Renewable Murchison Preliminary Feasibility Report May 2013

Transcription

RENEWABLE MURCHISON
PRELIMINARY FEASIBILITY STUDY
into
LOCAL RENEWABLE ENERGY OPTIONS
part of
Central Victoria Solar City’s Renewable Communities Program
MAY 2013
EARTH SYSTEMS
Central Victoria Solar City
This report is not to be used for purposes other than those for which it was intended. Environmental
conditions change with time. The information in this report is based on observations made during the site
visits and on the best publicly available data at the time of writing. Where this report is to be made
available, either in part or in its entirety, to a third party, Earth Systems reserves the right to review the
information and documentation contained in the report and revisit and update findings, conclusions and
recommendations. Earth Systems does not warrant that this document is definitive nor free from error and
does not accept liability for any loss caused or arising from reliance upon information provided herein.
Renewable Murchison Preliminary Feasibility Study
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Executive Summary
This Preliminary Feasibility Study provides the background and options analysis for the Murchison
community to establish local generation and ownership of renewable energy.
Explanation is provided about the project background and the approach to analysing renewable energy
options. The report includes comprehensive detail on current consumption, local resources, demographic
profile and current renewable energy technology for the renewable energy sources of solar, hydropower,
bioenergy and geothermal.
The current state of the electricity market is described paying particular attention to electricity generation
in Victoria, general market legislative and regulatory requirements as well as potential barriers for grid
connection. Local grid connection for Murchison is also summarised and illustrated indicating capacity
where grid connection could be established without major grid infrastructure upgrade.
An important focus of the report is to raise community enterprise options that can be matched with
renewable energy generation in an effort to pursue a business model that is led and managed locally
returning positive revenues to the community. Extensive information on community energy is provided,
including its history, types of ownership models, enabling factors, models in Victorian as well as barriers
to implementation. Benefits and impacts to community energy are outlined in relation to rural and regional
development and includes energy security and vulnerability and greenhouse gas savings.
Financial analysis for each renewable energy option at varied scales is presented using a ‘levelised cost
of energy’ measure as a base comparison and includes financial return available from the Australian
Government‘s Renewable Energy Target scheme. To assist in decision making against changes to
external factors, analysis has been captured to incorporate changes to capital and operational
expenditure, quantity of electricity generated, production costs, electricity prices, inflation and thermal
heat sale. This sensitivity comparison provides the key factors for consideration given changes to
financial scenarios.
The average local solar resource for Murchison shows good potential for power generation, similar to
regions where large scale solar power developments have been commissioned. The financial modelling
also presents attractive options for the community to generate electricity from solar where the electricity is
used and sold at the point of generation.
Findings also demonstrate favourable investment for biomass resources particularly where biomass can
be diverted from landfill and a fee charged for its disposal to the power plant, and electricity and heat via
cogeneration and are sold directly to customers. Although findings show that payback periods of less than
3 years are possible, Murchison does not currently present, from data obtained for this report, a biomass
fuel source of scale for commercial viability.
Although further detail is required, preliminary hydropower modelling indicates hydropower having the
lowest ‘levelised cost of energy’ compared to other renewable energy generation options considered.
This report provides a base for the Murchison community to pursue their own community enterprise.
Community leaders can utilise the report to track changing variables to maximise the financial, social and
environmental benefits and outcomes of the renewable energy options analysed (particularly solar
energy, bioenergy and hydropower) in combination with the most appropriate location and community
ownership model to form an enterprise that is commercially driven with community spirit. .
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Contents
Executive Summary ...................................................................................................... 3
1
Introduction ......................................................................................................... 10
1.1
Project Background .............................................................................................................. 10
1.2
Objectives and Scope ........................................................................................................... 10
1.2.1 Exclusions .............................................................................................................................................. 11
1.3
Stakeholders Role and Responsibilities ............................................................................ 11
1.4
Approach ............................................................................................................................... 13
1.5
Demographic Analysis ......................................................................................................... 14
2
Current and Projected Local Electricity Demand ............................................. 16
3
Local Electricity Grid Infrastructure .................................................................. 19
3.1
Introduction ........................................................................................................................... 19
3.1.1 Electricity Generation in Victoria ..................................................................................................... 19
3.2
State of the Network ............................................................................................................. 19
3.2.1 Network ................................................................................................................................................... 19
3.2.2 Constraints and Scheduled Upgrades .......................................................................................... 20
3.3
Legislative and Regulatory Requirements ......................................................................... 21
3.3.1 Administrative Organisation ............................................................................................................. 21
3.3.2 Scheduled vs Unscheduled Generation ....................................................................................... 21
3.4
4
Analysis – Local Grid in Murchison .................................................................................... 21
Community Power Generation ........................................................................... 24
4.1
Grid Connected vs Stand-Alone Generation ...................................................................... 24
4.2
Demand Response and Load Shedding ............................................................................. 27
4.2.1 Benefits of Demand Response ....................................................................................................... 28
4.2.2 Barriers to Demand Response ........................................................................................................ 29
4.3
Community Ownership Models ........................................................................................... 30
4.4
Community Energy – what makes it work? ........................................................................ 32
4.5
Models for Community Energy ............................................................................................ 33
4.6
Community Energy in Victoria............................................................................................. 36
4.7
Barriers to Implementation .................................................................................................. 38
5
Existing Renewable Generation......................................................................... 41
6
Potential for Co- or Tri-Generation .................................................................... 42
7
Modelling Methodology ...................................................................................... 43
7.1
Energy Generation Modelling .............................................................................................. 43
7.1.1 Electricity Pricing ................................................................................................................................. 43
7.1.2 Network Charges ................................................................................................................................. 43
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7.1.3 Connection Costs ................................................................................................................................ 44
7.1.4 Selected Capacities ............................................................................................................................ 44
7.2
Simple Economic Modelling ................................................................................................ 45
7.2.1 Levelised Cost of Energy .................................................................................................................. 45
7.2.2 Data and Assumptions ....................................................................................................................... 46
7.2.3 Sensitivity Analysis ............................................................................................................................. 47
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9
Solar Power ......................................................................................................... 48
8.1
Technology Overview ........................................................................................................... 50
8.2
Environmental Impact .......................................................................................................... 50
8.3
Local Solar Resource ........................................................................................................... 51
8.4
Modelling Results ................................................................................................................. 53
8.5
Sensitivity Analysis .............................................................................................................. 56
Hydro Power ........................................................................................................ 58
9.1
Technology Overview ........................................................................................................... 58
9.1.1 Technology Costs and Economics ................................................................................................ 60
9.1.2 Environmental Impact ........................................................................................................................ 61
9.2
Hydropower Resources in Victoria ..................................................................................... 61
9.3
Local Hydropower Potential ................................................................................................ 62
9.3.1 Canal and River Conditions ............................................................................................................. 64
9.3.2 Regulatory Processes ........................................................................................................................ 64
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9.4
Modelling Results ................................................................................................................. 65
9.5
Sensitivity Analysis .............................................................................................................. 68
Geothermal Energy ............................................................................................. 70
10.1 Environmental Impact .......................................................................................................... 70
10.2 Geothermal Resources in Victoria ...................................................................................... 71
10.3 Local Geothermal Potential ................................................................................................. 72
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Bioenergy............................................................................................................. 74
11.1 Biomass Resource ................................................................................................................ 74
11.1.1 Existing Forestry Operations ......................................................................................................... 74
11.1.2 Agricultural By-products and Residues ...................................................................................... 75
11.1.3 Waste Materials ................................................................................................................................. 76
11.1.4 Potential for Future Bioenergy Cropping ................................................................................... 77
11.2 Greenhouse gas emissions ................................................................................................. 79
11.3 Bioenergy Status................................................................................................................... 80
11.4 Modelling Results ................................................................................................................. 83
11.5 Sensitivity Analysis .............................................................................................................. 87
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Related Benefits and Impacts ............................................................................ 90
12.1 Related Benefits and Impacts .............................................................................................. 90
12.2 Energy Security and Vulnerability ...................................................................................... 92
12.2.1 Energy vulnerability at the household level ............................................................................... 92
12.2.2 Energy vulnerability for local business ....................................................................................... 93
12.2.3 Energy vulnerability in the agricultural sector ........................................................................... 93
12.3 Greenhouse Gas Emissions ................................................................................................ 94
13
Conclusions and Recommendations ................................................................ 95
14
References ......................................................................................................... 103
15
Abbreviations .................................................................................................... 118
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Figures
Figure 2-1: Murchison electricity supply area – see shaded field (provided from Powercor) .......... 17
Figure 2-2: Murchison load curve from January 2012 to October 2012 .............................................. 18
Figure 3-1: Representation of the Electricity Delivery Model (AER, 2008) .......................................... 20
Figure 3-2: High Voltage Shared Electricity Network in Victoria (AEMO, 2012a) ............................... 20
Figure 3-3: 22 kV supply to Murchison (provided by Powercor) .......................................................... 22
Figure 3-4: Murchison town 22 kV network (provided by Powercor) ................................................... 23
Figure 4-1: An example of an aggregated DR program ......................................................................... 28
Figure 4-2: Connection Process for Medium-scale Distributed Generation (VCEC, 2012) ................ 39
Figure 7-1: Levelised Cost of Energy (Melbourne Energy Institute, 2011) .......................................... 45
2
Figure 8-1: Worldwide annual global solar exposure in kWh/m (Creativhandz Energy Solution,
2012) .................................................................................................................................. 48
Figure 8-2: Solar operating plants with capacity of more than 30 kWe (Australian Government,
2012) .................................................................................................................................. 50
Figure 8-3: Murchison Global Solar Exposure by Month and Annual Average (BOM, 2012b) .......... 52
Figure 8-4: Sensitivity analysis on 1.6 MWe solar PV in Murchison ..................................................... 56
Figure 8-5: Sensitivity analysis on 5 MWe solar PV in Murchison ........................................................ 57
Figure 9-1: Hydroelectric power generation (IRENA, 2012a) ................................................................ 58
Figure 9-2: Hydro generators in Victoria (SV, 2012) .............................................................................. 62
Figure 9-3: Goulburn River system map (SKM, 2006) ........................................................................... 63
Figure 9-4: Sensitivity analysis on 1.6 MWe hydropower in Murchison .............................................. 68
Figure 9-5: Sensitivity analysis on 2.1 MWe hydropower in Murchison .............................................. 69
Figure 10-1: Geothermal temperatures of Victoria at 1500 m depth (SKM, 2005)............................... 71
Figure 10-2: Geothermal temperature of Murchison at 1500 m (SKM, 2010) ...................................... 73
Figure 11-2: Bioenergy electricity generation total for Australia (CEC, 2011b) .................................. 80
Figure 11-3: Bioenergy electricity generation by state in Australia (CEC, 2010b) ............................. 81
Figure 11-4: Bioenergy generators in Victoria (CEC, 2012b) ................................................................ 82
Figure 11-5: Sensitivity analysis on 1.6 MWe gasifier system in Murchison ....................................... 88
Figure 11-6: Sensitivity analysis on 1.6 MWe ORC system in Murchison............................................ 88
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Tables
Table 2-1: Residential electricity consumption in Murchison (ABS, 2011) ......................................... 16
Table 4-1: Benefits of demand response (Crossley, 2005) ................................................................... 28
Table 4-2: Barriers to demand response (Crossley, 2005) .................................................................... 29
Table 4-3: Understanding of the term community energy .................................................................... 30
Table 4-4: Basic Models for Community Energy (Martin, 2012) ........................................................... 34
Table 4-5: Comparison of community ownership models in the USA (NREL, 2010).......................... 36
Table 7-1: Data and assumptions used for financial modelling ........................................................... 46
Table 8-1: Greenhouse Gas analysis of solar PV ................................................................................... 51
Table 8-2: Solar PV energy generation modelling results ..................................................................... 53
Table 8-3: Solar PV energy generation modelling results ..................................................................... 53
Table 8-4: Data and results of key financial parameters (all in 2012 AU$) of solar PV 1.6 MWe ....... 54
Table 8-5: Data and results of key financial parameters (all in 2012 AU$) of solar PV 5 MW e .......... 55
Table 9-1: List of operating micro hydropower plants .......................................................................... 60
Table 9-2: Typical Data and Figures for Hydropower Technology (IEA, 2010b) ................................. 61
Table 9-3: Hydropower energy generation modelling data/assumptions and results – 1.6 MWe ..... 66
Table 9-4: Hydropower energy generation modelling results – 2.1 MWe............................................. 66
Table 9-5: Data and results of key financial parameters (all in 2012 AU$) of hydropower 1.6 MW e . 66
Table 9-6: Data and results of key financial parameters (all in 2012 AU$) of hydropower 2.1 MWe . 67
Table 10-1: Geothermal Power Summary ............................................................................................... 71
Table 11-1: Goulburn district agricultural commodities ....................................................................... 75
Table 11-2: Planted fruits in the Goulburn Valley region in 2010 ......................................................... 76
Table 11-3: Summary of LCA bioenergy scenarios vs current practice fossil fuel scenario from IEA
Task 38 (Bird et al, 2011) ................................................................................................. 79
Table 11-3: Gasification and ORC energy generation modelling – 1.6 MWe ....................................... 83
Table 11-4: Cost data for biomass to energy technologies .................................................................. 84
Table 11-5: Estimated Bioenergy Crop Harvesting Costs (Ghaffariyan et al, 2011 and Sylva
Systems, 2011) ................................................................................................................. 84
Table 11-6: Cost data for biomass production and transportation (Abadi, 2011) .............................. 85
Table 11-7: Data and results of key financial parameters (all in 2012 AU$) of a gasification system
at 1.6 MWe ......................................................................................................................... 85
Table 11-8: Data and results of key financial parameters (all in 2012 AU$) of an ORC system at 1.6
MWe ................................................................................................................................... 86
Table 12-1: GHG emissions avoided through the implementation of the proposed renewable
energy technologies ........................................................................................................ 94
Table 13-1: Summary of findings ............................................................................................................. 98
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Appendices
Appendix A
Regional Land and Climate Characteristics
Appendix B
Solar Power
Appendix C
Geothermal Energy
Appendix D
Bioenergy
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1 Introduction
Through the 100% Renewable Communities program, the community of Murchison, Victoria aims to
collectively reduce energy consumption, increase energy efficiency, and explore pathways to establish
the feasibility of local generation and ownership of renewable energy via an assessment of local
resources, current renewable energy technology and preliminary financial analysis.
1.1 Project Background
The 100% Renewable Communities program is a project of Central Victoria Solar City, part of the
Australian Government’s Solar Cities research trial into energy use, energy efficiency and renewable
energy generation. Sustainable Regional Australia manages the Central Victoria Solar City Project.
Sustainable Regional Australia is committed to viable regional communities through establishing
community owned renewable energy assets. A renewable energy asset that operates as a community
enterprise brings significant economic, environmental and social value to a community. As regional towns
confront higher electricity prices and struggle for their independence, a community owned renewable
energy asset is an avenue to establish energy security, to provide a positive return on investment, provide
local employment, stimulate social cohesion and provide a clear pathway to tackle climate change.
Building on the pilot project in Newstead called Renewable Newstead, Sustainable Regional Australia,
has partnered with Murchison and Kyabram to collectively reduce energy consumption and explore
pathways to establish local generation and ownership of renewable energy. These projects are
Renewable Kyabram and Renewable Murchison.
There will be a separate Feasibility Report for Renewable Kyabram and Renewable Murchison.
This Pre-Feasibility Report for Murchison community through the Renewable Murchison project
formalises the assessment of local resources, current renewable energy technology and preliminary
financial analysis. The Report has been prepared by Earth Systems in association with Sustainable
Regional Australia.
1.2 Objectives and Scope
The purpose of this report is to provide an initial assessment of the various local renewable energy
generation options that exist for the town of Murchison in the City of Greater Shepparton, Victoria.
It intended to be used for the following:




Estimate current consumption
Basis for more detailed planning
Allows the community to begin a dialogue with potential partners/investors
Attract local investors and involvement
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The scope of works undertaken by Earth Systems in the preparation of this document includes:






A basic analysis of the current and projected future electricity demand in Murchison and a
summary of the characteristics of the local electricity grid;
A summary and discussion of potential connection, power purchase and ownership models for
local generation, including micro-grid and behind-the-meter scenarios;
A summary of local land, climate, waste heat, and biomass resource potential for the Murchison
region;
A technology review and, (where appropriate) pre-feasibility financial assessment of the
opportunities for the following renewable generation options: solar, hydropower, bioenergy and
geothermal power;
A shortlist of key renewable generation opportunities identified in the study;
Discussion of related benefits and impacts of local renewable power generation in regional
communities.
1.2.1 Exclusions
Wind Energy. Based on discussions from the initial kick-off meeting, the present study did not consider
wind energy for Murchison as it was felt from local knowledge that the wind resource in and around
Murchison was not especially good. For reference, using data from the weather station at Tatura the
estimated annual average wind speeds at 120m elevation is approximately 5.2 m/s, which is too low to
achieve good economic performance with most conventional wind turbines. Particular low-speed turbines
with performance curves better matched to the resource in Murchison may be worth considering at some
future point.
Pumped Hydropower. Consideration of pumped hydro storage systems has not been included in the
preliminary energy generation and financial analysis.
Gas. There is currently no reticulated natural gas in Murchison.
Geothermal. Only geothermal technology relating to electricity generation has been included in the
analysis in this report. Geothermal heat pumps have not been included in this review, as they do not
constitute power generation.
1.3 Stakeholders Role and Responsibilities
Renewable Murchison
Renewable Murchison is a project in the 100% Renewable Communities program where Sustainable
Regional Australia partners with committed and connected community leaders to trial appropriate
pathways to support the take up of products and services and the extent to which small communities can
collectively reduce their electricity consumption. In addition, the trial will test ways to supply their town or
community with 100% renewable energy for their stationary energy needs.
Renewable Murchison represents the community of Murchison. The project is validated by the Murchison
Community Plan where a priority project to develop a district energy plan was determined. Renewable
Murchison has two paid employees – a Community Engagement Officer employed for one day a week
and a Home Energy Assessor employed for three days a week.
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GV Community Energy
GV Community Energy is a not-for-profit organisation established in September 2010 and provides a
community service to assist residents, businesses, community organizations and government authorities
to reduce their carbon footprint through the introduction of renewable and/or low emission energy
technologies. GV Community Energy entered into an Memorandum of Understanding with Sustainable
Regional Australia to facilitate the development of a community leadership group to govern the project
and provide products and services to participants within the program.
Renewable Murchison Community Leadership Group
The Community Leadership Group represents the community of Murchison in providing input into project
decisions.
Earth Systems
Earth Systems is a multidisciplinary environmental and social consulting firm, which develops and
implements innovative and effective environment, water and sustainability solutions throughout the world.
Established in 1993, we have successfully completed over 500 major projects in Australia, Asia, Africa,
South America, North America and the Pacific.
Earth Systems provides high quality services and solutions in the areas of environmental and social
impact assessment, water management and treatment, energy efficiency, carbon accounting and
community consultation and development.
Earth Systems research and development capabilities help to ensure that we are leaders in finding new
and more sustainable solutions to complex environmental problems.
Earth Systems was contracted Sustainable Regional Australia to deliver the Pre-Feasibility Report.
Sustainable Regional Australia Pty Ltd
Sustainable Regional Australia Pty Ltd (SRA) is a private company majority owned by the Central Victoria
Greenhouse Alliance, the region’s earliest climate change action groups with representation from fourteen
local governments in the Central Victorian region.
SRA manages the Central Victoria Solar City project and is the lead proponent of the Central Victoria
Solar City Consortium. Consortium members include Bendigo and Adelaide Bank, Central Victoria
Greenhouse Alliance (CVGA), Origin and Powercor.
The Central Victoria Solar City (CVSC) research trial is part of the Australian Government’s Solar Cities
program. The trial involves a variety of projects to test the effectiveness of different energy efficiency and
renewable energy options in reducing energy use and reliance on non-renewable energy. This includes
trialing the uptake of energy efficient measures and their impact on consumer energy use and explores
options to address a number of challenges in delivering sustainable energy outcomes in Australia
including distributed generation, renewable energy and load management.
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The CVSC project has developed a number of programs, products and services that can help
householders, businesses, community centres, schools and hospitals in the region to reduce their energy
use and/or transition towards more renewable energy sources.
The CVSC project is funded by the Department of Climate Change and Energy Efficiency, Central
Victoria Solar City consortium, Sustainability Victoria and the Sustainability Fund.
Department of Climate Change and Energy Efficiency
The Department of Climate Change was established on 3 December 2007. On 8 March 2010, a new
Department of Climate Change and Energy Efficiency was established. The Federal Government
Department of Climate Change and Energy Efficiency funds the Central Victoria Solar City project and
works to reduce Australia’s greenhouse gas emissions, adapting to the impacts of climate change and
helping to shape a global solution.
Sustainability Victoria
Sustainability Victoria was established under the Sustainability Victoria Act 2005. Sustainability Victoria
contributes to a liveable and prosperous Victoria by delivering integrated waste management and
resource efficiency programs. Sustainability Victoria is a key funding supporter of the project.
1.4 Approach
Commencing with a community stakeholder pre-report briefing to confirm the objectives of the study, the
basic step-by-step approach taken in the pre-feasibility assessment of renewable energy options is
typically as follows:
1) Establish baseline community energy usage via available data from local community home and
industry energy assessments / data access from network provider (if possible), and any known
future developments which may impact future local demand;
2) Identify any significant and realistic opportunities for efficiency measures which may have an
impact on long-term energy use in the region (these to be implemented first if they are low cost thus reducing the size of the required renewable generator and hence capital cost);
3) Identify any industrial co- or tri-generation opportunities in the local area which may benefit in
particular from a combined heat and power renewable installation (such as a biomass combustor
or a biogas facility);
4) Initiate a dialogue with the network provider to establish the characteristics of the electricity grid in
the area - any particular "strong" or "weak" points which may have a bearing on the placement of
any large grid-connected generation. Identify any known planned grid upgrades or expansions
which may affect or be influenced by local generation. Also, keep abreast of the development/rollout of smart network/grid system that allows interaction between the community and network
operator for optimising energy generation and minimising associated costs (e.g. in a case of
multiple renewable generation options, the cheapest option would take precedence when
resource is available);
5) Once the projected demand is known, as well as the grid characteristics and any local industrial
electricity and large-scale heat or refrigeration needs, a range of possible scales for renewable
generation, as well as potential locations can be proposed;
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6) Undertake an analysis of the availability and quality of the renewable resources in the local
region, using, for example, mapped datasets for solar, geothermal and hydro power;
7) Biomass resources are then assessed based on local knowledge of the agricultural, horticultural,
food production and waste processes in the area, assuming economically available resources
may be up to 50 km away. This generally needs to be treated case-by-case on the basis of the
opportunity, the resource type, the technology and the end-user site (which is normally an
industrial heat and power user);
8) All of the above inputs, combining some assumed generation system and infrastructure set-up
costs as well as the quality of the renewable resource and some agreed financial hurdle rates
(i.e. payback, IRR etc.) are then used to generate a range of LCOE (Levelised Cost of Energy)
values for each renewable generation scenario.
9) The LCOE, in $/MWh, can be compared for one scenario against another, as well as with current
electricity prices to determine whether grid feed-in or behind-the-meter generation makes more
sense.
10) From a comparison of the scenarios, a shortlist of the most viable renewable generation options
to match projected local demand is produced, as a basis for further detailed (i.e. investmentgrade) feasibility study/ies and long-term policy / direction setting on local renewables.
In the current work, the above process was undertaken for the assessment of solar, biomass, geothermal
and hydropower resources.
1.5 Demographic Analysis
Murchison is a small community situated on the banks of the Goulburn River, 35 kilometres south of
Shepparton and 160 km north of Melbourne in the state of Victoria.
Murchison is known as the "River Bank Garden Town" and is full of character and charm. The town is
also famous for its cheese, wines, and annual events such as the Murchison 10,000 footrace and
woodcut fundraiser.
Murchison is known for the discovery of gold in the 1850’s, paddle steamers up to 1887 and holding
4,000 Italian, German and Japanese POWs during World War II. Murchison is also the site of the
legendary Murchison Meteorite which estimated to be over 4.5 billion years old and broke up in the skies
above the town on 28 September 1969.
The following profiles for Murchison have been drafted using information from the 2011 Australian Bureau
of Statistics Census, unless otherwise noted. The information used is based on the combination of the
postcode 3610 category data statistics (from ABS census) and the statistics for solar power (from REC
registry) to provide data on residential solar installations.
Population
Murchison has a population of 1,675 where 55.2% were male and 44.8% were female. Aboriginal and
Torres Strait Islander people made up 2.2% of the population. The median age of people was 42 years
and for Aboriginal and 31 years for Torres Strait Islander people.
There are 399 families in Murchison with an average of 2 children per family. Children aged 0 - 14 years
made up 18.7% of the population which was higher than the Victorian average of 12.6% and people aged
65 years and over made up 16.5% of the population which was higher than the Victorian average of
14.2%.
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Employment
Labour force statistics were aligned with Victorian average where the 660 people who reported being in
the labour force, 56.8% were employed full time compared with a Victorian average of 59.2%. 30.2%
were employed part-time compared with 29.6% Victorian average. Unemployment was higher than the
rest of Victoria where 6.7% were unemployed against a Victorian average of 5.4%.
The most common occupations in Murchison included Managers 20.3%, Labourers 17.9%, Professionals
13.7%, Technicians and Trades Workers 12.7%, and Community and Personal Service Workers 10.9%.
Of the employed people in Murchison, 6.0% worked in School Education. Other major industries of
employment included Dairy Cattle Farming 5.9%, Sheep, Beef Cattle and Grain Farming 4.9%, Hospitals
3.7% and Fruit and Tree Nut Growing 2.9%.
The median weekly personal income for people aged 15 years and over in Murchison was $462
compared to the Victorian average of $561. Family and household income was significantly less than the
Victorian average with $1034 (Victorian average of $1460) and $856 (Victorian average of $1216) weekly
income respectively.
In the year before the Census, 19.6% of people did voluntary work through an organisation or a group
compared to the Victorian average of 17.7%.
Households
In Murchison, there were 535 occupied private dwellings. Of occupied private dwellings, 91.4% were
separate houses, 1.9% were semi-detached, row or terrace houses, townhouses, etc., 1.7% were flats,
units or apartments and 5% were other dwellings.
Of the occupied private dwellings, 7.5% had 1 bedroom, 15.5% had 2 bedrooms and 50.8% had 3
bedrooms. The average number of bedrooms per occupied private dwelling was 3. The average
household size was 2.5 people. Of occupied private dwellings 40.6% were owned outright (compared with
a Victorian average 34.2%), 35.5% were owned with a mortgage and 17.6% were rented. Of all the
households in Murchison, 72.4% were family households, 25.7% were single person households and
1.9% were group households.
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2 Current and Projected Local
Electricity Demand
Residential Power Consumption
Data on residential power consumption is based on the 2011 census data collected from ABS (2011) and
household survey of 50 dwellings (provided by Ross Egleton from SRA) of their average energy
consumption in summer and in winter. The resulting data is shown in the table below.
Note that the survey data provided does not indicate whether the dwellings utilise solar power. According
to the REC Registry data (CER, 2012a), there are a total of 120 installations of solar PV systems in
residential dwellings in Murchison.
Table 2-1: Residential electricity consumption in Murchison (ABS, 2011)
Summer electricity consumption
24.34 kWh/day/dwelling
Winter electricity consumption
27.44 kWh/day/dwelling
Data provided by Powercor for electricity consumption is estimated at approximately 8,300 MWhe/year.
The data is based on recorded values at the Murchison line recloser (circuit breaker), which includes rural
load around the town (see Figure 3-3 in Section 3.4). The shaded area shown in Figure 2-1 shows the
extent of the area that the electricity consumption data is based (this includes Avonlea flower farm at 420
River Road, Murchison).
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Figure 2-1: Murchison electricity supply area – see shaded field (provided from Powercor)
Power Load Data from Powercor
Data provided by Powercor has given an indication of the power load characteristics and consumption of
the area. This 5-minute interval data spanned 1 January 2012 to 15 October 2012. See below for the
power load curve of Murchison.
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Figure 2-2: Murchison load curve from January 2012 to October 2012
The load curve shows that base load occurs around 0.57 MW e and peak load at 2.8 MW e over a 10month period. The ‘spikes’ represent high demand period, which most likely occur during the summer
months due to the extensive use of air conditioners. This may indicate the need to run the proposed
renewable energy plant(s) in parallel to the grid such that any excess electricity required could be
obtained from the purchase of electricity from the grid (e.g. GreenPower).
The curve also shows that for about the 90% of the time, power requirement is at around 1.6 MW e.
However, based on the total power consumption in MWhe, the town requires approximately 8,300
MWhe/year.
For the purpose of the modelling analysis, a constant year-by-year electricity consumption of 8,300
MWhe/year has been assumed.
This then forms the basis of the scale of the modelling scenarios:

1.6 MW e nameplate capacity (meeting the town’s electricity demand for 90% of the time)

8,300 MWhe of electricity production per year (the nameplate capacity for this generation would
differ depending on the type of renewable energy technology, e.g. solar power capacity would
have to be bigger than bioenergy capacity to produce the same amount of energy)
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3 Local Electricity Grid Infrastructure
3.1 Introduction
Fundamental to evaluating the potential for renewable energy generation in Murchison is a thorough
understanding of the local electricity network’s capability to accept and distribute the generated electricity.
Generally with small-scale generation, two installation options exist: either a grid-connected option, where
electricity is “pooled” and distributed around the network, or a stand-alone option, where electricity is
generated specifically to meet a point demand. The relative merits of each system in regard Murchison’s
infrastructure are discussed in Chapters 3 and 4 of this report.
3.1.1 Electricity Generation in Victoria
In recent years a number of new small-scale generators have been installed in Victoria. Historically,
electricity has been generated in the La Trobe Valley in large coal-fired power stations, and distributed to
the rest of Victoria through extensive extra-high voltage power networks (VCEC, 2012). Recently this has
been supplemented by higher efficiency natural gas fired plants, which offer fast response to demand
changes.
Increasing energy prices, environmental concerns and grid instability have triggered significant interest in
renewable energy generation and distributed generation. As of 2010, approximately 4% of total electricity
consumed was from renewable sources, 87% of which was generated by large hydroelectric schemes in
the North East (SV, 2011) and 100MW e-scale wind farms. The federal government-mandated renewable
energy target (RET) is 20% of Australia’s electricity supply will come from renewable sources by 2020
(DCCEE, 2012a).
Small (i.e. household) scale renewable and low-emissions grid-connected generation has been
incentivised since 2011 by implementation of a feed-in tariff system which guarantees at minimum, ‘fair’
price for electricity exported to the grid, and issuance of solar credits, Renewable Energy Certificates
(RECs). This has led to a proliferation of domestic solar photovoltaic installations and concentrated solar
power projects, with 2 GW of photovoltaic capacity installed nationwide (CER, 2012a) at the present time.
The rapid expansion of small-scale distributed generation (DG) has already put pressure on the Victorian
electricity network, with exponential increase in DG predicted for the coming decade.
3.2 State of the Network
3.2.1 Network
The Victorian electricity network is built on a framework of extra-high voltage (EHV) transmission lines,
which transport electricity from generators to terminal substations at 220kV, 330kV and 500kV. The subtransmission network at 66kV delivers electricity from the transmission voltage to the distribution network;
and a distribution network at 22kV and below distributes the electricity to the end user (AER, 2008).
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Figure 3-1: Representation of the Electricity Delivery Model (AER, 2008)
Figure 3-2: High Voltage Shared Electricity Network in Victoria (AEMO, 2012a)
3.2.2 Constraints and Scheduled Upgrades
There do not appear to be any current or projected network constraints likely to require infrastructure
upgrade in the next few years in the Murchison region. Personal communication with a System Planning
Engineer from Powercor has indicated that it is possible to connect up to 2 MW e in Murchison town to the
existing 22 kV system without major upgrades. Opportunities for generation along this 22kV corridor from
the Mooroopna zone substation to Murchison should be prioritised, if the main objective of generation is
to be grid-exported electricity (see Figure 3-3 and Figure 3-4).
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EARTH SYSTEMS
3.3 Legislative and Regulatory Requirements
3.3.1 Administrative Organisation
At the administrative level the Victoria electricity network is part of the wider National Electricity Market
(NEM) which transports electricity throughout the eastern and southern states. The NEM is the largest
integrated electricity network in the world with a span of 4,500 km, and encompasses 13 distribution
networks and over 200 large generators. The flow of electricity through the NEM is managed by the
Australian Energy Market Operator, or AEMO (SP Ausnet, 2011).
The purchase and dispatch of electricity from the generators to the consumers is coordinated by the
Australian Energy Market Commission (AEMC), a division of the Australian Competition and Consumer
Commission (ACCC). The AEMC develops the National Energy Rules by which participants must abide.
The local Distribution Network Service Provider (DNSP) for Murchison is Powercor, who is responsible for
the construction and maintenance of the physical assets of the network.
3.3.2 Scheduled vs Unscheduled Generation
According to the National Electricity Rules (NER, ‘the Rules’), a new generator greater than 30 MWe
capacity intending to connect to the network must register with the AEMO and apply for an assessment of
the transmission network to establish whether augmentation is necessary. For generators in the 5 to 30
MWe range, whilst AEMO registration is encouraged, an exemption may be sought. For generators less
than 5MWe who connect to the distribution network, the network service provider (Powercor) must be
engaged, but AEMO registration is not necessary and a blanket exemption applies.
Under the Rules, generators are classified as either, scheduled, semi-scheduled or unscheduled, which
describe the degree of control the AEMO has over dispatch of electricity from a particular generator.
Necessarily, generators operating on intermittent energy sources such as solar cannot declare in
advance the amount of electricity that they will be able to produce at any one time; by comparison,
generators using fossil fuels and biomass for energy can schedule generation to meet anticipated peaks
in the load profile. In the current market system this may give fossil-fuels and biomass a competitive
advantage with regard to electricity dispatchability, especially in the case of gas-fired generators which
can meet peak demand (and charge high electricity prices) within a matter of minutes. From a system
stability perspective, the ability of intermittent generation to meet demand usually relies on extensive
voltage and frequency control equipment, and conservative operating procedures.
3.4 Analysis – Local Grid in Murchison
The local network in Murchison is supplied via a 22kV feeder from the Mooroopna zone substation. For
the purposes of considering town-scale renewable generation options, sites near or adjacent to this
feeder should be prioritised. As advised by a Powercor staff, up to 2 MW e generation in Murchison town
can be connected to the existing 22 kV system without major upgrades. Further detailed discussion with
Powercor will be required if this project proceeds to the next stage.
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Figure 3-3: 22 kV supply to Murchison (provided by Powercor)
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Figure 3-4: Murchison town 22 kV network (provided by Powercor)
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4 Community Power Generation
4.1 Grid Connected vs Stand-Alone Generation
Two connection options are available to a new small-scale generator in Murchison: connection to the
shared electricity network (‘grid connection’) which would supply electricity to the common “pool”, or
connection to a point demand which would supply electricity only to that demand (“stand-alone
generation”). The stand-alone arrangement would work well when coupled with microgrid technology
and/or virtual net metering (VNM).
Grid Connection
Grid connection provides the greatest flexibility for the generator in that all electricity generated will be
able to be used somewhere in the network. However the risk of an outage or reduced generation (a
particular issue for intermittent generation sources) is effectively borne by the network operator
(Powercor) with an associated cost that is passed on to the generator. Combination of the costs
associated with connecting to the network and the possible need to maintain the requisite high voltage
switchgear (this may not be applicable to this project), can make grid connection prohibitively expensive
for small and remote generators. Using high voltage reduces power losses as well as current to provide
the same power, therefore making it suitable for providing power over long distances. However, at high
voltage, the lines require a lot of insulation to stop the energy from flowing to the line structures on to the
ground causing faults, which would incur additional cost. On the other hand, lower voltage level may be
suitable for distribution of the energy over moderate distances to central points of residential, commercial,
and industrial load. In the case of small scale power generation technologies, the power is usually
generated close to where it is consumed on the network to which it is connected, therefore eliminating the
need to increase the voltage for transmission purposes (further analysis would be required).
(Westernpower, 2011)
Stand-alone Generation
Stand-alone generation can be the most practical option for the small generator. There are two types of
stand-alone generation, completely off grid and parallel (Clarke Energy, 2012). Off grid generation is
often used in areas isolated from the grid or in areas with unreliable local electricity networks
characterised by regular interruptions in power supply. Due to the intermittent nature of most forms of
renewable energy it is preferable in many circumstances to have a system capable of operating parallel
to, or in isolation of, the grid.
Typically a stand-alone generation plant utilising parallel mode will be installed customised to the load
duration profile of the demand point, offsetting grid-purchased electricity to the maximum possible extent
without exporting electricity back to the grid. The demand point retains its connection to the network in
order to mitigate risks associated with unforseen generator outages. Some switching equipment is still
required (i.e. to disconnect the connection to the local area system during grid electricity supply failure),
but infrastructure and compliance costs are reduced as costs of installing external site connections are
avoided (DECC, 2013). The change from parallel to stand-alone mode may occur instantaneously when
the local area supply system suffers an outage. In this situation, it should be possible for the small-scale
generator to continue supplying the designated site without interruption, on condition that the site load
can be immediately limited to the output level of this small-scale generator. This is usually achieved using
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load monitoring and control equipment, which can automatically disconnect selected parts of the site load
(Clarke Energy, 2012).
This also affords the small-scale generator a significant economic advantage by offsetting grid electricity
from the point-source at retail rates, thus creating a much higher value for the electricity generated. A
number of benefits with having a small-scale generator in parallel mode include (DECC, 2013):



The local area supply system to which the town is connected can provide any town power
demands that are in excess of the net power output of the generator plant: this is known as ‘topup’ power.
The local area supply system can instantaneously meet the total town demand in the event of the
generator plant shutting down suddenly: this is known as ‘back-up’ or ‘stand-by’ power. Back-up
is normally achieved without any loss of site power supply.
Potentially, it is also possible to export excess power from the small-scale generator back to the
grid and generate financial benefits.
However, according to a 2007 European Union report (Masokin, 2007), this type of generation faces a
number of barriers to growth including onerous planning and permitting processes. ‘Even where support
frameworks exist, it often contains significant uncertainty that may lead to investments being delayed’
(Masokin 2007, p.13).
Another option in some circumstances is off-grid generation. Eligible projects will receive additional
renewable energy credits for systems up to 100kW under the solar bonus scheme. To be eligible, a
system needs to be installed before June 30 2013 and either (CER, 2013a):

a small-scale solar panel, wind or hydro system installed at least 1 kilometre from the nearest
main-grid line, or

a small-scale solar panel, wind or hydro system less than 1 kilometre from a main-grid line where
the owner has provided written evidence from the local network service provider that the total
cost of connecting the SGU to the main-grid is more than $30,000.
A 100kW off-grid system installed in the Murchison region would currently be eligible for 1,777 Smallscale Technology Credits (STC’s) (CER, 2013b) which according to the spot price of $31.75 as at 14
January 2013 (CEC, 2013a), would equate to an up-front system rebate of $56,420.
The two options described above would work well with microgrid technology and/or virtual net metering
(VNM). In particular, VNM has been investigated thoroughly by SRA (see details below) and may
represent a good coupling arrangement with a stand-alone parallel mode generation system.
Microgrid Technology
At the time of writing, microgrid technology requires large upfront investment. Although microgrid
technology has its benefits (as described below), the large investment required may not deem the
technology feasible. It is likely to be more beneficial for sites with frequent power failures, many grid
network constraints (e.g. network reaching its maximum capacity with excess demand), and/or sites
prone to natural disasters that may affect the power network (e.g. earthquakes, hurricanes, etc.).
Microgrids are small-scale versions of typical large centralised electricity system, where it can generate,
distribute and regulate the flow of electricity to end customers. Microgrids are typically connected to the
large-scale centralised grid via a common coupling, which can be disconnected if required, i.e. microgrids
can function independently. Microgrids could increase the efficiency, reliability, and create ‘islands’ (or
stand-alone systems) of sustainable energy within the larger grid. The main benefits of microgrids are
(Yii, 2009):
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•
Microgrids increase power supply reliability
•
Microgrids make it easier to efficiently meet growing consumer demand
•
Microgrids make it possible to deploy clean, renewable energy
The main difference between centralised power generation system and a microgrid system is that
centralised power generation relies heavily on large base load power plants, whereas a microgrid system
has local generating source(s), i.e. small scale power plant(s) located within a certain site/town. In a
centralised power generation system, disruption of power between the power plants and the delivery of
that electricity to end users can occur anywhere along the network of transformers, transmission lines and
substations. In contrast, the ‘locality’ of a microgrid system allows rapid response to address instabilities
in the transmission grid, compensate load reduction, and efficient deployment of available generation.
(Santoianni, 2012)
Microgrids are designed and customised to the mix of electricity (and sometimes heat) needed for a
particular community and allow automated adjustable and sheddable loads to improve efficiency and
reliability (Santoianni, 2012).
Microgrid technology often requires large upfront investment which can be a barrier to entry. Siemens, a
key developer of microgrid power generation resources and management software, has estimated that a
microgrid to support a 40 megawatt (MW) load can require an investment upwards of US$150 million.
Although large-scale energy storage has been cost prohibitive, the smaller scale of microgrid storage,
efficiency improvements, and the ability of local distribution networks to manage intermittency are
expected to improve the economics in the foreseeable future. (Santoianni, 2012)
Because there are numerous technology options for generating resources, energy storage, smart meters,
transformers, control system architecture, and communication networks, microgrid planning is a
complicated exercise in investment optimisation. A comprehensive microgrid cost benefit analysis would
be necessary to carry out to evaluate the financial decisions (e.g. NPV, IRR), emissions performance,
reliability, and occupancy rate while evaluating uncertainty and risks associated with climate, technology
costs, energy prices, and changing demand. (Santoianni, 2012)
Virtual Net Metering
Virtual Net Metering (VNM) is where a component of the electricity consumption metered at one or more
sites, is 'netted-off' against the electricity exported from a generation site within the network area. VNM
could add direct financial value to the business case for community energy projects, without the need for
feed in tariffs or other government subsidies or funding. VNM allows utility customers to share the
electricity output from a single power project, typically in proportion to their ownership of the shared
system. This is especially applicable for community renewable energy projects, typically relying on
offsetting electricity at retail price. (SRA, 2012)
Implementation of each VNM project may require a single electricity retailer to coordinate the generation
and customer billing arrangements. Currently the wholesale price is established through either the half
hourly spot price market or through power purchase agreements (PPA's) and may range in the region of
$80 to $120/MWh (8 -12c/kWh). (SRA, 2012)
Distributors and Generators may argue that VNM allows the beneficiaries to have a 'free-ride' and give
access to poles and wires without the normal distribution charges that are currently collected through
normal retail billing practices. Even some renewable energy generators, whose customers currently pay a
network fee, may argue that VNM offers an unfair advantage. Whole communities would perceive VNM
as a step towards a level playing field. Some trade-offs and limitations will need to be set in place to
provide balance in this area.
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One suggestion by SRA could be setting longer term limits such as capping total generation under VNM
to a limit such as 1 GW of installed capacity per state, and/or individual projects capped to 20 MW. SRA
also proposes the 'netting-off ' be performed either annually or over a billing period. Netting daily or half
hourly should be avoided in early years as this may require additional metering and may be hindered due
to technical limitations. The life of the VNM agreement could also be capped at 8-10 years to present it as
a pioneering initiative. (SRA, 2012)
4.2 Demand Response and Load Shedding
In order to help manage energy use in times of peak demand, utilities throughout Australia are starting to
employ demand response programs. Demand Response (DR), also referred to as Demand-Side
Management (DSM) or Demand-Side Participation (DSP), involves organising consumers to reduce their
reliance on the energy grid at times of peak demand either by reducing energy used or by starting on-site
generation which may or may not be connected in parallel with the grid, usually in response to high peak
demand, problems in the electricity network, or high prices in the electricity market (EnerNOC, 2012;
Crossley, 2005). Load shedding is a practice that utilities use at peak times when the network is unable to
meet demand. It involves imposing brownouts (reduced electricity use) or rolling blackouts across the
network, usually targeting major industrial electricity consumers.
Traditional practice in power networks has been to match supply to demand. The problem with this
approach is that demand varies greatly with time (Chen et al, 2010). Utilities need to provide enough
generation, transmission and distribution capacities to cater for peak demand which in Australia amounts
to approximately 40 hours per year (AEMC, 2012). This means that the power network is underutilized
most of the time, which is very costly. As the proportion of renewable sources such as solar and wind
power steadily rises, power supply will become even more time-varying. Shaping demand to reduce the
peak and smooth the variation can greatly improve power system efficiency, thereby saving money and it
is more cost effective for utilities than building new power plants (Chen et al, 2010).
In parts of Europe and North America, demand response programs are mandatory and well established
(Deora, 2013). Most DR programs work in the following way (Crossley, 2005):

DR programs require end-use customers to reduce their electricity use at particular times, i.e.
during peak demand period.

Customers usually pay lower electricity tariffs in return for participating in a DR program.

Customers may also receive payments for the availability of demand response and the load
reductions actually received.
DR programs could also be implemented via a third party aggregator. The following diagram represents
how a DR program works via a third party aggregator.
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Figure 4-1: An example of an aggregated DR program
4.2.1 Benefits of Demand Response
There are many benefits in employing a DR program, such as listed below.
Table 4-1: Benefits of demand response (Crossley, 2005)
Recipients
Electricity retailers and network owners
End-use customers
Benefits

A physical insurance hedge against energy market
volatility

Cost savings from lower market clearing prices and
increased operating flexibility, system efficiency, and
asset utilization

Improved reliability during periods
shortages or network congestion

Deferral of costly (and difficult to site) new generation or
network capacity

A dampening effect on lumpy, asset-intensive and thus
inherently cyclical energy markets

Access to the same or similar price signals provided to
supply-side producers

Payments for availability and actual demand reductions
as well as reduced electricity tariffs

Improved understanding and control of day to day
electricity use (with investment in enabling technologies
such as interval metering, energy management
technology and energy information tools)

Increased customer choice in relation to dealing with high
electricity prices
of
generation
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4.2.2 Barriers to Demand Response
Examples of barriers to demand response are shown in the table below.
Table 4-2: Barriers to demand response (Crossley, 2005)
Barriers
Customer related barriers
Market related barriers

Most customers on retail tariffs never see wholesale electricity
market prices and are therefore unaware of the value of
demand response

Most small customers never see their load profile, because
installing interval metering without subsidies is too costly

Participating in a DR program can be complex (though this may
be mitigated by a third party aggregator, i.e. EnerNOC)

End-use customers must typically make additional investments
in enabling technology to maximise responsiveness

Current market designs do not enable demand response due to
o
Out-dated metering and related technologies
o
A lack of real-time price information reaching consumers
o
Regulated retail prices while wholesale markets have largely
been deregulated
o
System operators focused on supply-side resources
o
A legacy where DR is not considered important

Significant investment is needed in DR infrastructure to enable
markets to communicate the value and cost of electricity

Governments and regulators are key in enabling DR:
o
Benefits of DR are dispersed among different market players
o
Current markets will not develop a meaningful DR capability
without facilitation
A similar DR program is the Western Australian Government’s maximum reserve capacity requirement
(WA Government 2012) which is designed to increase energy efficiency for businesses, reduce peak
energy demand and promote the emergence of a new service industry for demand response providers
which assist businesses to incorporate demand response programs into their business models. The most
pertinent demand response method may be the use of time of use tariffs, which is a separate peak and
off peak tariff (higher rate during peak and lower rate during off peak) to encourage end users to shift load
to off peak period. Not only would this reduce peak load use (and thus energy and money savings), but
also reduce or shift the need for the network operator (i.e. Powercor) for network upgrades.
However, under the National Electricity Rules, amongst other requirements, there is obligation for a
transmission and distribution network service provider (i.e. Powercor) to:

Regularly incorporate forecast loads;
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
Consider the potential for augmentations or non-network alternatives to augmentations, that are
likely to provide a net economic benefit to all those who produce, consume and transport
electricity in the market; and

To provide, install operate and maintain facilities for load shedding in respect of any connection
point at which the maximum, load exceeds 10 MW.
This implies that the network operator may have incentive to promote DR programs to the communities
that it services.
4.3 Community Ownership Models
The understanding of community energy based on extensive surveys in the UK is defined by Hickson &
Ison (2011) as falling into five broad categories as shown in Table 4-3.
Table 4-3: Understanding of the term community energy
Category
Description
Legal
Specifying the legal entity or institutional
arrangement of the project as being without
commercial interests.
Physical
Involving community buildings or
spaces.
Process
Involving local people in decision-making.
Economic
Local people having a financial
stake in the project.
Technical
Relating to the scale of the renewable
technology, where the supply is designed to
match a given community’s energy demand.
When discussing community energy, a distinction is often made between communities of locality and
communities of interest. Community Energy, as discussed here, refers to any type of renewable energy
project in which the local and/or broader community owns some share of the development project, or the
energy produced by the project.
International History
Community ownership of renewable energy projects began as early as the late 1970s, when the first wind
energy co-operatives were set up in Denmark. The success of these co-operative partnerships is evident
today with residents of Danish communities representing over 150,000 households owning 86% of
Denmark’s total installed wind capacity (CEEO, 2003), which amounted to 3,871MW installed capacity
(as of end 2011) accounts for about 26% of Denmark’s electricity generation (EWEA, 2012).
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In Sweden, community investment in renewable energy began from the 1990s when the government
pledged to shut down nuclear power plants as energy efficiency increased and new renewable energy
became available to replace it. By 2000 Sweden had about 240 MW of installed capacity, 25 MW of which
was community owned (Bolinger, 2001).
Germany has followed Denmark’s example and has come up with similar community ownership models
that have strongly influenced the widespread development of decentralized wind energy. In Germany, for
example, over 50% of all renewable projects are community owned (Commission for Environmental
Cooperation, 2010) and, in the case of wind developments, 90% of installed turbines were owned by
citizens, representing over 200,000 individuals acting as shareholders in wind projects (Grepmeier, J. et
al., 2003; Martin, 2012).
The UK also had community owned renewable energy projects from the 1990s, but these had a small
share of national developments and were slower developing when compared with other European
countries in 2000 (Bolinger, 2001). Today there is significant interest in community based renewable
energy developments in the UK with examples of wind, solar, and hydropower projects (Brighton Energy,
2012; Ison, 2010).
Community based renewable energy has also been seen in other countries in Europe including the
Netherlands, and is currently growing in the United States, Canada, Japan and Australia.
Japan’s experience with community owned wind started in 2001 when its first community funded 990 kW
turbine was installed in Hamatonbetsu, Hokkaido, Northern Japan. Today, there are 12 community owned
turbines located across Japan, which total 17,770kW of output capacity. Most of these projects have been
financed through investment fund models, where citizens from all over the country can directly invest in a
given project. While these projects represent a small portion of Japan’s total installed wind capacity, they
are still examples to look up to and follow in the region (Martin, 2012).
In the USA community energy is also growing, with examples of both wind and solar projects (Little Rock
Wind LLC, 2012; Hicks, 2012c). In the USA in particular there are examples of large developers
delivering projects which are ultimately community owned. For example, in March 2009, National Wind,
which has been responsible for developing more than 10 wind farms, formed Little Rock Wind Limited
Liability Company, which is a community-owned wind energy company (Little Rock Wind LLC, 2012).
In Canada efforts have been made to develop community a based wind farms on first nationals land as a
way of bringing economic benefit to first nation people (Hicks, J., 2012b).
Australia
The key current example of community owned power is Hepburn Wind in Victoria, where the community
has developed, and built two wind turbines. Following European models, community ownership of this
project is based on the co-operative model (Hepburn Wind, 2012). Hepburn Wind is the first of a number
of community wind projects underway around Australia including those at Denmark in Western Australia,
New England in NSW and Mt. Alexander in Victoria. The Federal Government’s Solar Cities program has
also led to the development of two solar parks in Bendigo and Ballarat in Victoria (Australian PV
Association, 2012).
Many Australians have been showing support for renewable energy projects through household
installations of solar panels, which has been encouraged through government grants and rebates.
However, these programs rule out people without suitable roofs, apartment dwellers and renters. In
addition, the rebate programs rule out those who may not be able to purchase an entire system but who
might like to participate at a lower level (Webb, 2012). Thus there is a strong possibility that community
based solar projects in Australia would be appealing to households who have been unable to install solar
power.
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One example is the establishment of Embark, a not-for-profit organisation, which resulted from the
Hepburn Wind Project. Embark’s aim was to eliminate barriers to the development of the community
renewable energy sector in Australia, including lack of project funding, specialist information and advice,
reflexive opposition or the impact of poor policy settings (Embark, 2012). Embark has also developed a
website specifically for Australian communities, to provide interested groups with reliable and relevant
information on a range of topics that can help communities assess, plan and implement renewable
energy projects (Embark, 2012).The Community Power Agency (CPA) is another recently established not
for profit organisation playing a similar supporting role in Australia’s renewable energy sector (CPA 2012).
CPA’s current activities include wind projects for New England and Mt. Alexander as well as community
sustainability initiatives in the Blue Mountains and Southern Highlands.
More recently, a project called LIVE Community Power is organising the installation of 1000 solar panels
on the roof of South Melbourne Market, Melbourne, Victoria. The project will enable members of the
community to have financial interest in these 1000 panels. The objective of the project is to allow
community members that do not have appropriate site aspects for solar panel installation (e.g. roofs
shaded by trees, tenants renting apartments/houses in nearby areas, etc.) to still have access to solar
energy. The project is to be completed in 2013. (LIVE, 2013)
The growth in the Community Renewable Energy Sector can be attributed to the associated benefits a
community owned renewable energy asset can provide.
4.4 Community Energy – what makes it work?
A report from 2001 exploring wind power ownership schemes in Europe suggested the community
ownership of wind projects would likely be suitable under the following conditions (Bolinger, 2001):




