Modelling of the Clean Energy Finance Corporation

Australian Solar Council and WWF- Australia Modelling of the Clean Energy Finance Corporation Potential Impacts on Renewable Energy in Australia

Potential Impacts on Renewable Energy in Australia Prepared for Australian Solar Council and WWF-Australia Prepared by AECOM Australia Pty Ltd Level 21, 420 George Street, Sydney NSW 2000, PO Box Q410, QVB Post Office NSW 1230, Australia T +61 2 8934 0000 F +61 2 8934 0001 www.aecom.com ABN 20 093 846 925 In association with ROAM Consulting 60275617 AECOM in Australia and New Zealand is certified to the latest version of ISO9001 and ISO14001. AECOM has prepared this document for the sole use of the Client and for a specific purpose, each as expressly stated in the document. No other party should rely on this document without the prior written consent of AECOM. AECOM undertakes no duty, nor accepts any responsibility, to any third party who may rely upon or use this document. This document has been prepared based on the Client s description of its requirements and AECOM s experience, having regard to assumptions that AECOM can reasonably be expected to make in accordance with sound professional principles. AECOM may also have relied upon information provided by the Client and other third parties to prepare this document, some of which may not have been verified. Subject to the above conditions, this document may be transmitted, reproduced or disseminated only in its entirety.aecom has prepared this document for the sole use of the Client and for a specific purpose, each as expressly stated in the document. No other party should rely on this document without the prior written consent of AECOM. AECOM undertakes no duty, nor accepts any responsibility, to any third party who may rely upon or use this document. This document has been prepared based on the Client s description of its requirements and AECOM s experience, having regard to assumptions that AECOM can reasonably be expected to make in accordance with sound professional principles. AECOM may also have relied upon information provided by the Client and other third parties to prepare this document, some of which may not have been verified. Subject to the above conditions, this document may be transmitted, reproduced or disseminated only in its entirety.aecom has prepared this document for the sole use of the Client and for a specific purpose, each as expressly stated in the document. No other party should rely on this document without the prior written consent of AECOM. AECOM undertakes no duty, nor accepts any responsibility, to any third party who may rely upon or use this document. This document has been prepared based on the Client s description of its requirements and AECOM s experience, having regard to assumptions that AECOM can reasonably be expected to make in accordance with sound professional principles. AECOM may also have relied upon information provided by the Client and other third parties to prepare this document, some of which may not have been verified. Subject to the above conditions, this document may be transmitted, reproduced or disseminated only in its entirety Disclaimer Forecasting is not a precise science. It relies on complex sets of data inputs and assumptions, and in a large and rapidly developing market such as renewables, there are inevitably uncertainties about future installations and capacity. Projections are only a prediction of what might happen in the future and may not be achieved. Every reasonable effort has been made to ensure that the data contained in this document are accurate as of the date of this study; however factors exist that are outside the control of AECOM and that may affect the estimates and projections noted herein. This document is based on estimates, assumptions and other information developed by AECOM from its independent research effort, general knowledge of the industry, and information from published sources. No responsibility is assumed for inaccuracies in any data source used in preparing or presenting this document. This document may include forward-looking statements. These statements related to AECOM s expectations, beliefs, intentions or strategies regarding the future. These statements may be identified by the use of words like anticipate, expect, estimate, likely, project and similar expressions. The forward-looking statements reflect AECOM s views and assumptions with respect to future events as of the date of this report and are subject to future economic conditions, and other risks and uncertainties. Actual and future results and trends could differ materially from those set forth in such statements due to various factors. These factors are beyond AECOM s ability to control or predict. This report does not necessarily represent the views of the Australian Solar Council and WWF-Australia.

Quality Information Document Ref 60275617 Date Prepared by Reviewed by Dr Jenny Riesz Craig Chambers (GM Power Generation), Ken Spicer (Technical Director) Revision History Revision Revision Date Details Name/Position Authorised Signature 1 26-Oct-2012 Draft 2 31-Oct-2012 Draft 3 2-Nov-2012 Final 4 5-Nov-2012 Final Dr David Adams Director, Energy Advisory Dr David Adams Director, Energy Advisory Dr David Adams Director, Energy Advisory Dr David Adams Director, Energy Advisory

Table of Contents Executive Briefing i Executive Summary i 1.0 Abbreviations 1 2.0 Introduction 1 3.0 Scope 3 4.0 Approach 4 4.1 Overview 4 4.2 Calculating NPVs 4 4.2.1 Cost assumptions 5 4.2.2 Revenue assumptions 5 4.2.3 Technology eligibility for CEFC financing 6 4.2.4 Funding available 7 4.2.5 Allocation of funding 7 4.2.6 Capacity installed under CEFC 7 4.2.7 Total renewable capacity installed 7 4.3 Electricity prices 8 4.3.1 Wholesale electricity prices 8 4.3.2 Retail prices 8 5.0 Impacts on renewable energy capacity 8 5.1 Impact of the CEFC on technology viability dates 8 5.2 Renewable generation financed by the CEFC 9 5.3 Funding available for investment 11 5.4 Solar boost retrofit 12 5.5 Enabling technologies 12 6.0 Scenario outcomes 12 6.1 No CEFC scenario 12 6.2 CEFC as proposed scenario 14 6.3 CEFC additional to LRET scenario 16 6.4 Scenario comparison 17 6.5 Employment 19 7.0 Impacts on electricity prices 21 7.1 Wholesale electricity prices 21 7.2 Retail electricity prices 22 8.0 Considerations for CEFC additionality to the LRET 23 8.1.1 Retailer uncertainty 23 8.1.2 Retailer incentives 23 8.1.3 Implications beyond 2020 23 9.0 Conclusions 24

