Future Electricity Infrastructure Requirements of South Australia's
Resources Industry
Information Paper
November 2009
ElectraNet Corporate Headquarters 52-55 East Terrace, Adelaide, South Australia 5000 • PO Box, 7096, Hutt Street Post Office, Adelaide, South Australia 5000Tel: (08) 8404 7966 • Fax: (08) 8404 7104 • Toll Free: 1800 243 853 FUTURE ELECTRICITY INFRASTRUCTURE REQUIREMENTS OF SOUTH AUSTRALIA'S RESOURCES INDUSTRY November 2009
Copyright and Disclaimer
Copyright in this material is owned by or licensed to ElectraNet. Permission to publish, modify, commercialise or alter this material must be sought directly from ElectraNet.
Reasonable endeavours have been used to ensure that the information contained in this report is accurate at the time of writing; however, ElectraNet gives no warranty and accepts no liability for any loss or damage incurred in reliance on this information.
This document has been prepared to provide information requested by RESIC and SACOME to support discussion on long term infrastructure planning. This document is not intended to be relied upon or used for other purposes, such as making decisions to invest in further generation, transmission or distribution capacity. This document has been developed using information and reports prepared by a number of third parties, which are neither endorsed nor supported by ElectraNet and do not necessarily reflect any policies, procedures, standards or guidelines of ElectraNet.
Any individual proposing to use the information presented in this document should independently verify the accuracy, completeness, reliability and suitability of the information provided in this document, as well as the reports and other information used by ElectraNet in its preparation.
FUTURE ELECTRICITY INFRASTRUCTURE REQUIREMENTS OF SOUTH AUSTRALIA'S RESOURCES INDUSTRY November 2009
Contents
EXECUTIVE SUMMARY ...... 1
1. INTRODUCTION ...... 3
1.1 PURPOSE ...... 3
1.2 OBJECTIVES ...... 3
2. CONTEXT ...... 4
2.1 CLIMATE CHANGE POLICIES ...... 4
2.2 REVIEW OF ENERGY MARKET FRAMEWORKS IN LIGHT OF CLIMATE CHANGE POLICIES ...... 6
2.3 PEAK OIL ...... 7
2.4 SA RENEWABLE ELECTRICITY GENERATION OVERVIEW...... 8 2.4.1 Coal to Liquids...... 9 2.4.2 Geothermal...... 10 2.4.3 Wind ...... 10 2.4.4 Wave ...... 10 2.4.5 Solar ...... 10
2.5 EMERGENT NON-RENEWABLE TECHNOLOGIES...... 11 2.5.1 Carbon Capture and Storage ...... 11 2.5.2 Coal to Liquids...... 12
3. GRID CONNECTED ELECTRICITY SUPPLY...... 15
3.1 INTRODUCTION ...... 15
3.2 SCENARIO-BASED ANALYSIS ...... 15
3.3 SCENARIO 1 - GREEN GREEN GREEN ...... 16 3.3.1 Scenario Summary...... 16 3.3.2 Issues ...... 17 3.3.3 Electricity Infrastructure Response...... 19 3.3.4 Probability of Scenario ...... 25 3.3.5 Mining Index Consequences ...... 25
3.4 SCENARIO 2 - MORE SNAKES THAN LADDERS ...... 26 3.4.1 Scenario Summary:...... 26 3.4.2 Issues ...... 26 3.4.3 Electricity Infrastructure Response...... 27
3.5 SCENARIO 3 – GROWTH GROWTH GROWTH...... 31 3.5.1 Scenario Summary:...... 31 3.5.2 Issues ...... 31 3.5.3 Electricity Infrastructure Response...... 32
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3.5.4 Probability...... 35 3.5.5 Mining Index Consequence...... 35
3.6 OTHER SCENARIOS...... 35
4. REMOTE ELECTRICITY SUPPLY ...... 35
4.1 DEMAND SUMMARY...... 35
4.2 RENEWABLE GENERATION SOLUTIONS ...... 35
5. BEYOND 2030 ...... 36
5.1 SPACE BASED SOLAR POWER ...... 37
5.2 A GLOBAL GRID...... 39
6. IMPLICATIONS FOR ELECTRICITY INFRASTRUCTURE...... 40
6.1 CLIMATE CHANGE POLICIES ...... 40
6.2 SENES ...... 41
6.3 PEAK OIL ...... 41
6.4 RENEWABLE GENERATION ...... 41
6.5 EMERGING TECHNOLOGIES ...... 42
APPENDICES ...... A1
APPENDIX A SCENARIO DISCUSSION...... A1
A1 METHODOLOGY ...... A1
A2 ASSUMPTIONS ...... A1
A3 SCENARIO DESCRIPTIONS...... A1
A4 SCENARIO WORKSHOP ...... A2
A5 PROBABILITY AND CONSEQUENCE RATINGS ...... A2
A6 SCENARIO 1 - GREEN GREEN GREEN ...... A4
A7 SCENARIO 2 – MORE SNAKES THAN LADDERS ...... A5
A8 SCENARIO 3 – GROWTH GROWTH GROWTH...... A6
APPENDIX B SCENARIO WORKSHOP ATTENDEES...... A8
APPENDIX C SUMMARY OF EXISTING INFRASTRUCTURE BY REGION...... A9
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C1 EYRE ...... A9
C2 UPPER NORTH...... A9
C3 MID NORTH ...... A9
C4 RIVERLAND...... A9
C5 SOUTH EAST ...... A10
APPENDIX D RESOURCE MAPS ...... A12
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Glossary of Terms
Term Description AC Alternating Current ADE Adelaide AEMO Australian Energy Market Operator AGEA Australian Geothermal Energy Association ATSE Australian Academy of Technological Sciences and Engineering CCC Committee on Climate Change CCGT Combined Cycle Gas Turbine CCS Carbon Capture and Storage CET (University of Adelaide) Centre Of Energy Technology CPRS Carbon Pollution Reduction Scheme CSP Concentrating Solar Thermal Power CTL Coal to Liquids DC Direct Current DTEI Department Transport, Energy and Infrastructure ETS Emissions Trading Scheme NIEIR National Institute of Economic and Industry Research NSA Northern South Australia OCGT Open Cycle Gas Turbine ODX Olympic Dam Expansion OPEX Operating Expenditure PIRSA Primary Industries and Resources SA REDP Renewable Energy Demonstration Program Renewables SA Established to develop and oversee the implementation of a framework for attracting renewable energy investment to South Australia RESIC Resources and Energy Sector Infrastructure Council RET Renewable Energy Target Scheme SACOME South Australian Chamber of Mines and Energy SBSP Space Based Solar Power SENE Scale Efficient Network Extension SESA South East South Australia SSP Space Solar Power
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Executive Summary
ElectraNet is a registered Transmission Network Service Provider operating in the National Electricity Market. ElectraNet operates in accordance with the National Electricity Law and the National Electricity Rules, which establish an open access framework for connection to the electricity network. Accordingly, ElectraNet offers non-discriminatory access to all forms of generation technology and customer load seeking to connect to its network, in accordance with the applicable technical requirements.
The purpose of this paper is to explore the potential impacts of mandated renewable and carbon reduction policies adopted by government and the related impacts of potential energy demand growth driven by expansion of the mineral resources sector on South Australia’s electricity supply infrastructure.
To this end, this paper explores a range of hypothetical scenarios to identify electricity infrastructure issues and challenges for discussion. It does not purport to represent ElectraNet’s view of the likely pattern of future investment, or of the particular generation sources expected to connect to its network.
Accordingly, the information contained herein should not be attributed to ElectraNet or quoted without express permission.
The paper has been prepared through a cooperative process involving Primary Industries and Resources SA (PIRSA), the South Australian Chamber of Mines and Energy (SACOME) and ElectraNet and has been prepared in parallel with a Future Electricity Demand of South Australia’s Resources Industry study paper prepared by the Resources and Energy Sector Infrastructure Council (RESIC) and SACOME.
Through this collaborative effort a range of scenarios were developed by representatives of the above organisations to explore the economic, technical, and regulatory factors that could affect the supply of electricity to South Australia’s mineral resources projects and development of the State’s renewable energy sources over the time horizon of 2010 to 2030.
These scenarios were not developed to be realistic representations of likely outcomes, but instead were designed to test the sensitivities of specific variables. The selected scenarios were considered and analysed at a workshop conducted on 5 November 2009.
Generation technologies considered were limited to those forecast to be commercially available and achieve generation of significant capacity (>5MW at one site) over this timeframe. Nuclear power generation was excluded from consideration, based on current government policy.
Through this work, a number of implications for the State’s electricity supply infrastructure have been identified.
Government climate change policies are expected to drive significant shifts in the existing pattern of generation, transmission and consumption of electricity (and gas). These developments are expected to see the economic retirement of existing generation plant, the development of new conventional and renewable generation sources, and the emergence of new generation technologies in response to carbon cost signals. The changing patterns of electricity generation and demand which result are expected to have a major influence on the development of the electricity network.
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Many renewable energy sources and mining loads are also remote from the existing electricity network, posing challenges for connection to the grid. The introduction of the proposed Scale Efficient Network Extension (SENE) framework under the National Electricity Rules may through capturing economies of scale provide the opportunity to connect clusters of new generation to the transmission network that would not otherwise be economic, and facilitate connection to nearby loads.
The possible future decline in global oil production may impact on commodity prices and transportation costs in turn affecting electricity supply infrastructure through its effect on input costs, availability of fuels and material lead times. These resource and cost constraints may place upward pressure on new infrastructure costs and development timeframes.
Balanced against this, the cost of alternative forms of energy such as diesel fuel will gradually become more expensive and harder to obtain, impacting on the operating costs for mines and other energy intensive loads using diesel generation to power their operations. This might tend to make grid connection more economic from some load centres. The scenarios analysed also highlighted the need for timely market driven investment in a range of generation sources in order to meet the twin challenges of satisfying the State’s anticipated future energy requirements while reducing the State’s carbon footprint.
The development of emerging renewable generation sources to commercial maturity, including geothermal, wave and solar technologies is expected to play a key role in the future supply of energy within the State. The successful deployment of other emerging technologies including carbon capture and storage and coal to liquids production may impact on the economics of conventional generation. There is also a continuing need to maintain adequate investment in new and existing conventional generation sources through this transition, such as gas fired peaking plant, to ensure adequate supply capacity to meet expected peak demands in the face of increasing supplies of intermittent generation such as wind.
Scenario analysis shows that in order for the State to realise its renewable energy potential would require either significant new load sources or a major expansion in electricity interconnection to reach markets interstate. The potential expansion of mineral resource driven loads alone will not provide sufficient demand to absorb this growth. The development of additional interconnection to the eastern states would provide access to a much broader energy market while serving as a mitigation measure against any future shortfalls in generation capacity during the market transition.
It will also be important to secure reliable future sources of fuel for the ongoing supply of electricity to the growing number of mining operations that will remain remote from electricity supply infrastructure. Developing technologies such as coal to liquids production may play a role in securing access to new competitive supplies of these fuels.
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1. Introduction
The Commonwealth Government is taking measures to transition the Australian economy from a dependence on fossil fuels to a lower carbon economy with renewable forms of energy. It has established an expanded Renewable Energy Target (RET) Scheme to achieve 20% renewable energy generation by 2020. A further initiative to introduce an Emissions Trading Scheme known as the Carbon Pollution Reduction Scheme (CPRS) is currently subject to debate in parliament.
South Australia has a wealth of natural resources in the form of mineral and energy resources, including renewable energy such as wind, solar, wave and hot dry rocks. South Australia is currently leading the nation in the uptake of renewable energy and has set a Renewable Energy Target that exceeds that of the Commonwealth of Australia (33% by 2020).
A common thread between developing the State’s significant mineral and energy resource opportunities is electricity transmission. Many of these resources are in remote areas of the State, which are distant from the current electricity transmission network and harvesting these resources in an economic and sustainable manner will be a significant challenge that will require cooperation from government and industry across a number of sectors.
1.1 Purpose
The purpose of this Information Paper is to explore possible future scenarios related to the development of South Australia’s energy and mineral resources in a sustainable manner and the economic, technical, and regulatory factors that may affect the supply of electricity to South Australia’s mineral resources projects.
The paper has been prepared through a cooperative process involving Primary Industries and Resources SA (PIRSA), the South Australian Chamber of Mines and Energy (SACOME) and ElectraNet representatives and has been prepared in parallel with a Future Electricity Demand of South Australia’s Resources Industry study paper prepared by the Resources and Energy Sector Infrastructure Council (RESIC) and SACOME.
It is important to note that what is presented in this paper is the result of high level or conceptual analysis of future possibilities and is not based on detailed economic analysis to identify least cost options. The paper identifies challenges and issues impacting on electricity supply to South Australia’s Resources Industry over the next 20 years for information and discussion purposes only.
1.2 Objectives
The specific objectives of this paper are to:
• Document change drivers affecting the electricity infrastructure required to support a growing resources industry within South Australia;
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• Explore the potential for renewable and mineral resource development in South Australia by considering scenarios which describe possible futures for infrastructure requirements between the period 2010 to 2030;
• For each scenario compare the renewable energy potential with estimates of demand growth and identify implications for electricity supply infrastructure requirements; and
• Identify the electricity supply challenges and issues arising from the change drivers and scenarios considered for discussion.
2. Context
This section briefly discusses a number of change drivers and factors that impact on the electricity infrastructure required for the resources industry.