Economies of scale cannot be achieved, perhaps due to scarcity of suitable land on which to site
larger wind farms.
The potential to realize distributed generation benefits, i.e. by siting projects close to more
densely populated urban areas.
Financing from traditional commercial sources is either unattractive or, for small projects, perhaps
non- existent.
Community support is necessary to usher the project through the planning and permitting stages.
This report looked at community power ownership models existing in Germany, Denmark, Sweden and
the UK in 2000. Of these the UK had a significantly lower level of community investment than the other
three countries. A comparison of the underlying policies and institutions supporting wind development
attributed higher levels of community ownership in the other three countries to (Bolinger, 2001):





feed-in tariffs
tax advantages
standard interconnection agreements
a domestic wind turbine manufacturing base, and
familiarity with co-operative forms of ownership.
Feed-in Tariffs
Germany, Denmark, and to a lesser extent, Sweden, all offer or have offered attractive feed-in tariffs for
wind power. These tariffs, historically set at 90% of the average nationwide retail rate for all customer
classes in Germany and 85% of the local retail rate for small consumers in Denmark, have created a
stable, profitable, and essentially unlimited market for wind power, and one that can be accessed with
32
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very low transaction costs (Bolinger, 2001). On the other hand no feed in tariffs of this sort existed in the
UK as of 2000 and government incentives that did exist were constantly changing. Notably, a feed in tariff
has now been implemented in the UK and seems to be matched by increased community investment in
renewable energy (Brighton Energy Co-operative, 2012; Feed-In Tariffs Ltd., 2012).
Tax Advantages
Tax advantages come in three forms: tax-free generation (at least up to an individual shareholders’ own
energy consumption), refund of energy and/or CO 2 tax, and favourable depreciation rules for businesses.
Depreciation rules, in particular, which allow investors to write off large depreciation expenses against
various other forms of income, may explain the high level of individual farmers that own wind turbines in
the Netherlands (Bolinger, 2001).
Standard Interconnection Agreements
In Germany, Denmark, and Sweden (and other European countries, though notably not the UK),
distribution utilities are required to interconnect small wind projects to the grid according to a predetermined set of rules defining technical requirements and division of financial responsibility. German,
Danish and Swedish generators must pay the cost of connecting to the nearest feasible point on the grid,
while the distribution utility must pay the costs of strengthening or upgrading the grid as necessary to
interconnect the generator (Bolinger, 2001).
Requiring interconnection ensures a community-owned project access to a market (most often the utility
itself, through a feed-in tariff), while pre-defining interconnection requirements and responsibilities (both
technical and financial) enable a community-owned project to accurately estimate the cost of
interconnection in advance (Bolinger, 2001). Both of these factors reduce the project owners’ risk.
Wind Turbine Manufacturing Base
With representatives from turbine manufacturers often playing an important role in instigating or
resourcing community projects, and manufacturers themselves potentially lobbying politicians, the
existence of domestic turbine manufacturing has likely played an important role in community wind power
developments in both Denmark and Germany (Bolinger, 2001).
Familiarity with Cooperative Ownership Structures
In the UK in the 1990s the broad community was not well familiar with the legal structure of co-operatives,
resulting in less development at the community level (Bolinger, 2001).
4.5 Models for Community Energy
Organisational arrangements for community ownership of energy projects vary between projects and
across borders. Differences between organisational arrangements are in part influenced by a particular
countries legislation which will favour certain organisational structures over others. Other factors that
influence the ownership model used include whether investors are located locally to the project or
whether they are simply a ‘community of interest’ comprised of individuals living in many locations with a
common interest in renewable energy. Ownership structures of community energy projects also vary
depending on the vision, values, and mission that a community group has.
Broadly speaking, community ownership models fall into one of the categories outlined in the following
table.
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Table 4-4: Basic Models for Community Energy (Martin, 2012)
Ownership Structure
100% Community
Co-operative
Partnerships/Joint
Ventures
Landowner
Pools
Description
Profit Sharing
Individuals who share the same
interests come together to pool their
capital through the purchase of
shares. Community co-operatives
represent the interests of the whole
community and governance remains
in the hands of this community, with
a one-member, one-vote governance
structure. For this reason, the cooperative needs to be clear on
variables such as what the values
are and who the members can
include (i.e. do they need to be local
investors or can non-local people buy
shares?). Projects are financed,
owned and governed 100% by the
community co-operative.
Any profit earned by the project
based on the sale of energy over
the period of one year is distributed
to each co-operative member
depending on the amount of shares
purchased by each, meaning that
revenues in turn benefit each
member (Bolinger, 2001).
This type of hybrid ownership
structure often occurs when
communities do not have access to
sufficient capital, and, therefore,
partner, in most cases, with private
renewable energy developers,
utilities, or other co-operatives, to
enable project financing. In such
cases, while a community may only
provide a portion of the financing,
ideally, ownership, control and
decision-making should be relatively
equal.
Benefit distribution is usually
dependent on initial investments
made by stakeholders; however,
this equity distribution can vary from
project to project. For example, in
the Middlegrunden Wind Farm, a
joint venture project between a
community co-operative and the
municipal utility, assets are
distributed on a 50/50 basis,
despite the fact that the municipal
utility provided slightly more than
50% equity on the project
(Sorensen et al., 2002).
This type of ownership structure
occurs when landowners who own
adjacent land, band together to pool
funds to install turbines, and
maximize the use of their land. In
these cases, access to equity is
increased and risk is distributed
among landowners.
The idea behind this model is to
compensate all affected landowners
and create a distribution of benefits
dependant on the amount of land
each owner provides, the number of
turbines installed on their land, and
the amount of land used for new
roads or cable instalment. It is up to
the landowners to determine how
these benefits are to be distributed
exactly (Bolinger, 2001;
Commission for Environmental
Cooperation, 2010).
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EARTH SYSTEMS
In Europe several different community ownership models exist. Denmark, where community ownership
began, makes use solely of general partnerships that for the most part operate according to cooperative
principles (Bolinger, 2001). In principle, these partnerships are quite simple. Individuals (partners) pool
their savings to invest in a wind turbine, and sell the power produced to the local utility. All partners are
held jointly and severally liable for the project, but typically the partnership is prohibited from taking on
debt, thereby dispensing any serious risk. Partner shares are typically bought in chunks of 1000 kWh/yr
(Bolinger, 2001).
Sweden has employed two models – the real estate commune and the consumer cooperative. The real
estate commune model is based on Swedish common law and traditions of communal ownership of
physical resources, such as fishing and hunting rights, which were attached to land titles. In this model
real estate owners band together and establish a commune (which is relatively straightforward in
Sweden), and pool their funds to install wind turbines (Bolinger, 2001). The participating real estate
owners form a management association with officials elected from among their ranks to oversee the
operation and management of the turbines. The commune sells the energy produced to the local utility.
The consumer co-operative model is demonstrated by the case of the Swedish Wind Power Co-operative
who struck a clever deal with the energy distributer Falkenberg Energi. The co-operative manages the
development and sells shares to community investors throughout Sweden in 1000kWh/year blocks
(Bolinger, 2001). The investors then become members of the co-operative. The co-operative invests the
funds in wind turbines located in promising sites throughout Sweden and sells the energy produced to its
members at wholesale prices. Falkenberg Energi for a small fee of 0.06¢/kWh takes responsibility for the
collection and supply of electricity from the project to the co-op’s members (Hicks, 2012a). Since all cooperative members must also be Falkenberg customers, they will buy any extra electricity not covered by
their shares from Falkenberg, which is a key advantage for Falkenberg of participating.
Germany’s primary model is more commercial in nature – a limited partnership with a developer’s limited
liability company as general partner and individual investors as limited partners. In this model the
developers lead the way and shares are offered to the community partners in minimum bundle sizes.
Project revenues are distributed relative to each partner’s investment.
The UK, which lacks cooperative laws, has employed a legal structure known as an industrial and
provident society, which operates like a cooperative, though is not bound by strict cooperative limits on
investment (Bolinger, 2001). Nevertheless, many community energy groups, today, do call themselves
co-ops (Brighton Energy, 2012).The UK has also pursued an investment fund structure, which is similar in
nature to a mutual fund, though it invests in renewable energy projects and not publicly traded companies
(Bolinger, 2001).
In the U.S.A community owned solar power has been growing, including projects where the owners may
not necessarily be responsible for the panels. Three broad models have been identified and discussed by
the National Renewable Energy Laboratory (NREL, 2010). These are:



A utility sponsored model
Special purpose entity (SPE) model
Non-Profit “buy a brick” model
In most utility-sponsored projects, utility customers participate by contributing either an up-front or
ongoing payment to support a solar project. In exchange, customers receive a payment or credit on their
electric bills that is proportional to 1) their contribution and 2) how much electricity the solar project
produces. Usually, the utility or some identified third party owns the solar system itself. The participating
customer has no ownership stake in the solar system. Rather, the customer buys rights to the benefits of
the energy produced by the system. Note that utility-sponsored community solar programs are distinct
from traditional utility “green power” programs in that “green power” programs sell Renewable Energy
35
EARTH SYSTEMS
Credits (RECs) from a variety of renewable energy resources; utility community solar programs sell
energy or rights to energy from a specific solar installation, with or without the RECs (NREL, 2010).
Special Purpose Entities are essentially businesses created by groups of people in order to develop a
solar project. These entities typically mimic the structure of larger commercial solar projects and have
structures that allow them to tap into government tax incentives (NREL, 2010).
The non-profit models do not typically constitute community ownership in the traditional sense. Rather in
these models donors donate money to a not-for-profit organisation, such as a local school or church to
raise funds for a renewable energy installation. The donors do not receive a share in the electricity
produced or the installation which is owned and managed by the non-profit entity (NREL, 2010). Donors
may, however, receive a tax benefit as a result of their donation in the form of a tax deduction. They also
share in the environmental benefits of the installation.
A comparison of the features of these three ownership models is given in the table below.
Table 4-5: Comparison of community ownership models in the USA (NREL, 2010)
Special Purpose Entity
Administered by
Utility
Non-profit
(SPE)
rd
Owned by
Utility or 3 party
SPE members
Non-profit
Financed by
Utility, grants, ratepayer
subscriptions
Member investments
Donor contributions,
grants
Hosted by
Utility or 3 party
3 party
Non-profit
Subscriber
profile
Electric rate payers of the
utility
Community investors
Donors
Subscriber
motive
Offset personal electricity
use
Return on investment,
Offset personal electricity
use
Philanthropy
Long-term
strategy of
sponsor
Offer solar options
Sell system to host
Add solar generation
(possibly for renewable
portfolio standard)
Retain electricity production
for life of system
Retain electricity
production for life of
system
Examples
Sacramento Municipal
Utility District – SolarShares Program
University Park Community
Solar, LLC
rd
United Power Sol Partners
rd
Solar for Sakai
Clean Energy Collective,
LLC
4.6 Community Energy in Victoria
In Victoria current examples of community based electricity generation in Victoria include Hepburn Wind
and the Central Victoria Solar Cities Program.
Hepburn Wind
Hepburn Wind is a 4.1 MW two wind turbine system sited 10km south of Daylesford, Victoria and is
Australia’s first community wind farm (SV, 2011). The project was a grass-roots initiative led initially by a
small group of residents. After establishing broader community support for the project the initial steering
36
EARTH SYSTEMS
community set up the Hepburn Renewable Energy Association (HREA), which took responsibility for
garnering community support through a range of community engagement activities, including street
stands and public forums (Wise, 2012).
HREA were also responsible for researching the appropriate ownership model for the project. After an
exploration of several structures, HREA determined that the most appropriate way to own and operate the
wind farm would be a co-operative, completely separate from their own operations (Wise, 2012).
The final Structure of the co-operative was developed with legal assistance. Hepburn Wind is managed
by a board of directors who have been elected by its members at general meetings. The co-operative has
a democratic structure; such that each member receives one-vote regardless of the number of shares
they own (Hepburn Wind, 2012). Members will, however, receive dividends (if and when any exist)
proportional to their investment. Shares in the project were initially available to those in the local
community in minimum parcels of $100 and to those in the wider community in minimum parcels of $1000
(SV, 2011). This was to encourage investment by locals.
A number of players from outside the local community have also been crucial to the project’s success.
Future Energy, a niche developer of small to medium scale wind projects, brought technical expertise and
agreed to take responsibility for project development and advising the community. Future energy also
took on much of the early financial risk in exchange for a development fee (Wise, 2012).
In addition to the $9.7 million contributed by more than 1,950 co-operative members, financing for the
wind parks development was sourced from the Victorian state government, which has provided grants
totalling $1.725m through Sustainability Victoria's Renewable Energy Support Fund and Regional
Development Victoria's Regional Infrastructure Development Program; and the Bendigo Bank which
provided a $3.1m loan (Wise, 2012).
Red Energy, a retailer owned by Snowy Hydro, purchased the total output of the wind farm, and REpower
Systems has signed a long term turbine maintenance and service agreement with the Hepburn wind cooperative (Hepburn Wind, 2012).
Solar Cities
The Australian government’s solar cities program, which is a partnership between all levels of
government, business and local community to trial sustainable energy solutions, has also provided an
opportunity for community ownership of renewable energy. In late 2009 Central Victoria Solar City
(CVSC) led the charge in the development of large-scale renewable energy technology in Bendigo and
Ballarat with the construction of two 300kW solar parks. The project developed these Parks as part of its
mission to test new approaches in local, large-scale solar provision and they are Victoria’s first ground
mounted, flat plate and grid-connected solar installations (Central Victoria Solar City, 2012).
To finance construction of the Parks, CVSC secured a loan from Bendigo Bank as well as some initial
funding from the Victorian Government to set up battery storage and tracking solar panels. The project
also accesses subsidies from the Australian Government that help meet operating costs. CVSC sells the
power generated to Origin Energy, who then on-sell the energy as accredited GreenPower (Central
Victoria Solar City, 2010).
The Solar Parks each produce approximately 450 megawatt hours of accredited GreenPower each year,
which is pumped back into the main electricity grid and goes towards reducing Australia’s reliance on
non-renewable energy (Central Victoria Solar City, 2012).
The solar parks are testing infrastructure and funding ideas for renewable energy, ascertaining whether,
with the right price, people will invest in a local energy power station as a community company, much like
investment in community banks. The trial is about creating the right conditions, including the gross
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EARTH SYSTEMS
production feed-in tariff, and the right regulatory framework, as already exists in a number of European
countries (EcoGeneration 2010).
Currently, Bendigo Solar Park Pty Ltd and Ballarat Solar Park Pty Ltd own the solar parks.
4.7 Barriers to Implementation
Many of the barriers to community renewable energy are detailed succinctly by Walker (2008), these are
summarized here. Regardless of the chosen model of development, establishing a community renewable
energy program can be both complex and challenging. There will be a need for legal, technical and
administrative expertise to organize the legal considerations of the new entity, liaise throughout the
application, approvals and construction process and negotiate terms with various organisations such as
renewable energy developers, network providers and power companies. Although there are already
support organisations in Australia’s emerging community renewable energy sector such as Embark and
the Community Power Agency, they are currently small and have limited resources.
There is also a need to obtain finance for the project. Despite the fact that wind farms have demonstrated
a clear commercial viability, there are still financial constraints. Projects often require some form of
subsidized capital funding or grant schemes to get off the ground. Though there are a number of funding
programs available associated with Australia’s renewable energy target (RET), competition for funds can
be very high. It often has to be stitched together from different sources, and there has been much
instability in funding programs as well as less than favourable planning policies in some areas. The level
of future funding for renewable energy is currently uncertain in Australia. A change in Commonwealth
government in late 2013 may signal the end of the carbon tax, which could mean less funding for a range
of associated initiatives under the Clean Energy Future Climate Change Plan. An example of
unfavourable planning policy relating to renewable energy can be found in Victoria with recent changes to
wind farm regulations making them the strictest in the world (Lane 2011). Note that unlike carbon tax,
Renewable Energy Target (RET) has bipartisan support and is likely to still provide incentives for
renewable energy projects in the foreseeable future.
In the longer term, the costs of keeping generation systems maintained may become significant and
problematic unless an adequate income stream is being generated. Barriers to market and network
connection can greatly affect the viability of a project. Network providers may have little incentive to
connect to small generators and the costs of trading may be prohibitive.
Different communities have different capacities to take on the responsibilities of a renewable energy
project. In addition to the resources at hand, the commitment of key individuals as well as the support of
local institutions has shown to be critical to project success.
In addition to these other factors, community energy projects may not always find it easier to gain
planning permission than external proposals and they may become the subject of disagreement or even
controversy within the local region.
Grid Connection Complexity
The complexity of the connection process for potential generators in the 1-5 MW e range has been
highlighted as the largest barrier to investment (VCEC, 2012; SV, 2010a). As of July 2012, connection to
the shared electricity network has followed the procedure outlined in Figure 4-2 below.
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EARTH SYSTEMS
Figure 4-2: Connection Process for Medium-scale Distributed Generation (VCEC, 2012)
The process does not automatically bestow a right to connect to the medium-sized generator, despite
doing so for both small-scale generators with <100kW e capacity and large-scale generators. A business
group has made a rule change request to the AER that petitions to give medium-scale generators a
similar right, provided that the plant does not compromise grid integrity (VCEC, 2012). In addition, the
cost of connection and the lack of transparency in the process have been identified as other restrictive
factors.
The current feed-in tariff (FIT) system is also undergoing changes and has very recently been announced
by the Victoria Government that it will be reduced to a minimum rate of 8 c/kWh for small-scale
renewables (no greater than 100 kW in size). This tariff will be reviewed annually until 2016. In addition,
the Transitional and Premium feed-in tariffs for solar is closed to new applicants. Existing customers for
39
EARTH SYSTEMS
the Transitional feed-in tariff can retain their current rates until 2016, while eligible existing customers for
the Premium feed-in tariff are offered a credit of at least 60 cents /kWh until 2024. Conditions apply to
both the above (DEPI, 2013).
Where grid connection is required, this can be a long and expensive process, making distributed
generation with grid connection an expensive option.
40
EARTH SYSTEMS
5 Existing Renewable Generation
Data from Ross Egleton obtained from REC Registry indicates a total of 120 installations for 270 kW
generation in the Murchison postcode 3610. A total of 30 solar PV units have also been installed in the
aged care facility within the township (with an average system size of 2.2 kW) (GVCE, 2012). The
installation is driven by the GV Community Energy (GVCE) through the introduction of a solar PV bulk
buy initiative.
In addition, GVCE also offer energy assessment to both households and businesses. The assessment is
designed to help households and businesses to prioritise on investments in order to achieve maximum
greenhouse gas emissions reduction (GVCE, 2012).
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6 Potential for Co- or Tri-Generation
There do not appear to be any large-scale cogeneration (i.e. combined heat and power) opportunities
within Murchison to justify the installation of megawatt-scale cogeneration facilities. There is currently no
natural gas supply to Murchison and it is unlikely that natural gas infrastructure will be extended to include
Murchison in the foreseeable future.
Co-generation is the simultaneous production of electrical energy and thermal energy, also referred to as
combined heat and power (CHP). Tri-generation is the simultaneous production of electrical energy,
thermal energy and cooling. Co-generation and tri-generation can use various fuels, including coal,
petroleum products, natural gas, biomass and biogas. Most co- and tri-generation facilities in Australia
currently use natural gas due to its availability, cost and low greenhouse intensity (CEC, 2013b). It may
be best to consider an industry cooperative for the benefit of using the electricity and thermal energy
outputs from a centralised biomass based cogen/trigen project.
Co-generation and tri-generation are most attractive at sites with a large heating and/or cooling loads.
Large energy users (such as food processing facilities) are probably ideal candidates for the end users of
both electricity and thermal energy generated. If there is a surplus of electricity supply, it may be possible
to share the electricity output (retail licencing required) and share heat among nearby facilities.
An example of this type of arrangement is the Dandenong’s Precinct Energy Project (PEP). PEP, once
operational, will produce both low carbon power from natural gas, which can be accessed through the
existing power grid by applicable Dandenong businesses and a thermal energy source, which can provide
both heating and cooling by running hot water through a series of pipes to heat exchangers within a
series of individual buildings which then can heat or cool the building as required (RCD, 2012).
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EARTH SYSTEMS
7 Modelling Methodology
7.1 Energy Generation Modelling
For each of the renewable energy technologies surveyed, different scales have been evaluated reflecting
demand requirements and current network capacity.
In matching renewable energy generation to existing network availability, and projected network
improvements, two grid-connected scenarios were established for solar, hydro, and biomass
technologies. This allowed a suitable modelling methodology to be applied that would suit the targets of
Murchison, keep network infrastructure costs to a projected minimum, and allow a staged deployment of
technology.
The chosen scales range between 1.6 to 5 MW e as discussed in Section 7.1.4 below.
7.1.1 Electricity Pricing
Electricity prices are made up of two components: Energy charges which reflect the wholesale cost of the
electricity power generation itself, and Network and Retail charges which represent the cost of
transporting the electricity from the generator to the consumer including long-distance transmission,
distribution to households and businesses and retail services to the customer.
The coal and gas fired power plants in Victoria utilise known, plentiful stocks of low-cost fuel, and
capitalise on economies of scale. By comparison, the renewable energy plants modelled herein are small
(between 1.6 to 5 MW e) and in the case of solar power, utilise intermittently available energy. These
factors increase the cost of energy and can show poor comparative economic performance compared
with the current energy architecture in Victoria.
However, this is not the whole story. The electricity market sells “hedges” of electricity in known quantities
on a five-minute basis according to the balance of supply and demand. When demand is high, prices rise.
Although the average dispatched cost of electricity in Victoria is approximately 3¢/kWhe (AEMO, 2012b),
peak demand periods can push prices to 100¢/kWhe or more, usually for brief periods. One advantage of
solar power is that the resource is typically available during periods of higher demand, therefore the
average spot price is not a fair reflection of the value of this electricity. Despite this, payback periods for
investment purposes have been determined based on an estimated value for electricity that could be
negotiated for a small-scale renewable energy project.
7.1.2 Network Charges
Network charges have not been included in all analyses (although demand charges are assumed to be
included here – this implies that even in a stand-alone scenario, the community may be forced to retain
the grid supply as a back-up). Network charges will be incurred in either the grid-connected or standalone (point-source) generation scenarios. For grid-connected generation, network charges result due to
the network service provider using the network to transport energy from the generator to the grid (as
43
EARTH SYSTEMS
opposed from the grid to the consumer). For large-scale stand-alone generation, network connections are
typically retained as a backup against unplanned outages.
7.1.3 Connection Costs
The capital costs of connecting to the electricity network have not been evaluated. The costs of
connection vary significantly depending on location, generation capacity, and other factors, and a formal
network study is normally required to establish costs on a case-by-case basis. For Murchison, located
about 35km from the Mooroopna zone substation, a preliminary analysis by Powercor suggests
connection of up to 2 MW of generation to the 22 kV network would require minimal upgrading. This fits
well with the generation scales of all but one of the scenarios modelled.
Nevertheless, further detailed discussion with Powercor would be required to ascertain the current
suitability of the network to accommodate the proposed renewable energy plant(s) and any future
planning Powercor might have in relation to Murchison’s grid network structure, i.e. a formal request for
new connections to the grid based on site requirements may need to be submitted to Powercor to
officially inform and prepare Powercor for possible construction of the renewable energy plant(s).
7.1.4 Selected Capacities
As discussed in Section 2, the following scales have been chosen for the modelling:



Solar PV
o
1.6 MW e – meeting the town’s electricity demand for 90% of the time in peak sun
o
5 MW e – generating about 8,300 MWh/year to match the yearly estimated consumption
as indicated by the Powercor data
Hydropower
o
1.6 MW e – meeting the town’s electricity demand for 90% of the time when running at
capacity
o
2.1 MW e – generating about 8,300 MWh/year to match the yearly estimated consumption
as indicated by the Powercor data
Bioenergy plant
o
1.6 MW e – gasifier system (this system size meets both 90% demand and estimated
yearly power consumption of Murchison)
o
1.6 MW e – ORC system (this system size meets both 90% demand and estimated yearly
power consumption of Murchison)
Note that the capacity of the larger scale option for solar and hydropower are likely to exceed the
current’s grid capacity around the area. However, the large-scale analyses may give indication of what
costs are involved when considering the substitution of the whole town energy supply to renewable
energy. Consideration of decentralisation/distributed generation scenarios have been excluded in the
modelling analysis due to the focus on setting larger centralised and ‘industrial scale’ generation.
A mixture of renewable energy technologies (i.e. some solar, some hydro, and some bioenergy) to
provide the required energy for the whole town is also an option to consider for further work.
44
EARTH SYSTEMS
7.2 Simple Economic Modelling
The renewable energy sector is changing rapidly with new technologies being brought to market as
technology deployment begins to achieve critical momentum with the rise of low cost technology supply
from manufacturing centres such as China and India. The cost per unit falls dramatically as the
technology rides the cost curve down towards a solidly established technology. Other factors come into
play, which can affect the supply and demand balance. For example, the current financial crisis in Europe
has affected solar photovoltaic (PV) imports into this region, just as China was gearing up manufacturing
capacity. This imbalance and technology cost curve factors combined has placed downward pressures on
solar PV, resulting in an extraordinary reduction in price.
In this study, for each renewable technology reviewed the capital and operational expenditure (capex and
opex) was established from a review of published literature sources, manufacturer information and where
appropriate, anecdotal evidence due to the rapid change in costs of these technologies.
7.2.1 Levelised Cost of Energy
One of the important economic modelling outputs is the derivation of the Levelised Cost of Energy
(LCOE) for the renewable energy technologies investigated: solar, hydro, and biomass. LCOE is defined
as the point where the present value of the sum discounted revenue is equivalent to the discounted value
of the sum of costs, or when the NPV (Net Present Value) equals to zero. LCOE is a useful calculation
because it allows comparison of different generation technologies on an equal basis. (Melbourne Energy
Institute, 2011)
The LCOE calculation applies a discounted cash flow analysis to the sum of the costs of the technology
(capex and opex) and compares this against the sum of the revenue over the life of the plant. It then
establishes the minimum rate per unit electricity exported and sold required to achieve a net rate of return
of zero, including the discount rate and inflation (the discount rate is also a method of generating a set
interest payment, or profit factor). LCOE gives an indication of the price of selling the energy produced by
the proposed renewable energy plant(s) to make the project break even over the life of the plant(s), i.e.
the minimum energy selling price for the project to be considered viable.
In this way, different technologies can be compared in an equalised process by simply examining what
income the technology must achieve per unit of electricity exported and sold to be profitable for a set
discount rate and inflation rate over the life of the plant.
𝑅𝑒𝑣𝑒𝑛𝑢𝑒
=
𝑡
𝑡=0 (1 + 𝑟)
𝑛
𝐶𝑜𝑠𝑡𝑠
𝑡
𝑡=0 (1 + 𝑟)
𝑛
OR
𝑁𝑃𝑉 =
𝑛
𝑡=0
𝑃𝑉 = 0
Where: n = Project lifetime (yrs)
t = Year in which sale or cost is incurred
r = Discount rate (%)
Figure 7-1: Levelised Cost of Energy (Melbourne Energy Institute, 2011)
45
EARTH SYSTEMS
In the analysis, ‘income/revenue’ is generated from the sale of electricity to the grid or to a point-source
demand user plus the sale of Large-scale Generation Certificates (LGCs). A LGC is a form of Renewable
Energy Certificate (REC), which covers the large-scale renewable energy generation by power stations
as part of Australia’s Renewable Energy Target (RET) scheme. One LGC is equivalent to 1 MWh e of
eligible renewable electricity (CER, 2012).
The average price per unit LGC was estimated at $37 /MWh e generated (CEC, 2012a). This value was
applied to the economic modelling analysis (as an additional income) on each of the renewable energy
technology investigated.
The average price data for wholesale electricity in Victoria was $61.16/MWh e, obtained from the
Australian Energy Market Operator (AEMO) based on the average for the financial year 2012-2013
(AEMO, 2012c). In the preliminary analysis, the price per unit electricity sold was set at AU$95/MWhe for
economic modelling purposes. This value is approximately the summation of the wholesale electricity and
LGC price that is regarded as income in the following economic analyses.
7.2.2 Data and Assumptions
The table below lists the data and assumptions made across all the renewable technologies modelled.
Table 7-1: Data and assumptions used for financial modelling
Data
Value
Units
Assumed plant life
20
Discount rate
7%
Inflation
3%
Estimated electricity price increase
3%
Depreciation
5%
Tax rate
Combined electricity and LGC rate
years
Year on year
30%
0.095
$/kWhe
95.0
$/MWhe
Other cost related data is presented in the respective technology sections.
Capital cost data (capital expenditures or capex) used in the analysis includes all anticipated costs for
equipment and materials, installation labour, professional services (engineering and construction
management), and contingency. The cost associated with network, transmission, grid improvement
and/or connection, and land purchase cost is not included in this capital cost as it would vary from region
to region, and also is specific to the particular point that grid connection would occur, is influenced by the
grid infrastructure at that particular location, and the size and variability of the generating capacity and if
the grid can handle such a load or requires significant modification and/or equipment and line upgrades to
suitably connect.
Operational cost (operational expenditure or opex) includes major periodic maintenance, wages,
insurances, consumables, and overheads.
46
EARTH SYSTEMS
7.2.3 Sensitivity Analysis
For the modelling analysis conducted for each technology proposed, a sensitivity analysis is also carried
out. Sensitivity analysis is a form of risk management as it presents the change in outcome (e.g. LCOE)
with respect to changes made with the key input variables (based on the assumptions made). This allows
the viewer to anticipate outcome variation on different scenarios that may occur in the future and to
determine the most sensitive factor(s) affecting the outcome.
47
EARTH SYSTEMS
8 Solar Power
Solar power is electricity derived from the energy in sunlight. Electricity can be generated from solar
energy either by converting it directly to electricity with photovoltaic (PV) cells or in the case of solar
thermal plants by directly utilising solar thermal energy which can then be converted to electricity via
conventional thermal power processes.
Solar energy can be considered as consisting of two components: direct solar energy arriving at the earth
with the sun’s beam and diffuse solar energy, including scattered light (BOM, 2012d). Global solar
exposure is the sum of these two components. The type of solar technology used determines whether
global solar energy or only direct solar energy can be converted to electricity.
Australia has some of the best solar resources worldwide (see Figure 8-1). This means that even regions
with relatively low solar resources compared to the rest of Australia are nonetheless good by world
standards.
2
Figure 8-1: Worldwide annual global solar exposure in kWh/m (Creativhandz Energy Solution,
2012)
A disadvantage of solar power compared to other technologies is that solar radiation is an intermittent
source. Apart from being unavailable at night, solar energy reaching the earth is also subject to significant
seasonal and day-to-day variability. The amount of solar energy reaching the ground depends on a
number of factors; most importantly, the position of the sun in the sky and the extent of cloud cover
(BOM, 2011). The height of the sun at solar noon varies during the year by a significant amount, while
cloud cover varies irregularly depending on season and local geographical features.
Solar power has great potential and total installed capacity is currently undergoing rapid expansion
worldwide. For example, cumulative installed capacity of solar PV reached roughly 65 GW at the end of
2011, up from only 1.5 GW in 2000 (IEA, 2012a) representing a 40-fold increase. In Australia, 0.6 PJ of
solar electricity was produced in 2008-09 (DRET, 2011) and capacity is also growing (total installed
48
EARTH SYSTEMS
capacity in Victoria is more than 2 GW by the end of 2012, up 1.4 GW from the end of 2011) with solar
energy use projected to increase by 5.9% per year to 24 petajoules by 2030 (ABARE et al, 2010). As
shown below a number of solar plants with capacity greater than 30kW e already exist in Australia. As of
the time of this report writing, the largest solar PV facility is a 1.22 MW installation at the University of
Queensland’s St Lucia Campus and the largest concentrated solar thermal facility is a 3 MW facility at
Lidell, New South Wales (CEC, 2011d).
Governmental support has been established recently to kick-start large-scale solar generation in
Australia. Various definitions have been applied to categorise large scale solar including (CEC, 2011d):



