Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub Potential Market Analysis ? Task 3 Report Bahman Joodi, Matthew Ironside, Mark Tocock, Jody Rogers, Andrew Ross, Indiana Squiers December 2024 CSIRO Energy Citation Joodi, B., Ironside, M., Tocock, M., Rogers, J., Ross, A., Squiers, I. (2024) Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub. Potential Market Analysis ? Task 3 Report. CSIRO report number EP 2024 - 6138, pp 82. CSIRO, Australia. Copyright Commonwealth Scientific and Industrial Research Organisation 2024. To the extent permitted by law, all rights are reserved and no part of this publication covered by copyright may be reproduced or copied in any form or by any means except with the written permission of CSIRO. Important disclaimer CSIRO advises that the information contained in this publication comprises general statements based on scientific research. The reader is advised and needs to be aware that such information may be incomplete or unable to be used in any specific situation. No reliance or actions must therefore be made on that information without seeking prior expert professional, scientific and technical advice. To the extent permitted by law, CSIRO (including its employees and consultants) excludes all liability to any person for any consequences, including but not limited to all losses, damages, costs, expenses and any other compensation, arising directly or indirectly from using this publication (in part or in whole) and any information or material contained in it. CSIRO is committed to providing web accessible content wherever possible. If you are having difficulties with accessing this document, please contact csiro.au/contact. Foreword Transitioning the global energy system while rapidly reducing emissions to net zero by 2050 is a vast and complex global challenge. Modelling of a range of emissions pathways and decarbonisation scenarios from the Intergovernmental Panel on Climate Change (IPCC, 2024), International Energy Agency (IEA, 2024a) and Net Zero Australia (2024) shows that to meet net zero greenhouse gas emissions targets by 2050, a wide range of emissions reduction technologies will be required to decarbonise existing and future industries globally (IPCC, 2023b). These organisations identify that emissions elimination from hard-to-abate and high-emissions industries will require the use of carbon capture and storage (CCS) alongside other abatement strategies, such as electrification, underpinned by power generation from renewable energy sources such as photovoltaics and wind. Globally, there is considerable effort to identify industrial hubs and clusters where common user infrastructure can enable rapid decarbonisation of existing industries and enable future low-emissions industrial development. Australia has an opportunity to create new low-carbon growth industries and jobs in these areas, but lacks the infrastructure, skills base and business models to realise this. The transition to net zero will have disproportionate impact on regional communities, particularly those reliant on industries in transition, but it may also create economic opportunities through a wide range of new industries and jobs suited to regional areas. The Commonwealth Scientific and Industrial Research Organisation (CSIRO) is working to identify decarbonisation and transition pathways for existing and potential future industries that may be established in the Northern Territory by developing a Low Emissions Hub concept in the Darwin region. CSIRO has established a portfolio of projects to explore and evaluate a range of approaches and technologies to quantify and achieve the required emissions reductions. This includes research into the Northern Territorys renewable energy potential, hydrogen demand, generation and storage capacity, and carbon capture utilisation and storage (CCUS) potential. CSIRO is working collaboratively with industry and governments to understand their needs, drivers and strategic directions so that our research is informed and relevant. This includes establishing appropriate pathways and partnerships to understand and incorporate the perspectives of First Nations peoples. A key activity is the research into a business case project (CSIRO, 2024) (Ross et al., 2022) that aims to enhance understanding of the viability of a CCUS hub centred on the Middle Arm of Darwin Harbour. The work has three elements comprising 15 tasks: 1. analysing macroeconomic drivers, Northern Territory and regional emissions, low-emissions product markets (Ross et al., 2023), identifying key learnings from other low-emissions hubs being developed globally, and cross-sector coupling opportunities (Tasks 0?5) 2. completing CCUS hub technical definition and technical risk reduction studies, including detailed studies on the infrastructure requirements for a CCUS hub, renewable power requirements for existing and potential future industries, and road-mapping for CO2 utilisation industries that could be established to produce low or net zero products (e.g. zero-emission chemical feedstocks) (CSIRO, 2023) (Tasks 6?9) 3. creating a business case to appreciate the scale of investment required to develop a Low Emissions Hub and the economic returns from doing so. This will lead to suggested business models and routes of execution (Tasks 10?14). The CCUS business case project will involve research that is based on possible industrial development scenarios, models of future potential emissions, market demand, enabling technologies and costs. The project is intended to provide an understanding of possible future outcomes. Industry development will be determined by the investment decisions of individual industry proponents, framed by government policies and regulation, and constrained by the development trajectories of enabling technologies essential for the energy and emissions transition. On completion of this research, outcomes of the CCUS business case project will be made publicly available. The work summarised in this report comprises Task 3 of the Northern Territory CCUS business case project. It provides an assessment of the market for low-emissions energy and chemical products from major Northern Territory trading partner countries to establish an understanding of potential demand for chemicals that could be manufactured in the Northern Territory. Contents Acknowledgements viii Abbreviations ix Summary xii Demand drivers xiii Low-emissions product demand xv 1 Introduction 1 2 Carbon market price outlook 3 2.1 IPCC carbon price modelling 3 2.2 European carbon market price outlook 5 2.3 South-East Asian carbon market price outlook 6 2.4 Australian carbon credit unit price outlook 8 2.5 Australias Safeguard Mechanism 11 3 Other emissions reduction drivers 13 3.1 Powering Australia Plan 13 3.2 Future Made in Australia plan 14 3.3 Carbon border adjustment mechanisms 14 3.4 Green premium 16 3.5 Climate-related financial disclosures 16 4 Low-emissions products 18 4.1 Electricity generation 19 4.2 Iron and steel production 29 4.3 Cement production 34 4.4 Primary chemicals production 36 4.5 Aviation 38 5 Low-emissions products demand estimates 40 5.1 Electricity generation 41 5.2 Iron and steel production 43 5.3 Cement production 44 5.4 Primary chemicals production 44 5.5 Aviation 45 6 Demand estimate summary 47 References 51 Figures Figure 1: Global carbon median price outlook, C1 1.5C pathway. All prices have been inflated from 2010 to 2022 US$ (Federal Reserve Bank of St Louis, 2024) 4 Figure 2: Global carbon median price outlook, C3 2.0C pathway 5 Figure 3: European ETS price outlook 6 Figure 4: Emissions Reduction Fund auction results 9 Figure 5: ACCU voluntary market price, 2019?24 (Clean Energy Regulator, 2024b) 10 Figure 6: ACCU price outlook 10 Figure 7: Time required to bring emerging clean technologies to market 19 Figure 8: Thermal electricity generation forecast by fuel, under the NZE by 2050 scenario. (Left) Unabated coal, oil and gas electricity generation. (Right) CCUS retrofits and low-emissions fuel demand to co-fire in coal- and gas-fired electricity generation plants 20 Figure 9: System boundaries for the hydrogen value chain 21 Figure 10: Comparison of the emissions intensity of different hydrogen production routes, 2021 (production emissions only) 23 Figure 11: Price gap between hydrogen and existing fuels 24 Figure 12: Comparison of the cost for difference subsidy schemes for low-emissions hydrogen and ammonia in Japan and Republic of Korea 24 Figure 13. Levelised cost of electricity for co-firing low-emissions hydrogen in an existing natural gas electricity generation plant in Japan 25 Figure 14: Ammonia co-firing plans for selected Asia-Pacific Economic Cooperation (APEC) economies 26 Figure 15: Emissions intensities of different ammonia production routes (production emissions only) 27 Figure 16: Price gap between ammonia and existing fuels 27 Figure 17: Levelised cost of electricity after retrofitting coal-fired power plants for ammonia co-firing compared with new offshore wind in Japan 28 Figure 18: Mitigation measures for the steelmaking industry under the NZE by 2050 scenario 29 Figure 19: Age profile of global blast furnaces and direct iron reduction furnaces 30 Figure 20: US steel production capacity, by technology 31 Figure 21: Indicative levelised cost of steel production 32 Figure 22: The net-zero targets and strategic focus of selected Asian steelmakers 34 Figure 23: Emissions reductions by mitigation measure for the cement industry 35 Figure 24: Energy and emissions comparison for primary chemicals and selected other industries 36 Figure 25: Emissions reductions by mitigation measure for the primary chemicals sector 37 Figure 26: Near-zero emissions ammonia production projects 38 Figure 27: (Left) Alternative low-emissions fuels required for the aviation industry under the NZE by 2050 scenario. (Right) Consumer behavioural changes play an important role in the amount of sustainable aviation fuels required to decarbonise the aviation industry 39 Figure 28: Simplified method to estimate country-level demand for low-emissions products based on IEA models 41 Figure 29: Forecast of combined thermal electricity generation in the Northern Territorys five key trading partners by route 42 Figure 30: Forecast of combined steel production in the Northern Territorys five key trading partners. Note that Chinas steel production forecasts for the Announced Pledges scenario were not available in the published IEA reports. 43 Figure 31: Forecast of combined increases in flown passenger km in the Northern Territorys five key trading partners for different emissions reduction scenarios. Note that the forecast is not available for Sustainable Development scenario. The Stated Policies and Announced Pledges scenario forecasts are close, but not identical. 46 Figure 32: CCUS demand in the analysed sectors, compared with estimates from other sources. The dotted lines are for illustration purposes. The figure presents a summary of the estimated CCUS demand in NT main trade partner countries, from several sources. This includes: Simplified method presented above, based on IEA scenarios, noting that SDS does not include demand from Chemicals sector for IEA scenarios (STEPS, SDS, NZE), APEC models (Reference case, which reflects current policies and trends Carbon neutral case, which explores hypothetical decarbonization pathways, and Rystad (up to 2030) CCUS demand 50 Tables Table 1: Simplified projection of low-emissions product demand for Northern Territory trading partners xxi Table 2: Summary of carbon prices within South-East Asia as of 2023 (all prices shown in A$) 7 Table 3: Indicative remaining coal- and gas-fired plants worldwide 20 Table 4: Impact of steel cost on selected final products 32 Table 5: Near-zero steel market size estimates, 2030 33 Table 6: Simplified projection of low-emissions product demand in 2030 and 2050 in the electricity generation sectors of the Northern Territorys five key trading partners 42 Table 7: Simplified projection of low-emissions product demand in the steel sector of the Northern Territorys five key trading partners 44 Table 8: Simplified projection of low-emissions products demand in the cement sector of the Northern Territorys five key trading partners 44 Table 9: Simplified projection of low-emissions products demand in the chemical sector of the Northern Territorys five key trading partners 45 Table 10: Simplified projection of sustainable aviation fuels demand in the Northern Territorys five key trading partners 46 Table 11: Inclusions in estimates of low-emissions product demand 47 Table 12: Simplified projection of low-emissions product demand for the Northern Territorys five key trading partners 48 Acknowledgements CSIRO acknowledges the Traditional Owners of the land, sea and waters, of the area that we live and work on across Australia. We acknowledge their continuing connection to their culture, and we pay our respects to their Elders past and present. The authors of this report acknowledge the support and funding provided by CSIRO to undertake this work. We thank the internal CSIRO independent peer reviewers for their review of the report and valuable comments and suggestions. While this report is an output from a CSIRO-funded initiative, we thank our industry and government collaborators for their insights, contributions and suggestions, which have improved the report outcomes. Although CSIRO has sought feedback from government and industry on the technical content of the report, CSIRO has sole discretion on including such feedback. * Abbreviations Euro C Degrees Celsius ACCU Australian carbon credit unit APEC Asia-Pacific Economic Cooperation APS Announced Pledges scenario (IEA) A$ Australian dollar B Billion (1,000,000,000) BAT Battery BF Blast furnace BNEF BloombergNEF BOF Basic oxygen furnace BOH Basic open hearth CAPEX Capital expenditure CBAM Carbon border adjustment mechanism CCS Carbon capture and storage CCUS Carbon capture utilisation and storage CF Capacity factor CfD Cost for difference CNY Chinese Yan Renminbi CO2 Carbon dioxide CO2-e Carbon dioxide equivalent emission DCCEEW Department for Climate Change, Energy, Environment and Water DRI Direct iron reduction EAF Electric arc furnace ETS Emissions Trading Scheme EU European Union EV Electric vehicle GHG Greenhouse gas Gt CO2 Gigatonne Carbon Dioxide H2 Hydrogen IAM Integrated Assessment Model IDR Indonesian Rupiah IEA International Energy Agency IMP Illustrative Mitigation Pathway (IMP-REN = renewables; IMP-LD = lower energy demand; IMP-SP = sustainable development policies; IMP-GS = strengthened mitigation policies) IPCC Intergovernmental Panel on Climate Change JPY Japanese Yen kg Kilogram KRW Korean Won kWh Kilowatt hour LCOE Levelised cost of electricity LGC Large-scale generation certificates LIMES-EU Long-Term Investment Model for the Electricity Sector European Union LNG Liquefied natural gas MMBtu One million British thermal units M Million (1,000,000) Mt Millions of tonnes Mtpa Millions of tonnes per annum MW Megawatt MWh Megawatt hour NH3 Ammonia NT-LEH Northen Territory Low Emissions Hub NZE Net zero emissions OPEX Operational expenditure PEM Proton exchange membrane PJ Petajoule (1015 joules) POx Partial oxidation PRF Powering the Regions Fund PV Photovoltaic R&D Research and development SAF Sustainable aviation fuels SDS Sustainable Development scenario (IEA) SGD Singaporean Dollar SMR Steam methane reforming STC Small-scale technology certificates STEPS Stated Policies scenario (IEA) t Tonne TWh Terawatt hour (1012 watt-hours) US$ United States dollar WTO World Trade Organization Summary To support decisions around investments and regulatory structures that encourage the growth and emergence of a low-emissions economy and the transformation of hard-to-abate industries, it is critical to understand the current and future demand for low-emissions products and identify the key drivers in local and overseas markets. Low-emissions products are designed to minimise the release of greenhouse gases over their lifecycle by incorporating principles of a circular economy, energy efficiency, use of renewably sourced electricity and carbon management practices including process substitution and CCUS. Low-emissions products range from fuels such as low-emissions hydrogen and methanol, and manufactured goods based on recycling of plastics, through to building materials that incorporate captured CO2 in their manufacture. This report focuses primarily on hydrogen and hydrogen derivatives (e.g. ammonia, urea) and chemical feedstocks, since these are most relevant to opportunities for decarbonising and expanding existing industries based around liquefied natural gas (LNG) in Darwin and serving major export markets in the region. Low-emissions fuels and derivative chemical products can serve the decarbonisation needs of the largest emitting industrial sectors of the Northern Territorys five key trading partners (Japan, Republic of Korea, China, Singapore and Taiwan). Low-emissions products impact the entire lifecycle of emissions (scope 1, 2 and 3) and so reduce the need for offsets and abatements associated with maintaining business-as-usual in energy-intensive and hard-to-abate sectors. Development pathways that focus on conversion to low-emissions products therefore can achieve high levels and rates of decarbonisation for the local economy and in receiving overseas markets. Roadmaps for decarbonising hard-to-abate sectors to meet net zero emissions (NZE) by 2050 have been published by the IEA and various other bodies such as the European Commission (see references throughout). However, it is acknowledged that each jurisdiction will have its own approaches to decarbonisation of hard-to-abate sectors, tailored to its industrial mix, access to decarbonisation technologies and ease of implementation (e.g. sufficient renewable energy resources). This report explores drivers for the development of low-emissions products including carbon pricing and markets; policy levers such as tax incentives, grants and low-interest financing that support investments in enabling technologies; and direct government investment in renewable energy infrastructure. The demand drivers for the electricity generation, iron and steel, cement, primary chemicals and sustainable aviation fuels sectors are explored specifically, with a focus on the size of the demand for low-emissions products in Japan, Republic of Korea, China, Singapore and Taiwan. The size of these markets has been estimated using four different IEA scenarios. Demand drivers Carbon price and market forecasts A review of carbon prices and markets from IPCC forecasts of the carbon price required to meet global warming thresholds, the European Emissions Trading Scheme (ETS) and regional carbon markets, including the Australian carbon credit unit (ACCU) market, shows a significant range in forecast carbon prices. The forecast European Union (EU) ETS prices fall between the IPCC C1 1.5C and C3 2C scenario (see box below) median prices: US$262 (A$393) in 2030, US$756 (A$1,135) in 2050 for C1 1.5oC, and US$75 (A$112) in 2030 to US$285 (A$428) in 2050 for C3 2C. While the forecast upper-bound ACCU prices are broadly in line with the C3 2.0C scenario median prices, the Southeast Asian carbon markets, with the exception of Singapore (which more closely follows the IPCC C3 2.0C scenario), have carbon prices that are unlikely to stimulate demand for low-emissions products alone or to meet IPCC carbon price requirements. However, the development of carbon tax and emissions trading scheme legislation across the region will allow those countries to increase their emissions reduction ambition over time to drive towards their nationally determined contribution targets. IPCC scenarios The IPCC undertake a wide range of modelling to understand the different impacts of policies and mitigations on emissions and atmospheric warming, and the most recent modelling was presented in the 6th Assessment report (IPCC, 2023a). In this latest assessment the IPCC investigated emissions pathways to limit warming to 1.5C or below 2C. To do this the IPCC used integrated assessment models which