第三部分：绿氢成本和潜力报告（英）-IRENA.pdf

GLOBAL HYDROGEN TRADE TO MEET THE 1.5C CLIMATE GOAL PART III GREEN HYDROGEN COST AND POTENTIAL IRENA 2022 Unless otherwise stated, material in this publication may be freely used, shared, copied, reproduced, printed and/or stored, provided that appropriate acknowledgement is given of IRENA as the source and copyright holder. Material in this publication that is attributed to third parties may be subject to separate terms of use and restrictions, and appropriate permissions from these third parties may need to be secured before any use of such material. ISBN 978-92-9260-432-5 Citation IRENA 2022, Global hydrogen trade to meet the 1.5C climate goal Part III – Green hydrogen cost and potential, International Renewable Energy Agency, Abu Dhabi. Acknowledgements This report was authored by Jacopo de Maigret, Edoardo Gino Macchi Fondazione Bruno Kessler and Herib Blanco IRENA under the guidance of Emanuele Taibi and Roland Roesch. Technical support was provided by Luca Prattic Fondazione Bruno Kessler. The report was produced under the direction of Dolf Gielen Director, IRENA Innovation and Technology Centre. This report benefited from input and review of the following experts. David Armaroli, Filippo Bartoloni, Paola Brunetto, Ludovico Del Vecchio, Lodovico Della Chiesa d’Isasca, Matteo Moraschi, Michele Scaramuzzi, Irene Varoli, and Marco Zampini Enel; Carlo Napoli Enel Foundation, Laurent Antoni French Alternative Energies and Atomic Energy Commission, Georgia Kakoulaki Joint Research Centre, Bilal Hussain and Paul Komor IRENA, Brandon McKenna Mrsk Mc-Kinney Mller Center for Zero Carbon Shipping. The report was edited by Erin Crum. Report available online www.irena.org/publications For questions or to provide feedback publicationsirena.org IRENA is grateful for the scientific support from the Enel Foundation and the Fondazione Bruno Kessler in producing this publication. IRENA is grateful for the support of the Ministry of Economy, Trade and Industry METI of Japan in producing this publication. Disclaimer This publication and the material herein are provided “as is”. All reasonable precautions have been taken by IRENA to verify the reliability of the material in this publication. However, neither IRENA nor any of its officials, agents, data or other third-party content providers provides a warranty of any kind, either expressed or implied, and they accept no responsibility or liability for any consequence of use of the publication or material herein. The information contained herein does not necessarily represent the views of all Members of IRENA. The mention of specific companies or certain projects or products does not imply that they are endorsed or recommended by IRENA in preference to others of a similar nature that are not mentioned. The designations employed and the presentation of material herein do not imply the expression of any opinion on the part of IRENA concerning the legal status of any region, country, territory, city or area or of its authorities, or concerning the delimitation of frontiers or boundaries.GLOBAL HYDROGEN TRADE TO MEET THE 1.5C CLIMATE GOAL PART III – GREEN HYDROGEN COST AND POTENTIAL 3 TABLE OF CONTENTS ABBREVIATIONS 5 EXECUTIVE SUMMARY 6 CONTEXT OF THIS REPORT AND WHAT TO EXPECT 9 1 INTRODUCTION 12 2 METHODOLOGY 15 Geographical constraints and exclusion criteria 17 Techno-economic assumptions 19 3 LEVELISED COST OF HYDROGEN AROUND THE WORLD 24 Optimal combination of renewable energy sources and electrolysers 25 Global LCOH maps and potential 31 REFERENCES 414 FIGURES FIGURE 0.1. Global supply-cost curve of green hydrogen for the year 2050 under optimistic assumptions 7 FIGURE 0.2. Scope of this report series in the broader context of IRENA publications 9 FIGURE 1.1. Types of renewable energy potentials and applicable constraints 13 FIGURE 2.1. Land type distribution and suitability for variable renewable energy for a selection of countries 18 FIGURE 2.2. Percentage of land excluded for onshore wind left and utility-scale PV right due to land exclusion criteria 19 FIGURE 2.3. Full-load hours achievable depending on area for offshore wind deployment in the North Sea and expected yield in terawatt hours 21 FIGURE 2.4. Capital cost trends for renewable technologies towards 2050 under optimistic assumptions and benchmark with other studies 22 FIGURE 2.5. Range of WACC by technology and scenario 23 FIGURE 3.1. Comparison between levelised cost of solar- and wind-produced hydrogen as function of annual capacity factor and optimal ratio 26 FIGURE 3.2. Difference in onshore wind potential by resource quality in Chile, Germany and Saudi Arabia in GW 27 FIGURE 3.3. Relationship between LCOH and renewable to electrolyser capacity as a function of capacity factor for 2030 and 2050 29 FIGURE 3.4. Optimal hybrid system configurations dots in 2050 as a