5MW as a working definition applied by the Victorian Government
200kW and above as applied by the ACT expanded feed-in tariff scheme
100kW and above as applied by the eRET scheme
However industry advice suggests that the thresholds above are too low and that a reasonable threshold
would be 30MW, as applied by the federal government to define commercially proven large-scale solar
projects under the Solar Flagship Program (CEC, 2011d).
The Solar Flagships Program was established in 2009 to support the construction and demonstration of
large-scale solar power stations (up to 1,000 MW e) in Australia. Other national programs include the Solar
Cities program, launched in 2004 to showcase sustainable energy models. Trials have been conducted
since 2007 and currently include seven Solar Cities around Australia: Adelaide, Bankstown, Townsville,
Central Victoria, Alice Springs, Moreland and Perth.
At a state level, the ACT Government commissioned the ACT Solar Reverse Auction project in order to
develop a large scale, long term renewable energy source for ACT consumers. An initial scoping study by
private consultants resulted in the recommendation of an overall capacity of 210MW of solar energy
infrastructure for the ACT. The first stage of the project is 40MW in the form of two 20MW rollouts.
As of March 2013, two proposed 30MW solar farms in the town of Kerang, Victoria, have been approved
in principal by the Gannawarra Shire Council, one by AKK Consulting and another by Eco For Life.
Representatives from AKK Consulting and the Gannawarra Shire Council have both commented that this
is only an initial step in the process and there is much work to do with the negotiation of power purchase
agreements (PPA’s) and construction contracts as well as sourcing of materials.
The AKK Consulting project proposal is valued at $50 million while the proposal for the second 30MW
farm, by Eco For Life (a Wodonga based company) is valued at $38 million. The Eco For Life proposal
represents a large reduction in capital costs from the recently completed $50 million, 10MW Greenough
Solar farm in Western Australia and shows how quickly the large-scale solar market in Australia is
changing. When asked about the difference in costs estimated for the two Kerang projects, a spokesman
for the Gannawarra Shire Council pointed to the fact that AKK Consulting are planning to install all 30MW
in one project using a number of external sub-contractors for their $50 million project while Eco For Life
are planning to complete their $38 million project in stages keeping most of the work internally sourced.
While excited about project approval, a source from AKK consulting is realistic about the challenges
ahead which are typically associated with an emerging market. These include:





high capital costs;
little interest from financial institutions;
high insurance costs due to risk;
changing government regulations; and
lack of subsidies for grid connected projects.
49
EARTH SYSTEMS
Kerang was chosen as a suitable site primarily for its solar resource. The AKK Consulting project is due
to start in approximately June 2013, the Eco For Life project is due to start in approximately March-April
2014.
Solar Plants
Figure 8-2: Solar operating plants with capacity of more than 30 kW e (Australian Government,
2012)
8.1 Technology Overview
Solar power technologies include solar Photovoltaic (PV), concentrating solar thermal (CST),
concentrated PV systems (CPV), thermovoltaic devices and space-based solar. Solar PV and
concentrating solar thermal are the most widely developed (with solar PV being the main focus for this
report). Solar PV, CST, and CPV technologies are discussed in detail in Appendix B.
8.2 Environmental Impact
The lifecycle assessment (LCA) greenhouse gas (GHG) payback period refers to the length of time
required for a solar farm to generate sufficient electricity to offset the GHG emissions associated with the
manufacture, construction, operation and decommissioning of the project, versus the savings in the
displacement of fossil fuel electricity GHG emissions (GL Garrad Hassan, 2011).
The payback period also depends on the lifecycle emissions of the various technologies. For solar PV,
CO2 emissions usually include mining of the materials, production of the cells, transport and on site setup,
and maintenance. These factors are estimated at between 19 tCO 2e/GWhe to 59 tCO2e/GWhe. (Wright et
al, 2010)
For solar PV, the LCA GHG savings varies depending upon the location of installation, which determines
the solar resource and the fossil fuel mix for the offset electricity. The generally accepted method of
calculating emissions abatement is by using the state pool coefficient. According to a report by the Solar
PV Industry the annual GHG abated through PV electricity production in Victoria is 1,458 tCO 2e per MW e
installed of PV. (Solar Business Services et al, 2011)
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EARTH SYSTEMS
Solar PV
Table 8-1: Greenhouse Gas analysis of solar PV
Parameter
Value
Unit
Ref.
Best Case Scenario
Life cycle solar PV CO2 emissions per
unit of energy production
19
tCO2e/GWhe
Wright et al, 2010
Greenhouse gas abatement factor *
0.87
tCO2e/MWhe
Wright et al, 2010
Emissions payback period
0.44
years
Worst Case Scenario
59
tCO2e/GWhe
Wright et al, 2010
0.87
tCO2e/MWhe
Wright et al, 2010
1.36
years
*Derived from 1,458 tCO2e per MWe installed
8.3 Local Solar Resource
2
On average Murchison receives about 17.8 MJ/m per day of solar energy, which translates to about
2
1,809 kWh/m annually. This is similar to regions of Spain and Portugal where large scale solar power
developments have been commissioned. Based purely on the solar hotspots of the world and Australia,
diffuse and direct solar resources appear to be a potential renewable energy resource suitable for
Murchison.
The figure below shows how solar energy reaching the ground varies throughout the year in Murchison.
Note that the average solar energy reaching the ground in winter is only about half that of summer. This
reduction in available solar energy significantly affects the generation capacity of a solar plant month to
month.
51
EARTH SYSTEMS
Figure 8-3: Murchison Global Solar Exposure by Month and Annual Average (BOM, 2012b)
Given the intermittent and variable nature of solar energy, electricity generated from solar power must
either be stored for use when the sun is not shining or supplemented with another energy source.
Suitable Sites for Solar PV Installation
From preliminary research, local roof space that has loading capacity to potentially hold 20kW plus of
solar in Murchison includes the following sites:

Murchison Community Care.
Watson Street, Murchison
http://www.murchisonvictoria.com.au/contact-us.htm

DP Jones Nursing Home / Murchison Community Centre
38 Impey Street, Murchison

Murchison Bowls Club.
Cnr Robinson and Watson St, Murchison

Murchison Football Club
River Road, Murchison

Murchison Primary School (already have solar)
Impey Street, Murchison

Dhurringile Prison
Murchison-Tatura Road
http://www.justice.vic.gov.au/home/justice+service+locations/hume/
Note that the roof loading capacity at any of the above sites would require assessment to determine
whether the weight of PV panels could be accommodated without requiring structural reinforcement.
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EARTH SYSTEMS
8.4 Modelling Results
Energy Generation Modelling
The following tables show the key data used to estimate the energy that can be generated per year based
on the solar resources in Murchison. This data then feeds into the economic modelling analysis.
Table 8-2: Solar PV energy generation modelling results
Solar PV – 1.6 MWe
Data
Value
Units
Refs/notes
Solar PV efficiency
PV panel efficiency
15%
Solar-facts, 2013
Efficiency improvement via tilting
15%
CEC, 2012d
Energy generation data
Solar power density
86.4
Land use factor
59%
System capacity factor
19%
Average expected electricity output
2,647
W/m²
BOM, 2012b
Factor to account for geometry
restriction when installing solar
panels
A calculated number based on
MWhe/yr actual generation divided
by MWhe/yr nameplate capacity
MWh/yr
Table 8-3: Solar PV energy generation modelling results
Solar PV – 5 MWe
Data
Value
Units
Refs/notes
Solar PV efficiency
PV panel efficiency
15%
Solar-facts, 2013
Efficiency improvement via tilting
15%
CEC, 2012d
Solar power density
86.4
Global efficiency
8.6%
Land use factor
59%
19%
8,272
W/m²
BOM, 2012b
Factor to account for geometry
restriction when installing solar
panels
A calculated number based on
MWhe/yr
actual
generation
divided by MWhe/yr nameplate
capacity
MWh/yr
Note that the results presented above are based on data obtained from one of BOM’s weather stations at
Murchison.
53
EARTH SYSTEMS
Economic Modelling
The energy generation results above are used for the economic modelling below. Analysis has been
carried out assuming the systems are modular. Both scenarios for PV at 1.6 MWe and 5 MWe display
similar results. This is likely due to both being classified within the same scale range, which implies that
the economies of scale effect is not apparent (resulting in identical LCOE between the two scenarios).
Table 8-4: Data and results of key financial parameters (all in 2012 AU$) of solar PV 1.6 MW e
Solar PV - 1.6 MWe
Data
Value
Units
Ref./Notes
Actual performance summary
Avg. yearly generation
2,647
MWhe
Avg. Daily generation
7.25
MWhe
Avg. Power
0.30
MW e
Jun min
98
MWhe/month
Dec max
389
MWhe/month
19%
Cost data nameplate capacity
Capex
Capex total
3,500
5,600,000
Opex
Opex total
30
$/kW e nameplate
$
$/kW e/y
48,029
$/yr
18,532
$/kW e generated
Cost data actual performance
Capex
Opex
159
$/kW e/y generated
Key financial results*
NPV
IRR
-2,865,088
$
-0.39%
Simple payback (after tax)
20.9
Years
Target parameters for breakeven costs
LCOE at year 1
207
$/MWhe
Average LCOE**
277
$/MWhe
Averaged
value over
project life
*Based on the combined wholesale electricity and LGC income at $95/MWh
**Based on an electricity escalation rate of 3% year-by-year (assumed to be the same rate as inflation)
54
EARTH SYSTEMS
Table 8-5: Data and results of key financial parameters (all in 2012 AU$) of solar PV 5 MW e
Solar PV - 5 MWe
Data
Value
Units
Ref. /Notes
8,272
MWhe
22.66
MWhe
Avg. Power
0.94
MW e
Jun min
307
MWhe/month
1,214
MWhe/month
Dec max
19%
Capex
Capex total
3,500
17,500,000
Opex
Opex total
30
150,091
$/kW e nameplate
$
$/kW e/y
$/yr
Capex
18,532
Opex
159
$/kW e generated
$/kW e/y generated
Key financial results *
NPV
-8,953,400
IRR
$
-0.39%
20.9
years
LCOE at year 1
207
$/MWhe
Average LCOE**
277
$/MWhe
Averaged
value over
project life
The LCOE of solar PV for Murchison is estimated at AU$207/MWh e at year 1, with an average LCOE of
AU$277/MWhe over the project life (2012 dollars). This is relatively close when compared to LCOE
calculated by European Photovoltaic Industry Association (EPIA) at AU$181/MWhe (also converted to
2012 dollars) by 2015 (Melbourne Energy Institute, 2011). This EPIA estimation is based on ‘paradigm
shift’ case, which estimates the ‘full potential of PV in the next 40 years’, i.e. taking into consideration
increased production capacity, improved supply chains, economies of scale, and the role of Chinese
manufacturers on the global market, which as noted above appears to have already begun.
The NPVs and IRRs above both show negative numbers with a payback period of 20.9 years. This is
most likely due to the low combined rate of wholesale electricity and LGC. In a scenario where the
electricity could be sold to customers directly (on retail rate and off the grid) at an approximate rate of
$150/MWh, the payback period could reduce by up to 7 years (making the payback by approximately 14
years). This may represent a case where BOO (Build, Own, and Operate) could work well with this
technology. BOO implies that an entity could build, own, and operate the proposed renewable energy
55
EARTH SYSTEMS
plant with minimal involvement from other parties (i.e. the government). If possible, this could present a
more attractive option for Murchison to pursue this solar PV technology.
8.5 Sensitivity Analysis
Sensitivity analysis affecting the LCOE on the 1.6 MW e and 5 MW e scenarios was carried out to
determine the most sensitive contributing factors (see below).
Figure 8-4: Sensitivity analysis on 1.6 MWe solar PV in Murchison
56
EARTH SYSTEMS
Figure 8-5: Sensitivity analysis on 5 MWe solar PV in Murchison
In this simple analysis (assuming modular systems with no significant effect due to economies of scale), it
is expected that the sensitivity analyses would yield the same results independent of scale. As shown by
the figures above, the most sensitive factor is the quantity of electricity generated, followed by capex,
discount rate, electricity price escalation rate, opex, and inflation.
This indicates that the quantity of electricity generated from the system and capex are key factors in
determining the feasibility of this option.
57
EARTH SYSTEMS
9 Hydro Power
Hydroelectricity is electrical energy generated when falling water from reservoirs or flowing water from
rivers, streams or waterfalls (“run of river”) is channelled through water turbines. The pressure of the
flowing water on the turbine blades causes the shaft to rotate and the rotating shaft drives an electrical
generator, which converts the motion of the shaft into electrical energy. Most commonly, water is
dammed and the flow of water out of the dam to drive the turbines is controlled by the opening or closing
of sluices, gates or pipes. (Australia Energy Resource Assessment, 2009)
th
Hydroelectricity has been used in some form since the 19 century. Hydroelectricity is a relatively simple
but highly efficient process compared with other means of generating electricity, as it does not require
combustion. It is a renewable energy source, as rainfall renews the water in the reservoir, and has the
advantages of low greenhouse gas emissions, low operating costs, and a high ramp rate (quick response
to electricity demand). In many countries, it is used for peak load generation, taking advantage of its quick
start-up and its reliability (Australia Energy Resource Assessment, 2009).
Hydropower is the most advanced and mature renewable energy technology and provides some level of
electricity generation in more than 160 countries worldwide. China is the leading hydropower producer,
followed by Brazil, Canada, the United States, and Russia. Hydropower represents the largest share of
renewable electricity production. (IEA, 2012b)
Figure 9-1: Hydroelectric power generation (IRENA, 2012a)
In 2010, Hydro accounted for 16% of electricity production in the world, 3,427 terawatt-hours of electricity
production. In the OECD region, hydroelectricity generation is projected by the IEA to increase at an
average annual rate of only 0.7 per cent between 2007 and 2030 - reflecting limited undeveloped hydro
energy potential - whereas in non-OECD countries, the annual rate is projected to be 2.5 per cent reflecting large, undeveloped potential hydro energy resources in many of these countries. (Australia
Energy Resource Assessment, 2009)
58
EARTH SYSTEMS
In 2011, the total installed hydroelectric generation capacity in Australia was 8,186 megawatts with 108
operating hydroelectric power stations, representing approximately 1 per cent of the total installed
hydroelectric generation capacity in the world. The total amount of electricity generated from
hydroelectricity in Australia in each year is approximately 13,800GWhe. (Ecogeneration, 2011)
In 2008, Australia’s hydroelectricity use represented 0.8 per cent of total primary energy consumption and
4.5 per cent of total electricity generation. Hydroelectricity use has declined on average by 4.2 per cent
per year between 2000 and 2008, largely as a result of an extended period of drought. (Australia Energy
Resource Assessment, 2009)
Plants can be built on a large or small scale, each with its own characteristics:



Large-scale hydroelectricity plants (>10MW) generally involve the damming of rivers to form a
reservoir. Turbines are then used to capture the potential energy of the water as it flows between
reservoirs. This is the most technologically advanced form of hydroelectricity generation.
Small-scale hydroelectricity plants (100kW -10MW) are still at a relatively early stage of
development in Australia, and are expected to be the main source of future growth in
hydroelectricity generation.
Micro-scale (<100kW) hydroelectricity plants are reasonably widespread in rural areas and are
often utilised to run agricultural infrastructure such as pumps (Australia Energy Resource
Assessment, 2009, Australian Institute of Energy, 2003)
Hydropower generation is dependent on the hydrological cycle. High variability in rainfall, evaporation
rates and temperatures occurs between years, resulting in Australia having very limited and variable
surface water resources. Potential for the development of new large-scale hydroelectricity facilities in
Australia is limited, but there is some potential for small-scale hydroelectricity developments in Australia,
and this is likely to be an important source of future growth in capacity. (Australia Energy Resource
Assessment, 2009)
Recently, a new type of blade, called the Cetus Blade, has been developed and is being commercialised.
The blade is capable of capturing the energy available in omni-directional turbulent flows (as opposed to
conventional blades that could only capture flow matching the turbine’s plane of operation) and converting
it to clean, renewable electricity (Cetus Energy, 2013). Cetus is currently delivering a 100 kW Pilot
Demonstration Project in partnership with the State Government of Victoria in the outfall flows of the
Rubicon Hydroelectric Scheme, 40 km south west of Alexandra, with 10 turbines drawing energy from the
water flowing in the channel system.
Another recently developed turbine called Kouris Centri Turbine (KCT) seems to be able to operate with a
head well under the 3 metre minimum required by conventional turbines to operate efficiently. The KCT
uses the flow not the fall of water to create a vortex that can subsequently generate power. Furthermore it
does not interfere with the flow rate, which enables the system to be used sequentially in a waterway. At
the time of writing, a 40 kW transportable KCT unit is in progress to be installed at Mulwala Canal in
NSW. (Kourispower, 2012 and pers. comm. with Kourispower representatives)
Examples of micro hydropower plant around the globe are listed on the table below.
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EARTH SYSTEMS
Table 9-1: List of operating micro hydropower plants
Town
(Country)
Turbine
characteristic
Capacity
Total
production
(kWh/year)
Water source
Refs.
http://www.certificatvert.c
Chappes
Vertical axis
(France)
turbine
om/projets206 kW
~ 1,000,000
durable/microcentralehydroelectriquechappes/
http://www.lyonnaise-
Lods
(France)
Streams flows
Kaplan turbine
1,000 kW
~ 2,000,000
through between
11 and 30 m³ / s
deseaux.fr/collectivites/nosoffres/microcentrale-etpico-centralehydroelectriques
Chorro
http://www.greenempow
Blanco
20 kW
erment.org/countries/5/pr
(Peru)
Mae Klang
Luang
(Thailand)
oject/10
Low-head hydro
154 W
turbine
31.5 L/s of water
http://www.palangthai.or
at head of 1.8
g/docs/HP124pg76Grea
m.
cen.pdf
9.1.1 Technology Costs and Economics
The project development costs include planning and feasibility assessments, environmental impact
analysis, licensing, fish and wildlife/biodiversity mitigation measures, development of recreation
amenities, historical and archaeological mitigation and water quality monitoring and mitigation.
The total investment costs for hydropower vary significantly depending on the location, the site conditions,
design choices and the cost of local labour and materials (IRENA, 2012a).
More closely related to the conditions of hydropower resource at Murchison, is the Murray irrigation’s
hydropower plant in NSW, called the Drop. The hydropower plant, commissioned in 2002, is located on
Mulwala Canal and uses about 6,000 ML of water per day flowing through the turbines with total capacity
of 2.5 MW (with annual electricity generation of around 10 GWh per year) (Pacific Hydro, 2011). The Drop
was built by Pacific Hydro at a capital cost of $6.5 million (CEC, 2012c). The Mulwala canal is the largest
water delivery channel in Australia, and water at the Drop falls about 4 m, from one section of the canal to
the next (Murray Irrigation Limited, 2003).
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EARTH SYSTEMS
Table 9-2: Typical Data and Figures for Hydropower Technology (IEA, 2010b)
Micro-hydro (<100kWe)
Mini-hydro (100kWe 10MWe)
Large hydro (>10MWe)
Turbine Efficiency
Up to 92%
Up to 92%
Up to 92%
Construction time
[months]
6 – 10
10 – 18
18 – 96
40 – 60%
34 – 56%
34 – 56%
$2,500 – $10,000
$2,000 – $7,500
$1,750 – $6,250
O&M cost [$/kW e/y]
$50 – $90
$45 – $85
$35 – $85
LCOE [$/MWhe]
$55 – $185
$45 – $120
$40 –$110
Capacity factor
Investment cost [$/kW e]
9.1.2 Environmental Impact
According to International Energy Agency, the environmental and social effects of hydropower projects
need to be carefully considered. Authorities should follow an integrated approach in managing their water
resources, planning hydropower development in co-operation with other water-using sectors, and take a
full life-cycle approach to the assessment of the benefits and impacts of projects (IEA, 2012b).
Flora and fauna in rivers utilised for hydropower are affected due to the alteration of several factors such
as (IEA, 2002):





extension and frequency of flooding
drought conditions below diversion points
stresses from rapid changes in water level
water quality changes (low dissolved oxygen level)
change in groundwater conditions
In addition, the construction of dams and reservoirs means that land is flooded. There can be a loss of
productive agricultural or forested land, loss of pastures and the inundation can affect sites of cultural
significance (IEA, 2002).
9.2 Hydropower Resources in Victoria
A number of medium (mini-hydro) and large-scale hydropower facilities are in operation around the state.
The largest and most developed hydro schemes are the Kiewa and Lake Eildon hydro schemes, which
generate 630MW e from five plants. Collectively hydro power in Victoria accounts for 6% of the state’s
generating capacity (SV, 2012). Despite being a largely developed resource, potential still exists for
further mini-hydro scale installations (ABARES, 2011).
While large-scale hydropower developments require high pressure and large flows, mini-hydro schemes
can be installed as run-of-river plants with modest head. Several mini-hydro scale developments have
been installed as shown in Figure 9-2, with additional plants proposed at Dartmouth (20 MW e) and six
MW e-scale plants for Melbourne Water. However, due to the high variability of rainfall throughout the
61
EARTH SYSTEMS
continent, generation capacity can be unreliable in the long-term (ABARES, 2011). Other opportunities for
small-scale developments include installing turbines in pressure-reduction water stations, to generate
electricity from the necessary pressure let-down. A development at the Hallam water pressure reducing
station resulted in a 215 kW e turbine being installed for a total cost of $996,000 ($4,600 /kW e), generating
1,226 MWhe/y (SV, 2010b).
Figure 9-2: Hydro generators in Victoria (SV, 2012)
9.3 Local Hydropower Potential
Preliminary assessment undertaken by Earth Systems indicates the possibility of implementing a
hydropower plant for supplying electricity to Murchison. Potential sites surrounding Murchison were
treated to a desktop analysis including the Cattanach and Stuart Murray Canals, the East Goulburn Main
Channel and the Goulburn River. In order to determine some of the planning and regulatory
considerations listed in this section, local, regional and state water authorities were contacted with
respect to these sites including Goulburn Murray Water (GMW), the Goulburn Catchment Management
Authority (GCMA), The Department of Environment and Primary Industries and the Department of
Sustainability and Environment Victoria. Representatives from Murray Irrigation and Pacific Hydro were
also contacted for advice relating to their experience planning, constructing and operating the Mulwala
Canal Hydro Scheme in New South Wales.
As there was no site study and due to publicly limited technical data available online on the hydro
resources around Murchison, it is difficult to estimate the quantity of power that can be generating from
installing a hydropower plant on one of the river/canal systems. Note that water availability at the potential
sites mentioned above would depend on long term seasonal water availability and flows may be regulated
or restricted given their primary function of providing water for agriculture purposes.
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EARTH SYSTEMS
It is critical that more detailed data is obtained and site-specific study carried out to assess the following
key factors in a preliminary investigation (BHA, 2005):

The existence of a suitable turbine site;

A consistent flow of water at a usable head;

The likely acceptability of diverting water to a turbine;

Suitable site access for construction equipment;

A nearby demand for electricity, or the prospect of a grid connection at a reasonable cost;

The social and environmental impact on the local area; and

Land ownership and/or the prospect of securing or leasing land for the scheme at a reasonable
cost.
Professional advice on hydropower specialist should also be sought before proceeding further with this
option.
Considering the similarity of the canals around Murchison and the hydropower ‘The Drop’ in NSW (as
mentioned in Section 9.1.1), it may be feasible to construct a hydropower plant along one of the
canal/river systems near Murchison.
Based on the preliminary desktop research conducted, the map below shows the general location of the
potential sites.
MURCHISON
East Goulburn Main Channel
Figure 9-3: Goulburn River system map (SKM, 2006)
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EARTH SYSTEMS
Comparing Figure 9-3 above and the Murchison network maps on Figure 3-3 and Figure 3-4, the
Goulburn River and East Goulburn Main Channel seem to be the closest one to Mooroopna zone
substation. This gives an indication that the Goulburn River and East Goulburn Main Channel may have a
grid connection advantage over the other potential sites.
9.3.1 Canal and River Conditions
Cattanach Canal
The Cattanach Canal can divert up to 3,690 ML/d to Waranga Basin from Goulburn Weir. No irrigation
diversions occur along the channels length. In general, flows in the Cattanach Canal will be varied in
preference to the Stuart-Murray Canal resulting in it being operated to pass Goulburn Weir inflow
variations into Waranga Basin. As with the Stuart-Murray Canal the maximum regulation change is ±400
ML/d, however the number of regulations in a day is not restricted. (SKM, 2006)
Stuart Murray Canal
Diversions to the Stuart-Murray Canal are either passed through to the Waranga Basin or diverted into
the Central Goulburn Area. The capacity of the Stuart Murray Canal at the Goulburn Weir offtake
regulator is 3,500 ML/d. The available capacity reduces once Waranga Basin’s volume climbs above
380,000 ML. At close to full supply the volume that can be passed into Waranga Basin falls to 2,000
ML/d. (SKM, 2006)
Current operations restrict the maximum regulation to the Stuart-Murray Canal to a change of ±400 ML/d
with three regulations/day. In an emergency, four regulations/day can be undertaken. (SKM, 2006)
East Goulburn Main Channel
The East Goulburn Main (EGM) Channel is the main supply channel for the Shepparton Irrigation Area.
From Goulburn Weir it runs 95 km to the Broken Creek, outfalling at Katandra Weir. Up to 40,000 ML of
regulated outfall to supply diverters in the lower Broken Creek can be made each year. (SKM, 2006)
The EGM’s offtake capacity at Lake Nagambie is 2,590 ML/d with capacity having reduced to around 300
ML/d at its outfall to the Broken Creek. During periods of peak demand there is negligible spare capacity
in the EGM. (SKM, 2006)
Lower Goulburn River
Under the current Bulk Entitlement (BE) there is a minimum flow requirement in the Goulburn River
immediately downstream of Goulburn Weir of a weekly average flow of 250 ML/d and minimum flow on
any one day of 200 ML/d. Releases from Goulburn Weir may also be driven by the need to meet
minimum flow requirements when there are low tributary inflows and no other passing flow requirement at
McCoys Bridge. There is indication that environment water held by the Federal and State governments
will increase these flows, which imply there could be increased water flow at Goulburn Weir that could be
utilised.
9.3.2 Regulatory Processes
Goulburn Murray Water (GMW)
GMW is the operator for the channel system of the Goulburn River. They are responsible for controlling
the flow around the canals to ensure flow and irrigation requirements are met.
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EARTH SYSTEMS
GMW is about to put out an expression of interest to the market place to explore opportunities to partner
with companies to further expand their hydro operations within their infrastructure (including the channel
system). This indicates the likelihood for one of the channels to be equipped with a hydropower plant.
However, as the tender will be advertised through a normal government tender process in the next few
months, GMW was not willing to disclose any related information at present. It is recommended to keep
abreast on the development of this project.
Goulburn Catchment Management Authority (GCMA)
Earth Systems has also been in touch with GCMA with regards to planning considerations for a smallscale hydro. GCMA advises that the process should include:

An application for non-consumptive water use from Goulburn-Murray Water;

A license for construction and planning referrals from local government;

A license from the GCMA for any works undertaken on the banks of the waterway; and