i Executive Briefing The Australian Solar Council and WWF-Australia commissioned AECOM to model the potential impacts of the Clean Energy Finance Corporation (CEFC) on renewable energy deployment in Australia. This was achieved by assessing a range of renewable technologies against the eligibility criteria recommended by the CEFC expert review 1, which are: 1. Projects must be principally located in Australia 2. Projects must have a track record of technical performance 3. Projects must have financial barriers that inhibit the transaction 4. Projects must demonstrate a positive return and capacity to repay capital Technology costs were sourced from the Australian Energy Technology Assessment 2 (AETA) released by the Bureau of Resources and Energy Economics (BREE) in July 2012. Costs for solar thermal technologies were provided by the Australian Solar Council based upon an Australian Solar Institute report by IT Power 3. In the first decade (prior to 2020) CEFC financing is anticipated to focus on solar photovoltaic technologies. Embedded commercial scale photovoltaics are a likely candidate for early investment, transitioning into investment in non-tracking and single-axis tracking large-scale photovoltaic installations. By 2020, it is found that the CEFC could have supported investment in almost 3,000 MW of new solar capacity (above and beyond investment in the scenario modelled without the CEFC). The exact quantity is likely to be driven by technical limitations on the amount of capacity that can be rapidly installed (with the CEFC investing up to these technical limits). The impact of the CEFC is likely to be even greater in the period beyond 2020. During this second decade, a wide range of technologies reduce in cost to the point where they can earn a positive return (with concessional CEFC financing) and therefore become eligible for CEFC support. The CEFC is likely to continue to invest in photovoltaic technologies during the early part of the decade, and add dual axis tracking photovoltaics to the mixture. Solar thermal technologies are also added to the investment portfolio, along with solar boost retrofits at existing coal-fired power stations (provided the carbon price is sufficient). Hot sedimentary aquifer geothermal plant is also projected to be a candidate for investment from the point where it can demonstrate a track record of performance. Over this second decade (2020 to 2030) it is estimated that the CEFC could directly finance almost 4,000 MW of solar plant, and almost 200 MW of geothermal plant. Furthermore, there is likely to be ongoing market investment in solar photovoltaic technologies supported by the CEFC during the first decade (but no longer eligible for CEFC financing, since they can earn a positive return at normal market rates). This increases the projected total capacity of solar technologies installed to more than 11,000 MW by 2030, significantly larger than the 1,800 MW of solar capacity projected to be installed by 2030 in the absence of the CEFC. These results suggest that the success of the CEFC should be judged over the long term. Short term analysis of CEFC investment will tend to underestimate the long term potential for the CEFC to have significant impact beyond 2020, when a larger range of renewable technologies are closer to economic competitiveness. The impacts of CEFC additionality to the LRET were explored. It was found that if the LRET target is not adjusted to account for energy from CEFC financed projects, strong CEFC investment in solar technologies could produce the counter-intuitive result of crowding out wind deployment in the period prior to 2020 (compared with a scenario featuring only the LRET). This could be addressed by increasing the LRET target to make CEFC financed projects additional to the LRET in the period prior to 2020 making the CEFC additional to the LRET could serve to increase wind deployment by almost 4,000 MW by 2030, whilst minimally affecting costs to consumers. Even with CEFC additionality increasing LRET liability, the contribution of LGCs to retail tariffs is projected to remain below 1c/kWh in 2020 and 2030. In conclusion, this analysis suggests that the CEFC has the potential to significantly increase the deployment of a diverse range of renewable technologies in Australia. The CEFC is likely to prove especially important in increasing deployment of solar technologies over the next two decades. 1 Clean Energy Finance Corporation Expert Review Report to Government, March 2012. 2 Australian Energy Technology Assessment, Bureau of Resources and Energy Economics, July 2012. 3 Realising the Potential of Concentrating Solar Power in Australia, Report by IT Power, commissioned by the Australian Solar Institute (ASI), May 2012.

i Executive Summary The Australian Solar Council and WWF-Australia commissioned AECOM to model the potential impacts of the Clean Energy Finance Corporation (CEFC) on renewable energy deployment in Australia. Overview of the CEFC The Australian Government announced their intention to establish the Clean Energy Finance Corporation (CEFC) as a part of the Clean Energy Future package, intending to commence operations on 1 st July 2013. The objective of the CEFC is to: apply capital through a commercial filter to facilitate increased flows of finance into the clean energy sector thus preparing and positioning the Australian economy and industry for a cleaner energy future. The CEFC has essentially been designed as a bank which, for a given return, may take on higher risk and, for a given level of risk, due to positive externalities, may accept a lower financial return than their private sector equivalents. It will provide concessional finance to clean energy projects on a case-by-case basis, with the terms being the least generous possible whilst allowing the project to proceed 4. Co-financing with private investors is considered a prerequisite, to ensure that the CEFC will not supplant private finance. At least half of the fund ($5 billion) is reserved for renewable energy projects, or technologies that enable the deployment of renewable energy projects (such as transmission for renewable projects) 5. This study explores the impact of this half of the CEFC only; the potential impact of the remaining $5 billion (which can be spent more broadly on clean energy technologies such as energy efficiency) has not been investigated in this analysis. In order to be eligible for financing under the CEFC, the expert review recommended that projects should meet each of the following criteria 6 : 1. Be principally located in Australia 2. Have a track record of technical performance 3. Have financial barriers that inhibit the transaction 4. Demonstrate a positive return and capacity to repay capital Methodology For this analysis, potential renewable technologies have been considered against each of the eligibility criteria recommended by the expert review to determine when they are likely to be eligible for CEFC financing. The technologies assessed to be eligible in each year have shared the CEFC funds available, assuming a preference for investment diversity, and weighted by the respective learning rates of each technology (in recognition of the greater learning potential from investment in certain technologies) 7. Technology specific caps have also been applied to limit investment to within technically feasible limits. To assess technologies against the eligibility criteria of financial barriers and an ability to make a positive return, net present values (NPVs) were calculated for each technology installed in each year. Two possible pre-tax real WACCs 8 were applied: 10% as representative of a typical market rate, and 6.6% with concessional CEFC financing. In order to be eligible, technologies needed to exhibit a negative NPV at the typical market rate (to demonstrate financial barriers), but a positive NPV with the concessional CEFC rate (to demonstrate the ability to make a positive return). Technologies could also be manually flagged as exhibiting financial barriers where this was considered appropriate, recognising that other types of financial barriers may exist (such as investor unfamiliarity). 4 Clean Energy Finance Corporation Expert Review Report to Government, March 2012. 5 This funding is assumed to be re-invested as it is repaid to the CEFC, and thus provides ongoing support to the industry. 6 Clean Energy Finance Corporation Expert Review Report to Government, March 2012. 7 Learning rates were sourced from: J. Hayward, P. Graham, P. Campbell, Projections of the future costs of electricity generation technologies - An application of CSIRO s Global and Local Learning Model (GALLM), February 2011. 8 Weighted Average Cost of Capital