function of CAPEX of the generation technologies for Germany green lines and Australia blue lines 30 FIGURE 3.5. Breakdown of hydrogen production by renewable technology for selected countries 31 FIGURE 3.6. Comparison between economic potential of green hydrogen supply below USD 2/kgH 2 and forecast hydrogen demand, in EJ/year, by 2050 32 FIGURE 3.7. Global map of levelised cost of green hydrogen in 2030 considering water scarcity 33 FIGURE 3.8. Ratio between the potential domestic production of green hydrogen and the predicted 2050 hydrogen demand for countries with highest forecast hydrogen demand in 2050 34 FIGURE 3.9. Green hydrogen supply-cost curves for selected African countries in 2050 36 FIGURE 3.10. Levelised cost of hydrogen range in 2050 derived from supply-demand analysis 37 FIGURE 3.11. Global supply-cost curve of green hydrogen for the year 2050 under optimistic assumptions 38 FIGURE 3.12. Global map of levelised cost of green hydrogen in 2050 considering water scarcity 39 FIGURE 3.13. Effect of water constraints on land eligibility for on site production of green hydrogen 40 TABLES TABLE 3.1. Classification of resource quality for each renewable technology 25 BOXES BOX 2.1. Impact of offshore wind capacity expansion on capacity factor 20 BOX 3.1. Africa’s green hydrogen potential 34GLOBAL HYDROGEN TRADE TO MEET THE 1.5C CLIMATE GOAL PART III – GREEN HYDROGEN COST AND POTENTIAL 5 ABBREVIATIONS CAPEX capital expenditure CF capacity factor ECMWF European Centre for Medium-Range Weather Forecasts EJ exajoule FLOH full-load operating hours G20 Group of 20 GW gigawatt HHV higher heating value IRENA International Renewable Energy Agency kgH 2 kilograms of hydrogen km 2 square kilometre kW kilowatt kW e kilowatt electric kWh kilowatt hour LCOE levelised cost of electricity LCOH levelised cost of hydrogen m 3 cubic metre MENA Middle East and North Africa MtH 2 million tonnes of hydrogen MW megawatt MWh megawatt hour OPEX operational expenditure PV photovoltaic TW terawatt USD United States dollars WACC weighted average cost of capital6 EXECUTIVE SUMMARY Hydrogen is an essential component of a net zero energy system. It provides an alternative to decarbonise sectors that are difficult to electrify such as heavy industry and long-haul transport. Electrolytic hydrogen produced through renewables green hydrogen is the most sustainable hydrogen production technology. It allows sector coupling with the power sector providing additional flexibility to integrate variable renewable energy, and it provides an alternative for seasonal storage of energy and provision of capacity adequacy. One of the main challenges that green hydrogen faces today is its higher cost compared with fossil fuels and other alternative low-carbon technologies. With technology innovation to improve performance, deployment to increase global scale, larger electrolyser plants and continuous decrease in renewable power cost, which is the main cost driver, green hydrogen is expected to reach cost parity with fossil-derived hydrogen within the next decade. This report explores the global cost evolution of green hydrogen towards 2030 and 2050. For this, a geospatial approach is used since the renewable resources are highly dependent on the location. The world is divided in pixels of roughly 1 square kilometre km 2 , and the optimal configuration among renewable generation technologies solar PV, onshore wind and offshore wind and the electrolyser is determined to achieve the lowest production cost. The cost is based on the assumption of dedicated off-grid plants and refers only to production without hydrogen transport to the coastline or potential consumption site. The potential for a specific country or region is based on the land available, for which various exclusion zones are applied including protected areas, forests, wetlands, urban centres, slope and water scarcity, among others. This allows estimating both the production cost and the potential for green hydrogen for every region. The green hydrogen technical potential considering these land availability constraints is still almost 20 times the estimated global primary energy demand in 2050. Green hydrogen potential, however, is not a single value; it is a continuous relationship between cost and renewable capacity Figure 0.1. In terms of production cost, this is directly dependent on the cost of the renewable input major cost driver, the electrolyser and the WACC. In 2050, almost 14 terawatts TW of solar PV, 6 TW of onshore wind and 4-5 TW of electrolysis will be needed to achieve a net zero emissions energy system. Thanks to these deployments, technology costs are expected to decrease dramatically because of innovation, economies of scale and optimisation of the supply chain. In this future, green hydrogen production could reach levels of almost USD 0.65/kg of hydrogen kgH 2 