Permission from the Department of Sustainability and the Environment to carry out a project on a
heritage listed river (i.e. such as Goulburn River)
Note that it may be easier to look at installing a series of smaller generators rather a few big generators
due to difficulty to crown land and easement issues. There could also be a possible opportunity for
working group formation to look at hydro for property use (behind the meter with use of drive shaft to
overcome easement and crown land) and grid connection. This working group may consist of technology
company (Rubicon), Water Authority (GMW) and GV Community Energy.
Due to limited data availability, the major assumption made when developing the modelling for this
hydropower scenario is that it is possible to construct a hydropower plant that is similar to the Drop along
the canal/river systems in Murchison. Hence, data from the Drop is used as the basis of the modelling.
At this stage, there are too many unknowns related to the conditions of the canal/river systems to be able
to estimate and locate the most suitable site(s) for installing hydropower plants. It is beyond the scope of
this report to conduct on-site investigation, which would be required in the next stage if proceeding with
this option.
Pumped hydro and storage system has not been considered in the analysis conducted below. This type
of system works in a way that when electricity is cheap, water can be pumped up to a certain height and
released when the price rises, through a turbine to generate electricity. Since storage is needed only for a
day, the water storage usually is quite small. (Energy without Carbon, 2012)
Furthermore, a 40 kW transportable turbine unit (Kouris Centri Turbine) that is in progress to be installed
at Mulwala Canal in NSW could be suitable for installation at the canals around Murchison, as it is more
dependent on canal flow rather than head height. It is recommended to keep abreast of the development
of the installation of the turbine at Mulwala Canal.
The following tables show the key data used to estimate the energy that can be generated per year. This
data then feeds into the economic modelling analysis.
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EARTH SYSTEMS
Table 9-3: Hydropower energy generation modelling data/assumptions and results – 1.6 MWe
Hydro – 1.6 MWe
Data
Value
Units
System capacity factor*
46%
6,400
MWh/yr
* This number is based on the capacity factor of the Drop (Pacific Hydro, 2011)
Table 9-4: Hydropower energy generation modelling results – 2.1 MWe
Hydro – 2.1 MWe
Data
Value
Units
System capacity factor*
46%
8,400
MWh/yr
* This number is based on the capacity factor of the Drop (Pacific Hydro, 2011)
Economic Modelling
The energy generation results above are used for the economic modelling below. Both scenarios for
hydropower plant at 1.6 MW e and 2.1 MW e display similar results. This is likely due to both being
classified as small-scale, which implies that the economies of scale effect is not apparent (resulting in
identical LCOE between the two scenarios).
Table 9-5: Data and results of key financial parameters (all in 2012 AU$) of hydropower 1.6 MW e
Hydropower - 1.6 MWe
Data
Value
Units
Ref./Notes
6,400
MWhe
17.53
MWhe
Avg. Power
0.73
MW e
46%
Pacific Hydro, 2011
Capex
Capex total
4,148
6,637,000
Opex
Opex total
93
149,327
$/kW e nameplate
Average values based on
‘The Drop’ (CEC, 2012c),
IRENA (2012a), and
communication with
Pacific Hydro staff.
$
$/kW e/y
IRENA, 2012a and
ETSAP, 2010
$/yr
Capex
9,084
Opex
204
$/kW e generated
$/kW e/y generated
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EARTH SYSTEMS
Hydropower - 1.6 MWe
Data
Value
Units
Ref./Notes
NPV
-1,298,927
IRR
$
4.56%
12.5
Years
LCOE at year 1
117
$/MWhe
Average LCOE**
157
$/MWhe
Averaged value over
project life
Table 9-6: Data and results of key financial parameters (all in 2012 AU$) of hydropower 2.1 MW e
Hydropower – 2.1 MWe
Data
Value
Units
Ref. /Notes
8,400
MWhe
23.01
MWhe
Avg. Power
0.96
MW e
46%
Pacific Hydro, 2011
Capex
Capex total
4,148
8,710,000
Opex
Opex total
93
196,000
$/kW e nameplate
Average values based
on ‘The Drop’ (CEC,
2012c), IRENA (2012a),
and communication with
Pacific Hydro staff.
$
$/kW e/y
IRENA, 2012a and
ETSAP, 2010
$/yr
Capex
9,084
Opex
204
$/kW e generated
$/kW e/y generated
NPV
-1,704,842
IRR
$
4.56%
12.5
years
LCOE at year 1
117
$/MWhe
Average LCOE**
157
$/MWhe
Averaged value
project life
over
67
EARTH SYSTEMS
The LCOE of hydropower for Murchison is estimated at AU$117/MWhe at year 1, with an average LCOE
of AU$157/MWhe over the project life (2012 dollars). This number is within the range of LCOE reported by
the Hydropower report by IRENA (IRENA, 2012a) that is between US$20 to 270/MWh e (2010 dollars) for
small hydro. The wide range is likely due to the different construction requirements of hydropower plants,
i.e. some canal/river systems do not need extensive construction to install a hydropower plant, hence
lowering the resulting LCOE.
The payback period for hydro is calculated to be around 12.5 years. Although the financial results for this
option are not bad, there may be another alternative to consider to improve the economics. In a scenario
where the electricity could be sold to customers directly (on retail rate and off the grid) at an approximate
rate of $150/MWh, the payback period could reduce by up to 5 years (making the payback by
approximately 7.7 years) with an IRR of 10.3%. This could present a more attractive option for Murchison
to pursue this technology.
Sensitivity analysis affecting the LCOE on the 1.6 MW e and 2.1 MW e scenarios was carried out to
determine the most sensitive contributing factors (see below).
Figure 9-4: Sensitivity analysis on 1.6 MWe hydropower in Murchison
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EARTH SYSTEMS
Figure 9-5: Sensitivity analysis on 2.1 MWe hydropower in Murchison
Similar to the solar PV scenarios, the sensitivity analyses of the different hydropower scales yield the
same results. As shown by the figures above, the most sensitive factor is the quantity of electricity
generated, followed by capex, discount rate, electricity price escalation rate, opex, and inflation.
This indicates that the quantity of electricity generated from the system and capex are key factors in
determining the feasibility of this option.
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EARTH SYSTEMS
10 Geothermal Energy
Geothermal energy refers to energy stored as heat in the earth. As part of a low emissions energy
strategy, a geothermal power generator offers the benefit of being able to provide base-load power to
complement other generation types with fluctuating inputs (e.g. solar PV). It can provide a heat output
also. In Australia, geothermal resources of significance exist in two forms; either as Hot Fractured Rocks
(HFR) or Hot Sedimentary Aquifers (HSA). However, so-called “conventional” (volcanic) geothermal
sources (which have been utilised in other parts of the world) do not exist in Australia (AGEA, 2012).
Exploiting a geothermal resource involves the circulation of water between the underground heat source
and a power station or heat user at the surface via wells, which may (in the case of non-conventional
resources) be up to 5 km deep. Because no fuel is burned, there are no greenhouse gas emissions from
the power generation process.
For a number of reasons, including the technical challenges associated with intersecting and achieving
connectivity in non-conventional resources at significant depth, progress towards geothermal power in
Australia has been limited, with most of the activity in this space only occurring in the last ten years.
Whilst a variety of potentially significant geothermal projects are now under development in Australia,
there is only one (small) geothermal power station presently in operation.
Geothermal energy technology is discussed in Appendix C. The appendix only includes technology for
electricity generation via thermal power cycles (similar to coal or biomass-fired power stations).
Discussion on ground source heat pumps is not included as it is not within the scope of this review.
10.1 Environmental Impact
Environmental risks and impacts associated with geothermal projects include (IEA, 2008; Stewart, 2009):








Seismic effects – minor earthquakes and subsidence can occur as a result of geothermal projects
Resource depletion – geothermal plant may deplete the supply of hot water to nearby natural
geothermal features
Water usage – large quantities of water may be required in order to provide cooling (heat
rejection) for the power plant (a 5MW e plant may use up to 8.5 Mega Litres per day, if a closedloop cooling circuit is not employed)
Pumping energy - may be considerable, possibly amounting to as much as 20 to 45% of power
produced for a low temperature resource (<200°C)
Saline and contaminated waters - some aquifers can produce moderate to highly saline fluids
which are corrosive and present a pollution hazard to freshwater drainage systems and
groundwater
Air pollution – dissolved gases such as hydrogen sulfide (H2S) and carbon dioxide (CO2) may be
released from geothermal fluids and present a health risk in the vicinity of the wells or power plant
Noise – noise impacts associated with drilling, and subsequent power plant operation
Surface disturbances – general impacts associated with site development such as vegetation
clearing, roads, power line infrastructure, etc.
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EARTH SYSTEMS
Table 10-1: Geothermal Power Summary
Technology Characteristics
Data
References
~95
Geoscience Australia, 2012
Levelised Cost of Power Production ($/MWhe)
Conventional
Hot Sedimentary Aquifer
Hot Fractured Rock
45 to 80
80 to 140
100 to 200
IEA, 2008; REPP, 2012
Kallis, 2012
Kallis, 2012
Installation Capital Cost ($M per MW e)
1.2 to 5.5
IEA,2008
High
IEA,2008
Typical Plant Availability (%)
Project Risk Category
10.2 Geothermal Resources in Victoria
The maps of geothermal temperature presented in a report by SKM on geothermal potential in Victoria
indicate that temperatures between 30 and 60ºC are present over much of the state at depths of 500 to
1,500 m. The feasibility of extracting geothermal waters at these temperatures is strongly influenced by
the geology and hydrogeology of the deep sedimentary basins. The study has revealed that the average
geothermal gradients in the sedimentary basins (i.e. the Gippsland, Otway and Murray Basins) were
found to be between 3 and 4ºC per 100 m depth, which is marginally above the worldwide average of
3ºC/100 m. An obvious “hot spot” in the geothermal gradients appears to be present in the Latrobe Valley
in the Gippsland Basin where geothermal gradients are as high as 7.3ºC/100 m (SKM, 2005). The
geothermal temperature map at 1,500 m depth of Victoria is shown below.
Figure 10-1: Geothermal temperatures of Victoria at 1500 m depth (SKM, 2005)
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EARTH SYSTEMS
The report (SKM, 2005) concludes that the temperature of geothermal water within 2000 m of the surface
in Victoria is not sufficiently high for generating electricity in a conventional steam turbine. While there
may be possibility in employing Organic Rankine Cycle and Kalina Cycle electricity generation
technologies, the expected plant efficiencies at temperatures less than 100ºC are so low that such
developments are unlikely to be economic. Similarly, geothermal temperatures in that depth region easily
accessible by drilling are generally too low to be able to support a successful HFR development under
current economic conditions and with currently proven technologies (SKM, 2005). However, high
geothermal temperatures recorded in the Gippsland and Otway Basins could represent exploration
targets for potential geothermal energy generation developments, as in the case of Greenearth Energy
that is looking into implementing a 12 MW e pilot plant in the Geelong/Anglesea area (Gippsland).
10.3Local Geothermal Potential
A preliminary study of geothermal energy in Murchison shows a low potential, as illustrated by the
geothermal maps above and below. The maps show that the predicted geothermal temperature around
o
Murchison is in the range of 50-60 C at 1,500 m depth. Based on these temperatures, it is unlikely that a
geothermal resource exists which could be exploited economically for regional power generation, as the
foregoing section suggests a higher minimum resource temperature would be required for a geothermal
project.
Nonetheless, it is worth noting that the data sources for geothermal mapping in Victoria are limited, and
the majority of the maps have been generated via calculation and interpolation rather than direct
measurements from boreholes (SKM MMA, 2011), especially around the central and northern parts of
Victoria (see Figure 10-1 above). At the time of writing, we are unaware of any direct physical
measurements of geothermal source temperatures around Murchison. Given the limited geothermal
dataset for Victoria, it is suggested that geothermal opportunities surrounding Murchison be re-visited if in
future additional data becomes available.
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EARTH SYSTEMS
Murchison
Figure 10-2: Geothermal temperature of Murchison at 1500 m (SKM, 2010)
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EARTH SYSTEMS
11 Bioenergy
Wet and dry biomass resources require the application of appropriate technologies to either biologically or
thermochemically transform them into a usable form of syngas, liquid and/or solid stream(s). Secondary
energy conversion technologies are then required to efficiently convert the gas, liquid or solid outputs for
the production of thermal heat, the generation of electricity and/or upgrading the outputs to a suitable biooil level (e.g. methanol). There are significant technology and financial risks associated with each option.
Matching the primary and secondary energy technologies with the feedstock requires a detailed analysis
of the technology options.
One of the simplest technical and lowest financial cost opportunities for biomass is the supply of thermal
heat to an existing industrial process. This may negate the requirement for secondary energy conversion
technologies (e.g. electricity generation), or at least make the secondary technology simple and low cost
to implement. A primary energy technology of combustion is a mature technology that can accept and
process a wide range of feedstock. A large industrial scale thermal energy demand is needed to make
this option viable.
Within the town of Murchison, there do not appear to be any large industrial sites that may be suitable for
thermal heat supply from biomass at the MW scale.
The success of a local bioenergy project is dependent on many factors, not least the matching of biomass
resources to a bioenergy requirement. Waste biomass can represent a useful resource given it is
produced as a result of an alternative requirement. Often it can be procured at cost neutral supporting a
bioenergy business case.
Resources for the production of bioenergy are broadly defined and encompass a number of different feed
stocks, including woody plants, cultivated grasses and crops, green waste and other organic waste from
plant, sewage and animal processing. Waste biomass is generally broadly dispersed, has widely variable
physical properties and can be difficult to harvest, but generally has a zero or negative value. Cropped
biomass is concentrated, has well defined characteristics but can displace land for farming and food
production.
11.1 Biomass Resource
The following sections discuss potential sites where biomass feedstock could be sourced from. Note that
this would not include field-grown produce such as a tomato farm.
More information on regional land and climate characteristics of Murchison is available in Appendix A.
11.1.1
Existing Forestry Operations
According to Rhodey Bowman, Forestry Services Officer at DEPI Tatura, there are a number of public
forestry areas within a 50km radius around Murchison that are available for collection of firewood. There
are also approximately 75 – 100 hectares of private forestry within close proximity to Murchison, mainly
for sawlog production. Many of the species previously planted were designed for irrigated agriculture and
have become unsuitable for a sawlog resource after years of drought. These may be able to be used for
bioenergy. Alternatively, thinning of these and public plantations could provide some biomass resource.
Biomass can also be sourced periodically from roadside woody weeds and storm damage. Indications
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EARTH SYSTEMS
are, however, that the total quantities available from these sources would be significantly less than that
required for megawatt-scale generation in a bioenergy plant.
Agricultural enterprises in the region often have woody weed problems which are also a potential biomass
resource. Changing land use can periodically create biomass resources, particularly the change from
flooded to overhead irrigation and this may make it necessary to clear away trees to accommodate new
land use.
11.1.2
Agricultural By-products and Residues
This preliminary survey of local industry is intended to provide an example of the types of resources that
may be available to the local community. It is hoped that community members may be able to use this
section to further identify resources in the local area that could be potentially utilised for the production of
renewable energy. Table 7-1 shows ABS statistics for recorded agricultural commodities in the Goulburn
th
District as at 30 June 2012. These statistics suggest the extent of potential agricultural waste available
in the wider region.
Table 11-1: Goulburn district agricultural commodities
Agricultural commodities - year ended 30 June
Total area
Cereals for grain
Vegetables for human consumption
Orchard trees (including nuts)
All fruit (excluding grapes)
Non-cereal broadacre crops
Area of holding
Total number
Sheep and lambs
Milk cattle (excluding house cows)
Meat cattle
Pigs
ha
ha
ha
ha
ha
ha
180 730.6
3 136.2
13 266.4
13 489.0
35 273.0
1 559 111.6
no.
no.
no.
no.
2 017 728
453 370
433 196
182 269
Source: ABS, 2012
Crop Residues
More grain is being grown in the district in the past 5 years than previously – some by dairy farmers for
their own use and may not appear on statistical data. Stubble retention is now more common, making
less stubble potentially available. Depending on water availability, farmers are increasingly looking to
adopt double cropping systems which will create a biomass resource from summer crop residues which
need to be removed when using double cropping systems. According to one local farmer, maize leaves
an approximate maximum of 2 to 4 tonnes dry weight per hectare while wheat is more like 1 to 2 tonnes.
Initial estimates of the cost delivered to a plant would be approximately $100 tonne. Bailing the material
would be approximately $40 tonne and transport would be approximately $15-$20 tonne. These prices
suggest that as fuel for a biomass plant, the cropping residues would be uneconomic.
Orchard Turnover
Perhaps the largest source of potential biomass in the areas surrounding Murchison could be sourced
from fruit growers. A gasification project by Fruit Growers Victoria to utilise orchard trash (fruit waste) in
recent years was aborted due to the belief that there wasn’t enough energy potential in the fruit (mostly
water) but horticultural orchards that have ceased operating are a potential source of biomass. There is
also a large sustainable source of biomass that can be derived from periodic replacement of trees within
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EARTH SYSTEMS
the orchard industry. It is estimated that annual fruit tree turnover due to old age of trees is approximately
5%. The figures in Table 7-2 which were obtained from Fruit Growers Victoria show that in the Goulburn
Valley between 2006 and 2010 there were approximately 2,524 hectares of fruit trees removed at an
annual average of 504.8 hectares.
Table 11-2: Planted fruits in the Goulburn Valley region in 2010
Fruit
Hectares
Hectares
removed 2006 2010
Average
annual removal
(ha)
Plums
617
174
34.8
Pears
3,320
513
102.6
Peaches
991
831
166.2
Nectarines
542
239
47.8
Apricots
434
219
86.8
Apples
2,130
513
102.6
Cherries
202
35
40.4
Total
8,236
2,524
504.8
Source: Fruit Growers Victoria 2012
Typically, this potential resource is currently collected into piles and burnt by orchard owners at their own
cost. It is therefore recommended that further investigation be conducted on the total quantities and
seasonal availability of waste orchard tree biomass.
Livestock
A number of enquiries were made to local farmers with livestock operations in relation to potential waste
sources for bioenergy – particularly manure and wet wastes for biodigester use. Much of the waste
produced by many of these enterprises are utilised on farm for other purposes such as crop fertiliser but
there may be opportunities on intensive livestock farms not engaged in cropping.
11.1.3
Waste Materials
Food Processing Waste
A significant source of food waste in the region near Murchison is waste from out of date tinned food. One
local enterprise has developed a machine to separate food from cans on a large scale and is in the
process of developing a similar machine to separate plastics. They originally were paid to take out of date
tinned product from SPC and they currently separate 10 tonne of food (fed to the dairy cattle), and 1
tonne of cans (sold to Onesteel) per week. They have just bought the Heinz factory at Girgarre which is
already full of tinned products and is receiving 5 semi-trailers a day from Melbourne. All producers are
paying them to remove their out of date stock which would alternatively cost $140 tonne to move to
landfill. In addition to their market for tin they are also investigating markets for bailed plastic and
76
EARTH SYSTEMS
cardboard in Australia and overseas but yet they have no market for the food waste. Among the options
being considered for this resource are the extraction of high value sugar based products and bioenergy.
They estimate that Melbourne has a potential of about 200,000 tonnes/year for out of date products and
the region around Murchison between 40,000 – 60,000 tonnes. Overall in Victoria, the figure could be up
to 1 million tonnes.
The potential for a biodigester facility to utilise wet biomass wastes, especially food processing wastes,
should be further investigated if a reliable long-term supply of sufficiently large volume can be secured.
The waste food processing operation at Girgarre with approximately 1 million tonnes of biomass source
may be worth pursuing to evaluate possible options for Murchison.
Municipal Waste
A representative was contacted at the wastewater treatment plant in Tatura. Both sites at Tatura and
Shepparton currently incorporate digesters and utilise the methane for power generation. They are
currently looking at expanding their energy generation on some unused land at their Shepparton site
which they call their ‘recycling area’ and are considering developing this site into a bio-energy precinct in
partnership with local industry. In this regard, the site benefits from its size, appropriate buffer zone from
surrounding communities and its proximity to the grid and local populations.
A representative from the Shepparton Council waste department was contacted in relation to local waste
operations. The council have a resource recovery centre at Murchison where the waste dump used to be.
They contribute a small amount of green waste to the Shepparton municipal waste facility. Shepparton
and Ardmona both have waste facilities with green waste separators. Both facilities make mulch which is
3
then on-sold to the local community for $6/m . There is currently no facility for separation of food waste
so all food waste currently goes into landfill. They’re looking at providing kerbside options in the future to
create a food waste resource. This suggests that there is scope for a pilot survey in Murchison to
determine the potential to divert regional organic wastes from landfill as a source of wet biomass for a
digester operation.
Other Waste
There are a range of other sources of potential waste streams that could potentially be utilised within the
region if there was a centralised processing facility or organised contracted collection. Potential sources
include but are not limited to:
 Construction and demolition wood waste
 Timber crates and pallets
 Cardboard, paper and timber wastes
 Sawdust
According to Fruit Growers Victoria, there is also wash down water and cardboard/wood waste at
orchards throughout the Goulburn Valley but in their opinion, it is not currently economical to collect for
energy purposes.
11.1.4
Potential for Future Bioenergy Cropping
The decline in water availability for irrigated agriculture in areas around Murchison may present future
opportunities for dryland bioenergy cropping. The costs of production from irrigated land under current
uses may in some cases become prohibitive, creating the necessity to find more profitable alternatives.
Trials have already been undertaken by Yates in Kyabram growing eucalypts on marginal land for salinity
interception and these types of crops may be an option for marginal land where no other valuable product
can be produced. Investigation into bioenergy cropping has been completed by numerous bodies,
including CSIRO, the RIRDC and long-term trials in different areas of Australia. For the production of
electricity, thermochemical pathways (combustion, gasification and pyrolysis) typically favour woody
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EARTH SYSTEMS
biomass crops, whereas biochemical conversion (digesters and fermentation) favours waste and
leafy/grassy crops.
In Australia, oil mallee eucalyptus cropping research has been under development for over a decade, with
a pilot plant based on this feedstock having been trialled at Narrogin, Western Australia. An integrated
wood processing pilot plant, which generates 1 MW e, has been in operation at Narrogin, Western
Australia. This project co-produced eucalyptus oil and activated carbon. This project used oil mallee
trees, planted mainly for dryland salinity control. In early 2010 a prototype Mallee harvester was
launched, to further develop oil Mallee for energy and related products. (CEC, 2010)
Delta Electricity has also launched a substantial trial involving ten farmers in the Central West of NSW to
grow Mallee for wood energy pellet manufacture and trial co-combustion with coal. The project aims for
large scale planting of Mallee for conversion to wood pellets for a co-firing trialling at Wallerawang Power
Station. This trial involves some 10 farmers co-ordinated by agri-business Demand Farming. Others
involved in promoting and developing oil Mallee as an energy crop are the Oil Mallee Association, the
Future Farm Industries Cooperative Research Centre, and BioSystems Engineering, a Toowoomba
based company who have built a prototype mallee harvester for the Future Farm Industries CRC (CEC,
2010)
Several plant species have been identified worldwide for bioenergy cropping potential, including Pinus
radiata, Salix spp., Eucalyptus spp, Acacia saligna, and Miscanthus. Of these species, Pinus, and
Eucalyptus are most appropriate for the Murchison climate, which exhibits relatively low rainfall and
average temperatures. Salix may be appropriate but many of the species are weeds and growing them
prohibited.
Both regular forestry rotations and short-rotation crops have been studied, with particular interest in
Eucalypt Mallee. The Future Farm Industries Cooperative Research Centre (FFICRC) describes Mallee
as a robust native well suited to Australian dryland cropping regions (Future Farm Industries, 2009).
Mallee is particularly advantageous in that it coppices after harvesting, eliminating reestablishment costs.
Mallee biomass production achieves strong energy gain with an energy ratio (the ratio of total energy
outputs and total non-renewable energy inputs) of 41.7. This ratio is considerably higher than those of
other energy crops, e.g. approximately 7.0 for the production of rapeseed (as feedstock for biodiesel
production) in Central Europe (Wu et al, 2005).
As a short-rotation coppice crop (SRC), Mallee can produce upwards of 20t/ha/y of green biomass after
establishment (Greenline Sustainable Biomass, 2011). FFICRC and Greenline Sustainable Biomass
(2011) have investigated a resource management system whereby Mallee cropping can be integrated
with existing agriculture to mutually beneficial effect. As well as Mallee, a number of other eucalyptus
species including Sugar gums, Swamp yates and River Red gums have been identified as potentially
suitable SRC crops in low rainfall regions.
For Murchison, SRC may present an opportunity to grow its own energy crops and move towards selfsufficiency regarding energy supply. However, energy cropping is still under development, and
undergoing substantial research. Large-scale trials are yet to be conducted, and viability of this
opportunity over the longer term has not yet been established. Issues including species selection,
average growth rates specific to the region, soils, rainfall, etc. would have to be established. Other
coppice risks such as degradation of vigour expected over time and capacity of trees to recover would
have to be assessed. More investigation of the risks associated with this energy cropping approach would
be required before deployment in Murchison.
Finally, the economics of energy cropping are not well established and it remains challenging to produce
electricity in a profitable way from purpose-grown energy crops from which no other income is derived.
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11.2 Greenhouse gas emissions
Greenhouse gas emissions represent a very significant environmental benefit to bioenergy solutions. The
IEA Bioenergy Task 38 has assessed the GHG balance of biomass and bioenergy systems to investigate
processes involved in the use of bioenergy and carbon sequestration systems, with the aim of assessing
overall GHG balances (Bird et al, 2011). The group has applied LCA to quantify the cradle-to-grave GHG
environmental impacts of bioenergy systems along the supply chain. The Task 38 work assessed the
LCA bioenergy system GHG emissions compared with the emissions for a typical reference energy
system. The scenario parameters greatly affect the outcome and hence different representative scenarios
were assessed.
Of relevance to this report, the electricity bioenergy scenario using plantation waste residues from NSW
generated GHG savings of between 108-128% as compared to the current practice black coal fired 500
MW e power station. A large 70 MW th thermal bioenergy scenario replacing an oil-fired heating system
reduced emissions in the order of 85%.
Table 11-3: Summary of LCA bioenergy scenarios vs current practice fossil fuel scenario from IEA
Task 38 (Bird et al, 2011)
Bioenergy scenario - HEAT
g
CO2e/kWhth
tCO2e/
tdry
327
1.71
295
1.17
g CO2e/kWhe
tCO2e/
tdry
909
0.949
853
1.30
g
CO2e/kWhtotal
tCO2e/
tdry
The biogas plant in Paldau, Austria – Electricity is generated in a 500
MW e natural gas closed cycle power plant and the heat is supplied by oil
and wood boilers – closed storage.
207
129
As above – open storage
129
018
150 kW th wood versus oil-fired heating systems in Southern England
70 kW th Miscanthus versus oil-fired heating
systems in West London
Bioenergy scenario – ELECTRICITY
This case study assessed the potential GHG emissions reduction from
substituting electricity from black coal with bioenergy based on
Eucalyptus spp. plantation residues in northern New South Wales.
Firing of plantation residues in newly built 30 MW e wood-fired generating
stations in the plantation region. The 30 MW e wood-fired generating
stations use circulating fluidised bed boiler, steam turbine technology that
has a 20% conversion efficiency vs current practice 500MW e black coal
fired power station.
As above scenario but co-firing of plantation residues in existing black
coal 500 MW e generating station 360 km away from plantations. The
efficiency of the system is 29%, which is lower than the efficiency of coal
combustion due to the higher moisture content of the biomass.
Bioenergy scenario –COMBINED HEAT AND POWER BIOGAS
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11.3 Bioenergy Status
The following sections discuss bioenergy status in Australia and Victoria. Information on global bioenergy
status is available in Appendix D.
Australia
The Clean Energy Council (CEC) publishes a yearly review of the bioenergy industry of Australia.
According to the most recent report published in 2011 there is 773 MW e of bioenergy plants now installed
around the nation, and another 20.1 MW e of capacity under construction. Bioenergy generated an
estimated 2,500 GWhe in Australia per year, or ~0.9% of Australia’s total electricity consumption, and
around 8.5 per cent of total renewable energy generation (CEC, 2011b). This compares poorly to leading
European countries where in some countries up to ~14% of electricity generation is from bioenergy.
Figure 11-1: Bioenergy electricity generation total for Australia (CEC, 2011b)
Much of the energy created from biomass fuels is in the form of heat from firewood. Of the installed
electricity capacity, about half is from bagasse combustion in the sugar industry, with the second largest
contributor being biogas.
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Figure 11-2: Bioenergy electricity generation by state in Australia (CEC, 2010b)
Bioenergy in Victoria
Bioenergy generation in Victoria is dominated by landfill biogas generation. There are some examples of
generation at industrial sites as well, including:





Landfill gas: The use of landfill gas to generate electricity is a mature industry in Australia.
Victoria currently has 16 sites totalling 43.8 MW e
Australian Paper uses its pulp and paper waste stream to generate 54.5 MW e of electricity and up
to 100 MW th at its Maryvale paper mills.
Melbourne Water's Eastern Green Energy Project at Carrum Downs produces 9.1 MW e electricity
and 5 MW th from sewage waste.
McCain's Foods in Ballarat generates 5.0 MW th of steam from potato waste.
Berrybank piggery's 0.225 MW e plant near Ballarat has been generating 3.5 MWhe of electricity
per day from its waste since 1991.
Bioenergy plants under construction in Victoria include (CEC, 2011b):