ii To calculate NPVs, technology costs were sourced from the Australian Energy Technology Assessment 9 (AETA) study released by the Bureau of Resources and Energy Economics (BREE) in July 2012. Costs for solar thermal technologies were provided by the Australian Solar Council based upon an Australian Solar Institute report by IT Power 10. Revenues were based upon a wholesale electricity price forecast by ROAM Consulting, with volume weighting depending upon the technology. Results CEFC investment This analysis leads to the capacity of renewable generation directly financed by the CEFC over the total study period (present to 2030) illustrated in Figure 1. Solar technologies (both photovoltaic and thermal) are strongly represented. Solar photovoltaics are invested in heavily in the first decade, as the main technologies assessed to be eligible for CEFC financing during this period. Solar thermal technologies (including solar boost retrofits at existing coal-fired power stations) and geothermal become eligible later during the study, diversifying the investment mixture over the second decade. It is possible that ARENA could act to bring forward the date of eligibility of technologies, allowing a wider range of technologies to be financed by the CEFC in the first decade. Figure 1 - Capacity of renewable generation directly financed by the CEFC over the total study period (present to 2030) Applied to CEFC as proposed and CEFC additional to LRET scenarios (with differing additionality requirements). A number of technologies considered were assessed to be unlikely to achieve eligibility for financing under the CEFC for a range of reasons. Well established technologies such as on-shore wind, landfill gas, sugar cane waste and other biomass projects did not demonstrate financial barriers (in terms of the limited definition applied in this study). Off-shore wind, wave/ocean and enhanced geothermal systems did not achieve a positive return within the study timeframe, even at the concessional CEFC financing rate. Hybrid technologies were considered ineligible unless they featured a majority renewable component 11, and data for this type of plant was not available from the AETA data set (the hybrid technologies examined in that study featured only a small component of renewable energy). 9 Australian Energy Technology Assessment, Bureau of Resources and Energy Economics, July 2012. 10 Realising the Potential of Concentrating Solar Power in Australia, Report by IT Power, commissioned by the Australian Solar Institute (ASI), May 2012. 11 Clean Energy Finance Corporation Expert Review Report to Government, March 2012.

iii Results Scenario outcomes Three possible scenarios for future development of renewable energy in Australia were explored. These scenarios have been used for the purpose of analysis only and should not be taken as recommendations. No CEFC The CEFC was not implemented, and the LRET remains unchanged from the present 41,000 GWh by 2020 target. Renewable development proceeds according to a core development schedule based upon the technology mix in announced projects sufficient to meet the LRET, and expected technology economic viability in the absence of the CEFC. Since announced renewable projects at present are overwhelmingly wind generation, wind dominates the new technology mix until post 2020. CEFC as proposed The CEFC is implemented as proposed in the current legislation, and the LRET remains unchanged from the present 41,000 GWh by 2020 target. CEFC financed projects are assumed to be eligible to create LGCs under the LRET, and compete with other renewable sources to meet the 41,000 GWh by 2020 target. Projects financed by the CEFC were added to those in the No CEFC scenario, and an equivalent MWh of wind projects were displaced (removed) in the years 2015 to 2019, ensuring that the cumulative number of LGCs available always equalled or exceeded the cumulative target. CEFC additional to LRET The CEFC is implemented as proposed in the current legislation, and the LRET is adjusted such that any projects financed under the CEFC are additional to the 41,000 GWh by 2020 target. This would be achieved by increasing the LRET target to account for the energy production anticipated from CEFC financed projects. In this scenario, projects financed by the CEFC were added to those in the No CEFC scenario. The outcomes for each of these scenarios are illustrated in Figure 2. In these charts, the columns show amounts of generation, the dashed line shows LRET target and the solid line shows LRET target plus Greenpower 12. Figure 2 - Renewable energy produced in each scenario a) No CEFC 12 Greenpower sales projection was sourced from AEMO: National Transmission Network Development Plan (NTNDP) Consultation 2012, Planning Studies Input Tables.

iv b) CEFC as proposed c) CEFC additional to LRET These results suggest that making the CEFC additional to the LRET could ensure that the CEFC can invest heavily in solar (and other) technologies, without crowding out wind projects. This effect is likely to be most significant in the period prior to 2020 (when the LRET target is increasing), and could be addressed by increasing the LRET target by the amount of energy projected to be produced by projects financed by the CEFC in the period prior to 2020. ARENA may act to reduce technology costs more rapidly than assumed in this analysis, which could result in the CEFC achieving a larger and earlier increase in renewable deployment. ARENA has been represented in this analysis in a limited way via the inclusion of small geothermal and solar thermal pilot projects in all scenarios, but

v the anticipated investment under ARENA has not been modelled in detail. If a significant number of projects receive support by the CEFC and ARENA simultaneously, then there may be additional CEFC investment in projects that have not been anticipated by this analysis. In summary, this analysis suggests that the CEFC has the potential to significantly increase the deployment of a diverse range of renewable technologies in Australia. The CEFC is likely to prove especially important in increasing deployment of solar technologies over the next two decades. Uncertainty It is emphasised that the impacts of the CEFC will depend upon case-by-case decision making based upon underlying principles that are only broadly defined at present. The CEFC has been deliberately designed to allow significant flexibility in investment decisions, which makes projection of outcomes challenging. Furthermore, this study provides only one possible projection of outcomes under the CEFC (under each of the policy settings scenarios explored), and relies upon a wide range of input assumptions. There is large uncertainty over factors such as projected technology costs and carbon costs, and only one possible trajectory for these input assumptions has been considered. Every attempt has been made to apply a robust methodology and utilise widely agreed and referenced input assumptions, but we caution readers about the high degree of uncertainty inherent in any analysis of this nature. Readers must not make investment decisions based upon the analysis contained in this report.

1 1.0 Abbreviations AEMO AETA ARENA BREE CCGT CEC CEFC EGS EU EWEA FiT FTE HSA IMO WA LGC LRET NEM NPV PPA PV RET RRP SRES STC SWIS WACC Australian Energy Market Operator Australian Energy Technology Assessment Australian Renewable Energy Agency Bureau of Resources and Energy Economics Combined Cycle Gas Turbine Clean Energy Council Clean Energy Finance Corporation Enhanced Geothermal System European Union European Wind Energy Association Feed-in Tariff Full time equivalent (employment) Hot Sedimentary Aquifer (Geothermal) Independent Market Operator of Western Australia Large-scale Generation Certificate Large-scale Renewable Energy Target National Electricity Market Net Present Value Power Purchase Agreement Photovoltaic Renewable Energy Target Renewable Power Percentage Small-scale Renewable Energy Scheme Small-scale Technology Certificate South-West Interconnected System Weighted Average Cost of Capital 2.0 Introduction The intention to establish the Clean Energy Finance Corporation (CEFC) was announced by the Australian Government as a part of the Clean Energy Future Package. An Expert Review Panel was formed, and delivered its recommendations on broad principles to the Government on 28 March 2012 13. The Government accepted all recommendations in that report, and developed the Clean Energy Finance Corporation Bill 2012, which passed into legislation on 25 June 2012. The CEFC will commence its investment operations from 1 July 2013. The objective of the CEFC is to: 13 Clean Energy Finance Corporation Expert Review, Report to Government, March 2012.