draw on thousands of emissions pathways to develop 1,202 scenarios. These scenarios broadly fall into eight different categories labelled C21 to C8. A useful explainer to the models can be found at Carbon Brief (2022). An important consideration for each carbon market that has been implemented is the proportion of the economys emissions that are encompassed by that carbon market. The broader the proportion of the economy that is covered by the carbon market, the greater the opportunity to stimulate demand for low-emissions products in a range of sectors. In addition, a single carbon price allows choice in the appropriate emissions reduction technologies without distortions in markets created by technology subsidies or targets. While carbon markets and their associated pricing can, in principle, stimulate demand for low-emissions products, they are not likely, at current magnitudes, to be sufficient to displace existing technologies, which have been optimised over decades. As such, other emissions reduction drivers are being considered globally. Policy initiatives In Australia, the Federal Government has several policies targeted at reducing emissions and stimulating the development of low-emissions products and industries. These include: * the Powering Australia Plan, in which discrete funds are available through the Powering the Regions Fund (PRF) * the Safeguard Transformation Stream * the Industrial Transformation Stream * the Critical Inputs to Clean Energy Industries program * the Hydrogen Headstart program (Australian Treasury, 2024a). The majority of funding allocated to the electricity sector involves making available $20 billion in low-cost financing over four years for investments that strengthen the national electricity grid. The Future Made in Australia plan, announced in the 2024?25 Federal Budget, is a package of policies and funding designed to encourage additional private sector investment in key industries. In total, $22.6 billion has been allocated over the next decade to assist the diversification of Australias economy with a focus on producing and using renewable energy (Australian Government, 2024). Industries targeted include renewable hydrogen, green metals, critical minerals, and clean energy technology manufacturing. Each of these industries has been identified as being able to assist in the transition to net zero and/or to increase the economic resilience of the Australian economy. To prevent carbon leakage from markets (i.e. the importation of products with high embedded emissions into markets where industries are subject to carbon pricing or are required to produce products with lower embedded emissions), a number of jurisdictions have developed carbon border adjustment mechanisms (CBAMs), with the EU being the first to implement the mechanism. In April 2023 the CBAM was approved by the European Commission, with the mechanism being introduced across two periods. There is a transitional period (1 October 2023 to 31 December 2025) where importers must report relevant emissions data but are not yet financially liable in terms of purchasing and surrendering emissions allowances. A definitive period will be in effect from 1 January 2026 where importers will be required to purchase and surrender allowances and the free allocation of permits for domestic producers will be progressively phased out by 2034 (European Parliament, 2023). Several countries are also considering implementing their own CBAM, including the United Kingdom, the United States of America, Canada and Australia (a trigger is present within the Safeguard Mechanism legislation to implement a CBAM). This is in part to address their own country-specific risks of carbon leakage; however, there are revenue implications for countries that have not implemented their own carbon pricing regime. Once the CBAM is in effect, the EU will be collecting tariff revenues that can be used to enable other decarbonisation policies. There is a possibility that the European CBAM may breach World Trade Organization (WTO) trade rules (Leonelli, 2022; Zhong and Pei, 2024). While a number of countries have raised trade concerns to the World Trade Organization related to the European CBAM (including China, Japan and the Republic of Korea), as of September 2024 no country had lodged a dispute with the organisation (World Trade Organisation, 2024). The implementation of CBAM mechanisms in key consumer markets is likely to stimulate demand for low-emissions products and decarbonisation of industrial processes, especially in markets and jurisdictions that have high reliance on the export of manufactured goods. This impact will be felt in the Asia-Pacific region due to its large manufacturing sector. As part of the shift towards low-carbon economies, companies are also beginning to invest in technologies that reduce the embedded emissions of their products. Often these investments result in higher production costs that are either absorbed by the firm or passed on to consumers. The ability to pass on these costs is in part determined by a consumers willingness to pay for low-emissions products, often referred to as a green premium. Previous research has identified that consumers will pay a green premium for products such as buildings (Dwaikat and Ali, 2016), electricity (MacDonald and Eyre, 2018), organic products (Aschemann?Witzel and Zielke, 2017) and bonds (MacAskill et al., 2021). However, how the level of premium impacts on final product cost needs to be carefully considered (e.g. low-emissions steel costs as part of the overall cost of a vehicle). Changing consumer preferences reflecting stronger pro-environmental values and increasing eco-literacy may reduce the aversion to paying more for green products, assuming the products are credibly green (von Fle et al., 2023; Wei et al., 2018). Low-emissions product demand Low-emissions product demand for the electricity generation, iron and steel, cement, primary chemicals and sustainable aviation fuels sectors has been specifically explored with a focus on Japan, Republic of Korea, China, Singapore and Taiwan, the Northern Territorys five key trading partners. Electricity generation The electricity generation sector is the largest contributor to the point-source emissions of the five key trading partners. As well as enhanced energy efficiency and demand-side management, the sectors decarbonisation pathways can broadly be categorised as: 1. retiring high-emitting generation assets (particularly coal-fired thermal plants) and substituting them with new low-emissions capacity (e.g. renewable electricity generation from wind and solar) 2. reducing emissions from the existing fleet by: a. prioritising lower emitting technologies b. low-emissions fuel blending 3. retrofitting current plants to capture the emissions (CCUS) or including CCUS in new-build thermal generation plants. From a purely economic perspective, retirement of existing assets would typically occur at the end of their operational life, once asset capital depreciation has occurred or where maintenance costs rise excessively. By 2030, the majority of global coal and gas electricity generation plants will still have a useful technical life, even though in Australia almost all coal-fired power stations will have reached or be near to retirement. This problem is particularly pronounced in China and India, which have seen rapid industrialisation and urbanisation in the last few decades, with associated increases in demand for electricity. Consequently, most of the existing thermal power stations in the two largest contributors to greenhouse gas emissions in our region will still have a useful technical life out to 2040 and beyond. This makes the normal retirement schedule for the existing coal- and gas-fired plants inconsistent with the decarbonisation targets set out by the IPCC and IEA. Meeting these targets in India and China would require retirement of significant capital assets before the end of their useful technical life or prior to full capital depreciation. A further problem in achieving the decarbonisation targets in some countries in our region could be a lack of resources (e.g. land for solar or wind power), or lack of a social licence for certain technologies such as nuclear electricity generation, or additional transmission lines (National Academies of Sciences Engineering and Medicine, 2023; NSW Government, 2023). It is in this context that using substitute low-emission fuels and CCUS, although currently expensive, are included in the national decarbonisation pathways of some jurisdictions to realise the operating life of the existing assets and ensure energy security. Role of hydrogen as a low-emissions fuel When either burnt in thermal electricity generation or used in a fuel cell to produce electricity directly, hydrogen produces no carbon emissions and is therefore considered as a clean fuel that can substitute for or be blended with natural gas as part of decarbonisation efforts. Clearly, lowering the embodied carbon associated with the production of the hydrogen being used is critical for this pathway to realise net zero ambitions. The production and use of low-emissions hydrogen can attract government subsidies in several jurisdictions, based on meeting certain emissions-intensity criteria. There is no standard definition of clean or low-emissions hydrogen, but a review of the thresholds shows that they range from 0.451 to 4.92 kg CO2-e/kg hydrogen on a well-to-gate basis (International Energy Agency, 2023g). Within the region, Japan defines it as 3.4 kg CO2/kg hydrogen (New Zealand Embassy, 2023), while Chinas clean hydrogen threshold is 4.9 kg CO2/kg hydrogen on a well-to-gate basis (International Energy Agency, 2023g). This range limits hydrogen production methods to nuclear or renewable electricity via electrolysis, or CCUS-enabled natural gas or coal-based thermochemical reforming (Figure 10: Comparison of the emissions intensity of different hydrogen production routes, 2021 (production emissions only) ). China has an additional category for low-carbon hydrogen with a threshold of 14.5 kg CO2/kg hydrogen that can potentially encompass unabated natural gas-based projects using thermochemical reforming (International Energy Agency, 2023g). To bridge the gap in costs between existing fuels and low-emissions hydrogen in electricity generation, subsidies in the form of cost for difference (CfD) schemes are being introduced by the governments of Japan and Republic of Korea. These schemes pay a subsidy to mitigate the price gap between technologies. They allow for elastic price differentials and are typically implemented based on an expectation that the price gap will diminish over time as technologies and markets mature. The incentives in Japan and Republic of Korea are likely to be tested by a set of evaluation criteria and are expected to be granted for 15 years. Due to the uncertainty around production rules and available public funding, only 1% of the low-carbon hydrogen capacity announced in Japan and Republic of Korea (1.7 Mtpa in total) has reached final investment decision. Ammonia as a low-emissions fuel or hydrogen vector In addition to the use of hydrogen in electricity generation, ammonia is also considered an important energy vector, and together with broader hydrogen-based fuels it is included explicitly in the decarbonisation roadmaps and strategies of several countries (e.g. Japan, Republic of Korea and Singapore; IEA, 2023d). Its use is mainly focused on electricity generation, either in the form of co-firing in the coal-fired electricity generation plants, or using it in pure form in specially designed burners (International Energy Agency, 2021). China Energy Group has completed demonstration tests on co-firing of 35% ammonia with coal at the Yantai Power Plant in Shandong Province (Valera-Medina et al., 2023) and JERA is planning demonstration tests for co-firing 20% ammonia with coal at Unit 4 of the Hekinan Thermal Power Station in March 2024 (Jera, 2023). The latter test is in line with Japans Green Growth Strategy, which envisages 20% ammonia co-firing in coal plants by 2030, and a combination of 50% ammonia co-fired coal plants and 100% ammonia-fired plants by 2050. Countries such as Republic of Korea, Thailand and Vietnam also have similar targets (Asia Pacific Energy Research Centre, 2023). As with hydrogen use, to effectively reduce emissions and be eligible for any government rebates, ammonia needs to meet an emissions-intensity test. There is no globally accepted threshold for emissions intensity, but several jurisdictions (e.g. Japan, France, Canada) and intergovernmental organisations (e.g. EU) have proposed ranges to be considered as clean or low emissions. Japans threshold is 0.84 kg CO2/kg ammonia on a gate-to-gate basis (New Zealand Foreign Affairs & Trade, 2023). To put this into context, only ammonia produced from renewable energy-derived hydrogen, biomass or CCUS-enabled natural gas-based routes can meet this criterion. Low-emissions ammonia currently has a high cost premium over existing unabated sources of ammonia. As an example, in December 2023 the estimated price for natural gas-derived ammonia with CCS was $29/MMBtu more expensive than Japans imported thermal coal. Co-firing requires a complete restructuring of the ammonia supply chain, in terms of both the volume and carbon intensity. According to JERA, if the 20% co-combustion of ammonia were to be maintained in a single electricity generation plant throughout the year, the annual ammonia demand would be about 500,000 tonnes, which is more than 2.5 times the entire ammonia imports of Japan (Jera, 2023). JERA is planning to import around 2 Mtpa of fuel ammonia in 2030 to co-fire with coal at its electricity generation plants, which is a large portion of Japans 2030 ammonia demand target of 3 Mtpa (New Zealand Embassy, 2023). Under the NZE by 2050 scenario, global low-emissions ammonia demand is forecasted to be 450 Mt by 2035, of which 160 Mt will be used as fuel for electricity generation (International Energy Agency, 2023h). Ammonia is also considered a lower-emissions maritime fuel, with a forecasted demand under the same scenario of 90 Mt in 2035 (International Energy Agency, 2023g). Japan and Republic of Korea are expected to be two of the main demand drivers for hydrogen-based fuels by 2050, with their electricity generation, transport and industry sectors specifically planning to expand the use of these fuels. It should be noted that reducing CO2 emissions from coal-fired electricity generation plants by using low-emissions ammonia co-firing can help realise the current life of the assets and contribute to emissions reductions, but it is not an efficient method to materially reduce emissions at scale. For example, at 20% co-firing, coal plants still emit almost twice as many emissions per MWh produced as gas turbines, and at 50% it reaches parity with gas turbine emissions intensity. Aside from being combusted directly, or used in co-fired generation, ammonia is also used as a vector for hydrogen, since it is much more easily liquefied for transportation and has a higher energy density. This property and its important use in making fertilisers have stimulated greater investment in ammonia production both in Australia and other countries of the region. Iron and steel Iron and steel production currently accounts for nearly 8% of global emissions and the industry is under significant pressure to transition to lower emissions technologies and reduce the carbon intensity of its own operations and those of downstream industries. To meet the climate goals of the Paris Agreement, steel industry emissions must fall by at least 50% by 2050 (International Energy Agency, 2020), while a NZE by 2050 scenario requires the industrys emissions to be reduced by 90%, with residual emissions to be balanced by methods such as bioenergy with CCS and direct air capture of carbon dioxide with CCS (International Energy Agency, 2020). Under the Stated Policies scenario (STEPS), the global demand for steel is forecast to grow by more than one-third by 2050, while the demand growth is much more limited under its Sustainable Development scenario (SDS) and NZE by 2050 scenario (International Energy Agency, 2023h). The global blast furnace fleet is relatively young, with an average age of 13 years, compared with an expected useful life of 40+ years (IEA, 2020). Most of the youngest iron and steel plants are located in the Asia-Pacific region (IEA, 2020). As such, the demand for low-emissions products (e.g. alternative fuels or high-grade ores) in the region will be high, as these plants are typically not due for replacement for several decades. Japanese steelmakers have been refining blast furnace processes, in a bid to realise the asset life of its coal-based fleet. However, recent moves indicate potential diversification into hydrogen direct reduction, which can reduce carbon emissions by 80?90% (BloombergNEF, 2023a). Japans largest steelmaker, Nippon Steel, has completed development tests that achieved the worlds highest level of CO2 emissions reductions at 33% by injecting heated hydrogen in a month-long trial (Nippon Steel Corporation, 2024). The Republic of Koreas POSCO has also indicated its commitment to fully convert its domestic steelmaking capacity to hydrogen-based methods and is actively seeking overseas partners with the right resource mix, such as low-cost, low-carbon energy and high-quality iron ore (BloombergNEF, 2023a). China produces about half of all the world's steel and is also embarking on decarbonisation in the industry, which is responsible for nearly 15% of all CO2 emissions in that country (IEA, 2020). Aside from hydrogen direct reduction, Chinese steel companies are pursuing energy efficiency and waste heat recovery, electrification and CCUS in response to the perceived threat from CBAM and in pursuit of international markets with premium consumers, including the automotive industry. The IEA estimates a cost premium of 10?50% for low-emissions steel, while BloombergNEFs estimate of a green steel premium is about 40% compared with unabated production in 2021. The forecasted growth in the green/low-emissions steel market covers a very wide range. IEA analysis suggests a near-zero emission steel market size of US$90 billion in 2030 and US$900 billion in 2050 (International Energy Agency, 2023a). It is expected that the demand for low-emissions steel will start in industries where the cost premium for producing the steel has a small impact on the final product. These are the products where the bulk material costs comprise a relatively small share of the total production cost. As such, there has been a significant rise in supply agreements for low-emissions steel in the recent years. The demand is led by carmakers. BloombergNEF estimates that a 25% increase in the price of steel raises the production costs of motor vehicles by only 1% (BloombergNEF, 2023a). Cement Cement manufacture (specifically Portland cement made using calcined lime) increased faster than global population growth between the 1950s (when countries rapidly developed and urbanised) and the past decade (since then, production has remained static). Although there have been major energy efficiency improvements in the industry, including the use of pre-heaters to move from wet to dry kilns, the cement industrys direct emissions still account for 6.4?8.0% of total global emissions of CO2 (Bashmakov and Nilsson, 2020). The sectors emissions can be divided into energy-related emissions (one-third of the total) and process-related emissions (the remaining two-thirds, largely from calcining) (International Energy Agency, 2023a). Currently, multiple technologies are being developed to decarbonise the cement industry, including near-term efficiency improvements, CCUS, the use of clinker from non-carbonate sources to avoid calcining, supplementary/alternative cementitious materials, alternative binding materials, and fuel substitution (International Energy Agency, 2023a). CCUS is the most advanced technology and can achieve >90% emissions reduction, targeting both the emissions from fossil fuel combustion