Werribee expansion, sewage gas, AGL – 2MW e
Food and agricultural wet waste, Leongatha, Quantum Power – 0.76 MW e
Sewage gas, Melton, AGL – 0.2 MW e
Murray Goulbourn Co-operative, Leongatha, have recently completed the installation and
commissioning of two biogas generators to convert biogas from their waste food and water
treatment process, to 760 kW e of electricity. (CEC, 2010b)
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Figure 11-3: Bioenergy generators in Victoria (CEC, 2012b)
Future Bioenergy Projections
There are a relatively small number of proposed bioenergy projects in the pipeline in Australia when
compared with other renewable technologies. However, Australia’s biomass resources are abundant and
there is great potential for bioenergy to assist Australia in the transition to a low carbon economy.
The CEC’s Bioenergy Roadmap identified that an annual target of approximately 11,000 GWh e pa of
electricity generation can be delivered from an equivalent of about 1,845 MW e of installed capacity to
2020 (including both existing and new capacity) (CEC, 2008). Other analysis by the Federal Government
estimates bioenergy could provide between 19.8% and 30.7% per cent of Australia’s electricity generation
by 2050. (CEC, 2010b)
Unfortunately, it is clear that the generation potential required to meet these projections is not under
construction. A report recently commissioned by the CEC into examining the reasons behind the lack of
bioenergy generation increase found that there were several barriers to deployment. Market entry
barriers, grid connection issues and unknowns, biomass fuel supply, cost reliability and seasonality where
amongst the more important barriers. (SKM MMA, 2011)
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The modelling conducted is based on one scale only (as opposed to two scales for the other renewable
energy technologies) at 1.6 MW e. At this scale, the bioenergy plant is able to produce to a net expected
output rate of 11,400 MWhe/year and meet more than the yearly electricity consumption of the town
(based on data from Powercor, the town requires an estimated 8,300 MWhe/year).
There are two bioenergy technologies considered for Murchison: gasifier + gas engine and Organic
Rankine Cycle (ORC) plant (both at 1.6 MW e). These two technologies are suitable for a relatively smallscale bioenergy plant such as the proposed 1.6 MW e bioenergy plant (further information on bioenergy
technologies is available in Appendix D).
One of the main factors to consider (other than the associated costs for the different technologies) are the
characteristics of the available biomass feedstock. A gasification system usually requires the biomass
feedstock to be of certain characteristics, whereas, a combustion process (i.e. ORC) is generally more
fuel flexible.
As no option for heat utilisation was identified in Murchison, the economics are dependent on electricity
sales only – which significantly reduces the viability of the bioenergy plant. Additionally, it has been
assumed that purpose-grown energy cropping would be necessary to fulfil the plant fuel requirements.
Payment for fuel also reduces the economic benefit for a bioenergy plant.
It is anticipated that somewhere in the order 18,000 to 25,000 tonnes per annum of woody material would
need to be sourced to supply a 1.6 MW e generator. Detailed, on-the-ground investigation to determine
the characteristics of biomass available within the area has not been carried out. This will need to be
undertaken in the next stage to determine the most suitable bioenergy plant for Murchison.
Note that since the assumptions made (other than costs) for the two technologies are the same
(assuming both are able to accept the biomass feedstock available in Murchison), the energy generation
results are the same. Below are the results of the modelling exercise based on the two technologies.
Table 11-4: Gasification and ORC energy generation modelling – 1.6 MWe
Gasification and ORC – 1.6 MWe
Data
Value
Units
Ref./notes
Energy generation assumptions
Operating hours
Wood calorific value
Moisture content
7,500
8.6
Hrs/yr
GJ/t wet
45%
Energy generation
Plant capacity
1.6
MW e
Generator output
12,000
MWhe/yr
Plant electricity generation
11,400
MWhe/yr
Including parasitic load
of 5%
Biomass feedstock requirement
Biomass required
2.51
t wet basis/hr
18,814
t wet basis/yr
10,348
t dry basis/yr
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Economic Modelling
Each of the technologies discussed above (gasifier and ORC) possesses different capex and opex
characteristics.
Based on Stucley et al (2008) and Sanderson et al (2009), the following cost data is used (all data
presented in 2012 Australian dollars).
Table 11-5: Cost data for biomass to energy technologies
Data
Value
Units
Ref.
$/kW e
Stucley et al, 2008
$/kW e per year
Stucley et al, 2008
$/kW e
Sanderson et al, 2009
$/kW e per year
Sanderson et al, 2009
Gasifier and gas engine (1.6 MWe)
Capital cost
Operating cost
6,602
374
ORC (1.6 MWe)
Capital cost
Operating cost
9,122
415
Compared with waste biomass sources, bioenergy crops incur higher cost and can be expensive to a
potential bioenergy project. Ghaffariyan and Brown (2011) have summarised the results of harvest costs
of bioenergy crops for trees (mallee), given in Table 11-6.
Table 11-6: Estimated Bioenergy Crop Harvesting Costs (Ghaffariyan et al, 2011 and Sylva
Systems, 2011)
Harvest Cost per tonne
Total Cost per tonne
System
(road side)
(mill gate)
Bundler – scattered material
$65 - $70
$90 - $95
Bundler – concentrated material
$35 - $40
$60 - $65
Mobile Chip – stem only scattered
$35
$60
Mobile Chip – stem/limbs scattered
$33
$58
Mobile Chip – stem/limbs
concentrated
$37
$62
Mobile Chip – all residues scattered
$43
$68
Mobile Chip – stem forwarded road
side
$13 - $18
$38 - $43
Whole tree chip failed plantation
$30 - $45
$55 - $70
$20
$70
Mobile Chip – all biomass recovered
Abadi (2011) has also estimated the delivered cost of mallee biomass based on a Western Australia case
study around Great Southern and South Cost. The following table shows the result of his investigation.
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EARTH SYSTEMS
Table 11-7: Cost data for biomass production and transportation (Abadi, 2011)
Data
Lower Range ($/t wb)
Upper Range ($/t wb)
Land
8
9
Competition
13
22
Establishment
1
2
Fertiliser
4
7
Harvest and Haulage
20
23
Supply chain admin
4
6
Transport to processor
1
15
Total
60
84
Using Table 11-6 and
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EARTH SYSTEMS
Table 11-7 above, a total cost of biomass production cost of $70/t wet basis (including biomass growing,
harvesting, and transporting to gate within 50 km) has been applied to the economic modelling. This
value of $70/t wet basis falls between the lower and upper range of costs stated by Abadi (2011) in
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EARTH SYSTEMS
Table 11-7 above, and is also within the range shown on Table 11-6 (assuming mobile chipping and that
all biomass is recovered).
The energy generation results above are used for the economic modelling below.
Table 11-8: Data and results of key financial parameters (all in 2012 AU$) of a gasification system
at 1.6 MWe
Gasifier - 1.6 MWe
Data
Value
Units
Ref./Notes
11,400
MWhe
31.23
MWhe
Avg. Power
1.30
MW e
81%
Capex
6,602
Capex total
10,563,220
Opex
374
Opex total
597,918
Biomass production cost
70
total
1,313,621
$/kW e nameplate
$
$/kW e/y
$/yr
$/t wet basis biomass
$/yr
Capex
8,117
Opex
Biomass cost
$/kW e generated
459
$/kW e/y generated
1,009
$/kW e/y generated
Key financial results
NPV
-21,558,097
$
IRR
N/A
N/A
Years
LCOE at year 1
251
$/MWhe
Average LCOE**
337
$/MWhe
Averaged
project life
value
over
Table 11-9: Data and results of key financial parameters (all in 2012 AU$) of an ORC system at 1.6
MWe
ORC – 1.6 MWe
Data
Value
Units
Ref. /Notes
11,400
MWhe
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ORC – 1.6 MWe
Data
Value
Units
31.23
MWhe
Avg. Power
1.30
MW e
81%
Ref. /Notes
Capex
Capex total
9,122
14,594,658
Opex
Opex total
total
Capex
415
663,768
70
1,313,621
11,215
Opex
Biomass cost
$/kW e nameplate
$
$/kW e/y
$/yr
$/t wet basis biomass
$/yr
$/kW e generated
510
$/kW e/y generated
1,009
$/kW e/y generated
Key financial results
NPV
-26,465,673
$
IRR
N/A
N/A
years
LCOE at year 1
288
$/MWhe
Average LCOE**
388
$/MWhe
Averaged value
project life
over
The LCOEs for the above scenarios are estimated at AU$251/MWhe for a gasification system and
AU$288/MWhe for an ORC system at year 1, with an average LCOE of AU$337/MWhe and
AU$388/MWhe, respectively, over the project life (2012 dollars).
The NPVs for both of the bioenergy plant scenarios above show negative figures, due to the low
combined rate of wholesale electricity and LGC. This bioenergy option is the worst option compared to
solar and hydro, when considered in the absence of thermal heat sales and/or possible landfill diversion
revenue.
Other main financial benefits associated with the bioenergy options and utilising available waste biomass
resource(s) could include income from landfill diversion, selling recycled packaging, as well as selling
heat and electricity produced from the plant. In a best case scenario where there is no biomass
production cost, where it could act as a landfill diversion (i.e. receiving income for accepting biomass
waste at, for example, $70/tonne wet basis), and where the heat generated could also be sold to
customers (at a retail rate of $5.40/GJ based on an industrial site tariff), the resulting IRR is 18.4% with a
payback period of 4.6 years for a gasifier system and 13.3% IRR and 6.2 years payback for an ORC
system (assuming the wholesale electricity and LGC rate is kept at $95/MWh). ). (Note that the financial
benefits from selling recycled packaging are difficult to determine at this stage.)
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EARTH SYSTEMS
Bioenergy technology solutions carry significant and many technical and commercial risks that must be
appropriately managed for a successful project implementation. This includes the growth and harvesting
supply chain, ongoing operational costs, and technology risks with specific feedstocks. Commercial risks
must be carefully managed and stem primarily from assumptions made with biomass supply chain costs
(including harvesting and transportation) and technology. Assumptions made in the project assessment
cycle are critical and must be carefully assessed to ensure accuracy.
Sensitivity analysis affecting the LCOE on the 1.6 MW e gasification system and ORC system scenarios
was carried out to determine the most sensitive contributing factors (see below).
Figure 11-4: Sensitivity analysis on 1.6 MWe gasifier system in Murchison
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EARTH SYSTEMS
Figure 11-5: Sensitivity analysis on 1.6 MWe ORC system in Murchison
As shown by the figures above, the most sensitive factor is the quantity of electricity generated, followed
by biomass production cost. Capex, discount rate, electricity price escalation rate, opex, and inflation are
shown to have relatively similar sensitivity towards LCOE. This indicates that the quantity of electricity
generated from the system and biomass production cost are key factors in determining the feasibility of
this option.
This is slightly different to the other two renewable energy options investigated (solar and hydro) due to
the additional cost item introduced: biomass production cost. This biomass production cost represents the
costs associated with growing the biomass, harvesting, processing to suitable shape and size, and
transportation to site (within 50 km). Currently, as the data used to estimate biomass production cost is
not necessarily Murchison-specific, it is likely that this figure will change once a more detailed on-site
investigation is carried out.
In a scenario where discounting the cost of growing the biomass from the biomass production cost is
possible, the resulting LCOE could go down by up to 23% for the gasifier scenario and 20% for the ORC
scenario.
In another scenario where the proposed bioenergy plant could act as a landfill diversion and generating
additional income (i.e. accepting woody biomass waste at a rate of $70/t wb), the LCOE is likely to be
further reduced by up to 69% for the gasifier scenario and 60% for the ORC scenario.
In yet another more positive scenario, combining the two above (where there is no cost associated with
growing the biomass and there is additional income for landfill diversion) plus the sales of thermal heat
generated by the plant (at a rate of $5.40/GJ), the LCOE could reduce by up to 85% for a gasifier system
and 75% for an ORC system. This would make a very attractive case with expected relatively high NPV
and low payback period.
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12 Related Benefits and Impacts
12.1
Related Benefits and Impacts
Site specific renewable energy developments can potentially meet the different challenges faced by rural
Australia. In an area such as Denmark, Western Australia which is currently experiencing population
growth, their current wind farm project will help to provide for increasing electricity demand. In areas of
population decline, renewable energy projects represent a new source of income, new potential
enterprises and new jobs to attract people back to the area (Hicks & Ison 2011). Hicks & Ison (2011,
p.253) believe that ‘community renewable energy can be considered a strategy for fostering resilient
communities’ enabling them to adapt to social, technical, economic, environmental and political
disruptions and challenges’. This resilience can be attained through developing renewable energy
projects within a local context which accounts for: the needs of the local community based on the existing
infrastructure and power service agreements; the scale and technology required; organisational and
ownership structures; and motivations within the community (Hicks & Ison 2011). In the case of
Murchison, there is already a level of experience and expertise within the community energy sector due to
the establishment of GV Community Energy.
Benefits
According to a recent OECD report on renewable development in rural regions (OECD 2012), the global
deployment of renewable energy has been expanding rapidly. The renewable energy electricity sector
grew by 26% between 2005 and 2010 globally and currently provides about 20% of the world’s total
power including hydro-power. Rural areas attract a large part of investment related to renewable energy
deployment, tending to be sparsely populated but with abundant sources of renewable energy.
A move toward sustainable energy can potentially bring a range of benefits to Murchison and its
surrounding regions. Harnessing renewable energy sources can increase the sustainability of local
businesses, boost employment, create opportunities for tourism and renewable energy related
manufacturing and promote unity within the local community. Community involvement in local energy
supply may help to reduce consumption through education about how energy is produced and would also
help to shift the current focus of energy supply from increasing consumption to meeting local needs
(Kinrade 2007). Benefits to rural development from utilisation of renewable energy as listed by the OECD
are detailed below.
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EARTH SYSTEMS
Table 12-1. Benefits of renewable energy in rural communities.
Benefit
Description
New revenue
sources
Renewable energy increases the tax base for improving service provision in rural
communities. It can also generate extra income for land owners and land-based activities.
For example, farmers and forest owners integrating renewable energy production into their
activities have diversified, increased, and stabilised their income sources.
New job and
business
opportunities
Particularly when a large number of actors are involved and when the renewable energy
activity is embedded in the local economy. Although renewable energy tends to have a
limited impact on local labour markets, it can create some valuable job opportunities for
people in regions where there are otherwise limited employment opportunities. Renewable
energy can create direct jobs, such as in operating and maintaining equipment. However,
most long-term jobs are indirect, arising along the renewable energy supply-chain
(manufacturing, specialised services), and by adapting existing expertise to the needs of
renewable energy.
Innovations in
products, practices
and policies in rural
areas
In hosting renewable energy, rural areas are the places where new technologies are
tested, challenges first appear, and new policy approaches are trialled. Some form of
innovation related to renewable energy has been observed in all the case studies. The
presence of a large number of actors in the renewable energy industry enriches the
“learning fabric” of the region. Small and medium-sized enterprises are active in finding
business niches as well as clients and valuable suppliers. Even when the basic technology
is imported from outside the region, local actors often adapt it to local needs and potentials.
Capacity building
and community
empowerment
As actors become more specialised and accumulate skills in the new industry, their
capacity to learn and innovate is enhanced. Several rural regions have developed specific
institutions, organisms, and authorities to deal with renewable energy deployment in
reaction to large investment and top-down national policies. This dynamic has been
observed both in regions where local communities fully support renewable energy and in
regions where the population is against potentially harmful developments.
Affordable energy
Renewable energy provides remote rural regions with the opportunity to produce their own
energy (electricity and heat in particular), rather than importing conventional energy from
outside. Being able to generate reliable and cheap energy can trigger economic
development.
As well as the benefits listed above, Walker (2008) has listed a number of other potential benefits that
may arise from a community energy project. Projects owned or part owned by the community may be
more locally acceptable than those proposed by external stakeholders. They can also give local
stakeholders control over important aspects of the project such as the scale and location of the proposed
development. While large-scale renewables may create load problems for the electricity network, smallerscale projects, can potentially defer expensive upgrades and extensions of the network by matching the
existing load in an area. In addition, they can safeguard energy security during grid outages, and
contribute to voltage stability. As well as the practical considerations discussed, there are the ethical and
environmental aspects that can provide community benefits. Increasingly, people are being motivated to
participate in sustainable energy generation projects due to ethical and environmental considerations.
Such drivers are also important for public and private sector bodies, which have environmental and social
responsibility policies (Walker 2008).
Impacts
Although a renewable energy development can potentially create a range of benefits for local
communities, it is important to remember that any new development will have an environmental impact on
its surrounding area. Regardless of the type of proposed energy source (renewable or otherwise), the
potential for environmental and social impacts need to be given appropriate consideration during the
planning stages of the project.
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12.2 Energy Security and Vulnerability
As well as the benefits discussed above, diversifying the energy supply mix with renewable energy
options can help to safeguard communities against increasing energy vulnerability due to the rising costs
of electricity provision. Many rural areas are supplied by a single energy provider, which can potentially
lead to higher prices through a lack of competition. Utilisation of localised renewable energy also reduces
reliance on regional, national and international sources of fossil fuels for energy generation. These
sources are becoming increasingly scarce and will affect future energy security at all levels. In addition,
localised sources of energy can help to ensure continuity of supply and buffer communities against
energy infrastructure breakdown from remote sources of supply (IPCC 2011). Some of the ways in which
households, local businesses and agricultural enterprises may be vulnerable to energy supply in
Murchison and its surrounding regions are discussed below.
12.2.1
Energy vulnerability at the household level
Fuel poverty has been defined as a condition in which a household actually spends more than 10% of its
income on household energy (Simshauser et al, 2011).
Rising energy prices are particularly significant for low-income households as a higher proportion of
income is spent on domestic energy compared to wealthier households (Brotherhood of St Lawrence).
However, even within low-income households, household energy expenditure can vary. Whilst low
income households tend to consume less energy than wealthier households, studies have shown that a
small proportion of low-income households have a relatively high energy consumption due to certain
1
characteristics such as larger families, larger house sizes, living in a detached dwelling and not having
2
access to energy rebates . The implications of rising energy prices include:


Energy-related financial hardship, such as difficulty in paying electricity bills and increased
demand for emergency financial relief (Brotherhood of St Lawrence, 2012). This impact is often
masked as households prioritise the payment of utility bills above other household expenditure
and may constrain their energy use, sometimes to the detriment of their home comfort and health
(Green & Gilbertson 2008 in Brotherhood of St Lawrence, 2012).
Increased rates of electricity and gas disconnection and reconnections. The social and health
related consequences of these disconnections or restrictions in energy supply can include
increased stress, deterioration in health, poor diet and inability to fully participate in society
(National Disability Services, 2012).
One implication of analysing fuel poverty and household energy vulnerability is that only low-income
households require speciﬁc consideration by policymakers. Other households should be able to adjust
their budgets accordingly and absorb price increases (Simhauser, 2011).
1
Typically, more energy is required to heat/cool detached dwellings due to the lack of ‘insulation’ provided by the surrounding walls
(as opposed to semi-detached dwellings or units in an apartment buildings where one or more of the walls do not get exposed to
cold/hot outside air due to the adjacent house/unit acting as ‘insulation’)
2
In Victoria, concessions are available to customers holding an eligible Pensioner Card, Health Care Card or DVA Gold card on
behalf of the Department of Human Services, allowing a discount of 17.5% on year-round household electricity bills, applied after
the first $171.60 of a concession card holder’s annual electricity bill (Energy Australia, 2012). Concessions’ rebate/discount varies
from state to state.
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12.2.2
Energy vulnerability for local business
Business activities in rural Victoria could be exposed to energy vulnerability in the following ways:



Current energy expenditure costs for liquid fossil fuels, electricity and natural gas will increase
over time. Businesses will be required to find additional funds to support the increased
consumption and costs per unit energy, assuming current consumption rates do not decrease
(e.g. from energy efficiency measures).
Road transport – Vehicles use petrol, LPG or diesel. Most business owners and staff travel to
work by car. Increasing liquid fuel costs could impact on staff transportation options for work and
home travel as well as the cost of importing or exporting goods from the region.
Contractor operations are significant areas of supply chain energy consumption. Although energy
modelling of upstream cost impacts have not been modelled to a great extent in this study, it
would be expected that businesses will be required to expend more on energy intensive services
in future.
Financial management – businesses will need to account for energy vulnerability (price shocks and
carbon prices impacts) in their financial management.
12.2.3
Energy vulnerability in the agricultural sector
Agriculture is a hugely significant land use in Australia because of the vast spatial scale of agricultural
activities. The economic viability of agricultural land uses has important implications for regional
environmental, landscape, economic and cultural systems. Agricultural systems are also closely
interlinked with urban centres (Low Choy et al 2008 in Dodson et al 2008).
Regional and rural Australia is a major consumer of petroleum for agricultural and allied production and
for transportation. Rising fuel prices and the possibility of supply shortages have significant implications
for the rural and regional sector given the extent of use of these inputs in farm production. Land and
Water Australia has funded a three year project to examine the social and economic vulnerability of rural
landscapes and industries to impacts from rising petroleum prices (Sloan et al, 2008). Otherwise, little
research has been conducted on the role of energy in rural life, society and agriculture in Australia
(Coventry, 2011).
The agricultural sector is vulnerable to rising oil prices in several ways. Firstly, due to the heavy reliance
of the agricultural sector on petroleum-based products, high oil prices are expected to result in increased
prices for key petroleum based farm inputs. In addition, the impact of rising oil prices on the agricultural
sector are also likely to contribute to increased food prices due to the dependence of these sectors on
transportation and the large distances required for the transportation of agricultural produce within
Australia. This could also contribute to food supply or food security issues as well as impact the
agricultural export market, as the cost of Australian produce overseas could rise disproportionately in
relation to commodities produced in other countries.
It is likely that there will be adjustments in the agricultural sector in response to energy vulnerability
(especially rising oil prices), however very little is known about the likely secondary impacts of such price
increases or supply constraints on the farming sector and rural and regional areas generally (Department
of Land and Water). A major change in the global petroleum environment could have large implications
for spatial land-use planning. Initial investigations (Dodson et al 2008) have shown that the following land
use trends could occur as a result of agricultural oil vulnerability:


Changes to the distribution of agricultural types within Australia’s regions;
Changes to the intensities of agricultural land uses;
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

Shifts in the primary mode of transportation of agricultural products, such as from road to rail,
restructuring of settlement patterns – concentration or dispersal – as communities adapt to higher
transport costs;
Abandonment of some land types or sub-regions if production and transport costs became
prohibitive.
Dodson et al 2008 have also highlighted that different agricultural sectors will have differing degrees of
vulnerability and this will also depend on factors such as the competition between local markets and
supermarkets, and the feasibility of growing low-input biomass in remote marginal lands (which could
intensify land degradation). From a social perspective, increasing costs of transport and travel could
reduce the attraction of residing in rural centres within farming regions and increase dependence on
electronic communication.
12.3 Greenhouse Gas Emissions
Through the implementation of the renewable energy technologies proposed in this report, one of the
major impacts would be the avoided GHG emissions. The numbers presented below are based on
avoided emissions associated with equivalent fossil based energy generation.
A grid electricity emission factor of 1.19 kgCO2e/kWh has been used for calculating the avoided GHG
emissions at Murchison (DCCEE, 2012b). This emission factor is specific to Victoria where the majority of
electricity is produced from brown coal.
The following table lists out the reduction on each scenario of the proposed technologies. Note that
leakage emissions have not been accounted in the numbers below.
Note transmission losses could be in the order of 10%, therefore the greenhouse gas savings estimated
below would be conservative.
Table 12-1: GHG emissions avoided through the implementation of the proposed renewable
energy technologies
Renewable energy technology capacity
Emissions avoided (tCO2e/yr)
Solar PV
1.6 MW e
3,150
5 MW e
9,844
Hydro
1.6 MW e
7,616
2.1 MW e
9,996
Biomass
Gasifer – 1.6 MW e
13,566
ORC – 1.6 MW e
13,566
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13 Conclusions and Recommendations
A review of large-scale options for renewable electricity generation was conducted for the town of
Murchison. The review included consideration of the current local electricity demand, the local electricity
grid capacity, options for cogeneration and waste resources in the region. Specific renewable generation
based on solar PV, mini hydropower and bioenergy technologies was considered at scales consistent
with town electricity use. Key findings from the study are as follows:
Electricity Demand
Based on a small number of home energy surveys combined with network data from Powercor,
Murchison has an estimated annual power consumption of approximately 8,300 MWh.
Local Electricity Grid
Based on discussions with Powercor, up to 2 MWe of generation could most likely be connected to the
existing 22 kV system without major grid upgrades. Opportunities for generation along this 22kV corridor
from the Mooroopna zone substation to Murchison should be prioritised, if the main objective of
generation is to be grid-exported electricity.
There do not appear to be any current or projected network constraints likely to require infrastructure
upgrade in the Murchison area in the next few years. Thus, it is unlikely that strategic placement of
renewable generation will be of interest to the network operator in terms of deferred network asset
upgrades.
It should be noted that Goulburn Murray Water may be considering small hydro possibilities in the region
at present, with a view to putting out a tender request in the next few months. This could be a gamechanger as it is likely to affect grid capacity constraints for all options being considered. However, until
more information is available, no firm conclusion can be drawn on the likelihood or scale of any such
impact on the local grid.
There may also be connection issues with regards to a large number of decentralised systems (e.g. solar
on commercial rooftops) being connected to the network in a small area. Early dialogue with Powercor is
recommended if a large roll-out of small systems is anticipated.
Large Consumers
At present, there are no large energy users in Murchison of sufficient scale to justify large-scale behindthe-meter generation to off-set retail electricity purchases.
Demand Response
Demand response programs are an option that should be delved into further, as this could assist the
participating facilities in reducing their energy use during peak period, hence saving energy cost. One
opportunity is that an arrangement could be made with the network operator (i.e. Powercor) such that
participating facilities could sign up a contract that could make them eligible for some kind of financial
benefits by shedding loads during peak period. A further discussion with the network operator would give
direction as to what is required to implement a demand response program (i.e. meter upgrading may be
required).
Modelling
Based on the annual electricity demand, the following generation scenarios were modelled:
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


Solar PV at 1.6 and 5 MWe scales
Mini Hydro at 1.6 and 2.1 MWe scales
Biomass at 1.6 MWe scales, for two technology scenarios (combustion and gasification)
Solar PV at the 5 MWe scale and mini hydro at 2.1 MWe scale (to generate equivalent annual output to
match the projected annual consumption of the town) are the scenarios that exceed the current local grid
capacity and would likely necessitate grid augmentation.
Of the above, the biomass scenario is well-matched to the current local grid capacity and is also able to
generate enough electricity to meet the town’s annual demand.
It should be noted that only preliminary desktop analysis and modelling has been conducted in this
review. More detailed analysis to a higher accuracy level should be part of further work if proceeding
further with any of the option considered in this study.
Geothermal
A preliminary analysis of geothermal energy in Murchison shows a low potential for economic regional
power generation due to the limited resource. However, given the limited geothermal dataset for Victoria,
it is suggested that geothermal opportunities surrounding Murchison be re-visited if in future additional
data becomes available. (Note that other geothermal technology such as ground source heat pumps have
not been considered as they do not constitute power generation.)
Solar Photovoltaic Generation
Local solar power generation in Murchison shows good potential with similarity to regions where largescale solar power developments have been commissioned. Solar PV at the 1.6 and 5 MWe scale were
both projected to have an approximate Levelised Cost of Energy (LCOE) of $207 per MWh at year 1 and
an average LCOE of $277 per MWh.
The two analyses result in the same LCOE due to the capex and opex of both scales being in the same
‘utility’ scale category (in the 1-50 MWe range), hence there is no effect due to economies of scale. Note
the analysis is based on 2012 solar PV capex data, and considering the volatility of solar PV capex, more
up-to-date analysis (which may include supplier’s estimate on specific scale solar PV capex) will have to
be conducted if proceeding further with this solar PV option.
The LCOE is relatively high compared with typical grid electricity prices and results in a relatively long
payback period of about 20 years for grid feed in at an assumed $95 per MWh (total of feed in tariff plus
LGC). This suggests that a behind-the-meter or local grid arrangement whereby the generation could be
directly connected with retail electricity users would be advantageous, and that a series of smaller-scale
installations on the premises of larger energy users may be a better option economically than a
standalone solar “farm” dedicated to grid export.
As part of further investigation, the large solar farm scenario should be compared with the possibility of an
aggregated arrangement of smaller rooftop installations in terms of grid connection, technical feasibility,
and overall economics.
Hydroelectric Generation
Hydropower is a possible option for Murchison, based on general similarities to “The Drop” hydropower
project in NSW. However, considerably more detailed analysis is required to determine the technical
feasibility of a hydropower facility at a specific location within the local water network. Full feasibility
analysis should include an assessment of longer-term performance / capacity risk under drought
conditions.
As mentioned, Goulburn Murray Water may be considering small hydro possibilities in the region at
present, with a view to putting out a tender request in the next few months. This gives an indication that
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the conditions around the canals might be suitable for implementing hydropower generation. However,
this could also give rise to a future network constraint issue which may impact the connection of other
large-scale renewables in the region. Indicative modelling outputs for hydropower scenarios suggest an
LCOE of $117 per MWh at year 1 (with an average LCOE of $157 per MWh) at both the 1.6 and 2.1 MWe
scales, which is the lowest of all renewable scenarios considered. However the result should be treated
with caution as detailed stream flow data were unavailable at the time of writing. Similar to solar PV
modelling, the two scales investigated are considered under the same ‘small-scale’ category (between
100 kW-50 MW), thus there is no ‘economies of scale’ effect in the modelled results.
Biomass Resources
There do not appear to be any large-scale cogeneration (i.e. combined heat and power) opportunities
within Murchison to justify the installation of megawatt-scale cogeneration facilities.
Though not available in large quantities within the town itself, wet food wastes are prevalent in the region
around Murchison, especially resulting from food processing and waste food disposal (Girgarre). It is
recommended that the scope for an anaerobic digester operated on food wastes be investigated further
as there may be regional resources which Murchison could “tap in to”.
Spent fruit trees may offer a suitable resource for a bioenergy plant however the exact volume and
seasonal availability of this resource requires further investigation.
Forestry-based biomass resources within the region (i.e. 50 km radius) are also relatively small, and
would be insufficient to supply a bioenergy plant at the megawatt scale without growing energy crops.
Bioenergy Power Generation
The implementation of a “town-scale” biomass power plant is not economically favourable, as the cost of
energy crop production and lack of heat consumer constrain the opportunity. This is reflected in the high
LCOE range from $251 to $288 per MWh at year 1 (with an average LCOE in the range of $337 to $388
per MWh) depending on the technology selection.
Ideally, should a significant source of woody waste material be able to be sourced (18,000 to 25,000
tonnes per annum), in particular via diversion from landfill (which could represent an additional income
stream) and/or a large heat user can be identified on or near the 22kV feeder to Murchison, the case for
large-scale bioenergy should be revisited as it would likely be quite compelling under this set of
circumstances.
Mix of Renewable Energy Technologies
An investigation of a possible mix of renewable energy technologies (including solar, hydro, and biomass)
should be considered for further work. This may include analysis on the optimum combination of various
renewable technologies considered in this report to maximise the local production and minimise peak
time network import (i.e. solar cannot supply during evening peak and so using bioenergy during this
period would be beneficial). Appropriate analysis on stand-alone mode versus grid-connection mode
should also be undertaken in accordance with the potential optimum mix of renewable energy
technologies (including connection issues and associated costs).
A summary of the findings is shown on the table below.
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Table 13-1: Summary of findings
Resource
Type
Description
Option 1:





Biomass



Pros.
194
Gasification system
Biomass to be processed and
transported to plant site
Generating income in accepting
biomass waste (as a landfill
diversion) at $70/wet tonne
Electricity only for sale
Cons.
1.6

Good size as local
electricity network could
support an additional 1.6
MW generation.