2 apply capital through a commercial filter to facilitate increased flows of finance into the clean energy sector thus preparing and positioning the Australian economy and industry for a cleaner energy future. The CEFC has essentially been designed as a bank which, for a given return, may take on higher risk and, for a given level of risk, due to positive externalities, may accept a lower financial return than their private sector equivalents. It will provide concessional finance to clean energy projects on a case-by-case basis, with the terms being the least generous possible whilst allowing the project to proceed 14. Co-financing with private investors is considered a prerequisite, to ensure that the CEFC will not supplant private finance. The primary focus is seen to be in de-risking the capital structure of projects so that private finance can be secured, by, for example, being subordinate in the event of default to capital from private investors. At least half of the fund ($5 billion) is reserved for renewable energy projects, or manufacturing projects that produce later stage inputs for their construction. Enabling technologies are also eligible, which could include infrastructure such as transmission lines and new and upgraded interconnectors which assist the deployment of renewable energy projects. The remaining half (up to $5 billion) may also be spent on low emissions technologies (defined as having an emissions intensity of 50% or less than the grid) and energy efficiency projects (or manufacturing businesses that contribute later stage inputs to these). In order to be eligible for financing under the CEFC, projects must: Be principally located in Australia Have financial barriers that inhibit the transaction Have a track record of technical performance Demonstrate a positive return and capacity to repay capital The fund as a whole will be expected to provide a return on its portfolio of investments in line with the government bond rate (around 3%). This is significantly lower than the average return on equity for Australia s largest banks of around 15%, which provides the CEFC with the ability to provide highly attractive concessional rates compared to commercial lenders. Importantly, the CEFC will consider the potential for positive externalities in their assessment of projects. These are positive impacts where the proponent may not receive a return, but the market as a whole will benefit. In particular, effects where subsequent projects will see an improvement in viability due to the delivery of earlier projects are identified. These could include: Reduction in technology costs, as the technology progresses along the innovation chain and moves down the cost curve Improvements in technology design, construction and operating skills and financing structures Learning in the finance sector, particularly via the opportunity to co-invest with the CEFC to improve the transparency of investment opportunities and provide confidence to investors to deepen their own expertise in clean energy markets The CEFC is intended to work alongside the carbon price, the Large-scale Renewable Energy Target (LRET) and the Australian Renewable Energy Agency (ARENA) as illustrated in Figure 3 to drive significant renewable energy and clean energy investment and innovation. 14 Clean Energy Finance Corporation Expert Review Report to Government, March 2012.

3 Figure 3 - Interaction of ARENA, CEFC and LRET ARENA Supporting earlystage innovation and assisting immature technologies to achieve a track record of performance CEFC Supporting market entry for emerging technologies with a track record of performance RET Driving commercial deployment of the most mature and lowest cost renewable technologies Increasing renewable technology maturity and deployment 3.0 Scope The Australian Solar Council and WWF-Australia commissioned AECOM to model the potential impacts of the CEFC on renewable energy deployment in Australia, and specifically the interaction of the CEFC with the LRET and carbon pricing schemes. It is emphasised that the outcomes of any analysis of this nature are inherently uncertain, since the impacts of the CEFC will depend upon case-by-case decision making based upon underlying principles that are only broadly defined at present. However, this high level analysis attempts to provide an indication of potential impacts, based upon the best available projections of technology costs, carbon prices and other influencing factors. Three scenarios have been explored. These scenarios have been used for the purpose of analysis only, and should not be taken as recommendations. 1. No CEFC The CEFC is not implemented. The LRET remains as legislated. 2. CEFC as proposed The CEFC is implemented in conjunction with the LRET, with parameters for both as detailed in the existing legislation. 3. CEFC additional to LRET The CEFC is implemented, with any CEFC financed projects being additional to the LRET. This means that Large-scale Generation Certificates (LGCs) created by any projects financed by the CEFC are absorbed by an increase of the existing LRET target 15. The following factors have been projected for each scenario in 2020 and 2030: The total installed capacity of renewable energy (GW) The annual amount of energy delivered by renewable energy (GWh) The renewable technology mix (breakdown of GW and GWh by renewable technology) Total investment in renewable energy Wholesale prices Retail prices Estimated total number of jobs in renewable energy (including construction and ongoing maintenance phases), by region. ARENA has been represented in this analysis in a limited way via the inclusion of small geothermal and solar thermal pilot projects in all scenarios, but has not been modelled in detail. These pilot projects are assumed to enter the market due to the receipt of additional revenue supplied by ARENA. ARENA may also act to reduce technology costs more rapidly than assumed in this analysis, although these impacts are likely to primarily apply 15 Additionality is not an issue for the Small-Scale Renewable Energy Scheme (SRES) since this scheme does not involve a target, but rather provides provision for the annual Renewable Power Percentage to be adjusted according to the number of certificates created. Therefore only the large-scale component of the Renewable Energy Target would be affected.

4 beyond the study timeframe. However, if a significant number of projects receive support by the CEFC and ARENA simultaneously, then there may be additional CEFC investment in projects that have not been anticipated by this analysis. It is emphasised that this study provides one possible projection of outcomes under the CEFC (under each of the policy settings scenarios considered), and relies upon a wide range of uncertain input assumptions. The CEFC has been designed to allow significant flexibility in investment decisions, which makes projection of outcomes challenging. There is also large uncertainty over factors such as projected technology costs and carbon costs, and only one possible trajectory for these input assumptions has been considered. Every attempt has been made to apply a robust methodology and utilise widely agreed and referenced input assumptions, but we caution readers about the high degree of uncertainty inherent in any analysis of this nature. Readers must not make investment decisions based on the analysis contained in this report. All dollar values quoted in this report are in real 2012 Australian dollars, unless otherwise stated. 4.0 Approach 4.1 Overview To determine the likely impact of the CEFC, the following methodology was applied: 1. Calculate the net present value (NPV) of each technology installed in each year of the study (2012 to 2030). 2. Determine the subset of technologies likely to meet all of the CEFC eligibility criteria in each year (including analysis of NPV outcomes from step 1). 3. Calculate total funding available for investment by CEFC in each year. 4. Allocate available funding amongst eligible technologies, weighted by technology learning rates (with the largest proportion of funding allocated to technologies with the highest learning rates, in recognition of positive externalities). 5. Calculate capacity that can be installed under CEFC in each year based upon technology capital costs. 6. Determine total renewable energy installed in each scenario by comparison with capacity installed under the LRET in the absence of the CEFC. 7. Use renewable capacities installed in each scenario as an input to ROAM s electricity market price model, to calculate wholesale electricity prices in 2020 and 2030. Each of these steps is described in more detail below. 4.2 Calculating NPVs NPVs were calculated for each renewable technology installed in each year from 2012 to 2030 under two conditions for deciding whether the technology would be commissioned: 1. Without CEFC concessional financing A pre-tax real Weighted Average Cost of Capital (WACC) of 10% was applied. This was sourced from the AETA study to represent a typical project WACC in the absence of the CEFC. 2. With CEFC concessional financing A pre-tax real WACC of 6.6% was applied. This was based upon an assumption of 60% debt, 40% equity, with the CEFC providing half of the project finance (and the remaining half being sourced at typical commercial financing rates). CEFC debt was assumed to be provided at a real rate of 3%. The assumption of a 1:1 funding ratio is likely to be relatively conservative; other similar funds (such as Low Carbon Australia) have achieved a higher proportion of private investment. If CEFC similarly achieves a higher proportion of private investment, the funds available will extend to a larger quantity of renewable investment. In all cases, a discount rate of 10% was applied to the cash flow streams to calculate the summary NPV (representative of the average market rate). Cost and revenue assumptions for each technology were as follows:

5 4.2.1 Cost assumptions The Australian Energy Technology Assessment 16 (AETA) published by the Bureau of Resources and Energy Economics (BREE) in July 2012 provided the majority of technology cost assumptions used in this analysis. All assumptions about technology capital costs over time, operating costs, fuel costs, asset lifetimes, capacity factors, construction profiles etc were sourced from the AETA report, unless otherwise stated. The central estimate for New South Wales 17 was applied for each technology; it is recognised that a substantial range around these values can apply for individual projects. Readers should be aware that this uncertainty was not included explicitly in this study. Technology costs that were drawn from sources other than the BREE AETA study include: Solar thermal technologies - Estimates of solar thermal technology costs were based upon a report by IT Power 18, upon request by the Australian Solar Council. Solar boost retrofit to existing coal-fired power stations Costs for this technology were not provided in the BREE AETA study. Instead, the capital cost quoted for the Kogan Creek solar boost project was used ($104.7 million for 44MW, or equivalently $2380/kW in 2012 19 ). This cost was reduced over time at the same rate as the other solar thermal technologies. 4.2.2 Revenue assumptions Wholesale electricity market prices forecast by ROAM 20 in a central scenario were used as the basis for project revenues, as follows: High capacity factor technologies (such as geothermal, biomass and hybrid technologies) received the average (time-weighted) wholesale electricity price in each year. Wind and solar technologies received volume weighted wholesale prices applying to typical generation profiles of those technologies. ROAM s model indicated that wind technologies receive on average 20% lower prices than the average electricity price (due to weighted operation in periods that are heavily supplied by wind generation, lowering the average price they receive), while solar technologies receive on average 10% higher prices than the average electricity price (due to weighted operation in peak periods). No distinction was made between the revenues earned by solar photovoltaics and solar thermal projects with varying quantities of storage; all were assumed to earn the solar volume weighted price. It is recognised that solar thermal projects (particularly those with storage) will generally be able to achieve higher average prices by capturing a larger proportion of peak periods; this effect could be captured in a later round of more detailed modelling. However, solar thermal projects with higher levels of storage were assumed to earn higher revenues in line with their higher capacity factors (sourced from the BREE AETA data set). Commercial embedded photovoltaic projects were assumed to earn revenues equivalent to avoided retail prices, where these were assumed to be 30% lower than average residential retail prices (in line with assumptions made in the Treasury Strong Growth, Low Pollution Future modelling). This assumes that embedded projects are capacity matched to the local load that they serve, and minimal electricity is fed back into the grid. This will be also affected by the structure of network tariffs at commercial premises, and the extent to which these can be minimised by embedded photovoltaics. This varies location to location, and has not been considered in detail in this analysis. Solar boost retrofit projects were considered to earn revenues equivalent to the costs avoided at the coal-fired power station where they were installed (being equal to avoided fuel costs, and carbon costs). 16 Australian Energy Technology Assessment, Bureau of Resources and Energy Economics, July 2012. 17 NSW was selected since this region has the highest demand and is therefore likely to be able to host the largest quantity of renewable generation without significant merit order effects. 18 Realising the Potential of Concentrating Solar Power in Australia, Report by IT Power, commissioned by the Australian Solar Institute (ASI), May 2012. 19 CS Energy, Factsheet, Kogan Creek Solar Boost Project, http://www.csenergy.com.au/userfiles/file/kogan%20creek%20solar%20boost%20fact%20sheet%20- %2029%20August%202012.pdf 20 Prices for each of the five NEM regions were averaged to provide a representative NEM-wide price.

6 The carbon price trajectory forms an important input assumption to this modelling. It is a significant driver of electricity prices over time, which directly affects the revenues of all renewable projects. It is also the main driver of the effective revenue of solar boost retrofit projects (these projects will only have a positive return when the carbon price is sufficiently high). In general, higher carbon prices will bring forward the date where renewable technologies can achieve a positive return, hastening their entry into the market. A single carbon price trajectory was used for this analysis, although it is emphasised that there remains substantial uncertainty over future carbon prices during the next two decades. The carbon price trajectory utilised for this analysis was sourced from the Treasury Strong Growth, Low Pollution Future modelling, equivalent to a -5% by 2020 emissions trajectory (from 2000 levels), as illustrated in Figure 4. Figure 4 - Assumed carbon price trajectory (Real 2012$) Source: Federal Treasury, Strong Growth, Low Pollution, Modelling a carbon price, 2011. CEFC projects were assumed to be eligible to create LGCs, and in the period prior to 2020 were assumed to seek power purchase agreements (PPAs) with retailers. Prior to 2020, renewable technologies were assumed to obtain a PPA for the life of the asset (30 years). Since on-shore wind remains the lowest cost renewable technology over the period of the study, it was assumed to continue to set the PPA price which retailers are willing to commit to, with the addition of the difference between the average wholesale price earned by wind and that technology (this creates an equivalent effective LGC price ). PPA prices were determined to be the higher of either the flat price that would need to be earned by a wind farm installed in that year to meet its long run marginal costs, or the flat price that produced an equivalent revenue stream (in net present value terms) to the wholesale revenue stream that would be earned by the wind farm over its lifetime (net of LGCs). Other technologies were assumed to receive the same PPA price, plus the difference between average wind farm wholesale revenues, and the wholesale revenues for that technology, in each year. 4.2.3 Technology eligibility for CEFC financing Technologies were considered eligible for CEFC financing if they met all of the following criteria: Principally located in Australia Only Australian based projects were considered. Have a track record of technical performance Technologies were only considered eligible after the first year available for construction defined in the AETA data set. Demonstrate a positive return and ability to repay capital In order to be eligible, technologies must have a positive NPV under the concessional CEFC financing rate. Financial barriers Technologies were considered to demonstrate a financial barrier that inhibited the transaction if they met either of the following conditions:

7 o o A negative NPV in the absence of concessional CEFC financing, or Having only achieved a positive NPV with concessional CEFC financing during the last five years (allowing for learning in the finance sector over a five year period). Each technology in each year was considered against all of these criteria, to produce a short list of technologies eligible for financing under the CEFC in each year. 4.2.4 Funding available The CEFC fund was modelled as an account with deposits of $1 billion in each of the first five years, and earning a return at the government bond rate (assumed to be 3% real per annum). This is an assumed portfolio-wide rate of return, and it is understood that it may differ on a project by project basis. Funds were withdrawn as they were invested in renewable projects, and principal and interest repaid were assumed to be available for reinvestment by the CEFC as they became available. It was assumed that funds can be held by the CEFC if necessary and only applied to projects as they become eligible. 4.2.5 Allocation of funding The funding available for investment in each year was allocated between all the eligible technologies in that year, weighted by their respective learning rates. Technologies with a higher learning rate received a larger proportion of available funds, due to their greater potential to produce positive externalities (in the form of reduced costs for future projects). Learning rates for each technology were sourced from the CSIRO 21. It was assumed that 10% of the funding was allocated to enabling technologies, such as transmission projects (servicing renewable generation) and manufacturing projects (manufacturing later stage renewable components). 4.2.6 Capacity installed under CEFC The capacity of renewable generation installed was calculated based upon the amount of CEFC funds allocated to each technology type, multiplied by two (to include the 50% of financing assumed to be sourced from the private sector) and then divided by the capital cost of each technology (with technology cost assumptions as outlined in section 4.2.1). The installed capacity of each technology in each year was limited by a technologyspecific cap, to ensure technical feasibility. Technology caps were set to be equal to twice the unit size in the AETA, per year. This is acknowledged to be a subjective measure of the technically feasible installation limit, and could be explored further in later analysis. 4.2.7 Total renewable capacity installed To determine the total quantity of renewable generation installed in each case, each of the three scenarios was treated as follows: No CEFC The CEFC is not implemented, and the LRET remains unchanged from the present 41,000 GWh by 2020 target. Renewable development proceeds according to a core development schedule based upon announced projects sufficient to meet the LRET, and expected technology economic viability in the absence of the CEFC. Since announced renewable projects at present are overwhelmingly wind generation, wind dominates the new technology mix until post 2020. CEFC as proposed The CEFC is implemented as proposed in the current legislation, and the LRET remains unchanged from the present 41,000 GWh by 2020 target. CEFC financed projects are assumed to be eligible to create LGCs under the LRET, and compete with other renewable sources to meet the 41,000 GWh by 2020 target. Projects financed by the CEFC were added to those in The No CEFC scenario, and an equivalent MWh of wind projects were displaced (removed) in the years 2015 to 2019, ensuring that the cumulative number of LGCs available always equalled or exceeded the cumulative target. 21 J. Hayward, P. Graham, P. Campbell, Projections of the future costs of electricity generation technologies - An application of CSIRO s Global and Local Learning Model (GALLM), February 2011.

8 CEFC additional to LRET The CEFC is implemented as proposed in the current legislation, and the LRET is adjusted such that any projects financed under the CEFC are additional to the 41,000 GWh by 2020 target. This would be achieved by increasing the LRET target to account for the energy production anticipated from CEFC financed projects. In this scenario, projects financed by the CEFC were added to those in the No CEFC scenario. 4.3 Electricity prices 4.3.1 Wholesale electricity prices ROAM s 2-4-C electricity market dispatch model of the National Electricity Market (NEM) was utilised to calculate electricity prices in each scenario. The capacities of renewable generation of each type in each scenario were used as an input to 2-4-C, with other modelling assumptions remaining constant between the scenarios. Retrofit of solar boosting to existing coal-fired plant was modelled as a reduction of emissions factors, with generator bids remaining unchanged. Energy efficiency and other technologies financed under the non-renewables half of the CEFC were not included in this analysis. This study explores the impact of the renewables half of the CEFC only. Therefore the demand profile used in all scenarios was identical, and based upon AEMO s medium projections 22. ROAM s model explicitly calculates prices for each NEM region, depending upon the generation installed in that region and the incidence of network constraints (and other factors). For this analysis these state-based prices were averaged to provide indicative NEM-wide prices. 4.3.2 Retail prices ROAM calculated retail prices in each scenario based upon: A volume weighted calculation of the wholesale price (volume weighted by demand). The annual Renewable Power Percentage (RPP) for which retailers are liable. The RPP is higher in the CEFC additional to LRET scenario due to the increase in the LRET target. Forecast LGC prices. This was based upon the anticipated supply-demand balance for certificates, the wholesale electricity price, and the marginal cost of production of renewable energy (providing an indication of Power Purchase Agreement prices). Network and retail components based upon analysis of current retail prices. Differences in network tariffs and retail components between scenarios were not considered. With a significantly larger proportion of renewable generation installed with CEFC, an increase in transmission augmentation is likely to be required. However, transmission network tariffs typically only form a small component of retail bills (less than 5%), so this effect is likely to be minimal. Distribution network tariffs (which consistently form the most significant component of retail tariffs) are likely to remain relatively unaffected by large-scale renewable deployment under the CEFC. 5.0 Impacts on renewable energy capacity 5.1 Impact of the CEFC on technology viability dates The first date under which a technology becomes economically viable with and without concessional CEFC financing is listed in Table 1. Generally, the lower cost of capital available under the CEFC acts to bring forward the date of viability by 2-5 years. These dates are based upon net present values (NPVs) calculated as per the methodology outlined in section 4.2. 22 AEMO, National Electricity Forecasting Report for the National Electricity Market (NEM), 2012.