and the CO2 gas released when limestone is calcined. Alternative production technologies are also being developed to produce lower emissions cement without CCUS requirements, although producing a reliable replacement for Portland cement (used in 98% of the worlds concrete) remains a challenge. The estimated cost of capture for a commercial-scale cement CCUS plant is US$60?120 per tonne of CO2 (International Energy Agency, 2023a). The IEA estimates a 60?110% cost premium for producing low-emissions cement, but this premium is expected to have relatively small impact on some of the main final products (such as housing). While there is limited feedstock availability and demand for cement in the Northern Territory, there are opportunities to generate alternative fuels for cement manufacture, such as hydrogen. Primary chemicals The chemicals sector is the largest industrial consumer of hydrocarbons from which thousands of products are derived. However, since the hydrocarbon inputs are in the form of feedstock, rather than fuel, the sector is only the third-largest CO2 emitter (International Energy Agency, 2023a). Most of the value chains included in the chemical sector are derived from only seven primary chemicals: * ammonia * methanol * the high-value chemicals of ethylene, propylene, benzene, toluene and mixed xylenes. Production of primary chemicals accounts for two-thirds of energy consumption in the sector. The remaining third is divided across the manufacture of thousands of different products. No single decarbonisation method can deliver the decarbonisation level required under the NZE by 2050 scenario. Electrolytic hydrogen production, CCUS and direct electrification of thermally activated processes are the key technologies to align the sectors emissions with NZE (International Energy Agency, 2021). Aviation Emissions from the aviation sector are among the most difficult to avoid, due to the industrys need for energy-dense fuels (Bergero et al., 2023) and lack of practical alternatives to kerosene in jet and turboprop engines. Around 280 Mt of aviation fuel are consumed annually in the sector. Electrification of commercial aircraft is still impractical, except for very short duration flights, although hybrid engines could play a role in future aircraft designs. Sustainable aviation fuels are the most promising option to achieve the deep decarbonisation required in the aviation industry. These range from biojet kerosene (kerosene substitute produced from biomass) to synthetic kerosene produced from hydrogen and (ideally captured) CO2 via Fischer-Tropsch synthesis (see the Task 9 report, Banfield et al. (2023)). Under current regulations, these alternative fuels can be blended with conventional fuels at concentrations up to 50%. Tests are in progress to run aircraft on only sustainable aviation fuels. Sustainable aviation fuel production is expected to increase significantly in the coming years, but it is still too early to foresee impacts on global emissions from the aviation sector. In 2022 sustainable aviation fuels accounted for only 0.1% of global aviation fuel, whereas the International Air Transport Association expects this to rise fivefold by the end of 2024 (IATA, 2024). In the United States, the forecasted sustainable aviation fuel production for 2027 will be 60 times higher than 2022 levels, but this is still less than the sector targets (Advanced Motor Fuels, 2023). In 2021, the International Civil Aviation Organization forecast sustainable aviation fuel production in 2030 to be about 3?17 Mt in the low and high+ scenarios, respectively (ICAO), a rate of growth that entirely fails to keep pace with total aviation fuel demand, which is expected to reach 450 Mt by the end of this decade. Estimation of low-emissions product demand Many datasets from various providers address demand trajectories for low-emissions fuels and products. There are differences across these datasets, the origins of which cannot be conclusively ascertained. While every effort has been made to ensure that demand estimates are consistent across the project results, there will be differences based on the datasets used. For clarity, the origin of the data used is noted in each case. In this report, low-emissions product demand for the electricity generation, iron and steel, cement, primary chemicals and sustainable aviation fuels sectors has been estimated using four IEA scenarios: * Stated Policies scenario (International Energy Agency, 2023d) * Announced Pledges scenario (International Energy Agency, 2023d) * NZE by 2050 scenario (International Energy Agency, 2023d) * Sustainable Development scenario, which has been excluded in recent IEA reports (IEA, 2024b). In this analysis, the size of CCUS demand has also been estimated and this provides a comparator to the approach used to estimate CCUS demand in the Task 2 report Rogers et al. (2024a). The IEA does not share country-level details on the specified products (personal communication with the IEA, 24 July 2024). Therefore, to assess the potential market size for the low-emissions products within the industrial sectors of the Northern Territorys five key trading partners, simplified estimates of regional demand for these products and services were developed. The estimation method principally relies on the officially reported most recent activity indicators (electricity generation, steel, cement and chemicals production, and billions of passenger kilometres for air travel) for each country as the starting point. These indicators were then forecast up to 2050. Where country-level forecast growth rates for the indicators are available, they are used in the analysis. Otherwise, it was assumed that their growth follows the global average forecast trends. A similar approach was taken for estimating the low-emissions products adoption rate to meet the decarbonisation targets. The collated demand estimates are shown in Table 1. For all forecast estimates there is strong demand for hydrogen, ammonia, sustainable aviation fuels, methanol and CCUS, as a feedstock for chemicals manufacture, from the five key trading partners. These estimates of demand for low-emissions products do not include demand from other countries within the region, so are therefore conservative. Table 1: Simplified projection of low-emissions product demand for Northern Territory trading partners 2030 2050 STEPS APS SDS *2021 NZE STEPS APS SDS *2021 NZE Hydrogen and H2-based Fuels (Mt H2 Eq.) Electricity generation 1 2 2 8 4 14 19 12 Steel 0 2 3 0 42 39 Cement 0 0.3 0 2.1 Primary Chemical Feedstock (Mt) Ammonia* 62.4 58.9 58.9 73.2 65.8 65.8 Methanol 88Mt @ 2022 in the trading partners countries Global Demand: >100Mt 2024 - Projected to increase up to 500Mt by 2050 **. Sustainable Aviation Fuel (PJ) Bio Fuel 137 229 309 444 1,038 1,004 Hydrogen 0 0 0 9.3 102 278 Synthetic Kerosene 3.5 7.0 29 0.0 636 1,128 CCUS (Mt CO2) by Sector Electricity generation 2 14 150 106 15 345 820 342 Steel 0 10 17 0 192 249 Cement 0 131 86 0 596 665 P. Chemicals 0 15 0 102 * SDS scenario assumes savings in the ammonia demand in the chemical feedstock, mainly due to fertiliser use efficiency and plastic recycling (International Energy Agency, 2021). ** Global demand is projected to increase dramatically from 100Mt to 500Mt due to more adaptation in the transportation sector, as well as the growth in methanol-to-olefin (MTO) route as an alternative to e traditional production of ethylene and propylene through petrochemical routes, MTO share increased from almost zero percent in 2010 to 25% of global consumption in 2020 (IRENA and Methanol Institute, 2021). Globally, the demand for low-emissions hydrogen in the electricity generation sector is expected to grow from negligible amounts in 2022 to 14 Mt in 2030 and 42 Mt in 2050 under the NZE by 2050 scenario. As shown in Table 1 demand for hydrogen and hydrogen derivatives for the five key trading partners in this sector using the NZE by 2050 scenario represents 57% of total forecast global demand in 2030 and 28.5 % of global forecast demand in 2050 (summing to 8 and 12 Mt hydrogen, respectively). The NZE by 2050 scenario is the most aggressive emissions reduction scenario used for demand estimates. However, while the Announced Pledges scenario and Sustainable Development scenario have lower gross demand estimates in 2030, they exceed the NZE demand estimates in 2050 (Table 1). Globally, in the NZE by 2050 scenario across all the industrial sectors, the demand for low-emissions hydrogen is 70 Mt in 2030 and 420 Mt in 2050, the majority of which is expected to be produced through electrolysis, with the rest produced from the methane thermochemical sources equipped with CCUS. Even just considering the electricity generation, steel and cement sectors of the five key trading partners, the demand estimates presented here represent 16% of the total global hydrogen market by 2030 and 12.6% of the market by 2050. There will be additional demand in these jurisdictions from other sectors, including the aviation other transport and primary chemicals sectors (Table 1). Around 200 Mt of ammonia are currently produced worldwide each year, only 10% of which is traded on the international market. Under the NZE by 2050 scenario, global annual ammonia demand is expected to grow to 204 Mt by 2030 and 228 Mt by 2050. For the five key trading partners, low-emissions ammonia demand estimates represent about 29% of global demand in both 2030 and 2050. The Stated Policies scenario (and Sustainable Development scenario) demand estimates exceed the NZE-derived estimates of demand, reflective of the drivers and policies enacted for ammonia use, particularly by Japan and Republic of Korea. Specific demand estimates cannot be ascertained for methanol and high-value chemicals due to insufficient data availability. It is known, however, that most current global methanol demand comes from the five key trading partners. Total global demand for methanol is expected to grow rapidly through to 2050, from 100 Mtpa to 500 Mtpa. Under the NZE by 2050 scenario, emissions from the chemical sector will need to drop by 21% by 2030 and 96% by 2050, so there will be strong demand for low-emissions methanol feedstocks for the chemicals industry in the region. Currently, the aviation sector consumes approximately 280 Mt (11,000 PJ) of oil-based fuels (IATA, 2024; International Energy Agency, 2023h). Based on IEA modelling, the annual demand for sustainable aviation fuels under the NZE by 2050 scenario reaches 1,700 PJ in 2030 and 11,900 PJ in 2050 (International Energy Agency, 2023e). Of this estimated global demand, about 20% is derived from the five key trading partners in both 2030 and 2050. The gross Stated Policies scenario and Announced Pledges scenario demand forecasts are somewhat lower than the NZE by 2050 scenario in 2030 but have higher demand in 2050. There is significant estimated forecast demand for CCUS in the electricity generation, iron and steel, cement and primary chemicals sectors in all but the Stated Policies scenario in 2030 and 2050. Total CCUS demand from the five jurisdictions is estimated for these sectors. This estimated demand differs from that determined in the Task 2 report (Rogers et al., 2024a) for 2030. Here the analysis incorporates applied IEA scenarios that use country-level reporting of sectorial emissions. In the Task 2 report (Rogers et al., 2024a), existing point-source emissions were used to estimate total 2030 CO2 emissions, the emissions further than 50 km from suitable ports were removed and then the IEA NZE technology road maps were applied to each of those sectors. These methods and the differences in the reported datasets lead to differences in the demand estimates across the reports. The differences in methodologies allow an appreciation of possible ranges in CCUS demand ? which in both cases is large. The estimates of low-emissions product demand have shown that under the IEA scenarios there is strong demand from the key Northern Territory trading partner countries in the near (2030) and long term (2050). Much of this demand will be driven by China due to the size of its economy and associated emissions, but there are also important demand contributions from the other trading partners. Some of the demand for low-emissions products will be met by the countries themselves (e.g. electrolyser-derived hydrogen), but due to the scale of the demand, current levels of energy imports and the natural resources available there will be significant opportunities for Northern Territory exports of low-emissions products. While the demand estimates for low-emissions products is large, even in the Stated Policies scenario, further policies and mechanisms (e.g. carbon markets, cost for difference schemes, CBAM) are required to meet the Announced Pledges scenario and NZE by 2050 scenario. These policies need to ensure that price gaps between existing non-abated products are bridged, and that they provide sufficient market certainty to enable investment in the development of low-emissions product value chains. Key to the bridging of the price differential between existing non-abated and low-emissions products will be the acceleration of commercialisation and adoption of new technologies and the realisation of industrial efficiencies through process intensification and sector coupling (see the Task 5 report; Czapla et al. (2024)). 1 Introduction Understanding the current and future demand for low-emissions products, particularly from hard-to-abate sectors, helps us to discern the drivers for future development of the industries that will provide these products. Low-emissions products can range from low-emissions hydrogen through to building aggregates. The focus here is primarily hydrogen and hydrogen derivatives (e.g. ammonia) and chemical feedstocks. Low-emissions products will be essential to avoid the creation of emissions from hard-to-abate industries and will negate some of the demand for abatement technologies. Low-emissions products alone will not be sufficient to eliminate all emissions from these industrial sectors, but they will fulfill an important role in the decarbonisation of sectors and other approaches, such as direct electrification, CCS (see the Task 2 report; Rogers et al. (2024a) ) and offsets. The decarbonisation roadmaps for hard-to-abate sectors to meet NZE by 2050 are described in a number of publications, including those published by the IEA (referenced throughout below). It is acknowledged that each jurisdiction will have its own approaches to decarbonisation of hard-to-abate sectors, tailored to its industrial mix, access to decarbonisation technologies and ease of implementation (e.g. sufficient renewable energy resources). This report explores drivers for the development of low-emissions products (section 2). This includes analysis of carbon market price outlooks. IPCC-modelled carbon prices for 1.5C and 2.0C scenarios are compared with existing carbon market prices and forecasts, within both established (e.g. European ETS) and emerging carbon markets within the region. This analysis also includes the ACCU market as this represents, in effect, a carbon market. Other emissions reduction drivers are also explored to understand their impact on the demand for low-emissions products (section 3). This review focuses on mechanisms and drivers that have been implemented in Australia, as well as developing an appreciation of more broad-ranging drivers such as CBAM, green premiums and company requirements for climate-related financial disclosures. The demand drivers for the electricity generation, iron and steel, cement, primary chemicals and sustainable aviation fuel sectors are explored in section 4, with a focus on those sectors in the Northern Territorys five key trading partners and the region. In addition to analysing emissions reduction needs, mechanisms that also promote demand in each of these jurisdictions are identified. In section 5, the size of the demand for low-emissions products is estimated for Japan, Republic of Korea, China, Singapore and Taiwan using the four different IEA scenarios. In this analysis the size of CCUS demand is also estimated. This provides a comparator to the approach used to estimate CCUS demand in the Task 2 report (Rogers et al., 2024a). The methods used here to estimate demand for low-emissions products are just one approach among many that can be used (e.g. see the Task 2 estimation of CCUS demand for an alternative method). While every effort has been made to establish the validity of the numbers used in the estimations (by using and referencing reputable sources), there are differences in emissions and demand figures in the various sources. The purpose of this report is therefore not to provide absolute demand numbers but to understand the amount and range in the demand for low-emissions products that could be required by the Northern Territorys five key trading partners and provide context for potential low-emissions industrial development in the Northern Territory Low Emissions Hub (NT-LEH). 2 Carbon market price outlook Several mechanisms can be used to stimulate the demand for low-emissions products. One of these mechanisms will be assigning costs to CO2 emissions. While there is no global carbon pricing mechanism, there are numerous carbon price forecasts that predict the carbon price required to meet emissions reduction targets. In addition, a number of regional or country-based ETS and mandated carbon price mechanisms are in operation. Current carbon prices and forecasts can be used to understand the likely impact that these prices will have on low-emissions product demand. It is not the purpose of this report to review all carbon pricing and ETS, but rather to provide a snapshot of the range of prices today and future forecasts. 