High Temperature Solar Thermal Technology Roadmap

121 Bay Road, Sandringham VIC 3191, Australia Ph: +61 (0)3 9502 0019 Fax: +61 (0)3 9533 1433

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ABN: 53 099 078 485

HIGH TEMPERATURE SOLAR THERMAL TECHNOLOGY ROADMAP

Prepared for the

New South Wales and Victorian Governments

by

WYLD GROUP PTY LTD

in conjunction with

Disclaimer: While Wyld Group and MMA endeavour to provide reliable analysis and believe the material presented is accurate, neither will be liable for any claim by any party acting on such information.

WYLD GROUP AND MMA FINAL

© New South Wales and Victorian Governments 2008

The Steering Committee overseeing development of this roadmap comprised:

Victorian Department of Primary Industries (lead agency for Victoria)

Victorian Department of Sustainability and Environment

Victorian Department of Premier and Cabinet

Sustainability Victoria

Commonwealth Department of Climate Change

South Australian Department of Premier and Cabinet

NSW Department of Water and Energy

NSW Department of State and Regional Development

NSW Department of Environment and Climate Change (lead agency for NSW) Of these departments and agencies, the following contributed funding for its development:

Victorian Department of Primary Industries

Victorian Department of Sustainability and Environment

Sustainability Victoria

NSW Department of Water and Energy

NSW Department of Environment and Climate Change



Table of Contents EXECUTIVE SUMMARY ...................................................................................... I

1 INTRODUCTION ....................................................................................... 1

1.1 Background to this roadmap ....................................................................... 1

1.2 The methodology for this roadmap ............................................................... 1

2 HTST TECHNOLOGIES — STATE-OF-THE-ART ........................................................ 3

2.1 Parabolic trough ..................................................................................... 4 2.1.1 Technology ................................................................................................... 4 2.1.2 Commercial activities ...................................................................................... 6

2.2 Linear Fresnel ........................................................................................ 7 2.2.1 Technology ................................................................................................... 7 2.2.2 Commercial activities ...................................................................................... 8

2.3 Power tower .......................................................................................... 9 2.3.1 Technology ................................................................................................... 9 2.3.2 Commercial activities ..................................................................................... 11

2.4 Parabolic dish .......................................................................................11 2.4.1 Technology .................................................................................................. 11 2.4.2 Commercial activities ..................................................................................... 13

2.5 High temperature thermal storage ..............................................................13

2.6 Solar thermochemical processes .................................................................15

3 HTST — OVERSEAS MARKET GROWTH AND COST PROJECTIONS .................................... 17

3.1 European Union – Middle East North Africa (EU-MENA) .......................................17

3.2 USA ....................................................................................................19

3.3 Cost perspectives ...................................................................................21

4 HTST — MARKET POTENTIAL AND BARRIERS IN AUSTRALIA ........................................ 24

4.1 Australia’s electricity market characteristics ..................................................24

4.2 Role of renewable generation ....................................................................24

4.3 Economics of HTST generation ...................................................................26 4.3.1 Methodology ................................................................................................ 28 4.3.2 Assumptions ................................................................................................. 29 4.3.3 Cost comparisons .......................................................................................... 30

4.4 Market potential ....................................................................................35 4.4.1 Competition principles .................................................................................... 35 4.4.2 Market segments ........................................................................................... 36

4.5 Role of HTST .........................................................................................40

4.6 Market barriers ......................................................................................41

5 STRATEGIC ANALYSIS ............................................................................... 44

5.1 Prime drivers of change on Australia’s energy systems ......................................44

5.2 The need for HTST in Australia ...................................................................45

5.3 The potential contribution of HTST to Australia’s needs ....................................46 5.3.1 Electricity generation ..................................................................................... 46 5.3.2 Industrial process heat .................................................................................... 47 5.3.3 Thermochemical processes ............................................................................... 48



5.3.4 Stakeholders’ views ....................................................................................... 49

5.4 Key barriers and challenges for HTST ...........................................................50

5.5 Australia as a ‘taker’ or ‘maker’ .................................................................51

5.6 SWOT analysis .......................................................................................52

6 CONCLUSIONS ...................................................................................... 55

7 A ROADMAP FOR AUSTRALIA ....................................................................... 58

7.1 Vision .................................................................................................58

7.2 Recommended strategies ..........................................................................58

7.3 Options for key activities ..........................................................................59

7.4 Roadmap implementation .........................................................................64

APPENDIX A HTST MARKET POTENTIAL ANALYSIS .................................................. 66

A.1 Australia’s electricity market characteristics ..................................................66 A.1.1 Electricity Market Arrangements ........................................................................ 67

A.2 Role of Renewable Generation ...................................................................68

A.3 Economics of High Temperature Solar Thermal Generation .................................71 A.3.1 Method ....................................................................................................... 73 A.3.2 Assumptions ................................................................................................. 75 A.3.3 Cost comparisons .......................................................................................... 79 A.3.4 Summary .................................................................................................... 89

A.4 Market Potential ....................................................................................89 A.4.1 Competition principles .................................................................................... 90 A.4.2 Peak lopping market segment ........................................................................... 91 A.4.3 High load duty market segment ......................................................................... 91 A.4.4 Solar assist market segment ............................................................................. 99 A.4.5 End-of-grid-support market segment ................................................................. 101 A.4.6 Remote area power supplies market segment ...................................................... 102

A.5 Role of HTST ....................................................................................... 103

APPENDIX B STAKEHOLDERS CONSULTED .......................................................... 105



Abbreviations ANU Australian National University

ANZSES Australian and New Zealand Solar Energy Society

APEC Asia-Pacific Economic Cooperation

APP Asia-Pacific Partnership on Clean Development and Climate

CCG COAG Climate Change Group

CCGT Combined Cycle Gas Turbine

CH4 Methane

COAG Council of Australian Governments

CO2 Carbon dioxide

CO2-e Carbon dioxide equivalent

CSES Centre for Sustainable Energy Systems at ANU

CSIRO Commonwealth Scientific and Industrial research Organisation

CSP Concentrating Solar Power

°C Degrees Celsius

DKIS Darwin-Katherine Interconnected System

DLR German Aerospace Centre

DOE United States Department of Energy

DWE NSW Department of Water and Energy

ESAA Energy Supply Association of Australia

€ Euro currency unit

EU European Union

GSP Gross state product

HCG High-level Coordination Group

HDI Household disposable income

HTF Heat Transfer Fluid

HTST High Temperature Solar Thermal

HVDC High Voltage Direct Current

GHG Greenhouse Gas

GW Gigawatt

GWh Gigawatt-hours

IEA International Energy Agency

ISCCS Integrated Solar Combined Cycle System

IGCC Integrated Gasification Combined Cycle Plants

IMO Independent Market Operator

K degrees Kelvin

kWh Kilowatt-hour

LEC Levelised Energy Cost

LFR Linear Fresnel Collector

LNG Liquefied Natural Gas



m2 Square metres

MCE Ministerial Council on Energy

MENA Middle East North Africa

MJ Megajoule

MMA McLennan Magasanik Associates

MRET Mandatory Renewable Energy Target

MW Megawatt

MWe or MWelect Megawatt electrical

MWh Megawatt-hour

NEM National Electricity Market

NGGI National Greenhouse Gas Inventory

NRET NSW Renewable Energy Target

NSW New South Wales

OECD Organisation for Economic Co-operation and Development

PCM Phase Change Materials

PV Photovoltaic

R&D Research and Development

RE Renewable Energy

REC Renewable Energy Certificates, which are created under the Australian MRET Scheme

RECWA Renewable Energy Certificates Western Australia, which are created by eligible generators under the RETWA scheme

REDI Renewable Energy Development Initiative

REMMA Renewable Energy Market Model Australia

RETWA Renewable Energy Target Western Australia

RPS Renewable Portfolio Standard

RTIL Room temperature Ionic Liquids

SEDA Sustainable Energy Development Authority

SES Stirling Energy Systems, Inc.

SHP Solar Heat and Power Pty Ltd

STEM Short Term Electricity Market

SWIS South West Interconnected System

TWh Terawatt-hours

UCC Ultra Clean Coal

US or USA United States of America

VRET Victorian Renewable Energy Target

W Watt

Wp Watt peak

WEM Western Australian Electricity Market

y Year


© New South Wales and Victorian Governments 2008 i

Executive Summary On the 13 April 2007, the Council of Australian Governments (COAG) announced the development of four energy technology roadmaps: coal-gasification, geothermal, hydrogen and high temperature solar thermal (HTST). The objective of the HTST roadmapping process was to establish a plan for the development of HTST technology and research in Australia. To this end, the roadmap identifies, among other outputs, the suggested role of Australian governments, industry and researchers in enabling and facilitating the development of an HTST industry and technologies in Australia. It recommends a range of strategies and initiatives; and suggests responsibilities, and proposes a time frame, for implementation. HTST has advantages over a number of other renewable energy options:

• It can integrate well with conventional thermodynamic cycles and power generation equipment as well as complementary renewable technologies such as geothermal energy.

• It offers dispatchable power when integrated with thermal storage and/or gas co-firing, and thus good matching between solar insolation and the growth in electrical demand in many countries that is driven by air conditioning loads during summer.

• The collector technology itself is constructed of predominantly conventional materials (glass, steel, concrete) — no scientific breakthroughs are required for the cost to continue to drop as the volume of megawatts deployed increases.

However, apart from a number of small-scale trials in various countries, the Solar Energy Generating Systems (SEGS) plants built between 1984 and 1989 in southern California were the only commercial HTST electricity plants in operation until a re-birth in market interest and renewed enthusiasm for deployment commenced in 2005. The analysis in this roadmap shows that this enthusiasm is growing — rapidly. By early 2008 over 6 GW of HTST-based electricity generation projects have been announced for deployment by 2012 in Europe (particularly Spain), USA and Middle-East North Africa region. While not all of these announced projects may be constructed and/or their proposed timeframe for deployment by 2012 may be optimistic, provided that current policy and fiscal incentives remain in place a high proportion of these projects appear likely to receive financing and achieve commercial operation — laying a foundation for sustainable growth for HTST globally. Importantly, major project development companies, component suppliers and utilities in Europe and the USA are behind much of the growth in commercial deployment of HTST electricity plants. The presence of these large companies alongside the innovative, usually-smaller, HTST technology suppliers has been a significant and positive change to the global HTST industry structure over the last three years. The market potential in Australia of HTST electricity generation was examined through the use of a model that determines the levelised energy cost of various generation options in the electricity markets in Australia. A number of cost-modelling case studies were developed to examine the potential, with these sites being representative of the market opportunities available for HTST generation. Locations covered were: Port Augusta in South Australia, north-west Victoria and central/north-west NSW (all connected to the National Electricity Market); Kalbarri in Western Australia (connected to the South West Interconnected System); Katherine (connected to the Darwin-Katherine Interconnected System); and remote locations in the Northern Territory and Western Australia. Based on the cost-modelling and market potential analysis in this roadmap, it is clear that there are opportunities for HTST technologies and commercial plants to contribute, and potentially to


© New South Wales and Victorian Governments 2008 ii

contribute strongly, to Australia’s carbon abatement and international competitiveness needs in the near, medium and long terms. There are near-term markets in Australia that HTST electricity generation can exploit in targeted markets: isolated grids, remote power systems and solar assist to conventional power generation stations. Over the next decade, market opportunities approaching 1,000 MW in total capacity could be available in Australia to HTST systems for large-scale demonstration and early-deployment projects. However, at its current level of development HTST generates electricity at a higher cost than some existing renewable energy technologies. As a result, it is unlikely that HTST will benefit significantly through to 2020 from the Australian government’s expanded Mandatory Renewable Energy Target as, in its currently proposed form, this is a competitive support mechanism. Exploiting opportunities in these near-term markets, however, will assist in preparing the local supply chain for HTST component technologies, system design capability, project development and delivery capability and financing capacity. This will position Australian industry for the longer term market opportunity, which is for HTST to be an option to supply the major grids in Australia when carbon prices are likely to be above $50/t CO2-e. There is a deployment capacity of around 20,000 MW through to 2050 available in Australia in this market — although HTST will have to compete with a range of alternative low-emission and renewable energy options to supply this demand and market share will ultimately depend on cost-competitiveness, supply reliability and resource availability of each option. This large-scale market should be available to HTST technologies by 2030 (and possibly much earlier) provided that HTST continues to reduce its cost of generation, which is likely in a global sense given the rapid growth in announced commercial projects overseas. The best prospects for cost reductions are in solar field and thermal storage sub-systems, which make up a large component of capital costs. Increasing plant size may also reduce operating costs through economies of scale. It is also clear that in many market contexts, including Australia, development of cost effective thermal storage or siting HTST plants near gas pipelines to utilise gas as a co-firing fuel is crucial for the long term prospects for this technology. There is a range of solar concentrator (linear Fresnel reflector, parabolic trough, power tower and parabolic dish), thermal receiver/heat transfer fluid (hot oil, molten salts, direct steam), heat storage and power generation (steam turbine, Stirling engine) technologies that are proceeding through innovation and/or commercialisation pathways. There is no clear-cut ‘winner’ today in HTST system configurations — and it will take many years and multiple commercial-scale projects for lowest LEC configurations to be identified. Indeed it is possible that most, if not all, HTST concentrator approaches will prove to provide economic solutions for zero or low emission electricity generation. It therefore is prudent, within a sensible strategic approach, for industry and governments to continue to support promising HTST system and component technologies through their innovation and commercialisation paths and processes. Large sums of money have been, and continue to be, invested overseas in HTST-related RD&D and again now in commercial deployment of utility-scale systems. To date Australia has not invested comparably to investigate the opportunities that HTST may offer for a clean energy future. Australia has locally-developed and innovative HTST technologies, a strong R&D reputation in the field that has been gained over the last 20+ years and world-class technology strengths in specific HTST technology areas.


© New South Wales and Victorian Governments 2008 iii

However, if a decision is not made soon to exploit the outcomes of Australia’s past investment then Australian HTST companies and technologies are likely to continue to pursue more economically attractive opportunities in the rapidly-accelerating commercial, financial and RD&D HTST activity overseas. Under this scenario, Australia will lose its existing HTST strengths and will ultimately be a taker (i.e. importer) of these and other HTST technologies. Stakeholders felt strongly that the window of opportunity for Australia to extract significant industry-development value from the R&D legacy and current RD&D capacity and capability in HTST fields is as short as 2015 — particularly given the pace of industry growth and project deployments overseas. This strongly suggests that a policy regime is required in Australia that will promote industry investment in local deployment of commercial HTST technologies and associated supply-chain infrastructure/capability; large-scale demonstration of less-mature HTST technologies; and ongoing R&D of next-generation HTST technologies at the system and key sub-system/component levels to reduce cost and expand market options. Achieving this will require:

• Development of a favourable policy framework for clean energy in Australia;

• Knowledge building in consumers, utilities, financiers, industry, regulators and governments about HTST;

• Market development efforts to promote the sector and to remove barriers to deployment;

• Development of Australian supply-chains for viable near-term applications and large-scale demonstration programs; and

• Training and competence building in human resources and technology capability and capacity.

The vision for HTST in Australia therefore is:

By 2015, Australia’s HTST industry and technologies are strongly positioned in supply chains for local and global energy markets.

Key strategies to implement this vision, options for activities, indicative timeframes and suggested organisations responsible for their implementation are summarised in the table over. Investing in these activities will enable Australian governments, industry, researchers and the broader community to position Australian industry and technologies in the strongly-growing, global HTST sector and to exploit HTST as a key component of Australia’s energy future. While acknowledging the importance of building on and extending the R&D capability and capacity in Australia for HTST and related areas (particularly manufacturing R&D to reduce key-component production costs), stakeholders’ top five priorities focused primarily on market and supply-chain development activities, as follows:

• Large-scale demonstrations, which stakeholders noted pull and underpin: R&D; technology, industry and policy development; removal of implementation barriers; and overseas interest in Australia as a market.

• Capacity and capability building, particularly in manufacturing and engineering areas relevant to HTST systems and components.

• Establishment of an advocacy group to be a champion for HTST in Australia.

• Establishment now of long-term public policy that both pulls and pushes progress in Australia in HTST, particularly market-support mechanisms and removal of specific or inadvertent barriers to market entry for HTST.

o For example, as with similar overseas programs, through banding of technologies under the expanded MRET to ensure prescribed levels of deployment are met or implementation of banded feed-in tariff policies.


© New South Wales and Victorian Governments 2008 iv

• Exploit viable near-term markets, which stakeholders noted will enable (in conjunction with large-scale demonstrations) establishment of sustainable supply chains in Australia for HTST system design, implementation and operation.

The Australian government has proposed the establishment of a $500 million Renewable Energy Fund and a $150 million Energy Innovation Fund, a proportion of each of which is available to or committed to supporting large-scale demonstration and R&D (respectively) of HTST technologies. Expediting the establishment of these Funds will provide an important ‘kick-start’ to the implementation of this roadmap. However, these Australian government funds alone are not sufficient to progress this roadmap optimally. State and Territory governments are encouraged to financially support R&D and large-scale demonstration HTST projects, either on a case-by-case, co-investment basis with project proponents or on a pooled co-investment and joint project selection basis with the Australian government and industry. Learning from joint technology initiative approaches taken overseas, as a transitional arrangement until an appropriate and strong advocacy group for HTST can take leadership of the implementation of this roadmap, a high level co-ordination group (HCG) comprising government, industry, utilities and research sector representatives should be established to oversight and drive start-up of this roadmap.


© New South Wales and Victorian Governments 2008 v

Summary of key strategies, options for activities and implementation

Key Strategies Options for Activities Indicative Time-Frame for Implementation

Responsibility for Implementation

Market Development: Market Support Mechanisms

• Ensure timely introduction of Australia’s proposed national emissions trading scheme and renewable (clean) energy target for 2020.

• Ensure other clean energy market support mechanisms at State and Australian government levels can be applied to HTST systems of appropriate scale.

• State and Australian governments continue to cooperate to quickly remove specific or inadvertent barriers to market entry for HTST.

2008 — 2010

2008 onwards

2008 onwards

• Australian, State and Territory governments


• Ministerial Council on

Energy’s Renewable and Distributed Generation Working Group

Market Development: Strong Industry Advocacy

• Ensure that strong industry advocacy is established to promote HTST in Australia.

2008 onwards • HCG in conjunction with industry

Supply-Chain Development: Viable Near-Term Applications

• Minimise impediments to market entry and promote uptake in Australia of HTST technologies and systems for applications where they are economically competitive now.

• Australian-based companies actively seek opportunities in global supply chains for HTST technology and system design services, components supply and project development to maximise Australian industry and employment growth.

2008 onwards

2008 onwards

• Industry in conjunction with HCG / industry advocacy group

• Industry

Supply-Chain Development: Large Scale Demonstrations

• Expedite establishment of the Australian government’s proposed Renewable Energy Fund for large scale demonstrations.

• Develop and promote world-class, large-scale demonstration projects of pre- or early-commercial HTST technologies and, where appropriate, maximise participation by Australian companies in these large-scale demonstrations.

• Ensure that such demonstration projects are linked internationally where appropriate and that data is shared internationally as a key input into modelling and analysis of energy system options for Australia.

2008 — 2009

2008 onwards

2009 onwards

• Australian government • Industry in conjunction

with HCG / industry advocacy group

• Governments in

conjunction with HCG / industry advocacy group


© New South Wales and Victorian Governments 2008 vi



Competence Building: World-Scale Collaborative R&D Projects

• Expedite establishment of the Australian government’s proposed Energy Innovation Fund in clean energy technology research.

• Industry and researchers jointly develop world-class and world-scale R&D projects to submit into Australian and State government R&D funding initiatives.

2008

2008 onwards

• Australian government • Industry and researchers

Competence Building: Capacity and Capability Building

• Tertiary and secondary educational institutions ensure that relevant technical and business courses incorporate HTST as a key teaching topic and that postgraduate research opportunities in these and allied technical fields are available and promoted.

2009 onwards • HCG / industry advocacy group in conjunction with educational institutions and learned academies

Knowledge Building: Education and Outreach

• Develop education and outreach tools (e.g. dedicated website; educational material; up-to-date database of RD&D activities in HTST in Australia) for local use by educators, researchers, government and industry.

• Identify key public and private-sector decision makers (e.g. regulators, network planners, project and venture capital financiers) and specifically focus on their information and knowledge needs in HTST.

• Ensure that relevant national conferences (e.g. those of the Clean Energy Council, ESAA and ANZSES) incorporate sessions on HTST R&D, demonstration, deployment and market development (as appropriate to each conference).

2009 onwards

2008 onwards

2008 onwards

• Industry advocacy group • HCG / industry advocacy

group • HCG / industry advocacy

group in conjunction with conference organisers

Knowledge Building: Active in International Forums

• Continue / enhance involvement in multilateral (e.g. IEA, APEC, APP) and bilateral forums.

2008 onwards • Australian government in conjunction with the HCG / industry advocacy group


© New South Wales and Victorian Governments 2008 1

1 Introduction 1.1 Background to this roadmap In July 2006, the Council of Australian Governments (COAG) asked its Climate Change Group (COAG CCG) to provide options for the development of technology roadmaps that would identify goals and milestones for the research, development and demonstration of each of the nominated technologies. When completed, jurisdictions could use the roadmaps in their assessment of new research, development and demonstration projects. COAG subsequently agreed to the development of four energy technology roadmaps, and it was agreed that NSW and Victoria would collaborate on development of a high temperature solar thermal (HTST) technologies roadmap. The primary applications for these HTST technologies were seen by the COAG CCG to be electricity generation and industrial process steam. Specifically excluded from this roadmap are lower-temperature solar thermal technologies which collect solar radiation such as solar water heaters; building heating and cooling systems; heating and cooling for industrial processes below 200°C; and solar thermal water desalination.

1.2 The methodology for this roadmap Roadmapping is a technology planning process to help identify, select, and develop technology alternatives to satisfy a set of product needs.1 It starts with needs, not solutions.2 The main benefit of technology roadmapping is that it provides information to help make better technology investment decisions. In developing this Australian roadmap for HTST technologies, this needs-driven approach has been kept foremost. That is, this roadmap does not start with an end-point assumption that there will be a certain level of deployment of HTST systems at some point in the future. Rather, the need and market potential for HTST in Australia have been assessed — taking into account competing options in the marketplaces they will operate in. To develop a credible and defensible roadmap for use by Australian governments and researchers, together with suppliers and customers in the HTST system value chains, Wyld Group, in conjunction with its partner McLennan Magasanik Associates (MMA), have:

• Undertaken bottom-up data gathering through extensive and direct consultation with stakeholders by:

o preparing a discussion paper for targeted use with key stakeholders to focus the consultation process and responses3;

o carrying out one-on-one interviews with stakeholders from industry, research and government — nationally and internationally — about opportunities and constraints facing HTST technologies; and

o conducting workshops in Melbourne and Sydney with cross-sectional representation to enable sharing of views and cross-fertilisation of ideas.

• Undertaken desktop research in order to:

1 M.L. Garcia and O.H. Bray, Fundamentals of Technology Roadmapping, Sandia National Laboratories Report No.

SAND97-0665, April 1997. 2 Industry Canada, Technology Roadmapping – A Strategy for Success, available at

http://strategis.ic.gc.ca/epic/site/trm-crt.nsf/en/rm00064e.html. 3 Discussion Paper — High Temperature Solar Thermal (HTST) Technologies, Market Potential and Innovation

Opportunities, Prepared for the New South Wales Department of Environment and Climate Change and Victorian Department of Primary Industries, October 2007.



o collect and review relevant national and international publications and the outputs of similar roadmapping projects overseas; and

o modelling costs in Australia of electricity generation incorporating HTST-based generation as well as that based on other new renewable and established technologies.

• Analysed the collected data to assess the market, industry-development and technology-development potential in Australia for HTST technologies.

• Completed a draft roadmap document, and tested it and the analyses behind it via an additional stakeholder workshop in Sydney.

It is emphasised that development of a technology roadmap is done with the best available data at the time to optimise the factors that affect a technology’s development, but the practitioners will still have to deal with day-to-day successes and set-backs to reach their and the roadmap’s goals.



2 HTST technologies — state-of-the-art HTST systems obtain their energy input by concentrating solar radiation, which is converted to high temperature steam or other fluid that can drive a turbine or engine (for electricity generation) or be used directly for industrial process heat or in thermochemical processes. Four main elements are required: a concentrator, a receiver, some form of heat transport medium or storage and, for electricity generation, a power conversion unit. Many different types of systems are possible, including combinations with other renewable and non-renewable technologies. Apart from a number of small-scale trials in various countries, the Solar Energy Generating Systems (SEGS) plants built between 1984 and 1989 in southern California were the only commercial HTST electricity plants in operation until a re-birth in market interest commenced in 2005. Figure 1 below shows online and planned HTST electricity plants while the Table 1 over lists the current operational, under-construction and announced HTST electricity generation plants. These plants appear to be funded on a commercial basis; however, their economic viability is supported by a range of government policies designed to promote renewable energy technology deployment including renewable portfolio standards, feed-in tariffs, tax credits, clean development mechanisms and direct government or multi-lateral funding agency grants.

Figure 1: Online and planned HTST electricity generation plants4

4 Compiled from http://www.sunwize.com/info_center/insolmap.htm (last accessed 26 Feb 2008) and

http://blogs.zdnet.com/green/images/csp-project-activity-jpeg.jpg (last accessed 22 Feb 2008), the latter reporting a recent study from Emerging Energy Research entitled Global Concentrated Solar Power Markets and Strategies, 2007-2020 released 11 December 2007 (see http://www.emerging-energy.com/user/GlobalConcentratingSolarPowerMarketsandStrategies200720201451383184_pub/EERSolarCSPpr_121007.pdf).

North America (MW)

Online 418

Planned2007‐2012

2,954

Asia‐Pacific (MW)

Online –

Planned2007‐2012

175

Middle East Africa (MW)

Online –

Planned2007‐2012

1,185

Europe (MW)

Online 12

Planned2007‐2012

2,046

Map shows the amount of solar energy, in hours, received each day on an optimally tilted surface during the worst month of the year.(Based on accumulated worldwide solar insolation data.)



Table 1: Listing of currently-known HTST commercial plants globally5

Name Location Capacity Technology Developer Operational SEGS Nevada Solar One PS10

California, USA Nevada, USA Spain

354 MW 64 MW 11 MW

Parabolic trough Parabolic trough Power tower

FPL Energy Acciona Solar Power Abengoa

Under Construction Andasol 1 Andasol 2 Liddell Solar Tres

Spain Spain Australia Écija, Spain

50 MW 50 MW 38 MW 15 MW

Parabolic trough Parabolic trough Linear Fresnel reflector Power tower

Solar Millenium Solar Millenium Solar Heat & Power SENER

Announced Mojave Solar Park Beacon Solar Project Shams Solana Station Barstow Yazd Victorville 2 Kuraymat Plant Ben Mathar Plant Hassi R’mel Unnamed Carrizo Energy Ivanpah Solar Upington Pisgah Imperial Valley Cloncurry Queensland

California, USA California, USA Abu Dhabi Arizona, USA California, USA Iran California, USA Egypt Morocco Algeria Florida, USA California, USA California, USA South Africa California, USA California, USA Australia Australia

553 MW 250 MW 100 MW 280 MW 59 MW 67 MW 50 MW 40 MW 30 MW 25 MW

300 MW 177 MW 400 MW 100 MW 500 MW 300 MW 10 MW 5 MW

Parabolic trough Parabolic trough Parabolic trough Parabolic trough + storage Parabolic trough + storage Parabolic trough ISCCS* Parabolic trough ISCCS Parabolic trough ISCCS Parabolic trough ISCCS Parabolic trough ISCCS Linear Fresnel reflector Linear Fresnel reflector Power tower Power tower Dish Stirling Dish Stirling Multi tower array + storage Multiple Tower SolarGas

Solel FPL Energy ADFEC Abengoa Solar Solar MW Energy Unknown City of Victorville Iberdrola Abengoa Abener Ausra Ausra Bright Source Energy Eskom Stirling Energy Systems Stirling Energy Systems Lloyd Energy Systems CSIRO

* Integrated Solar Combined Cycle System The following sections briefly describe the major HTST technologies and their technical and commercial states-of-the-art.