9 Table 1 - First year when net present value (NPV) becomes positive Technology First year NPV becomes positive With CEFC Without CEFC Solar Photovoltaic (PV) - non-tracking 2014-15 2019-20 Solar photovoltaic (PV) - single axis tracking 2016-17 2022-23 Solar photovoltaic (PV) - dual axis tracking 2024-25 Not within study Embedded PV - Commercial 2012-13 2012-13 Wind (on-shore) 2012-13 2012-13 Wind (off-shore) Not within study Not within study Wave/Ocean Not within study Not within study Geothermal - hot sedimentary aquifer (HSA) 2020-21 (first year available for construction) Not within study Geothermal - enhanced geothermal system (EGS) Not within study Not within study Landfill gas power plant 2012-13 2012-13 Sugar cane waste power plant 2012-13 2012-13 Other biomass waste power plant (eg. wood) Solar thermal boost retrofit to 1.0tCO 2/MWh coal-fired power station Solar thermal boost retrofit to 1.2tCO 2/MWh coal-fired power station 2012-13 2012-13 2022-23 2025-26 2021-22 2023-24 Solar thermal with no storage 2021-22 2025-26 Solar thermal with 2hrs storage 2019-20 2023-24 Solar thermal with 5hrs storage 2019-20 2023-24 5.2 Renewable generation financed by the CEFC Applying the methodology outlined in section 4.0 leads to the capacities financed by the CEFC given in Table 2. These are also illustrated in pie charts in Figure 5 and Figure 6. Solar technologies (both photovoltaic and thermal) are strongly represented. Solar photovoltaics are invested in heavily in the first decade, since few other technologies are projected to be eligible for CEFC financing during this period (very few can achieve a positive return even with CEFC financing). In the first decade, these results suggest that the CEFC is likely to invest in solar photovoltaics up to the technically feasible annual installation limit. Solar thermal technologies (including solar boost retrofits at existing coal-fired power stations) and geothermal become eligible later during the study, diversifying the investment mixture over the second decade.

Geothermal Solar Thermal Solar Photovoltaic AECOM 10 A number of technologies considered were assessed to be unlikely to achieve eligibility for financing under the CEFC for the following reasons: Wind (on-shore), landfill gas, sugar cane waste, and other biomass These technologies were assessed to be able to achieve a positive return without CEFC financing (in the presence of the LRET), and are therefore are unlikely to demonstrate financial barriers. With rising electricity prices (in large part due to a rising carbon price) these technologies remain commercially viable beyond 2020, even in the absence of continuing LRET growth. If the carbon price were repealed such that electricity prices did not rise sufficiently, these technologies may qualify as demonstrating financial barriers beyond 2020. Wind (off-shore), wave/ocean, Enhanced Geothermal System (EGS) These technologies did not achieve a positive return within the study timeframe, even with the concessional CEFC financing rate 23. Hybrid technologies Two hybrid technologies were included in the BREE AETA data set: solar/coal hybrid and Integrated solar combined cycle (ISCS) parabolic trough with combined cycle gas. Analysis of the data provided in the AETA study indicates that the technology costs provided relate to only a small proportion of renewable energy being produced. The Clean Energy Finance Corporation Bill 2012 Explanatory Memorandum specifies that hybrid technologies must have a majority renewable component. These technologies were therefore considered likely to be ineligible for CEFC financing. Hybrid technologies with a higher proportion of renewable generation could achieve eligibility, but technology cost estimates for these were not provided in the AETA data set. Table 2 - Renewable capacity directly financed by the CEFC Technologies Renewable capacity directly financed by the CEFC 24 (MW) 2012 to 2020 2020 to 2030 Total to 2030 Solar Photovoltaic (PV) - non-tracking 1,200 440 1,640 Solar photovoltaic (PV) - single axis tracking 800 480 1,280 Solar photovoltaic (PV) - dual axis tracking - 570 570 Embedded PV - Commercial 100-100 Solar thermal with no storage - 330 330 Solar thermal with 2hrs storage 200 370 570 Solar thermal with 5hrs storage 200 290 490 Solar boost retrofit (coal intensity 1tCO2/MWh) - 830 830 Solar boost retrofit (coal intensity 1.2tCO2/MWh) - 600 600 Geothermal - hot sedimentary aquifer (HSA) - 170 170 23 As technologies at an earlier stage of maturity, they are likely to instead be eligible for funding under ARENA (the Australian Renewable Energy Agency). The impact of ARENA has been included in a limited way in this analysis via the inclusion of several small pilot projects in geothermal and solar thermal technologies in all scenarios, but has not been modelled in detail. 24 The same capacity financed by the CEFC is applied in both the CEFC as proposed and CEFC additional to LRET scenarios, but with differing assumptions on additionality.

11 Figure 5 - Capacity of renewable generation directly financed by the CEFC by decade 25 2012 to 2020 2020 to 2030 Figure 6 - Capacity of renewable generation directly financed by the CEFC over the total study period (present to 2030) 26 5.3 Funding available for investment As outlined in section 4.0, the CEFC fund was modelled as an account with deposits of $1 billion in each of the first five years, and earning a return at the government bond rate (assumed to be 3% real per annum). This is an assumed portfolio-wide rate of return, and it is understood that it may differ on a project by project basis. 25 The same capacity financed by the CEFC is applied in both the CEFC as proposed and CEFC additional to LRET scenarios, but with differing assumptions on additionality. 26 The same capacity financed by the CEFC is applied in both the CEFC as proposed and CEFC additional to LRET scenarios, but with differing assumptions on additionality.

12 Importantly, this distinguishes the CEFC from a grant scheme, because the principal and interest repaid can be re-invested in new projects, with the total amount of financing either invested or available to be invested growing continuously over time. AECOM s analysis shows that the initial $5 billion invested in renewables should grow to around $5.6 billion by 2019-20, and to around $7.6 billion by 2029-30. AECOM s modelling indicates that the full amount of funds available are invested by 2022-23, with ongoing investment continuing beyond that point based upon annual project repayments. 5.4 Solar boost retrofit A substantial proportion of the CEFC funds are projected to be invested in solar boost retrofit at existing coal-fired power stations (based upon costs announced for the Kogan Creek 44MW solar boost project, and a carbon price trajectory as projected by the Federal Treasury). A total of 1430 MW of this technology is projected to be installed by 2030. With 30,000 MW of coal-fired generation installed in Australia at present, this would equate to 5% of existing coal-fired capacity being displaced by solar pre-heating. This is less than the proportion of Kogan Creek supplied by the 44 MW solar boost project (6%), suggesting that this is likely to be technically feasible, and available at a cost not dissimilar to that for the Kogan Creek project. 5.5 Enabling technologies The CEFC guidelines allow for investment in technologies that are related to renewable energy technologies, such as enabling technologies. For this analysis, it has been assumed that 10% of the funds available under the renewable energy stream of the CEFC are invested in enabling technologies, or in businesses supplying goods or services needed to develop or commercialise renewable generation. The Australian Energy Market Operator (AEMO) estimates that transmission in Australia costs approximately $1.65 million per kilometre, for 330kV double circuit overhead transmission lines with a capacity of 1,245 MVA for each circuit 27. Applying this to the 10% of finances dedicated to enabling technologies provides an indication of the scale of finances available, as listed in Table 3. Some of this funding may be invested in other types of enabling technologies. However, this estimate suggests that if the full 10% were invested in transmission projects, up to 1190km of 330kV line could be installed by 2030, to connect renewable generation to the main grid. Table 3 - Length of transmission that could be financed by the CEFC with 10% of available funds Length of transmission line financed (km) (Assumes 330kV double circuit overhead transmission line with a capacity of 1,245 MVA for each circuit) 2012 to 2020 770 km 2020 to 2030 410 km Total to 2030 1190 km 6.0 Scenario outcomes 6.1 No CEFC scenario In the No CEFC scenario the CEFC is not implemented, and the main driver of renewable deployment in the period to 2020 remains the LRET. Renewable generation expected to enter the market in this scenario is illustrated in Figure 7. This projection is based upon the technology distribution observed in announced projects, which are heavily dominated by wind generation. Some small (pilot) geothermal, hydro and solar projects are also assumed to enter. Where these involve emerging technologies, they are assumed to be supported by ARENA 28. 27 AEMO, National Transmission Network Development Plan (NTNDP), 2011, Page 8-3. 28 ARENA has been represented in this analysis in a limited way via the inclusion of small geothermal and solar thermal pilot projects in all scenarios, but has not been modelled in detail.