2.1 Climate Change Policies
Renewable Energy Target Scheme
The Commonwealth Government passed expanded RET Scheme legislation on 20 August 2009. This scheme only applies to the electricity supply system and obligates electricity retailers to purchase 20% of what they sell to Australian electricity consumers from renewable energy sources.
Such sources can include hydro, wind, solar and geothermal generation but can also include solar household generation units and energy equivalents from solar hot water systems. The original RET scheme in Australia commenced in April 2001 and required 2% of electricity sold by retailers to be covered by Renewable Energy Certificates (RECs). This has continued without increase until the introduction of the expanded RET scheme in 2010 which will then increase those targets and ramp them up to 20% over the next 10 years. The shape of the increase is important as this contributes to whether emerging technologies are likely to be able to contribute to meeting the targets. The requirements are shown in the figure below.
The expanded RET scheme has an end date of 2030 because it is envisaged that alternative drivers to mitigate carbon emissions will be in place and effective by this time thereby making the mandated nature of this scheme unnecessary.
A further factor in determining the technologies for meeting the renewable energy targets is the ability to bank certificates. When the legislation was passed changes were made to the profile to increase the target at 2010 from 9,500 to 12,500 GWh. This will support more rapid introduction of renewable energy sources in the immediate years which may have implications for how the renewable targets are actually delivered. Some consider that this may favour existing technologies such as wind, over the more developmental type technologies such as carbon capture and storage; geothermal; solar thermal or even solar photovoltaic.
However, it is interesting to note that the recent price declines for renewable energy certificates are believed to be driven by the selling of certificates derived from the success of solar thermal hot water initiatives.
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Figure 1: RET annual target profile in calendar years
The value of the shortfall (payable for non compliance) has also been increased from $40 to $65 per MWh (equivalent to $93 pre-tax), reflecting the greater importance being placed on meeting the targets.
Carbon Pollution Reduction Scheme
The Carbon Pollution Reduction Scheme (CPRS) has not been passed by the Australian Parliament at this time. Opponents of the legislation are concerned about the cost to the economy and the implications of the global financial crisis. Negotiations on the proposed legislation are currently underway.
One important characteristic of the proposed CPRS is that it is a wider scheme, applying not only to electricity supply, but also to other sectors of the economy, such as transport. Therefore, it provides a much broader signal to the Australian economy to reduce carbon usage and lower the level of emissions within Australia.
From an electricity supply perspective, the intention of the CPRS is to facilitate a market based response to reducing emissions from all generation sources. It is also intended that the CPRS will be in place indefinitely; i.e. it has no end date, unlike the expanded RET scheme.
The key characteristics of the scheme include:
• Cap and trade model;
• Covers all six greenhouse gases under Kyoto protocol;
• Sectors included are industrial processes, stationary energy, transport, waste, and oil and gas fugitive sources (agriculture not included);
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• Liable entities (generators) required to surrender one permit for each tonne of CO2 equivalent produced;
• Federal government to auction a very high percentage of permits;
• Permits to be tradeable in secondary markets;
• Unlimited import of permits allowed;
• Trade exposed industries will receive special assistance;
• Some high intensity generators will receive special assistance; and
• Consumers will receive compensation (from auction receipts).
Implications for Electricity Infrastructure
The introduction of Government climate change policies is expected to result in large shifts in the existing pattern of generation, transmission and consumption of electricity (and gas). Many renewable energy sources are remote from the existing electricity network and changing patterns of electricity generation and demand are expected to put pressure on the existing networks.
2.2 Review of Energy Market Frameworks in Light of Climate Change Policies
Following a recent review1, the Australian Energy Market Commission (AEMC) has recommended changes to the current arrangements in the National Electricity Market for connecting generators to the electricity network.
These changes have been proposed to better facilitate efficiently sized investment to extend the network to connect new generators, where economies of scale are available.
Specifically, the AEMC has proposed that:
• A new type of network service is introduced under the National Electricity Rules for connection of generation to distribution and transmission networks where clusters of generators in the same locations are expected to seek connection over a period of time.
• This new type of network service, and adjustments to the regime for planning, charging and revenue recovery, would allow for Scale Efficient Network Extensions (SENEs).
• Generators would be required to pay a cost reflective charge based on their contracted capacity. Should all generators connect as forecast, the asset will be fully funded by generators.
1 Australian Energy Market Commission, Review of Energy Market Frameworks in light of Climate Change Policies: Final Report to the Ministerial Council on Energy, 30 September 2009
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• Customers will underwrite the cost of any additional capacity in excess of the requirements of the first connecting generators that is forecast to be efficient.
• The policy for SENEs should be reviewed after a period of five years.
If approved, the new Rules would take effect as early as late 2010. Under the new framework:
• The Australian Energy Market Operator (AEMO) would identify candidate SENE zones;
• The relevant transmission business would publish a high level assessment of credible options in its Annual Planning Report;
• Following an application to connect, the transmission business would undertake detailed planning and publish a SENE connection offer;
• The Australian Energy Regulator (AER), following advice from AEMO, would review the SENE connection offer; and
• If approved, construction of the SENE would begin.
In its review, the AEMC also recommended the introduction of inter-regional transmission charging arrangements and further consideration of the introduction of congestion pricing and locational transmission charging to signal network costs to generators.
Implications for Electricity Infrastructure
The introduction of the proposed new SENE framework may through capturing economies of scale provide the opportunity to connect clusters of new generation to the transmission network that would not otherwise be economic. Future changes to congestion and locational pricing arrangements may also impact on the optimal location of new generation sources.
2.3 Peak Oil
The principle behind the Peak Oil theory is derived from M. King Hubbert’s model for forecasting oil production, which was applied in 1956 to correctly predict that US oil production would peak in the 1970s2.
This model assumes that a new oil well will initially produce oil owly; following which the rate of production increases to a peak level that is reached when roughly half the oil in the well has been extracted. From this point, the output progressively declines and the marginal cost of extraction increases.
While opinion is divided, the majority of global oil production models indicate that global oil production will enter decline sometime in the years 2010-2020, following which prices are expected to progressively increase as demand outstrips supply.
2 “Beyond Oil, The View From Hubbert’s Peak” Kenneth S. Deffeyes; Hill and Wang 2006
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In the interim, price volatility can be expected to continue. According to Tino Guglielmo, Managing Director of South Australia’s Stuart Petroleum Pty Ltd, for the next 20 years, 80% of the world’s petroleum will come from West Africa, the Middle East, and Russia. These three places have two important things in common: political instability; and restricted access to oil reserves by the free market.
Through a combination of factors, including the inherent lag between exploration and production (as much as 10 years), restricted free-market access to the largest oil reserves, and the inherent challenges of timely supply infrastructure development and investment, further prices spikes can be expected.
Implications for Electricity Infrastructure
The issue of a decline in global oil production effects electricity supply infrastructure in terms of input costs, availability of fuels and material lead times. With greater costs of oil comes an increased cost for every commodity that uses oil in its production or transportation to market, including construction materials. This might place upward pressure on new infrastructure costs, including transmission.
Diesel fuel, which is already experiencing very high demands within South Australia, will gradually become more expensive and harder to obtain, impacting on the operating costs for mines using diesel generation to power their operations. This might tend to make grid connection more economic from some load centres.
2.4 SA Renewable Electricity Generation Overview
“If we get it right South Australia will do very well in the renewables industries”
Prof. Ross Garnaut, author, Garnaut Climate Change Review
Figure 2 below depicts an indicative development timeline outlining the earliest feasible dates for all renewable including emergent technologies considered to have the potential to provide commercially available, transmission level generation capacity (>5MW at one connection point) in the period 2010 to 2030.
Technology 2009 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Coal to Liquids Geothermal
Wind
Wave
Solar
Commercially Feasibility Studies Demonstration Construction Pilot Grid connection Available
Figure 2: Timeline for Renewable and Emergent Technology
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This timeline is based on information provided by RESIC, the SACOME Renewable and Emergent Technologies Subgroup of the Energy Policy Working Group and renewable proponents for each type of technology. The data obtained was refined in the light of infrastructure construction timeframes required to connect the given technologies to the SA transmission network.
The data was reviewed by several key stakeholders including Renewables SA, the AGEA, and the University of South Australia’s Renewable Energy Engineering Division. In short, this timeline represents a consolidated, broadly consulted picture of the earliest timeframes in which renewable and emergent technologies may develop over time within South Australia.
16000 14487 15000 14000 13000 Wave 12000 11000 Solar 10000 8362 9000 Wind 8000 7000 Geothermal 6000 4564 Coal to Liquids
Capacity (MW) Capacity 5000 4000 Total 3000 16 9 8 2000 869 1000 0 2010 2015 2020 2025 2030
Figure 3: Renewable and Emergent Energy Capacity Forecast for South Australia
Figure 3 above depicts a view of South Australia’s potential for growth in grid connected renewable generation between now and 2030, based on the earliest feasible dates outlined in Figure 2.
The following discussion provides more detail on the assumptions and considerations applied to renewable technologies in developing Figures 1 and 2. A discussion of emergent non-renewable technologies follows in Sections 2.5 and 2.6.
2.4.1 Coal to Liquids
For clarification, Coal to Liquids is classed as an emergent technology, and cannot be considered renewable. The timeline in Figure 2 combines data from the six commercial Coal to Liquids projects proposed within South Australia. Although some are still in the concept definition phase, most of the projects are in the study and demonstration phases throughout 2009. Some construction work will be required prior to grid connection being realised with expected completion around 2015. Grid connection is shown to commence as of 2018.
Figure 3 assumes that four of the six proposed Coal to Liquids projects will be in operation by 2030, with each of these projects delivering 500MW each to the grid.
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2.4.2 Geothermal
The timeline for geothermal energy assumes an earliest feasible connection date of a commercial scale facility in 2018. The potential output for geothermal generation between 2010 and 2015 is estimated to be between 100-200MW. On this projection, potential capacity in 2015-2020 could be as high as 500-1000MW. For the purposes of Figure 2 an average has been taken for these values within the designated time frames.
Other steps are being taken to support the development and commercialisation of this technology through the Renewable Energy Demonstration Program (REDP), including:
• MNGI Pty Ltd (wholly owned subsidiary of Petratherm) - $63 million grant subject to successful offer negotiations. The 30MW Paralana Geothermal Energy Project is located adjacent to the Beverley uranium mine.
• Geodynamics Limited - $90 million grant subject to successful offer negotiations. The Geodynamics Cooper Basin 25 MW Geothermal Demonstration Project will be located in the north east corner of South Australia in the Cooper Basin, between Moomba and Innamincka.
2.4.3 Wind
There is currently 869MW of wind generation capacity connected to the South Australian transmission network in 09/10, with another 289MW confirmed in the next 2 years.
2.4.4 Wave
The National Institute of Economic and Industry Research “Future Prospects for Renewable Energy in South Australia” report3 indicates that this technology is unlikely to become a significant renewable energy source until post 2020. Grid connection has been programmed for that timeframe.
Minimal output for this technology has been predicted prior to 2020 with expanding potential ‘post 2020’; however, future values are unknown for the purposes of this chart.
2.4.5 Solar
The timeline combines both solar thermal and solar photovoltaic technologies. There are key solar projects underway in South Australia, which have the potential to generate significant amounts of electricity.
Recently the Federal Government has announced additional details around its $1.5 billion project to construct and demonstrate up to four large-scale solar power plants in Australia, using solar thermal and photovoltaic (PV) technologies – known as the
3 The Future Prospects For Renewable Energy In South Australia, NIEIR Report, 14 May 2009
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Solar Flagships program. The timeline above assumes that South Australia will be awarded one of those Solar Flagships projects.
Potential capacity data includes all available solar thermal and photovoltaic technologies. Solar shows a greater capacity than other technologies by 2030, due to the potential for greater flexibility in the location of connections relative to the transmission network. By 2015 the Australian Government’s Solar Flagship initiative should see approximately 250MW installed in South Australia (1000MW Australia- wide). From this point onwards, 25% predicted growth has been calculated per annum.
Implications for Electricity Infrastructure
The development of renewable generation sources poses a number of challenges for the electricity network, particularly as many of these resources are remote from the existing grid. The optimal timing and location of these projects will therefore be influenced by the costs of connection, but may be assisted by coordinated and efficiently scaled development of the required infrastructure. However, the challenge of extending the network to as yet unproven technologies remains.
The established renewable generation technologies currently being developed have largely been intermittent in nature, with typically low capacity factors, leading to lower network utilisation than conventional generation and posing added challenges for the design and operation of the network. These challenges have been managed to date but will increase as the scale of the renewable generation fleet continues to expand.
2.5 Emergent Non-Renewable Technologies
2.5.1 Carbon Capture and Storage
Carbon Capture and Storage (CCS) is the set of technologies that capture, 4 transport, and safely store anthropogenic carbon dioxide (CO2) deep underground .
The Australian Academy of Technological Sciences and Engineering (ATSE) Submission on “Maximising the Value of Technology in the Energy Sector” May 2009 stated that “Fossil fuel generation with carbon capture and storage (CCS) would overcome the carbon penalties concern, but the technology is not yet available and has yet to be proven at commercial scale anywhere in the world. The challenges and probable costs are substantial. Investment is still remote.”
According to Peter Mullinger, University of Adelaide professor and Technical Director of Hybrid Energy Pty Ltd, post combustion CO2 capture is the only realistic short term option, and is therefore essential for achieving rapid reductions in CO2 emissions5. Post Combustion capture Amine solvent extraction processes can be retrofitted to existing plants and is commercially available now. Loy Yang power station in Victoria is currently conducting a feasibility study to assess options.