2.1 Parabolic trough

2.1.1 Technology Parabolic trough HTST plants (Figure 2) are considered to be the most economic and most mature HTST technology available today. Parabolic trough-shaped mirror reflectors are used to concentrate sunlight onto thermally-efficient receiver tubes placed in the trough focal line. In these tubes a thermal transfer fluid is circulated, such as a synthetic thermal oil. Heated to approximately 400°C by the concentrated sun’s rays, this oil is then pumped through a series of heat exchangers to produce superheated steam. The steam is converted to electrical energy in a conventional steam turbine generator, which can either be part of a conventional steam cycle or integrated into a combined steam and gas turbine cycle.

5 Adapted from http://en.wikipedia.org/wiki/List_of_solar_thermal_power_stations, last accessed on 09 Feb 2008.



Figure 2: Parabolic trough collector and system diagram of Andasol 50MW HTST plant in Spain6 Since 1998, another generation of parabolic collector technology has been under development at the Plataforma Solar Research Centre in Almeria, Spain by a European consortium. Known as EuroTrough, this technology aims to achieve better performance and lower costs by significantly enhancing the optical accuracy by a new design of the trough structure. With funding from the European Union, 100 metre and a 150 metre long prototypes of the EuroTrough were successfully commissioned at the Plataforma Solar Research Centre7 in 2000 and 2002 respectively. While the commercial plants in California use a synthetic oil as the heat transfer fluid because of its low operating pressure and ease of storage, R&D efforts are under way at the Plataforma Solar Research Centre through the DISS (Direct Solar Steam) and INDITEP projects sponsored by the European Commission to achieve direct steam generation within absorber tubes and to eliminate the need for intermediate heat transfer.8 This increases efficiency and could reduce costs by as much as 30%. The Centre for Sustainable Energy Systems (CSES) at the Australian National University, in collaboration with partners in Australia, China, and the USA, develops and implements commercial hybrid trough concentrator systems for combined generation of heat and electricity. These systems range from industrial-scale single-axis tracking Combined Heat and Power Solar (CHAPS) to smaller versions such as a micro-concentrator system suitable for mounting on residential roof-tops. The hybrid systems can optionally be supplied as single-function PV or thermal concentrators. The latter is capable of generating temperature differentials well in excess of 200C, which is of particular interest for solar air-conditioning systems that are also being developed at CSES. Commercially-focused research at CSES is united by the concept of a greenhouse neutral house.9 In 2005, the ANU group collaborated with CSIRO’s National Solar

6 Reproduced from Concentrating Solar Power: From Research to Implementation, European Commission

Directorates-General of Energy & Transport and Research, 2007. 7 Greenpeace International and the European Solar Thermal Power Industry Association, Solar Thermal Power 2020:

Exploiting The Heat From The Sun To Combat Climate Change, October 2003. 8 http://ec.europa.eu/research/energy/nn/nn_rt/nn_rt_cs/article_1118_en.htm, last accessed 22 Jan 2008. 9 Personal communication from Ray Prowse, Centre Manager, CSES, ANU.



Energy Centre in Newcastle on trough system development. CSIRO purchased from ANU 130 m2 of trough concentrator mirror modules for its Organic Rankine Cycle power generation project.10

2.1.2 Commercial activities Parabolic trough HTST systems, with a total capacity of 354 MW, have been connected to the Southern California grid since the 1980s, with over 2 million square metres of collectors operating with a long term availability of over 99%. Managed and operated by the Israeli company Solel Solar Systems, this HTST power system supplies an annual 800 million kWh at a generation cost of about 10 to 12 US cents/kWh. These plants have demonstrated a maximum summer peak efficiency of 21% in terms of conversion of direct solar radiation into grid electricity.11 There has been a lapse of over 15 years since the Southern California systems were commercially deployed, but now there are a number of parabolic trough pre-commercial and fully-commercial deployments underway. With its favourable feed-in tariff for solar power, Spain is leading the way in Europe with new deployments in a range of HTST technologies. Andasol-1 (see Figure 2 for a schematic representation of the system) is a 50 MW parabolic trough system being developed and promoted by the Spanish ACS Cobra Group, the majority shareholder, and the German Solar Millennium Group, the minority shareholder. The European Investment Bank is providing a €60 million tranche of funding for this plant12, and the project has a grant from the European Union of €5 million.13 The total project cost is reported to be €310 million.14 The AndaSol project will be the first application of molten salt-based thermal storage technology with parabolic trough collectors. The heat exchange between the heat transfer fluid (HTF) circulating in the solar field, the molten salt storage medium and the water/steam cycle will be optimised in this commercial scale design.15 In May 2007, MAN Ferrostaal AG, the industrial service provider in the German MAN group, announced the establishment of a joint company with Solar Millennium for project development and construction of solar thermal power stations. The companies each hold 50% in the new joint company MAN Solar Millennium GmbH, whose goal is to establish the joint venture as one of the world's leading suppliers of solar thermal power stations.16 In the USA, the Nevada Solar One project is a 64 MW parabolic trough HTST system developed and owned by Acciona Solar Power, a subsidiary of global Acciona Energía group. Built over the course of 16 months and with an investment of over US$250 million, it officially began supplying power to the Nevada Power grid in June 2007 under long-term power purchase agreements17. In July 2007, Acciona announced that it had closed a US$266 million long-term project financing deal for its Nevada Solar One project — the first leveraged lease, structured financing for an HTST plant in the United States. The leveraged lease structure was financed by debt participants 10 http://engnet.anu.edu.au/DEresearch/solarthermal/high_temp/concentrators/index.php, last accessed 22 Sep

2007. 11 Greenpeace International and the European Solar Thermal Power Industry Association, Solar Thermal Power 2020:

Exploiting The Heat From The Sun To Combat Climate Change, October 2003. 12 http://www.eib.org/projects/press/2006/2006-077-eib-loan-for-first-european-solar-thermal-power-plant-in-

spain.htm, last accessed on 03 Sep 2007. 13 Concentrating Solar Power – From Research to Implementation, European Communities, 2007. 14 http://www.schott.com/newsfiles/20060925151741_DuF_Andasol_E.pdf?PHPSESSID=91, last accessed 25 May 08. 15 http://www.flagsol.com/andasol_project_RD.htm, last accessed 13 Apr 2008. 16 http://www.manferrostaal.com/man_solar_millennium.news_detail+M52ee3164173.0.html, last accessed 22 Sep

07. 17 http://www.renewableenergyaccess.com/rea/news/story?id=48848, last accessed on 16 Sep 2007.



Banco Santander and BBVA, headquartered in Spain, and Caixa Geral de Depósitos, headquartered in Portugal, and equity investors JPMorgan Capital Corporation, Northern Trust and Wells Fargo in the USA.18 Recently Solel Solar Systems has announced the development of a 553 MW parabolic trough HTST power system in the Mojave Desert in California that will be completed and fully operational in 2011. Solel has secured a long-term power purchase agreement with California utility PG&E that will bring renewable energy to 18% of the company's total power supply in coming years, and closer to compliance with a California requirement of 20% by 201019. Beacon Solar, a wholly-owned subsidiary of Florida Power & Light Energy, filed in March 2008 an application for certification with the California Energy Commission to construct, own and operate a 250-megawatt solar plant in the Mojave Desert to be called the Beacon Solar Energy Project. Using parabolic trough solar thermal technology, the approximately US$1 billion project is scheduled to begin construction in late 2009 with commercial operation commencing approximately two years later.20 Abu Dhabi Future Energy Company of the United Arab Emirates has announced that it will invest US$400-500 million to build a parabolic trough CSP plant with a capacity of 100 MW that is expected to be operational by the end of 2010. It will be built in the town of Madinat Zayad in the western region of Abu Dhabi, and is reported to be the first of many CSP plants to be setup in the UAE to feed electric power to the national grid.21 ADFEC is mandated to develop and execute the Masdar Initiative, Abu Dhabi's $15bn future energy initiative to promote commercialization of renewable and sustainable energy technologies.22 In September 2006 Schott-Rohrglas, a division of global German company Schott AG, officially opened a production line for parabolic trough solar receivers (a key component in trough power plants) and launched industrial-scale mass production of this receiver in Germany. The German Federal Ministry for the Environment, Nature Conservation and Nuclear Safety has funded development of the receiver since 2002. Schott-Rohrglas is a world market leader in receiver technology, and its receivers are used in the Nevada Solar One and ANDASOL I projects. Schott has invested €15 million in the production plant in Germany, which has created 120 jobs.23

2.2 Linear Fresnel

2.2.1 Technology A Linear Fresnel Reflector (LFR) is a single-axis tracking technology that focuses sunlight reflected by long heliostats onto a linear receiver to convert solar energy to heat. The classical linear Fresnel system uses an array of mirror strips close to the ground to direct solar radiation to a single, linear, elevated, fixed receiver (Figure 3). The technology is seen as a lower cost alternative to trough technology for the production of solar steam for power generation. The main advantages of the Linear Fresnel collector, compared to trough collectors, are seen to be24:

• Inexpensive planar mirrors and simple tracking system. 18 http://www.acciona-energia.com/default.asp?x=00020401&z=000105&item=263, last accessed on 22 Sep 2007. 19 http://www.msnbc.msn.com/id/20068703/, last accessed on 22 Sep 2007. 20 http://www.energy.ca.gov/sitingcases/beacon/DESCRIPTION.PDF, last accessed 02 Apr 08. 21http://www.khaleejtimes.com/DisplayArticleNew.asp?xfile=data/business/2008/January/business_January587.xml&

section=business&col=, last accessed on 09 Feb 2008. 22 http://www.ameinfo.com/144481.html, last accessed on 09 Feb 2008. 23 http://www.bmu.de/files/pdfs/allgemein/application/pdf/jb_ee_2006_engl.pdf, last accessed on 22 Sep 07. 24 ECOSTAR: European Concentrated Solar Thermal Roadmap Document, European Commission Document No. SES6-

CT-2003-502578, Issue 1-25 on 15 Feb 2005.



• Fixed absorber tube with no need for flexible high pressure joints or thermal expansion bellows.

• No vacuum technology and no metal-to-glass sealing. • Wind loads are substantially reduced on the reflector strips, so the reflector width for

one absorber tube can be up to three times the width of parabolic troughs.

• Due to direct steam generation no heat exchanger is necessary — although trough technology also is evolving to direct steam generation (see Section 2.1.1).

• Efficient use of land since the collectors can be placed close to one another.

Figure 3: Linear Fresnel reflector (LFR) technology by Ausra, Inc (left25) and NOVATEC Biosol AG (right26)

The ECOSTAR Roadmap comments that a disadvantage of linear Fresnel systems is a reduction in the efficiency compared to parabolic troughs, which has to be compensated for by a lower investment cost in the solar field. These cost reductions can come from economies of scale and design optimisation of the collector and there are also potential savings offered by lower operation and maintenance costs in LFR systems. An early and leading exponent of LFR technology was the Australian company Solar Heat and Power Pty Ltd (SHP) founded by Dr David Mills, Prof. Graham Morrison and Peter le Lievre. It has demonstrated a proof-of-concept LFR array next to Macquarie Generation’s Liddell Power Station in NSW. SHP’s commercial and technical approach has been to focus on the major issue for HTST systems — capital cost.

2.2.2 Commercial activities SHP’s multi-megawatt demonstration plant at Liddell continues to be expanded with AU$3.25 million support from the Commonwealth Government’s Renewable Energy Development Initiative (REDI) program. However, market forces — principally the rapid growth in market interest in the USA driven by state-based renewable portfolio standards in each — have resulted in SHP’s founders moving the company’s commercial headquarters to the USA into a new company (Ausra, Inc.). Located in Palo Alto, California, Ausra is a privately held company with more than US$40M secured in investment by Khosla Ventures and Kleiner, Perkins, Caufield & Byers. Ausra is planning to build and operate utility-scale HTST power plants worldwide27 and more recently has announced it will bring on-line in Las Vegas, Nevada in April 2008 a large-scale, highly-automated, manufacturing plant for LFR solar field components28.

25 From http://www.ausra.com/, last accessed on 22 Sep 07. 26 From http://www.novatec-biosol.com/downloads.htm, last accessed 22 Jan 08. 27 http://www.ausra.com/news/releases/070910.html, last accessed on 22 Sep 07. 28 http://www.reuters.com/article/companyNewsAndPR/idUSN1363008120071213, last accessed 22 Jan 2008.



LFR technology is also gaining momentum in Europe. The German company Solar Power Group GmbH was founded by one of the former owners and chief R&D engineer of the Solarmundo company, an early proponent and developer of LFR technology. In cooperation with MAN Ferrostaal (which has taken a 25% shareholding in Solar Power Group), it has constructed an approximately 1 MW (thermal) LFR demonstration plant at the Plataforma Solar de Almeria in Spain with German government funding support of €1.2 million. The inauguration and first testing of this LFR system took place in mid-July 2007.29 Another proponent of LFR technology is the German company NOVATEC Biosol AG. At the start of 2007, the first mass-production machine was commissioned for it to start producing NOVATEC Biosol’s patented solar field components. In August 2007, the factory expected to start operating in southern Spain and begin producing reflectors and receiver elements of the solar steam generator. Initial production capacity is 220,000 square metres of reflector surface per year.30 In May 2007, NOVATEC BioSol and M+W Zander FE GmbH concluded a joint-venture contract with the goal of joining forces to build solar thermal power stations in Spain. The agreement initially comprises the construction of three solar power stations in southern Spain, each planned with an output of around 30 megawatts and the commencement of the first plant during 200731.

2.3 Power tower

2.3.1 Technology Power towers use a circular or semi-circular array of heliostats (large individually-tracking mirrors) to concentrate sunlight on to a central receiver mounted at the top of a tower (Figure 4). A heat transfer medium in this central receiver absorbs the highly concentrated radiation reflected by the heliostats and converts it into thermal energy to be used for the subsequent generation of superheated steam for turbine operation. Heat transfer media so far demonstrated include water/steam, molten salts, liquid sodium and air.

Figure 4: Power tower technology implementations: Solar 1, USA (left32) and PS10, Spain (right33)

29 http://www.spg-gmbh.com/news.asp?news_id=12, last accessed on 22 Sep 07. 30 http://www.novatec-biosol.com/engl/index.html, last accessed on 22 Sep 07. 31 http://www.mw-zander.com/hld-index/hld-news/hld-news-archive.htm?newsId=45415, last accessed on 22 Sep

07. 32 L. Stoddard, J. Abiecunas, and R. O'Connell, Economic, Energy, and Environmental Benefits of Concentrating Solar

Power in California, National Renewable Energy Laboratory Report NREL/SR-550-39291, April 2006. 33 Concentrating Solar Power – From Research to Implementation, European Communities, 2007.



Concentrating sunlight over 500 times, power tower technology has the potential advantage of delivering high temperature solar heat in utility scale quantities at temperatures of 500°C or more for steam cycles and greater than 1,000°C for gas turbines and combined cycle power plants. The technical feasibility of central receiver technology was first proved during the 1980s in the USA with the Solar 1 and Solar 2 demonstration plants in California. Power tower technology is in renaissance in Europe and the USA as market incentive programs attract commercial interest in all HTST technologies. PS-10, an 11 MW (electrical) power tower system constructed outside of Seville, Spain, was the first HTST plant completed in Europe. It was built by Solúcar Energía S.A., a member of the Abengoa group, at a total cost of approximately €35 million (for which a contribution from the European Union of €5 million was received). It is intended to demonstrate the commercial viability of the chosen solar tower approach under the given geographic, technical and legal framework. This plant was commissioned in March 2007.34 The Solar Tres project, also to be constructed outside of Seville, Spain, is a 17 MW power-tower HTST system that builds on the Solar 2 technology demonstrated in the USA. The project, which has received a contribution of €5 million from the European Commission towards the approximately €53 million total cost, will make use of several advances in technology since Solar Two was designed and built. These include35:

• A larger plant with a heliostat field approximately three times the size of Solar Two and an improved plant availability with a 6% improvement in overall annual plant efficiency.

• 2493 glass-metal heliostats, each of 96 m², with higher-reflectivity glass and a 45% reduction in manufacturing costs because of the simplified design.

• A larger thermal energy storage system using 6,250 tonnes of molten nitrate salt (16 hours, 600 MWh).

• Advanced pump designs that will pump salt directly from the storage tanks, eliminating the need for pump sumps.

• A steam generator system that will have a forced-recirculation steam drum. • A more efficient, higher-pressure reheat turbine, and • A simplified molten-salt flow loop that reduces the number of valves by 50%.

Although the turbine will be only slightly larger than that of Solar Two, the larger heliostat field and thermal storage system will enable the plant to operate 24 hours a day during summer and have an annual capacity factor approaching 70%. Up to 15% hybridisation of the plant with natural gas will provide additional reliability of generation. Project construction by the developer, SENER Ingeniería y Sistemas, S.A., is expected to start by the end of 2007.36 CSIRO operates a 500kW solar tower at the National Solar Energy Centre in Newcastle, Australia (see Figure 5A). It is a tower for research and demonstration purposes, and presently is used to reform natural gas to a hydrogen-rich gas containing embodied solar energy (see also Section 2.6), and eventually for high temperature steam generation. The tower is unique in that it is based on cost reductions emanating from mass production using off-the-shelf components rather than economies of scale alone. Larger capacities are simply a result of replication of these smaller modules. It has reached temperatures over 1,000 °C at solar concentrations of 2,000 suns.

34 http://www.ens-newswire.com/ens/mar2007/2007-03-30-02.asp, last accessed 23 Sep 2007. 35 http://en.wikipedia.org/wiki/Solar_Tres_Power_Tower, last accessed 23 Sep 2007. 36 http://www.nrel.gov/csp/troughnet/pdfs/2007/martin_solar_tres.pdf, last accessed 23 Sep 2007.



CSIRO’s Energy Transformed Flagship research program plans to use the high temperature solar field to develop other solar technologies such as beam spectrum splitting, water splitting to produce hydrogen and distributed generation using microturbines.37 It has been recently announced that CSIRO will receive $7.5 million from the Queensland Renewable Energy Fund towards a 5 MWthermal demonstration plant (see Figure 5B) to be constructed in Queensland with operation in 2011 — the first major scale-up of this innovative tower-based technology. It will be based on the open-loop solar reforming process and demonstrate production of solar electricity with intermediate load operation, and the potential for future base load.

(A) (B)

Figure 5: (A) CSIRO 500 kW solar tower (B) Artist’s impression of CSIRO 5 MWthermal tower demonstration plant in Queensland38

2.3.2 Commercial activities While no commercial power tower plants are yet under construction, two groups recently have announced plans for utility-scale facilities. In the USA, Hamilton Sundstrand (a subsidiary of United Technologies) and US Renewables Group (a private equity firm) have announced plans to commercialise the Solar1 and Solar 2 power tower and molten salt storage technology. They plan to build as many as 10 plants over the next 10 to 15 years.39 Recently Abu Dhabi’s Masdar Initiative and Spain’s Sener Grupo de Ingenieria have established a new venture, Torresol Energy, to widen the adoption of HTST technology generally. Initially three plants will be built in Spain with a combined value of US$1.2 billlion, with one of these plants to be a power tower system.40

2.4 Parabolic dish

2.4.1 Technology Using parabolic dishes is a well-tested approach to concentrate solar radiation, and was an early experimental tool at many locations worldwide. The optical efficiency of parabolic dishes is

37 http://www.csiro.au/science/ps15e.html, last accessed 13 Apr 2008. 38 Personal communication, Mark Squires, CSIRO. 39 http://media.cleantech.com/2253/concentrated-solar-gets-salty, last accessed 02 Apr 08. 40 http://media.cleantech.com/2592/masdar-sener-in-1-2b-solar-thermal-venture, last accessed 02 Apr 08.



considerably higher than that of trough, LFR or power tower systems because the mirror is always pointed directly at the sun, whereas the trough, LFR and power tower have a reduction in projected area due to a frequent low angle of incidence of the solar radiation (known as cosine losses). However, the higher optical efficiency of dishes (which ultimately translates to a higher efficiency of conversion of sunlight to electricity41) is partially offset because their capital cost per installed megawatt currently is higher than the others. How these efficiency—capital cost tradeoffs translate to levelised energy cost must be determined on a case-by-case basis for commercial HTST plants. A well-known example of parabolic dish HTST technology is the Big Dish system developed and demonstrated at the Australian National University since the early 1990s (Figure 6) and now undergoing commercial development and system scale-up by Wizard Power Pty Ltd in Canberra. Wizard’s intention for commercial-scale HTST power generation is that an array of dishes would feed steam — via a steam line network — to a single high efficiency central power block. Wizard has received an AU$3.5 million REDI grant to support the development of a second generation Big Dish with a 50% improvement in solar-to-electricity conversion performance and potentially a threefold reduction in overall manufacturing and maintenance costs.42

Figure 6: Parabolic dish implementations: ANU/Wizard Power ‘Big Dish’ (left43)

and Stirling Energy Systems Inc. dish-Stirling (right44). In 1996, Stirling Energy Systems, Inc. (SES) in the USA acquired the patent, tooling, and equipment rights to the dish Stirling technology initially developed in the 1980s by McDonnell Douglas (now owned by The Boeing Co.). These systems were field-tested by Southern California Edison and Georgia Power for over 175,000 hours between 1982 and 1988. Edison's test data indicated the dish Stirling out-performed all other solar-to-electric generating systems by a factor of two, yet had comparable start-up costs. SES optimised the McDonnell Douglas dish to operate with a 25kW Stirling power conversion unit developed in Sweden by United Stirling, Kockums and Volvo (Figure 6). The resulting system, the Dish Stirling, has fewer moving parts than comparable diesel engines and operates relatively

41 K. Lovegrove, A. Zawadski and J. Coventy, Paraboloidal Dish Concentrators for Multi-Megawatt Power Stations,

presented at Solar World Congress, Beijing, 18–22 September 2007. 42 http://www.ausindustry.gov.au/library/REDI_grant_offers_Rd_1_v220051209025230.pdf, last accessed 23 Sep

2007. 43 http://www.wizardpower.com.au/technology/solartechnology.html, last accessed 22 Jan 2008. 44 http://www.stirlingenergy.com/default.asp, last accessed 22 Jan 2008.



quietly. The SES solar test site and related tooling and equipment facilities are located at the Boeing facility in Huntington Beach, California. The 25 kW SES Dish Stirling system has an operating track record of more than 17 years.45 In Europe, the EuroDISH project – a €1.7 million project co-funded by the Euopean Commission with a €750,000 contribution – is a claimed to be a fundamental rethinking of classic dish/Stirling systems, focusing on the optical dish design, the supporting structure, the Stirling engine and the control system.46 Led by Schlaich Bergermann und Partner (SBP), Germany, the EuroDISH Stirling system is a 10 kWe output plant. SBP has built dish–Stirling prototype units in Saudi Arabia (two units with 17 m diameter/50 kWe), Spain (six units with 7.5/8.5 m diameter and 9/10 kWe) and several units in Germany.47

2.4.2 Commercial activities In August 2005, SES signed 20-year power purchase agreement with Southern California Edison that calls for development of a 500 MW HTST project in the Mojave Desert northeast of Los Angeles, using SES’s Dish Stirling technology. The agreement includes an option to expand the project to 850 MW. Initially, SES will build a one MW test facility using 40 of the company’s 11 metre diameter dish assemblies. Subsequently, a 20,000-dish array will be constructed during a four-year period.48 This commercial development was quickly followed with the announcement in September 2005 of a contract with San Diego Gas & Electric (SDG&E ) to provide between 300 and 900 MW of Dish Stirling power. Under this contract, SES and SDG&E have agreed to an initial 20-year contract to purchase all the output from a 300 MW HTST plant, which consists of 12,000 Stirling solar dishes on approximately eight square kilometres in the Imperial Valley of Southern California. SDG&E has options on two future phases that could add up to 600 MW of additional renewable energy and capacity to SDG&E’s resource mix.49

2.5 High temperature thermal storage Cost-effective storage will enable a high penetration of intermittent renewable energy into markets. A potentially important advantage of HTST systems is that thermal energy is, relatively, easier and less-costly to store than electrical or other forms of energy. Three storage techniques have been developed and demonstrated for HTST systems: sensible heat storage; latent heat storage; and thermochemical storage. Sensible heat storage This is the most-commonly used approach in current parabolic trough and power tower HTST systems where hot heat transfer fluids such as water, oils or molten salts are stored in tanks or underground caverns. This is the approach proposed by Solar Heat and Power Pty Ltd (now Ausra, Inc.).50 State of the art for high temperature heat storage is the 2-tank molten salt system tested in the Solar Two demonstration project in combination with a Central Receiver Solar Power Plant using salt as the heat transfer fluid. The use of new storage materials, so called room temperature ionic liquids (RTILs), has recently been proposed. RTILs are organic salts with negligible vapour

45 http://www.stirlingenergy.com/products.asp?Type=solar, last accessed 23 Sep 2007. 46 Concentrating Solar Power – From Research to Implementation, European Communities, 2007. 47 http://www.klst.com/projekte/eurodish/sbp_page.html, last accessed 23 Sep 2007. 48 http://www.stirlingenergy.com/news/SES%20Press%20Release%20-%20FINAL%20Aug%2011%202005.pdf, last

accessed 23 Sep 2007. 49 http://www.stirlingenergy.com/news/SES%20Press%20-%20SDGE%20V%203.pdf, last accessed 23 Sep 2007. 50 D. Mills and P. le Lièvre, Competitive Solar Electricity, ANZSES Conference, Perth, November 2004



pressure in the relevant temperature range and a melting temperature below 25°C. Room temperature ionic liquids are quite new materials and it is not yet clear whether they are stable up to the temperature level required for HTST systems and also whether they may be produced at reasonable costs.51 The concept of using concrete or castable ceramics to store sensible heat for parabolic trough power plants with synthetic oil as the heat transfer fluid has been investigated in a number of European projects. The implementation of a concrete storage system is claimed to be able to be feasible within approximately 5 years52. In Australia, Lloyd Energy Systems Pty Ltd is scaling up its graphite-based, high-temperature sensible heat storage system (Figure 7) with the support of an A$5 million grant from the Commonwealth government’s Advanced Energy Storage System program.53 A high concentration tower solar array will be installed at Lloyd’s factory site in Cooma and, once proven, a 16-tower solar array—graphite storage system will be built at Lake Cargelligo in western NSW using a tower solar array supplied by Solar Heat and Power Pty Ltd. The heliostats in each array will direct concentrated sunlight into a 10 tonne graphite block mounted on a 15 metre high tower. The completed 16-tower system will drive a 3 MWe steam turbine to generate power.

Figure 7: First Lloyd Energy solar concentrator—graphite storage module in Cooma, NSW

Lloyd Energy recently has announced another, larger system, to be built at Cloncurry in Queensland to provide peak and backup supply for Cloncurry. It will ensure power quality in the area, increase renewable energy use and reduce the need for more power transmission lines in the area in the future. A total solar collection area of 60,000 m2 will focus sunlight onto 54 graphite modules of 10 tonnes each to provide generation capacity of 10 MWelect for 8 hours. Lloyd Energy has an energy purchase and network support fee agreement with Ergon Energy and this AU$31 million project is receiving a grant of AU$7 million from the Queensland government.54 Latent heat storage Phase change materials (PCM) are potential candidates for latent heat storage, which is of particular importance for systems that have to deal with large fractions of latent heat, such as direct steam generating systems. At present, two principal measures are being investigated: encapsulation of small amounts of PCM; and embedding of PCM in a matrix made of another solid material with high heat conduction.