13 The green bars in Figure 7 show the LGCs created from existing projects, including the large oversupply of certificates created by deemed rooftop solar in 2010. A large proportion of these certificates remain banked, and are assumed to be surrendered to assist in meeting LRET liability during the years 2019 to 2025, allowing installed projects to remain below the annual target during that period. The preference for utilising banked LGCs at a later date is for two reasons. Firstly, developers are assumed to offer attractive terms to retailers in order to develop projects as early as possible to secure an early mover advantage 29. Secondly, this pattern of renewable growth eases the rate of growth that needs to be achieved during the steepest part of the LRET trajectory. The LRET target is assumed to remain at the legislated level of 41,000 GWh in 2020. Greenpower liability has been added to the target, based upon analysis of historical Greenpower sales, and forward projection by AEMO 30. The BREE AETA data set indicates that a number of renewable technologies will become economically viable even in the absence of LRET support in the period post 2020. For this reason, wind generation is assumed to increase at a rate of 200 MW per year from 2021 onwards, large-scale photovoltaic generation is assumed to increase at a rate of 100 MW per year from 2024 onwards and solar thermal generation is assumed to increase at a rate of 100 MW per year from 2028. This is driven by decreasing technology costs (as forecast by BREE) and rising wholesale electricity prices, caused in large part by the rising carbon price. If the carbon price is lower than the Treasury projection (illustrated in Figure 4) the date of economic viability of these technologies will be later. In these charts, the columns show amounts of generation, the dashed line shows LRET target and the solid line shows LRET target plus Greenpower 31. Figure 7 - No CEFC scenario Renewable energy produced Figure 8 illustrates the cumulative LGCs created in The No CEFC scenario, compared with the cumulative LRET target (with Greenpower included). This figure illustrates that although there is an oversupply of banked LGCs at the start of the study, this reduces over time, and is exhausted by 2025. At this point, growth in wind and solar photovoltaics continues above the LRET minimum requirement, supported solely by the higher electricity prices. 29 An early mover advantage arises under the LRET scheme since projects installed earlier receive LGC support for a longer period before the scheme ends in 2030. There remains uncertainty over whether the carbon price will be sufficient to support renewable projects in the absence of the LRET post 2030. 30 National Transmission Network Development Plan (NTNDP) Consultation 2012, Planning Studies Input Tables. 31 GreenPower allows voluntary purchase of renewable certificates. Greenpower sales projection was sourced from AEMO: National Transmission Network Development Plan (NTNDP) Consultation 2012, Planning Studies Input Tables.

14 Figure 8 No CEFC scenario Cumulative LGCs created compared with target 6.2 CEFC as proposed scenario Figure 9 illustrates the projected energy from renewable sources in the CEFC as proposed scenario, with the CEFC as proposed in the current legislation. In this scenario, the additional renewable projects financed by the CEFC (as listed in Table 2) enter the market, creating LGCs. This crowds out wind generation which otherwise would have entered in the years 2015 to 2019, since CEFC financed projects contribute to meeting the LRET. Thus, counter-intuitively, the support of the CEFC results in less wind generation entering the market (at least in the period prior to 2020), and the LRET being met with a higher cost mixture of renewable generation. Technologies that receive financing under the CEFC are assumed to remain eligible for a minimum of five years, or until the technology can achieve a positive return without CEFC concessional financing. When a technology ceases to be eligible for CEFC financing, it is assumed that market investment in the technology continues. The carbon price is assumed to favour the entry of renewable technologies, increasing their competitiveness compared with existing coal-fired plant. This creates significant growth in solar technologies (in particular) beyond 2025. Thus, the CEFC is likely to increase renewable deployment in Australia over the longer term. The entry of significant quantities of renewable generation is expected to depress wholesale electricity prices (the so called merit order effect ). This effect is not unique to renewable technologies, and is simply associated with an oversupply of generation. Over time, low prices can be expected to drive the retirement of the most emissions intensive coal-fired generation (also facing high costs due to the rising carbon price). This retirement will then act to increase electricity prices to their earlier levels, thus restoring the market equilibrium. Forecast electricity prices in each scenario are discussed in more detail section 4.3. This preliminary high level analysis has not iteratively included the effect of these market price interactions; this is recommended for later study.

15 Figure 9 - CEFC as proposed scenario Renewable energy produced Figure 10 shows the cumulative LGC balance, showing that no shortfalls occur in any year (the cumulative creation of LGCs always exceeds the cumulative target). Some additional renewable generation enters post 2020 (as in the No CEFC scenario) when wind and solar become economically viable without LRET support. Figure 10 - CEFC as proposed scenario Cumulative LGCs created compared with target

16 6.3 CEFC additional to LRET scenario Figure 11 shows the renewable capacity installed in the CEFC additional to LRET scenario. In this scenario, the CEFC is additional to the LRET, such that the LRET target is increased to create additional demand for LGCs corresponding to the energy produced by CEFC financed projects. For ease of comparison with the previous scenarios, the target is illustrated at the original level (in black) as well as at the increased level (in dark green). In this scenario, projects that entered in the No CEFC scenario under the support of the LRET should remain relatively unaffected by the CEFC (excluding second order market price interactions). These projects are assumed to proceed identically to the No CEFC scenario, with CEFC financed projects added. This means that wind projects are not displaced by CEFC financed projects (as observed in the CEFC as proposed scenario). Figure 11 - CEFC additional to LRET scenario Renewable energy produced The cumulative LGC balance is illustrated in Figure 12, indicating that the original LRET target is exceeded.