4 Worley Parsons Status of CCS Synthesis Report 5 Peter Mullinger Clean Coal Presentation
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The challenges for the commercial success of CCS revolve around the integration of potentially very expensive plant and infrastructure with traditional processes that in the past have been relatively inexpensive. Additionally, the expense of high solvent consumption rates and high energy consumption required to support on-going operations must be considered. There will likely be a significant increase in fuel consumption for electricity generation, due to reduced efficiencies.
The CCS landscape is changing. In its report “Strategic Analysis of the Global Status of Carbon Capture and Storage” (October 2009), Worley Parsons analysed a total of 275 CCS projects around the world6. Of these, 62 projects are considered as integrated, that is they demonstrate the entire CCS process chain of CO2 capture, transport, and storage. Seven of these 62 projects are already in operation. This leaves potentially 55 projects that could be candidates for the Group of Eight objective of supporting the launch of 20 large scale CCS demonstration projects globally by 2010.
The Worley Parsons study reveals that in order to accelerate the deployment of CCS projects the world must exploit cost advantages that exist in advancing projects in developing countries such as China and India, and industries such as natural gas 7 processing and fertiliser production in which CO2 capture is inherent in their design .
Key findings of the report include:
• The leading developers of fully integrated, commercial scale projects include participants in Europe (37 per cent), USA (24 per cent), Australia (11 per cent) and Canada (10 per cent).
• One of the seven identified Australian projects is located in South Australia: the FuturGas project is a Coal to Liquid fuels project that has a forecasted operational date of 2017. The plan for this project is to use an 80-200km pipeline and depleted oil and gas fields to sequester 1.6 mega tonnes of CO2 per annum. The project information also indicates the potential use of saline aquifers for CO2 storage, though this approach may give rise to important environmental and water use considerations.
2.5.2 Coal to Liquids
“Unless significant new oilfields are found, Australian domestic oil production could represent as little as 20 per cent of our consumption by 2015…an annual trade deficit of up to $27 billion.”
Prime Minister Kevin Rudd in “Securing a sustainable energy supply for Australia’s future”, 2007 election policy
Transport fuels become relevant when considering the supply of electricity to mineral resources projects. A significant number of mines source their power from on-site diesel generators. In the context of diminishing oil supplies, it is wise then to
6 Worley Parsons Status of CCS Synthesis Report 7 Australian Journal of Mining website, article by Paula Wallace, 28 October 2009
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consider alternatives as recommended by the Australian Academy of Technological Sciences & Engineering:
“Australia’s oil production is falling due to depletion of reserves, with the rate of discovery of new oil reserves not keeping up with production. Accordingly, Australia must adopt a number of strategies. Industry must be encouraged to … diversify the sources of liquid fuel supply and/or attempt to mitigate demand. The development of alternative sources requires very long lead times, at least on the order of a decade or more for hydrocarbon fuels and much longer for alternative sources of transportation power. This is where government can play a significant role.
In the case of petroleum-based transport fuels, it will be necessary to manage a transition to a larger, mixed economy in which liquid fuels are derived from a number of sources8”.
There is an increasing demand for diesel fuel, especially in South Australia and principally from the mining sector. Over 50% of Australian diesel fuel is imported. Limitations due to local and Asian refining capacity are resulting in diesel shortages, especially in South Australia9.
The Fischer–Tropsch process (or Fischer–Tropsch Synthesis) is a catalysed chemical reaction in which synthesis gas, a mixture of carbon monoxide and hydrogen, is converted into liquid hydrocarbons of various forms. Through this process, coal and water can be used to produce low sulphur diesel that can be immediately used in existing fuel transport and storage infrastructure. CTL projects can produce any hydrocarbon-based fuel, including jet fuel and petrol.
In addition to high quality diesel and jet fuels, CTL plants can also generate significant amounts of base load electricity.
There are currently six companies that are at various stages of developing CTL projects in South Australia. Each of these projects features a unique risk profile associated with the type of resource it is looking to exploit. These projects are located in different regions around the state including the Eyre, Upper North, and South East regions.
Using an average forecast production of 10,000 barrels per day, and assuming all of these projects were successfully implemented, South Australia could become a producer of over 18 million barrels of diesel fuel per year by 2018 to 2020.
South Africa has been producing coal-derived fuels since 1955 and has the only commercial coal to liquids industry in operation today. Not only are CTL fuels used in cars and other vehicles, South African energy company Sasol’s CTL fuels also have approval to be utilised in commercial jets. Currently around 30% of the country’s gasoline and diesel needs are produced from indigenous coal. The total
8 ATSE 30/50 Report 9 Presentation, SA Coal Utilisation – Peter Mullinger
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capacity of the South African CTL operations now stands in excess of 160,000bbl/d10.
Based on the number of projects and the proven nature of the Fischer–Tropsch technology, the South Australian CTL market has significant potential to provide both electricity and a secure source of transport fuels for Australia. There are currently four impediments to the development of CTL projects.
• Technical challenges associated with the use of South Australia’s brown coal in Fischer–Tropsch reactors. This is due to their high sulphur and sodium content. Research into these challenges is progressing.
• Process water consumption is potentially high with Fischer-Tropsch synthesis. Diesel fuel contains more H2 than coal. Each additional 1kg of H2 requires 9kg of water.
• Large plant items have to be moved long distances over land, potentially over unpaved tracks. Likewise products must be transported over long distances, impacting the profitability of the business. The workforce for the plant requires dedicated accommodation and the need for fly-in fly-out of staff. The higher wages required to attract workers to remote locations increases running costs.
• Greenhouse gas emitters are likely to be subject to controls and permitting requirements. This will result in higher costs.
Recalling the earlier quote from ATSE:
“The development of alternative sources requires very long lead times, at least on the order of a decade or more for hydrocarbon fuels and much longer for alternative sources of transportation power. This is where government can play a significant role.”
Implications for Electricity Infrastructure
The successful deployment of carbon capture and storage and coal to liquids technologies will impact on the economics of conventional generation and influence the timing of plant retirement in response to carbon cost signals.
This will influence the rate at which other emerging technologies become commercially competitive, and in turn will impact on the pattern of future generation development on the network. The development of the transmission network will therefore be impacted by the generation investments which emerge as the competing technologies continue to develop.
10 World Coal Institute Website: http://www.worldcoal.org/coal/uses-of-coal/coal-to-liquids/
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3. Grid Connected Electricity Supply
3.1 Introduction
The Future Electricity Demand of South Australia’s Resources Industry information paper prepared by RESIC and SACOME presents the following projections of demand from the resources sector based on a survey of over 40 resource and infrastructure companies.
Forecasted Peak Power Demand for the SA Resource Sector
2500
2000
1500 Power Demand (MW) Source Not Provided 1000 Grid Generators 500
0 2010 - 11 2012 - 14 2015 - 19 beyond 2020 Time Period
Figure 4: Forecast of Future Electricity Demand of South Australia’s Resources Industry
Based on the data in Figure 4, it appears that only a small amount of electricity is expected to be supplied to mining projects from the grid by 2030 compared to the projected level of onsite generation. However it is likely, given climate change drivers, that the transmission network could be extended to more remote regions of the State to facilitate connection of remote renewable generation of various technologies.
It is therefore possible that much more of the electricity required by mining projects operating in 2020-2030 could be sourced from the transmission grid. To analyse this opportunity, a scenario analysis approach was applied, assuming that all of the energy supplied by unspecified sources above is able to be supplied by the grid.
3.2 Scenario-Based Analysis
A scenario analysis was undertaken to explore future possibilities for supply of South Australian demand by renewable generation sources.
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Scenarios were developed by Bridge 8 Pty Ltd., a consultancy that specialises in futurist theory, based on input from Government and industry representatives. These scenarios were considered and analysed at a workshop conducted on 5 November 2009 involving Government and industry representatives.
The following sections detail the key issues and outcomes identified as a result of the workshop. For details on the methodologies used to develop the scenarios, the scenarios themselves, or more detail on the observations and outputs of each scenario, please refer to Appendix A. For a list of workshop attendees, please see Appendix B. For maps and descriptions of the existing network relative to mining and renewable energy projects refer to Appendix C. For a comprehensive set of maps showing projected mining and renewable energy developments related to the scenarios considered refer to Appendix D.
The input key assumptions common to all scenarios are as follows:
Common Scenario Assumptions Timing Green Grid, phase 2 (Eyre Peninsula wind, mining loads) 2016 CPRS 2011
3.3 Scenario 1 - Green Green Green
3.3.1 Scenario Summary
This scenario explores the impact of maximum development of renewable energy and supporting infrastructure:
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Key Scenario Features Timing Upper North (Solar, ODX and other Mining Loads) 2020 Green Grid, Phase 3 (Paralana, Cooper Basin - Solar, 2020 Geothermal, Mining Loads) Interconnector (South East, Geothermal, Wind, Wave) 2018 Concentrating Solar Thermal (includes storage capability) 2025 Combined Cycle Gas Turbine Base load power generator Not constructed No investment, Coal to Liquids (CTL) due CPRS Peak Oil Price Impacts Not a factor
Key Scenario Features and Timing (Scenario 1)
Year Demand Capacity (MW) (MW) Technology 2010 2015 2020 2025 2030 2010 0 Coal to 2015 200 Liquids 0 0 0 0 0 2020 700 Geothermal 0 0 750 2000 3000 2025 800 Wind 869 1448 2198 2948 3698 2030 1000 Wave 0 0 5 50 100 Solar 0 127 377 877 1877 New Mining Demand (Scenario1) Alternative Generation Capacity (Scenario 1)
3.3.2 Issues
Electricity Costs
This scenario involves maximum development of potential renewable energy sources in the State, which will clearly require massive private sector capital investment.
To make the Green Green Green scenario viable, it was noted that strong global carbon pricing signals need to be in place to offset the significant capital cost for infrastructure to the point that clean energy becomes cost competitive with conventional sources.
This in turn would suggest that prices for electricity would be high to cover the higher cost of the energy and network investment involved to deliver this generation to market.
This would appear to be borne out by experience in other markets, including Spain which has the highest percentage of installed renewable generation of any country in the world. To facilitate this, the Spanish government has heavily subsidised the funding of the required infrastructure.
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Need For Base Load Electricity
No conventional base load plant was constructed in this scenario to mitigate the risk associated with geothermal technologies running late, falling short of forecasts, or failing outright.
The view of the workshop was that this apparent “investment strike” in base load generation was largely driven by the current uncertainty and delayed policy setting related to establishing a CPRS.
One investor also cited the lack of capacity payments to generators operating in the National Electricity Market as making investment in other markets potentially more attractive11.
A related issue that was highlighted was the requirement for conventional peaking plant in order to cover the variability of wind generated electricity. Back-up peaking plant will be needed to mitigate the demonstrated unavailability of wind generation and ensure that sufficient reliable supply capacity is available at peak demand times.
This environment may lead investors to construct open cycle gas turbines for peaking requirements, but configure them in a way that would allow them to be converted into combined cycle gas turbines for use in meeting base load requirements in the case that base load renewable generation is delayed or fails to eventuate.
Interconnector Need versus Justification
To deliver the scale of new renewable generation developed under this scenario to market would require either significant new load sources or a major expansion in interconnection to increase access to markets interstate.
It is clear that the electricity requirements of the Resources Industry in South Australia and other demand growth are of themselves not large enough to provide sufficient market growth to absorb the potential renewable generation capacity in the state.
Therefore, additional interconnector capacity would be required for this scenario to be realised.
However, workshop participants considered it unlikely that an interconnector project of the required size would pass the required market benefits test, in the absence of broader economic, environmental, and social considerations.
Resource Sector Response
Based on input from the mineral resources experts involved in the workshop, it became clear that not all mines would seek to connect to the grid, even if it was made more accessible to them. Each mining project would assess its options and
11 Barry Ford, General Manager of Business Development, ATCO Power
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seek to minimise capital investment, accepting high operating costs in order to achieve the lowest risk solution for meeting electricity supply requirements.
The Olympic Dam expansion features a long forecast mine life. Given that there is a pre-existing power line connecting the site to the transmission network, and large electrically operated equipment to power, a grid-connected solution is likely to be most suitable.
Other mining projects may not seek a grid connection, based on a combination of factors including forecast demand and distance from the grid. The assumption in developing the forecast mining related electricity demand for this scenario is that mines remote from existing power lines will generate on site.
3.3.3 Electricity Infrastructure Response
In this scenario, an interconnector to NSW is constructed, and the vision of South Australia becoming a major exporter of green power is realised by leveraging the State’s wind, solar, and geothermal endowment (see Figure 5).
Green Green Green - Renewable Mix - 2030 0% 16%
1%
Coal to Liquids Geothermal Wind Wave 56% 27% Solar
Figure 5: Renewable Energy Mix at 2030 – Scenario 1
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Scenario: Green Green Green Renewable Energy and Energy Growth
70000 Medium Forecast Energy
60000 Medium 33% High Forecast Energy
50000 High 33% Scenario Energy 40000
30000 Energy GWh Energy
20000
10000
0 10 12 14 16 18 20 22 24 26 28 30 Year ending
Figure 6: Renewable Energy and Energy Growth – Scenario 1. Green Green Green
Figure 6 above shows the energy generated from only renewable and emergent sources (Scenario Energy, shown in red) compared to the Renewable Energy Target of 33%, and forecast demand.
Medium forecast demand (shown in a blue solid line) is based on the Electricity Supply Industry Planning Council’s (ESIPC) 2009 Annual Planning Report (APR) and is linearly extrapolated out to 2030.