51 ECOSTAR: European Concentrated Solar Thermal Roadmap Document, European Commission Document No. SES6-

CT-2003-502578, Issue 1-25 on 15 Feb 2005. 52 Ibid. 53 http://minister.industry.gov.au/index.cfm?event=object.showContent&objectID=4ACDEAAE-BD82-BB6A-

71D6B60AE64B4511, last accessed 23 Sep 2007. 54 http://www.lloydenergy.com/presentations/Cloncurry%20Solar%20Thermal%20Storage%20Project.pdf, last

accessed on 22 Jan 2008.



The first measure is based on the reduction of distances between the capsules of PCM and the second one uses the enhancement of heat conduction by other materials e.g. graphite. Storages based on PCM are in an early stage of development but the cost target is to stay below €20/kWh based on the thermal capacity. Although the uncertainties and risks of the PCM storage technology is considered to be in a medium range, the time required for full development of the technology and its commercial implementation is more than 10 years.55

2.6 Solar thermochemical processes Solar thermochemical processes convert radiant energy into chemical energy, with the absorbed, concentrated, solar radiation driving an endothermic chemical reaction. Concentrated solar radiation is used as the energy source for high temperature process heat to drive chemical reactions towards the production of storable and transportable fuels (Figure 8(A)).

(A) (B)

Figure 8: High temperature solar thermochemical storage concepts56

An alternate approach (Figure 8(B)) is to use HTST heat to drive a reversible reaction in a solar chemical reactor. The products can be stored long-term and transported to the customer site where the energy is needed. At that site, the exothermic reverse reaction is effected, yielding process heat in an amount equal to the stored solar energy. This high-temperature heat may be applied, for example, to generate electricity using a Rankine cycle. The chemical products from this reverse reaction are the original chemicals that can then be returned to the solar reactor where the process is repeated. Two reactions that have been extensively investigated for application in such ‘chemical heat pipes’ are methane (CH4) reforming-methanation and ammonia dissociation-synthesis. The ammonia-based process has been extensively researched at the Australian National University over the last two decades.57 This technology now is being commercially developed by Wizard Power, which has received AU$7.4 million from the Commonwealth government’s


CT-2003-502578, Issue 1-25 on 15 Feb 2005. 56 Sourced from A. Steinfeld and R. Palumbo, Solar Thermochemical Process Technology, Encyclopedia of Physical

Science & Technology, Vol. 15, pp237-256, 2001 (available at http://www.pre.ethz.ch/publications/0_pdf/books/Solar_Thermochemical_Process_Technology.pdf).

57 http://engnet.anu.edu.au/DEresearch/solarthermal/high_temp/thermochem/index.php, last accessed 23 Sep 2007.



Advanced Energy Storage System program58 to demonstrate a solar energy storage system based on ammonia dissociation-synthesis. In this project, four 400 m2 Big Dish solar collectors will be installed near Whyalla to provide the heat required to split ammonia into nitrogen and hydrogen for storage. When power is required, the gases will be recombined in an exothermic process that gives off heat to boil water and generate electricity through a steam turbine. The methane-based process, which has undergone considerable development in Australia by CSIRO Energy Technology59, is an example of a hybrid solar/fossil process. The products (in this case syngas) are fuels whose quality has been upgraded by solar energy. That is, the calorific value is increased above that of the fossil fuel by solar energy input equal to the enthalpy change of the reaction. Increased energy content means extended fuel life and reduced pollution of the environment. Therefore, these fuels are considered to be cleaner fuels. The mix of solar and fossil energies creates a link between current fossil fuel-based technologies and future solar chemical technologies (Figure 9), including the production of hydrogen.

Figure 9: CSIRO’s envisaged supply chain for its SolarGasTM technology60

58 http://minister.industry.gov.au/index.cfm?event=object.showContent&objectID=4ACDEAAE-BD82-BB6A-

71D6B60AE64B4511, last accessed 23 Sep 2007. 59 http://www.det.csiro.au/science/r_h/renewable_topics.htm, last accessed 23 Sep 2007. 60 http://www.det.csiro.au/science/r_h/images/NSEC_SolarGas%20Benefits.pdf, last accessed 22 Jan 2008.



3 HTST — Overseas market growth and cost projections The primary focus worldwide for HTST systems at present is electricity generation and this section focuses on the market potential, drivers and challenges for HTST electricity-generation applications only.61

3.1 European Union – Middle East North Africa (EU-MENA) The HTST sector’s rebirth in Europe is being carried forward by Spain, which has set an objective of 500 MWe to be deployed by 2010 that is backed by its feed-in tariff law. Spain inaugurated its first commercial HTST power plant in Seville in 2006 (PS10 with 11 MWe), with the next one expected for 2008 in Grenada (Andasol 1 with 50 MWe). More than 1,000 MW of HTST electricity generation systems are under development or proposed in Spain (Figure 10 illustrates the range of these installations).

Figure 10: Proposed concentrating solar thermal power installations in Spain62 Interest is also increasing in other southern European countries and Israel to deploy HTST systems that take advantage of feed-in tariff support measures such as the following63:

SPAIN The feed-in tariff regulations of Royal Decree 436/2004 have been refined with the recent Royal Decree 661 from 2007. The primary change with respect to RD436 is the decoupling from the market reference price, which rose with oil price increases and automatically increased renewable tariffs with the oil price. A fixed tariff of 0.269375Euro/kWh is granted for Concentrating Solar Power (CSP) plants up to

61 Background research has indicated that while reference is made to other applications for HTST systems, the

readily available data is predominantly focused on power applications. No compelling evidence was found in Australia or elsewhere for industrial process heat applications of HTST, although it is recognised that this is a potential market. It also is acknowledged that a future application could be the generation of fuels such as hydrogen for transport and stationary power applications or syngas for chemical processes or stationary power.

62 Mark Schmitz, Solar Thermal Power and Process Heat: Overview and State of the Art Examples, Lyon (2007). 63 http://www.solarpaces.org/News/news.htm, last accessed 23 Sep 07.



50MW for 25years, increasing yearly with inflation minus 1 percentage point. The CSP target was increased to 500MW by 2010.

PORTUGAL A new feed-in tariff for solar electricity was published in Portugal in 2007, granting 0.27 €/kWh for CSP plants up to 10MW and 0.16-0.20 €/kWh for CSP plants beyond 10MW.

FRANCE A new feed-in tariff for solar electricity was published in France on July 26, 2006, granting 0.30 €/kWh plus an extra 0.25 €/kWh if integrated to a building. This tariff is limited to solar only installations with less than 12 MW capacity and less than 1500 hours/year operation. For production over this limit the tariff is 0.05 €/kWh.

GREECE Law 3468/2006 Generation Of Electricity Using Renewable Energy Sources And High-Efficiency Cogeneration Of Electricity And Heat And Miscellaneous Provisions (Official Gazette A’ 129) was published in 2006 and grants solar energy exploited in units employing a technology other than that of photovoltaics with an installed capacity up to 5 MWe 0.25 €/kWh on the mainland and 0.27 €/kWh on non-interconnected islands.

ISRAEL The Israel Ministry of National Infrastructures, which is responsible for the energy sector, decided in 2002 to introduce to the Israel electricity market CSP as a strategic ingredient, with a minimal power unit of 100 MWe. In 2006, Israel Public Utilities Authority’s New Feed-in Incentives For Solar-Driven Independent Power Producers were published, being valid as from September 3 2006 for a 20 year period. For plants with installed capacity larger than 20 MWe the tariff for the solar part only is approximately 16.3 UScents/kWh (Nov.2006). Maximum allowed fossil back-up is 30% of the energy produced in the plant. For smaller plants below 20MW in the range of 100 kW to 20 MW, for the first 20 years period the tariff is approximately 20.4 UScents/kWh.

The Middle East and North Africa (MENA) region is particularly prospective — because of the very favourable solar insolation in this region — for HTST power generation to meet the growing needs of the MENA region as well as, prospectively, to supply northern Europe. One example is the Masdar Initiative, Abu Dhabi's landmark program in sustainable energy, which is driving the adoption of advanced solar technologies in the United Arab Emirates.

“With regard to concentrating solar power, Masdar is in the process of contracting the United Nations Environmental Program (UNEP) to conduct a comprehensive solar energy resource assessment to evaluate the potential of large-scale concentrating solar power (CSP) projects in Abu Dhabi. In tandem Masdar, with the support of the Abu Dhabi Water and Electricity Authority (ADWEA), have engaged Fichtner of Germany to provide technical advisory services and the German Aerospace Agency (DLR) to provide evaluation for the first major solar power plant to be built in the region. This CSP plant would feed into the national electricity grid and provide opportunities for peak-power 'shaving'.

Complementing these solar projects is the Masdar Research Network (MRN), which is funding advanced solar research and development together with six world-class research institutes in North America, Europe and Japan. The research focus includes thin-film photovoltaics, spherical PV, beam-down solar towers and thermal storage for solar power.”64

A major study undertaken by the German Aerospace Centre’s (DLR) Institute of Technical Thermodynamics on Concentrating Solar Power for the Mediterranean Region65 was published in November 2005. This study noted that “A strategic partnership between the European Union (EU), the Middle East (ME) and North Africa (NA) is a key element of such a policy (to introduce

64 http://www.ameinfo.com/109358.html, last accessed 23 September 2007. 65 Available at http://www.dlr.de/tt/desktopdefault.aspx/tabid-2885/4422_read-6575/



renewable energies on a large scale) for the benefit of both sides: MENA has vast resources of solar energy for its economic growth and as a valuable export product, while the EU can provide technologies and finance to activate those potentials and to cope with its national and international responsibility for climate protection. ....... (The MED-CSP study revealed) that the installed concentrating solar power capacity by 2050 is as large as that of wind, PV, biomass and geothermal plants together, but due to their built-in solar thermal storage capability, CSP plants deliver twice as much electricity per year as those resources” (see Figure 11).

Figure 11: Projected annual electricity demand and generation within the countries in the MED-CSP

scenario66 A later study by DLR published in April 2006 (‘TRANS-CSP’) concluded that “solar electricity generated by concentrating solar thermal power stations in MENA and transferred to Europe via high voltage direct current transmission can provide firm capacity for base load, intermediate and peaking power, effectively complementing European electricity sources. Starting between 2020 and 2025 with a transfer of 60 TWh/y, solar electricity imports could subsequently be extended to 700 TWh/y in 2050. High solar irradiance in MENA and low transmission losses of 10-15% will yield a competitive import solar electricity cost of around 0.05 €/kWh.”67

3.2 USA The U.S. Department of Energy (DOE) has established a goal to install 1,000 MW of new concentrating solar power systems in the southwestern United States by 2010.68 This level of deployment, combined with research and development to reduce technology component costs, could help reduce concentrating solar power electricity costs to US$0.07/kWh. At this cost, concentrating solar power can compete effectively in the Southwest's energy markets. 66 Concentrating Solar Power for the Mediterranean Region — Executive Summary, German Aerospace Center (DLR),

Institute of Technical Thermodynamics, Section Systems Analysis and Technology Assessment, April 2005. 67 Available at http://www.dlr.de/tt/desktopdefault.aspx/tabid-2885/4422_read-6583/ 68 http://www.nrel.gov/csp/1000mw_initiative.html, last accessed 12 Sep 2007.

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To achieve this goal, the DOE is partnering with the Western Governors' Association to encourage concentrating solar power installations in Arizona, California, Colorado, New Mexico, Nevada, Texas, and Utah. These states not only have the best solar resources in the United States, but installing concentrating solar power systems also is perceived to assist them to:

• Meet rapidly growing electricity demand, providing the highest capacity during utility peak loads

• Reduce the load on long distance transmission lines

• Meet their renewable energy portfolio standards

• Diversify their energy supply

• Reduce the demand for and price pressure on natural gas

• Improve and/or maintain air quality

• Create new jobs and economic opportunity. A February 2007 report to the US Congress by the DOE69 concluded that recent events have occurred that have changed the outlook for the deployment of concentrating solar power. Foremost among the changes are policies initiated by US State and Federal Governments:

• Many States have implemented renewable portfolio standards (RPS’s) which encourage the deployment of solar technologies, including CSP (Figure 12).

• The US Government, through Section 1335 of the Energy Policy Act of 2005 (EPACT 2005), established a 30% investment tax credit for solar installations.

o However, the continuation of the production tax credits in the USA beyond December 2007 is not assured.70

Figure 12: USA States with renewable portfolio standards71

69 US DoE Energy Efficiency and Renewable Energy, Assessment of Potential Impact of Concentrating Solar Power for

Electricity Generation, Report No. DOE/GO-102007-2400, February 2007. 70 Clean energy groups face 'tough road' in getting tax-credit extensions in stimulus package, San Jose Mercury News,

29 January 2008 (http://www.mercurynews.com/greenenergy/ci_8110550?nclick_check=1, last accessed 31 Jan 2008).

71 Sourced from http://www.pewclimate.org/what_s_being_done/in_the_states/rps.cfm, last accessed 31 Jan 2008.



This report also noted that “although CSP costs more today than other renewable options such as wind, there are several reasons for utility interest in CSP:

• CSP electricity production aligns closely with periods of peak electricity demand, reducing the need for investment in new generating plants and transmission system upgrades.

• Thermal storage or the hybridization of CSP systems with natural gas avoids the problems of solar intermittency and allows the plant to dispatch power to the line when it is needed.

• The widespread availability of solar energy throughout the Southwest provides utilities with flexibility in locating CSP plants near existing or planned transmission lines.

• Placing CSP plants on the “right” side of congestion can reduce grid congestion and increase grid reliability.

• Large centrally-located power plants are the types of systems that the utilities have operated for years and with which they are most comfortable.

• Once the CSP plant is built, its energy costs are fixed; this stands in contrast to fossil fueled plants that have experienced large fluctuations in fuel prices during the last several years.”

The States of Nevada and New Mexico have conducted economic feasibility studies on deployment in their States, while California has conducted a broader-scope economic study72 that provided an assessment of CSP technologies and California’s solar resource, determined the environmental and energy benefits of CSP, and estimated the economic impact to the state. The California study also compared the economic impact of CSP with natural gas power plants. Because California’s need for electrical power is much greater than Nevada and New Mexico, the study examined large-scale deployment scenarios assumed to be built between 2008 and 2020 and found that building between 2,000 and 4,000 MW of CSP would have the following effects:

• US$7 to US$13 billion in new investment, of which an estimated US$2.8 to US$5.4 billion would be spent in California.

• An increase in Gross State Product of between US$13 and US$24 billion.

• The creation of 1,500 to 3,000 jobs. Moreover, the study found that a CSP plant requires an approximately 67% larger workforce than a comparably sized combined cycle plant. During construction, the impact of each 100 MW of CSP on Gross State Product is significantly higher than that of a similarly sized combined cycle gas plant (US$628 million vs. US$64 million). The report concluded that “investment in CSP power plants delivers greater return to California in both economic activity and employment than corresponding investment in natural gas equipment”.

3.3 Cost perspectives Sandia Laboratories in the USA has published an overview that provides an estimate of current and future costs for HTST technologies (Table 2). In 2003, the US DOE published a major cost-reduction study undertaken by the consulting firm Sargent & Lundy73. This study concluded that HTST is a proven technology for energy production; there is a potential market for CSP technology; and significant cost reductions (see Figure 13) are achievable assuming reasonable deployment (multi-GW scale) of CSP technologies occurs. In the technically aggressive cases for

72 L. Stoddard, J. Abiecunas, and R. O’Connell, Economic, Energy, and Environmental Benefits of Concentrating

Solar Power in California, Black and Veatch, April 2006 73 Sargent & Lundy, Assessment of Parabolic Trough and Power Tower Solar Technology Cost and Performance

Forecasts, Prepared for Department of Energy and National Renewable Energy Laboratory, May 2003.



troughs/towers, the Sargent & Lundy analysis found that cost reductions were due to volume production (26%/28%), plant scale-up (20%/48%), and technological advance (54%/24%).

Table 2: Characteristics of solar thermal electric power systems (from Sandia Laboratories74)

Parabolic Trough Power Tower Dish/Engine Size 30-320 MW* 10-200 MW* 5-25 kW* Operating Temperature 390 ºC 565 ºC 750 ºC Annual Capacity Factor** 23-50%* 20-77%* 25% Peak Efficiency 20%(d) 23%(p) 29.4%(d) Net Annual Efficiency 11(d’)-16%* 7(d’)-20%* 12-25%*(p) Commercial Status Technology Development Risk Storage Available Hybrid Designs

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3,100-320* 12.6-1.3* 12.6-1.1*

* Values indicate changes over the 1997-2030 timeframe. ** Increases in capacity factor due to the use of thermal storage. † $/Wp removes the effect of thermal storage (or hybridization for dish/engine). (p) = predicted; (d) = demonstrated; (d’) = has been demonstrated, out years are predicted values

Figure 13: Levelised electricity cost projections — summary from Sargent & Lundy study, 2003.

74 http://www.energylan.sandia.gov/sunlab/PDFs/solar_overview.pdf, last accessed 23 Sep 2007.



The European Union’s ECOSTAR roadmap75 notes that today’s technology of HTST could provide electricity in the cost range of 15 to 20 cents€/kWh and compete in the conventional market in Europe with mid-load power in the range of 3 to 4 cents€/kWh. The ECOSTAR roadmap continues that “sustainable market integration as predicted by different scenarios can only be achieved if the cost will be reduced in the next 10 to 15 years to a competitive level. Competitiveness is not only impacted by the cost of the technology itself but also by a potential rise of the price of fossil energy and by the internalization of associated social costs such as carbon emissions. Therefore (it is assumed) that in the medium to long-term competitiveness is achieved at a level of 5-7 cents€/kWh for dispatchable mid-load power. Using a scenario technique to quantify the world-wide deployment of CSP through 2025 and taking into account learning and scaling effects, the overall investment cost and the average levelised electricity cost (have been) estimated. This approach predicts a cost reduction down to 5 cents/kWh at a total installed capacity of 40 GW achieved between 2020 and 2025 (Figure 14).”

Figure 14: Scenario of reducing LEC for HTST electricity using learning curve approach

(from European ECOSTAR roadmap)


CT-2003-502578, Issue 1-25 on 15 Feb 2005.



4 HTST — Market potential and barriers in Australia The potential market for HTST-based systems will depend upon their economic competitiveness, which in turn depends upon the relative costs of energy generation compared to conventional technologies, as well as other new technologies. Future costs of fossil fuel based technologies will increase under existing or proposed greenhouse gas mitigation measures such as emissions trading. To gain an understanding of their economic competitiveness and market potential in Australia, a study of the costs of electricity generation using HTST systems has been undertaken by McLennan Magasanik Associates (MMA). This study explored the market potential through the use of a model that determines the long run marginal cost (also known as levelised cost) of HTST electricity generation in Australia76. The full analysis of the results of this study is provided in Appendix A to this roadmap.

4.1 Australia’s electricity market characteristics The principal electricity grids in Australia are the National Electricity Market (NEM), the South West Interconnected System (SWIS) and the Darwin Katherine Interconnected System (DKIS). Smaller but still important potential markets for high temperature solar thermal (HTST) power generation include the Alice Springs-Tennant Creek system, the Mount Isa grid and the Pilbara System in Western Australia. Remote mining operations may also offer prospects for HTST, but the short life of many mines (typically less than the life of the HTST plant) acts as a major barrier for HTST technology in this particular market segment. Loads at remote homesteads and communities are generally considered to be too small to be suited to HTST technologies. Fossil fuels are the dominant form of energy for electricity generation in Australia due to their low costs and maturity of the generation technologies based on them. Coal-fired generation is dominant in most of the mainland states and contributes 75% of the total generation in Australia while natural gas contributes 14%. High electricity growth rates over the past decade have been mainly met by increased natural gas fired generation and higher coal-based generation. Ongoing drought has also limited the contribution from hydro-electric systems. Electricity demand, projected to grow by 1.7% to 2.1% per annum over the period to 2050, and the need to curb emissions of carbon dioxide may favour increasing penetration of renewable electricity generation.

4.2 Role of renewable generation Renewable generation currently plays a limited role in Australia’s electricity markets. Renewable electricity generation has grown but its share of total generation has fallen from 10.5% in 1996/97 to 9.4% in 2006/07. Although wind and other new renewable generation have grown, hydroelectric generation has fallen as a result of prolonged drought. Growth in renewable generation has been economically possible mainly through Government support by measures including:

• Australian and State Government imposed mandatory targets for the purchase of renewable generation.

o The Australian Government’s MRET scheme came into operation in 2001 and mandates the generation of 9,500 GWh of renewable generation from 2010.

76 All costs in this Chapter 4 are in real terms as of mid-2007.



Victoria, Queensland and Western Australia have also imposed their own targets. However, the Australian Government has proposed that these State schemes be replaced by a single, expanded MRET target of 45,000 GWh of new renewable generation by 2020 (Table 3).

Table 3: Renewable energy targets, GWh

Year Current MRET Target Expanded MRET Target 2010 9,500 9,500

2011 9,500 13,050 2012 9,500 16,600 2013 9,500 20,150

2014 9,500 23,700 2015 9,500 27,250

2016 9,500 30,800 2017 9,500 34,350 2018 9,500 37,900

2019 9,500 41,450 2020 9,500 45,000

Source: MMA estimate

• Green Power schemes, which grew by 25% during 2006–07 as more people become concerned over climate change, and now comprise around 1,500 GWh of generation.

o In 2006 Green Power has contributed around 20% additional renewable energy sales above the MRET target.

• Renewable Energy Development Initiative and Renewable Energy Equity Fund, which have been used to develop and commercialise novel renewable energy technologies.

o The Australian Government has proposed establishment of a $150 million fund for research and development of new renewable energy technologies.

• Renewable Remote Power Generator Program.

• Photovoltaic Rebate Program.

• Low Emission Technology Development Fund, which has funded some demonstration projects for low emission technologies, including a 150 MW solar PV concentrator plant.

o The Australian Government has proposed establishment of another $500 million fund to demonstrate new renewable energy technologies.

• The $100 million NSW Renewable Energy Development Fund. Despite the support from government programs, renewable energy generation is still more expensive than fossil fuel generation options. Only in remote area power supply systems is renewable generation now competitive with fossil fuel alternatives and this applies to PV type systems, not large scale systems like HTST. To date, HTST has not been able to exploit the potential market under MRET or any other deployment support program. This probably reflects its stage of development, a negative attitude towards the technology and cost reductions achieved in more mature technologies such as wind generation. Current estimates of levelised costs for generation options are shown in Figure 15 The chart indicates that renewable energy costs are at least 50% above fossil fuel generation costs and HTST is some three times more expensive than fossil fuel generation options.



Figure 15: Levelised electricity generation costs in 2007 (Source: MMA analysis)77

4.3 Economics of HTST generation Although HTST-derived electricity is currently expensive, further technological development and increased deployment will see this cost fall over time. Its market potential was examined through the use of a model that determines the levelised energy cost of various generation options in the electricity markets in Australia. A number of case studies are developed to examine the potential, with these studies being representative of the market opportunities available for HTST generation. The cost of HTST generation is compared to the cost of alternative generation options. The premise is that the least cost alternative will be selected to supply the market. Thus, HTST generation will only have potential if its cost of generation is lower than the alternatives. Seven potential locations were selected on the basis of having good insolation levels, proximity to local loads and high generation electricity costs from alternative options:

• Port Augusta in South Australia. A plant located here would be connected to the National Electricity Market (NEM). There are local industrial loads and any excess can be transmitted to other load centres in South Australia. The HTST options include retrofitting an existing coal fired unit at Northern Power Station, which provides additional advantages including prolonging the life of the coal mine supplying the plant and avoiding imports of black coal from NSW. Alternatives to HTST include gas-fired generation in South Australia, imports of black coal-based or brown coal-based generation from other states and geothermal generation.

77 Calculated using a real weighted average cost of capital of 9%, lifespan varying from 25 to 35 years, capacity

factors of 34% for wind, 25% for solar thermal, 80% of geothermal and biomass, and 90% for all other options

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• North West Victoria. A plant located here would be connected to the National Electricity Market and supply a number of regional towns in north-west Victoria such as Mildura and Swan Hill and, through the Murraylink interconnect (a 220 MW HVDC link connecting Victoria and South Australia), could also supply some regional loads in South Australia. HTST technology would not only be competing against centrally dispatched thermal generation, but also potentially against other renewable technologies, e.g. the 150 MW concentrator PV technology plant proposed by Solar Systems in this location.

• Central and North West NSW. A location with good solar insolation levels, an economic sized plant located here would supply some small regional loads but would also need to be supplying loads further away. The plant would be competing with black coal generation in NSW and Queensland as well as some other renewable energy projects proposed for the area (such as the 1000 MW Silverton Wind Farm near Broken Hill). Because of the small size of the local load, supporting a large scale HTST option here would likely require an upgrade of the regional transmission system. A gas pipeline connection may also need to be constructed to provide gas for when there is no sunshine.

• Darwin-Katherine Interconnected System, which supplies Darwin and other major regional centres nearby. Electricity prices in the DKIS are high, reflecting the high cost of gas and the small scale of generation capacity. HTST would be competing against gas fired combined cycle or open cycle generation. A major advantage for HTST is the limited options for renewable generation in the region in the form of hydro and wind, with the long term potential limited to biomass and geothermal. A location near Katherine, just south of the wet season zone, has been assumed.

• Alice Springs – Tennant Creek. This location has good insolation and a load sufficient to cater for HTST plant of between 10 MW to 40MW. Alternatives are limited and are high cost.

• Kalbarri, which is the northern-most extremity of the South West Interconnected System. Again there is reasonable local load (township of Geraldton). Black coal and natural gas based generation are the major competitors. Although HTST generation is more expensive currently than these forms of generation, there have recently been sharp increases in fuel prices in the region: gas prices have more than doubled and coal prices have increased by 50%. Assuming fuel prices stay at, or increase from, current levels then the gap in cost may well narrow.

• Remote large town or mining operation. Western Australia and the Northern Territory contain many such locations that would support HTST generation in the order of 10MW. Again, alternative options are high cost, particularly given high liquid fuel and natural gas prices.

Three high temperature solar thermal options were examined in this analysis:

• Stand-alone HTST operation, with gas used as a back-up fuel for when there is no sunlight. Where gas is not available on-site, it was assumed that a lateral from the nearest pipeline would be built to the site.

• HTST with sufficient storage to allow intermediate operation.

• HTST providing steam to an existing coal or gas-fired plant (so called solar assist). For grid connected applications, the cost of providing power was examined for peak period operation of the plant (typically 6.00 am to 10.00 pm on weekdays). Demand in peak periods is growing faster than off-peak demand due to a combination of increased penetration of air-conditioners in homes and commercial buildings and increased use of computers and other electrical appliances. Prices are typically higher in the peak period reflecting the high cost of conventional options supplying peak power. For off-grid application, 24 hour power supply options are considered.



4.3.1 Methodology Generation costs have been estimated using MMA’s GENCHOICE model that calculates the levelised energy cost (LEC) for generation plant. The LEC of a new generation option is equal to the present value of capital, fuel and operating costs divided by the present value of the output over the expected life of the plant. For each option, the full costs of generation are modelled. Costs include:

• Capital costs, which are modelled as a function of capacity (to reflect the economies of scale with unit size).

• Coal, biomass, liquid fuel or natural gas costs are modelled as delivered cost for the fuel on a $/GJ basis and a heat rate for each technology option.

o The natural gas cost is equal to the forecast city gate price for the nearest city gas node as forecast by MMA plus any additional transmission cost (in some locations the additional transmission cost may be negative if the plant location is closer to the gas field than the city gate node).

• Non fuel operating and maintenance costs.

• Transmission connection costs (including deep connection cost if the plant supplies more than the local loads).

• Network fees for backup supply.