2.1 IPCC carbon price modelling In the IPCC's 6th assessment report, which review the latest scientific information on climate change, Chapter 3 (IPCC, 2023a) provides a summary of various mitigation pathways, many of which incorporate carbon pricing. Each of these mitigation pathways uses integrated assessment models (IAMs), which are developed with a predefined outcome, such as limiting warming to 1.5C. The models then backcast to determine how the system could evolve to reach that outcome. Each model is differentiated according to which climate and economic models are included, with each model containing its own sets of assumptions and constraints. Given the wide range of scenarios that could be considered, eight broad categories were developed. Each category includes a defined warming outcome, as well as links to several illustrative mitigation pathways (IMPs). Differences in pathways are attributed to alternative ways that given warming outcomes might be reached. For example, some pathways emphasise the rapid deployment of renewable energy and CO2 removal technologies. Other pathways are based on different assumptions about economic variables, such as below-average growth in final energy demand and more ambitious climate (price) policies. For more details see Riahi et al. (2022). For this report, two categories (C1 and C3) were selected to analyse how carbon prices develop within the models assigned to each category. The first category, C1, includes scenarios where the outcome is warming being limited to 1.5C during the 21st century, with a likelihood of 67%, and warming limited to 1.5C in 2100, with a likelihood of >50%. In this category, scenarios include the assumption of limited or no overshooting and include illustrative mitigation pathways related to a heavy reliance on renewables (IMP-REN), significant reductions in final energy demand (IMP-LD) and the introduction of sustainable development policies (IMP-SP) (Soergel et al., 2021). Within this category, there are 97 scenarios (or models) that correspond to the identified illustrative mitigation pathways but that differ in key outputs due to variations in assumptions and imposed constraints. Of relevance to this report is the reported carbon price over time and its variation between each of the scenarios within this category. Figure 1 shows that over time the median carbon price for a tonne of CO2 increases from US$262 (A$393) in 2030 to US$756 (A$1,135) in 2050. There is significant variation in the modelled price, with some models reporting a $0 carbon price up until 2030 and other models reporting carbon prices exceeding US$10,000 (A$15,016) in 2050. This variation is expected due to differences in assumptions and imposed constraints. Nonetheless, the price of carbon generally increases over time, and at least 50% of the modelled scenarios include prices that are equal to or exceed the median price for each decade. It should be noted that the scenarios modelled for this category represent the most ambitious emissions reduction policies and climate outcome. Figure 1: Global carbon median price outlook, C1 1.5C pathway. All prices have been inflated from 2010 to 2022 US$ (Federal Reserve Bank of St Louis, 2024) Source: IPCC (2023a) The second category, C3, represents a less ambitious climate outcome. It assumes that peak warming is limited to 2.0C throughout the 21st century, with a likelihood of >67%. Scenarios within this category relate to the gradual strengthening of current mitigation policies implemented by countries as of 2020 (IMP-GS). Emissions in this category fall more slowly over time relative to category C1 due to a slower reduction in fossil fuel use. In addition, there is a need to rely on net negative emissions to achieve the climate outcome by the end of the century, which is not the case with category C1. Figure 2 shows the range of carbon prices for the 311 scenarios that fall under category C3. Less ambitious policies, as well as a higher warming outcome, result in a lower carbon price compared with category C1. Nonetheless, there is still the same upwards trajectory in carbon price over time, with the median price per tonne of CO2 increasing from US$75 (A$112) in 2030 to US$285 (A$428) in 2050. Figure 2: Global carbon median price outlook, C3 2.0C pathway Source: IPCC (2023a) 2.2 European carbon market price outlook Since its introduction in 2005, the EUs ETS has become the worlds largest emissions trading scheme (World Bank, 2023). The cap-and-trade system sets an upper limit on emissions each year which declines in line with emission reduction targets set by the EU. Over time the scheme has undergone several significant changes that increase the number of industries where emissions must be accounted for, transitioning away from free allowances and introducing a market stability reserve (European Commission, 2024). In 2023 the EU updated its 2030 greenhouse gas target after it was identified that previous policies were insufficient to meet its net zero goals in 2050 (European Commission, 2020). From this update the Fit for 55 package was developed, representing a collection of policies that could reduce emissions within the EU by 55% by 2030 compared with 1990 levels (European Council, 2024). Separate to these policies, modelling has evaluated how the price of EU allowances would develop over time towards 2030. Pahle et al. (2022) conducted a workshop with various experts who develop carbon market models. The workshop aimed to evaluate the differences in parameter assumptions, model setups and other relevant factors that influence the key cost drivers of EU allowances. Figure 3: European ETS price outlook Source: Pahle et al. (2022) In total six models were evaluated, with the ETS price outlook for each model plotted in Figure 3. Except for one model, prices are expected to be between 130/t (A$215) and 160/t (A$265) by 2030. These results are comparable to those reported using alternative models for sectors within the EU. For example, (Pietzcker et al., 2021) modelled an equivalent 2030 emissions target for the EUs power sector. Using the long-term investment model for the electricity sector (LIMES-EU) they identified that carbon prices would increase to 129/t (A$214) by 2030. Although not directly comparable, this is one example where the trend in a sector-specific model aligns with broader carbon market models, showing that carbon prices are expected to rise into the medium term. 2.3 South-East Asian carbon market price outlook In South-East Asia, several countries have implemented carbon pricing regimes. As of 2023 most of these countries had adopted both an ETS and a carbon tax, as detailed in Table 2. All prices are either average or end-of-year prices converted to A$ using average exchange rates for the year (Exchange Rates UK, 2024). Table 2: Summary of carbon prices within South-East Asia as of 2023 (all prices shown in A$) Country Carbon tax ETS Source China Not implemented National ETS ($14.55/t CO2) International Carbon Action Partnership (2024a) Indonesia $3.00/t CO2 $6.87/t CO2 Chandra (2024) Japan $3.09/t CO2 Saitama $1.54/t CO2 Tokyo $6.95/t CO2 International Carbon Action Partnership (2022a; 2022b) Singapore $5.60/t CO2 Not implemented National Climate Change Secretariat (2024) Republic of Korea Not implemented $10.19/t CO2 World Bank Group (2024) The following average 2023 exchange rates were applied: CNY:A$ 0.2129, IDR:A$ 0.0001, JPY:A$ 0.0107, SGD:A$ 1.1213, KRW:A$ 0.0012 Between countries there is significant variation with respect to sectors covered. For example, Chinas national ETS only covers power sector CO2 emissions (International Carbon Action Partnership, 2024a), while Republic of Koreas ETS covers 89% of its national greenhouse gas emissions and includes CO2 equivalents (International Carbon Action Partnership, 2024b). In terms of future carbon prices, only one of the listed countries in Table 2 has defined policies that lead to prices rising over time. In 2024, the Singaporean Government increased its carbon price to SGD 25/t (A$28.03); by 2030 the price is expected to range between SGD 50/t and SGD 80/t (A$56.06$89.70) (National Climate Change Secretariat, 2024). In terms of future prices, several factors could lead to prices evolving over time. Expanding existing schemes to cover a greater proportion of a countrys emissions would increase demand within an ETS. In addition, public investment to reduce the cost-competitiveness gap with existing technologies could increase each countrys rate of decarbonisation. Several countries are planning on developing more ambitious carbon policies. For example, in 2024 Japan announced that it would be developing a 2040 Green Transformation strategy to include policies promoting additional investments in decarbonisation technologies (Reuters, 2024). The Malaysian Government, in conjunction with the World Bank, is completing a study evaluating the introduction of a carbon pricing instrument. The study will evaluate whether a carbon price or ETS would be an effective policy to reduce the countrys greenhouse gas emissions (Malaysian Investment Development Authority, 2023). Alongside individual countries developing their own carbon policies, there is ongoing policy development to enable international carbon trading. The details of the associated mechanisms are described in Article 6 of the Paris Agreement, with the overall goal of reducing the cost of emissions abatement across countries (Edmonds et al., 2021). These would enable countries to voluntarily enter into agreements to fund emissions mitigation programs while making the necessary adjustments to their own nationally determined contributions. For example, country A could fund a project that leads to the mass deployment of renewable energy technologies in country B. By doing so, country A can lower its reportable emissions by the quantity of tonnes of CO2-e reduced (or an equivalent metric) throughout the project. Country B would realise the economic benefits associated with the project, but to avoid double counting would increase its reportable emissions by the same adjustment made by country A. This example assumes that country B would not exceed its nationally determined contributions after the required adjustment is made. From the perspective of country A, the assumption is that it is not on track to meet its nationally determined contributions, and the cost of the project is less than the cost of alternative emissions reduction projects. To enable an international carbon market, Article 6 defines the rules and accounting framework that would enable trading to occur. Discussions of Article 6 often focus on two subsections: Article 6.2 and Article 6.4. Article 6.2 as a framework enables the bilateral or multilateral transfer of internationally traded mitigation outcomes. These mitigation outcomes are a traded commodity, conceptually equivalent to carbon credits, that describe the adjustments each country makes to its nationally determined contributions. Article 6.2 describes the additional rules that countries must adhere to when facilitating agreements to trade the mitigation outcomes, with key rules relating to how adjustments are made, initial and ongoing reporting requirements, and requirements for technical experts to reviewing reports submitted by each country. Article 6.4, which is relatively less mature in its development, will establish a trading mechanism for any country seeking to engage in international carbon trading. In contrast to what is described in Article 6.2, a centralised supervisory body will administer a standardised method for carbon trading. Established methodologies for carbon mitigation, as well as rules for reporting, would reduce the transaction costs associated with bilateral agreements, allowing for greater participation and minimising the global cost of mitigation. 2.4 Australian carbon credit unit price outlook While Australia does not have an official carbon price or ETS, legislative mechanisms have been implemented that broadly achieve a similar outcome. Australias carbon market involves the trading of several market-based instruments, including ACCUs, large-scale generation certificates and small-scale technology certificates. Each instrument is designed to reduce domestic emissions through incentivising projects that reduce emissions (ACCUs) or incentivising renewable energy generation technologies (large-scale generation certificates and small-scale technology certificates).3 ACCUs were initially developed as a voluntary scheme under the Carbon Credits (Carbon Farming Initiative) Act 2011 (DCCEEW, 2023). This scheme existed alongside an Australian carbon tax, which was in effect from 2012 to 2014 with prices per tonne of CO2 ranging between $23.00 and $25.40 (Gonalves and Menezes, 2024) . Replacing the carbon tax was the Emissions Reduction Fund, a successor scheme to the Carbon Farming Initiative (Australian Government, 2014). The voluntary scheme provides incentives for organisations and individuals to develop projects that reduce emissions. Eligible projects generate ACCUs, with each unit representing one tonne of CO2-e either stored or avoided. ACCUs surrendered to the Clean Energy Regulator can be used to offset an organisations total reportable emissions. ACCUs can also generate income by being sold to the government through a reverse auction mechanism associated with the Emissions Reduction Fund. In total, 15 auctions have been held so far, with the government purchasing a predetermined value of ACCUs from parties who propose eligible projects. As of March 2023, A$2.7 billion had been committed across 443 projects, representing 217.3 million tonnes of abatement (Clean Energy Regulator, 2024a). Figure 4 shows that the average price has slowly increased over time, with the latest price as of March 2023 equal to A$17.35 per tonne of abatement. Figure 4: Emissions Reduction Fund auction results Source: Clean Energy Regulator (2024a) In addition to government demand, there is also the potential for ACCUs to be sold on the secondary market, where buyers in the secondary market can surrender purchased ACCUs to reduce their net emissions. Before the introduction of the Safeguard Mechanism (see section 2.5), the market for ACCUs was voluntary, and their price was influenced by the outcomes of Emissions Reduction Fund auctions. As shown in Figure 5, the price of ACCUs was below A$20 before increasing to almost A$60 in early 2022, following speculation as to a lack of supply and changes to fixed delivery contracts related to the Emissions Reduction Fund (Clean Energy Regulator, 2022). Following these changes, peak prices have fluctuated between A$25 and A$40 in the most recent reporting period. There are a wide range of ACCU price forecasts from industry and the banking sector, a selection of which are shown in Figure 6. These forecasts all show increasing ACCU costs towards the ACCU price cap associated with the Safeguard Mechanism (see below). It is interesting to note that since the data were collated for Figure 6, the ACCU voluntary market has not followed the lowest growth forecast in ACCU price. Figure 5: ACCU voluntary market price, 2019?24 (Clean Energy Regulator, 2024b) Figure 6: ACCU price outlook Source: Adapted from AgTech (2023) 2.5 Australias Safeguard Mechanism In 2016 the Safeguard Mechanism was enacted as a policy to incentivise the reduction of scope 1 (direct) emissions associated with Australias largest emitters. Any facility that produces more than 100,000 tonnes of CO2-e in a financial year is covered by the Safeguard Mechanism and is required to initially measure its baseline level of emissions. In each successive year this baseline level is reduced, requiring the facility to either invest in abatement technologies or purchase offsets. Most of the facilities covered are within the mining, manufacturing, transport, oil, gas and waste sectors and represent 28% of Australias 2020?21 emissions (Australian Government, 2023c). Since July 2023, a reformed version of the scheme has been in place. The reforms were developed to assist the governments goal of achieving a 43% reduction in emissions on 2005 levels by 2030 and net zero by 2050. Three changes were introduced: a gradual reduction in baselines that is predictable (4.9% per annum to 2030); adjustments for emissions-intensive trade-exposed facilities to reduce the risk of carbon leakage; and tradable credits for firms that reduce emissions below their baseline level, termed Safeguard Mechanism credits (Australian Government, 2023c). When the scheme was first developed, facilities measured their emissions using one of the baseline determination methods described in the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule (Australian Government, 2015). Over time, the use of site-specific emissions-intensity values will transition to industry-specific values, the latter providing an incentive for production to occur at sites where emissions are below the average. Emissions associated with electricity production, specifically those classified as scope 1 emissions, are not covered by the Safeguard Mechanism if the aggregated emissions of all electricity-producing facilities do not exceed 198 million tonnes of CO2-e in a financial year. If the sectoral emissions limit is exceeded in a given year, individual facility baselines will be applied to electricity generators. Beyond investment in avoidance and abatement technologies, facilities have several methods for achieving their baseline level each year. If in any year the baseline is exceeded, a facility can apply for a borrowing adjustment. In exchange for raising the baseline level in the year applied for, it must further reduce its emissions in a later year, in effect lowering the future baseline level more than what it would have been if the adjustment was not applied for. For any year that a facility reduces its emissions below its baseline, the operator may be eligible to receive Safeguard Mechanism credits. These credits can be banked until 2030, surrendered in a year in which the baseline is exceed, or sold to other facilities. ACCUs can also be purchased and surrendered by a facility to offset its recorded emissions. However, if the amount of ACCUs surrendered represents 30% or more of its baseline emissions, the facility is required to disclose to the Clean Energy Regulator why this quantity of ACCUs was required to be surrendered. Currently, no additional actions are required beyond notification to the regulator. Finally, if a facility exceeds its baseline and does not purchase sufficient ACCUs or Safeguard Mechanism credits to reduce its net emissions, civil penalties can be enforced by the Clean Energy Regulator. When comparing the various forecasts of carbon prices, some markets are closer to realising prices that align with IPCC modelling. The EU ETS prices fall between the IPCCs C1 1.5C and C3 2.0C scenario median prices, while the forecast upper ACCU prices are broadly in line with the C3 2.0C scenario median prices. The South-East Asian carbon markets, with the exception of Singapore which more closely follows the C3 2.0C scenario, have carbon prices that are unlikely to stimulate demand for low-emissions products alone. However, the development of carbon tax and ETS legislation across the region will allow those countries to increase their emissions reduction ambitions over time to drive towards their nationally determined contribution targets. An important consideration for each of the carbon markets that has been implemented is the proportion of each countrys emissions that is covered by that carbon market. The broader the carbon market coverage, the greater the opportunity to stimulate demand for low-emissions products from a range of sectors. While each market can, in principle, stimulate demand for low-emissions products, this is unlikely to be sufficient to displace existing technologies which have been optimised over decades (Hepburn et al., 2020). As such, other emissions reduction drivers are being considered globally. In addition, the progressive implementation of Article 6 over time may reduce the barriers that enable carbon markets to be more integrated, stimulating mitigation efforts in countries whereby the abatement cost is minimised. 3 Other emissions reduction drivers While carbon price will drive emissions reductions, many jurisdictions are using carbon prices in conjunction with other emissions reduction polices, such as mandated targets for low-emissions products and low-cost financing. The Australian Government has several policies targeted at reducing emissions and stimulating the development of low-emissions products and industries. 3.1 Powering Australia Plan In 2022, the Australian Government developed its Powering Australia Plan, representing a set of policies and funding available to assist the transition towards a low-carbon economy as well as to help Australia meet existing international climate commitments (International Energy Agency, 2023f). One of the pillars of the plan is the Powering the Regions Fund, representing $1.9 billion worth of funds available to assist in the transition to net zero (DCCEEW, 2023). Funding is to be allocated across four key areas: * decarbonising existing industries * developing new clean energy industries * developing the workforce * purchasing ACCUs. Several other significant funding streams include the Safeguard Transformation Stream, the Industrial Transformation Stream, the Critical Input to Clean Energy Industries program, and the Hydrogen Headstart program (Australian Treasury, 2024a). Each of these streams represents pools of funds that target key sectors identified through stakeholder consultation as requiring financial support. Reasons for these sectors requiring support include them being emissions intensive and/or trade exposed, being capital intensive or having limited technologies available to decarbonise. Specific strategies and funding have also been provided to the transport and electricity sectors. The National Electric Vehicle Strategy was released in April 2023, outlining several measures that, if implemented, could increase use of electric vehicles. In conjunction with this strategy, a review of national fuel efficiency standards was available for public consultation. Transport-related funding totalling more than $600 million has been made available to reduce taxes and tariffs related to electric vehicle purchases as well as for installing relevant infrastructure. The majority of funding allocated to the electricity sector involves making available $20 billion in low-cost financing over four years for investments that strengthen the national electricity grid. Key projects currently being funded include the Marinus link, transmission links in New South Wales and Western Australia, and Renewable Energy Zones within Victoria (Australian Government, 2023d). Finally, $1 billion in funding has been allocated to the Clean Energy Finance Corporation as a means to provide low-cost financing for household energy upgrades. 