The High demand forecast (shown in a blue dashed line) is based on the ESIPC (APR) demand profile with the potential new mining demand agreed during the scenario workshop added in.
The 33% Renewable Energy Target for the Medium and High demand profiles are shown in green solid and dashed lines respectively.
Renewable Energy Target
By 2015-16 the 33% Renewable Energy Target is met for both Medium and High demand. In fact, 100% energy can be achieved from renewable energy for the medium load forecast by 2021-22 and by 2024-25 for the high demand case.
Interconnector Need and Timing
While excluding conventional generation, Figure 6 indicates that an operating interconnector would be needed for use in exporting electricity from 2020-2022. Without a new, properly sized interconnector, there would be insufficient market to sustain the excess generation, even assuming significant expansion in the State’s
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mining loads. Without the interconnector providing access to a broader market, the vision of South Australia becoming a major exporter of renewable energy under this scenario would not come to pass.
Scenario : Green Green Green Peak Demand and Generation Availability 11000
10000 Medium Peak Demand Forecast
9000 High Peak Demand Forecasts
8000 Scenario Generation Availability
7000 MW
6000
5000
4000
3000 10 12 14 16 18 20 22 24 26 28 30 Year ending
Figure 7 Peak Demand and Generation Availability – Scenario 1. Green Green Green
Peaking Plant Requirements
In this scenario, conventional generation was assumed to have been replaced with all demand met by renewable generation by 2030. While modelling indicates this is theoretically possible, this outcome was considered highly unlikely by those attending the workshop.
Figure 7 above illustrates the current 10-year peak electricity Medium Peak Demand forecasts for South Australia published by ESIPC, extrapolated to 2030. Potential mining loads are then overlaid to illustrate the possible growth in peak demand, and compared with projected total generation development.
This modelling indicates there is sufficient generation available at peak periods to meet the Medium Peak Demand in 2030. However, for the high demand forecast there is a generation capacity shortfall starting in 2015 which requires additional conventional Open Cycle Gas Turbine (OCGT) generation as follows:
• 2015: 400 MW
• 2020: 400 additional MW (for a total of 800MW)
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As depicted below in Figure 8, a minimum of 300 MW of the above OCGT peak generation is assumed to be located in Adelaide (Central Node) for network stability purposes.
Again, these OCGTs could be designed and installed by generation proponents for conversion to Combined Cycle Gas Turbine (CCGT) base load power plants at a later stage.
153 MW Scenario Input variables 200 MW SA D em and 2425 New loads D em and + Lo sses ( 5 % ) 2546.25 Murraylink Interconnector +200 MW Conductor Rating ( click on adjacent cell 1000 MW for drop down menu) Spring/Autumn NSA Heywood dispatch + for Export 460 2328 MW Murraylink dispatch + for Export 200 BHP/ Other loads in NSA 1000 Penola PM / O ther Loads in SESA 0 Generator Type Disp %NSA ADE SESA T o t al Coal/ Gas 90 0 300 0 300 Coal to Liquids 50 0 0 0 5162.25 Geothermal 90 2700 300 3000 Wind 75 2588.6 1109 3698 Wave 40 100 0 100 So l ar 40 1877 0 1877 1481 Capacity : 1500 MW Total 5162.25 270 1102 6534
Total Generation in SA 6534 Total Demand in SA 3546 N et Export+ / I mport- 6 6 0 Generation Surplus(+ )/Shortfall (-) 2328 MW
2037 MW 0MW ADE N ew Interconnector from ( click on adjacent cell for drop down menu) NSA
270
Capacity : 660 MW
286
460 MW
Heywood Interconnector +460 MW New loads 0 MW SESA 0MW
1102.05 356 MW
Figure 8: Average Demand Network Model 2030 – Scenario 1. Green Green Green
Interconnector Capacity
The above diagram depicts a model of the South Australian electricity transmission network at average demand. The model is simplified to show the three major nodes of the network: Northern South Australia (NSA), Adelaide (ADE), and South East South Australia (SESA). The currently existing Murraylink and Heywood interconnectors are shown in purple at the NSA and SESA nodes respectively.
The orange, two-way arrows at each node depict indicative interconnector locations. If the value adjacent to the orange arrows is zero, no interconnector is required at that location. The blue one-way arrows indicate the direction of positive travel of electricity and the corresponding number indicates the amount of electricity being transported.
Based on the model outputs for the Green Green Green scenario, there is a generation surplus of 3350 MW under light load conditions (not shown) and under medium load conditions there is a generation surplus of 2328 MW. This means an
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additional interconnector of this capacity would need to be in place to fully evacuate this generation, without constraints, under these conditions. Generation is concentrated on the Northern Node (geothermal, wind, and solar), so the new interconnector would best emanate from that node to avoid any inefficient ‘wheeling’ through the state system.
Potential for Wind Farm Developments
It was noted that the capital investment required to connect wind generated electricity from the west coast of the Eyre Peninsula would be significant. ElectraNet is has a total of 869 MW of wind generation currently installed with a combination of approximately 3100 MW of committed wind farm projects and connection enquires. This value does not include consideration of additional opportunities on the Eyre Peninsula that may arise due to Green Grid developments.
A total of 3,698 MW of installed wind generation forecast at 2030 was agreed during the scenario workshop, including consideration of Eyre Peninsula-based wind. It was considered that there is potential for even greater amounts of renewable generation.
This is tempered however by recent statements12 suggesting that AGL is unlikely to progress any further wind farm developments until 2016 due to reduced Renewable Energy Certificate (REC) pricing. This could also impact on the economic viability of the Green Grid expansion of the network to the Eyre Peninsula. The scenario timing for commissioning of an Eyre Peninsula power line (2016) is consistent with these considerations.
This situation could create an opportunity for some required conventional peaking plant (400MW of OCGTs) to be installed on the network between 2010 and 2015 in parallel with the construction of the Eyre Peninsula power lines (if the line project were to proceed).
Concentrating Solar Power
Late in this scenario (2025), Concentrating Solar Thermal Power (CSP) plants with storage capability were introduced to improve network stability, based on the large amounts of wind generated electricity on the network.
Analysis showed that this plant was required as generation at Port Augusta is decommissioned (from 2020). In this scenario, the industry recognition of this need came late in the period under review (in 2025, after which both Playford and Northern Power Stations were decommissioned).
It was noted during the workshop that CSP plants with storage can only be viewed as peaking plant; this type of power plant was not considered to be capable of providing base load generation. However, data received after the workshop from Dr Wasim Saman, Director of the University of South Australia Sustainable Energy Centre, indicates that CSP with storage may be capable of much higher capacity
12 Jeff Dimery of AGL
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factors (>85%), and therefore may be considered for future use in providing base load generation.
It was pointed out that CSP plants do not necessarily need to be installed stand- alone, but instead can be integrated with other technologies e.g. geothermal and gas-fired combustion plants to yield a very efficient power plant made up of a portfolio of generation technologies. Gus Nathan, Director of the University of Adelaide Centre of Energy Technology (CET) confirmed there is research work in this area happening at the CET now.
The workshop teams noted that, if geothermal is successful, it will likely be cheaper than CSP generated electricity. It was concluded therefore that CSP is unlikely to outstrip geothermal generation by 2030.
The graph of forecast carbon-adjusted electricity costs indicates that the cost cross- over between CSP and geothermal might occur earlier, around 2025.
Figure 9: Renewable energy, led by high-volume concentrating solar power, geothermal and wind, offers the prospect of low-cost, clean, abundant energy in coming years (Sources: ABARE, IEA, IPCC)
Coal-Fired Power Stations
It was assumed for the purposes of the scenario that the Playford Power Station would be decommissioned in 2020, while the Northern Power Station would be decommissioned in 2025. These dates were used to populate the reduction in conventional base load generation at the appropriate dates in the ElectraNet model, and influenced the timing of replacement plant as above.
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10000 8675 9000
8000 Wave 7000 58 75 Solar 6000 Wind 5000 Geothermal 4000 3330 Coal to Liquids
Capacity (MW) Capacity 3000 1575 Total 2000 869 1000 0 2010 2015 2020 2025 2030
Figure 10 Renewable and Emergent Energy Forecast – Scenario 1. Green Green Green
This scenario yielded the above grid-connected potential renewable energy growth profile.
3.3.4 Probability of Scenario
This scenario depends heavily on new technologies being available according to the earliest forecast feasible dates. This is considered to be an unlikely outcome, given the technical risks involved with some aspects of geothermal projects for example.
The Green Green Green scenario also relies on major assumptions about funding approvals for the capital construction works required to establish the infrastructure called for in this scenario. The reality is that there are significant capital costs involved that would impact on the business case for the given network extensions.
The probability that South Australia would arrive in the end state described by this scenario was judged as Very Low to Low: 10%-30%. This assessment was made based on the unmitigated risks highlighted above.
3.3.5 Mining Index Consequences
The probability of this scenario actually coming to pass, based on South Australia’s current energy trajectory, is low. However, if it is assumed that the identified risks are managed to yield the outcome described by the scenario, the consequences of the scenario would be as follows:
• Mineral Production Indictor: Target Achieved
• Fraser Institute Mineral Potential Ranking: Target Exceeded
This assessment is based on the fact that the South Australian Resources Industry would benefit from significantly improved electricity supply infrastructure and lower energy prices.
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3.4 Scenario 2 - More Snakes Than Ladders
3.4.1 Scenario Summary:
This scenario explores the effect of technological and investment challenges which prevent the development of base load renewable energy supply:
Key Scenario Features Timing Upper North (Solar, ODX and other Mining Loads) 2020 Green Grid, Phase 3 (Paralana, Cooper Basin - Solar, Not Geothermal, Mining Loads) developed Interconnector (South East, Geothermal, Wind, Wave) 2020 Concentrating Solar Thermal (includes storage capability) Not developed Combined Cycle Gas Turbine Base load power generator Not developed Coal to Liquids (CTL) Not developed Peak Oil Price Impacts 2030
Key Scenario Features and Timing (Scenario 2)
Year Demand Capacity (MW) (MW) Technology 2010 2015 2020 2025 2030 2010 0 Coal to 2015 200 Liquids 0 0 0 0 0 2020 700 Geothermal 0 0 0 0 0 2025 800 Wind 869 1448 2198 2948 3698 2030 1000 Wave 0 0 5 50 100 Solar 0 127 127 127 127 New Mining Demand Alternative Generation Capacity (Scenario 2)
3.4.2 Issues
Lack of Renewable Base Load Generation
The key feature in this scenario is the assumed technical difficulties preventing the commercial realisation of hot dry rock geothermal generation that ultimately results in a significant shortfall in base load generation by 2030.
As this scenario plays out, South Australia becomes increasingly dependent on imports of electricity from the eastern states (likely expensive energy due to CPRS, depending on fuel source) while there is a scramble to replace ageing coal-fired power plants.
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The outer limit of the useful life of both Playford Power Station and Northern Power Station was assumed as being 2028. It is likely that both will be retired before that date (perhaps 2020 and 2025 respectively), due largely to commercial factors. The unmitigated implications of peak oil price impacts included in this scenario exacerbate the situation. The required infrastructure would be much more costly to construct at this stage. Manufacturing and transport lead times would likely grow as materials become more expensive while availability diminishes and shipping costs increase.
Taking a time-phased approach to stepping up conventional generation to replace Playford Power Station and Northern Power Station, the additional generation needed to meet high demand is, cumulatively:
• 2015 : 300 MW
• 2020 : 600 MW
• 2025 : 700 MW
• 2030 : 1000 MW
The additional cumulative generation needed to meet Medium demand is:
• 2020 : 500 MW
• 2025 : 600 MW
• 2030 : 700 MW
These assumptions align with subsequent announcements from AGL on 6 November 2009 of plans for an expansion to Torrens Island Power Plant. AGL intends to add four OCGT units by 2015 at an estimated cost of $800m.
This development will not on its own fully satisfy the potential requirement identified in this scenario, but leaves opportunities for further peaking plant development by the market over the timeframes outlined above.
It is also possible that generation proponents may elect to design and install OCGTs with the capability to be converted to CCGTs at a later stage to meet future market requirements.
3.4.3 Electricity Infrastructure Response
In this scenario, geothermal generation fails to reach commercial maturity within the scenario timeframe and solar never progresses beyond the initial Solar Flagship projects. The renewable energy market is populated largely by wind.
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Renewable Mix - 2030 4% 0%0% 3%
Coal to Liquids Geothermal Wind Wave Solar
93%
Figure 11: Renewable Energy Mix at 2030 – Scenario 2. More Snakes than Ladders
Scenario : More Snakes than Ladders Renewable Energy and Demand growth
70000 Medium Forecast Energy Medium 33%
60000 High Forecast Energy High 33% Scenario Energy 50000
40000
30000 Energy GWh Energy
20000
10000
0 10 12 14 16 18 20 22 24 26 28 30 Year ending
Figure 12: Renewable Energy and Energy Growth – Scenario 2. More Snakes than Ladders
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Renewable Energy Target
Under this scenario, by 2015-16 the 33% Renewable Energy target is met for the Medium forecast and 2020-21 for the High demand forecast. South Australia can therefore be confident that the State is on track to achieve its renewable energy target of 33% by 2020, given that this scenario is fairly pessimistic in terms of technology development and investment. It is worth highlighting that just under 50% of energy demand for the state is being met by renewable energy by 2030 in this scenario.