• Sequestration costs (if any). Levelised generation costs are calculated for each year of entry of the plant from 2010 to 2030. In this way, trends in capital costs, conversion efficiency and fuel prices are captured. Costs are also affected by the following:

• Carbon prices.

o The model adds a variable cost equal to the assumed carbon price multiplied by the emission intensity of the generator. Emission intensities are based on the emission intensities of fuels supplying power stations as estimated in the National Greenhouse Gas Inventory.

• Locational benefits in the form of avoided transmission costs.

o These benefits, if any, are treated as negative costs. Avoided transmission upgrade costs are treated as negative capital costs. Avoided transmission use of system charges are treated as negative variable costs.

Renewable generation such as HTST generation may also provide other benefits. For example, renewable generation provides generators with a hedge against fuel supply risks. Fossil fuel based generators can face significant risks over the future cost of the fuel, even when they enter into a long term contract for fuel (as these often contain price re-openers). Ample supplies of coal and natural gas have meant that the risks of price changes for fuel have, in the past, been minimal in Australia. However, in some regions of Australia recent developments have increased the risk, particularly for natural gas and even more so for liquid fuels. Future emission prices are also highly uncertain, with prices depending on the targets on emissions imposed and the cost of abatement. This means that owners of fossil fuel plants also face uncertainties over future cost imposts on emissions. On the other hand, intermittent sources of generation such as stand-alone HTST have the risk of not being able to supply electricity when needed. In this analysis, this has been mitigated by the inclusion of storage or natural gas co-firing to extend the hours of operation on a reliable basis.



Reflecting the lower fuel supply and lower emission risks of HTST, a deduction of 1 percentage point from the weighted average cost of capital is applied to HTST options with no gas co-firing and 0.5 percentage point deduction for HTST with natural gas co-firing.

4.3.2 Assumptions Initial physical and cost assumptions and key escalators for all generation systems modelled and for fuel prices are provided in Appendix A. The key inputs used in MMA’s GENCHOICE model for HTST are shown in Table 4. Capital costs of HTST used for the 2010 estimate compare with the following cost estimates78 for recent projects completed or underway:

• €29 million for the 10 MW PS10 solar tower plant in Southern Spain, amounting to around $50 million in 2007 dollars or around $5,150/kW.

• €53 million for the 15 MW Solar Tres solar tower plant in Spain, which includes an innovative molten salt storage system. This amounts to around $90 million in 2007 dollars or around $5,900/kW.

• €157 million for the 50 MW Euro Trough plant proposed for Andasol in Spain, which includes a molten salt based storage system to provide 9 hours of storage. This amounts to around $260 million in 2007 dollars or around $5,230/kW.

Table 4: Physical and cost assumptions for HTST technologies79

Item 2010 2020

Net Power MWe (per plant) 150 400

Solar field optical efficiency 0.598 0.602

Annual solar to electric efficiency 17.0% 17.2%

Capacity factor 56% 56%

Capital costs ($A/kWe)

Structures 95 70

Solar collector 2,625 1,965

Thermal storage 665 665

Steam Generator 130 125

EPGS 510 340

BOP 295 200

Total 4,320 3,360

Operating costs ($A/MWh) 13.5 10

Source: MMA analysis based on Simons (2005) and Sargent and Lundy (2003). US dollar estimates were converted into Australian dollar estimates using an exchange rate of 0.89. Capital costs were increased by 40% for the 2010 estimates to reflect the impact on capital costs of recent shortages of skilled labour, equipment supply constraints and high material costs. The 2020 estimates were left as is to reflect the assumptions that current tight supply constraints in materials and equipment will have been alleviated by then.

78 European Commission, Concentrating Solar Power: Main Projects Supported By The Commission, Brussels, 2007.

Costs were reported in 2005 dollars. All costs were converted to mid 2007 Australian dollar terms by inflating 2005 price by 2.5% per annum and using an exchange rate of A$:€0.60

79 Differences in solar irradiation by location were based on data provided by the Bureau of Meteorology and were expressed in the model in differences in the capacity factor applicable to HTST capacity without storage (with the amount and thus cost of storage adjusted to give the required time of operation of 91 hours per week).



A key issue is the rate of change in capital cost for HTST in the future. Estimates of the potential cost reduction vary widely, as follows:

• Navigant Consulting in a study for Arizona Department of Commerce80 claim that costs of electricity from parabolic dishes will decline by more than 50% by 2025 (to US$80/MWh or around A$90/MWh assuming an exchange rate of 0.89).

• A recent Sandia National Laboratories report81 identified 6 possible avenues for technological improvements in heliostat technologies for power towers that would reduce capital costs.

• A study by the DLR for Europe82 indicated that levelised energy costs could fall from current levels of around 15 (parabolic trough) to 20 (Dish Stirling) Euro cents/kWh (or A$265 to A$350/MWh in 2007 dollar terms) to around 5 Euro cents/kWh (or A$90/MWh in 2007 dollar terms) through learning by doing and economies of scale if around 40 GW of capacity was installed by 2020 to 2025.

o Around half of this cost reduction is predicted to be due to production scale up effects and the other half by technological development.

o The cost reductions are likely to come through improved concentrator performance, scaling up plant size, improved storage systems and improving the capability of receivers to generate high temperature steam.

4.3.3 Cost comparisons Results of the cost modelling for HTST generation plants and comparisons to alternatives are detailed in Appendix A. The following is a summary, focusing particularly on the effect of a carbon pricing through the proposed emissions trading scheme in Australia. NEM (South Australia, Victoria and NSW) HTST, on a stand-alone basis (with gas co-firing) or with storage, is currently not economic as an option for locations near Port Augusta in South Australia, near Mildura in north-west Victoria and locations in central and north-west NSW. Although the cost of HTST technology is likely to fall over time, the rate of decline based on data available for this analysis is likely to be insufficient under current progress ratios for capital cost. Solar assist options offer the best prospect, with this option likely to be economic by 2020. Carbon prices of around $10/t CO2e would likely see solar assist being economic relative to other new generation options. Carbon prices of around $60 to $70/t CO2e are likely to see other HTST technologies being economic in these NEM-connected locations relative to other new generation options (Figures 16 to 18).

80 Arizona Solar Electric Roadmap Study, prepared for the Arizona Department of Commerce by Navigant Consulting,

Inc., January 2007. 81 G. Kolb et al, Heliostat Cost Reduction Study, Sandia National Laboratories Report No. SAND2007-3293, June 2007. 82 ECOSTAR: European Concentrated Solar Thermal Roadmap Document, European Commission Document No. SES6-

CT-2003-502578, Issue 1-25 on 15 Feb 2005.



Figure 16: LEC of generation to supply Port Augusta as a

function of carbon price, peak period duty, 202083

Figure 17: LEC of generation to supply north west Victoria as a function of carbon price, peak period duty, 2020

83 Note that the cost of HTST technology increases with carbon price to reflect the cost of emissions from the gas-

fired component of the generation. The minimum cost alternative represents the levelised cost of the lowest cost fossil fuel alternative at each carbon price.

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Figure 18: LEC of generation to supply central and north west NSW as a function of carbon price, peak period duty, 2020

Kalbarri The analysis assesses the cost of supplying power to the Geraldton node for stand alone HTST and alternatives in the SWIS supplied from the grid. Note that HTST plant greater than about 100 MW in this location would be supplying other nodes in the SWIS apart from Geraldton. HTST technologies are likely to be higher cost than alternatives for supplying loads to Geraldton in the near future, but HTST solar assist attached to an existing coal steam plant (Muja Power Station) could be economic next decade (assuming gas prices remain high) and the life of this thermal power station could be extended as a result. Carbon prices of $60/t CO2-e would make HTST with gas co-firing economic for intermediate load duty. Carbon prices of $50/t CO2-e would make HTST with storage economic relative to other options for high load duties towards the end of next decade (Figure 19).



Figure 19: LEC of generation to supply Geraldton as a function of carbon price, peak period duty, 202084

Katherine For other locations examined, the gap between the cost of HTST technologies and alternatives is narrower. At current fuel prices, the gap between HTST and other technologies is estimated to be around $40/MWh in 2010. By 2020, some HTST technologies could well be close to being an economic alternative in places like Katherine (Figure 20), especially if gas and liquid fuel prices rise further. Carbon prices of around $30/t CO2-e; capital costs of alternatives moving 10% higher than current costs; or fuel costs similarly higher than current levels may see HTST technologies being able to compete in remote northern locations with large loads by 2020. These regions offer the best near term prospects for HTST technologies. Remote areas Remote area power supply systems tend to be much smaller in size, with demand ranging from less than 1 MW for small communities and homesteads to around 20 MW for the larger communities and mining operations. Because of the small size of the operation and potentially low water availability in remote areas, the analysis was confined to parabolic dish systems of 5 to 10 MW minimum capacity, backed up by some diesel engines. Because of the small scale and the relative capital intensity of HTST systems, the technology is not likely to be an economic option for remote power systems. However, carbon prices of around $30/t CO2-e will likely see HTST options economic relative to diesel only operation by mid next decade. Increasing the carbon price to $55/t CO2-e will likely see it economic compared to the compressed natural gas options by 2020 (Figure 21).

84 The minimum cost alternative line kinks at around $30/t CO2e due to the change in least cost technology. Below

$30/t CO2e, the least cost technology is a coal-fired option. After $30/t CO2e, the preferred or least cost technology is a gas-fired option.

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Figure 20: LEC of generation to supply Katherine as a function of carbon price, peak period duty, 2020

Figure 21: LEC of generation to supply remote areas at a carbon price of $55/t CO2e

250

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Compressed Gas Engines Diesel Only HTST

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4.4 Market potential A recent report by Connell Wagner for the Owen Inquiry into electricity supply in New South Wales85 noted that “the cost of power from a solar thermal power plant is mainly due to the initial construction investment cost and the low capacity factor, the fuel cost is zero as the energy input is free. This makes the marginal cost of generating very low and competitive with coal fired plant in this respect. However, once the return on capital is factored it would require that the investor receive a relatively high price for the electricity for the economic life of the plant, to make a project financially viable. Since the technology is still in an early stage of development the construction cost is expected to reduce as experience is gained. ............ The “all in” plant costs for previous concentrating solar plants resulted in electricity prices in the range $170 to $210/MWh. Technology improvements have since reduced this price to $120 to $150/MWh. Cost reductions for solar plants are related to the installed MW and further technology improvements. The approximate cost of a solar plant is estimated to be around $3000/kW based on US conditions. The levelised cost of electricity from solar thermal is likely to reduce as a function of MW installed. At the 5000MW level it has been estimated that electricity may be able to be produced at $80/MWh.” The results of MMA’s cost-modelling analysis are in line with those from the Connell Wagner report and other studies overseas that predict that HTST technologies are unlikely to be competitive with alternative generation options in the near term, although it is evident that HTST, particularly with thermal energy storage, has high potential to penetrate electricity markets in locations with suitable solar exposure. Near-term exceptions in Australia are in remote northern locations with major loads and solar assist in certain other locations. Improving the competitiveness of HTST technologies will require either or both:

• Faster rate of development and deployment of the technologies so that capital costs decrease substantially.

o It appears from this analysis that the best option for gains comes from reducing the capital costs of the solar collectors or mirrors.

o Conversion efficiency improvements could also help but the impact on cost is more limited.

• Imposition of an emission trading scheme.

o Prices of $50/t CO2-e or more are required. Such prices are likely in the future if deep cuts in emissions are to be achieved. This offers the greatest promise for solar thermal technologies.

4.4.1 Competition principles A key feature of Australia’s electricity market is its competitive nature. HTST has to compete with other technologies in order to supply electricity in the markets. In the major grids, generators bear the risk of their generation remaining competitive. Generators compete for the right to be dispatched on the spot market through a regular auction process, which tends to select for the lowest cost options available to meet particular market segments (base, intermediate and peak loads). Even in smaller grid or remote power supply systems, generation rights are now largely determined through tenders that select the least cost option. The

85 R Boyd, A Sproule, P Benyon, C Grima, K Naicker, P Ward and C Feltrin, NSW Power Generation and CO2 Emissions

Reduction Technology Options, Connell Wagner Pty Ltd, 27 August 2007 (an expert report to the Owen Inquiry into Electricity Supply in NSW, available at http://www.nsw.gov.au/energy/download.aspx?id=83395475-24a6-401c-adcd-2ca4d60f05fb).



competitive nature of the markets is also enshrined in National Competition Laws, which prevents Governments or market operators from enacting regulations that favour one type of technology over any other type of technology unless there is a clear, demonstrated benefit to the community. The competitive nature of markets has tended to favour fossil fuel generation due to its low fuel cost and its high conversion efficiency. However, the markets for electricity are evolving. Increasing fossil fuel and capital costs have increased the cost of fossil fuel generation relative to renewable energy generation. In some states, gas prices have more than doubled over the last two years. Coal prices have also increased due to higher demand for thermal coals on world markets. The likelihood that carbon abatement policies will be enacted sometime in the near future has put a risk premium on high emission fossil fuel generation options such as coal-fired. These factors are favouring the adoption of renewable energy generation, which has been backed by a number of government support measures designed to increase the deployment of renewable energy and reduce its cost. But Australia also is blessed with other renewable or low emission resources. Good wind profiles and niche biomass resources are available and this has led these technologies to dominate the market for renewable energy in Australia so far. HTST will be competing with these and other renewable and low-emission technologies on cost in order to carve out a market niche.

4.4.2 Market segments Peak lopping The analysis confirms that HTST could compete with gas-fired generation to meet peak demand sometime over the next decade should HTST capital costs be reduced as planned. However, the peak demand in the major electricity markets is characterised by a high level of demand for a short period of time. For example, the highest 1000 MW of peak demand in Victoria occurs for less than 1% of the hours in the year. Thus, an HTST plant would be competing with a mixture of peaking and intermediate plant in most electricity markets in Australia. High load duty HTST can supply high load duty (base and intermediate load) markets either where there is a high solar insolation level near a major load, where there is a nearby gas network to supplement steam raising at the HTST plant or adequate energy storage is part of the HTST plant. In Australia, there are two circumstances where HTST technology can provide high load duty operation. First, isolated grid systems where there is a gas network as well as good solar insolation resources could provide an opportunity for high load duty operation by HTST plant with gas co-firing. Potential grids include the Mt Isa Mineral Province (which is currently supplied by gas fired generation and is the site for a proposed HTST plant with graphite block storage (Cloncurry)), Alice Springs Reticulated System, Tennant Creek Reticulated System and North West Interconnected System in the Pilbara. All sites have average daily sunshine hours of greater than 9 hours per day86 and average daily insolation levels of greater than 21 MJ/m2. All have gas pipelines supplying gas-fired open cycle gas turbines. Generation costs are also typically high due to the high cost of gas and the small scale of the generating plant. The need for new capacity to meet load growth in these four isolated grid systems is around 350 MW by 2030, with the bulk of this required at Mt Isa and the North West Interconnected

86 Australian Bureau of Meteorology (2000) quoted in D.R. Mills, Fresnel Reflector Solar Power Plants, University of

Sydney, 2006.



System.87 Furthermore the cost of generation has increased markedly in these regions because of recent increases in prices of natural gas (which have more than doubled over the past two years) and liquid fuels. Although published data on electricity supply costs are somewhat limited, the data available indicate that purchase costs are up to $145/MWh at the wholesale level. Assuming an average size of 20 MW for an HTST plant, the cost analysis indicates that HTST could be an economic option for these grids some time towards 2020. The second potential market for high load duty power is to supply the major grids under a favourable policy regime where governments support renewable generation or there is a high price on carbon emissions. The Australian Government has a target of 45,000 GWh of new renewable generation by 2020, of which 9,500 GWh is already locked in under the existing MRET scheme giving an additional requirement from now until 2020 of around 35,500 GWh. HTST will compete with other renewable resources to meet this target. Unless there are substantial cost reductions for HTST though, it is unlikely to benefit from this scheme (see Figure 22). The cost of HTST generation is forecast to likely be substantially greater to 2020 than the low cost options for wind, hot dry rocks geothermal and biomass generation.

Source: MMA analysis from its database of renewable energy project costs. Note: Covers existing and committed plant (short run marginal costs only) as well as the cost for

new renewable generation for all other sources of renewable generation apart from HTST. Each point represents the net levelised electricity cost (levelised cost after average electricity prices earnt have been deducted). The curves provide a guide to the certificate price required for each level of renewable generation.

Figure 22: Net levelised energy cost curves for renewable generation, mid 2007 dollar terms

87 Sources: MMA analysis based on Horizon Power, NT Utilities Commissions, and CS Energy Annual Reports.

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Expanded MRET Target



However, beyond 2020, additional tranches of renewable energy are likely to be required to meet emission abatement targets. The Australian Government has an aspirational goal of a 60% reduction on 2000 emissions by 2050. A cut of 60% of 2000 levels applied to electricity generation would imply an emission target of 70 Mt CO2-e by 2050, some 330 Mt CO2-e less than projected levels. As shown in Figure 23, around 370,000 GWh of low emission generation (renewable generation or fossil fuel generation with carbon capture and storage) or energy efficiency would be required to meet this target. The level of low emission generation required could ultimately be much higher than this if there is a shift towards electricity generation as a result of abatement in other sectors88. About 150,000 GWh of low emission generation or energy efficiency would be required by 2030, representing a substantial market opportunity for renewable generation or fossil fuel generation with carbon capture and storage.

Source: MMA analysis assuming average emission intensity of 0.90 t/MWh

Figure 23: Requirement of low emission generation or energy efficiency to meet abatement target

HTST will compete with other renewable options to meet this demand for low emission generation. However, there are limits (see Appendix A) to the ability of other renewable options to meet this target. A summary of the renewable energy resource availability is provided in Table 5. After deducting energy efficiency potential and the potential generation from other renewable energy resources, there is a gap in generation required from further low emission sources to meet abatement requirements of about 25,000 GWh in 2030 and about 100,000 GWh in 2050.

88 For example, a shift towards plug-in hybrid electric vehicles.

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Table 5: Low emission generation potential by source of generation, TWh

2010 2015 2020 2030 2050

Abatement requirements 0 7 39 160 371

Assumed energy efficiency contribution (0) (2) (13) (53) (122)

Low emission generation requirement 0 5 26 107 249

Potential contribution of renewable generation sources

Hydro electric (0) (1) (1) (1) (1)

Wind (0) (4) (20) (30) (30)

Biomass (0) (1) (6) (21) (40)

Hot dry rocks geothermal (0) (0) (0) (30) (75)

Deficit 0 0 0 25 103

Source: MMA analysis. Assumes energy efficiency can meet one-third of the abatement requirements This gap in generation could be met from clean fossil fuel generation (requiring around 5 x 750 MW coal plants with carbon capture and storage by 2030), retrofitting of existing fossil fuel plants with carbon capture and storage or HTST generation. If met solely by HTST power generation then about 5,000 MW in 2030 and 20,000 MW in 2050 of HTST capacity will be required to be installed. While this analysis is illustrative only, it does highlight that in order for Australia to meet its long term commitments to reduce abatement a range of low emission generation options are required to be deployed, including HTST technology. The need for low abatement generation to supply electricity to the major grids represents the largest market potential for HTST-based generation in this country. Solar assist Solar assist is the option of utilising HTST technologies to provide steam to existing fossil fuel steam plant thereby reducing the use of fossil fuel in steam raising. According to the case study analysis, solar assist is potentially a highly economic option due to its lower capital cost. That is, there is no need to provide a steam generator and the thermal “back-up” is provided. Solar assist also offers the potential to extend the life of existing plant where there is limited coal supply or where there are issues in relation to air pollution limits. The market potential for solar assist is limited to around 5% of the thermal capacity because thermal imbalance issues arise at greater levels89. Another limit is the availability of flat land to support the solar collectors. About 4000 square metres of land is required per MW of capacity. A forecast of the potential capacity for solar assist based on estimates of the availability of land, fuel cost avoided, life of plant and competing options for carbon abatement is provided in Appendix A. Overall, the capacity of solar assist with moderate to high prospects of proceeding to deployment amount to around 400 MW, or about 1% of total installed generating capacity in Australia. Of course the potential could be higher if emissions permit prices of greater than $50/t CO2-e become the norm. Nonetheless, solar assist could provide a near term niche market for proven HTST technologies. Assuming a capacity factor of around 13% for the solar component, this capacity would contribute around 525 GWh of generation.

89 L. Wibberley, A. Cottrell, P. Scaife and P. Brown, Synergies with Renewables: Concentrating Solar Power,

Cooperative Research Centre for Coal in Sustainable Development Technology Assessment Report No 56, 2006. The report states that “the amount of solar assist can be higher than this if the host plant is adapted for solar augment.” In the analysis of market potential in MMA’s study, the assumption of a 5% upper limit is maintained.



End-of-grid-support Another market niche for HTST is to support demand at end points of the major grids that are in locations with good direct insolation levels, particularly where the value to utilities of avoidance of line losses and provision of network support services is recognised. An estimate (see Appendix A for detail) has been made of the loads at end of grid regions for the NEM. The regions were selected if peak loads were greater than 20 MW and if there were no other forms of local generation nearby. The load centres were matched with data on gas availability and insolation levels. Despite the wide dispersal of loads in Australia, a key feature appears to be a spread of small loads, with very few regions with sufficient loads in good insolation areas to support localised generation with HTST technology. It is estimated that there is around 200 MW of potential load with good prospects for HTST generation, having available gas and/or very good insolation levels. Most of the good prospects are in South Australia and NSW. A further 600 MW potential may come from medium prospects for HTST and could be serviced by this technology from nearby generation sites as long as transmission costs from the HTST plant are reasonable. Remote area power supplies There are about 200 MW of load in remote townships and mining operations that could potentially be serviced by HTST generation. Most are located in outback Western Australia and the Northern Territory, where there is good insolation and a lack of alternative renewable options. However, around 150 MW of this load has been locked out for the next twenty years as part of a process recently enacted by Horizon Energy to contract out generation to least cost options, which has seen mainly liquid fuel-based generation phased out in favour of compressed natural gas-based generation. Hence this market has limited near term prospects of about 50 MW. Over the long term, when existing contracts expire, the market potential could increase to between 200 MW to 250 MW.

4.5 Role of HTST HTST will compete with a range of alternative low-emission energy options to supply electricity demand in Australia and clearly all options will be utilised to some extent — dependent on their relative costs, supply reliability and resource availability. While HTST has advantages over many other renewable energy options, exploitation of the potential market niches for it will require a reduction in the cost of HTST generation. The best prospects for cost reductions are in solar field and thermal storage sub-systems, which make up a large component of capital costs. Increasing plant size may also reduce operating costs through economies of scale. It is also clear that in the Australian market context, development of cost effective thermal storage or siting plants near gas pipelines to utilise gas as a co-firing fuel is crucial for the long term prospects for this technology. The development of an HTST generation sector will require a staged process as follows:

• Over the next decade, scale-up the technology through medium-scale demonstration and early-deployment projects in niche markets in remote regions.

o Deploy to capture opportunities in niche markets in isolated grids and remote power systems over the period to 2020. About 400 MW of market demand is available for HTST in these markets and this could be a good testing ground for commercialised projects.

o There is strong potential for solar assist, but this market is limited to around 400 MW.



• The commercial development of HTST technologies through exploiting opportunities in niche markets will assist in preparing the technology for the longer term market opportunity, which is for HTST to be an option to supply the major grids when carbon prices are likely to be above $50/t CO2-e.

o The analysis indicates that this market should be available to HTST technologies by 2030.

o As long as HTST continues to reduce its cost of generation, there is a large potential in this market of around 20,000 MW as other renewable options are likely to become limited by this stage.

This phased approach is broadly in agreement with that proposed in the assessment in 2006 of the World Bank GEF strategy for the market development of HTST, which concluded that HTST “should be supported to encourage a rapid growth phase to the point that it plays a key role in the electricity supply mix of developing countries where there is a good solar resource.” 90

4.6 Market barriers Electricity market arrangements Australia’s electricity markets comprise a number of components with different arrangements governing each component. A wholesale market has now been established for most of the major grid systems, including the National Electricity Market (NEM), the West Australian Electricity Market (WEM) and the NT market. Transactions occur on spot exchange in most of these markets, but long term contracts and hedges are still the dominant form of transactions between generators and retailers of electricity. Market rules have been established to govern the operation of these spot markets. Ancillary service markets have also been established in most states on a user pays basis to help equalise supply and demand at all times. Trading in the spot market is an inherently risky business, resulting in the development of a range of financial instruments to manage the risks. However, the markets for financial instruments have not been liquid91. An increasing concentration of generation and a trend to vertical integration (combined generation-retail entities) has also reduced the effectiveness of these instruments. These electricity market arrangements have a number of important implications for the development of HTST power generation:

• Participants in the market need large financial reserves to back up their contractual arrangements.

o An HTST plant experiencing an outage during the crucial peak demand period will need to purchase electricity from the spot market to meet its operator’s contractual obligations.

• Retailers are reluctant to enter into long term contracts with new generators, with the longest terms generally being 10 years (although there are a few 15 year contracts).

o Retailers are increasingly buying or building their own generators, which acts as a substitute for the long term contracts

On this basis, it is likely that the market environment will be very difficult for small technology development companies to operate in unless they develop strategic relationships with large generating companies or retailers to help manage the risks involved. 90 Assessment of the World Bank/GEF Strategy for the Market Development of Concentrating Solar Thermal Power,

Global Environment Facility Program, The World Bank, June 2006. 91 Electricity Reform Implementation Group (2007), Energy Reform: The Way Forward, report to the Council of

Australian Governments, Canberra, January



A number of issues will affect the uptake of renewable energy generation including high temperature solar thermal92: Lack of resource information There is a lack of information on the potential resource available for each renewable energy technology. Some general information is available on wind resources, biomass resources and solar insolation levels. However, this information is imprecise. Nor are the social, environmental and economic constraints to utilising this resource well understood. This affects the potential uptake of HTST generation in two ways:

• Directly as there is only a partial understanding of the solar insolation resource and its proximity to load centres; and

• Indirectly as there is a lack of knowledge on the renewable resources that would compete with HTST.

Limited understanding of business opportunities There is limited understanding of business opportunities and the risks of investing in renewable energy to serve competitive electricity markets. On the one hand many developers lack the financial skills and knowledge to manage the risks of trading electricity on spot markets. On the other hand, investors have little confidence in the veracity of non-conventional technologies, although ongoing implementation of standards and accreditation systems can improve confidence in them. Rights to the resource Development of some renewable energy sources is hindered by underdeveloped and inconsistent rights to the resource. This issue is unlikely to impact on HTST generation, but will impact on competitors such as geothermal generation. Project approval can also be onerous and expensive, often requiring the same level of effort for small scale projects (as is typical of many renewable energy projects) as for large scale projects, conferring significant economies of scale for large scale projects. Network pricing and connection provisions Perhaps the most critical near term issue, has to do with network pricing and provision. In relation to new forms of generation such as HTST, the issues include:

• Current arrangements may not appropriately value distributed generation as an alternative to network upgrades to remove transmission constraints and to reduce line losses.

o As stated by the MCE Working Group “there are not sufficient levels of transparency in network planning information, particularly forecast future loads, constraints, and proposed augmentations. As a result, R&DG proposals are limited in their ability to identify business opportunities that could bring network management benefits because the data with which to calculate connection costs and benefits of DG options are not available in most cases.”

• Network pricing structures can distort locational signals so that the location of generation may not be optimised to minimise system costs (which is a factor that dampens the uptake of distributed generation).

o As stated by the MCE Working Group, “Lack of transparent cost effective price and appropriate metering inhibits the accurate reflection of value of distributed generation in managing network losses and constraints”

92 Ministerial Council on Energy Standing Committee of Officials Renewable and Distributed Generation Working

Group (2006), Impediments to the Uptake of Renewable and Distributed Generation, Canberra



• Connection costs can be inequitable especially where early adopters bear the full cost of an expansion in the network service and follow on generators pay only the marginal cost — a classic network externality.

o As stated by the MCE Working Group, “network connection requirements for non-conventional technologies can be inconsistent, complex, inappropriate to technology and impose relatively high transaction costs”.