for the best locations in the most optimistic scenario. In a more GLOBAL HYDROGEN TRADE TO MEET THE 1.5C CLIMATE GOAL PART III – GREEN HYDROGEN COST AND POTENTIAL 7 pessimistic scenario with higher technology costs, still for 2050, the lowest production cost is USD 1.15/kgH 2 increasing to USD 1.25/kgH 2 to meet a demand of 74 exajoules EJ per year. While global green hydrogen potential is more than enough, there are specific countries where potential is restricted and where domestic production might not be enough to satisfy domestic demand. Due to the nature of their territory, Japan and the Republic of Korea are the most restricted 91 of Japan’s total country land and 87 of the Republic of Korea’s total country land is excluded for hydrogen production. The Republic of Korea would need to use about one-third of its renewable potential to satisfy its domestic energy demand in 2050. However, once the electricity consumption is considered, there is hardly any left for hydrogen production. The technical potential for Japan is about 380 gigawatts GW of PV and 180 GW of onshore wind, which would be enough to produce about 20 million tonnes of hydrogen MtH 2 per year of hydrogen below USD 2.4/kgH 2 . The quality of the resources is relatively poor less than 14 for the majority of PV and less than 30 for wind and most of this potential is used to satisfy electricity demand rather than hydrogen. Other countries that would require a relatively high share of their renewable potential to satisfy their domestic hydrogen demand are India 89 of the land is excluded mainly due to population density, cropland, savannahs and forests; Germany 66 excluded mainly by forests and cropland; Italy 62 excluded mainly due to slope, population density and croplands; and Saudi Arabia 94 excluded mainly due to water stress. FIGURE 0.1. Global supply-cost curve of green hydrogen for the year 2050 under optimistic assumptions              
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   apaEJ Gba   ma7EJ Gbap ma  upp 6EJ Notes MENA Middle East and North Africa. Optimistic assumptions for 2050 CAPEX are as follows PV, USD 225/ kilowatt kW to USD 455/kW; onshore wind, USD 700/kW to USD 1 070/kW; offshore wind, USD 1 275/kW to USD 1 745/kW. WACC per 2020 values without technology risks across regions. Electrolyser CAPEX and efficiency set to USD 134/kW e and 87.5 higher heating value [HHV]. Technical potential has been calculated based on land availability considering several exclusion zones protected areas, forests, permanent wetlands, croplands, urban areas, slope of 5 [PV] and 20 [onshore wind], population density and water stress.8 Water is used as input to electrolysis, and it is perceived as one of the critical parameters for green hydrogen production. In water- scarce regions, desalination could be used. Even in regions far from the coastline, water transport could be considered, which will increase the cost of water supply, but it will still represent a relatively small share of the total hydrogen production cost, reaching levels of USD 0.05/kgH 2 and representing 1-2 of the energy consumption of the electrolyser. The regions where this constraint restricts the hydrogen potential the most are Saudi Arabia 92 reduction; the Middle East 83 reduction; Morocco 63 reduction; and the rest of Asia 61 reduction. Even then, the potential remains relatively vast. The reduced PV potential in Saudi Arabia would still be enough to produce about 190 MtH 2 /year and Morocco would represent the smallest one from these regions and still be able to produce about 90 MtH 2 /year. The main uncertainties for the analysis lie in the cost levels and, in particular, the evolution of CAPEX for renewables, and electrolysis and the WACC towards 2050. On the one hand, technology will continue to progress, and deployment will lead to optimisation of global supply chains, standardisation and faster execution. On the other hand, as the system transitions to fixed capital assets rather than fuels, cycles in commodity prices such as the one experienced in 2021 can lead to periods of higher capital costs although with a smaller impact on energy prices since it would be affecting only new assets. The floor costs for the various technologies are not yet known with certainty. If solar PV cost continues its recent trend and electrolyser costs also achieve low levels, PV-dominated can become more cost-effective. Multiple countries in sub-Saharan Africa, the Middle East and Latin America have vast renewable potential and the main uncertainty in their cost levels is how much they will be able to decrease their high WACCs towards 2050. This proved to be more critical in defining the cost differential among countries than the quality of the renewable resource.GLOBAL HYDROGEN TRADE TO MEET THE 1.5C CLIMATE GOAL PART III – GREEN HYDROGEN COST AND POTENTIAL 9 CO