Scenario: More snakes than ladders 11000 Peak Demand and Generation Availability
10000
9000 Medium Peak Demand Forecast High Peak Demand Forecasts 8000 Scenario Generation Availability
7000 MW
6000
5000
4000
3000 10 15 20 25 30 Year ending
Figure 13: Peak Demand and Generation Availability – Scenario 2. More Snakes than Ladders
Peak Load Generation Shortfall
Under peak load conditions however, there is a critical generation shortfall beginning in 2015, based on the potential demand identified in Figure 12 above. This generation shortfall reaches a maximum of 2922 MW by 2030 and could be addressed by:
• Adding new generation in the state; or
• Building a new interconnector of adequate size.
Under this scenario, the interconnector is constructed, and proves valuable for both maximising the opportunities and mitigating the risks associated with the transition to renewable energy. An interconnector sized at approximately 3000MW could serve to export excess renewable energy generated in SA.
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Upgrade of Ageing Coal-Fired Power Plants
Solar thermal troughs are added to Playford Power Station late in its lifecycle in this scenario. It was noted that this was unrealistic, based on commercial considerations. This may indicate the need in the 2010-2015 period for investment to improve the efficiency of both Playford and Northern Power Stations to get the most out of these assets between now and 2028.
5000
3925 4000 Wave 3125 Solar 3000 2330 Wind Geothermal 2000 1575 Coal to Liquids Capacity (MW) Capacity 869 Total 1000
0 2010 2015 2020 2025 2030
Figure 14: Renewable and Emergent Energy Forecast – Scenario 2. More Snakes than Ladders
Renewable & Emergent Technology Capacity Forecast
This scenario yields the potential renewable and emergent technology capacity development profile shown in Figure 13, which is roughly 50% of the capacity of the Green Green Green scenario.
Probability
The probability that South Australia would arrive in the end-state described by this scenario was judged as Low to Very Low – 15%.
Mineral Index Consequences
This scenario ends with South Australia being dependent on energy supplied by the eastern states, and remaining a price taker in a volatile market. While the Olympic Dam mine expansion goes ahead, the final outcome of this scenario largely serves to increase risks to mineral resources projects due to an ever widening gap between energy demand and energy generated within the state.
With no mitigation of Peak Oil price impacts (CTL projects not progressed and CSP technologies not developed), the increased cost of diesel fuel means that mines that select distributed generation solutions using diesel engines are impacted. The consequence was therefore judged as follows:
• Mineral Production Indictor: Target Not Achieved
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• Fraser Institute Mineral Potential Ranking: Target Not Achieved
3.5 Scenario 3 – Growth Growth Growth
3.5.1 Scenario Summary:
This scenario explores the development of both renewable and gas fired generation sources to supply growth driven by mining expansion and population growth:
Key Scenario Features Timing Upper North (Solar, ODX and other Mining Loads) 2019 Green Grid, Phase 3 (Paralana, Cooper Basin - Solar, 2025 Geothermal, Mining Loads) Interconnector (South East, Geothermal, Wind, Wave) 2018 Concentrating Solar Thermal (includes storage capability) 2015 Combined Cycle Gas Turbine Base load power generator 2015 Coal to Liquids (CTL) 2016 Peak Oil Price Impacts 2025
Key Scenario Features and Timing (Scenario 3)
Year Demand Capacity (MW) (MW) Technology 2010 2015 2020 2025 2030 2010 0 Coal to 2015 800 Liquids 0 0 760 760 760 2020 1360 Geothermal 0 0 0 750 2000 2025 1800 Wind 869 1448 2198 2948 3698 2030 2000 Wave 0 0 5 50 100 Solar 0 127 377 877 1877 New Mining Demand Alternative Generation Capacity (Scenario 3)
3.5.2 Issues
Coals to Liquid vs. Biofuels
An observation was made that CTL fuels may not be viable, based on the fact that they would likely be economically displaced by biofuels. While this may be true late in the period between 2020 and 2030, CTL products appear more likely to mitigate peak oil fuel price impacts in the short term.
While research is on-going - Flinders University currently has a biofuels project in progress at Torrens Island for example - biofuels produced from algae are not anticipated to be commercially available for at least 10-20 years. Meanwhile there
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are currently six commercially promising CTL projects under development in South Australia. These projects are forecasting that they will be able to start fuel production and electricity generation in 2015.
CTL competes with petroleum based diesel fuel at US$80 per barrel. Adding in costs for CCS, this cost-cross over increases to US$100-110 per barrel. Whilst high, it can be expected to be much more predictable than petroleum prices later in the next decade.
Peak oil is relevant to the mineral resources industry because many mines use diesel powered generators to source their electricity supply. If peak oil price shocks and supply shortages become a reality, it will significantly hinder mining operations that are not grid-connected. With indicators pointing towards peak oil price shocks beginning between 2010 and 2020, a three-phased approach to mitigating those impacts might be possible.
The first phase would focus on establishing CTL fuels production while continuing biofuel research. The second phase would involve a shift to biofuel production when the costs were on par with CTL products combined with a transition to electric, grid- connected vehicles as the next step.
CTL processes bring the added benefit of being capable of producing base load electricity generation. In this scenario, that is an important contribution.
3.5.3 Electricity Infrastructure Response
Based on this scenario, South Australia becomes a major exporter of electricity through the transition to a portfolio of energy sources including renewable and natural gas generation. Construction of a high capacity High Voltage Direct Current (HVDC) interconnector in the Northern South Australia network node provides SA generators direct access to the broader energy market.
HVDC is considered because typically, over distances greater than 500 km, an HVDC transmission solution is more cost effective than an Alternating Current (AC) installation.
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Figure 15: Future SA Interconnector and Main Grid Development for Renewable Energy
Figure 15 above provides a high-level, conceptual view of what the expanded network could look like in 2030. Note the indicative Scale Efficient Network Extension (SENE) zones identified on the map. SENEs in these areas would allow generators to connect to the transmission network in clusters over a period of time. This approach, coupled with the construction of a Direct Current (DC) interconnector to NSW, would unlock significant opportunity to harvest South Australia’s renewable energy resources.
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Mining projects in each of the SENE zones would directly benefit from network extensions developed in these areas. There are synergies that can be leveraged between the remote nature of renewable generation and similarly the remote location of mineral resources projects. For example, the Olympic Dam SENE zone opens up opportunities for solar, geothermal, and CTL generators to connect as well as multiple mining projects.
9000 8435 8000 7000 Wave 6000 5385 Solar 5000 Wind
4000 3340 Geothermal 3000 Coal to Liquids Capacity (MW) Capacity 1575 2000 Total 869 1000 0 2010 2015 2020 2025 2030
Figure 16: Renewable and Emergent Energy Forecast – Scenario 3. Growth Growth Growth
Figure 16 above depicts the Scenario 3 potential capacity growth profile for renewable energy technologies as well as CTL generated electricity. This profile is integrated with the implementation timeline for the infrastructure outlined in the scenario summary.
Renewable Energy Target
Under this scenario by 2016-17 the 33% Renewable Energy Target is met for both Medium and High demand. In fact, 100% of forecast energy can be achieved from renewable energy for the medium load forecast by 2021-22 and by 2024-25 for the high demand case.
Base Load Generation
Based on this scenario, it was assumed that Playford Power Station could be expected to be decommissioned by 2015 while Northern Power Station would continue to operate until 2020.
The workshop estimated that a second 500MW CCGT plant would be required in 2020 to replace Northern Power Station in the case that geothermal failed to meet expectations. It was also noted that, in this scenario, Torrens Island Power Station may face economic pressure to retire post 2020.
The mining load forecast in this scenario assumes substantial mineral expansion:
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• All projected 32 mining development projects get funded and start production in roughly 2015.
• ODX is in full production by 2020;
• Another project similar to Prominent Hill starts production in 2025; and
• Further substantial mines/expansions by 2030
3.5.4 Probability
The probability that South Australia would arrive in the end-state described by this scenario was judged as Medium – 50%.
3.5.5 Mining Index Consequence
This scenario was considered the most preferable outcome, involving an aggressive transition to renewable energy, backed up by sound market development of conventional base load generation. In the result, South Australia is flush with electricity to export, mining operations are taking off, and even though peak oil hits late in the second decade, the CTL projects that came on line in 2016 set the State up as a major transport fuels producer for the nation.
• Mineral Production Indictor: Target Exceeded
• Fraser Institute Mineral Potential Ranking: Target Exceeded
3.6 Other Scenarios
The others two scenarios considered at the scenario workshop, Scenario 4 “Luxury Power” and Scenario 5 “User Pays” are not covered in this document, due to the fact that all of the observations and issues captured against those scenarios were adequately covered in the analysis of Scenarios 1-3.
4. Remote Electricity Supply
4.1 Demand Summary
As shown in Figure 4, the large majority of mining projects in South Australia are expected to be supplied by off grid electricity sources in the years ahead. The data also indicates that the amount of electricity sourced from on-site diesel generators will significantly increase over the next 10 years.
4.2 Renewable Generation Solutions
Diesel generation may be the most appropriate and economic supply option in the short term. However, given the context of peak oil and climate change, it would be ideal if an economic solution providing reliable, renewable, on-site generation could be developed.
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South Australia’s environment and geography is such that a hybrid solution of multiple generation technologies (i.e. solar, wind, and micro-turbine) centred on a solar energy-based solution could potentially serve remote mining locations. To provide base load power to the mine site, such a solution would ideally include storage capability (i.e. thermal storage).
There may be opportunities for further research to develop a hybrid Concentrating Solar Power (CSP) distributed generation solution that is competitive with diesel generators, both in terms of cost and output.
5. Beyond 2030
“From time to time in human history there occur events of a truly seismic significance, events that mark a turning point between one epoch and the next, when one orthodoxy is overthrown and another takes its place. The significance of these events is rarely apparent as they unfold: it becomes clear only in retrospect, when observed from the commanding heights of history. By such time it is often too late to act to shape the course of such events and their effects on the day-to-day working lives of men and women and the families they support.”
Prime Minister Kevin Rudd, February 2009
In May 2007 the Australian Academy of Technological Sciences and Engineering (ATSE) published a report for the Scanlon Foundation entitled “30/50 The Technical Implications of An Australian Population of 30 Million by 2050”. The Scanlon Foundation, with its mission "to support the creation of a larger cohesive Australian society" adopted, as a working hypothesis, a future population for Australia of 30 million people by 2050. This number was based on advice from the Australian Institute for Demographic Research of the Australian National University. The aim of the 30/50 report was to determine if there were any engineering, scientific, or environmental barriers to reaching an Australian population of 30 million people by 2050.
The principal findings of the ATSE 30/50 report were:
• there are no inherent physical, resource or technological barriers to achieving the population milestone of 30 million people by 2050;
• long-term planning is imperative to ensure timely and orderly provision of needed infrastructure; and
• leadership from governments is essential in setting clear policy directions.
The study highlights the critical need for long-term leadership, planning and coordination among governments, agencies and other industry and community participants if the challenges are to be met successfully.
The following are just two visions for the applications of existing technologies to meet energy requirements by 2050.
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5.1 Space Based Solar Power
Figure 17: Space Based Solar Power
The concept of Space Based Solar Power (SBSP) involves the collection and transmission of solar power using geosynchronous satellites and rectifying antennas on the ground. The solar energy is converted to a microwave signal at the satellite and transmitted to the ground station. The rectifying antenna converts received energy to electricity which is then transmitted to customers using existing electricity infrastructure.
In 2008, U.S. and Japanese researchers crossed an important SBSP threshold when they wirelessly transmitted microwave energy between two Hawaiian islands about 90 miles (145 kilometres) apart, representing the distance through Earth's atmosphere that a transmission from orbit would have to penetrate13.
In April 2009, the California power utility Pacific Gas & Electric Co. (PG&E) announced plans to purchase clean energy generated by a satellite beaming solar power from orbit. The agreement between PG&E and Solaren Corp., still hinges on state regulatory approval. If approved, Solaren must then privately raise billions of dollars to design, launch and operate a satellite as well as an energy-receiving ground station. The satellite is scheduled to be completed by 2016.
13 Will Space-Based Solar Power Finally See the Light of Day?, Adam Hadhazy, Scientific American, April 2009
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South Australia is particularly well placed within Australia to become the hub of SBSP for the Asia-Pacific region:
• Known as The Defence State, South Australia boasts the aerospace industry base required to realise a vision like SBSP;
• The Woomera test range is centrally located within the state. This facility is already established as a rocket firing range, and has attracted international entrepreneurial interest; and
• The Royal Australian Air Force’s Aircraft Research and Development Unit (ARDU) is located in South Australia, and with it a significant aerospace engineering and testing capability.
The following potential benefits of SBSP were highlighted in a submission to the U.S. President Barack Obama as he took office in November of last year14.
• Immensely scalable — SBSP can scale to provide the energy needs of the entire global community. Most other near-term renewable options are strictly limited in scalability. As the National Security Space Office (NSSO) report states “A single kilometre-wide band of geosynchronous Earth orbit experiences enough solar flux in one year to nearly equal the amount of energy contained within all known recoverable conventional oil reserves on Earth today.”
• Safe global availability — Unlike nuclear power technology which cannot be safely shared with most of the countries on this planet because of proliferation concerns.
• Steady and assured — SBSP is a continuous, rather than intermittent, power source. It is not subject to the weather, the seasons, or the day-night cycle.
• No fundamental breakthroughs — SBSP does not require a fundamental breakthrough in either physics or engineering, such as those required by fusion.