• Distributed generators (like HTST) can have difficulty in obtaining value for the network services they provide (such as voltage support and provision of reactive power).

• There is uncertainty over the rules to apply to intermittent generators to maintain voltage stability and the need for additional network services to cover intermittent sources of generation.

o This issue may also apply to HTST generators without storage.



5 Strategic analysis 5.1 Prime drivers of change on Australia’s energy systems In considering the development of a roadmap for high temperature solar thermal for Australia it is important to clearly identify the prime drivers of change to energy systems and their importance in Australia’s particular environmental and economic circumstances today. Once these energy system needs are determined then the potential contribution of HTST to fulfilling them — that is, the ‘need’ — can be placed in context. In a review of the hydrogen futures literature covering a total of 40 studies published between 1996 and 2004, 93 McDowall and Eames identified four overarching problems or policy objectives (Figure 24) that consistently stand out in the literature as providing the underlying drivers of a transition to a hydrogen future. These drivers are equally applicable to a broader clean energy future in Australia and elsewhere. They are:

• Climate change: Reducing carbon dioxide emissions is clearly considered to be the most important of these.

• Energy security: This encompasses a range of concerns over the finite nature of primary energy reserves, their geopolitical sensitivity and location, energy prices, and vulnerability of centralised energy systems to attack.

• Local air quality: Reductions in local air pollution can be a benefit of a transition to clean energy economy.

• Competitiveness: This encompasses international industrial competitiveness and participation in global and local energy supply chains.

Figure 24: Prime drivers of change to energy systems

93 W. McDowall and M. Eames, Forecasts, scenarios, visions, backcasts and roadmaps to the hydrogen economy: A

review of the hydrogen futures literature, Energy Policy, Vol. 34, 1236–1250, 2006.

PRIMEDRIVERS

OF CHANGE TO ENERGY SYSTEMS

PollutionReduction

EnergySecurity

International Competitiveness

Carbon Abatement



5.2 The need for HTST in Australia As noted in Section 1.2, roadmapping should be a needs-driven, not solutions-driven, process. The needs related to Australia’s energy systems and their relevance to HTST are summarised below and discussed in more detail below:

Carbon abatement — HIGH and of great relevance to HTST

Pollution reduction — LOW and of little relevance to HTST

Energy security — LOW, except in specific liquid fuels where it is HIGH and of little relevance to HTST

International competitiveness — HIGH and of some relevance to HTST Carbon Abatement While Australia’s total contribution to global GHG emissions is small, Australian governments have recognised that this is not a reason for “no action”. Australia is a heavily carbonised economy — its end-use energy needs are satisfied primarily from fossil fuels, thereby making Australians among the most intense GHG emitters per capita globally. Carbon abatement therefore is considered a high need in Australia’s energy systems as it plays a constructive role in contributing to global efforts to reduce the impacts of climate change. Recent important examples of Australian government responses to this imperative are its commitments to ratification of the Kyoto protocol; to introduction of a trading scheme in 2010 that will price carbon emissions; and — of greatest short to medium term importance for renewable technologies such as HTST — to introduction of a National Clean Energy Target for renewable electricity production. Overall, the national policy environment in Australia is evolving in a manner that is favourable for the development of clean energy technologies. Pollution Reduction Unlike many other regions and cities in the world, Australia is blessed in a relative sense with clean air in its cities and regions. However, that does not mean that action should not be taken to improve indoor and outdoor air quality. Local reduction of health-impairing pollutants such as diesel particulates, volatile organic compounds and smog-inducing chemicals (nitrous oxides) is important. Pollution reduction remains, however, a low need in Australia compared to other localities internationally where the health benefits to be gained are relatively much greater. Energy Security Australia is a resource rich country with significant resources of liquid petroleum, natural gas, coal and uranium. It is one of the few OECD countries that is a significant net energy exporter. Since 1986, Australia has been the world’s largest exporter of coal, and since 1989 has emerged as one of the largest exporters of liquefied natural gas (LNG) and uranium.94 Australia can be considered to have a low vulnerability in regard to energy security (i.e. interruption to supply) except in one area of current high energy security vulnerability for the liquid fuels that Australia imports, particularly diesel and fuel oil, the loss of which would cause severe disruption to key sectors including mining, agriculture and freight logistics. International Competitiveness Fossil fuel energy exports are major contributors to Australia’s economy, as is the competitive advantage derived from Australia’s low-cost, indigenous, coal resources that are utilised particularly for electricity generation. In a world economy in which the externalities of GHG

94 Australian Bureau of Agricultural and Resource Economics (ABARE), Energy in Australia 2006, published March

2007.



emissions, particularly carbon dioxide, are internalised into energy prices Australia’s international competitiveness may be threatened. In another aspect of competitiveness, Australia should seek to capitalise on technology developments that drive, or are driven by, change in energy systems, noting that pricing of GHG emissions is beneficial to these new technologies in that their price gap to incumbent, high-emission energy supplies is reduced. International competitiveness in new energy technologies, and particularly Australian industry competitiveness and participation in global and local energy supply chains, are important for the economic and social (particularly job creation) benefits that come from them. International economic and industrial competitiveness therefore is considered to be a high need in Australia’s energy systems.

5.3 The potential contribution of HTST to Australia’s needs The question now is what contribution HTST as an energy supply technology could make to each of these needs, focusing particularly on their contributions in Australia to carbon abatement and international competitiveness in three key application areas — electricity generation, industrial process heat and thermochemical processes. The views of stakeholders also are summarised in Section 5.3.4.

5.3.1 Electricity generation Electricity production in Australia is the largest source of GHG emissions here with 194.3 Mt or approximately 37% of total annual emissions in 2005.95 This is due to the dominant use here (approximately 85%) of Australia’s plentiful and (relatively) inexpensive black coal, brown coal and natural gas primary energy resources for its generation. Demand for electricity is expected to more than double by 2050. The Australian government’s Emissions Trading Report of May 2007 noted that “over this period, more than two-thirds of existing electricity generation capacity will need to be substantially upgraded or replaced, and new capacity equivalent to the currently installed capacity will need to be added to meet such a demand outlook (see Figure 25). If emissions from the electricity sector are to be reduced from today’s levels, this will require a combination of significant improvements in energy efficiency and conservation and substantial amounts of new generation capacity using low-emissions technology.”96 The analysis in Section 4 shows that HTST electricity generation could make a major contribution to meeting this future demand for low-emissions electricity supply in Australia — provided that it continues to reduce its levelised cost of generation and that an effective trading regime for GHG emissions is established here. In the shorter term, the introduction of a higher target for low emission electricity generation may be more important for HTST than emissions trading. Thus there are opportunities for Australia to develop and commercialise innovative, low-cost, HTST technologies for electricity generation here and for Australian companies to participate competitively in the global supply chain for HTST technology, components and deployment projects for electricity generation. As discussed in Section 2, Australian companies and researchers have been pursuing HTST electricity generation technologies for many years, thus providing a technology foundation here to build on in the near to medium term to supply the market opportunities identified in Section 4. 95 Australia’s National Greenhouse Accounts, National Inventory Report 2005 — Volume 1, The Australian Government

Submission to the UN Framework Convention on Climate Change, April 2007. 96 Report of the Task Group on Emissions Trading, The Department of the Prime Minister and Cabinet, May 2007.



Figure 25: Projected demand-supply balance for electricity (from Emissions Trading and UMPNER97 reports)

5.3.2 Industrial process heat The manufacturing industries and construction sector GHG emissions in Australia were 43.7 Mt CO2-e in 2005.98 This sector includes direct emissions from fuel combustion in manufacturing industries, ferrous and non-ferrous metals production, plastics production, construction and non-energy mining. These calculations do not fully reflect the greenhouse impact of this sector because the emissions generated from the production of electricity that is used in these industries are included under electricity and heat production. Industrial process heat tends to be either at very high temperatures (e.g. ferrous and non-ferrous metals production) or relatively modest temperatures across a broad range of manufacturing subsectors. A 2006 report by the European Solar Thermal Industry Federation noted that “the major share of energy which is needed in industrial production processes is below 250°C” and, as Table 6 shows, mostly below 200°C — and therefore explicitly excluded from this roadmap. Overall, there appears to be little compelling evidence in Australia or elsewhere for industrial process heat applications of HTST above 200°C, although it is recognised that this is a potential market.99 As noted by stakeholders in one of the consultation workshops held for this roadmap “industrial process heat applications have the challenge of co-location of the point of heat demand and the right solar resource (need at least 400 W per m2). Can heat-intensive plants be

97 Uranium Mining, Processing and Nuclear Energy — Opportunities for Australia?, Report to the Prime Minister by

the Uranium Mining, Processing and Nuclear Energy Review Taskforce, December 2006. 98 Australia’s National Greenhouse Accounts, National Inventory Report 2005 — Volume 1, The Australian Government

Submission to the UN Framework Convention on Climate Change, April 2007. 99 As a rare example, Frito-Lay North America recently announced an HTST system at its Modesto plant in California's

Central Valley comprising 5065 m2 of parabolic trough collectors covering an area of about 1.5 hectares. The collectors will operate at temperatures up to 250°C to deliver high temperature pressurized water that is used to generate 21 bar steam. This steam is delivered to the plant where it is mainly used to heat the oil used to fry potato and corn chips. When complete this will be the largest operating solar process heat system in the U.S. The project is a public-private partnership with the California Energy Commission providing $700,000 in funds. (http://www.centralvalleybusinesstimes.com/stories/001/?ID=8509 and http://www.solucar.es/sites/solar/en/geografias_eeuu_california.jsp, last accessed 13 May 2008).



drawn to good solar sites? We haven’t convinced many people to accept low temperature solar thermal yet, so how long will it take for industry to accept HTST?” The one potential exception to this is the use of heat from HTST systems for water desalination — noting that this application is specifically excluded from this roadmap. However, a number of Australian and overseas stakeholders interviewed for this roadmap noted the potential synergies between HTST electricity generation and desalination.

Table 6: Industrial sectors and processes with the greatest potential for solar thermal uses100

Industrial sector Process Temperature level (°C)

Food and beverages Drying Washing Pasteurising Boiling Sterilising Heat treatment

30 — 90 40 — 80 80 — 110 95 — 105 140 — 150 40 — 60

Textile industry Washing Bleaching Dyeing

40 — 80 60 — 100 100 — 160

Chemical industry Boiling Distilling Various chemical processes

95 — 100 110 — 300 120 — 180

All sectors Pre-heating of boiler feed water Heating of production halls

30 — 100 30 — 80

One overseas interviewee specifically commented that “it is a problem to exclude desalination in Australia’s HTST roadmap. This application could be one of CSP’s strengths because many places where one would like to do CSP have water shortages that could be fixed. Spain is building CSP plants for electricity and fossil fuel plants for desalination where in the latter the heat from combined cycle plants is used to desalinate water. Such exclusion prevents consideration of CSP for combined power and desalination applications.”

5.3.3 Thermochemical processes A future application for HTST could be the generation of fuels such as hydrogen for transport and stationary power applications or syngas for chemical processes or stationary power. As Steinfeld and Palumbo note in their 2001 paper the global solar resource “does not capture our imagination as the ingredient that could help us deal with two of the most pressing problems that (will be met) head-on in the 21st century, namely, the impending shortage of crude oil and environmental pollution. ............ (if sunlight is used) in a typical flat-plate solar collector, warm water (can be produced) that could be used for taking baths or supplying space heat. Although this type of device can make a great deal of sense for certain local conditions, it will not enable solar energy collected in Australia to be transported to Japan. If solar energy (is supplied) to a chemical reactor at very high temperatures near 2300 K, the possibility (is opened up) for such a feat: solar energy collected in Australia can heat homes, supply electricity, propel cars, and more ... in Tokyo.”101

100 Key Issues for Renewable Heat in Europe (K4RES-H), Solar Industrial Process Heat – WP3, Task 3.5, European Solar

Thermal Industry Federation, Contract EIE/04/204/S07.38607, August 2006. 101 A. Steinfeld and R. Palumbo, Solar Thermochemical Process Technology, Encyclopedia of Physical Science &

Technology, Vol. 15, pp237-256, 2001.



There are opportunities for Australia to develop and commercialise low GHG emission thermochemical technologies here based on innovative HTST technologies and for Australian companies to participate competitively in the global supply chain for technology, components and projects in this application when it reaches a commercial level. As discussed in Section 2.6 and illustrated in Figure 9 of this roadmap, Australian researchers have been pursuing HTST thermochemical technologies for a number of years, thus providing a technology foundation here to build on in the medium term.

5.3.4 Stakeholders’ views In the workshops held in Melbourne and Sydney with key stakeholders and in response to the Discussion Paper, their views on the need generally, and specifically in Australia, for HTST were sought. A summary of the key points made includes:

• Higher recognition of climate change issues and response in USA, Europe and elsewhere are leading to policies to support deployment of RE systems.

o When obvious solutions — hydro, wind — reach their limits then need to look at other RE sources.

• Imminent pricing of carbon makes HTST more attractive because it has scale potential.

o Indeed HTST works best at 10s+ MW plant scales.

• HTST contributes to risk management on carbon prices, fuel prices and public perception.

• Some countries have energy security issues/risks and HTST is one mitigation mechanism.

• If Australia is to meet the deep cuts in emissions that are being considered, a wide portfolio of options are needed.

• All of the world’s electricity, except wind and hydro, is generated by heating a fluid, so HTST fits in to existing generating technologies, that is, it is another way of heating a fluid.

• HTST advantages include:

o From a distributor’s point of view, predictability of HTST makes the management of feed-in easier and could reduce line augmentation needs.

o Generation in daylight hours when demand is highest.

o The relative ease of thermal storage.

• Parabolic trough HTST technology is bankable today — systems have been running for around 20 years in California.

• HTST could be used to stimulate Australian industrial activity, regional development and export of expertise.

• Australia has great solar resources, of the right type (i.e. lots of direct radiation from clear skies) and it is diversely located from other RE sources in the country.

• Some of the high potential HTST areas in Australia also have good geothermal resources.

o These areas could act as generating hubs, in the same way that the Latrobe Valley acts as a generating hub using brown coal.

• HTST was one of the forgotten technologies, until two years ago.

o HTST provides an opportunity for Australia to be a leader in development, such as Denmark was for wind 20 years ago.

Stakeholder views were also sought on whether there is a need to reduce the ‘natural’ timeframe for deployment of HTST in Australia, i.e. is there a need to move faster than market forces require? Broadly stakeholders’ answer was YES because:



• Going early (i.e. national targets beyond carbon pricing) has a long-term benefit to the economy because deployment issues are learnt earlier, including about Australian conditions such as grids, markets and funding.

• There are too many risks in the “chasm of death” between development and the time when a new HTST technology is at its commercial-ready stage, which is why encouraging technologies through the research and demonstration (scale-up) phases can get them to lower cost curves sooner.

o Once they reach this commercial-ready stage, the market will select the lowest cost options.

• There is an opportunity to build on local HTST capability and technologies.

o If it is desired that intellectual property stays here AND to capitalise on international developments then there is a need to move faster.

• Overseas HTST will not necessarily be adapted for Australian conditions, so there will be a cost of adaptation later.

• Everyone else is moving to large-scale HTST deployment.

o There are gigawatts of HTST planned to go into production in Europe and USA.

o Need to move here to large-scale, on-grid HTST generation delivering energy at the same cost as alternatives such as current gas-fired generators.

5.4 Key barriers and challenges for HTST In the workshops held in Melbourne and Sydney with key stakeholders and in response to the Discussion Paper, their views on key barriers and challenges for HTST generally and in Australia were sought. A summary of the key points made includes. Market entry challenges

• Overall, the biggest market-entry challenge for HTST is its levelised energy cost.

• HTST, because it ‘disappeared’ for 20 years, has a credibility problem — people in Australia just don’t know what has happened in HTST elsewhere in the world in the last two years.

o There is a lack of knowledge about the reality of HTST’s accomplishments within the energy fraternity that advises/lobbies government.

o There is nothing visible in Australia to feel ‘real’, particularly to the decision makers and influencers.

• Reliable learning curve numbers for HTST CAPEX and OPEX are lacking, particularly early-stage numbers.

• What is Australia’s carbon-pricing mechanism going to be?

• The scale of funding required for the class of technology, i.e. HTST supplies large-scale power solutions.

o The smallest feasible HTST project is in the scale of 10 MW and 30 MW is more realistic and this ‘lumpiness’ has made it harder to learn on small-scale demonstration projects.

• Integration risk with existing or with hybrid HTST electricity generation.

o Who will put a 400 MW conventional plant at risk for the sake of a small improvement in efficiency?

• The best solar resource and large loads are far apart in Australia — legacy grids are sunk costs, so who will build new transmission lines?



• The fact that there are four or five competing HTST technologies makes it harder for business to choose.

• Solar thermal is mis-thought of as solar hot water systems and photovoltaics are considered the solar technology because it is visible at the public level.

Supply chain challenges

• There are no particular supply chain challenges — HTST requires glass, steel, cement and real estate, all of which are available.

o Steam turbine delivery times are 18 months, although can get second-hand systems.

o If water is the cooling fluid, there may be issues of availability of water but air cooling is possible (although it adds to the capital cost).

Technology challenges/gaps

• In one sense there are none to stop deployment now — commercial HTST systems are being built.

• Improving the levelised energy cost of HTST systems.

o Higher efficiencies are needed for all stages, and high efficiencies also lead to lower CAPEX and OPEX.

o Improvements are needed in:

Receivers (noting these are technology dependent)

Cost of the solar field because it drives the cost of HTST systems now (40% to 70% of plant CAPEX).

Direct steam generation in the solar field.

• Proving to bankability point a number of components and system integration for local HTST technologies.

o A lot of the components are proven but they need scale-up and their integration needs to be proved.

• Storage for stand-alone, grid-connected systems (i.e. 90% solar contribution) — steam turbines can’t be just turned on and off.

o Need storage for operational reasons (i.e. 30 to 60 minutes) — solutions are available but they are expensive.

o Need long-term storage (i.e. overnight) — there are no cost-effective solutions today.

o Storage also is not ‘bankable’ today from a financier’s point of view.

• Thermo-chemical storage systems offer an opportunity to transport solar energy via fuels (i.e. in a chemical form) but the challenge is that it is working at 0.5 MW scale and there are scale-up issues.

5.5 Australia as a ‘taker’ or ‘maker’

Given these barriers and challenges, the current context for HTST in Australia and the high levels of activity in it overseas, stakeholders were posed the question “should Australia be a ‘taker’ or ‘maker’ in HTST technology?” A summary of their responses is provided below.

• Australia hasn’t quite missed the boat yet, but if a decision isn’t made soon to be a maker then Australia will become just a taker.

o Australia has a 10 year window to be a player in HTST.



• Australia will not have credibility globally unless some systems are built locally.

o To be credible in R&D, one has to have built examples.

o Collaboration with other countries continues because of the legacy of Australia’s reputation and means Australia needs to be a maker to continue to be an attractive collaboration partner.

• Without a certain level of skills, how can competitive technologies be assessed sensibly?

• Making in key areas provides opportunities for collaboration and supply chain niches.

• If want to realise potential locally, then this needs markets locally.

o Australia can be used as the demonstration site to support export industry development — wind in Denmark and Nokia in Finland are examples of encouraging a technology in a small country.

• If Australians don’t control their intellectual property (IP) then there is no point in having it — this means having IP and making engineering input into every plant through establishment of local design centres.

In summary, stakeholders felt that:

• Australia is not devoid of ‘making’ opportunities in specific HTST or enabling technologies — but there are local market and innovation system challenges to develop and commercialise them successfully here; and

• To be a competent ‘taker’ there must be local, independent, technical capability and capacity to evaluate any HTST technologies that are sought to brought in.

5.6 SWOT analysis Stakeholders were asked to provide their views on the Strengths and Weaknesses (i.e. the internal landscape) of Australia, and the Opportunities and Threats (i.e. the external landscape) facing Australia, in HTST. A consolidated SWOT analysis from the two workshops is presented below and over.

Strengths (in Australia in HTST) Weaknesses (in Australia in HTST)

• Australia has a history in HTST for a long time at the R&D level,

• Australia has novel HTST technologies and innovators and locally-developed HTST technologies are now being adopted overseas.

• There is an appropriate skill base here — Australia is as good as the rest of the world, at least in R&D, and Australians are well-enough connected internationally to know what others are doing overseas.

• The Australian manufacturing base matches the components needed for HTST systems.

• Australia is an ideal continent for solar applications — lot’s of the ‘right’ solar resource and plenty of flat, suitable, low-cost space to site HTST plants.

• The absence of a political champion for HTST and lack of knowledge about HTST among policymakers.

• No strategic policy/regulatory framework for HTST (and RE generally).

• NEM operators and Australian electricity distributors don’t like new technologies /distributed generation.

• The Australian market is small.

• There is a lack of financiers in Australia to take risk that others do overseas.

• There is a lack here of entrepreneurs with the right skills and the financial backing.

• Australia is not strongly connected into international forums relevant to HTST.

• The Kyoto protocol has not been ratified yet.



• Australia has a well-developed market and experience in electricity.

• Government policy shift in last six months e.g. national clean energy target and carbon pricing is coming.

• Robust intellectual property and regulatory framework.

• First world economy and mature financial markets.

• Active renewable energy industry over the last five years has made banks aware of renewable energy.

• The industry association (the Clean Energy Council) has the three largest privately-owned energy companies as sponsoring members.

• Skilled people are attracted overseas.

• No experience in scale-up of HTST here.

• Government support is not focussed on industry development, only RD&D.

• Australia doesn’t have a critical mass of researchers and they are distributed over several institutions.

• The industry association (the Clean Energy Council) is focussed on today’s technologies as it has to support today’s industry.

Opportunities (in HTST) Threats (to HTST)

• Australia can be a maker of a few HTST technologies

• Leap-frog to 2nd and 3rd generation102 HTST technologies.

• HTST delivers high energy security, dispatchable and low-fuel-supply-risk electricity generation.

o Synergies with coal-fired generation provide a transition path for that industry.

o New electricity plants are sited for the best solar resource, not the lowest-cost coal resource.

o Multi-output plants e.g. electricity + desalination.

• HTST rescues rural areas and their economies (energy farming)

• HTST underpins new industries in Australia.

o Australia exploits existing skills in design and construction to establish a major industry supporting HTST plant design and delivery.

o In the longer term, supply of renewable fuels.

• Australia ratifies the Kyoto protocol, thus enabling overseas HTST developers to come here and Australian HTST companies to access joint technology initiative and Clean Development Mechanisms

• The investment climate in Australia is not conducive to RE technologies.

o Australian HTST technologies have already moved to where the markets and money are.

• Competition from other RE technologies for deployment and investment dollars.

• Lack of clear focus and motivation to support/pull HTST — promises have to go to policy and policy has to provide incentives that enable profits.

• Politicians don’t understand/believe HTST.

• Global warming isn’t accepted, leading to no change or not enough change in policy.

• Coal industry is the incumbent and the coal/fossil fuel lobby focuses on and is heavily investing in carbon capture and storage as the solution.

• The nuclear veto in Australia goes away.

• A plant is built here, doesn’t work and this leads to a reduction in enthusiasm for HTST generally.

• The high level of activity overseas draws attention and investment there.

• Unexpected community opposition, for example native title; rare fauna or flora.

• Competing land uses.

• Incentives that drive investment for the up-

102 Stakeholders defined 1st Generation HTST as troughs + heat transfer fluid; 2nd Generation HTST as direct steam

generation; and 3rd Generation HTST as inherent energy storage via thermochemical processes.



• Proximity to other markets for HTST technologies.

• Establish Australia as a test and development site for HTST — provides a breeding ground for innovation.

• HTST is at the beginning of its experience curve.

front tax credits only.

• Fuel security is not an issue for Australia —gas and coal are exported.

• HTST is at the beginning of its experience curve.



6 Conclusions The overall objective of this project was to establish, using a technology roadmapping process, a plan for the development of HTST technology and research in Australia. With this objective in mind and based on the information and analyses in earlier sections of this roadmap, the following key conclusions are drawn. HTST market growth As noted in the 2006 World Bank/GEF assessment of market development for HTST technologies, “there is now a renewed enthusiasm for solar energy development around the world. Project development and implementation is moving at a fast pace, especially in Europe. The new-found enthusiasm is largely built around strong national policy commitments that reduce the revenue risks faced by developers. .......... However, in order to reach commercial competitiveness, (HTST electricity generation) industry would need a significantly higher order of capacity additions, which can be realized only through large national programs in both the developed and developing worlds.”103 The analysis in this roadmap shows that this enthusiasm is growing — rapidly. Over 6 GW of HTST-based electricity generation projects have been announced as at early 2008 for deployment by 2012 in Europe (particularly Spain), USA and Middle-East North Africa region from a position prior to 2005 where no new HTST projects had been planned for 15 years. While it may be argued that not all of these announced projects will be constructed and/or that the proposed timeframe for their deployment by 2012 is optimistic, provided that current policy and fiscal incentives remain in place, a high proportion of these projects appear likely to receive financing and achieve commercial operation. These projects will lay a solid foundation for sustainable growth for HTST globally. Importantly, major project development companies, component suppliers and utilities in Europe and the USA are behind much of the growth in commercial deployment of HTST electricity plants. The presence of these large companies alongside the innovative, usually-smaller HTST technology suppliers has seen a significant and positive change to the global HTST industry structure over the last three years. HTST has advantages over a number of other renewable energy options:

• It can integrate well with conventional thermodynamic cycles and power generation equipment as well as complementary renewable technologies such as geothermal energy.

• It offers dispatchable power when integrated with thermal storage and/or gas co-firing, and thus good load matching between solar insolation and the growth in electrical demand in many countries that is driven by air conditioning loads during summer.

• The collector technology itself is constructed of predominantly conventional materials (glass, steel, concrete) — no scientific breakthroughs are required for the cost to continue to drop with increasing volume of megawatts deployed.

The best prospects for cost reductions are in solar field and thermal storage sub-systems, which make up a large component of capital costs. Increasing plant size may also reduce operating costs through economies of scale. It is also clear that in many market contexts, including Australia, development of cost effective thermal storage or siting HTST plants near gas pipelines to utilise gas as a co-firing fuel is crucial for the long term prospects for this technology.

103 Assessment of the World Bank/GEF Strategy for the Market Development of Concentrating Solar Thermal Power,

Global Environment Facility Program, The World Bank, June 2006.