3.2 Future Made in Australia plan The Future Made in Australia plan, announced in the 2024?25 Federal Budget, is a package of policies and funding designed to encourage additional private sector investment in key industries. In total, $22.6 billion has been allocated over the next decade to assist the diversification of Australias economy, with a focus on producing and using renewable energy (Australian Government, 2024). There are several key themes that describe the priorities of the plan. A National Interest Framework is being developed to identify which industries should receive public investment, with the goal of sufficiently incentivising private investment to then scale up these industries. These industries include renewable hydrogen, green metals, critical minerals, and clean energy technology manufacturing. Each industry has been identified as being able to assist in the transition to net zero and/or to increase the resilience of the Australian economy. Other themes of the plan relate to reducing the transaction costs associated with investments in renewable energy and related technologies. The plan emphasises connections to other existing government programs and funding sources, such as the hydrogen Guarantee of Origin scheme and the additional funds allocated to the Australian Renewable Energy Agency. As of August 2024, various elements of the Future Made in Australia plan are being developed with the goal of passing the Future Made in Australia Act through Parliament. Two related Treasury publications explain how the National Interest Framework can be used to better inform national decision making (Australian Treasury, 2024b) and the development of a Sustainable Financial Roadmap, which will assist in the provision of additional climate-related financial disclosures relevant for financial investment decisions related to decarbonisation (Australian Treasury, 2024c). 3.3 Carbon border adjustment mechanisms To prevent carbon leakage from markets (i.e. the importation of products with high embedded emissions into markets where industries are subject to carbon pricing or are required to produce products with lower embedded emissions), a number of jurisdictions have developed CBAMs. In 2005 the EU launched an emissions trading system that could over time reduce emissions within the EU. Since its inception, numerous reforms have been enacted that work towards achieving the goal of NZE by 2050. One recent reform of note relates to addressing the risk of carbon leakage. Any country that enacts a policy-driven carbon pricing regime faces the possibility that firms will move their production activities offshore to avoid regulation (Grubb et al., 2022). Historically, this risk has been mitigated by providing concessions to emissions-intensive trade-exposed industries (e.g. cement, iron and steel, and chemical refineries; IEA (2020)). Currently, a subset of industries is receiving free emissions allowances, in effect disincentivising any abatement activities but avoiding losing international competitiveness due to the EUs ETS. As part of the EUs Fit for 55 package, a CBAM was proposed to level the playing field between domestic producers and imported goods (European Parliament, 2022). Although domestic producers will progressively lose their free emissions allowance, importers will be required to obtain allowances based on the embedded emissions of equivalent products (and related precursors). This will remove any competitive advantage that non-EU countries have, assuming they are not already subject to an equivalent carbon pricing regime. The CBAM was approved by the European Commission in April 2023, with the mechanism being introduced across two periods: * During the transitional period (1 October 2023 to 31 December 2025) importers must report relevant emissions data but are not financially liable in terms of purchasing and surrendering emissions allowances. The purpose of this period is to allow all relevant parties time to understand how the reporting process works and to refine the methodology for calculating embedded emissions. * In the definitive period (in effect from 1 January 2026) importers will be required to purchase and surrender allowances, and the free allocation of permits for domestic producers will be progressively phased out by 2034 (European Parliament, 2023). Initially, the following imported goods will be subject to the CBAM: cement, iron and steel, aluminium, fertilisers, electricity and hydrogen. Each firm that imports any of these goods will need to calculate the embedded (direct and indirect) emissions associated with that product. To calculate direct emissions, either the calculation- or measurement-based approach can be employed (European Union, 2023). The calculation-based approach involves obtaining from the producer of the goods the quantities of all relevant fuels and materials used, then multiplying by their corresponding emissions factors (CO2-e content). The measurement-based approach involves calculating the concentration of greenhouse gases and the flow of flue gas for each emission source. Further details regarding regulation of the CBAM is governed by Commission Implementing Regulation (EU) 2023/1773 (European Union, 2023). Specifically, Annexes I?IX address what needs to be included within CBAM reports submitted to customs, production routes for products, rules for determining relevant emissions data, relevant fuel emission factors, and efficiency factors for producing electricity and heat. Exporting countries that currently have carbon pricing policies in place can reduce the effective carbon price due. To be considered an effective price, it must be paid in the country of origin in which the good was produced and be net of any rebates received on the carbon price paid. The European Commission has created a guidance document outlining what information is required (European Commission, 2023b). If it is determined that an effective carbon price has already been paid, then the number of CBAM certificates required to be purchased does not change; however, a rebate will apply, reducing the amount to be paid per certificate. The Commission will provide more guidance explaining the calculation of the effective carbon price paid before the end of the transition period (European Commission, 2023a). Several countries are also considering implementing their own CBAM, including the United Kingdom, the United States of America, Canada and Australia (in Australia, there is a trigger within the Safeguard Mechanism legislation to implement a CBAM). This is in part to address their own country-specific risks of carbon leakage, but there are revenue implications for countries that have not implemented their own carbon pricing regime. Once the CBAM is in effect, the EU will collect tariff revenues that can be used to enable other decarbonisation policies. It is possible that the EU CBAM may breach World Trade Organization trade rules (Leonelli, 2022; Zhong and Pei, 2024). While several countries have raised trade concerns related to the European CBAM (including China, Japan and the Republic of Korea), as of September 2024 no country had lodged a dispute with the organisation. The implementation of CBAM mechanisms in key consumer markets is likely to stimulate demand for low-emissions products and decarbonisation of industrial processes, especially in markets and jurisdictions that have high reliance on the export of manufactured goods. This impact will be felt in the Asia-Pacific region due to its large manufacturing sector. 3.4 Green premium As part of the shift towards low-carbon economies, firms are beginning to make investments in technologies that reduce the embedded emissions of their products. These investments are in part a response to carbon pricing, market access requirements (e.g. CBAM), market opportunities, and shareholder and community expectations. Often, these investments result in higher production costs that are either absorbed by the firm or passed on to consumers. The ability to pass on these costs is in part determined by a consumers willingness to pay for low-emissions products, often referred to as a green premium. The existence of a premium suggests that consumer purchase decisions factor in the embedded emissions of products and that they prefer lower or zero-emission products. Previous research has identified that consumers will pay a green premium for products such as buildings (Dwaikat and Ali, 2016), electricity (MacDonald and Eyre, 2018), organic products (Aschemann?Witzel and Zielke, 2017) and bonds (MacAskill et al., 2021). What distinguishes green premiums from other methods to price emissions is that they represent a voluntary premium that firms and consumers are not required to pay; unlike carbon taxes or permits, firms and consumers can choose to purchase substitute goods that only differ in terms of embedded emissions. Encouraging the shift towards low-emissions products can be achieved by lowering the green premium associated with products. One way to lower the premium is to reduce the associated production costs that achieve lower emissions. Cost-saving innovations (e.g. R&D breakthroughs and learning effects), could enable economies of scale and consequently reduce the cost pass-through to consumers (Caldeira et al., 2023). Introducing carbon pricing regimes could reduce the price differential with products that have an associated green premium. Finally, changing consumer preferences reflecting stronger pro-environmental values and increasing eco-literacy may reduce the aversion to paying more for green products, assuming the products are credibly green (von Fle et al., 2023; Wei et al., 2018). 3.5 Climate-related financial disclosures As the impacts of climate change continue to emerge, there is a growing desire to understand how the associated physical and transition risks may impact future capital allocation decisions. The material financial risks that impact firms are already required to be disclosed under international and Australian Accounting Standards, but risks related to climate change have not explicitly required disclosure. Following the recommendations made by the Taskforce on Climate-related Financial Disclosures, the Australian Government has begun consultation on developing Australian Accounting Standards to standardise climate-related financial disclosure requirements. The standards are intended to align with international financial reporting standards and be implementable by Commonwealth public sector entities and companies (Australian Treasury, 2023). Since December 2022 two rounds of consultation have been completed and as of December 2023 draft legislation is still in development. In addition, the Australian Accounting Standards Board is seeking consultation on exposure draft SR1 relating to the development of three new Australian Sustainability Reporting Standards, with consultation open until March 2024 (Australian Accounting Standards Board, 2023). At the most recent round of consultation, several policy proposals were discussed regarding the scope and implementation of climate-related disclosures. Where possible, the additional reporting requirements would be supplemental to existing disclosures requirement; for example, those disclosures as described in AASB 101 (Australian Accounting Standards Board, 2023). However, additional disclosures have been proposed that go beyond existing accounting standards including how the firms governance processes address and manage climate-related risks and opportunities, industry-based metrics, climate resilience assessments to future possible states as described in the Climate Change Act 2022 (Cth), and scope 1, 2 and 3 emissions (Australian Treasury, 2023). Any firm that meets the prescribed thresholds described in Chapter 2M of the Corporations Act 2001 (Cth) and is required to lodge financial reports would be required to make climate-related disclosures (Australian Treasury, 2023). In addition, any firm that is considered a controlling corporation and therefore required to report under the National Greenhouse and Energy Reporting Act 2007 (Cth) would also be required to produce climate-related disclosures, regardless of the requirements of the Corporations Act. It has been proposed that the requirements to disclose be phased in, with the lowest threshold requirements being applied in the 2027?28 financial year. Phasing-in arrangements have also been proposed with respect to emissions disclosures. Each firm would initially be required to report its gross scope 1 and 2 emissions, with material scope 3 emissions to be reported the year following initial reporting. Scope 3 emissions will be limited to upstream and downstream emissions estimated using applicable emissions accounting frameworks, with Australia-specific emissions factors used when possible (Australian Treasury 2023). Consistent with other financial disclosures, assurance will need to be provided on all climate-related disclosures. Given the significant changes being proposed, the assurance to be provided will be limited initially, progressing to reasonable assurance over time. It has been noted that, in particular with estimating scope 3 emissions, there needs to be an appropriate balance in terms of what liabilities may be applicable when firms produce misleading, erroneous or inadequate climate disclosures. Consequently, it has been proposed that within the first three years of the disclosure regime being implemented, non-compliance will be limited to regulator-only actions. After this period, civil penalties as described under the Corporations Act would apply. The net result of these climate-related financial disclosures will be a much greater scrutiny on company emissions and their validity. This will likely increase the demand for low-emissions products from Australian companies. 4 Low-emissions products As discussed above, there are a growing number of drivers to produce low-emissions products both within Australia and globally. These have implications for industrial sectors within Australia and the Northern Territorys five key trading partners (Japan, Republic of Korea, China, Singapore and Taiwan). The Task 2 report (Rogers et al., 2024a) summarises emissions from point sources for each partner, concluding that the top emitting industrial sectors are: electricity generation (coal, gas and oil) iron and steel production cement production chemical production. This analysis clearly identifies the demand for CCS (see the Task 2 report; Rogers et al. (2024a)). However, further emissions reduction pathways beyond CCS are required for each of the sectors. While this is a considerable challenge, it provides an opportunity for the Northern Territory given its world-class energy resources, CCS potential, well-established infrastructure and existing trading relationships. Decarbonisation pathways for each industrial sector, as modelled by the IEA, are reviewed below with a focus on the demand for products suppliable by the Northern Territory. In addition, a brief section is also included on the aviation sector to estimate the demand for sustainable aviation fuels by the five key trading partners. The IEA does not share country-level details on the specified products (personal communication with the IEA, 24 July 2024). As such, to assess the potential market size for the low-emissions products within the industrial sectors of the key trading partners, simplified estimates of regional demand for these products and services were developed. One critical point to note is the time requirement for developing the new technologies that are required under the NZE by 2050 scenario. Historically, new technologies take 20?70 years from developing a prototype to widespread commercial adoption (Figure 7; (International Energy Agency, 2023c). NZE requires a more accelerated adoption timeframe. While this can be facilitated by improving the commercial advantage of clean energy technologies, global cooperation and international knowledge transfer, it is clearly challenging to meet the timeframe to deploy these technologies at the required scale (International Energy Agency, 2023c). Figure 7: Time required to bring emerging clean technologies to market Source: International Energy Agency (2023c) 4.1 Electricity generation The electricity generation sector is the largest contributor to point-source emissions of the Northern Territorys five key trading partners. As well as enhanced energy efficiency and demand-side management, the electricity generation sectors decarbonisation pathways can broadly be categorised as: 1. retirement of high-emitting generation assets (particularly coal-fired thermal plants) and their substitution by new low-emissions capacity (e.g. renewable electricity generation from wind and solar) 2. reduction of emissions from the existing fleet by: a. prioritising lower emitting technologies b. low-emissions fuel blending 3. retrofitting current plants to capture the emissions (CCUS) or including CCUS in new-build thermal generation plants. From a purely economic perspective, retirement of existing assets would typically occur at the end of an assets operational life, once capital depreciation has occurred or where maintenance costs rise excessively. The average lifetime of coal electricity generation plants is 46 years, but they can remain operational for up to 60 years (Cui et al., 2019). In 2030, the majority of coal- and gas-fired plants globally will still have a useful technical life (Table 3). This is particularly the case in China and India, whose economies have seen rapid industrialisation and urbanisation in the last few decades, with associated increases in demand for electricity. In 2040 much of the existing electricity generation fleet in the two largest contributors to greenhouse gas emissions in our region will still have a useful technical life (Table 3). This makes the normal retirement schedule of these plants inconsistent with the decarbonisation targets set out by the IPCC and IEA, unless capital assets are retired prior to the end of their useful technical life or prior to full capital depreciation. Table 3: Indicative remaining coal- and gas-fired plants worldwide Source: International Energy Agency (2022) Region % of coal- and gas-fired plants with useful technical life 2030 2040 Advanced economies 79% N/A* Emerging economies 83% 61% China 95% 79% India 86% 73% * Not assessed In addition to the relatively young global coal- and gas-fired electricity generation fleet, lack of resources (e.g. land, solar or wind) or social licence for certain technologies (e.g. nuclear, additional transmission lines) could also pose difficulties in achieving decarbonisation targets in some countries (National Academies of Sciences Engineering and Medicine, 2023; NSW Government, 2023; Singapore Ministry of Sustainability and the Environment, 2019). It is in this context that using substitute low-emissions fuels and CCUS, although currently expensive, are included in the national decarbonisation pathways of some jurisdictions to extend the operating life of the existing assets and ensure energy security. Under the NZE by 2050 scenario, to achieve net zero emissions by 2050, more than 2,000 TWh of electricity will need to be produced globally from CCUS-enabled electricity generation plants or using alternative low-emissions fuels to co-fire in the coal- and gas-fired electricity generation plants (Figure 8). Figure 8: Thermal electricity generation forecast by fuel, under the NZE by 2050 scenario. (Left) Unabated coal, oil and gas electricity generation. (Right) CCUS retrofits and low-emissions fuel demand to co-fire in coal- and gas-fired electricity generation plants Source: IEA (2023) It is expected that the Northern Territory can support its key trading partners electricity generation sectors, especially in Japan and the Republic of Korea, by offering low-emissions hydrogen-derived fuels and CCS. There are other initiatives, such as the Australia-Asia PowerLink proposal ? which includes a large-scale solar farm with battery storage to directly export part of the electricity generated to Singapore via a subsea cable (Australian Government, 2023a) ? but these are beyond the scope of the current task, and market size assessment for direct electricity export is not evaluated as part of this report. 