• Highly flexible and optimal for export — SBSP could enable America to become a net energy exporter, and expand to become the world’s largest exporter of energy for the 21st and 22nd Centuries, and beyond.
Economics is the Key Barrier to SBSP. The extremely high-cost of space transportation and building spacecraft is the principal barrier. Some believe the cost of SBSP is so high that it will never be economical for base load power. The NSSO believes these cost challenges can be overcome.
14 Space Solar Power (SSP) — A Solution for Energy Independence & Climate Change
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5.2 A Global Grid
Figure 18 Global Grid
The German DESERTEC Foundation has proposed a compelling vision for Australia. Through the construction of a pan-hemispheric High-Voltage Direct Current (HVDC) power line and natural gas pipeline network stretching from the Great Australian Bight to Beijing, DESERTEC sees the opportunity for Australia to become a Clean Energy Super Power by 2050. DESERTEC proposes that a large percentage of the power transported would be generated using Concentrating Solar Thermal Power Plants located in Australia’s deserts.
According to a document entitled “The Red Paper” submitted by the DESERTEC Foundation, by 2050 roughly 10bn people will inhabit the Earth15. Yet, even today, one third of the world‘s population has only limited access to the basics of living – food, water, and energy. On the basis of current economic conditions, it will be impossible for the economically leading nations to maintain or even increase their level of prosperity while, at the same time, several billion people will be pursuing a comparable level of prosperity. The paper predicts that conflicts regarding access to natural resources — in particular water and energy — will be aggravated, changes in the climate will accelerate and the prerequisites of life for a majority of the world‘s population will be in serious danger.
According to Dr Gerhard Knies, the coordinator of TREC, the Trans-Mediterranean Renewable Energy Cooperation, a network of around 50 experts in renewable energies and sustainability, there is an even darker possibility. The unmitigated
15 DESERTEC Red Paper
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effects of Climate Change and an unsuccessful transition from the world’s dependence on fossil fuels could result in a population crash between now and 2050.
DESERTEC Australia laid the foundation of a strategic intent in a submission to Infrastructure Australia16. That submission recommended the following steps to 2050:
By exploiting its unrivalled supplies of sunshine, natural gas, wind, geothermal energy and uranium, Australia could power Asia. In coming years, Australia should capitalise on this opportunity by:
• Rapidly expanding domestic natural gas electricity - This would require building out natural gas capacity between now and 2020 at a rate of roughly 12% per year in coming years, twice the currently forecasted rate.
• Banning new coal-fired power plants without carbon capture and storage - This is common sense. But it should be accompanied by a progressive phase- out of non carbon capture equipped coal-fired power over the next 25 years. The idled capacity can be kept on standby. Owners would be compensated through higher prices for less power.
• Building out Australia's large-scale renewable energy resources such as concentrating solar power, geothermal and wind power. The market will do this anyway once coal is stripped of unfair market advantages. Smaller scale renewable energy such as solar photovoltaic and biomass also should be encouraged.
• Exporting surplus energy. As the build out of renewable energy capacity picks up speed, it will create large surpluses of clean energy that can be exported to Asia, particularly China. A combined electricity/ natural gas export infrastructure can carry the energy to market.
6. Implications for Electricity Infrastructure
This section summarises some of the key points raised in this Information Paper.
6.1 Climate Change Policies
The introduction of Government climate change policies is expected to result in large shifts in the existing pattern of generation, transmission and consumption of electricity (and gas). Many renewable energy sources are remote from the existing electricity network and changing patterns of electricity generation and demand are also expected to put pressure on the existing networks.
The outputs of the scenario-based analysis highlighted that the costs of connecting renewable generators to market are potentially very high, which will likely translate into high energy costs. The potential timelines for construction of proposed
16 DESERTEC Australia - Infrastructure Australia Submission
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infrastructure will also be challenging and the market will need to respond with timely investment to avoid the risk of a shortfall in conventional base load and peaking generation.
6.2 SENEs
The introduction of the proposed new SENE framework may through capturing economies of scale provide the opportunity to connect clusters of new generation to the transmission network that would not otherwise be economic. Future changes to congestion and locational pricing arrangements may also impact on the optimal location of new generation sources.
Several potential South Australian SENE zones that would offer opportunities to connect renewable generators as well as electrical loads for mineral resources projects in the vicinity were identified as a part of this project. The potential exists to consider the connection of new load centres within the context of the new SENE framework.
6.3 Peak Oil
The issue of the coming peak in global oil production effects electricity supply infrastructure in terms of input costs, availability of fuels and material lead times. With greater costs of oil comes an increase in every commodity that uses oil in its production or transportation to market, including construction materials. This might place upward pressure on new infrastructure costs, including transmission.
However, diesel fuel which is already experiencing very high demands within South Australia will gradually become more expensive and harder to obtain, impacting on the operating costs for mines using diesel generation to power their operations. This might tend to make grid connection more economic from some load centres.
Scenario analysis including peak oil considerations shows that securing reliable sources of diesel fuel is important to the on-going supply of electricity to a growing number of mining operations that are remote from electricity supply infrastructure.
6.4 Renewable Generation
The development of renewable generation sources poses a number of challenges for the electricity network, particularly as many of these resources are remote from the existing grid. The optimal timing and location of these projects will therefore be influenced by the costs of connection, but may be assisted by coordinated and efficiently scaled development of the required infrastructure. However, the challenge of extending the network to as yet unproven technologies remains.
The established renewable generation technologies currently being developed have largely been intermittent in nature, with typically low capacity factors, leading to lower network utilisation than conventional generation and posing added challenges for the design and operation of the network. These challenges have been managed to date but will increase as the scale of the renewable generation fleet continues to expand.
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One view based on scenario analysis shows that it is theoretically possible that South Australia’s renewable supply could exceed the State’s energy requirements between 2020 and 2030. However, analysis conducted during the scenario workshop shows that a broader market for energy must be made available in order to leverage the State’s renewable energy potential. The construction of additional interconnector capacity to the eastern states would accomplish this while serving as a mitigation measure against a shortfall in conventional generation.
6.5 Emerging Technologies
The successful deployment of carbon capture and storage and coal to liquids technologies will impact on the economics of conventional generation and influence the timing of plant retirement in response to carbon cost signals.
This will influence the rate at which other emerging technologies become commercially competitive, and in turn will impact on the pattern of future generation development on the network. The development of the transmission network will therefore be impacted by the generation investments which emerge as the competing technologies continue to develop.
Through the analysis of selected scenarios a need for timely investment to maximise the efficiency and commercial life of existing base load power plants was identified. This includes possible integration of carbon capture and storage technologies as well as consideration of solar trough technologies.
According to the RESIC/ SACOME Demand Study, many of the growing number of mining projects expect to source their electricity from generators on-site. It is likely that the majority of this off-grid electricity will be generated using diesel-powered generators. Through the information gathering process conducted as a part of this project, it was identified that South Australia has a unique opportunity to develop a secure, coal-based transport fuels production capability using Coal to Liquids processes.
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Future Electricity Infrastructure Requirements of South Australia's Resources Industry Appendices
November 2009
FUTURE ELECTRICITY INFRASTRUCTURE REQUIREMENTS OF SOUTH AUSTRALIA'S RESOURCES INDUSTRY November 2009
Appendix A Scenario Discussion
As South Australia looks to its future economic development and the impacts of climate change, appropriate energy provision becomes a priority.
The following scenarios have been devised for use in testing the sensitivities of some the key variables associated with a combination of decision-making, social, and technological change. It is important to understand that these scenarios are by no means a forecast of what might actually happen. Instead, they are simply planning tools for use in generating thought and discussion at the 5 November 2009 Scenario Workshop.
The scenarios were developed in a closed process conducted by representatives from RESIC, SACOME, and ElectraNet. The process was facilitated by Bridge 8 Pty Ltd, a consultancy that specialises in futurist theory.
A1 Methodology
The scenarios were devised using a decision-tree method where the various options around major infrastructure investment were mapped out to generate alternatives. The key infrastructure inputs included the implementation of the Green Grid, new infrastructure such as a gas plant, interconnector, and renewable energy generation plant including geothermal and solar.
A2 Assumptions
The scenarios assume that the following factors remain constant:
• Transmission via the grid is still a primary mechanism for energy provision;
• Effects of climate change and weather conditions are the same across all scenarios;
• Current policies on the use of uranium remain, and nuclear energy is not a consideration;
• Green Grid Phase 2 network extension to the Eyre Peninsula is included in each scenario; and
• The Carbon Pollution Reduction Scheme commences in 2011.
A3 Scenario descriptions
Green Green Green – where the focus is on committing to green energy infrastructure, and the system runs close to capacity.
More Snakes than Ladders – where the focus is on committing to green energy infrastructure, but the system suffers technological and investment challenges
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Growth Growth Growth – where both green infrastructure and a gas plant are built to supply a growing economy, driven primarily by the Olympic Dam expansion and other a growth in mining production in the state.
Luxury Power - where both green infrastructure and a gas plant are built, but the economic growth is slower than anticipated, partly due to delays in the Olympic Dam expansion.
User Pays – where infrastructure decisions were delayed with the expectation that the market would respond to the need.
A4 Scenario Workshop
On 5 November 2009, a workshop was conducted to analyse the scenarios. Three teams of 5-7 representatives from Government, Industry, and Academia were tasked to review each scenario. The membership of each of three teams was selected to include renewable energy, electricity generation, electricity transmission, and mineral resources experts. Each team was assigned one major focus area of economic, technical, and regulatory considerations associated with supplying electricity to South Australia’s Resources Industry within the current context.
The period to be considered by the teams was the timeframe between 2010-2030. This window was selected based on the development timelines of the various alternative energy technologies.
A5 Probability and Consequence Ratings
For each scenario, the teams were asked to assess the probability that the given scenario would be the eventual future that plays out for South Australia’s electricity infrastructure. The probability rankings were as follows:
• Low: 0-40% probability;
• Medium: 41-60% probability; or
• High: 61-100% probability.
Additionally the teams were asked to rank the consequence of each scenario in terms of impact to the Resources Industry.
The consequence was to be judged by the impact (negative or positive) to the state’s Mineral Production indicator (Measure 1.18 in the State Strategic Plan) and the state’s Fraser Institute Mineral Potential ranking. The 2008 Mineral Production indicator for South Australia was $2.873 billion. In 2008, South Australia was ranked 10th in the world in terms of Mineral Potential. The consequence rankings were as follows:
• Target Not Achieved;
• Target Achieved; or
• Target Exceeded.
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Scenario 4 “Luxury Power” and Scenario 5 “User Pays” are not covered in this document, due to the fact that all of the observations and issues captured against those scenarios were adequately covered in the analysis of Scenarios 1-3.
Growth Growth Growth More Snakes than Ladders OD comes Luxury Power online Green Green Base Load OD is Green Renewables deferred Fail beyond 2030 Geothermal online Green infrastructure + gas plant User Pays Green infrastructure Wait and See
Figure 19: Scenarios
Green Green More Snakes Growth Luxury User Pays Green than Ladders Growth Power Growth Green Grid to Eyre 9 in part 9 9 in part Green Grid to 9 8 9 9 8 Cooper Basin Inter‐Connector 9 9 9 9 8 Gas Plant 8 8 9 9 8 Geothermal 9 in part 9 9 in part Coal‐to‐Liquids 8 9 9 9 8 Solar Thermal 9 9 9 8 8 Distributed Solar 9 8 8 8 9 Upgrade of Coal 8 9 8 8 9 Power Stations
Figure 20: Scenarios reviewed
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A6 Scenario 1 - Green Green Green
Scenario Description
In this scenario, in 2010, the government strengthened its strategic focus on positioning South Australia as the leader in clean and renewable energy technologies. As a result of the desire to encourage economic development in a sustainable way, energy infrastructure to support further wind farm investment in the Eyre Peninsula was installed. The improved electricity supply infrastructure that resulted from the Green Grid, further opened up mining opportunities in this region.
The CPRS, implemented in June 2011, introduced an initially low price on carbon. As the carbon price increased later in the decade, pressure was put on electricity prices. Mining projects had to reassess their economic models, resulting in the adoption of some localised renewable generation to meet the electricity requirements of the mines.
Geothermal was projected to come on line around 2015 and so provisions were made in advance to secure the geothermal opportunities as the second element of the Green Grid. The third element, an interconnector, was completed in 2018 to enable the supply of both wind and geothermal power to the Eastern States. Geothermal was successfully contributing to base load by 2020.
By 2025, Leigh Creek coal reserves had run down and the Playford and Northern Power Stations were decommissioned. While the interconnector meant some power could be exported off-peak, during the hot summers the system was often at capacity. After potential supply shortages emerged due to reduced wind velocities on the hottest days, the focus on wind generation shifted to the late installation of concentrated solar thermal generation with storage capacity. Generally though, these shortfalls were recognised as an unfortunate side effect of living in a more sustainable way and people have grown to accept this.
South Australia is now viewed as an international leader in energy transformation, due in part to its ability to keep power costs low compared with the Eastern states that still rely on highly polluting coal, and partly because of the community’s expectations around green power.
Observations
Carbon Emissions
It was noted that both coal-fired electricity generation and CTL will have similar constraints with regards to being CO2 intensive. Since this scenario assumed a CPRS instituted in 2011, it was assumed that both the Playford and Northern power stations were decommissioned in 2025.
An observation noted during the workshop highlighted that, in the event of high oil prices CTL plus CCS could make CTL viable, even in a carbon-constrained market. Without the CCS costs being factored in, CTL produces clean, low sulphur diesel fuel and jet fuel at a price that is comparable with petroleum at $80 per barrel.