HTST technologies There are a range of solar concentrator (linear Fresnel reflector, parabolic trough, power tower and parabolic dish), thermal receiver/heat transfer fluid (hot oil, molten salts, direct steam), heat storage and power generation (steam turbine, Stirling engine) technologies that are proceeding through innovation and/or commercialisation pathways. The combination of parabolic trough concentrators using hot oil transfer fluids (no storage) and steam turbine power generation is the only system configuration that has been commercially deployed to date. However, this does not mean that this HTST system configuration is the only, or even necessarily the long-term preferred, option for wide-spread deployment. All concentrator approaches, each with particular integrations of receivers, power generation and/or storage components, have been proposed for commercial, utility-scale projects. There is no clear-cut ‘winner’ today in HTST system configurations — and it will take many years and multiple commercial-scale projects for lowest LEC configurations to be identified. Indeed it is possible that most, if not all, HTST concentrator approaches will prove to provide economic solutions for zero or low emission electricity generation. It therefore is prudent, within a sensible strategic approach, for industry and governments to continue to support promising HTST system and component technologies through their innovation and commercialisation paths and processes to reduce capital and levelised energy costs. Positioning Australia in HTST Based on the cost-modelling and market potential analysis in this roadmap, there are near-term markets in Australia that HTST electricity generation can exploit in targeted markets: isolated grids, remote power systems and solar assist to conventional power generation stations. Over the next decade, market potential approaching 1,000 MW in total capacity could be available to HTST systems for large-scale demonstration and early-deployment projects. However, at its current level of development HTST generates electricity at a higher cost than some existing renewable energy technologies. As a result, it is unlikely that HTST will benefit significantly through to 2020 from the Australian government’s expanded Mandatory Renewable Energy Target as, in its currently proposed form, this is a competitive support mechanism. Exploiting opportunities in these near-term markets, however, will assist in preparing the local supply chain for HTST component technologies, system design capability, project development and delivery capability and financing capacity. This will position Australian industry for the longer term market opportunity, which is for HTST to be an option to supply the major grids in Australia when carbon prices are likely to be above $50/t CO2-e. This market should be available to HTST technologies by 2030 provided that HTST continues to reduce its cost of generation, which is likely in a global sense given the rapid growth in announced commercial projects overseas. There is a deployment capacity of around 20,000 MW through to 2050 available in Australia in this market. HTST will, however, compete with a range of alternative low-emission and renewable energy options to supply this demand and market share will ultimately depend on cost-competitiveness, supply reliability and resource availability. Large sums of money have been, and continue to be, invested overseas in HTST-related RD&D and again now in commercial deployment of utility-scale systems. To date Australia has not invested comparably to investigate the opportunities that HTST may offer for a clean energy future. Australia risks significant competitive disadvantage in the global HTST markets and local industry growth if it is simply left to market forces to prepare for its commercial introduction locally. A pertinent example of this disadvantage at an operational level was given by a stakeholder who noted that “practical experience with the operation of solar thermal plant utilising the given technology is desperately needed to understand day to day operational issues



with respect to operating costs, heliostat cleaning, heliostat operation and maintenance, impact of weather (e.g. cloud cover), etc”. Australia has locally-developed and innovative HTST technologies, a strong R&D reputation in the field that has been gained over the last 20+ years and world-class technology strengths in specific HTST technology areas. However, if a decision is not made soon to exploit the outcomes of Australia’s past investment then Australian HTST companies and technologies are likely to continue to pursue more economically attractive opportunities in the rapidly-accelerating commercial, financial and RD&D HTST activity overseas. Under this scenario, Australia will lose its existing HTST strengths and will ultimately be a taker (i.e. importer) of these and other HTST technologies. The economic benefits of early preparation and support of Australian-developed HTST technologies into local and global markets, as proposed in this roadmap, are likely to exceed the costs, because:

• Australia will be prepared to move earlier and more efficiently to benefit economically and environmentally from deployment of products and services based on HTST technologies; and

• Australian companies and researchers will be better positioned to participate successfully in global supply chains for HTST components, systems and technology.

The need for HTST in Australia It is clear that there are opportunities for HTST technologies and commercial plants to contribute, and potentially to contribute strongly, to Australia’s carbon abatement and international competitiveness needs in the near, medium and long terms. However, stakeholders felt strongly that the window of opportunity for Australia to extract significant industry-development value from the R&D legacy and current RD&D capacity and capability in HTST fields is as short as 2015 — particularly given the pace of industry growth and project deployments overseas. This strongly suggests that a policy regime is required in Australia that will promote industry investment in local deployment of commercial HTST technologies and associated supply-chain infrastructure/capability; large-scale demonstration of less-mature HTST technologies; and ongoing R&D of next-generation HTST technologies at the system and key sub-system/component levels to reduce cost and expand market options. Achieving this will require:

• Development of a favourable policy framework for clean energy in Australia;

• Knowledge building in consumers, utilities, financiers, industry, regulators and governments about HTST;

• Market development efforts to promote the sector and to remove barriers to deployment;

• Development of Australian supply-chains for viable near-term applications and large-scale demonstration programs; and

• Training and competence building in human resources and technology capability and capacity.

Investing in these activities will enable Australian governments, industry, researchers and the broader community to position Australian industry and technologies in the strongly-growing, global HTST sector and to exploit HTST as a key component of Australia’s energy future.



7 A roadmap for Australia 7.1 Vision Drawing from the key conclusions in the previous chapter, Australian governments, industry, researchers and the broader community should collaborate and co-invest:

• To prepare technically and socially for possible widespread deployment so that Australia can easily leverage the rest of the world’s considerable investments in HTST and that our uptake can be earlier, more efficient and lower cost.

• To foster local industry development opportunities as they arise in order to extract significant economic and industrial value from participation in the global supply chains for HTST systems.

The vision for HTST in Australia therefore is:

7.2 Recommended strategies Building off stakeholder input, eight inter-related strategies are required to achieve this roadmap vision, as depicted over and described below.

• Market Development o Australian governments expedite market support mechanisms including the

implementation of a national GHG emissions trading scheme and a national renewable energy target scheme together with uniform policies that remove market barriers to the deployment of clean energy systems.

o Strong industry advocacy is established that recognises and promotes HTST energy supply (particularly electricity generation) as a potentially important component of Australia’s low-emissions future.

• Supply-Chain Development o Australian companies identify and supply components and/or technology into

viable near-term applications of HTST electricity generation.

o Australian industry and governments jointly invest in large-scale demonstrations in Australia of HTST technologies that will become economically viable in the near to medium term.

By 2015, Australia’s HTST industry and technologies are strongly positioned in supply chains for local and global energy markets.



• Competence building

o Support world-class R&D in HTST areas (particularly 2nd and 3rd generation technologies) and specifically establish world-scale collaborative R&D projects that build on technology strengths in Australia that are being, or could be, applied to commercially-important technical problems in HTST energy collection and conversion.

o Educators, industry and governments actively support the capacity and capability building in Australia necessary to supply the skilled personnel needs of Australian industry and research organisations in key fields of importance to HTST technology development and commercial exploitation.

• Knowledge Building

o Australian industry, researchers and government are active in international forums related to HTST to learn from and to contribute to global knowledge networks.

o Industry, utilities, government (including market regulators) and public education and outreach activities are strengthened and expanded, building from credible international and national HTST data and activities.

7.3 Options for key activities Building off stakeholder input and the preceding analysis, the following key activities against each of these strategies are recommended. These activities are neither exhaustive nor complete — rather they form a basis for consideration by government, industry and research stakeholders to commence implementation of this roadmap.

VISIONBy 2015, Australia’s HTST industry and technologies are

strongly positioned in supply chains for local

and global energy markets.

Supply‐ChainDevelopment

CompetenceBuilding

MarketDevelopment

KnowledgeBuilding

Capacity andCapabilityBuilding

World‐ScaleCollaborative R&D

Projects

Market Support

Mechanisms

Active in International

Forums

Education and

Outreach

StrongIndustryAdvocacy

Viable Near‐TermApplications

Large‐ScaleDemonstrations



• Market support mechanisms

o Ensure timely introduction of Australia’s proposed national emissions trading scheme and renewable (clean) energy target for 2020.

o Ensure other clean energy market support mechanisms at State and Australian government levels (e.g. the Renewable Remote Power Generation Program (RRPGP)) can be applied to HTST systems of appropriate scale.

o State and Australian governments continue to cooperate to quickly remove specific or inadvertent barriers to market entry for HTST including but not limited to resource data availability; solar resource rights; network pricing; connection rules and costs; and value attribution for reduction in fuel-supply risk and/or offset of augmentation costs.

• Strong industry advocacy

o Ensure that strong industry advocacy is established to promote HTST to Australian industry, utilities, governments and research and teaching institutions as a key component of Australia’s clean energy future.

• Viable near-term applications

o Minimise impediments to market entry and promote uptake in Australia of HTST technologies and systems for applications where they are economically competitive now, including but not limited to capturing near to medium-term deployment opportunities in:

Niche markets in isolated grids and remote power systems over the period to 2020 (around 400 MWe potential).

Solar assist applications with conventional power stations (around 400 MWe potential).

o Australian-based companies actively seek opportunities in global supply chains for HTST technology and system design services, components supply and project development to maximise Australian industry and employment growth.

• Large-scale demonstrations

o Expedite establishment of the Australian government’s proposed $500 million Renewable Energy Fund that aims “to support renewable energy demonstration projects already underway and to expand the range of renewable technologies in Australia”.104

A goal of this Fund is to generate $1.5 billion worth of investment in renewable energy technologies in Australia by encouraging the private sector to contribute $2 for every $1 provided by the Australian Government.

o National and international companies develop world-class, large-scale demonstration projects of pre- or early-commercial HTST technologies to submit into the proposed Renewable Energy Fund and other State or Australian government initiatives that may be established.

o To support local industry development and/or retention, where appropriate maximise participation by Australian companies in these large-scale demonstrations.

o Ensure that such demonstration projects are linked internationally where appropriate and that data is shared internationally as a key input into modelling and analysis of energy system options for Australia.

104 http://www.alp.org.au/download/now/renewable_energy_factsheet_campaign_launch.pdf, last accessed 03 Feb

2008.



• World-scale, collaborative R&D projects

o Expedite establishment of the Australian government’s proposed $150 million Energy Innovation Fund in clean energy technology research,105 noting that $50 million of this fund is targeted for a significant expansion of solar thermal R&D capacity that will build on the existing CSIRO National Solar Energy Centre in Newcastle.

o Industry and researchers jointly develop world-class and world-scale R&D projects to submit into the proposed Energy Innovation Fund and other State or Australian government R&D funding initiatives. These projects should build on advanced materials, thermodynamics, fluids handling and engineering strengths in Australia that already are being, or could be, applied to commercially-important technical problems in HTST technologies and their applications including but not limited to:

Reducing the capital cost of key components and increasing the efficiency of generation in HTST systems.

Increasing the capacity factor of HTST systems through integration of low-cost storage technologies.

Cost-effective integration of HTST with conventional and other renewable electricity generation technologies.

Cost-effective integration of complementary HTST technologies to minimise levelised energy cost and/or maximise energy output.

3rd generation, high temperature solar thermochemical processes.

• Capacity and capability building

o Tertiary and secondary educational institutions ensure that relevant technical and business courses incorporate HTST as a key teaching topic and that postgraduate research opportunities in these and allied technical fields are available and promoted.

• Active in international forums

o Ensure Australia is actively participating in, and where appropriate taking a leadership role in, key multilateral forums relevant to HTST, e.g. IEA SolarPACES Implementing Agreement and relevant IEA high-level groups; Asia Pacific Economic Cooperation (APEC) Energy Working Group; Asia Pacific Partnership for Clean Development and Climate (APP).

o Utilise established bilateral links and forums to share knowledge and experience in HTST between Australia and the USA, European Commission and EU countries, Relevant MENA region countries, China, India and Japan.

• Education and outreach

o Develop education and outreach tools (e.g. dedicated website; educational material; up-to-date database of RD&D activities in HTST in Australia) for local use by educators, researchers, government and industry.

o Identify key public and private-sector decision makers (e.g. regulators, network planners, project and venture capital financiers) and specifically focus on their information and knowledge needs in HTST.

o Ensure that relevant national conferences (e.g. those of the Clean Energy Council, ESAA and ANZSES) incorporate sessions on HTST R&D, demonstration, deployment and market development (as appropriate to each conference).

These activities are summarised in Table 7 together with indicative timeframes and suggested organisations responsible for their implementation.

105 http://www.alp.org.au/download/now/clean_r_d_facsheet_campaign_launch.pdf, last accessed 03 Feb 2008.



Table 7: Summary of key strategies, options for activities and implementation



Market Development: Market Support Mechanisms

• Ensure timely introduction of Australia’s proposed national emissions trading scheme and renewable (clean) energy target for 2020.

• Ensure other clean energy market support mechanisms at State and Australian government levels can be applied to HTST systems of appropriate scale.

• State and Australian governments continue to cooperate to quickly remove specific or inadvertent barriers to market entry for HTST.

2008 — 2010

2008 onwards

2008 onwards



• Ministerial Council on

Energy’s Renewable and Distributed Generation Working Group

Market Development: Strong Industry Advocacy

• Ensure that strong industry advocacy is established to promote HTST in Australia.

2008 onwards • HCG in conjunction with industry

Supply-Chain Development: Viable Near-Term Applications

• Minimise impediments to market entry and promote uptake in Australia of HTST technologies and systems for applications where they are economically competitive now.

• Australian-based companies actively seek opportunities in global supply chains for HTST technology and system design services, components supply and project development to maximise Australian industry and employment growth.

2008 onwards

2008 onwards

• Industry in conjunction with HCG / industry advocacy group

• Industry

Supply-Chain Development: Large Scale Demonstrations

• Expedite establishment of the Australian government’s proposed Renewable Energy Fund for large scale demonstrations.

• Develop and promote world-class, large-scale demonstration projects of pre- or early-commercial HTST technologies and, where appropriate, maximise participation by Australian companies in these large-scale demonstrations.

• Ensure that such demonstration projects are linked internationally where appropriate and that data is shared internationally as a key input into modelling and analysis of energy system options for Australia.

2008 — 2009

2008 onwards

2009 onwards

• Australian government • Industry in conjunction

with HCG / industry advocacy group

• Governments in

conjunction with HCG / industry advocacy group





Competence Building: World-Scale Collaborative R&D Projects

• Expedite establishment of the Australian government’s proposed Energy Innovation Fund in clean energy technology research.

• Industry and researchers jointly develop world-class and world-scale R&D projects to submit into Australian and State government R&D funding initiatives.

2008

2008 onwards

• Australian government • Industry and researchers

Competence Building: Capacity and Capability Building

• Tertiary and secondary educational institutions ensure that relevant technical and business courses incorporate HTST as a key teaching topic and that postgraduate research opportunities in these and allied technical fields are available and promoted.

2009 onwards • HCG / industry advocacy group in conjunction with educational institutions and learned academies

Knowledge Building: Education and Outreach

• Develop education and outreach tools (e.g. dedicated website; educational material; up-to-date database of RD&D activities in HTST in Australia) for local use by educators, researchers, government and industry.

• Identify key public and private-sector decision makers (e.g. regulators, network planners, project and venture capital financiers) and specifically focus on their information and knowledge needs in HTST.

• Ensure that relevant national conferences (e.g. those of the Clean Energy Council, ESAA and ANZSES) incorporate sessions on HTST R&D, demonstration, deployment and market development (as appropriate to each conference).

2009 onwards

2008 onwards

2008 onwards

• Industry advocacy group • HCG / industry advocacy

group • HCG / industry advocacy

group in conjunction with conference organisers

Knowledge Building: Active in International Forums

• Continue / enhance involvement in multilateral (e.g. IEA, IPHE, APEC, APP) and bilateral forums.

2008 onwards • Australian government in conjunction with the HCG / industry advocacy group



At the final consultation workshop for this roadmap, stakeholders were asked to nominate the five activities that are a first priority for them for commencement of implementation of this roadmap. While acknowledging the importance of building on and extending the R&D capability and capacity in Australia for HTST and related areas (particularly manufacturing R&D to reduce key-component production costs), stakeholders’ top five priorities focused primarily on market and supply-chain development activities, as follows:

• Large-scale demonstrations, which stakeholders noted pull and underpin: R&D; technology, industry and policy development; removal of implementation barriers; and overseas interest in Australia as a market.

o Stakeholders in particular suggested projects in the 200 to 400 MW scale for system configurations such as HTST + CCGT; HTST + gas or biomass co-firing; HTST + geothermal; and low-temperature + high temperature HTST systems.

• Capacity and capability building, particularly in manufacturing and engineering areas relevant to HTST systems and components.

• Establishment of an advocacy group, which is comprehensive for and widely supported by HTST industry members, to be a champion for HTST in Australia.

o Stakeholders noted that an important function for this advocacy group will be education and awareness-raising to a wide range of parties but particularly to utilities and project/venture financiers.

• Establishment soon of public policy that both pulls and pushes progress in Australia in HTST, particularly market-support mechanisms and removal of specific or inadvertent barriers to market entry for HTST.

o For example, as with similar overseas programs, through banding of technologies under the expanded MRET to ensure prescribed levels of deployment are met or implementation of banded feed-in tariff policies.

• Exploit viable near-term markets, which stakeholders noted will enable (in conjunction with large-scale demonstrations) establishment of sustainable supply chains in Australia for HTST system design, implementation and operation.

o It is noted that these supply chains also would supply the solar field components for concentrating photovoltaics, providing an expanded or alternate market for these suppliers.

7.4 Roadmap implementation To expedite the removal of specific or inadvertent barriers to market entry for HTST systems, the Ministerial Council on Energy’s Renewable and Distributed Generation Working Group’s activities in applicable areas106 should be completed as soon as practically possible and implemented at all relevant jurisdictional levels. Removal of these market barriers together with timely implementation of an emissions trading scheme and a national renewable (clean) energy target will provide market conditions conducive to all renewable energy generation technologies, which then will compete on their individual economic merits in these national markets. Implementation of this roadmap also requires a long term commitment from:

106 http://www.mce.gov.au/index.cfm?event=object.showIndexPage&objectID=1F93FC94-65BF-4956-

B9D7FCF8537C7438, last accessed 03 Feb 2008.



• The public sector — primarily the Australian and State Governments that will have to make a decision to provide a significant proportion of the R&D and large-scale demonstration funds required.

• The private sector — primarily the companies and utilities that are interested in, will invest in and will benefit from, progressing HTST deployment and development.

• The research sector — albeit not separate from the public sector in that it is supported largely by public monies but its ongoing participation in many aspects of implementation is essential.

As noted earlier, the Australian government has proposed the establishment of a $500 million Renewable Energy Fund and a $150 million Energy Innovation Fund, a proportion of each of which is available to or committed to supporting large-scale demonstration and R&D (respectively) of HTST technologies. Expediting the establishment of these Funds will provide an important ‘kick-start’ to the implementation of this roadmap. However, these Australian government Funds alone are not sufficient to progress this roadmap optimally. State and Territory governments are encouraged to financially support R&D and large-scale demonstration HTST projects, either on a case-by-case, co-investment basis with project proponents or on a pooled co-investment and joint project selection basis with the Australian government (similar to the Joint Technology Initiatives implemented in the EU107). As a transitional arrangement until an appropriate and strong advocacy group for HTST can take leadership of the implementation of this roadmap, to oversight and drive start-up of this roadmap a high-level coordination group (HCG) comprising government, industry, utilities and research sector representatives should be established. The coordination and oversight mechanisms of many overseas countries or regions have the characteristic of a strong partnership between industry and government working together and with researchers. Such a joint and active approach should result in a significant commitment by industry, utilities and research organisations, working with Australian governments, to ensure full implementation of this roadmap.108

107 ftp://ftp.cordis.europa.eu/pub/fp7/docs/faqs-jtis_en.pdf, last accessed 11 Feb 2008. 108 The Victorian ($180 million) and Australian ($250 million) governments’ funding commitments to RD&D initiatives

under Victoria’s current Energy Technology Innovation Strategy (ETIS) program are an example. This public-sector commitment to ETIS has leveraged $1,250 million of project partner (primarily industry) co-investment into a wide range of brown coal, renewable and clean energy innovation projects.

WYLD GROUP and MMA FINAL


APPENDIX A HTST market potential analysis A.1 Australia’s electricity market characteristics Australia’s electricity markets comprise a number of large grid based systems, isolated power supply systems supplying remote towns and mining operations plus stand alone generation systems supplying remote tourist operations, homesteads and small towns. The principal grids are the National Electricity Market (NEM), the South West Interconnected System (SWIS) and the Darwin Katherine Interconnected System (DKIS). Smaller but still important potential markets for high temperature solar thermal (HTST) power generation include the Alice Springs-Tennant Creek system, the Mount Isa grid and the Pilbara System in Western Australia. Remote mining operation may also offer prospects for HTST, but the short life of the mines (typically less than the life of the HTST plant) acts as a major barrier for HTST technology in this market. Loads at remote homesteads and communities are generally too small to be suited to HTST technologies. Fossil fuel is the dominant form of electricity generation in Australia (Table A-1). Coal-fired generation is dominant in most of the mainland states and contributes 75% of the total generation in Australia. Natural gas contributes 14% and renewable energy contributes only 9%, with most of this coming from hydro-electric generation. Wind and other forms of renewable energy currently contribute less than 2%, with HTST not supplying to grids at all in Australia109.

Table A-1: Generation by technology and fuel type (GWh)

Qld NSW Vic Tas SA WA NT AUST Black Coal - Steam Turbine 44,121 63,484 0 0 4,991 8,430 0 121,025 Brown Coal - Steam Turbine 0 0 44,975 0 0 0 0 44,975

Gas - OCGT 3,615 1,274 2,088 2,046 411 6,990 1,581 18,006

Gas - CCGT 629 0 0 0 751 1,769 490 3,639

Gas -Cogeneration 0 513 0 0 1,267 3,553 0 5,334

Gas - Steam Turbine 0 0 567 0 1,512 2,664 0 4,743

Liquid Fuels - OCGT 20 0 0 0 0 1,413 988 2,421

Liquid fuel - Steam 0 0 0 0 1 0 0 1

Hydro 632 5,198 730 10,531 0 0 0 17,092

Wind 42 50 249 479 963 66 0 1,849

Biomass 711 517 94 289 46 143 0 1,801

Geothermal 0 0 0 0 0 0 0 0

Solar Thermal/PV 0 0 0 0 0 0 0 1 Source: MMA analysis from Electricity Supply Association of Australia (2007), WA Independent Market Operator (2007), Verve Energy (2007) and NEMMCO (2007) Despite numerous support measures, including mandating the purchase of up to 9,500 GWh of generation, the proportion of renewable generation has fallen from 10.5% in 1996/97 to 9.4% in 2006/07. High electricity growth rates over the past decade have been mainly met by increased natural gas fired generation and higher brown coal generation. Ongoing drought has also limited the contribution from hydro-electric systems.

109 Although solar hot water systems are increasing in sales and are taking market share from electric hot water

systems.



Fossil fuels dominate electricity production due to the low cost and maturity of these generation technologies. Nonetheless, there could be an increasing role for renewable energy — as long as it can become competitive. Electricity demand is projected to grow by between 1.7% to 2.1% per annum over the period to 2050. The need to curb emissions of carbon dioxide may also favour renewable energy generation.

A.1.1 Electricity Market Arrangements Electricity markets comprise a number of components with different arrangements governing each component. A wholesale market has now been established for most of the major grid systems, including the National Electricity Market (NEM), the West Australian Electricity Market (WEM) and the NT market. Transactions occur on spot exchange in most of these markets, but long term contracts and hedges are still the dominant form of transactions between generators and retailers of electricity. Market rules have been established to govern the operation of these spot markets. Ancillary service markets have also been established in most states on a user pays basis to help equalise supply and demand at all times. Trading in the spot market is an inherently risky business, resulting in the development of a range of financial instruments to manage the risks. However, the markets for financial instruments have not been liquid110. An increasing concentration of generation and a trend to vertical integration (combined generation-retail entities) has also reduced the effectiveness of these instruments. These arrangements have a number of important implications for the development of HTST power generation:

• Participants in the market need large financial reserves to back up their contractual arrangements.

o A HTST plant experiencing an outage during the crucial peak demand period will need to purchase electricity from the spot market to meet its operator’s contractual obligations.

• Retailers are reluctant to enter into long term contracts with new generators, with the longest terms generally being 10 years (although there are a few 15 year contracts).

o Retailers are increasingly buying or building their own generators, which acts as a substitute for the long term contracts

Thus, it is likely that the market environment will be very difficult for small technology development companies to operate in. Small companies developing HTST technologies will need to develop strategic relationships with large generating companies or retailers to help manage the risks involved. Transmission systems are generally highly regulated. Prices for transmission services are determined by a national regulator on a revenue cap basis. Up until now, customers generally pay for network services on a user pays basis, but there is an increasing trend for generators to pay some more of the share of network costs. Currently generators only pay for connection costs, but there is a trend towards making new generators pay for a portion of deep connection costs according to the benefits received by them in relation to upgrades of the network system.

110 Electricity Reform Implementation Group (2007), Energy Reform: The Way Forward, report to the Council of

Australian Governments, Canberra, January



A number of issues will affect the uptake of renewable energy generation including high temperature solar thermal111. First, there is a lack of information on the potential resource available for each renewable energy technology. Some general information is available on wind resources, biomass resources and solar insolation levels. However, this information is imprecise. Nor are the social, environmental and economic constraints to utilising this resource well understood. This affects the potential uptake of HTST generation in two ways: directly as there is only a partial understanding of the solar insolation resource and its proximity to load centres and indirectly as there is a lack of knowledge on the renewable resources that would compete with HTST. Second, there is limited understanding of business opportunities and the risks of investing in renewable energy serving competitive electricity markets. Many of the developers lack the financial skills and knowledge to manage the risks of trading electricity on spot markets. On the other hand, investors have little confidence in the veracity of non-conventional technologies, although ongoing implementation of standards and accreditation systems can improve confidence in them. Third, development of some renewable energy sources is hindered by underdeveloped and inconsistent rights to the resource. This issue is unlikely to impact on HTST generation, but will impact on many of the competitors such as geothermal generation. Project approval can also be onerous and expensive, often requiring the same level of effort for small scale projects (as is typical of many renewable energy projects) as for large scale projects, conferring significant economies of scale for large scale projects. Fourth, and perhaps the most critical near term issue has to do with network pricing and provision. These issues are discussed in Section 4.6 of this roadmap.

A.2 Role of Renewable Generation Renewable generation currently plays a limited role in Australia’s electricity markets. Renewable energy generation has grown but its share of total generation has remained steady. Although wind and other new renewable generation have grown, hydroelectric generation has fallen as a result of prolonged drought. Growth in renewable generation has been mainly through Government support by measures including:

• Australian and State Government imposed mandatory targets for the purchase of renewable generation.

o The Australian Government’s MRET scheme came into operation in 2001 and mandates the generation of 9,500 GWh of renewable generation from 2010. Victoria, Queensland and Western Australia have also imposed their own targets, tallying up to around 27,000 GWh of mandated renewable generation by 2020. However, the recent election of the ALP to the Australian Government means that these State schemes are likely to be replaced by a single expanded MRET target of 45,000 GWh of new renewable generation by 2020 (see Table A-2).

o When added to pre-existing generation this will give a total level of renewable generation of 60,000 GWh in 2020 (about 20% of total electricity demand then).

• Green Power Schemes, which grew by 25% over the last year as more people become concerned over climate change, and now comprise around 1,500 GWh of generation.

• Renewable Energy Development Initiative and Renewable Energy Equity Fund, which have been used to develop and commercialise novel renewable energy technologies.

111 Ministerial Council on Energy Standing Committee of Officials Renewable and Distributed Generation Working

Group (2006), Impediments to the Uptake of Renewable and Distributed Generation, Canberra



• Renewable Remote Power Generator Program.

• Photovoltaic Rebate Program.

• Low Emission Technology Development Fund, which has funded some demonstration projects for low emission technologies, including a 150 MW solar PV concentrator plant. The new Australian Government has promised to establish another $500 million fund to demonstrate and develop new renewable energy technologies.

Table A-2: Renewable energy targets, GWh Year Current MRET Target Expanded MRET Target 2010 9,500 9,500

2011 9,500 13,050

2012 9,500 16,600

2013 9,500 20,150

2014 9,500 23,700

2015 9,500 27,250

2016 9,500 30,800

2017 9,500 34,350

2018 9,500 37,900

2019 9,500 41,450

2020 9,500 45,000 An additional market is to sell the output of an HTST plant on Green Power markets. Green Power is a product developed by electricity retailers comprising electricity sourced from accredited renewable generation. The high cost of renewable generation relative to conventional generation results in Greenpower being sold at a premium of a few cents per kilowatt hour. Green Power schemes can be either of two types:

• Consumption-based schemes, in which a premium is charged on the price paid by consumers on some or all of the electricity consumed. An example is Energy Australia's Pure Energy Scheme, which allows consumers to nominate a percentage of their electricity (25%, 50%, 75% and 100%) to come from renewable sources.

• Contribution-based schemes, in which consumers contribute to a fund administered by a retailer to support renewable energy generation.