4.1.1 Low-emissions hydrogen Hydrogen has a unique role in decarbonising the electricity generation sector and hard-to-abate industries (International Energy Agency, 2023d; 2023h). While hydrogen transport remains a challenge, many of the pathways to achieve NZE by 2050 and limit global warming below 1.5C are contingent on technologies that use low-emissions hydrogen as an alternative fuel (Figure 8). However, in the electricity generation sector hydrogens application is likely to be restricted to jurisdictions with limited alternative options to decarbonise their coal- and gas-fired electricity generation plants economically. This is mainly because a high concentration of hydrogen needs to be co-fired with natural gas to significantly reduce the emissions, making it economically unattractive. As will be discussed below, in several jurisdictions the production and use of low-emissions hydrogen may attract government subsidies, based on meeting certain emissions-intensity criteria. There is no standard definition of clean or low-emissions hydrogen. The thresholds set by different jurisdictions and organisations are based on the emissions covering part or all of the hydrogen value chain. Most of these thresholds are based on gate-to-gate emissions, which cover only the production and processing phase. The system boundaries are shown in Figure 9 (International Energy Agency, 2023g). Figure 9: System boundaries for the hydrogen value chain Source: Australian Government (2021) A review of the thresholds shows that they range from 0.45to 4.9 kg CO2-e/kg4-5 hydrogen on a well-to-gate basis (International Energy Agency, 2023g). Japans threshold is 3.4 kg CO2/kg hydrogen (New Zealand Embassy, 2023), while Chinas clean hydrogen threshold is 4.9 kg CO2/kg hydrogen on a well-to-gate basis (International Energy Agency, 2023g). This range limits hydrogen production methods to nuclear or renewable electricity via electrolysis, or CCUS-enabled natural gas or coal-based projects thermochemical reforming (Figure 10). China has an additional category for low-carbon hydrogen with a threshold of 14.5 kg CO2/kg hydrogen that can potentially encompass unabated natural gas-based projects using thermochemical reforming (International Energy Agency, 2023g). Using grid electricity with a current global average emissions intensity of 460 g CO2-e/kWh, the hydrogen produced would have an emissions intensity of 24 kg CO2-e/kg hydrogen, which is similar to the unabated coal hydrogen generation route (International Energy Agency, 2023g). This intensity refers to the current average grid, which is dominated by coal. The emissions intensity is highly dependent on the nature of the electricity generation technologies, as is evident in Figure 10 in the 2021 global grid bar (<4 kg CO2-e/kg hydrogen to >35 kg CO2-e/kg hydrogen). As electricity grids are progressively decarbonised through greater shares of renewable energy, the effective emissions from electrolyser-generated hydrogen will diminish. However, large-scale electrolyser hydrogen generation will also occur on standalone projects not connected to networks and may comprise projects explicitly for the generation of hydrogen from renewable electricity (International Energy Agency, 2023g). Figure 10: Comparison of the emissions intensity of different hydrogen production routes, 2021 (production emissions only) BAT: best available technology; CCS: carbon capture and storage; SMR: steam methane reforming; POx: partial oxidation; Median upstr emis: global median value of upstream and midstream emissions in 2021; BAT upstr emis: best-available technology today to address upstream and midstream emissions. Source: International Energy Agency (2023g) Low-emissions hydrogen currently has a cost-premium compared with existing fuels. Figure 11 shows the price differential between liquefied natural gas and carbon neutral and proton exchange membrane (PEM) electrolysis-derived hydrogen in South-East Asia (Japan and Republic of Korea). To displace these existing fuels and reduce the associated emissions requires mechanisms as described above to bridge the cost premium. Figure 11: Price gap between hydrogen and existing fuels Source: S&P Global Commodity Insights To bridge the gap in costs between existing fuels and low-emissions hydrogen in electricity generation, subsidies in the form of cost for difference schemes are being introduced by the governments of Japan and Republic of Korea. These schemes pay a subsidy to mitigate the price gap between technologies. They allow for elastic price differentials and are typically implemented based on an expectation that the price gap will diminish over time as technologies and markets mature. Each of these incentives is likely to be tested by a set of evaluation criteria and is expected to be granted for 15 years (Ministry of Economy and Trade and Industry, 2022). A more detailed description of the schemes is shown in Figure 12. Figure 12: Comparison of the cost for difference subsidy schemes for low-emissions hydrogen and ammonia in Japan and Republic of Korea 1For comparability of the low-carbon hydrogen cost for difference (CfD) scheme, involving only Republic of Koreas clean hydrogen power bidding market here. 2Japans CfD scheme was proposed but not officially launched as of June 2024. SMP: system marginal price. Source: Republic of Koreas Clean Hydrogen Power Bidding Market Overview June 2024, Woodmac The IEA has modelled the economic impact of co-firing hydrogen with natural gas at a typical gas electricity generation plant in Japan, with two capacity factor (CF) assumptions, as shown in (Figure 13; International Energy Agency (2022). Within this model it is assumed that low-emissions hydrogen is sourced from Australia and is coal-based, with production emissions captured and stored. The model shows the significant increases in electricity cost with hydrogen use versus natural gas, which will be mitigated through the cost for difference mechanism when implemented. Figure 13. Levelised cost of electricity for co-firing low-emissions hydrogen in an existing natural gas electricity generation plant in Japan Source: International Energy Agency (2022) While the near-term outlook for low-emissions hydrogen is uncertain due to policy details and supply chain bottlenecks (International Energy Agency, 2023h), it is expected to grow significantly in the next decades. Globally, the demand for low-emissions hydrogen in the electricity generation sector is expected to grow from negligible amounts in 2022 to 14 Mt in 2030 and 42 Mt in 2050 under the NZE by 2050 scenario. Across all industrial sectors, the demand is expected to be 70 Mt in 2030 and 420 Mt in 2050 under the NZE by 2050 scenario, the majority of which is expected to be produced through electrolysis as per IEA analysis, with the remainder from the hydrocarbon sources equipped with CCUS. Section 5 presents a summary of the estimated demand within the Northern Territorys trading partner countries under each IEA scenario (IEA, 2023). 4.1.2 Low-emissions ammonia Around 200 million tonnes of ammonia are produced worldwide each year, only 10% of which is traded on the international market (International Energy Agency, 2021). Around 70% of this production is used to make fertilisers, with the remainder used in other industrial applications such as plastics, explosives and synthetic fibres. Currently, ammonia is predominantly produced from fossil fuels, which accounts for around 2% of total final energy consumption and 1.3% of CO2 emissions from the global energy system (International Energy Agency, 2021). Ammonia is also considered an important energy vector, and together with broader hydrogen-based fuels is included explicitly in the decarbonisation roadmaps and strategies of several countries (e.g. Japan, Republic of Korea and Singapore; IEA, 2023d). Its use is mainly focused on electricity generation, in the form of co-firing in coal-fired electricity generation plants, or using it in pure form in specially designed burners or as a low-emissions fuel in non-road transport (International Energy Agency, 2021). R&D, technology demonstration and pilot testing for ammonia co-firing are being pursued by energy companies in several countries, as summarised in Figure 14. China Energy Group has completed demonstration tests on co-firing of 35% ammonia with coal at the Yantai Power Plant in Shandong Province (Valera-Medina et al., 2023), and JERA is planning demonstration tests for co-firing 20% ammonia with coal at Unit 4 of the Hekinan Thermal Power Station in March 2024 (Jera, 2023). The latter is in line with Japans Green Growth Strategy (Ministry of Economy and Trade and Industry, 2022), which envisages 20% ammonia co-firing in coal plants by 2030 and a combination of 50% ammonia co-fired coal plants and 100% ammonia-fired plants by 2050 (Ministry of Economy and Trade and Industry, 2022). Countries such as Republic of Korea, Thailand and Vietnam have similar targets (Asia Pacific Energy Research Centre, 2023). Figure 14: Ammonia co-firing plans for selected Asia-Pacific Economic Cooperation (APEC) economies Source: Asia Pacific Energy Research Centre (2023) To effectively reduce the emissions and be eligible for any available government rebates, ammonia needs to meet an emissions-intensity test. There is no globally accepted threshold for emissions intensity, but several jurisdictions (e.g. Japan, France, Canada) and intergovernmental organisations (e.g. EU) have proposed ranges to be considered as clean or low-emissions (International Energy Agency, 2023g). For example, Japans threshold is 0.84 kg CO2/kg of ammonia on a gate-to-gate basis (New Zealand Foreign Affairs & Trade, 2023). To put this into context, only ammonia produced from renewable energy-derived hydrogen, biomass or CCUS-enabled natural gas-based routes can meet these criteria, as shown in Figure 15. Figure 15: Emissions intensities of different ammonia production routes (production emissions only) Source: IEA (2023) Low-emissions ammonia currently has a high cost premium over existing unabated sources of ammonia. As an example, in December 2023, the estimated price for natural gas-derived ammonia with CCS was $29/MMBtu, more expensive than Japans imported thermal coal (Figure 16; S&P Global (2024)). Figure 16: Price gap between ammonia and existing fuels Source: S&P Global (2024) The low-emissions ammonia cost premium will increase the cost of electricity generation. Figure 17 shows the typical levelised cost of electricity at different co-firing ratios in Japans coal-fired plants (BloombergNEF, 2022). The range in each ratio is mainly related to the source of the ammonia, with the highest range representing renewable energy-derived ammonia produced in Japan. It is assumed that renewable energy-derived ammonia imported from Australia and natural gas-derived ammonia from the Middle East will be less expensive than domestically produced product for most of the modelled period (BloombergNEF, 2022). Figure 17: Levelised cost of electricity after retrofitting coal-fired power plants for ammonia co-firing compared with new offshore wind in Japan Source: BloombergNEF (2022) Reducing CO2 emissions from coal-fired electricity generation plants by co-firing with low-emissions ammonia can realise an assets life and contribute to emissions reductions, but it is not an efficient method to materially reduce emissions at scale. For example, at 20% co-firing, coal plants still emit almost twice as many emissions per MWh produced as gas turbines, and at 50% their emissions intensity is still higher than combined cycle gas turbine electricity generation (BloombergNEF, 2022). Due to the uncertainty around production rules and available public funding, only 1% of the low-carbon hydrogen capacity announced in Japan and Republic of Korea (1.7 Mtpa in total) has reached final investment decision (S&P Global, 2024). To support CO2 emissions reductions and reduce the risk on suppliers, the Japanese and Republic of Korea governments are both working on a cost for difference subsidy scheme that will cover the gap between existing fuels (coal and gas) and low-emission fuels (Figure 12). It is expected that these support programs, when finalised, will facilitate offtake agreements between low-carbon fuel providers and end users. Co-firing requires a complete restructuring of the ammonia supply chain, in terms of both the volume and carbon intensity. According to JERA, if the 20% co-combustion of ammonia in a single electricity generation plant were to be maintained throughout the year, the annual ammonia demand would be about 500,000 tonnes, which is more than 2.5 times the entire ammonia imports of Japan (Jera, 2023). JERA is planning to import around 2 Mtpa of fuel ammonia in 2030 to co-fire with coal at its electricity generation plants, which is a large portion of Japans 2030 ammonia demand target of 3 Mtpa (New Zealand Embassy, 2023). Under the NZE by 2050 scenario, global low-emissions ammonia demand is forecast to grow to 450 Mt by 2035, of which around 160 Mt will be used as fuel for electricity generation (International Energy Agency, 2023h). Ammonia is also considered a lower-emissions maritime fuel, with a forecasted demand under the same scenario of 90 Mt in 2035 (International Energy Agency, 2023g). Japan and Korea are expected to be two of the main demand drivers for hydrogen-based fuels by 2050, with their electricity generation, transport and industry sectors specifically planning to expand the use of these fuels. In the Announced Pledges scenario, Japan and Koreas combined demand is forecast to be almost 40% of global hydrogen-based fuel imports by 2050 (International Energy Agency, 2023h). The demand for low-emissions ammonia within the Northern Territorys key trading partners is estimated in section 5. 4.2 Iron and steel production The iron and steel industry currently accounts for nearly 8% of global emissions and the industry is under significant pressure to transition to lower emissions technologies and reduce the carbon intensity of its own operations and those of its downstream industries. To meet the climate goals of the Paris Agreement, steel industry emissions must fall by at least 50% by 2050 (International Energy Agency, 2020), while the NZE by 2050 scenario requires the industrys emissions to be reduced by 90%, with residual emissions to be balanced by methods such as bioenergy with CCS and direct air capture (IEA, 2023; International Energy Agency, 2023h). Under the Stated Policies scenario, global demand for iron and steel is forecast to grow by more than one-third to 2050, while the demand growth is much more limited under the Sustainable Development scenario and the NZE by 2050 scenario (International Energy Agency, 2023h). Although low-emissions technologies are currently available and have been tested, they have not been deployed at a commercial scale. Furthermore, the material and infrastructure required for some of these technologies are not readily available. The high degree of competitiveness, capital intensity and longevity of the assets mean that steelmaking is one of the hard-to-abate industries (International Energy Agency, 2020). Figure 18 summarises the roadmap to achieve NZE-compatible emission reductions, as modelled by the IEA (International Energy Agency, 2023a). Figure 18: Mitigation measures for the steelmaking industry under the NZE by 2050 scenario Source: International Energy Agency (2023a) Around 30% of global steelmaking is based on recycling steel scrap, while the remaining 70% is sourced from iron ore. Steelmaking from scrap requires around one-eighth of the energy (in the form of electricity rather than coal) as steelmaking from iron ore, but due to limited supply of scrap metal it cannot meet steel demand. Most iron ore is processed in blast furnaces, which are energy and emissions intensive (IEA, 2020). Iron and steel manufacturing using blast furnace/basic oxygen furnace technology accounts for 95% of the greenhouse gas emissions in the steel value chain, while mining and logistics make up 4% and 1%, respectively (Deloitte, 2024). The global blast furnace fleet is relatively young, with an average age of 13 years, compared with an expected useful life of 40+ years (International Energy Agency, 2020). Most of the young fleet is located in the Asia-Pacific region, as shown in Figure 19 (IEA, 2020). Figure 19: Age profile of global blast furnaces and direct iron reduction furnaces Source: International Energy Agency (2020) While capital inertia is a well-established concept, technological advancements and market preference shifts can cause new technologies to dominate a market and leave behind a fleet of stranded assets. This happened in the steel industry about 60 years ago, when the Linz-Donawitz process, broadly known as basic oxygen furnaces, replaced basic open hearth technology, which constituted 88% of US steel capacity at the time and was worth billions of dollars. The new technology was more cost competitive and environmentally friendly, and the steelmaking industry had access to industrial oxygen at a reasonable cost and large scale (Blank, 2020). The resulting transition dramatically reduced the share of basic open hearth furnaces in US steel capacity from 90% to 10% in 20 years, leaving behind a large group of stranded assets (Blank, 2020); see Figure 20. Figure 20: US steel production capacity, by technology Source: Blank (2020) In the conventional steelmaking process (blast furnace/basic oxygen furnace), nearly 50% of the crude steel production costs are related to the raw materials, with the rest related to capital expenditure, operational expenditure and fuel costs (International Energy Agency, 2023c). Switching to low-emissions technologies is likely to change this proportion and increase the cost of the produced raw steel, the level of which depends on the technology used. Figure 21 shows the cost premium for steel production using low-emissions processes. The IEA estimates a cost premium of 10?50% for low-emissions steel, while BloombergNEFs estimate of green steel premium is about 40% compared with unabated production in 2021 (BloombergNEF, 2023b; International Energy Agency, 2023c). BloombergNEF estimates that the green steel production cost will be 5% less than traditional coal-based methods by 2050 (BloombergNEF, 2023b). While the economics of low-emissions steelmaking technologies are not currently favourable to compete with blast furnace/basic oxygen furnace (International Energy Agency, 2023c), reduced low-emissions energy costs, a higher carbon price, the availability of low-cost/low-emissions hydrogen, access to CCUS and consumer preference will narrow the gap between blast furnace/basic oxygen furnace technology coupled with CCUS, hydrogen-based iron production (direct iron reduction) and electric arc furnaces. . Figure 21: Indicative levelised cost of steel production Source: International Energy Agency (2023c) It is expected that demand for low-emissions steel will start in industries where the cost premium for producing the steel has a small impact on the final product. These are the products where the bulk material costs comprise a relatively small share of the total production cost; some examples are listed in Table 4. Table 4: Impact of steel cost on selected final products Source: International Energy Agency (2023c) Final product Cost increase from 50% increase in cost of steel Electric car 0.5% Residential heat pump 0.2% Offshore wind farm 