

a) Contact solar CST suppliersb with regard to long-term intention to install (dependent on price), and request quotations.

2013

b) Keep a watching brief on technology and revisit quotations. 2014

a The model provided to PSC with this report can of assist in these decisions, but detailed feasibility is beyond the scope of this work. b Including at least Albiasa and Lloyd Energy

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REFERENCES

1 PSC 2010. Project proposal Strategy to Develop a Sustainable Water and Energy Plan (SWEP) EOI supplementary information, page 4. 2 Tariff BLND1CO, called ‘low tariff’ here 3 Tariff BLNT1CO, called ‘high tariff’ here 4 Ison, N and. Rutovitz, J. 2011. NSW business energy prices 2000 – 2020. Institute for Sustainable Futures, University of Technology, Sydney for NSW Department of Environment, Climate Change and Water.

5 Essential Energy, Annual network prices report 2010-11, Figure 6 pg11, low voltage energy tariff. 6 Essential Energy (2010) Statement of expected Price Trends, Figure 3 page 2. 7 MMA (2008) Impacts of the Carbon Pollution Reduction Scheme on Australia’s Electricity Markets, Report to Federal Treasury, p22 8 MMA (2008) Impacts of the Carbon Pollution Reduction Scheme on Australia’s Electricity Markets, Report to the Federal Treasury, Figure 4.1, p43 9 Energy Australia (2009) Schedule – Retail Electricity Contract for 160+MWH Customers 10 ROAM Consulting (2010) Implications of the LRET and SRES modifications to the RET: Report to the Clean Energy Council, Table 9.6, p30. Note the large and small scale renewable prices are combined. 11 NSW Department of Industry and Investment (2011) Solar Bonus Scheme for NSW, Viewed March 2011 www.industry.nsw.gov.au/energy/sustainable/renewable/solar/solar-scheme

12 NSW Government, February 1, 2011. Press release. NSW government will offset the cost of the solar bonus scheme. 13 Ison, N and. Rutovitz, J. 2011. NSW business energy prices 2000 – 2020. Institute for Sustainable Futures, University of Technology, Sydney for NSW Department of Environment, Climate Change and Water. 14 DEWHA. 2009. Renewable Energy Atlas of Australia, a product of the Australian Government Department of the Environment, Water, Heritage and the Arts. www.environment.gov.au/renewable/atlas 15 BWEA (British Wind Energy Association) 2009 BWEA Briefing on UK Wind Capacity Factors. www.bwea.com/ref/capacityfactors.html downloaded 8/10/09 16 Gipe, Pl. 2004 Wind power, renewable energy for home, farm, and business. Figure 4.4, page 60 17 7th Wind™ Wind Turbine Performance Model.

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Parkes Shire Council: Distributed Energy Plan 62

18 Personal communication, Richard Johnston, The Wind Turbine Company, April 7th 2011. 19 See http://www.industry.nsw.gov.au/__data/assets/pdf_file/0016/372211/solar-bonus-applicants-urged-to-consider-all-options.pdf 20 Diesendorf, Greenhouse Solutions With Sustainable Energy; Lovegrove and Dennis, “Solar thermal energy systems in Australia”; Kreith and Goswami, Energy management and conservation handbook 21 Diesendorf, Greenhouse Solutions With Sustainable Energy; Frank Kreith and D. Yogi Goswami, Energy management and conservation handbook (CRC Press, 2007); Keith Lovegrove and Mike Dennis, “Solar thermal energy systems in Australia,” International Journal of Environmental Studies 63, no. 6 (12, 2006): 791-802. 22 Albiasa Solar - www.albiasasolar.com/administrador/new12.pdf, accessed Jan 2011. 23 Personal communication, Emmanuel. Ozaez, Albiasa Solar, 19/1/2011. Note: the quoted price was Au$5900 per kW, but this was for a 1 MW system, and did not allow for the additional cost of import to Australia. 24 Adjacent to Liddell Coal Fired Power Station in the Hunter Valley. 25 Humberto Blanco-Canqui (2010) ‘Energy Crops and Their Implications on Soil and Environment’ in. Agronomy Journal. 102:403-419 26 Personal communication, Mark Crowther, Rheem Australia, February 8th, 2011. 27 Personal communication, Andrew Francis, 17th January 2011.