For the year ending December 2006, there were over 138,879 customers who have opted for Green Power from their retailer. Green Power energy was 859 GWh in 2006. Green Power has had an impact on encouraging development in renewable energy and in 2006 it has contributed to around 20% additional renewable energy sales above the MRET target. Green Power is an ongoing program. Green Power schemes originated in New South Wales through the Sustainable Energy Development Authority (SEDA). SEDA had taken on the role of accrediting Green Power generators and auditing retailers to ensure that all Green Power sold is actually generated by an accredited generator. The functions of SEDA are now undertaken by the NSW Department of Energy and Water (DEW). The introduction of the Renewable Energy Certificate (REC) scheme has complicated the Green Power scheme and there was considerable uncertainty as to whether generation could be



accredited for both and therefore gain two additional revenue streams. This confusion has been resolved through new Green Power accreditation rules that essentially mean that renewable generation may be either used for the RECs or sold as Green Power, but not both. The decision a generator must make therefore is whether there is more value in the RECs or from Green Power sales. It is difficult to predict the market outlook for Green Power as it is a voluntary scheme and is entirely dependent on consumer demand. Although sales under Green Power have been growing strongly in recent years, the volumes of renewable energy are still small compared to other schemes such as MRET. Growing concern about the environment and climate change may encourage more consumers to purchase Green Power. For example, the South Australia Government has recently announced that it will purchase 20% of its energy needs from Greenpower. This will result in a reduction of the government’s greenhouse gas emissions by 107,741 tonnes per year. Assuming an emission intensity coefficient of 0.9t CO2e/MWh for electricity consumption, the Green Power purchase for the SA government is 120 GWh. The forecast market for renewable generation under the expanded MRET scheme and under Green Power Sales is shown in Figure A-2.

Figure A-2: Renewable generation required to meet expanded MRET target and Green Power sales

Despite the considerable investments on renewable energy under Government programs, very little of the investment has gone to HTST technologies. Only two projects have received funding, mainly in the form of R&D grants. To date, HTST has not been able to exploit the potential market under MRET or any other deployment support program. This probably reflects its stage of development, a negative attitude towards the technology and cost reductions achieved in more mature technologies such as wind generation.

0

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15,000

20,000

25,000

30,000

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2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

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Despite the support from government programs, renewable energy generation is still more expensive than fossil fuel generation options. Only in remote area power supply systems is renewable generation now competitive with fossil fuel alternatives and this in relation to PV type systems, not large scale systems like HTST. Current estimates of levelised costs for generation options are shown in Figure A-3. The chart indicates that renewable energy costs are at least 50% above fossil fuel generation costs and HTST is some three times more expensive than fossil fuel generation options.

Figure A-3: Levelised electricity generation costs in 2007 (Source: MMA analysis)

A.3 Economics of High Temperature Solar Thermal Generation Although HTST is currently expensive, further technological development could see this cost fall over time. In this Section, an analysis is undertaken of the market potential for high temperature solar thermal for electricity generation. The market potential is explored through the use of a model that determines the levelised energy cost of various generation options in the electricity markets in Australia. A number of case studies are developed for examining the potential, with the case studies being representative of the market opportunities available for HTST generation. The cost of HTST generation is compared to the cost of alternative generation options. The basis is that the least cost alternative will be selected to supply the market. Thus, HTST generation will only have potential if its cost of generation is lower than the alternatives. Seven potential locations were selected on the basis of having good insolation levels, proximity to local loads and high generation electricity costs from alternative options:

• Port Augusta in South Australia. A plant located here would be connected to the National Electricity Market (NEM). There are local industrial loads and any excess can be transmitted to other load centres in South Australia. The HTST options include retrofitting an existing coal fired unit at Northern Power Station, which provides additional advantages including prolonging the life of the coal mine supplying the plant

0

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Geothermal hotdry rocks

$/M

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Western Australia Queensland



and avoiding imports of black coal from NSW. Alternatives to HTST include gas-fired generation in South Australia, imports of black coal based or brown coal based generation from other states and geothermal generation.

• North West Victoria. A plant located here would be connected to the National Electricity Market and supply a number of regional towns in north-west Victoria such as Mildura and Swan Hill and, though the Murraylink interconnect (a 220 MW HVDC link connecting Victoria and South Australia), could also supply some regional loads in South Australia. HTST technology would not only be competing against centrally dispatched thermal generation, but also potentially against other renewable technologies such as the 150 MW concentrator PV technology plant proposed by Solar Systems in this area.

• Central and North West NSW. A location with good solar insolation levels, an economic sized plant located here would supply some small regional loads but would also need to be supplying loads further away. The plant would be competing with black coal generation in NSW and Queensland as well as some other renewable energy projects proposed for the area (such as the 1000 MW Silverton Wind Farm near Broken Hill). Because of the small size of the local load, supporting a large scale HTST option here would likely require an upgrade of the regional transmission system. A gas pipeline connection may also need to be constructed to provide gas for when there is no sunshine.

• Darwin-Katherine Interconnected System, which supplies Darwin and other major regional centres nearby. Electricity prices in the DKIS are traditionally high, reflecting the high cost of gas and the small scale of generation capacity. HTST would be competing against gas fired combined cycle or open cycle generation. A major advantage for HTST is the limited options for renewable generation, with the long term potential limited to biomass and geothermal. A location near Katherine is assumed, just below the wet season zone.

• Alice Springs – Tennant Creek. This location is blessed with good insolation and connects to a load sufficient to cater for HTST plant of between 20 MW to 50MW. Alternatives are limited and are high cost.

• Kalbarri, which is the northern most extremity of the South West Interconnected System. Again there is reasonable local load (township of Geraldton). Black coal and natural gas based generation are the major competitors. Although HTST generation is more expensive currently than these forms of generation, there have recently been sharp increases in fuel prices in the region: gas prices have more than doubled and coal prices have increased by 50%. Assuming fuel prices stay at or increase from current levels may narrow the gap in cost.

• Remote mining operation or remote large town. Western Australia and Northern Territory contain many such locations that would support HTST generation in the order of 10MW. Again, alternative options are high cost, particularly given high liquid fuel and natural gas prices.

Three high temperature solar thermal options were examined in this study:

• Stand-alone HTST operation, with gas used as a back-up fuel for when there is no sunlight. Where gas is not available on-site, it was assumed that a lateral from the nearest pipeline would be built to the site.

• HTST with sufficient storage to allow intermediate operation.

• HTST providing steam to an existing coal or gas-fired plant (so called solar assist). For grid connected applications, the cost of providing power was examined for peak period operation of the plant (typically 6.00 am to 10.00 pm on weekdays). Demand in peak periods is growing faster than off-peak demand due to a combination of increased penetration of air-conditioners in homes and commercial buildings and increased use of computers and other electrical appliances. Prices are typically higher in the peak period reflecting the high cost of



conventional options supplying peak power. For off-grid application, 24 hour power supply options are considered.

A.3.1 Method Generation costs have been estimated using MMA’s GENCHOICE model. The model calculates the levelised energy cost (LEC) for new generation plant. The LEC of a new generation option is equal to the present value of capital, fuel and operating costs divided by the present value of the output over the expected life of the plant. For each option, the full costs of generation are modelled. Costs include:

• Capital cost, which are modelled as a function of capacity (to reflect the economies of scale with unit size).

• Coal, biomass, liquid fuel or natural gas costs are modelled as delivered cost for the fuel on a $/GJ basis and a heat rate for each technological option.

o The natural gas cost is equal to the forecast city gate price for the nearest city gas node as forecast by MMA plus any additional transmission cost (in some locations the additional transmission cost may be negative if the plant location is closer to the gas field than the city gate node).

• Non fuel operating and maintenance costs.

• Transmission connection costs (including deep connection cost if the plant supplies more than the local loads).

• Network fees for backup supply.

• Sequestration costs (if any). Levelised generation costs are calculated for each year of entry of the plant from 2010 to 2030. In this way, trends in capital costs, conversion efficiency and fuel prices are captured. Costs are also affected by the following:

• Carbon prices. The model adds a variable cost equal to the carbon price multiplied by the emission intensity of the generator. Greenhouse gas emissions from the combustion process result from the conversion of carbon in the fuel to CO2. The key parameters in determining the CO2 emissions are therefore the quantities and types of fuel used and the carbon content of the relevant fuels. Carbon contents and combustion emission intensities for each different coal and gas that supplies electricity-generating facilities have been identified and incorporated into the model. Emission intensities are based on the emission intensities of fuels supplying power stations as estimated in the National Greenhouse Gas Inventory.

• Locational benefits in the form of avoided transmission costs. These benefits, if any, are treated as negative costs. Avoided transmission upgrade costs are treated as negative capital costs. Avoided transmission use of system charges are treated as negative variable costs.

Renewable generation such as HTST generation may also provide other benefits. For example, renewable generation provides generators with a hedge against fuel supply risks. Fossil fuel based generators can face significant risks over the future cost of the fuel, even when they enter into a long term contract for fuel (as these often contain price re-openers). Ample supplies of coal and natural gas have meant that the risks of price changes for fuel have been minimal in Australia. However, in some regions of Australia recent developments have increased the risk, particularly in remote locations. For example, fuel prices have increased sharply in Western Australia and there is considerable uncertainty over future prices for natural gas in particular. Coal prices have increased markedly for new coal contracts across the board due to increased world prices for coal.



Future emission prices are also highly uncertain, with prices depending on the targets on emissions imposed and the cost of abatement. This means that owners of fossil fuel plants also face uncertainties over future cost imposts on emissions. On the other hand, intermittent sources of generation such as stand-alone HTST have the risk of not being able to supply electricity when needed. In this analysis, this has been mitigated by the inclusion of back up options (either natural gas or some form of storage). To reflect the lower fuel supply and lower emission risks of HTST plants, 1 percentage point has been deducted from the weighted average cost of capital applied to HTST options with no gas back-up and 0.5 percentage points deducted for HTST with natural gas back-up. For the Port Augusta location, the alternative options considered are:

• Combined cycle gas turbine located in Adelaide • Combined cycle gas turbine located in Port Augusta • Imported power from a black coal supercritical plant • Imported power from a black coal ultra supercritical plant • Imported power from a brown coal supercritical plant

• Imported power from a brown coal IGCC • Imported power from a brown coal IGCC with carbon capture and storage.

For the north west Victoria location, the alternatives are:

• Combined cycle gas turbine located in south west Victoria • Imported power from a black coal supercritical plant • Imported power from a black coal ultra supercritical plant

• Brown coal supercritical plant located in the Latrobe Valley • Brown coal IGCC plant located in the Latrobe Valley • Brown coal IGCC plant located in the Latrobe Valley with carbon capture and storage.

For the central and north west location in NSW, the alternative options considered are:

• Black coal supercritical plant located in the Hunter Valley • Black coal ultra supercritical plant

• Black coal IGCC • Black coal IGCC with carbon capture and storage

For the Kalbarri location the alternatives are:

• Combined cycle gas turbine, located in Kwinana • Combined cycle gas turbine with carbon capture and storage located in Kwinana • Combined cycle gas turbine, located north of Perth

• Black coal supercritical plant • Black coal IGCC • Black coal IGCC with carbon capture and storage.

For the Darwin-Katherine Interconnected System, the alternatives are:

• 50 MW combined cycle gas turbine located near Darwin • 30 MW open cycle gas turbines • 10 MW biomass generation

• 50 MW geothermal generator located south of the Darwin Katherine system but with HVDC transmission to the grid.



For the Alice Springs – Tennant Creek location, the alternatives are:

• 10 MW open cycle gas turbine • Power imported from a nearby geothermal plant of 10 MW.

For remote locations, a 10 MW peak load was assumed. The options for supply are:

• Diesel generation. • LNG-fuelled engine.

A.3.2 Assumptions Initial physical and cost assumptions and key escalators are shown in Table A-3. Assumptions applying to HTST technologies were obtained from a range of sources, with the basic source a study conducted for NREL. The key inputs used in the GENCHOICE model for HTST are given in Table A-4. Capital costs of HTST used for the 2010 estimate compare with the following cost estimates for recent projects completed or underway:

• 29 million euros for the 10 MW PS10 solar tower plant in Southern Spain, amounting to around $50 million in 2007 dollars or around $5,150/kW112.

• 53 million euros for the 15 MW Solar Tres solar tower plant in Spain, which includes an innovative molten salt storage system. This amounts to around $90 million in 2007 dollars or around $5,900/kW113.

• 157 million euros for the 50 MW Euro Trough plant proposed for Andasol in Spain, which includes a molten salt based storage system to provide 9 hours of storage. This amounts to around $260 million in 2007 dollars or around $5,230/kW114.

112 European Commission (2007), Concentrating Solar Power: Main Projects Supported By The Commission, Brussels.

Costs were reported in 2005 dollars. All costs were converted to mid 2007 Australian dollar terms by inflating 2005 price by 2.5% per annum and using an exchange rate of A$:euro of 0.60

113 European Commission (2007), Concentrating Solar Power: Main Projects Supported By The Commission, Brussels. Costs were reported in 2007 dollars. All costs were converted to mid 2007 Australian dollar terms by inflating 2005 price by using an exchange rate of A$:euro of 0.60

114 European Commission (2007), Concentrating Solar Power: Main Projects Supported By The Commission, Brussels. Costs were reported in 2007 dollars. All costs were converted to mid 2007 Australian dollar terms by inflating 2005 price by using an exchange rate of A$:euro of 0.60



Table A-3: Technology costs and performance assumptions, mid 2007 dollar terms Option Life Auxilliary

Load Sent-out Capacity

Capital Cost, 2010

Capital Cost Deescalater, 2010 to 2020


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Efficiency improvement

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Black Coal Options

Supercritical coal (dry-cooling) 35 8 690 1,677 0.5 0.5 9.6 0.48 3 30

Ultrasupercritical coal 60 8 690 2,012 0.5 0.5 8.7 0.48 3 38

IGCC 30 22 554 2,385 2.0 1.0 9.1 1.20 2 44

IGCC with CC 30 25 473 4,050 2.5 1.0 11.4 1.30 3 50

Ultrasupercritical with CC and oxyfiring 60 30 525 2,674 1.0 0.5 12.0 0.58 3 39

USC with post-combustion capture 35 19 608 2,215 2.5 0.5 12.9 0.58 4 39

Brown Coal Options

Supercritical coal with drying 60 12 636 1,759 0.5 0.5 9.2 0.48 5 55

Supercritical coal 60 8 665 2,018 0.5 0.5 10.4 0.48 5 42

Ultra supercritical coal with drying 60 12 636 2,111 2.0 0.5 8.8 0.48 5 60

IGCC with drying 30 18 430 2,169 2.0 1.0 9.5 1.20 4 42

IDGCC 30 18 458 1,875 1.0 0.5 9.2 1.20 6 39

IGCC with CC and drying 30 22 400 3,800 2.5 0.5 12.0 1.30 5 55

IDGCC with CC 30 20 416 3,700 1.5 0.5 10.8 1.30 5 61



Option Life Auxilliary Load

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CCGT - SA 30 2 235 1,309 0.5 0.5 7.4 0.60 3 22

CCGT - NT 30 2 47 1,833 0.5 0.5 7.8 0.60 4 25

CCGT - Elsewhere 30 2 490 1,190 0.5 0.5 6.8 0.60 3 20

Cogeneration 30 2 235 1,553 0.5 0.5 5.0 0.60 3 20

CCGT with CC 30 10 450 3,810 1.0 0.5 7.9 0.70 4 40

Renewables

Hydro Upgrades 40 2 100 2,500 0.5 0.5 na 0.10 1 5

Wind 25 1 99 1,822 2.0 0.5 na 0.20 2 35

Biomass - Steam 30 6 28 2,318 1.0 0.5 11.5 0.10 4 50

Biomass - Gasification 25 10 27 2,484 2.0 1.0 11.0 0.10 5 50

Geothermal - Hot Dry Rocks 25 10 45 3,350 2.0 1.0 12.0 0.10 3 70

Concentrating PV 30 3 97 2,700 1.0 1.0 0.10 Note: Plant capacity, efficiency and cost data are based on a sent out basis; na = not applicable



Table A-4: Physical and cost assumptions for HTST technologies115 Item 2010 2020

Net Power MWe (per plant) 150 400

Solar field optical efficiency 0.598 0.602

Annual solar to electric efficiency (%)

17.0 17.2

Capacity factor 56 56

Capital costs ($A/kWe)

Structures 95 70

Solar collector 2,625 1,965

Thermal storage 665 665

Steam Generator 130 125

EPGS 510 340

BOP 295 200

Total 4,320 3,360

Operating costs $A/MWh 13.5 10 Source: MMA analysis based on Simons (2005) and Sargent and Lundy (2003). US dollar estimates were

converted into Australian dollar estimates using an exchange rate of 0.89. Capital costs were increased by 40% for the 2010 estimates to reflect the impact on capital costs of recent shortages of skilled labour, equipment supply constraints and high material costs. The 2020 estimates were left as is to reflect the assumptions that current tight supply constraints in materials and equipment will have been alleviated by then.

A key issue is the rate of change in capital cost for HTST in the future. Estimates of the potential cost reduction vary widely, as follows:

• Navigant Consulting in a study for Arizona Department of Commerce claim that costs of electricity from parabolic dishes will decline by more than 50% by 2025 (to US$80/MWh or around $A90/MWh assuming an exchange rate of 0.89).

• A recent study (US DOE (2006)) identified 6 possible avenues for technological improvements in power tower technologies that would reduce capital costs including less conservative azimuth drive (leading to cost reductions of around 33% or around $8/m2 for heliostats); pipe in pipe azimuth drive (leading to cost reductions of around 33% or around $8/m2 for heliostats); large carousel type stretched membrane heliostat (estimated to lead to a 10% reduction in capital cost); large single fabric stretched membrane facet (estimated to lead to a reduction in capital cost of around $7/m2); mega heliostats (estimated to lead to a net cost reduction in capital cost of around $18/m2); and water-ballasted heliostats.

• A study by DLR (2005), indicated that levelised energy costs could fall from current levels of around 15 (parabolic trough) to 20 (Dish Stirling) Euro cents/kWh (or $A265 to $A350/MWh in 2007 dollar terms) to around 5 Euro cents/kWh (or $A90/MWh in 2007 dollar terms) through learning by doing and economies of scale if around 40 GW of capacity was installed by 2020 to 2025. Around half of this cost reduction is predicted to be due to production scale up effects and the other half by technological development. The cost reductions are likely to come through improved concentrator performance, scaling up plant size, improved storage systems and improving the capability of receivers to generator high temperature steam.

115 Differences in solar irradiation by location were based on data provided by the Bureau of Meteorology and were

expressed in the model in differences in the capacity factor applicable to HTST capacity without storage (with the cost of storage adjusted to give the required time of operation of 91 hours per week).



Fuel prices are a key assumption driving the cost of alternatives. Assumed gas prices are shown in Figure A-4. Coal prices are shown in Figure A-5.

Figure A-4: Gas prices

Figure A-5: Coal prices

A.3.3 Cost comparisons Port Augusta Costs of selected alternatives for new plant entering the market in 2020 are shown in Figure A-6. HTST, on a stand-alone basis (with gas back-up) or with storage, is currently not economic as an option for location near Port Augusta. HTST providing solar assist for an existing power station may be economic in the near term.

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Trends in costs for the various options over time are shown in Figure A-7. Although the cost of HTST technology is likely to fall over time, the rate of decline is likely to be insufficient under current progress ratios for capital cost. Solar assist options offer the best prospect, with this option likely to be economic by 2020.

Figure A-6: Levelised energy cost of new plant in Port Augusta, 2020

Figure A-7: Trends in LEC at Port Augusta, 47% capacity factor (peak period operation during 6.00 am to 10.00 pm weekdays)

Imposition of carbon prices under an emission trading scheme could alter the relative costs and improve the prospects of HTST generation. Carbon prices of around $10/t CO2e would likely see

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solar assist being economic relative to other new generation options. Carbon prices of around $70/t CO2e are likely to see other HTST technologies being economic relative to other new generation options (see Figure A-8).

Figure A-8: Impacts of carbon price on LEC at Port Augusta, 2020, peak period operation North West Victoria North-west Victoria has good solar insolation levels (particularly in summer) so is a prospective location for HTST generation. However, it has some natural disadvantages such as limited natural gas transmission systems to provide adequate capacity116 and limited local load to accommodate the output of a plant of an economic scale capacity. Unlike in South Australia, electricity generation costs from alternatives are likely to be much lower due to the availability of low cost coal-fired generation options and lower gas prices than in South Australia. The lack of competitiveness is borne out in Figure A-9, which shows the levelised cost of various generation options for Victoria. In 2020 HTST technologies would not be competitive even after an assumed decrease in capital costs for HTST technologies. The levelised costs for HTST are predicted to be around $120/MWh when relying on gas generation for back up and $100/MWh with on-site energy storage. However, as with South Australia, imposition of a carbon tax could make the HTST plant competitive with other fossil fuel options. Carbon prices of $65/t CO2e would make the technology competitive (Figure A-10). As there is much uncertainty over the capital costs of some alternative low emission technologies such as carbon capture and storage, HTST may even be more competitive in the long term than indicated by this analysis.

116 A new gas pipeline to Mildura was recently completed, but this pipeline system has limited capacity and may need

to be upgraded to accommodate supplying a new load such as an HTST plant. Gas to the plant has been assumed to cost $6/GJ on a delivered basis

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Figure A-10: Impacts of carbon price on LEC at north west Victoria, 2020, peak period

operation117 117 As in other charts in this Appendix showing the impact of the carbon price, the minimum cost alternative curve

represents the levelised cost of the least cost fossil fuel alternative. A kink in this curve indicates that the minimum cost alternative technology changes at a certain carbon price. In this case, the minimum cost alternative changes from a conventional steam fired coal plant to a gas fired combined cycle plant with carbon prices above $15/t CO2e

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operation118 Kalbarri Solar thermal technologies have reasonable prospects in some regions of Western Australia compared with the NEM, due to better insolation levels. Kalbarri already operates a demonstration PV plant and its closeness to the SWIS grid offers a market for power from a HTST plant. The analysis reports the cost of supplying power to the Geraldton node for HTST and alternatives in the SWIS supplied from the grid. Note that HTST plant greater than about 100 MW in this location would be supplying other nodes in the SWIS apart from Geraldton. HTST technologies are likely to be higher cost than alternatives for supplying loads to Geraldton in the near future (see Figure A-13), but HTST solar assist attached to an existing coal steam plant (Muja Power Station) could be economic next decade (assuming gas prices remain high) and the life of this thermal power station could be extended as a result. Even increases in fuel prices for coal and natural gas of 30% would not see HTST technologies being the least-cost technologies in this location. Significantly faster rates of decline in capital costs or imposition of carbon penalties is required to make the technology economic. Carbon prices of $50/t CO2-e would make HTST with gas back-up economic compared for intermediate load duty. Carbon prices of $50/t CO2-e would make HTST with storage economic relative to other options for high load duties towards the end on next decade (see Figure A-14).

118 As in other charts in this Appendix showing the impact of the carbon price, the minimum cost alternative curve

represents the levelised cost of the least cost fossil fuel alternative. A kink in this curve indicates that the minimum cost alternative technology changes at a certain carbon price. In this case, the minimum cost alternative changes from a conventional steam fired coal plant to a gas fired combined cycle plant with carbon prices above $15/t CO2e



Figure A-13: Trends in LEC, 47% capacity factor, Geraldton location

Figure A-9: LEC of generation to supply Geraldton as a function of carbon price, peak period

duty, 2020119 119 The minimum cost alternative line kinks at around $30/t CO2e due to the change in least cost technology. Below

$30/t CO2e, the least cost technology is a coal-fired option. After $30/t CO2e, the preferred or least cost technology is a gas-fired option.

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Katherine For other locations examined, the gap between the cost of HTST technologies and alternatives is narrower. At current fuel prices, the gap between HTST and other technologies is estimated to be around $20/MWh in 2010. By 2020, some HTST technologies could well be an economic alternative in places like Katherine (Figures A-15 to A-17), especially if gas and liquid fuel prices rise further. Carbon prices of around $30/t CO2-e, capital costs of alternatives moving 10% higher than current costs or fuel costs similarly higher than current levels may see HTST technologies being able to compete in remote northern locations with large loads by 2020. These regions offer the best near term prospects for HTST technologies.

Figure A-105: LEC of new plant options with no CO2-e price, Katherine, 2020

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Figure A-127: Impact of carbon prices on LEC, 47% capacity factor, Katherine location,2020



Remote areas Remote area power supply systems tend to be much smaller in size, with demand ranging from less than 1 MW for small communities and homesteads to around 20 MW for the larger communities and mining operations. Because of the small size of the operation and potentially low water availability in remote areas, the analysis was confined to parabolic dish systems, backed up by some diesel engines. Because of the small scale and the relative capital intensity of HTST systems, the technology is not likely to be an economic option for remote power systems (Figures A-18 and A-19). However, carbon prices of around $30/t CO2-e will likely see HTST options economic relative to diesel only operation by mid next decade. Increasing the carbon price to $55/t CO2-e will likely see it economic compared to the compressed natural gas options by 2020.

Figure A-138: Levelised costs of generation options for remote power supplies

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Figure A-149: Levelised generation costs with carbon prices of $55/t CO2e in remote systems

A.3.4 Summary The results of this cost-modelling analysis are in line with other studies. Most overseas studies predict that without further support, HTST technologies will be able to compete on a levelised cost basis with conventional fossil fuel technologies by sometime in the period after 2020. For example, Navigant Consulting (2007) predicts that HTST technologies (Dish Stirling and Parabolic Troughs) will be competitive with gas-fired generation in the USA by 2025, assuming gas prices remain between US$5.30/GJ to US$10.50/GJ and that further technological development occurs. Navigant also predicts that HTST could be economic relative to coal-fired generation by 2025 if scale production of mirrors was to occur. Cost reductions estimated in this report could occur through a number of technological developments. The cost reduction for HTST technology predicted by many commentators reflects a rate of decline in costs that is greater than assumed for other renewable energy technologies. This is justified on the grounds that HTST technology is in the early stages of its development; there is enormous scope for expanding production of HTST mirrors allowing for economies of scale to be captured; and the average size of plant is likely to increase once the technology is proven.

A.4 Market Potential HTST technologies can bring many benefits to electricity markets:

• Reduce emissions of greenhouse gases and other harmful air pollutants

• Provision of network support services, particularly in fringe of grid areas

• Potential to supply electricity at peak times (to the extent they coincide with peak sunny periods)

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• Potential for reducing network infrastructure investments if distributed widely in the grid system

• Diversifying energy sources, improving reliability and security of supply.

• Can better match load growth with capacity additions.

• Can provide heat as well as power in some locations and some applications, although the opportunity for this appears to be limited in Australia.

However, HTST technologies are unlikely to be competitive in the near term with alternative generation options except in remote northern locations with major loads. Solar assist, however, does promise to be competitive in other locations. Improving the competitiveness of solar thermal technologies will require either:

• Faster rate of development and deployment of the technologies so that capital costs decrease substantially.

o It appears from this analysis that the best option for gains comes from reducing the capital costs of the solar collectors or mirrors.

o Conversion efficiency improvements could also help but the impact on cost is more limited.

• Imposition of an emission trading scheme.

o Prices of $50/t CO2-e or more are required. However, these prices are likely in the future if deep cuts in emissions are required. This offers the greatest promise for solar thermal technologies.

In this section, the principal markets for HTST generation are examined. The potential applications are detailed and a projection of market potential for HTST provided.