1% Utility-scale solar photovoltaics 1.5% There has been a significant rise in the supply agreements for low-emissions steel in recent years. The demand has been led by carmakers. BloombergNEF estimates that a 25% increase in the price of steel only raises production costs by 1%. According to BloombergNEFs tracking of green steel procurement agreements, 44% of the agreements are related to the transport sector (BloombergNEF, 2023b). The IEA has tracked more than 60 companies that have committed to low-emissions steel, with at least 10 companies in the automotive sector already committing to use green steel from 2025 (BloombergNEF, 2023b; International Energy Agency, 2023c). The IEA, through its Steel Breakthrough agenda, has requested governments to increase their procurement commitments for near-zero emissions steel. In its most recent update, the IEA has reported modest progress on this, although the increases in demand-side commitments have been insufficient to accelerate major new investments (International Energy Agency, 2023a). Critical to these commitments will be how the demand for low-emissions steel is addressed and the technologies that will be implemented in different jurisdictions, as well as whether these jurisdictions will retrofit existing facilities or choose to write down capital assets in favour of developing new steelmaking facilities. The forecast growth in the green/low-emissions steel market varies widely. IEA analysis suggests a near-zero emissions steel market size of US$90 billion in 2030 and US$900 billion in 2050 (International Energy Agency, 2023a). Table 5 summarises market demand estimates from other selected sources for 2030 and shows the significant variance in the estimates, even in the relative near term. Table 5: Near-zero steel market size estimates, 2030 Estimated market size Forecaster US$47.2 billion Fairfield Market Research US$90 billion IEA US$120 billion Vantage Market Research US$124 billion Precedence Research Japanese steelmakers have been refining blast furnace processes in a bid to realise the asset life of coal-based fleets. However, recent moves indicate potential diversification into hydrogen direct reduction, which may reduce carbon emissions by 80?90% (BloombergNEF, 2023a). Japans largest steelmaker, Nippon Steel, completed development tests that achieved the worlds highest level of CO2 emissions reduction at 33% by injecting heated hydrogen in a month-long trial (Nippon Steel Corporation, 2024). Nippon Steel is also considering shifting from blast furnace processes to electric arc furnace, but has stated concerns over policy support for capital investment and increased production costs (Nippon Steel Corporation, 2023). The Republic of Koreas POSCO has also indicated its commitment to fully convert its domestic steelmaking capacity to hydrogen-based methods and is actively seeking overseas partners with the right resource mix, such as low-cost/low-carbon energy and high-quality iron ore (BloombergNEF, 2023a). Figure 22 shows the net-zero targets and strategic focus of selected Asian steelmakers (BloombergNEF, 2023a). China, which produces around half of all the worlds steel, is also embarking on decarbonisation in the industry, which is responsible for nearly 15% of all CO2 emissions in that country (BloombergNEF, 2023a). Aside from hydrogen direct reduction, Chinese steel companies are pursuing energy efficiency and waste heat recovery, electrification and CCUS in response to the perceived threat from CBAM and in pursuit of international markets with premium consumers, including the automotive industry. Figure 22: The net-zero targets and strategic focus of selected Asian steelmakers Source: BloombergNEF (2023a) Trialling green steel technology is also gaining momentum in Australia, with BHP, Rio Tinto and BlueScope joining an Australian-first collaboration to develop a pilot plant using direct iron reduction technology to remove oxygen from lower grade Pilbara iron ores and an electric smelting furnace to produce liquid iron (BlueScope, 2024). Initially the direct iron reduction process will use natural gas, which is expected to reduce emissions by 60% compared with coal, with a vision to use renewable electricity-derived hydrogen later (BlueScope, 2024). The electricity required for the electric smelting furnace will be supplied from renewable sources. Securing the required natural gas is likely to be a challenge, suggesting any future plant should ideally be in a location with access to natural gas for the transition phase, and ultimately close to low-emissions hydrogen sources (Fuller, 2024). The Northern Territory produces 0.56 Mt (2022?23) of iron ore annually and has an estimated 1 billion tonnes of reserves (see Task 1 Report Rogers et al. (2024b)), with many iron ore reserves close to Darwin (Northern Territory Government, 2024). The presence of iron ore deposits within the Northern Territory could therefore add to regional demand for low-emissions hydrogen for steel. 4.3 Cement production Cement production has been growing faster than the global population since the 1950s as countries have rapidly developed and urbanised. Although there have been major improvements in energy efficiency in the industry, including the use of preheaters to move from wet to dry kilns, the industrys direct emissions still account for 6.4?8.0% of total emissions (Bashmakov and Nilsson, 2020). These emissions can be divided into energy-related emissions (one-third of the total) and process-related emissions (the remaining two-thirds) (International Energy Agency, 2023a). Due to high transport costs as cement is a heavy material, as well as the global availability of limestone, cement is generally produced locally where it is used (International Energy Agency, 2023c). Currently, multiple technologies are being developed to decarbonise the cement industry (Figure 23), including near-term efficiency improvements, CCUS, the use of clinker from non-carbonate sources to avoid calcining, supplementary/alternative cementitious materials, alternative binding materials and fuel substitution (International Energy Agency, 2023a). CCUS is the most advanced technology and can achieve >90% emissions reductions, targeting both the emissions from fossil fuel combustion and the CO2 gas released when limestone is calcined. Alternative technologies are also being developed to produce lower emissions cement without CCUS requirements, although producing a reliable replacement for Portland cement (which is used in 98% of the worlds concrete) remains a challenge. Only some of these new technologies, once commercially available, can fully eliminate CO2 emissions to produce near-zero emissions cement (International Energy Agency, 2023a). To achieve sectoral decarbonisation, a combination of all the methods is required. Given the above-mentioned restrictions, the roadmaps produced by the IEA and the Global Cement and Concrete Association suggest that the industry will remain heavily dependent on CCUS to align its emissions with the NZE by 2050 scenario (Global Cement and Concrete Association, 2021). Figure 23: Emissions reductions by mitigation measure for the cement industry Source: International Energy Agency (2023b) The estimated cost of capture for a commercial-scale cement CCUS plant is US$60?120 per tonne of CO2 (International Energy Agency, 2023a). IEA estimates a 60?110% cost premium for producing low-emissions cement, but this premium is expected to have a relatively small impact on some of the main final products. As an example, a typical house will be about 1% more expensive if built by low-emissions cement. In the NZE by 2050 scenario, the IEA forecasts the near-zero cement market to grow from current negligible values to US$35 billion by 2030 and US$370 billion by 2050 (International Energy Agency, 2023c). Several initiatives have already been formed where the member industries set their targets for purchasing low-emissions cement (International Energy Agency, 2023c). The IEA has tracked the recent wave of commercial-scale project announcements, which are predominantly based on CCUS, although several non-CCUS based projects are in the earlier stages of feasibility studies. The IEAs data reveal that all 14 commercial-scale near-zero emissions cement plants in the planning stage are based on CCUS with dedicated storage. None of these plants was operational as of 2023 and all are in Europe or North America. Several demonstration-scale projects are also progressing in other countries (International Energy Agency, 2023a). The first full-scale CCUS-enabled cement project is the Brevik plant in Norway, which is expected to start production in late 2024. It will capture 0.4 Mt CO2/year, equal to half of the plants emissions (Heidelberg Materials, 2024). The announced low-emissions cement projects with a specific start date by 2030 total about 10 Mt CO2/year. The figure is higher, at 15 Mt CO2/year, if all the announced projects are included. This is less than 10% of the capacity that is needed to be captured and stored by 2020 under the NZE by 2050 scenario (International Energy Agency, 2023c). While there is limited feedstock availability and demand for cement in the Northern Territory there are opportunities to generate alternative fuels for cement manufacture, such as hydrogen. 4.4 Primary chemicals production The chemical sector is the largest industrial consumer of hydrocarbons from which thousands of products are derived. However, since the hydrocarbon inputs are in the form of feedstock, rather than fuel, the sector is only the third-largest CO2 emitter (International Energy Agency, 2023a). Most of the value chains included in the chemical sector are derived from only seven primary chemicals: * ammonia * methanol * the high-value chemicals of ethylene, propylene, benzene, toluene and mixed xylenes. Production of primary chemicals accounts for two-thirds of the energy consumption in the sector. The remaining one-third is divided across the manufacture of thousands of different products. Within the primary chemicals, ammonia production is the largest source of CO2 emissions (45%), followed by methanol and high-value chemicals, with an emissions share of 28% and 27%, respectively (International Energy Agency, 2021). As shown in Figure 24, primary chemicals production was significantly more energy and emissions intensive than the steel and cement industries in 2020. Figure 24: Energy and emissions comparison for primary chemicals and selected other industries Source: International Energy Agency (2021) No single method can deliver the decarbonisation level required under the NZE by 2050 scenario. Electrolytic hydrogen production, CCUS and direct electrification of thermally activated processes are the key technologies to align the sectors emissions with NZE, as shown in the IEAs modelling in Figure 25. Figure 25: Emissions reductions by mitigation measure for the primary chemicals sector Source: International Energy Agency (2021) More than 99% of the ammonia produced in 2020 used coal or natural gas, with natural gas having the highest share (72%). CO2 utilisation is a common method in urea fertiliser production. Globally, steam methane reforming for ammonia production produces roughly 250 Mt of process CO2, of which 130 Mt is captured and used in the subsequent production of urea. This CO2 is released downstream, where it is used in the agricultural sector. The fuel used in the steam methane reforming process generates a diluted CO2 stream that requires additional facilities to capture the CO2. The steam methane reforming production route for ammonia could be considered near-zero emissions if all of the CO2 from both the feedstock and the flue gas were captured and permanently stored. Current technology and costs yield an optimum capture rate of 85?90% (International Energy Agency, 2021). Alternative options to produce low-emissions ammonia includes the electrolysis-based hydrogen route (see the Task 5 report; Czapla et al. (2024)), which makes up a significant portion of recently announced projects. Figure 26 shows planned and announced capacity additions for near-zero emissions ammonia production, as of 2021. Figure 26: Near-zero emissions ammonia production projects Source: International Energy Agency (2021) Global methanol production was about 100 Mt in 2020, emitting approximately 220 Mt CO2 (International Energy Agency, 2021; IRENA and Methanol Institute, 2021). Methanol is one of the key primary chemicals and is used as a fuel (27%) or in the production of a range of chemicals, including polymers (28%), resins (22%) and other products. Similar to ammonia, methanol is considered as one of the alternative fuels to replace oil and gas in shipping and aviation (International Energy Agency, 2023a). More detailed information about methanol production routes is discussed in the Task 5 (Czapla et al., 2024) and Task 9 (Banfield et al., 2023) reports . High-value chemicals are conventionally produced from high-temperature cracking of oil and gas-based petrochemical products. This led to global emissions of around 250 Mt CO2 in 2020. These products can also be produced from methanol replacing oil and gas as feedstock (International Energy Agency, 2024b). High-value chemicals are key components of making plastics. The process to convert high-value chemicals to plastics is also carbon intensive, which makes the carbon footprint of plastics (1.4 Gt CO2/year in 2020) significantly higher than for high-value chemicals (Gabrielli et al., 2023). The IEA estimates that global near-zero emissions primary chemicals production will increase from 14 Mt in 2022 to 145 Mt in 2030 and 816 Mt in 2050 (IEA, 2023). Further information about the demand in the Northern Territorys key trading partner countries is summarised in section 5. 4.5 Aviation Emissions from aviation saw an average growth rate of 2.3% from 1990 to 2019 and passed the 1,000 Mt CO2 mark. COVID-19 had a significant impact on the industry: due to the resultant reduced activity, the industrys emissions dropped by more than 40%, but these subsequently increased in 2022 to reach 80% of their pre-COVID peak (International Energy Agency, 2024a). The increased demand is expected to lead to an average 4% annual growth rate in flight activity until 2050 (International Energy Agency, 2023h). The emissions from the aviation industry are among the most difficult to avoid, due to the industrys need for energy-dense fuels (Bergero et al., 2023). The decarbonisation pathway for the aviation sector includes traffic optimisation measures, energy efficiency gains, consumer behavioural changes and replacing fossil fuels with sustainable aviation fuels (International Energy Agency, 2023e). Consumer behavioural changes are expected to account for almost 20% of energy savings by 2050 under the NZE by 2050 scenario and this dependency on demand reductions is so large that, without it, the required sustainable aviation fuel volumes almost double (International Energy Agency, 2023e). Figure 27 shows the fuel shift required in shipping and aviation to align these sectors with the NZE by 2050 scenario. Figure 27: (Left) Alternative low-emissions fuels required for the aviation industry under the NZE by 2050 scenario. (Right) Consumer behavioural changes play an important role in the amount of sustainable aviation fuels required to decarbonise the aviation industry Source: International Energy Agency (2023e) According to the IEA, sustainable aviation fuels are the most promising option to achieve the deep decarbonisation required in the aviation industry. These range from biojet kerosene (a kerosene substitute produced from biomass) to synthetic kerosene (produced from hydrogen; see the Task 9 report; Banfield et al. (2023)) and sustainable aviation fuels can be blended with conventional oil products at concentrations up to 50%. Tests are in progress to run aircraft on sustainable aviation fuels only. The cost and greenhouse gas savings from sustainable aviation fuels depend on the feedstock and technology used (Advanced Motor Fuels, 2023). While production of sustainable aviation fuels is expected to see a significant increase in the coming years, it accounted for only 0.1% of global aviation fuel in 2022. In the United States, the forecasted production in 2027 is 60 times higher than 2022 levels, but this is still less than the sector targets (Advanced Motor Fuels, 2023). In 2021, ICAO forecast production to grow from negligible amounts to about 3?17 Mt in 2030, in the low and high+ scenarios, respectively (ICAO, 2022) The demand for sustainable aviation fuels within the Northern Territorys five key trading partners is summarised in section 5. 5 Low-emissions products demand estimates While global demand for low-emissions products is modelled by the IEA and updated annually in the World Energy Outlook reports, the IEA does not share country-level details (personal communication with the IEA, 24 July 2024). As a result, a simplified method was adopted to estimate the demand for low-emissions products in each of the Northern Territorys five key trading partners (Japan, Republic of Korea, China, Singapore and Taiwan). To be consistent, where possible all information used was derived from IEA datasets. There are many datasets available from various providers and during the course of the wider study differences have been observed across these datasets, the source of which cannot be conclusively ascertained. While every effort has been made to ensure that demand estimates are consistent across the project results, there will be differences based on the dataset used. For clarity, the origin of the data used is described in each case. The low-emissions product demand estimates described below are estimates only based on forecast models, which have inherent uncertainty. The purpose of the estimation is to understand the possible amount and range in the demand for low-emissions products, not absolute numbers. The methods used here to estimate demand differ from those used in the Task 2 report (Rogers et al., 2024a), but these task results should be considered as complementary to each other in that they provide a greater number of forecasts of demand. The estimation method principally relies on the officially reported most recent activity indicators (electricity generation, steel, cement and chemicals production, billions of passenger kilometres for air travel) for each country as the starting point. These indicators are then forecast up to 2050. When country-level forecast growth rates for the indicators are available, they are used in the analysis. Otherwise, it was assumed that their growth follows the global average forecast trends. A similar approach was taken for estimating the low-emissions products adoption rate to meet the decarbonisation targets. Figure 28 outlines the methodology used to estimate low-emissions product demand. Figure 28: Simplified method to estimate country-level demand for low-emissions products based on IEA models As noted above, this simplified methodology aims to show the range of possible demand for products, rather than specifically predicting the future demand. For this reason, demand estimates were undertaken under four different scenarios, as modelled by the IEA: * Stated Policies scenario (STEPS) (International Energy Agency, 2023d) * Announced Pledges scenario (APS) (International Energy Agency, 2023d) * Net Zero Emissions by 2050 scenario (NZE) (International Energy Agency, 2023d) * Sustainable Development scenario (SDS); although this scenario has been excluded in the recent IEA reports (IEA, 2024b). More information about these scenarios can be found on the IEA website. Decarbonisation pathways and low-emissions products demand are likely to be updated every year, as actual progress diverges from the models and the models are updated. Slow progress in early years will require a much higher decarbonisation effort (including low-emissions products) in later years to meet NZE by 2050 emissions goals. 