Negative NPV due to high
cost of biomass production,
processing, and
transportation to plant site.
1.6

Good size as local
MW generation.

Need to ensure there are
sufficient biomass residues to
support the energy generation
for the town all year round.
Type of biomass waste may
not always be suitable for the
process.
Gasification system
Harvesting biomass residues
(e.g. forestry, spent fruit trees)
Option 3:


Suggested
Capacity*
(MWe)
Gasification system
Purpose grown feedstock
Option 2:


Approx.
LCOE^
($/MWhe) at
year 1
251

21
1.6


Good size as local
MW generation.
Payback period of ~5.7
years.



100
sufficient biomass wastes to
process.
The price of $70/wet tonne is
an estimation. This number
would need to be fine-tuned
and compared to a landfill
operator around Murchison.
EARTH SYSTEMS
Resource
Type
Description
Option 4:




Gasification system
Electricity and heat for sale
Approx.
LCOE^
($/MWhe) at
year 1
0 (profitable
even if
electricity is
not sold)
Suggested
Capacity*
(MWe)
1.6
Pros.


Good size as local
MW generation.
years.
Cons.




Option 5:







288
1.6

Good size as local
MW generation.

Negative NPV due to high
cost of biomass production,
processing, and
transportation to plant site.
232
1.6

Good size as local
MW generation.

sufficient biomass residues to
Organic Rankine Cycle (ORC)
Purpose grown feedstock
Option 6:
ORC system
Harvesting biomass residues
(e.g. forestry, spent fruit trees)
process.
Need to ensure that there is
sufficient market for thermal
energy produced.

101
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Resource
Type
Description





Pros.
Cons.
process.
58
1.6
ORC system
Option 8:


Suggested
Capacity*
(MWe)
Option 7:


Approx.
LCOE^
($/MWhe) at
year 1
ORC system
Electricity and heat for sale


Good size as local
MW generation.
years.



13
1.6


Good size as local
MW generation.
years.




102
process.
process.
Need to ensure that there is
sufficient market for thermal
EARTH SYSTEMS
Resource
Type
Description
Approx.
LCOE^
($/MWhe) at
year 1
Suggested
Capacity*
(MWe)
Pros.
Cons.
energy produced.
Option 1:


117
1.6
Modelling based on the capacity
factor of the ‘Drop’
Capacity factor of 46%



Hydro
Option 2:


117
2.1
Modelling based on the capacity
factor of the ‘Drop’
Capacity factor of 46%



Option 1:
Solar PV

Modelling based on weather data
207
1.6

Good size as local
MW generation.
Very little maintenance
required.
Reasonable payback
period of 12.6 years.

Good size as local
MW generation.
required.
Reasonable payback
period of 12.6 years.

Good size as local

103


The energy generated would
be sensitive to actual flow at
the chosen site(s) – further
on-site investigation is highly
recommended.
This is a very high level
estimation based on the
turbines installed at the Drop.
Since then, there could be
more advanced turbine better
suited for conditions at
Murchison.
The energy generated would
be sensitive to actual flow at
the chosen site(s) – further
on-site investigation is highly
recommended.
This is a very high level
estimation based on the
turbines installed at the Drop.
Since then, there could be
more advanced turbine better
suited for conditions at
Murchison.
Not a continuous source of
electricity for the town.
EARTH SYSTEMS
Resource
Type
Description
Approx.
LCOE^
($/MWhe) at
year 1
Suggested
Capacity*
(MWe)
Pros.
from Murchison weather station


Option 2:

207
Modelling based on weather data
from Murchison weather station
5


MW generation.
required.
Proven technology.
required.
Proven technology.
Cons.

This option could be profitable
if there exists an opportunity
to sell electricity to customers
directly (rather than grid
export).

Capacity is higher than what
could be supported on the
existing grid.
Not a continuous source of
electricity for the town.
This option could be profitable
if there exists an opportunity
to sell electricity to customers
directly (rather than grid
export).


^LCOE is based on electricity sales only (thermal heat sales is considered as fixed income)
*Rated Capacity (Average actual generated power taking into account capacity factor)
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Sylva Systems Pty Ltd, 2011, “Kangaroo Island Biomass Feedstock Study”
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Available: http://solareis.anl.gov/documents/docs/NREL_PV_3.pdf. Last Accessed 21 June 2012
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December 2012
Vos, J., Remrova, M., Wildbacher, N., 2005, “Biomass for Heating and Hot Water Supply in Belarus –
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March 2013
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15 Abbreviations
ACCC
Australian Competition and Consumer Commission
AEMO
Australian Energy Market Operator
AEMC
Australian Energy Market Commission
AER
Australian Energy Regulator
BOM
Bureau of Meteorology
Capex
Capital Expenditures
CEF
Clean Energy Future
CF
Capacity Factor
CLFR
Compact Linear Fresnel Reflector
CPM
Carbon Pricing Mechanism
CPV
Concentrating photovoltaic
CSP
Concentrating Solar Power
CST
Concentrating Solar Thermal
db
Dry basis
DCF
Discounted Cash Flow
DG
Distributed Generation
DNI
Direct Normal Irradiance
DNSP
Distribution Network Source Provider
EEO
Energy Efficiency Opportunities
EHV
Extra High Voltage
EPRI
Electric Power Research Institute
FIT
Feed-in Tariff
GHG
Greenhouse Gas
GHI
Global Horizontal Irradiance
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HFR
Hot Fractured Rocks
HSA
Hot Sedimentary Aquifers
IEA
International Energy Agency
IEC
International Electrotechnical Commission
IPCC
Intergovernmental Panel on Climate Change
IRR
Internal Rate of Return
km/h
Kilometre per hour
kV
KiloVolt
kVA
Kilo Volt Amp
kW
KiloWatts
kW e
KiloWatts electrical
kWh
KilloWatt Hour
kWhth
KiloWatt hour thermal
kWhtot
KiloWatt hour total (electrical and thermal)
kW th
KiloWatts thermal
kW tot
KiloWatts total (electric and thermal)
LCA
Lifecycle Assessment
LCOE
Levelised Cost of Energy
LGC
Large-scale Generation Certificates
M
Metre
m/s
Metre per second
MW
MegaWatts
MW e
MegaWatts electrical
MWh
MegaWatt hour
MWhe
MegaWatt hour electrical
MWhth
MegaWatt hour thermal
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MWhtot
MegaWatt hour total (electrical and thermal)
MW th
MegaWatts thermal
MW tot
MegaWatts total (electric and thermal)
NASA
National Aeronautics and Space Administration (United States)
NEM
National Electricity Market
NER
National Electricity Rules
NGER
National Greenhouse and Energy Reporting
NPV
Net Present Value
NREL
National Renewable Energy Laboratory
Opex
Operational Expenditures
ORC
Organic Rankine Cycle
PV
Photovoltaic
RECs
Renewable Energy Certificates
RET
Renewable Energy Target
tCO2
Tonne carbon dioxide
tCO2e
Tonne carbon dioxide equivalent
wb
Wet basis
ZSS
Zone Substation
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Appendix A
Regional Climate and Land
Characteristics
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1 Regional Climate & Land
Characteristics
1.1 Regional Climate and Land Characteristics
The climate of Murchison is temperate, with a mean annual rainfall of approximately 448 mm. Mean
maximum temperatures recorded at Murchison are highest in January (30ºC) and mean minimum
o
temperatures are lowest in July (3 C). Mean annual solar exposure ranges from a high of 28.1
2
2
Megajoules per square metre (MJ/m ) in December to a low of 7.3 MJ/m in June. Temperature and
solar exposure statistics are illustrated below.
Figure 1-1: Mean monthly temperature and solar exposure for Murchison 1965 – 2012(BOM,
2012a)
Relative humidity levels range between 61% (in December and January) and 90% (in June). Mean
wind speeds recorded at Murchison are approximately 12.7 km/hr. The prevailing wind direction is
from the south-east in the morning and south-west in the afternoon (BOM, 2012b).
The meteorological data in this section is collected from two Bureau of Meteorology (BOM) weather
stations. Temperature and rainfall statistics have been taken from Murchison weather station while
other climate statistics are from the Institute of Sustainable Agriculture at Tatura.
Table 1-1: Bureau of Meteorology weather station in Murchison
Location
Station Number
Collection Period
Station Location
Murchison (0.8km)
081035
1883-2012
36.62°S, 145.12°E
Tatura (24km)
081049
1942-2012
36.44°S, 145.27°E
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1.1.1 Rainfall
Meteorological records from the Murchison station indicate that monthly rainfall varies between
approximately 33 mm and 60 mm, with highest mean rainfall occurring between May and October.
The annual average rainfall at Murchison is approximately 448.7 mm. The highest mean monthly
rainfall event between 1883 and 2012 recorded at Murchison was 307 mm in March 1950, and the
highest 24hr rainfall event was 105.9 mm in March 1950.
Figure 1-2: Maximum and mean monthly rainfall for Murchison 1883 – 2012 (BOM, 2012a)
Figure 1-3 shows the intensity of rainfall events (mm/hour) based on duration and the Average
Recurrence Interval (ARI) at Murchison. ARI represents a statistical estimate of the average period
between exceedances of a given rainfall total over the various given durations.
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Figure 1-3: 100 year rainfall intensity for Murchison (BOM, 2012c)
1.1.2 Soils
A detailed study of the soils around Murchison is provided in Soils and Land Use in Part of the
Goulburn Valley, Victoria (Skene et al, 1962). A brief summary of this information is provided below.
Soils around Murchison and throughout much of the Goulburn Valley soil survey area are
predominantly Group V.
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Figure 1-4: Map of the Goulburn Valley soil survey 1962
Group V soils range from clays through to clay loams and loams listed in sub-groups A and B (Figure
1-5). Soils in the area are suitable for fodder crops, cereals and annual and perennial pastures.
Figure 1-5: Description of group V soil types from the Goulburn Valley soil survey 1962
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1.1.3 Land Use
Land use statistics are shown below for the Goulburn Broken Shire Catchment of which Murchison is
a part. The Department of Primary Industries (DPI) divides land use into six major zones.
Table 1-2: Land Uses in Goulburn Broken Shire Catchment Management region (DPI, 2012)
Land use
Area (%)
Conservation
environments
and
natural
13%
Production from relatively natural
environments
20%
Production from dryland agriculture
and plantations
51%
Production from irrigated agriculture
and plantations
11%
Intensive uses
4%
Water
2%
Table 1-2 shows land use at the catchment level for the Goulburn Broken Shire which includes
Murchison and its surrounding areas. The majority of land use in the Goulburn Broken Shire is
production from dryland agriculture and plantations (51%). Production from relatively natural
environments (20%), conservation (13%) and production from irrigated agriculture (11%) form the
other major land uses in the region.
The Murchison and District Community Plan 2011 (MCP Steering Committee 2011) recognises the
importance of the natural river environment to the town and recognises the fact that the majority of
current land use in the area is highly dependent on water use which is a possible threat given the
likely scenario of a move to a warmer, drier climate. Water for irrigated agriculture is the largest form
of water consumption in the region. Water use for agriculture in the Goulburn region is shown below.
Table 1-3: Water use in the Goulburn region (ABS, 2012)
Land area
Total area (km )
Area of
agricultural
land
(Hectares)
27,270
1,559,000
2
Water use
Irrigated
area
(Hectares)
Irrigation
volume
applied
(ML)
Other
agricultural
uses (ML)
Total
water use
(ML)
Area
irrigated as
a proportion
of
agricultural
land (%)
281,000
1,144,486
36,542
1,181,028
18
Murchison is is well known for its local produce including cheese, wine and seasonal crops
(Murchison 2012).Major industry sectors in terms of employment for Murchison according to the 2011
ABS Census are listed in Figure 1-6 (ABS 2011). Education (5.9%) is the largest employer in
Murchison followed by dairy cattle farming (4.4%), Sheep, beef cattle and grain farming (3.9%), fruit
and vegetable growing (3.7%) and dairy manufacturing (3.3%). The Murchison District Community
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Plan has identified Tourism and a renewable energy strategy as key drivers of future growth for
Murchison and its surrounding regions (MCP Steering Committee, 2011).
Figure 1-6: Employment by Industry sector in Murchison 2011 (ABS, 2011)
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Appendix B
Solar Power
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1 Technology Overview
1.1 Solar Photovoltaic Systems
Solar photovoltaic (PV) systems utilise the photovoltaic effect to produce electrical current. The
photovoltaic effect is similar to the photoelectric effect and is most pronounced in semi conducting
materials such as silicon. When struck by light from the sun, these materials will generate a direct
current (DC) which can flow through an electric circuit. This current is typically converted to alternating
current (AC) using an inverter.
Figure 1-1: Martifer Solar PV array (left) (Stuart, 2010); Schematic of PV Solar generation
system (right) (Clean Green Energy, 2011)
The primary component of a PV system is the solar cell of which there are 3 main types (Clifton et al,
2010 and Planetary Power, 2009):



Monocrystalline silicon is the most efficient and produces the smallest solar cells, and
therefore the smallest panels but these are also the most expensive.
Polycrystalline (or multi-crystalline) silicon produces the next most efficient type of solar cell
and is the most popular choice as it provides an excellent balance of performance and
economy. The European market has now adopted polycrystalline as the standard.
Amorphous (or thin-film) silicon uses the least amount of silicon and also produces the least
efficient solar cells. However, these cells are less affected by variations in temperature than
the other two types of cell (CEC, 2007).
Efficiency
On average, photovoltaic panels convert sunlight to electric power at an efficiency of just over 15%.
Photovoltaic efficiency and cost-effectiveness is improving constantly with further research and
development in the area. Solar cells utilising low cost materials and manufacturing methods achieve
lower efficiencies (approximately 8-10%) but these can be cost effective compared with high cost
units utilising rare minerals which generate at high efficiencies (up to 40%).
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Maturity
By August 2011, Australia has an estimated 1,031 MW e of installed PV power (around 510,000 solar
PV systems), contributing an estimated 2.3% of total electricity production (see Figure 1-2). Note that
this number has risen to above 2,000 MW e by the end of 2012. More recently, there has been a rapid
deployment of this technology with the amount of installed PV capacity in Australia experiencing a
dramatic 10-fold increase between 2009 and 2011. Feed-in tariffs and the mandatory renewable
energy target designed to assist renewable energy commercialisation in Australia have largely been
responsible for the rapid increase.
Figure 1-2: Installed capacity of Solar PV internationally and in Australia (IEA, 2012)
The majority of Australia’s solar PV installations to date have been at the household level, with
occasional examples of large scale PV solar developments. Part of the reason for this may be that the
current Australian policy environment strongly favours residential offerings above all else, with system
sizes around 2 kW e (Solar Business et al, 2011). However, examples of larger scale installations also
exist with plants ranging in size from 0.24MW e to 1.2MW e (CEC, 2011a). A much larger PV plant that
has received funding under the Solar Flagships Program is the AGL - First Solar project involving a
106 MW e project at Nyngan and a 53 MW e project at Broken Hill. The project is currently in early
stages of development.
The map below shows the current larger scale solar PV plants currently installed in Australia.
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Figure 1-3: Solar PV large scale installations in Australia (CEC, 2012b)
PV Solar Plant Cost
A paradigm shift is occurring at the moment regarding the cost of solar PV. Recent project based in
Australia has shown that the cost of solar PV has continued to decrease in the order of 30% from mid
2010 to Quarter 2, 2012 (BREE, 2012). The rapid change in price has led some renewable energy
commentators to state that the new price of solar PV is at or below that of fossil fuel generation, and
will be a “game-changer” for renewables (CEC, 2010a; McKinsey and Co., 2012).
In terms of cost, a large-scale PV plant, including profit margins for the suppliers, can be built
presently for close to AU$2.80 per watt-DC (or AU$3.30 per watt-AC) (Greentechsolar, 2011). The
price of modules ranges from AU$0.71-AU$2.5 per watt depending on the type of cells mentioned
above (Earth Systems, 2012). With the rapid decreasing cost of solar PV panels, costs reported even
6 months ago could now be out of date. As an example, the capital investment for the planned 30
MW solar PV project in Kerang, northern Victoria is approximately $38 billion, which equates to
approximately $1.27 per watt.
Between 2000 and 2008, module prices fell at an average annual rate of 2% while demand grew at an
average of 51% per annum. However, in 2008 global demand growth was roughly flat while the
module production capacity increased significantly. This placed significant downward pressure on
costs as the balance of supply and demand was changed. In terms of supply, solar power products
are readily available and supply at present is very able to meet demand (CEC, 2010a).This is good
news for large scale solar PV projects lowering the commercial risk of product supply.
A recent report by McKinsey & Co. provides good insight for the recent fall in prices. This report
argues that armed with inexpensive labour and equipment, Chinese players triggered a race to
expand capacity in manufacturing that drove PV prices down by 40% per year in the last few years
(McKinsey and Co., 2012). According to this report prices fell from more than $4 per Wp in 2008 to
about $1 per Wp in January 2012, and the balance-of-system (BOS) costs declined by about 16% per
year in this period, from about $4 per Wp in 2008 to approximately $2 per Wp in 2012 (these are more
difficult to track, in part because BOS costs vary more than module costs) (McKinsey and Co., 2012).
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Figure 1-4: Australian PV module prices in current AUD (Australian PV Association, 2011)
It is projected that costs will continue to fall into the future. The figure below shows how the capital
cost for a PV system is expected to decrease out to 2020 as the technology continues to ride the cost
curve lower as more installed capacity is achieved.
Figure 1-5: PV System Capital Cost (Renewable Energy Index, 2010)
According to IEA (International Energy Agency), the Levelised Cost of Energy (calculated from capital
and operating cost data at a common renewable resource level, exclusive of subsidies or carbon
costs) is around AU$0.26/kWhe. In 2010, the LCOE ranges from AU$0.27 and AU$0.45 per kilowatt
hour and the capital costs were reported at AU$3.5 and AU$5.2/W. Solar PV systems currently give
typical paybacks of 40-80 years (Baziliana, 2012; Danowitz, 2010; Madden, 2010) without subsidies
such as a FIT. However, as noted above, the rapid change in cost has reduced these figures further,
lowering the LCOE and payback periods significantly even over the past two years. According to the
Australian Energy Technology Assessment report for 2012, the LCOE of solar PV in 2012 ranged
from $0.212 / kWh – $0.344 / kWh and capital costs ranged from $3.8 / W – 5.4 / W sent out
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depending on the type of solar PV system (BREE, 2012). Current costs are reflected in the modelling
outlined below.
In line with forecast increases in efficiency and decreases in system cost, the levelised cost of energy
generated from PV systems is expected to continue decreasing out to 2020 as seen in Figure 1-7
below (Renewable Energy Index, 2010).
Figure 1-6: PV Levelised cost of energy (Renewable Energy Index, 2010)
Figure 1-7: Balance of System Cost and Levelised Cost of Energy forecast (McKinsey and Co.,
2012)
McKinsey & Co also predict decreasing energy costs for PV installation and an associated decrease
in the levelised cost of energy. They further explain where they believe the cost savings will be
derived from as shown in Figure 1-7. The upfront cost of capital is often the most crucial factor
determining returns on solar projects and that in order to succeed in downstream markets, companies
need strong capabilities in project finance – indeed, the entities that structure solar investments often
achieve better returns than the companies that manufacture or install modules (McKinsey and Co.,
2012). McKinsey predict that as the solar investment pool swells, financial institutions, professional
investors, and asset managers are likely to be drawn to the sector, since solar projects that are
capital-heavy up front but rely on stable contracts will become attractive in comparison with traditional
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financial products. New types of downstream developers and investment products will emerge to
aggregate low-cost equity and debt and to structure financial products with risk-return profiles aligned
with the specific needs of institutional investors (McKinsey and Co., 2012).
Thus it seems likely that investments in solar PV will become achievable either now or in the very
near future, especially as more sophisticated investment products emerge to match the technology
requirements and financial risk profile.
1.2 Concentrating Solar Thermal
Solar thermal power plants produce electric power by converting the sun’s energy into high
temperature heat using various mirror or lens configurations to concentrate solar radiation into a small
area (Stoddard et al, 2006).The heat generated is then transported by a working fluid such as steam
or thermal oil and is subsequently converted to electricity using a turbine or engine.
Figure 1-8:Schematic of Typical Concentrating Solar Plant (NREL, 2001)
Solar thermal systems convert solar energy to electricity with an overall efficiency of between about
8% and 25% (DLR, 2009). The overall plant efficiency will depend on both the solar technology and
the type of thermodynamic cycle used to convert heat to electricity.
Concentrating solar thermal (CST) plants utilise only direct solar radiation, whereas photovoltaic
panels utilise both direct and diffuse radiation. This means that on a very cloudy day energy
production from a solar thermal plant will be zero, while from a PV plant it will only be very low.
Solar thermal power plants are fundamentally different to PV systems in that they create heat as their
primary energy source, not electricity. As a result, this heat energy can be "stored" and released as
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needed. This storage capability is a major advantage of concentrating solar power. For instance,
molten salt storage tanks are now in use as a means to retain a high temperature thermal energy over
time, including at night.
Compared to PV installations, CST also requires some additional infrastructure: in particular
generator systems to convert heat to electricity, water supply for mirror cleaning and system cooling,
and storage systems for maintaining system temperatures at night or during low solar irradiation
periods, if continuous operation is a necessity. A natural gas supply may be necessary if continuous
process is required and thermal storage from a resource such as molten salt is not available. Hence,
natural gas may be a necessary connection requirement and ongoing cost impact for consideration.
Currently there is only a very small number of working solar thermal power systems in Australia. The
largest is the Liddell Power station, which uses Compact Linear Fresnel Reflector (CLFR) solar
thermal technology, and is a demonstration plant of around 1.5 MW e although a larger system is
being planned on this site. The Commonwealth Scientific and Industrial Research Organisation
(CSIRO) is also constructing a 0.5 MW e solar thermal power station in Mayfield (CEC, 2009).
Figure 1-9: Australia Concentrating Solar Thermal plants (CEC, 2012b)
Worldwide the solar thermal power industry is growing rapidly, with about 1.2 gigawatts (GW e)
of concentrating solar power (CSP) plants online as of mid-2011.
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Figure 1-10: World Installed Concentrating Solar Thermal (Earth Policy Institute, 2010)
Plant sizes usually range from 1 MW e to 470 MW e. However, most of the smaller scale plants below
20 MW e have been built as research facilities or to demonstrate specific technologies potential.
Figure 1-11: Estimated LCOE dependence on system size (normalised to a 100 MW e system
with 5 hours’ storage) (IT Power, 2012)
As for solar PV, the cost of CST and its related LCOE is forecast to decrease in the future, with an
overall reduction of LCOE relative to 2012 of 40 to 50% by 2025 (IT Power, 2012) (see Error!
Reference source not found.).
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Figure 1-12: Estimated CSP cost / LCOE reductions (Reproduced from AT Kearney, 2010)(IT
Power, 2012)
From Error! Reference source not found., CST technology appears to have significant capacity for
cost efficiencies in the near future, and as installed capacity increases worldwide the LCOE will
reduce to a point where it becomes economically viable compared to traditional generation
technologies. System nameplate capacity will be a key factor in determining the economic viability of
a specific project - from Error! Reference source not found. and Error! Reference source not
found., projects below 20 MW e have significantly increased LCOE values and operate more for
demonstration or R&D purposes. Below 20 MW e currently would be unlikely to be economic. No
modelling analysis for this technology is carried out for this report considering the low maturity and
high cost associated with this technology at the small scale.
1.3 Concentrating Photovoltaic (CPV)
By concentrating light onto PV cells the system achieves a higher efficiency per unit area of PV cell.
The PV cells in a Concentrating Photovoltaic (CPV) system are built into concentrating collectors that
use a lens or mirrors to focus the sunlight onto the cells. CPV plants utilise the same solar collectors
as described above for concentrating solar thermal plants.
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Figure 1-13: Concentrating PV Dishes (top); Power Tower in Bridgwater VIC (bottom left);
Concentrating PV System (bottom right) (Solar Systems, 2011a; US DOE, 2008; Courtice, 2012)
The challenge of CPV is that increased incident sunlight also produces more heat, which requires a
heat sink or active cooling to maintain cell efficiency. By utilising the heat generated by the solar cells
in addition to the electricity generated by the photoelectric effect, it is possible to construct integrated
combined heat and power solar plants, or boost the amount of electricity produced by the photovoltaic
panels by conversion of the heat through a Rankine cycle.
The advantage of CPV when compared with standard or flat plate PV is the substitution of large area,
high cost semiconductor PV cells by less expensive lenses or mirrors, capable of concentrating
sunlight on a much smaller area, high efficiency PV cell (Bosetti et al, 2012).
CPV technology, while less well known than standard flat plate PV panels has been used in a number
of larger scale solar power projects. For example, a number of such plants are operating in America
with capacities ranging from 25 to 720 kW e. In Australia the company Solar Systems (now Silex Solar)
have installed CPV dish systems in remote locations in Queensland, South Australia and the Northern
Territory (Solar Systems, 2011b). In addition, Solar Systems have a test facility in Bridgwater in
central Victoria, where they have built a ‘power tower’ heliostat-based (CPV) system as well as 16
concentrating dish structures (Solar Systems, 2008). Silex Solar also have a contract for a 150MW e
concentrated solar PV plant in Mildura, Victoria.
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2 Environmental Impact
The lifecycle assessment (LCA) greenhouse gas (GHG) payback period refers to the length of time
required for a solar farm to generate sufficient electricity to offset the GHG emissions associated with
the manufacture, construction, operation and decommissioning of the project, versus the savings in
the displacement of fossil fuel electricity GHG emissions (GL Garrad Hassan, 2011).
The payback period also depends on the lifecycle emissions of the various technologies. For solar
PV, CO2 emissions usually include mining of the materials, production of the cells, transport and on
site setup, and maintenance. These factors are estimated at between 19 tCO2e/GWhe to 59
tCO2e/GWhe. For solar CST, the life cycle emissions vary between 8.5 and 11.3 tCO 2e/GWhe, which
include materials, transport, construction and maintenance. (Wright et al, 2010)
For solar PV, the LCA GHG savings varies depending upon the location of installation, which
determines the solar resource and the fossil fuel mix for the offset electricity. The generally accepted
method of calculating emissions abatement is by using the state pool coefficient. According to a report
by the Solar PV Industry the annual GHG abated through PV electricity production in Victoria is 1,458
tCO2e per MW e installed of PV. (Solar Business Services et al, 2011)
As there is limited data regarding GHG savings for CSP in Victoria, the Victorian electricity emission
factor of 1.23 kgCO2e/kWhe has been used. (DCCEE, 2011; GL Garrad Hassan, 2011)
Solar PV
Table 2-1: Greenhouse Gas analysis of solar PV
Parameter
Value
Unit
Ref.
Best Case Scenario
19
tCO2e/GWhe
Wright et al, 2010
0.87
tCO2e/MWhe
Wright et al, 2010
0.44
Years
Worst Case Scenario
59
tCO2e/GWhe
Wright et al, 2010
0.87
tCO2e/MWhe
Wright et al, 2010
1.36
Years
*Derived from 1,458 tCO2e per MWe installed
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CST
Table 2-2: Greenhouse Gas analysis of CST
Parameter
Value
Unit
Ref.
Best Case Scenario
Life cycle solar CST CO2 emissions
per unit of energy production
8.5
tCO2e/GWhe
Wright et al, 2010
Greenhouse gas abatement factor
1.23
tCO2e/MWhe
Wright et al, 2010
0.14
Years
Life cycle solar CST CO2 emissions
per unit of energy production
11.3
tCO2e/GWhe
Wright et al, 2010
Greenhouse gas abatement factor
1.23
tCO2e/MWhe
Wright et al, 2010
0.18
Years
Worst Case Scenario
Emissions payback period for solar PV and CST technologies range from 0.44 to 1.36 years and 0.14
to 0.18 years respectively.
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3 Local Solar Resource
To estimate the electricity that can be generated by solar installations in a given region the primary
input is the amount of solar radiation available. Solar energy can be considered as consisting of two
components: direct solar energy arriving at the earth with the sun’s beam and diffuse solar energy,
including scattered light (BOM, 2012b). Some technologies such as PV cells use both types of solar
energy (diffuse and direct) to create electricity, while concentrating systems that collect solar energy
and focus onto a small area only use direct solar energy.
Concentrating systems also use tracking systems to ensure the direct solar energy is directed to the
right area. The tracking systems mean that normal incidence solar energy can be utilised to the full
capacity rather than fixed arrays which do not track and hence do not capture and utilise all of the
available sun radiation energy (such as fixed solar PV arrays).
Global Radiation = Diffuse + Direct
Concentrating systems only use direct radiation
Figure 3-1: Solar energy components and concentrating system (INFORSE, 2012; Brighthub,
2012)
2
On average Murchison receives about 17.8 MJ/m per day of solar energy, which translates to about
2
1,809 kWh/m annually. This is similar to regions of Spain and Portugal where large scale solar power
developments have been commissioned. Based purely on the solar hotspots of the world and
Australia, diffuse and direct solar resources appear to be a potential renewable energy resource
suitable for Murchison.
The figure below shows how solar energy reaching the ground varies throughout the year in
Murchison. Note that the average solar energy reaching the ground in winter is only about half that of
summer. This reduction in available solar energy significantly affects the generation capacity of a
solar plant month to month.
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Figure 3-2: Murchison Global Solar Exposure by Month and Annual Average (BOM, 2012b)
Given the intermittent and variable nature of solar energy, electricity generated from solar power must
either be stored for use when the sun is not shining or supplemented with another energy source.
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Appendix C
Geothermal Energy
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1 Geothermal Technology Overview
Geothermal energy has been utilised for electric power generation since 1904 (Dickson et al, 2004).
By 2010, worldwide there was an estimated 10,715MW e of installed geothermal power systems
(Bertani, 2010) (this equates to about one-third of Australia’s current total generation capacity). In
addition, there was an estimated 25,800MW th of geothermal energy used directly for a variety of
3
heating purposes (Lund et al, 2010) (excludes geothermal heat pumps ). The sector is still
experiencing “double digit” growth in many countries resulting from a combination of environmental
(low emissions technology) and economic (increasing fossil energy prices) drivers (Bertani, 2010).
In Australia, the only geothermal power station operates at Birdsville Queensland, generating around
80 kW e of electricity. This small-scale plant utilises an unconventional HSA resource to drive an
Organic Rankine Cycle (ORC) power generator and has been operating since 1992 (Ergon Energy,
2006). Direct use of geothermal energy in Australia amounts to an estimated 9.3 MW th (mostly for
bathing and swimming, and some fish-farms) (Ergon Energy, 2006).
Worldwide, geothermal power plants typically operate at scales within the range 1 to 100 MW e
(Bertani, 2010). Conversion technology for generating electricity from the heat is based on
conventional thermal power cycles, (i.e. similar to coal or biomass-fired power stations) and is mature
technology. Due to the nature of the resource, geothermal power plant can achieve high availability
factors (close to 100%), typically similar to other thermal power plant of comparable size. Availability
factor indicates how much of the time the plant is available to meet demand.
The major project development risk thus relates to the geothermal resource itself and the sub-surface
engineering required to exploit it.
This is particularly important in Australia, where only
unconventional geothermal resources exist.
There are relatively few geothermal companies in Australia with advanced geothermal development
programs. Frontrunners include Geodynamics Ltd, Petratherm Ltd, Green Rock Energy Ltd,
Greenearth Energy Ltd, and Panax Geothermal Ltd. Greenearth Energy is of particular interest as the
company is exploring a geothermal resource in the Geelong/Anglesea area of Victoria, with a view to
implementing a 12 MW e pilot plant, should the proposed drilling program achieve successful “Proof-ofResource”. The project has been awarded State Government funding, however it is unclear what
degree of progress has been achieved.
3
Note: It is important to distinguish between the direct use of geothermal energy to provide heat and generate power (which is
covered by the scope of this review) and ground-source heat pumps which use a buried heat exchanger (at a shallow depth) to
provide a heat source or sink for the operation of heat pumps either for heating or air conditioning, depending on the time of
year. Whilst ground source heat pumps may offer an efficient alternative to other heating and cooling technologies in the right
circumstances, and are often referred to as “geothermal”, they are not within the scope of this review.
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2 Technology Costs and Economics
Major factors affecting geothermal power cost are the resource characteristics (depth, temperature
and well productivity), project infrastructure, environmental compliance, and economic factors such as
the scale of development and project financing costs.
For a geothermal resource to be exploited in a cost-effective way, it must have a sufficient source
temperature, able to sustain a sufficient fluid flow, and be at an economically accessible depth. The
authors were unable to identify any consistent numerical values for these metrics against which to
reliably benchmark a given geothermal resource for electric power generation, (particularly
o
unconventional resources), however source temperatures of at least 150 C appear to represent one
possible threshold. Some useful guidance on the economics of small-scale (<5MW e) conventional
geothermal resources was provided in (Enting et al, 1994), with indicative capital cost multipliers
provided as a function of plant output, reservoir temperature and well depth for systems up to 1MW e.
The cost of drilling a geothermal well is typically the major cost in the development of the resource,
accounting for 42 to 95% of total power plant costs (Tester et al, 1994). Well costs increase nonlinearly with depth, and are typically 2 to 5 times greater than the cost of an oil or gas well drilled to a
comparable depth (Augustine et al, 2006).
Levelised costs for geothermal electricity are in the range $45 to $80 per MWh e for conventional
resources (USA) (IEA, 2008; REPP, 2003), and projected to be $80 to $140 per MWh e for hot
sedimentary aquifers and $100 to $200 per MWhe for hot fractured rocks (Kallis, 2012). Capital costs
may range from 1.2 to 5.5 million dollars per MW e of installed capacity (IEA, 2008).
Geothermal projects involve a relatively high level of commercial risk due to the uncertainties around
identifying and developing the geothermal reservoir that can sustain long-term fluid and heat flow. An
average 20% failure rate has been reported (Glacier Partners, 2009) for conventional well
development. To make geothermal projects more attractive to private investors, some countries with
geothermal resources have developed policies to underwrite these risks (IEA, 2008).
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Appendix D
Bioenergy
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1 Introduction
1.1 What is Biomass?
Biomass is organic matter originally derived from plants, produced through the process of photosynthesis,
and which is not fossilised (such as coal). Biomass can act as a store of chemical energy to provide heat,
electricity and transportation fuels, or as a chemical feedstock for bio-based product. The chemical
energy contained in the biomass is derived from solar energy using the process of photosynthesis.
(Stucley et al, 2008)
Biomass is regarded as a renewable resource, and includes forest and mill residues, agricultural crops
and wastes, wood and wood wastes, animal wastes, livestock operation residues, aquatic plants, fastgrowing trees and plants, and municipal and industrial wastes (CEC, 2008).
1.2 What is Bioenergy?
Bioenergy is a form of renewable energy produced from organic matter that converts the complex
carbohydrates in organic matter to energy such as electricity, bio-liquids and/or heat, while emitting very
low or no net GHGs (CEC, 2008; CHAF, 2009). In practical terms, a form of technology (for example a
combustion process) is applied to the biomass to convert the useful stored chemical energy into a more
usable form such as electricity, bio-oils and/or thermal energy.
Some of the benefits associated with bioenergy include (CEC, 2008; CHAF, 2009):