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Geothermal Base Load Supply
Based on the outputs of the energy modelling completed during the workshop, if geothermal is successful and provides the levels of base load power forecasted, this will solve the significant peak demand supply shortfall forecasted once Playford and Northern power stations retire.
Renewable Technologies Capacity Factors
Capacity factors for renewable technologies are boosted by storage capability. The following assessments regarding the capacity factors for the various technologies at peak demand were agreed during the workshop. These factors were then used in the model to determine electricity available at times of peak demand:
• Geothermal capacity factor 90% (at peak) depends on new cooling technologies being developed and available, geothermal requires air cooling and current technologies provide capacity factors of only 40%;
• Solar is well matched to peak demand periods in South Australia, therefore capacity factors may be higher at peak as discussed above, however 40% was agreed during the workshop;
• The capacity factor for wind generated electricity at peak demand is reduced to 3%. This value is supported by the 2009 Electricity Supply Industry Planning Council Annual Planning Review;
• Wave at peak demand, capacity factor is 20%
A7 Scenario 2 – More Snakes Than Ladders
Scenario Description
In this scenario, in 2010, the government continued to encourage mining and economic development for the state while aiming to address the community concerns associated with climate change. The CPRS, implemented in June 2011, introduced an initially low price on carbon. As a result of the desire to encourage economic development in a sustainable way, energy infrastructure to support further wind farm investment in the Eyre Peninsula was installed. Geothermal was projected to come on line as a base load option by 2015, with an expansion of the Green Grid to this region projected. The outlook was still optimistic; therefore an inter-connector to the Eastern States was also planned for completion by 2018 to supply both wind and geothermal power.
The impact of the CPRS was initially less than anticipated, but as the carbon price increased, there was an economic slowdown in late 2014. This delayed a number of mining projects, including the ODX.
Further expansion of the Green Grid to the Cooper Basin was shelved, driven by difficulties in securing investment. Technical issues with geothermal were also not resolved and commercial capacity unproven.
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The growing issues with renewable supplies and the state’s reliance on ageing coal power stations concerned the government. Additional R&D investment was made into geothermal and the inter-connector was installed in order to allow for both import and export of electricity. The power line to the Upper North was commissioning in 2019 and by mid 2020, the ODX has commenced shipping concentrate.
By 2025, Leigh Creek coal reserves had been depleted and little capital works had been put into the Playford and Northern Power Stations. Geothermal was still not performing to expectations. Instead of being used to export green energy, the inter- connector was being used to cover the shortfall in South Australian supply by importing electricity. Investment in capital works to install solar thermal trough systems at both the Playford and Northern Power Stations was finally undertaken to improve efficiency of these coal-fired generators.
Peak oil has seen a spike in petroleum prices and high demand for alternative liquid fuels as a replacement. The costs of power have slowed further economic development and many deposits that were touted for production past 2030 have proved uneconomic with the currently available technologies. Materials and transport costs have also increased, exploding the budgets for new capital projects and planning for a new gas plant has had to be shelved.
By 2030, South Australia is reliant on the import of electricity and ageing energy infrastructure, and facing an uncertain economic future.
A8 Scenario 3 – Growth Growth Growth
Scenario Description
In 2010, following a strategic review of energy demand and supply forecasts, the level of uncertainty regarding geothermal development timelines was such that the government approved an application to construct an additional base-load power station to be commissioned by 2015.
Community opposition to the scheme was initially high, but was addressed by backing the further development of renewables in the form of concentrating solar thermal generation with storage capability starting in 2015. The gas plant was commissioned soon after and located adjacent to geothermal development prospects with the expectation that the electricity infrastructure could be shared.
As a result of the desire to encourage economic development in a sustainable way, energy infrastructure to support further wind farm investment in the Eyre Peninsula was installed. The improved electricity supply infrastructure that resulted opened up mining opportunities in this region, including Coal-to-Liquids projects in 2016.
Geothermal came on line in 2017 with full capacity for base-load power by 2025.
An inter-connector to the Eastern States was built in 2018 to supply both wind and geothermal power.
ODX moved ahead, and first concentrate shipped in early 2019 with additional power needs supplied through a new transmission line. This transmission line also
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facilitated the dispatch of electricity generated by CTL projects in the Upper North Region.
Peak oil effects hit petrol prices hard in 2025; however, the abundance of high quality diesel fuel and jet fuel from coal-to-liquids production significantly mitigated the cost impacts to South Australians. Demand for electric cars increased along with demand for electricity. Capacity for this was easily met by the grid, and the cost of power was kept at reasonable levels. Other states tried to compensate by building gas plants at this time, but found that the significantly increased capital costs, along with political pressure to subsidise fuel and food expenses, made this level of investment extremely difficult.
In 2030, with significant excess base load generating capacity from concentrating solar thermal plant and geothermal plants, South Australia is the major domestic supplier of green electricity.
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Appendix B Scenario Workshop Attendees
Surname First Name Title Organisation Expertise
Workshop Facilitators (Lead - Sean Leyden)
Alford Kristin Managing Director Bridge 8 Pty Ltd Futurist Leyden Sean Senior Manager, Network Portfolio ElectraNet Project Management Team 1 - Economics (Red, Team Captain - Dr Kristin Alford) Congreave Michael Manager Alternative Energy Santos Alternative Energy Forbes Jonathan Director - Industry Development SACOME Strategic Investment Haddow John Principal Strategic Network ElectraNet Network Planning Planning Engineer Jones Keith Manager, Climate Change & DTED Climate Change Sustainability Odlum Keith Senior Energy Project Officer DTEI Markets Rowett Andrew Manager, Minerals Information and PIRSA Mineral Resources Promotion Ward Steve General Manager, Strategic PIRSA Strategic Investment Division Investment Team 2 - Technical (Blue, Team Captain - Nigel Long) Dayal Vinod Senior Strategic Planning Engineer ElectraNet Network Planning Long Nigel Director, Environment and SACOME Climate Change Sustainability Nathan "Gus" Director, Centre for Energy The University of Renewable Energy Technology Adelaide Walker Sam Program Manager Olympic Dam PIRSA Mineral Resources Walton Malcolm Principal Project Officer Resource PIRSA Mineral Resources Development MER Williamson Mark B&B Power Coal Generation Team 3 - Regulatory (Green, Team Captain - Joe Mastrangelo) Abbot Peta Senior Geologist PIRSA Mineral Resources Korte Rainer Executive Manager, Regulation ElectraNet Regulation and and Corporate Services Network Planning Mastrangelo Joe Director, RESIC RESIC Strategic Investment Oakeshott Craig Senior Manager, Strategy & AEMO Network Planning Economics Way Catherine Industry Development Manager DPC Renewable Energy
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Appendix C Summary of Existing Infrastructure by Region
The following section provides a regional summary of the existing South Australian electricity transmission network.
Maps have been developed to aid in gaining an understanding of the current electricity transmission network relative to existing and proposed mining projects.
In addition, the location of existing and proposed renewable and emergent technology generation projects has been captured on these maps to serve as an aid in infrastructure discussions and planning.
Figure b.1.0 provides a high level overview of these different regions of South Australia.
C1 Eyre
ElectraNet currently supplies electricity to the Eyre Peninsula via a 275kV and 132kV electricity transmission network. Substations at Whyalla, Middleback, Yadnarie, Wudinna and Port Lincoln provide reliable connections to ETSA Utilities’ distribution systems and to direct connect customers (see Figure b.1.1).
C2 Upper North
ElectraNet currently supplies electricity to the Upper North Region via a 275kV and 132kV electricity transmission network. A substation at Davenport near Port Augusta provides reliable connections to ETSA Utilities’ distribution systems and to direct connect customers. The 132 kV transmission lines north of Port Augusta are radial, and substations at Mount Gunson, Pimba, Woomera, Neuroodla and Leigh Creek provide additional connections to ETSA Utilities’ distribution systems and to direct connect customers (see Figure b.2).
C3 Mid North
ElectraNet currently supplies electricity to the Mid North region via a 132 kV electricity transmission network. Substations at Roseworthy, Dorrien, Templers, Waterloo, Hummocks, Kadina East, Dalrymple, Ardrossan West, Brinkworth, Bungama (near Port Pirie) and Baroota provide reliable connections to ETSA Utilities’ distribution systems and to direct connect customers (see Figure b.1.3).
C4 Riverland
ElectraNet currently supplies the Riverland region from substations at Berri, Monash and North West Bend, all energised via a 132kV electricity transmission network. This system provides reliable and secure electricity supply to ETSA Utilities’ distribution system (see Figure b.1.4).
Page A9 FUTURE ELECTRICITY INFRASTRUCTURE REQUIREMENTS OF SOUTH AUSTRALIA'S RESOURCES INDUSTRY November 2009
C5 South East
ElectraNet currently supplies electricity to the South East via a 132kV electricity transmission network. Substations at Tailem Bend, Keith, Kincraig near Naracoorte, Penola West, Mount Gambier, Blanche (west of Mount Gambier) and Snuggery near Millicent, provide reliable connections to ETSA Utilities’ distribution systems (see Figure b.1.5).
Page A10 FUTURE ELECTRICITY INFRASTRUCTURE REQUIREMENTS OF SOUTH AUSTRALIA'S RESOURCES INDUSTRY November 2009
This page is intentionally left blank
Page A11
Figure B.1.0 Figure
LOCATION MAP of SUB-REGIONS of MAP LOCATION
of South Australia's resources industry resources Australia's South of
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Figure B.1.1 Figure
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203834_004
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AS OF 2010 OF AS
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MID NORTH REGION NORTH MID
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astructure requirements astructure infr electricity Future
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¢
50 MW 50
136°0'E 136°30'E 137°0'E 137°30'E 138°0'E 138°30'E 139°0'E 139°30'E FUTURE ELECTRICITY INFRASTRUCTURE REQUIREMENTS OF SOUTH AUSTRALIA'S RESOURCES INDUSTRY November 2009
Appendix D Resource Maps
Page A12 FUTURE ELECTRICITY INFRASTRUCTURE REQUIREMENTS OF SOUTH AUSTRALIA'S RESOURCES INDUSTRY November 2009
This page is intentionally left blank
Page A13
Figure 3.5.3.0 Figure
INFRASTRUCTURE SCENARIO ZONES SCENARIO INFRASTRUCTURE
LOCATION MAP of MAP LOCATION
of South Australia's resources industry resources Australia's South of
Future electricity infrastructure requirements infrastructure electricity Future
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Figure 3.5.3.1 Figure
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2010 – 2020 – 2010
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50 MW 50
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of South Australia's resources industry resources Australia's South of Yunta ¢
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Figure 3.5.3.2 Figure
138°0'E 140°0'E
2020 – 2030 – 2020
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2010 – 2020 – 2010 *# 36°0'S
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Figure 3.5.3.6 Figure
136°0'E 140°0'E 138°0'E
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G F
Renewable energy Renewable Petroleum Wells Petroleum
) "
O Harbor Victor 120 MW 120 34 MW 34
Developing projects Developing Gas pipeline Gas
G F F R G
20 MW 20
( !
I
ð
Gas facility Gas mines Operating
F A G 60 MW 60 ( ! ANGAS: 5 MW 5 ANGAS:
Pinnaroo
) "
( ! Tailem Bend Tailem
*# Bridge
10 MW 10
Murray
25 MW 25
KANMANTOO
G F
) "
F G 91 MW 91
(
*# *# *#! *#
Edithburgh )
*# *# *# "
)
" *#
Mount Gambier Mount # BIRD IN HAND: 10 MW 10 HAND: IN BIRD *
( ! Mannum
ADELAIDE
) "
Dalrymple ) "
*# Tungkillo *# Vincent St 4 MW 4
*#*# ê *#
( ! # Gulf MINDARIE *
*#*# *# *# *# *#*# MW 59.4
F
*#*# G
ADELAIDE *#
*#*# Terminal Lincoln Port
)
" *#
Port Lincoln Port
) "
) " ê Port Lincoln Port
) " PORT LINCOLN PORT
Renmark *#
Roseworthy
Loxton ê
ANGASTON Port Pirie Port
)
" *# ) "
Whyalla
)
) "
" *# Dorrien
) "
Berri *#
Port Augusta Port Templers
Ardrossan West Ardrossan ) "
Barmera
Ceduna *#
) "
) "
( *# !
Wakefield
*# 1 Rinjin
)
"
Tarcoola Waikerie
Leigh Creek Leigh ) Renmark
"
Port ) ) "
"
) "
Olympic Dam Olympic
Uwibami 1 Uwibami
150 MW 150
)
" S
34°0'S p
(
!
e
G F Morgan (
!
n
Hummocks
Coober Pedy Coober
c
Raitaro 1 Raitaro
e
r
)
" Moonta 117 MW 117
G 96 MW 96
)
" *# )
" Waterloo
*# u G F G F G F
Moomba l
*# f
ê 34°0'S MINTARO
*# *# East Kadina
) " *# MW 180
SOUTH AUSTRALIA SOUTH *#
) "
*# MW 55
Kadina
Robertstown *#
)
"
G F
) Wallaroo
"
Marla #
Oodnadatta *
) Mintaro "
G F
( !
100 MW 100 129 MW 129 Chowilla 1 Chowilla
WILGERUP
98.7 MW 98.7
Snowtown
F G Burra
136°0'E 138°0'E 140°0'E
( ! ) " *#
) *#
203834_012
Figure 3.5.3.7 Figure
G F 130°0'E 136°0'E 134°0'E 132°0'E
2010 – 2020 – 2010
? MW ? 32°0'S MUSGRAVE SCENARIO MUSGRAVE
( !