5.1 Electricity generation Electricity generation data for Japan, Republic of Korea, China, Singapore and Taiwan were collected from official sources or the IEA website. Forecast unabated thermal electricity generation from coal and gas were selected as the main activity indicators, as these are the areas that require low-emissions products (Figure 29). Data for the proportion of forecast CCUS-enabled thermal generation were also collected to understand the proportion of thermal generation emissions that would be captured (Figure 29). Global average growth trends were used to project the country-level activity indicators to 2030, 2040 and 2050. Figure 29: Forecast of combined thermal electricity generation in the Northern Territorys five key trading partners by route Low-emissions hydrogen and hydrogen-based fuels demand forecasts were available for Japan and the Republic of Korea under the Stated Policies and Announced Pledges scenarios. In the absence of more specific data, and given the relatively advanced state of clean hydrogen policies in the two countries, it was assumed that the combined demand of Japan and the Republic of Korea will be the same under the Announced Pledges, Sustainable Development and NZE by 2050 scenarios. For the other countries, hydrogen and hydrogen-based fuels demand was estimated based on the forecasted global average demand per TWh of produced electricity (PJ H2/TWh) from unabated coal and gas. CCUS demand was estimated based on the forecasted CO2 emissions from the CCUS-enabled coal and gas-fired electricity generation plants. The estimate was based on the global average coal and gas plant efficiency, and emissions factor for coal and gas combustion (Australian Government, 2023b). Table 6 shows the summary results of the combined demand estimates for Japan, Republic of Korea, China, Singapore and Taiwan for the electricity generation sector for CCUS and hydrogen-based fuels in 2030 and 2050 across the range of IEA emissions reduction scenarios. Table 6: Simplified projection of low-emissions product demand in 2030 and 2050 in the electricity generation sectors of the Northern Territorys five key trading partners 2030 2050 STEPS APS SDS *2021 NZE STEPS APS SDS *2021 NZE CCUS (Mt CO2) 2 14 150 106 15 345 820 342 Hydrogen and hydrogen-based fuels (Mt H2 eq) 1 2 2 8 4 14 19 12 5.2 Iron and steel production While the Northern Territory has iron ore reserves and has both significant energy resources and CCS potential that can benefit future low-emissions iron and steel manufacturing, assessing the feasibility of this option is beyond the scope of this report. The Northern Territory can, however, supply the low-emissions products and abatement solutions required by its trading partners in the form of low-emissions hydrogen-based fuels and CCUS. To estimate the potential market for these products, crude steel production data for Japan, Republic of Korea, China, Singapore and Taiwan were collected and projected to 2050. The projection was based on the forecast steel production data for China, which currently constitutes 85% of steel production in the key trading partners and is the largest steel producer in the world. Japan and Republic of Korea rank third and sixth for global steel production, respectively, and have a stated ambition to maintain or grow their steel industries (Nippon Steel Corporation, 2022). Due to the lack of published information, it was assumed that steel production in China under the NZE by 2050 scenario follows the same trajectory as the Sustainable Development scenario. Production in other countries was assumed to follow global growth trends (Figure 30). Figure 30: Forecast of combined steel production in the Northern Territorys five key trading partners. Note that Chinas steel production forecasts for the Announced Pledges scenario were not available in the published IEA reports. Global decarbonisation trajectories (Mt CO2 captured/Mt steel production, Mt hydrogen/Mt steel production) were applied to each country to estimate its CCUS and low-emissions hydrogen requirements to support the steel industry. The data for the Announced Pledges scenario were not available, hence the corresponding values in Table 7 are not estimated; and the data at the sector level were not available for the Stated Policies scenario, so the values were conservatively set to zero.6 The summary results of the combined demand estimates for CCUS and hydrogen-based fuels in each countrys iron and steel sector are shown in Table 7 across the range of IEA emissions reduction scenarios. Table 7: Simplified projection of low-emissions product demand in the steel sector of the Northern Territorys five key trading partners 2030 2050 STEPS APS SDS *2021 NZE STEPS APS SDS *2021 NZE CCUS (Mt CO2) 0 10 17 0 192 249 Hydrogen and hydrogen-based fuels (Mt H2 eq) 0 2 3 0 42 39 5.3 Cement production A feasibility study to assess the possibility of producing low-emissions cement in the Northern Territory is beyond the scope of this report. However, the Northern Territory can support the decarbonisation ambitions of its trading partners by supplying low-emissions hydrogen and CCUS. The estimation process included collecting cement production data for Japan, Republic of Korea, China, Singapore and Taiwan and projecting to 2050 using global trends. When specific data were available for each country, they were included in the analysis. The IEAs projections of cement production in China for the Stated Policies, Announced Pledges and Sustainable Development scenarios were directly input into the analysis. Global decarbonisation trajectories were applied to the other countries to estimate their CCUS and low-emissions hydrogen requirements to support the cement industry. The summary results of the combined demand estimates for CCUS and hydrogen-based fuels in each countrys cement sector are shown in Table 8 across the range of IEA emissions reduction scenarios. Table 8: Simplified projection of low-emissions products demand in the cement sector of the Northern Territorys five key trading partners 2030 2050 STEPS APS SDS *2021 NZE STEPS APS SDS *2021 NZE CCUS (Mt CO2) 0 131 86 0 596 665 Hydrogen and hydrogen-based fuels (Mt H2 eq) 0.3 2.1 5.4 Primary chemicals production The chemical sectors decarbonisation strategies include using low-emissions alternatives for feedstock, as well as using low-emissions fuels and CCUS. The Northern Territory is well positioned to provide most of these products and services. To estimate the market size for these products, production data for the main chemicals (ammonia, methanol, ethylene and propylene) were collected for Japan, Republic of Korea, China, Singapore and Taiwan. As the list of chemicals is not comprehensive, the results are expected to be conservative. Projections of feedstock demand were carried out by category (separate trajectories for ammonia, methanol and high-value chemicals). Global CCUS demand was applied to each country. The summary results of the combined demand estimates for CCUS and hydrogen-based fuels in each countrys primary chemical sector are shown in Table 9 across the range of IEA emissions reduction scenarios. Table 9: Simplified projection of low-emissions products demand in the chemical sector of the Northern Territorys five key trading partners 2030 2050 STEPS APS SDS *2021 NZE STEPS APS SDS *2021 NZE CCUS (Mt CO2) 0 15 0 102 Feedstock Ammonia (Mt) 62.4 58.9 58.9 73.2 65.8 65.8 Methanol (Mt) 88 Mt @2022 for key trading partners Global demand: >100 Mt ? projected to increase up to 500 Mt by 2050* *Global demand is projected to increase dramatically from 100 Mt to 500 Mt due to more adaptation in the transportation sector, as well as growth in the methanol-to-olefin (MTO) route as an alternative to traditional production of ethylene and propylene through petrochemical routes. MTOs share increased from almost 0% of global consumption in 2010 to 25% in 2020 (IRENA and Methanol Institute, 2021). 5.5 Aviation To estimate the sustainable aviation fuels market size in Japan, Republic of Korea, China, Singapore and Taiwan, domestic and international aviation data were collected from each country and projected to 2050 based on global growth trends (ICAO, 2021). For the estimation, 2019 data were used, as the latest data appear to still carry some impacts from COVID-19 at the country level (Figure 31). Figure 31: Forecast of combined increases in flown passenger km in the Northern Territorys five key trading partners for different emissions reduction scenarios. Note that the forecast is not available for Sustainable Development scenario. The Stated Policies and Announced Pledges scenario forecasts are close, but not identical. Sustainable aviation fuels are grouped into three classes: * biofuel * hydrogen * synthetic kerosene. Global decarbonisation trajectories were applied to the key trading partners. The aviation decarbonisation roadmap relies on the previously discussed measures, as well as demand reductions from consumer behavioural changes. As such, the market sizes presented assume some level of energy savings from behavioural changes. The summary results of the combined demand estimates for each countrys aviation sector are shown in Table 10 across the range of IEA emissions reduction scenarios. Table 10: Simplified projection of sustainable aviation fuels demand in the Northern Territorys five key trading partners 2030 2050 STEPS APS SDS *2021 NZE STEPS APS SDS *2021 NZE Biofuel (PJ) 137 229 309 444 1,038 1,004 Hydrogen (PJ ) 0.0 0.0 0.0 9.3 102.4 278.1 Synthetic kerosene (PJ ) 3.5 7.0 29.3 12.5 636.0 1,127.7 6 Demand estimate summary The methodology to estimate the demand for low-emissions products is primarily based on the results of Task 2 (Rogers et al., 2024a), where the point-source emissions for each of the Northern Territorys five key trading partners (Japan, Republic of Korea, China, Singapore and Taiwan) were collected and analysed. The top emitting industries (electricity generation, iron and steel, cement and chemicals) accounted for approximately 95% of the total energy-related point-source emissions. It was assumed that demand for low-emissions products will be driven by these industries. The aviation sector was also analysed to estimate the low-emissions fuel required for decarbonising the sector. The purpose of the estimate was to show the range of possible demand for products, rather than specifically predicting the future demand. The decarbonisation roadmaps modelled by the IEA were used to estimate the technological adaptation rate in each sector, for each country and under each decarbonisation scenario. As expected, the demand for low-emissions products is the lowest under the State Policies scenario and highest in most cases under the NZE by 2050 scenario. Due to the observed differences between the databases, and to be consistent throughout the estimation process, an attempt was made to source all the required information from the IEA, although there were gaps in the data that were filled with data from other sources. Table 11 summarises the potential low-emissions products, and whether they are included in the assessment. Table 11: Inclusions in estimates of low-emissions product demand Sector Products included in the assessments Products excluded from the assessments Electricity generation Hydrogen, hydrogen-based fuels and CCUS Direct electricity export Iron and steelmaking Hydrogen, hydrogen-based fuels and CCUS Production of low-emissions steel in the Northern Territory Cement production Hydrogen, hydrogen-based fuels and CCUS Production of low-emissions cement in the Northern Territory Chemical production Ammonia, methanol Other low-emissions chemicals Aviation Biofuel, hydrogen, synthetic kerosene Any other alternatives Globally, the demand for low-emissions hydrogen in the electricity generation sector is expected to grow from negligible amounts in 2022 to 14 Mt in 2030 and 42 Mt in 2050 under the NZE by 2050 scenario. As shown in , the demand for hydrogen and hydrogen derivatives in this sector for the Northern Territorys five key trading partners using the NZE by 2050 scenario represents 57% of total forecast global demand in 2030 and 28.5 % of global forecast demand in 2050 (summing to 8 and 12 Mt hydrogen, respectively). The NZE by 2050 scenario is the most aggressive emissions reduction scenario used for demand estimates. However, while the Announced Pledges and Sustainable Development scenarios have lower gross demand estimates in 2030, they exceed the NZE demand estimates in 2050 (Table 12). Table 12: Simplified projection of low-emissions product demand for the Northern Territorys five key trading partners 2030 2050 STEPS APS SDS *2021 NZE STEPS APS SDS *2021 NZE Hydrogen and hydrogen-based fuels (Mt H2 eq) Electricity generation 1 2 2 8 4 14 19 12 Steel 0 2 3 0 42 39 Cement 0 0.3 0 2.1 Primary chemical feedstock (Mt) Ammonia* 62.4 58.9 58.9 73.2 65.8 65.8 Methanol 88 Mt @ 2022 for the trading partners Global demand: >100 Mt 2024 ? projected to increase up to 500 Mt by 2050 ** Sustainable aviation fuel (PJ) Biofuel 137 229 309 444 1,038 1,004 Hydrogen 0 0 0 9.3 102 278 Synthetic kerosene 3.5 7.0 29 0.0 636 1,128 CCUS (Mt CO2) by sector Electricity generation 2 14 150 106 15 345 820 342 Steel 0 10 17 0 192 249 Cement 0 131 86 0 596 665 Chemicals 0 15 0 102 * The Sustainable Development scenario assumes savings in ammonia demand in the chemical feedstock, mainly due to fertiliser use efficiency and plastic recycling (International Energy Agency, 2021). **Global demand is projected to increase dramatically from 100 Mt to 500 Mt due to more adaptation in the transportation sector, as well as growth in the methanol-to-olefin (MTO) route as an alternative to the traditional production of ethylene and propylene through petrochemical routes. MTOs share increased from almost 0% of global consumption in 2010 to 25% in 2020 (IRENA and Methanol Institute (2021). Globally, in the NZE by 2050 scenario across all industrial sectors, the demand for low-emissions hydrogen is 70 Mt in 2030 and 420 Mt in 2050, the majority of which is expected to be produced through electrolysis, with the remainder from the methane thermochemical sources equipped with CCUS. Even considering only the electricity generation, steelmaking and cement production sectors of the key trading partners, the demand estimates presented here represent 16% of the total global hydrogen market by 2030 and 12.6% of the market in 2050. There will be additional demand from these jurisdictions from other sectors, including the aviation, other transport (e.g. hydrogen for fuel cells and ammonia for maritime) and primary chemicals sectors (Table 12). Around 200 Mt of ammonia are currently produced worldwide each year, only 10% of which is traded on the international market. Under the NZE by 2050 scenario, global annual ammonia demand is forecast to grow to 204 Mt by 2030 and 228 Mt in 2050. For the key trading partners, low-emissions ammonia demand estimates represent about 29% of the global demand in both 2030 and 2050. The Stated Policies (and Sustainable Development) scenario demands estimates exceed the NZE-derived estimates of demand, reflective of the drivers and policies enacted for ammonia use, particularly by Japan and Republic of Korea. Specific demand estimates cannot be ascertained for methanol and high-value chemicals due to insufficient data being available. The majority of current global methanol demand comes the five key trading partners. Total global demand for methanol is expected to grow rapidly through to 2050, from 100 Mtpa to 500 Mtpa. Under the NZE by 2050 scenario, emissions from the chemical sector will need to drop by 21% by 2030 and 96% by 2050 so there will be strong demand for low-emissions methanol feedstock for the chemical industry in the region. Currently, the aviation sector consumes approximately 280 Mt (11,000 PJ) of oil-based fuels (IATA, 2024; International Energy Agency, 2023h). Based on IEA modelling, the annual demand for sustainable aviation fuels under the NZE by 2050 scenario reaches 1,700 PJ in 2030 and 11,900 PJ in 2050 (IEA, 2023). Of this estimated global demand, about 20% is derived from the five key trading partners in both 2030 and 2050. The gross Stated Policies and Announced Pledges scenarios demand forecasts are somewhat lower than the NZE by 2050 scenario in 2030 but have higher demand in 2050. There is significant forecast demand for CCUS in the electricity generation, iron and steel, cement and primary chemicals sectors in all but the Stated Policies scenario in 2030 and 2050. Total CCUS demand from the five key trading partners was estimated for these sectors. Other sources of CO2, such as liquefied natural gas production in other states and countries, are not covered in this assessment and they may provide opportunities for the Northern Territory that are excluded from the analysis. The estimated demand shown here differs from that determined in the Task 2 report (Rogers et al., 2024a) for 2030. The CCUS demand using the Stated Policies, Sustainable Development and NZE by 2050 scenarios has been plotted alongside Asia-Pacific Economic Cooperation (APEC) and Rystad energy CO2 demand projections (Figure 32).IRENA and Methanol Institute (2021) Here the analysis has used IEA scenarios based on country-level reporting of sectorial emissions. In the Task 2 report, existing point-source emissions were used to estimate total 2030 CO2 emissions, the emissions further than 50 km from suitable ports were removed and then the IEA NZE technology road maps were applied to each of those sectors. These methods and the differences in the reported datasets lead to differences in the demand estimates across the reports. The differences in methodologies allow an appreciation of the possible ranges in CCUS demand, which in both cases is large. The estimates of low-emissions product demand have shown that under IEA scenarios there is strong demand from the key trading partners in the near (2030) and long term (2050). Much of this demand will be driven by China due to the size of its economy and associated emissions, but there are also important demand contributions from the other trading partners. Figure 32: CCUS demand in the analysed sectors, compared with estimates from other sources. The dotted lines are for illustration purposes. The figure presents a summary of the estimated CCUS demand in NT main trade partner countries, from several sources. This includes: Simplified method presented above, based on IEA scenarios, noting that SDS does not include demand from Chemicals sector for IEA scenarios (STEPS, SDS, NZE), APEC models (Reference case, which reflects current policies and trends Carbon neutral case, which explores hypothetical decarbonization pathways, and Rystad (up to 2030) CCUS demand Source: IRENA and Methanol Institute (2021) Although some of the demand for low-emissions products will be met by the countries themselves (e.g. electrolyser-derived hydrogen), due to the scale of the demand, current levels of energy imports and the natural resources available there will be significant opportunities for Northern Territory exports of low-emissions products. 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Contact us 1300 363 400 +61 3 9545 2176 csiro.au/contact csiro.au For further information CSIRO Energy Andrew Ross +61 8 6436 8790 Andrew.Ross@csiro.au csiro.au/Energy 1 US Clean Hydrogen Production Tax Credit [0.45 to 4.0 kg CO2e/kg hydrogen] 2 China Clean Hydrogen 3 For the rest of this report we focus our analysis on the price of ACCUs, as the price of large-scale generation certificates and small-scale technology certificates is linked to the renewable energy target, which as of August 2024 is set to be phased out in 2030 (Clean Energy Regulator, 2024). 4 US clean hydrogen production tax credit (0.45 to 4.0 kg CO2e/kg hydrogen) 5 China clean hydrogen 6 The global CCUS demand in the Stated Policies scenario for all industrial sectors (iron and steel, chemicals, cement, pulp and paper) is estimated to be 15 Mt in 2030 and 108 Mt in 2050. --------------- ------------------------------------------------------------ --------------- ------------------------------------------------------------ Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub | i ii | CSIRO Australias National Science Agency