Economic: the diversion of waste from landfill to a bioenergy solution can have a saved cost,
the reduced use of fossil fuels especially in remote locations can save costs, income generation
from electricity generation and thermal heat
Environmental: there are significant environmental benefits associated with bioenergy. Most
notable is the reduction in GHG emissions compared to fossil fuel generation. In some
circumstances a Life Cycle Assessment (LCA) can show a net carbon abatement, especially from
pyrolysis and the creation of biochar as a carbon sequestration process. The renewable nature
of biomass supports the sustainability of bioenergy.
Social: construction and operating a bioenergy plant creates employment for the local
community. The ongoing operation of the plant creates ongoing employment.
Thermal value-add: bioenergy is unique as it can supply both heat and power. The thermal
generation ability of bioenergy makes it suitable for thermal heat needs, especially for
industrial requirements.
Connection Infrastructure: a biomass technology can be easily located close to suitable grid
connection points. This keeps grid connection costs low.
Controllable and continuous supply of power: the power generated from wind and solar is
variable and intermittent in nature. Biomass on the other hand is a controllable resource, and
as required can be a continuous supply of known quantity (assuming suitable biomass supply).
Enhances energy security: the renewable nature of biomass and the plentiful resources of
Australia support a secure bioenergy generation potential
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EARTH SYSTEMS


Energy cropping with oil mallee: the energy cropping trials in WA are in part being conducted to
reduce salinity in the growth region.
Under an energy cropping scenario this could provide diversification of farming incomes.
1.3 Global Bioenergy Status
World
In 2008, biomass provided about 10% (50.3 EJ/yr) of the global primary energy supply (Edenhofer et al,
2012). The majority of the world’s bioenergy is used directly for heat production through the burning of
biomass with only 4% being used for electricity generation. Internationally, bioenergy provides an
increasing share of electricity and heat with an estimated 62 GW in operation by the end of 2010. Of the
biomass resources available globally, fuel wood dominated at 67% of total energy use.
Figure 1-1: Shares of energy sources in total global primary energy supply in 2008 (492 EJ)
(Edenhofer et al, 2012)
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Figure 1-2: Shares of global primary biomass sources for energy in 2008 (50.3EJ) (Edenhofer et al,
2012)
Regarding electricity generation, bioenergy plays a significant role in the renewable energy mix.
Bioenergy generated approximately 1.1% of total global electricity generation, or 228 TWh.
Figure 1-3: Share of primary energy sources in world electricity generation in 2008 (Edenhofer,
2012)
The main growth markets for power generation from bioenergy are the United States of America (US),
European Union (EU) (led by Germany, Sweden and the United Kingdom), Brazil, China and Japan. In
2010, the US generated 48 terawatt-hours (TWh) of bioelectricity while the EU generated 87.4 TWh. As a
percentage of total electricity generation, Finland generates approximately 12%, while in Australia it was
~0.9%.
Figure 1-4: Proportions of Energy Generated from Biomass for Selected Nations (CEC, 2008)
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In China there is a rapid deployment of bioenergy occurring. The country hit its 2010 target of 5.5GW
generating potential two years early than planned with bioenergy, and plans to generate 30GW by 2020.
Thermal conversion of biomass to energy is arguably the first “technology” to be developed by humans.
Thermal technology for bioenergy can be broadly classified into three sub-groups: gasification,
combustion, and pyrolysis.
Thermal processes for electricity generation from a fuel source (including biomass sources) also offer the
possibility of utilising both the heat and electrical outputs from the process. This is termed “cogeneration”,
or Combined Heat and Power (CHP) production, and is more formally defined as “the simultaneous
production of two energy sources; electrical (or mechanical) and thermal, from the same system”. In a
further embellishment, “tri-generation”, or Combined Heat, Cooling and Power (CHCP) production, heat
produced from the cogeneration plant is additionally used to produce cooling, via an absorption
refrigeration cycle. Tri-generation is seen as advantageous in circumstances where refrigeration has a
higher value than electricity (for example, where electricity is consumed in order to produce refrigeration).
As a good starting reference guide for thermal bioenergy plant configurations, and representative
biomass requirements, the table below shows some basic performance parameters.
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EARTH SYSTEMS
Figure 1-5: Typical scales of various thermochemical conversion technologies (Stucley et al,
2008)
The biological process known as anaerobic digestion also represents a commercially mature mechanism
for deriving useful high-grade energy from wet (putrescible) biomass materials. Anaerobic digestion can
be applied to heat and/or power production via the combustion of the fuel gases produced from bacteria
decomposing the biomass.
1.4.1 Gasification
Gasification plants are relatively low cost, simple to install and operate, and are of most benefit where the
biomass feedstock properties (especially shape, size and reactivity) can be carefully controlled to suit the
process and a high quality gas suitable for engine or gas turbine use can be reliably generated.
The basic process involves the thermal decomposition of the biomass into a weak fuel gas known as
“producer gas” or “woodgas” in a reactor called the “gasifier” or “gas producer”. This is a high
temperature process and a variety of system configurations have been developed to enable this
conversion to be undertaken on the majority of solid (and some liquid) fuel feed stocks.
The fuel gas is then fed into a conventional piston engine, or in some cases, a gas turbine. The engine or
turbine then drives a generator to produce electrical output. Heat is available as a by-product of both the
gas making step (i.e. from the gasifier) as well as from the engine (exhaust or water jacket heat).
Exhaust Gases
Fuel
Generator
Engine /
Turbine
Air
Gasifier
G
Producer
Gas
Heat
(by-product)
Electricity
Ash
and carbon
Figure 1-6: Schematic representation of a gasification process
(adapted from NAPE, 2008)
The integration of wood gasifiers with gas engines is not necessarily trouble-free. In most cases, gasifiers
coupled with gas engines are based on the downdraft principle because of the relatively low tar
production (BTG, 2005). Most technical problems with such plant can be traced to feedstock issues.
Gasifiers can also be used simply to produce a crude gas which is then burned in a combustion chamber,
in a process also known as “two-stage combustion”. In this instance, gas quality can be lower as it is not
passing through complex machinery. A thermodynamic cycle (such as will be discussed under
“combustion” is then used to produce the electrical output.
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EARTH SYSTEMS
Feedstock Requirements
The feedstock size for gasifiers varies depending on the type of gasifier. The feedstock size for downdraft
gasifiers is usually around 20-100 mm. Large-scale plant based on fluid bed gasifier technology take in
chips, and entrained flow gasifiers usually require feedstock size to be less than 1 mm (BTG, 2005).
Table 1-1: Fuel requirements versus gasifier design
Gasifier type
Downdraft
Updraft
Fluid bed
Entrained flow
Size (mm)
20-100
5-100
10-100
<1
Moisture content (% w.b.)
<15-20
<50
<40
<15
<5
<15
<20
<20
Uniform
Almost uniform
Uniform
Uniform
3
>500
>400
>100
>400
o
>1250
>1000
>1000
>1250
Ash content (% db)
Physical structure
Bulk density (kg/m )
Ash melting point ( C)
One of the major constraints in employing gasification processes for this project is the shape, size and
form of the feedstock to be used, as most gasifier types require almost uniform physical structure and
small size of feedstock. It is important to note that the more commercially mature fixed bed gasifiers will
in general not operate successfully on ground or shredded feedstock.
1.4.2 Combustion
Combustion involves a sequence of chemical reactions between a fuel and an oxidant (usually air) to
produce heat. The main technical advantage of a combustion process in the biomass power-plant context
is that it is generally more fuel-flexible than a gasification process.
There are many types of processes that are driven by the heat from a combustion system in order to
generate electricity. Processes reviewed for suitability to this project include Steam Rankine Cycle,
Organic Rankine Cycle, and Kalina Cycle.
This section considers first the combustion technology and then the power cycle needed for converting
the heat energy to electrical output.
Furnaces and Boilers Suitable for Ground Biomass
Forestry residues and by-products, as well as demolition wood waste and agricultural wastes, are all
forms of biomass that have been successfully fired in systems for heat and/or power generation. Woodfired systems operating either on chipped, ground or shredded wood are common in many European
countries.
The standard biomass boiler site arrangement normally includes a 3 to 4 week stockpile of appropriately
sized fuel and a belt conveyor system to deliver this to a “walking-floor” fuel bunker. The walking floor
consists of steel elements which periodically move to transfer the biomass into the feed system of the
furnace.
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EARTH SYSTEMS
Furnaces normally range from 0.3 to 30 MW th in size and are enclosed in a building about 4 or 5 storeys
high. Via a system of primary and secondary air feed points and a stepped-grate sloping furnace floor
with moving elements to allow the biomass to progress steadily downwards as it burns, the furnaces
achieve efficient and very clean combustion and can tolerate a range of feedstock sizes and moisture
contents.
The flue gases produced by the furnace are normally scrubbed by cyclone and electrostatic precipitators
to remove ash and particulates. Ash is collected both from the flue gas (“fly ash”) and from the bottom of
the furnace (“bottom ash”).There are no other key waste products from the process.
Heat from the furnace is normally used to raise steam (for industrial uses), heat water (for industrial or
district heat uses) or heat a thermal oil heat transfer fluid (in the case in which an Organic Rankine Cycle
system is employed for power generation).
Steam Rankine Cycle
The steam Rankine cycle is the most commonly found thermodynamic cycle in power plants, especially at
the large scale. Heat sources for the cycle are usually provided by coal, natural gas, or oil combustion, or
by heat release from nuclear fission. The simplified Rankine cycle is illustrated in the figure below.
Figure 1-7: Simple steam Rankine cycle (adapted from Northwestern University, 2009)
The basic cycle involves 4 stages:




Stage 1 (S1): Water is pumped at high pressure to the boiler for heating.
Stage 2 (S2): The boiler turns the water to steam and it enters the turbine at high temperature and
pressure where it expands as it passes through the turbine causing the turbine to spin (thus
providing mechanical energy to drive the generator for electricity production).
Stage 3 (S3): The low pressure steam exiting the turbine then enters the condenser where it is
cooled and turns back to liquid water.
Stage 4 (S4): Exiting the condenser, the water returns to the pump to repeat the cycle.
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EARTH SYSTEMS
Organic Rankine Cycle
An Organic Rankine Cycle (ORC) process is similar to the conventional Rankine process except that an
organic working fluid with favourable thermodynamic properties is used in an ORC instead of water. The
two most common fluids used in commercial systems are iso-pentane and silicone oil. The main
advantage of choosing an ORC is that for a power plant with lower than 5 MW e output, it can have
significantly lower operating costs. As it works at much lower pressures and temperatures (typically at or
o
below 10 atmospheres and 300 C) than a steam plant, it is not governed by the same level of stringent
regulations for operation and maintenance requirements. When optimised for electricity generation,
efficiencies are typically up to 24% (CEC, 2010b).
Figure 1-8: An ORC trigeneration process with wood as feedstock (adapted from Stadtwärme
Lienz, 2009)
In a biomass-fired ORC system, a thermal oil is used as the heat carrier to transfer the heat from the
combustion system to the ORC working fluid. Advantages of using thermal oil as the transfer medium
include (Duvia et al, 2002):

Low boiler pressure;

Large inertia and insensitivity to load changes;

Simple and safe operation and control; and

The adopted temperature (~300 C) for the hot side ensures a very long life of the oil.
o
Biomass-fired ORC systems are in relatively widespread use in a number of European countries and are
considered to be technically and commercially mature technology.
156
EARTH SYSTEMS
A good example of an ORC power plant is the “Stadtwärme Lienz” Project in Austria (Stadtwärme Lienz,
2009). The plant consists of an open-air storage area for timber and sawmill by-products, a covered fuel
store, a thermal solar collector, a timber chipping machine with automatic fuel feed and the two power
plants, Lienz I and Lienz II.
The solar thermal collector captures the heat from the sun for additional heat input. Due to the high
number of hours of sunshine in Lienz, some 250 MWhe p.a. of heat can be fed into the heating network.
Table 1-2: Technical data of Lienz I and Lienz II
Nominal Capacities
Lienz I
Lienz II
Electric capacity
1 MWe
1.5 MWe
Thermal capacity (hot water)
7 MWth
-
Thermal capacity (thermal oil)
6 MWth
8.7 MWth
District heating network
40.5 km
9.5 km
Since the cycle of the ORC process is closed and thus virtually no losses of the working medium occur,
the operating costs are low. Only moderate consumption-based costs (electricity, lubricants) and
maintenance costs are incurred. The usual lifetime of ORC units is greater than twenty years, as has
been demonstrated by geothermal applications. The silicone oil used as working medium has the same
lifetime as the ORC since it does not undergo any appreciable ageing (Vos et al, 2005).
Kalina Cycle
Another thermodynamic cycle is the Kalina cycle which converts thermal energy to mechanical power.
This cycle is best suited for use with thermal sources of moderately low temperature, especially from
geothermal fluids. The Kalina cycle has been applied in geothermal power plants because the phase
change from liquid to gas is not at a constant temperature and the temperature of hot fluid is often below
o
100 C. This is due to the characteristics of the mixture of working fluids (usually ammonia and water) that
have varying boiling and dew points throughout the process.
The Kalina cycle is similar to the Rankine cycle except that it heats two fluids, (ammonia (NH3) and
water), instead of one.
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EARTH SYSTEMS
Electricity
G
Generator
Turbine
S1
S2
Distiller Subsystem
S3
Heater
Condenser
S6
S5
S4
Mixing
point
Pump
Figure 1-9: Simple Kalina cycle
The characteristics of the Kalina cycle include (Renz, 2006):

Kalina cycle plants can have higher efficiencies than ORC processes, especially where the total
temperature difference across the process is small;

The working fluid is usually a mixture of ammonia (NH3) and water (H2O); and

The same working fluid may cover a wide range of heat source temperatures (variable temperature
boiling permits the working fluid to maintain a temperature closer to that of the hot combustion gases
in the boiler), i.e. optimisation may be achieved by switching concentration.
The Kalina cycle is less commercially mature than steam Rankine or organic Rankine (ORC) cycles,
however it has particular advantages in lower temperature applications. Examples of Kalina Cycle plants
in operation are as follows (Power Engineering, 2002):

The first commercial Kalina Cycle plant in operation was the Sumitomo Power Plant in Kashima
o
Japan using 98 C hot water at 1,300 tonnes/hr as its heat source. The power plant is able to produce
3.1 MW enet electricity; and

In Husavik, Iceland, a distributed generation plant based on the Kalina Cycle came on-line in July
o
2000. Using a geothermal brine flow at 120 C as the heat source, the plant produces around 1.8
MW e net electrical output.
1.4.3 Pyrolysis
Pyrolysis is an emerging technological area in relation to biomass and in simple terms consists of the
controlled heating of the feedstock in a low or zero-oxygen environment such that all the volatile matter is
driven out of the material, leaving behind a solid residue (char) and producing a combination of energyrich gases and liquids.
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Pyrolysis is not usually considered first and foremost as an energy production process, but is more often
applied where the physical products (either the char or the volatile gases/liquids) are the desirable
products. Historically, pyrolysis processes have been used as a first-stage in the production of synthetic
liquid fuels (the crude liquids then being subject to an extensive series of further processing steps) from
coal or biomass, and more recently the approach has been getting attention as a means of producing
“biochar” – a form of biomass-derived charcoal for use in soil amendment.
It is generally accepted that biochar is a highly stable form of carbon and as such has the potential to
form an effective C sink, therefore sequestering atmospheric CO 2. Current analyses suggest that there is
global potential for annual sequestration of atmospheric CO 2 at the billion-tonne scale per annum within
30 years.
Pyrolysis is the technology pathway for the generation of biochar. During pyrolysis the majority of energy
embodied in feedstock (about 70%) is converted into combustible syngas, but with the liberation of only
half of the feedstock carbon. This is because energy rich but less carbonaceous functional groups are
liberated first (Sohi et al, 2009). Pyrolysis is a true win-win, in that the majority of the energy of the
biomass feedstock is liberated for heat and/or electricity generation, while leaving the fixed carbon behind
in the biochar. This creates a unique environmental advantage of carbon drawdown.
Figure 1-10: the production of the solid fraction biochar from a slow pyrolysis process can result
in a net removal of carbon from the atmosphere (Sohi et al, 2009)
Pyrolysis processes for energy production are not commercially mature, but may offer a future pathway
for the production of heat, power and potentially other high-value chemical products as well as liquid
fuels.
1.4.4 Anaerobic Digestion
The anaerobic digestion process, carried out in the absence of oxygen, involves the use of
microorganisms for the conversion of biodegradable biomass material into energy, in the form of methane
gas and a stable humus material. Anaerobic digestion can occur under control conditions in specially
designed vessels (reactors), semi-control conditions such as in a landfill, or under uncontrolled conditions
as it does in the environment. The methane-rich gas produced in the process may then be scrubbed to
remove minor contaminants and passed to an internal combustion engine to generate motive or electrical
power.
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EARTH SYSTEMS
Anaerobic digestion requires wet feed stocks and is thus best applied to wet wastes, e.g. food wastes,
manures and other putrescible matter. The process is often considered more for its benefit as waste
management system, with the energy in the gas stream being an added benefit. Most commonly,
digesters are found at the larger wastewater treatment plants and some intensive animal farming
operations where large quantities of manure are produced. Landfill gas is also produced via anaerobic
digestion processes occurring within the landfill itself.
1.5 Comparative Technology Costs and Maturity
A good summary comparing the ranges of expected costs for different forms of generation including
bioenergy technologies, is provided in the following two figures. The broad range of LCOE provided for
biomass electricity reflects the variety of technology and feedstock types that may be employed, as well
as the broad range of scales on which bioenergy can be applied.
Figure 1-11: Range in recent LCOE for commercially available renewable energy technologies in
comparison to recent non-renewable energy costs. Technology subcategories and discount rates
were aggregated (Edenhofer, 2012)
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EARTH SYSTEMS
Figure 1-12: Typical recent bioenergy LCOE at a 7% discount rate, calculated over a year of
feedstock costs, which differ between technologies. These costs do not include interest, taxes,
depreciation and amortization (Edenhofer, 2012)
The IPCC has reviewed recently renewable energy opportunities internationally, and the figure below
provides a recent assessment of the level of technical maturity of a variety of bioenergy processes. The
IPCC report shows that combustion processes as generally more established than gasification. Biogas
systems are also commercially mature, although secondary gas upgrading schemes are not so well
established.
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EARTH SYSTEMS
Figure 1-13: Technology maturity states of bioenergy: thermochemical (orange), and biochemical
(blue), and for heat and power (Edenhofer, 2012)
Another recent review of the status of various bioenergy technologies by the International Renewable
Energy Agency (IRENA) found that combustion technologies were also regarded as a mature
commercialised technology. Gasification and pyrolysis were regarded as deployed, but not as a mature
technology (IRENA, 2012).
Figure 1-14: Biomass power generation technology maturity status (IRENA, 2012)
162

Renewable Murchison Preliminary Feasibility Report May 2013

Transcription

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