GULLIVERS ) "
32°0'S Ceduna
infrastructure requirements infrastructure
ture electricity ture fu Australia's South
Gairdner
Everard
25 MW 25
( ! Lake
Lake TRIPITAKA
Projection: Zone 53 Zone Projection:
0101020Kilometers 200 150 100 50 0
Pimba
50 MW 50 Harris
TUNKILLIA
(
Lake !
Woomera ) *#"
*# MW 25 Woomera
JACINTH/AMBROSIA
) " Glendambo
( !
( ! Tarcoola
W
) "
E Olympic Dam Olympic
S Blanche 1 Blanche
T
) " ( !
Olympic Dam West Dam Olympic E
(
*#!
R
300 MW 300
Maralinga
¢ N
OLYMPIC DAM OLYMPIC
¢
¢
100 MW 100
30°0'S )
" A ¢ ¢ HAWKSNEST
U
30°0'S
( ! (
! S
( !
( ! ( ! ( ! ( !
¢ T
CHALLENGER: 5 MW 5 CHALLENGER:
( ! ¢
66 000 volts 000 66 R ¢
¢ A 30 MW 30 ¢
132 000 volts 000 132
L PROMINENT HILL PROMINENT
( !
I
275 000 volts 000 275 A
100 MW 100 ( !
Woomera Prohibited Area Prohibited Woomera
Woomera Prohibited Area Prohibited Woomera PECULIAR KNOB PECULIAR Transmission lines Transmission
66 MW 66
*# MW 100
132 MW 132 CAIRN HILL CAIRN (
*# !
275 MW 275 *#
Wave Substations
ê )
"
Coober Pedy Coober Wind Less than 500 MW 500 than Less G F
ê
Solar Greater than 500 MW 500 than Greater ¢
Power station Power Geothermal
Emu
( !
) "
Oil
' Proposed renewable energy renewable Proposed
F G Gas Wind '
( !
¢ Eyre CO Solar 2
' 560 MW 560
Lake ( ! ARCKARINGA Petroleum Wells Petroleum energy Renewable
28°0'S
Gas pipeline Gas projects Developing
( !
(
28°0'S !
ð
Gas facility Gas mines Operating
( ! ( !
( !
Mount Gambier Mount
) "
) " Oodnadatta
Mintabie
) "
) " Marla
ADELAIDE
) "
) "
Port Lincoln Port
) "
Renmark
Port Pirie Port
) "
Whyalla
) "
) "
Port Augusta Port
) "
Ceduna
Tarcoola Leigh Creek Leigh
)
"
) "
) " Olympic Dam Olympic
26°0'S
) "
Coober Pedy Coober Moomba
26°0'S
) "
SOUTH AUSTRALIA SOUTH
) "
NORTHERN TERRITORY NORTHERN Oodnadatta Marla ) "
130°0'E 132°0'E 134°0'E 136°0'E
203834_017
Figure 3.5.3.8 Figure
G F 130°0'E 136°0'E 134°0'E 132°0'E
G F
2020 – 2030 – 2020
? MW ? 32°0'S MUSGRAVE SCENARIO MUSGRAVE
( !
GULLIVERS ) "
32°0'S Ceduna
infrastructure requirements infrastructure
ture electricity ture fu Australia's South
Gairdner
Everard
25 MW 25
( ! Lake
Lake TRIPITAKA
Projection: Zone 53 Zone Projection:
0101020Kilometers 200 150 100 50 0
Pimba
50 MW 50 Harris
TUNKILLIA
( Lake ! Woomera
) *#"
*# MW 25 Woomera
JACINTH/AMBROSIA
Glendambo ) "
( !
( ! Tarcoola
W
¢
¢
) "
¢ E Olympic Dam Olympic ¢
S
Blanche 1 Blanche
¢ T
) " ( !
Olympic Dam West Dam Olympic E
(
*#!
R
300 MW 300
Maralinga
¢ N
OLYMPIC DAM OLYMPIC
¢
¢
100 MW 100
30°0'S )
" A ¢ ¢ HAWKSNEST
U
30°0'S
( ! (
! S
( !
( ! ( ! ( ! ( !
¢ T
CHALLENGER: 5 MW 5 CHALLENGER:
( ! ¢
66 000 volts 000 66 R ¢
¢ A 30 MW 30 ¢
132 000 volts 000 132
L PROMINENT HILL PROMINENT
( !
I
275 000 volts 000 275 A
100 MW 100 ( !
Woomera Prohibited Area Prohibited Woomera
Woomera Prohibited Area Prohibited Woomera PECULIAR KNOB PECULIAR Transmission lines Transmission
66 MW 66
*# MW 100
132 MW 132 CAIRN HILL CAIRN (
*# !
275 MW 275 *#
Wave Substations
ê )
"
Coober Pedy Coober Wind Less than 500 MW 500 than Less G F
ê
Solar Greater than 500 MW 500 than Greater ¢
Power station Power Geothermal
Emu
( !
) "
Oil
' Proposed renewable energy renewable Proposed
F G Gas Wind '
( !
¢ Eyre CO Solar 2
' 560 MW 560
Lake ( ! ARCKARINGA Petroleum Wells Petroleum energy Renewable
28°0'S
Gas pipeline Gas projects Developing
( !
(
28°0'S !
ð
Gas facility Gas mines Operating
( ! ( !
( !
Mount Gambier Mount
) "
) " Oodnadatta
Mintabie
) "
) " Marla
ADELAIDE
) " ¢ ¢
) "
Port Lincoln Port
) "
¢ ¢
Renmark ( !
¢
¢
( !
Port Pirie Port
) "
Whyalla
) "
( !
) "
Port Augusta Port
) "
Ceduna
Tarcoola Leigh Creek Leigh
)
"
) "
) " Olympic Dam Olympic
26°0'S
) "
Coober Pedy Coober Moomba
26°0'S
) "
SOUTH AUSTRALIA SOUTH
) "
Oodnadatta
NORTHERN TERRITORY NORTHERN Marla ) "
130°0'E 132°0'E 134°0'E 136°0'E
203834_011
Figure 3.5.3.9 Figure
G F
100 MW 100
130°0'E 136°0'E 134°0'E 132°0'E
2010 – 2020 – 2010
S
p
e
n
c
WEST COAST SCENARIO COAST WEST e
r
34°0'S G
u
l f
infrastructure requirements infrastructure 34°0'S
110 MW 110
G F
G F
55 MW 55
ture electricity ture fu Australia's South 100 MW 100
49.5 MW 49.5
WILGERUP
Cleve
G F
54 MW 54 G F
Yadnarie (
!
) "
Elliston
F G
70 MW 70
Projection: Zone 53 Zone Projection: *# ) "
? MW ?
G F (
*# !
Mt Millar Mt BRAMFIELD
010102020Kilometers 250 200 150 100 50 0
G F ? MW ?
WARRAMBOO
( ! (
*# ! G F
Wudinna
) "
#Wudinna F * G
100 MW 100
? MW ?
WILCHERRY HILL WILCHERRY
( ! Streaky Bay Streaky POOCHERA
) "
( !
50 MW 50
( !
MENNINNIE DAM MENNINNIE G F
G F ? MW ?
32°0'S
GULLIVERS ( !
) "
32°0'S Ceduna
66 000 volts 000 66
132 000 volts 000 132
275 000 volts 000 275 Everard Gairdner 25 MW 25
TRIPITAKA ( ! Lake Lake Woomera Prohibited Area Prohibited Woomera
Transmission lines Transmission
66 MW 66 *# *
132 MW 132
Pimba
50 MW 50
*# Harris
275 MW 275 TUNKILLIA
( ! Lake
Woomera )
*# *#"
Wave
Substations *#
W Woomera
ê
Wind Less than 500 MW 500 than Less
G F
25 MW 25 E
Glendambo ) "
ê
( !
JACINTH/AMBROSIA S Solar
Greater than 500 MW 500 than Greater
¢
(
! T
Tarcoola
Power station Power Geothermal E
( !
R
) "
Oil
' Proposed renewable energy renewable Proposed
Olympic Dam Olympic N
F G Gas
Wind Blanche 1 Blanche
' A
) "
( !
U
Olympic Dam West Dam Olympic ¢
CO Solar
2 '
( *#!
S
300 MW 300
Petroleum Wells Petroleum energy Renewable
¢ T
OLYMIC DAM OLYMIC ¢
100 MW 100
Maralinga R
¢ Gas pipeline Gas
Developing projects Developing 30°0'S
) " ( ! HAWKSNEST ¢
¢ A
ð
Gas facility Gas mines Operating 5 MW 5
( ! L
30°0'S
CHALLENGER ( ! ( !
( ! ( ! ( ! I
( ( ! !
¢ A
( ! ¢
¢
¢
30 MW 30 ¢
Mount Gambier Mount
PROMINENT HILL PROMINENT ) " ( !
100 MW 100 ( !
Woomera Prohibited Area Prohibited Woomera
PECULIAR KNOB PECULIAR
100 MW 100
( !
CAIRN HILL CAIRN
ADELAIDE
Port Lincoln Port ) "
) "
) "
Renmark
)
" Coober Pedy Coober
Port Pirie Port
) "
Whyalla
) "
) "
Port Augusta Port
) " Ceduna
Emu
) "
Tarcoola Leigh Creek Leigh
)
"
) "
) "
Olympic Dam Olympic
( !
Lake Eyre Lake
560 MW 560
( !
ARCKARINGA
) "
Coober Pedy Coober 28°0'S
Moomba
) "
( ! SOUTH AUSTRALIA SOUTH 28°0'S
( !
) "
Oodnadatta
Marla ) "
( !
130°0'E 132°0'E 134°0'E 136°0'E
203834_016
Figure 3.5.3.10 Figure
G F
100 MW 100
130°0'E 136°0'E 134°0'E 132°0'E
2020 – 2030 – 2020
G F S
p
e
n
G F c
WEST COAST SCENARIO COAST WEST e
r
34°0'S G
u
l f
G F infrastructure requirements infrastructure 34°0'S
110 MW 110
G F
G F
55 MW 55
G F ture electricity ture fu Australia's South 100 MW 100
49.5 MW 49.5
WILGERUP
Cleve
G F
54 MW 54 G F
Yadnarie (
!
) "
Elliston
F G
70 MW 70
Projection: Zone 53 Zone Projection: *# ) "
? MW ?
G F (
*# !
Mt Millar Mt
BRAMFIELD
G F
010102020Kilometers 250 200 150 100 50 0
G F ? MW ?
WARRAMBOO
( ! (
*# !
G F
G F
Wudinna
) "
#Wudinna F * G
100 MW 100
? MW ?
WILCHERRY HILL WILCHERRY
POOCHERA Streaky Bay Streaky
( !
) "
( !
50 MW 50
( !
MENNINNIE DAM MENNINNIE G F
G F
G F ? MW ?
32°0'S
GULLIVERS ( !
) "
32°0'S Ceduna
66 000 volts 000 66
132 000 volts 000 132
275 000 volts 000 275 Everard Gairdner 25 MW 25
TRIPITAKA ( ! Lake
Lake Woomera Prohibited Area Prohibited Woomera
Transmission lines Transmission
66 MW 66 *# *
132 MW 132
Pimba
50 MW 50
*# Harris
275 MW 275 TUNKILLIA
( ! Lake
Woomera )
*# *#"
Wave
Substations *#
W Woomera
ê
Wind Less than 500 MW 500 than Less
G F
25 MW 25 E Glendambo
) "
ê
( !
JACINTH/AMBROSIA S Solar
Greater than 500 MW 500 than Greater
¢
(
! T Tarcoola
Power station Power Geothermal E
(
!
¢
¢ R
)
"
Oil
¢ '
Proposed renewable energy renewable Proposed N Olympic Dam Olympic
¢
F G Gas
Wind Blanche 1 Blanche '
¢ A
) "
( !
U
Olympic Dam West Dam Olympic ¢
CO Solar
2 '
( *#!
S
300 MW 300
Petroleum Wells Petroleum energy Renewable
¢ T
OLYMIC DAM OLYMIC ¢
100 MW 100
Maralinga R
¢ Gas pipeline Gas
Developing projects Developing 30°0'S
) " ( ! HAWKSNEST ¢
¢ A
ð
Gas facility Gas mines Operating 5 MW 5
( ! L
30°0'S
CHALLENGER ( ! ( !
( ! ( ! ( ! I
( ( ! !
¢ A
( ! ¢
¢
¢
30 MW 30 ¢
Mount Gambier Mount
PROMINENT HILL PROMINENT ) " ( !
100 MW 100 ( !
Woomera Prohibited Area Prohibited Woomera
PECULIAR KNOB PECULIAR
100 MW 100
( !
CAIRN HILL CAIRN
ADELAIDE
Port Lincoln Port ) "
) "
) "
Renmark
)
" Coober Pedy Coober
Port Pirie Port
) "
Whyalla
) "
) "
Port Augusta Port
) " Ceduna
Emu
) "
Tarcoola Leigh Creek Leigh
)
"
) "
) "
Olympic Dam Olympic
( !
Lake Eyre Lake
560 MW 560
( !
ARCKARINGA
) "
Coober Pedy Coober 28°0'S
Moomba
) "
( ! SOUTH AUSTRALIA SOUTH 28°0'S
( !
) "
Oodnadatta
Marla ) "
( !
130°0'E 132°0'E 134°0'E 136°0'E