A.4.1 Competition principles A key feature of Australia’s electricity market is its competitive nature. HTST has to compete with other technologies for the right to supply electricity in the markets. In the major grids, generators bear the risk of their generation remaining competitive. Generators compete for the right to be dispatched on the spot market through a regular auction process, which tends to select for the lowest cost options available to meet particular market segments (base, intermediate and peak loads). Even in smaller grid or remote power supply systems, generation rights are now largely determined through tenders that select the least cost option. The competitive nature of the markets is also enshrined in National Competition Laws, which prevents Governments or market operators from enacting regulations that favour one type of technology over any other type of technology unless there is a clear, demonstrated benefit to the community. The competitive nature of markets has tended to favour fossil fuel generation due to its low fuel cost and its high conversion efficiency. However, the markets for electricity are evolving. Increasing fossil fuel and capital costs have increased the cost of fossil fuel generation relative to renewable energy generation. In some states, gas prices have more than doubled over the last two years. Coal prices have also increased due to higher demand for thermal coals on world markets. The likelihood that carbon abatement policies will be enacted sometime in the near future has put a risk premium on high emission fossil fuel generation options such as coal-fired. These factors are favouring the adoption of renewable energy generation, which has been backed by a number of government support measures designed to increase the deployment of renewable energy and reduce its cost. But Australia also is blessed with other renewable or low emission resources. Good wind profiles and niche biomass resources are available and this has led these technologies to dominate the



market for renewable energy in Australia. HTST will need to compete with these technologies on cost in order to carve out a market niche.

A.4.2 Peak lopping market segment The analysis confirms that HTST could compete with gas-fired generation to meet peak demand sometime over the next decade should HTST capital costs be reduced as planned. However, the peak demand in the major electricity markets is characterised by a high level of demand for a short period of time. For example, the highest 1000 MW of peak demand in Victoria occurs for less than 1% of the hours in the year. Thus, a HTST plant would be competing with a mixture of peaking and intermediate plant in most electricity markets in Australia. Although the analysis indicates that the levelised cost of electricity for HTST could be comparable to the cost of gas-fired generation for peak power, the cost of the two options for peak load duty are not directly comparable because other factors affect their performance for peak load duty. These factors include120:

• HTST output is comparable to a mix of peaking and intermediate cycle and so is not only competing with open cycle gas turbines for peaking duty.

• Open cycle gas turbine capacity has added flexibility to generate when needed.

o HTST can provide some of this flexibility if thermal storage is added.

• Open cycle gas turbine capacity may still be required to address intermittency and the non-coincidence of system and solar peak.

• HTST provides a hedge value against gas price volatility (which is increasingly important in Western Australia and Northern Territory).

• High level penetration of HTST will reduce gas usage and put downward pressure on gas prices.

• A value to HTST for emissions reduction, not just of greenhouse gas emissions but other air pollutants.

• Six hour storage capability built into post-2010 HTST costs mitigate intermittency and non-coincidence issues

A.4.3 High load duty market segment HTST can supply high load duty (base and intermediate load) markets either where there is a high solar insolation level near a major load, where there is a nearby gas network to supplement steam raising at the HTST plant or adequate energy storage is part of the HTST plant. In Australia, there are two circumstances where HTST technology can provide high load duty operation. First, isolated grid systems where there is a gas network as well as good solar insolation resources could provide an opportunity for high load duty operation by HTST plant with gas co-firing as a fuel. Potential grids include the Mt Isa Mineral Province (which is currently supplied by gas fired generation and is the site for a proposed HTST plant with graphite block storage (Cloncurry)), Alice Springs Reticulated System, Tennant Creek Reticulated System and North West Interconnected System in the Pilbara. All sites have average daily sunshine hours of greater than 9 hours per day121 and average daily insolation levels of greater than 21 MJ/m2. All have gas pipelines supplying gas-fired open cycle gas turbines. Generation costs are also typically high due to the high cost of gas and the small scale of the generating plant.

120 Navigant Consulting, Arizona Solar Electric Roadmap Study: Full Report, published by Arizona Department of

Commerce, January 2007. 121 Australian Bureau of Meteorology (2000) quoted in D.R. Mills, Fresnel Reflector Solar Power Plants, University of

Sydney, 2006.



Table A-5 contains details of the maximum load and current generating capacity at these sites. Although the loads are small, load growth is quite high at Mt Isa and in the Pilbara, averaging around 4% per annum on the back of high demand for the mineral products mined at these locations. As shown in Figure A- (a) to (d) and Figure A-, the need for new capacity to meet load growth is around 350 MW by 2030, with the bulk of this required at Mt Isa and the North West Interconnected System.

Table A-5: Electricity demand and existing capacity at selected isolated grid systems, 2005/06 Location Energy Consumption,

GWh Peak demand, MW Capacity, MW

Alice Springs1 275 62 90 Tenant Creek1 33 8 21 Mt Isa 2,008 306 430 Pilbara 829 152 656

1. Includes regulated and non-regulated loads. Sources: MMA analysis based on Horizon Power, NT Utilities Commissions, and CS Energy Annual Reports

Furthermore the cost of generation has increased markedly in these regions because of recent increases in prices of natural gas (which have more than doubled over the past two years) and liquid fuels. Although published data on electricity supply costs are somewhat limited, the data available indicate that purchase costs are at least $145/MWh at the wholesale level, and probably more above $200/MWh when capital costs are included. Assuming an average size of 20 MW for a HTST plant, the analysis in Section 1.4.3.5 would indicate that HTST could be an economic option for these grids some time towards 2020.

Figure A-20: Supply/demand in isolated grid systems (a) Alice Springs

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Figure A-21: Total new capacity requirements in isolated grids The second potential market for high load duty power is to supply the major grids under a favourable policy regime where governments support renewable generation or there is a high price on carbon emissions.

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The new Australian Government has a target of 45,000 GWh of new renewable generation by 2020, of which 9,500 GWh is already locked in under the existing MRET scheme giving an additional requirement from now until 2020 of around 35,500 GWh. However, HTST will be competing with other renewable resources such as wind and biomass generation to meet this target. Unless there are substantial cost reductions for HTST, it is unlikely to benefit from this scheme (see Figure A-). The cost of HTST generation is likely to be substantially greater to 2020 than the low cost options for wind, hot dry rocks geothermal and biomass generation.

Figure A-22: Net levelised energy cost curves for renewable generation, mid 2007 dollar terms Source: MMA analysis from its database of renewable energy project costs. Note: Covers existing and committed plant (short run marginal costs only) as well as the cost for new

renewable generation. Each point represents the net levelised electricity cost (levelised cost after average electricity prices earnt have been deducted). The curves provide a guide to the certificate price required for each level of renewable generation.

However, beyond 2020, additional tranches of renewable energy are likely to be required to meet emission abatement targets. The Australian Government has an aspirational goal of a 60% reduction on 2000 emissions by 2050. In Figure A-, emissions under the current policy regime are shown122, assuming no emission trading scheme but including the 45,000 GWh renewable energy target. Without further action to abate greenhouse gases, emissions from electricity generation are likely to remain at current levels over the next decade due to the impact of existing abatement policy measures, but then climb by around 1.7% per annum to reach about 400 Mt CO2-e by 2050. Forecasts by other agencies such as ABARE have even higher projections of emissions from electricity generation. 122 Assuming trend growth rates in electricity demand of just under 2% per annum, the 45,000 GWh renewable energy

target by 2020 is imposed and other Government abatement policy measures continue operating to expiry date with the exception of the NSW Greenhouse Gas Abatement Scheme which is assumed to expire in 2012.

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Figure A-23: Projections of emissions from electricity generation (Source: MMA analysis) A cut of 60% of 2000 levels applied to electricity generation would imply an emission target of 70 Mt CO2-e by 2050, some 330 Mt CO2-e less than projected levels and implying a level of abatement greater than current emission levels. As shown in Figure A-, around 370,000 GWh of low emission generation (renewable generation or fossil fuel generation with carbon capture and storage) or energy efficiency would be required to meet this target. The level of low emission generation required could ultimately be much higher than this if there is a shift towards electricity generation as a result of abatement in other sectors123. About 150,000 GWh of low emission generation or energy efficiency would be required by 2030, representing a substantial market opportunity for renewable generation or fossil fuel generation with carbon capture and storage.

123 For example, a shift towards plug-in electric hybrid vehicles.

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Figure A-15: Requirement of low emission generation or energy efficiency to meet abatement target (Source: MMA analysis assuming average emission intensity of 0.90 t/MWh)

HTST would be competing with other renewable options to meet this demand for low emission generation. However, there are limits to the ability of other renewable options to meet this target:

• Analysis by MMA indicates that about two-thirds of the 45,000 GWh Renewable Energy Target by 2020 would be met by wind generation, or around 30,000 GWh.

o Assuming an average capacity factor of 33% would imply around 10,500 MW of wind capacity would be installed, representing around 4,200 turbines at an average capacity of 2.5 MW or 3,500 turbines at an average capacity of 3 MW.

o Installing additional wind capacity is possible, but costs would increase as wind farms locate in areas with less favourable wind regimes. Further, there may be limits on the capacity of the grid to accept higher levels of intermittent generation. Such a high number of wind turbines would also create social protest for aesthetic reasons.

o A reasonable assumption would be to assume around an additional 30,000 GWh of wind generation could be installed by 2030 (on top of the 30,000 GWh required for the expanded MRET target) representing a total capacity of 21,000 MW or at least 7,000 wind turbines dotted around the major grids. This additional capacity is likely to cost in excess of $100/MWh in 2007 dollar terms.

• Optimistic estimates put the hot dry rocks geothermal potential at around 10,000 MW of capacity. Assuming a capacity factor of 85%, around 75,000 GWh could be met from this resource over the long term.

• The resource potential from low cost biomass covering agricultural processing waste, food production waste, cereal straw and municipal solid waste is limited.

o Analysis by MMA (Table A-6) indicates that this potential is limited to around 10,000 GWh. Assuming carbon prices lead to electricity prices greater than

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$200/MWh could also lead to the utilisation of cereal straw as a fuel for generation, adding around 10,000 GWh.

o Further biomass resource could be obtained through energy crops but this would be very expensive due to the high cost of the fuel and could result in resources being diverted away from food production.

• Only about 600 GWh of additional renewable energy could be obtained from upgrades of existing hydro-electric facilities or installation of new mini-hydro plant.

Table A-6: Biomass generation potential, GWh

2010 2015 2020 2025 2030

Bagasse 6,117 6,700 7,072 7,287 7,507

Rice husks 20 319 335 352 370

Wood and wood products 1,000 1,104 1,219 1,346 1,486

LFG and municipal solid waste 500 513 526 539 552

Total without cereal straw 7,637 8,636 9,152 9,524 9,915

Cereal straw 9,177 9,645 10,137 10,654 11,197

Total 16,813 18,280 19,289 20,178 21,113 Source: MMA analysis

A summary of the renewable energy resource availability is provided in Table A-. After deducting energy efficiency potential and the potential generation from standard renewable energy resources, there is gap in generation required from other low emission sources to meet abatement requirements of about 25,000 GWh in 2030 and about 100,000 GWh in 2050.

Table A-7: Low emission generation potential by source of generation, TWh 2010 2015 2020 2030 2050

Abatement requirements 0 7 39 160 371

Energy efficiency 0 2 13 53 122

Low emission generation requirements 0 5 26 107 249

Sources of low emission generation

Hydro electric 0 1 1 1 1

Wind 0 4 20 30 30

Biomass 0 1 6 21 40

Hot dry rocks geothermal 0 0 0 30 75

Deficit 0 0 0 25 103

Source: MMA analysis. Assumes energy efficiency can meet one-third of the abatement requirements The gap in generation could be met from fossil fuel generation (requiring around 5 x 750 MW coal plant with carbon capture and storage by 2030), retrofitting of existing plant with carbon capture and storage or HTST generation. The gap represents about 5,000 MW in 2030 and 20,000 MW in 2050 of HTST capacity. This analysis is illustrative only, but it does highlight that in order for Australia to meet its long term commitments to reduce abatement a range of low emission generation options are required to be deployed, including HTST technology. The need for low abatement generation to supply electricity to the major grids represents the largest market potential for HTST-based generation in this country.



A.4.4 Solar assist market segment Solar assist is the option of utilising HTST technologies to provide steam to existing fossil fuel steam plant and reduce the use of fossil fuel in steam raising. According to the case study analysis, solar assist is potentially a highly economic option due to the lower capital cost because there is no need to provide a steam generator and the thermal “back-up” is provided. Solar assist could also assist in extending the life of existing plant where there is limited coal supply or where there are issues in relation to air pollution limits. The market potential for solar assist is limited, though, to around 5% of the thermal capacity, as there are thermal imbalance issues if more than this is provided124. Another limit is the availability of flat land to support the solar collectors. About 4000 square metres of land is required per MW of capacity. Table A- contains an analysis of the potential capacity that could be met by solar assist. Only steam plants were considered in the analysis. An attempt was made to estimate the potential capacity for solar assist based on estimates of the availability of land, fuel cost avoided, life of plant and competing options for carbon abatement.

Table A-8: Potential for HTST capacity in solar assist Power plant Fuel Used Capacity

(MW) Solar Assist Maximum Potential

(MW)

Land Area Required1

(m2)

Solar Assist Potential2

(MW)

Prospect

South Australia

Northern Coal 500 25 100,000 25 Very High

Playford Coal 240 12 48,000 12 Very High

Torrens Island

Gas, Oil 1,320 66 264,000 5 Low

Victoria

Loy Yang A Coal 2,200 110 440,000 55 Moderate

Loy Yang B Coal 1,000 50 200,000 25 Moderate

Yallourn W Coal 1,450 73 292,000 36 Moderate

Hazelwood Coal 1,760 88 352,000 44 High

Newport Gas 500 25 100,000 0 None

New South Wales Bayswater Coal 2,680 134 536,000 35 Moderate

Liddell Coal 2,060 103 412,000 25 Moderate

Mt Piper Coal 1.320 66 264,000 33 Moderate

Wallerawang Coal 1,000 50 200,000 25 Moderate

Vales Point Coal 1,320 66 264,000 0 None

Munmorah Coal 600 30 120,000 0 None

Eraring Coal 2,640 132 528,000 30 Moderate

Queensland

Swanbank B Coal 480 24 96,000 0 None

Millmerran Coal 800 40 160,000 40 Low

Kogan Creek Coal 750 38 150,000 38 Low

124 L. Wibberley, A. Cottrell, P. Scaife and P. Brown, Synergies with Renewables: Concentrating Solar Power,

Cooperative Research Centre for Coal in Sustainable Development Technology Assessment Report No 56, 2006. The report states that “the amount of solar assist can be higher than this if the host plant is adapted for solar augment.” In the analysis of market potential in MMA’s study, the assumption of a 5% upper limit is maintained.



Tarong Coal 1,400 70 280,000 70 Moderate

Tarong North

Coal 450 23 90,000 23 Low

Callide A Coal 120 6 24,000 0 None

Callide C Coal 840 42 168,000 21 Low

Callide B Coal 700 35 140,000 15 Moderate

Stanwell Coal 1,400 70 280,000 20 Low

Gladstone Coal 1,680 84 336,000 0 None

Collinsville Coal 185 9 37,000 0 None

Western Australia

Muja C Coal 440 22 88,000 11 High

Muja D Coal 440 22 88,000 11 High

Bluewaters Coal 200 10 40,000 5 Low

Collie Coal 320 16 64,000 8 Moderate

Kwinana C Coal, Gas 480 24 96,000 0 None Notes: (1) Land area calculated assuming 4,000 square metres per MW of capacity based on the land

area for the proposed 5 MW plant at Liddell. (2) Solar assist potential based on estimates of the land area available and assumes the

technology works as planned. The prospects for development depended on a number of factors. Plants with low or no prospects for solar assist were affected by:

• Availability of land. Some power stations are located within industrial estates near major urban centres (such as Newport, Torrens Island and Munmorah) and therefore there is likely to be a lack of space available for solar collectors.

• For some power stations, coal costs are low (such as the brown coal units in Victoria) and/or have relatively low carbon intensities (such as the new black coal units in the Surat Basin in Queensland), which mitigates against the economics of solar assist (as avoided fuel cost and carbon abatement are the major components of the benefit of solar assist).

• Undulating land limiting the amount of solar collectors that could be installed.

• The power station was planned to be mothballed due to the age of the plant (e.g. Swanbank B, Callide A, Kwinana C and Collinsville).

Some plants have been accorded moderate to high prospects for solar assist. This is because these plants face high costs under an emission trading regime, have good insolation levels (particularly in Western Australia and Queensland) and are likely to have some flat land available adjacent to the power station to install solar fields. Hazelwood is deemed to have high prospects because its current license limits its operating life to an lifetime emission cap, giving its operator the incentive to increase the station’s lifespan by adopting low emission technologies. However, insolation levels in south eastern Victoria are relatively modest. The Northern and Playford Power Stations in South Australia are also deemed to have very high prospects due to the fact that coal reserves supplying these power stations are likely to be depleted some time next decade under current operating regimes. Attaching solar assist can extend the life time of the coal resource and avoid the plant accessing more expensive coals from interstate.



Overall, the capacity of solar assist with moderate to high prospects of proceeding amount to around 460 MW, or about 1% of total installed generating capacity in Australia. Of course the potential could be higher if emissions permit prices of greater than $50/t CO2-e became the norm. Nonetheless, solar assist could provide a near term niche market for proven HTST technologies. Assuming a capacity factor of around 13% for the solar component, this capacity would contribute around 525 GWh of generation.

A.4.5 End-of-grid-support market segment HTST may have a market niche to support demand at end points of the major grids with good direct insolation levels, being more competitive with grid-supplied electricity by avoiding line losses and providing network support services. Table A- provides estimates of loads at end of grid regions for the NEM. The regions were selected if peak loads were greater than 20 MW and if there were no other forms of local generation nearby. The load centres were matched with data on gas availability and insolation levels. Despite the wide dispersal of loads in Australia, a key feature appears to be a spread of small loads across the regions, with very few regions with sufficient loads in good insolation areas to support localised generation with HTST technology. It is estimated that there is around 200 MW of potential load with good prospects for HTST generation, having available gas and/or very good insolation levels. Most of the good prospects were in South Australia and NSW. A further 600 MW potential may come from medium prospects for HTST and could be serviced by this technology from nearby generation sites as long as transmission costs from the HTST plant were reasonable.

Table A-9: Regional loads with potential for distributed generation Region Peak Demand,

MW Insolation

level, MJ/M2

Hours direct sunlight, Ave/day

Gas Available

Prospect

Victoria

Ballarat 156 <15 6 Yes Poor

Bendigo 197 <18 7 Yes Low

Geelong 380 <15 6 Yes Poor

Horsham 80 <18 7 Yes Low

Kerang 66 <21 8 Yes Medium

Red Cliffs 168 <21 9 No Medium

Shepparton 267 <18 7 Yes Low

Terang 164 <15 6 No Poor

Glenrowan 95 <18 7 No Low

Mount Beauty 127 <15 6 No Poor

Wodonga 96 <18 7 Yes Low

South Australia

Berri 100 <21 9 Yes Good

Blanche 33 <15 6 No Poor

Dorrien 55 <18 7 No Low

Kadina East 21 <18 7 No Low

Keith 24 <15 6 No Poor

Kincraig 24 <15 6 No Poor

Mt Barker 78 <18 7 No Low

Mt Gambier 32 <15 6 No Poor



North West Bend 30 <18 7 No Low

Playford 30 <21 9 No Medium

Port Lincoln 35 <15 6 No Poor

Snuggery 58 <15 6 No Poor

Tailem Bend 23 <15 6 No Poor

Waterloo 23 <18 7 Yes Low

Whyalla 98 <21 9 Yes Good

New South Wales

Armidale 30 <18 7 No Low

Gunnedah 25 <18 7 No Low

Lismore 114 <18 7 No Low

Mullumbimby 49 <18 7 No Low

Narrabri 43 <21 9 No Medium

Tamworth 109 <21 9 No Medium

Taree 103 <18 7 No Low

Terranora 103 <18 7 No Low

Albury 122 <18 7 No Low

Broken Hill 53 <21 9 No Good

Cooma 68 <18 7 No Low

Deniliquin 43 <21 9 No Medium

Griffith 70 <21 9 No Medium

Wagga 184 <18 7 No Low

Cowra 37 <18 7 No Low

Forbes 36 <18 7 No Low

Orange 127 <18 7 No Low

Wellington 167 <18 7 No Low

Queensland

Blackwater 87 <21 9 No Medium

Cairns 155 <18 7 Yes Low

Dysart 38 <21 9 No Medium

Egans Hill 64 <21 9 No Medium

Innisfail 30 <18 7 Yes Low

Kamerunga 42 <18 7 Yes Low

Lilyvale 86 <21 9 No Medium

Ross 46 <18 7 Yes Low

Source: MMA analysis based on annual planning statements

A.4.6 Remote area power supplies market segment There are about 200 MW of load in remote townships and mining operations that could potentially be serviced by HTST generation. Most are located in outback Western Australia and the Northern Territory, where there is good insolation and a lack of alternative renewable options. However, around 150 MW of this load has been locked out for the next twenty years as part of a process recently enacted by Horizon Energy to contract out generation to least cost options,



which has seen mainly liquid fuel-based generation phased out in favour of compressed natural gas-based generation. Hence this market has limited near term prospects of about 50 MW. Over the long term, when existing contracts expire, the market potential could increase to between 200 MW to 250 MW.

A.5 Role of HTST Clearly there will be a role for renewable energy generation to supply electricity demand in Australia, driven in the short term by Government support measures such as MRET and R&D funding, and in the long term by competing with low emission fossil fuel generation sources. HTST will be competing with a range of alternative renewable energy options and clearly all options will be utilised to some extent — dependent on their relative costs, supply reliability and resource availability. HTST has advantages (Table A-10) over other many other renewable energy options including:

• Free fuel source, unlike biomass and fossil fuel options, removing a significant source of uncertainty to investors.

• More reliable source (less intermittent) of generation compared with wind generation options.

• Potentially takes up less land space than wind.

• Much of the components are mature technologies.

Table A-10: Risks surrounding competing low emission technologies in Australia Issue Wind Biomass Photovoltaics HTST CCS Nuclear

Resource availability

Limited by wind availability, network issues and locational constraints to around 20% of peak load of grid systems

Limited at low cost to MSW products, agricultural wastes, food and wood production wastes.

Potentially unlimited with storage. Issues with adequate roof space or building façade space to enable use beyond domestic and commercial sectors. Perhaps only 25% to 30% of total roof space viable (correct orientation, no shading)

Potentially unlimited with storage.

6 billion tonnes of CO2 storage so far identified (equivalent to 30 years of emissions from current fossil generation)

Not limited in the short to medium term

Learning by doing potential

Moderate High Very high Moderate Moderate Moderate

Potential for cost reduction through scale economies

Very High Low Very high Moderate Low Low (potentially high for pebble bed reactors)

Regulatory issues

Network and locational pricing

Pricing issues over transport and storage

Waste disposal and location



Issue Wind Biomass Photovoltaics HTST CCS Nuclear Market issues

Reliability due to intermittency Competes on wholesale market

Fuel supply reliability. High fuel cost if using energy crops transported to plant. Competes on wholesale market

Reliability due to intermittency although storage can alleviate. Competes on retail market for small systems or wholesale market for large, concentrating PV systems

Reliability due to intermittencyalthough storage or co-firing with gas can alleviate. Competes on wholesale market

Fuel price risk. Cost of storage of carbon. Competes on wholesale market

Fuel price risk. Competes on wholesale market

Technical issues

Network stability issues

Other issues

Large land requirements Visual and noise impact

Noise and congestion from fuel transport

Urban planning issues (siting, shading) for small systems. Large land requirements and visual impact for concentrating PV systems.

Large land requirements Visual impact

Concern of long term radioactivity issues

In order to exploit the potential market niches available for HTST technologies, costs of generation will need to come down. The best prospects for cost reductions are through reducing the cost of field mirrors and thermal storage systems, which make up a large component of capital costs. Increasing plant size may also reduce operating costs through economies of scale. It is also clear that in the Australian market context, development of cost effective thermal storage or siting plants near gas pipelines to utilise gas as a backup fuel is crucial for the long term prospects for this technology. The development of a HTST generation sector would appear to have to go through a staged process as follows:

• Over the next decade, commercialise the technology through large-scale demonstration and early-deployment projects in niche markets in remote regions.

o Deploy to capture opportunities in niche markets in isolated grids and remote power systems over the period to 2020.

o About 400 MW of market demand is available for HTST in these markets and this could be a good testing ground for commercialised projects.

o There is strong potential for solar assist, but this market is limited in the long term to around 400 MW at most.

• The development of HTST technologies through exploiting opportunities in niche markets would all assist to prepare the technology for the long term main game, which is to be an option to supply the major grids when carbon prices are likely to be above $50/t CO2-e.

o The analysis indicates that by 2030 this market should be available to HTST technologies to provide low emission generation.

o As long as HTST continues to reduce its cost of generation, there is an enormous potential in this market of around 20,000 MW as other renewable options are likely to become limited by this stage.



APPENDIX B Stakeholders consulted The following people were interviewed and/or participated in stakeholder workshops during the development of this roadmap. Their contributions are gratefully acknowledged. National

Person Organisation Petra Stock Acciona Energy Keith Lovegrove Australian National University Igor Skryabin Australian National University, CSES Ray Prowse Australian National University, CSES Vince Power Citipower and Powercor Electricity Networks Rob Jackson Clean Energy Council Tim Burrows Climate Managers David Brockway CSIRO Energy Technology Wes Stein CSIRO Energy Technology John Carras CSIRO Energy Technology Paul Graham CSIRO Energy Technology Mark Squires CSIRO Energy Technology John Wright CSIRO Energy Transformed Flagship Roy Chamberlain CSIRO Energy Transformed Flagship Regg Benito CSIRO Griff Rose CVC REEF Eric Hu Deakin University Kumar Thambar Department of Mines and Energy, QLD Elizabeth Cryer Department of Primary Industries, VIC Mark Hull Department of Primary Industries, VIC Michael Butler Department of Primary Industries, VIC Rohan Tepper Department of Resources, Energy and Tourism (Federal) Trevor Apolloni Department of Resources, Energy and Tourism (Federal) Paul Butler Department of State and Regional Development, NSW Michael Lord Department of Sustainability and Environment, VIC Ralph Griffiths Energy Supply Association of Australia Yvan Guerra Epuron Pty Ltd Stuart McCreery Evans & Peck Pty Ltd Ralph Griffiths Energy Supply Association of Australia John Titchen Hydro Tasmania Tony Vassallo Invenergy Pty Ltd Steve Hollis Lloyd Energy Systems Pty Ltd Col Duck Macquarie Generation (Lidell Power Station) Lindsay Smith Macquarie Generation (Lidell Power Station) Johan Dreyer New Energy Partners Pty Ltd Trevor Horman NT Power and Water Authority Michelle Cannane NSW Department of Environment and Climate Change Belinda Brown NSW Office for Science and Medical Research Nathan Rudder NSW Office for Science and Medical Research David Hemming NSW Department of Water and Energy



Mal Williams NSW Department of Water and Energy Trevor Horman Power and Water Corporation Peter le Lievre Solar Heat and Power Pty Ltd Graham Morrison Solar Heat and Power Pty Ltd Bob Matthews Solar Heat and Power Pty Ltd Dave Holland Solar Systems Pty Ltd Trevor Gleeson Stanwell Corporation David Holder Sustainability Victoria Mark Collette TRUenergy (CLP Power Asia) Adrian Chegwidden Verve Energy Evan Gray WA Office of Energy Artur Zawadski Wizard Power Pty Ltd David Mofflin WorleyParsons Scott George Private Citizen

International

Person Organisation Country Steve Szewczuk Council for Scientific and Industrial Research South Africa Robert Pitz-Paal DLR Institute of Technical Thermodynamics Germany Nigel Hall European Investment Bank Luxembourg Robert Pitz-Paal German Aerospace Centre Germany Tim Richards GE Power USA Cédric Philibert International Energy Agency / OECD France Tom Mancini International Energy Agency - SolarPACES USA John Nimmons John Nimmons & Associates Inc USA David Kearney Kearney & Associates USA Rolf Bernhard MAN Solar Millenium GmbH Germany Fred Morse Morse Associates, Inc USA John Loughhead UK Energy Research Centre England Ulrich Langnickel VGB PowerTech e.V. Germany Kelly Beninga WorleyParsons Group USA

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