GREEN HYDROGEN IN DEVELOPING COUNTRIES This report was researched and prepared by staff and consultants at the Energy Sector Management Assistance Program (ESMAP), part of the World Bank. The work was funded by ESMAP and the World Bank. The authors and main contributors to the report were Fernando de Sisternes (Task Team Leader and Energy Specialist, ES- MAP) and Christopher Jackson (Consultant, ESMAP). The authors thank peer reviewers Demetrios Papathanasiou (Practice Manager, World Bank), Rafael Ben (Energy Specialist, World Bank), Peter Mockel (Principal Industry Specialist, IFC), Pierre Audinet (Lead Energy Specialist, World Bank), Manuel Millan (Senior Energy Special- ist, World Bank), Gabriela Elizondo (Senior Energy Specialist, World Bank), Daniel Roberts (CSIRO), Jenny Hayward (CSIRO), Chris Munnings (CSIRO), and Jenifer Baxter (IMechE), who gave their time and comments to drafts of this report. The authors wish to express their gratitude to Rohit Khanna (Practice Manager, ESMAP), Zuzana Dobrotkova (Senior Energy Specialist, ESMAP), Ivan Jaques (Senior Energy Specialist, ESMAP), Sandra Chavez (Consultant, ESMAP), and Elizabeth Minchew (Associate Operations Officer, IFC) for their valuable comments throughout different stages of this report. The authors also wish to thank Marjorie Araya (Program Assistant, ESMAP), Pauline Chin (Senior Program Assistant, ESMAP), and Melissa Taylor (Program Assistant, ESMAP) for their invaluable support, and Ashley Young (Publications Professionals), Linda Stringer (Publications Professionals), Marcy Gessel (Publications Professionals), and Debra Naylor (Naylor Design) for their editorial and design work. © 2020 International Bank for Reconstruction and Development/The World Bank 1818 H Street NW, Washington, DC 20433 | USA 202-473-1000 | www.worldbank.org This work is a product of the staff of the World Bank with external contributions. The findings, interpretations, and conclusions expressed in this work do not necessarily reflect the views of the World Bank, its Board of Executive Directors, or the governments they represent. The World Bank does not guarantee the accuracy of the data included in this work. The boundaries, colors, denominations, and other information shown on any map in this work do not imply any judgment on the part of the World Bank concerning the legal status of any territory or the endorsement or acceptance of such boundaries. RIGHTS AND PERMISSIONS The material in this work is subject to copyright. Because the World Bank encourages dissemination of its knowledge, this work may be reproduced, in whole or in part, for noncommercial purposes as long as full attribution to this work is given. Any queries on rights and licenses, including subsidiary rights, should be addressed to: World Bank Publications, World Bank Group, 1818 H Street NW, Washington, DC 20433, USA; fax: 202- 522-2625; pubrights@worldbank.org. ESMAP would appreciate a copy of or link to the publication that uses this publication for its source, addressed to ESMAP Manager, World Bank, 1818 H Street NW, Washington, DC 20433 USA; esmap@worldbank.org. All images remain the sole property of their source and may not be used for any purpose without written permission from the source. Attribution—Please cite the work as follows: ESMAP. 2020. Green Hydrogen in Developing Countries. Washington, DC: World Bank. Front Cover: © Ad Astra Rocket Back Cover: © Geoff Brown/AngloAmerican ii GREEN HYDROGEN IN DEVELOPING COUNTRIES © CERES POWER ESMAP MISSION The Energy Sector Management Assistance Program (ESMAP) is a global knowledge and technical assistance program administered by the World Bank. ESMAP assists low- and middle-income coun- tries in increasing their know-how and institutional capacity to achieve environmentally sustainable energy solutions for poverty reduction and economic growth. ESMAP is funded by Australia, Austria, Canada, Denmark, the European Commission, Finland, France, Germany, Iceland, Italy, Japan, Lithuania, Luxembourg, the Netherlands, Norway, the Rocke- feller Foundation, Sweden, Switzerland, the United Kingdom, and the World Bank. © SFC CONTENTS EXECUTIVE SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi ABBREVIATIONS AND ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii GLOSSARY OF TERMS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix 1: INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 2: WHY GREEN HYDROGEN, WHY NOW, AND WHY DEVELOPING COUNTRIES? . . . . . . . . . . . . . . . 9 2.1. Why green hydrogen?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 2.2. Why now?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 2.3. Why developing countries? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 2.4. Short-term, medium-term, and long-term opportunities for green hydrogen. . . . . . . . . . . . . . . . . . . . . . . . . . . 25 3: STATE OF THE MARKET. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 3.1. How fuel cell and electrolyzer technologies work. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 3.2. Market size. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 3.3. Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 4: ENERGY APPLICATIONS AND COMMERCIAL SOLUTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 4.1. Residential applications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 4.2. Back-up power applications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 4.3. Off-grid power applications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 4.4. Commercial applications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 4.5. Utility-scale applications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 4.6. Levelized cost of energy illustrative modeling: green hydrogen production and fuel cell system. . . . . . . . . . . . . 55 5: MOBILITY APPLICATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 5.1. Fuel cell electric vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 5.2. Fuel cell electric buses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 5.4. Shipping and trains. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 5.5. Hydrogen refueling stations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70 5.6. Material handling and forklifts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 6: INDUSTRIAL APPLICATIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 6.1. Iron and steel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 6.2. Ammonia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 6.3. Refining. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 6.4. Glass, food, and other areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 6.5. Other hydrogen fuels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 7: IMPLEMENTATION CHALLENGES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 7.1. Implementation capacity and infrastructure requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 7.2. Getting the right inputs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90 7.3. Transport and storage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 8: AREAS FOR FURTHER RESEARCH. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99 BIBLIOGRAPHY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 v LIST OF FIGURES ES.1: Primary hydrogen and fuel cell applications and ecosystem for developing countries. . . . . . . . . . . . . . . . . . . xvi ES.2: Hydrogen South Africa solar plus battery, hydrogen electrolysis, and fuel cell system. . . . . . . . . . . . . . . . . . . xix 1.1: Global hydrogen market, by production method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 1.2: Green hydrogen generation and fuel cell examples: Electrolyzer and community wind site, Shapinsey, Orkney Islands, United Kingdom (left) and Bloom Energy commercial unit, United States (right) . . . . . . . . . . . 6 2.1: OECD RD&D Spending, US$, millions, 2001–17. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 2.2: World’s Largest Electrolyzer: Norsk Hydro 135 MW Electrolyzer, Glomfjord, Norway . . . . . . . . . . . . . . . . . . 13 2.3: Lifetime Performance of Siemens-Westinghouse SOFC Units, Test Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 2.4: World’s largest current electrolyzer (25 MW), polysilicon plant, Sarawak, Malaysia. . . . . . . . . . . . . . . . . . . . 19 2.5: Fuel cells for critical infrastructure in Indonesia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 2.6: Commercial fuel cell installation in India . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 3.1: Simple diagram of a proton exchange membrane fuel cell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 3.2: Simplified diagrams of a PEM and alkaline electrolyzer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 3.3: Projections and roadmaps for global hydrogen in the energy sector demand. . . . . . . . . . . . . . . . . . . . . . . . . 31 3.4: Power to gas, wind to hydrogen in Germany . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 3.5: Electrolyzer gigafactory under construction in Sheffield, United Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 3.6: Technology deployment curves for fuel cells versus wind, and solar photovoltaic. . . . . . . . . . . . . . . . . . . . . . . 35 3.7: Average fuel cell electrical efficiencies between 2005 and 2019. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 3.8: Spread in United States hydrogen prices from HyDRA, April 2019. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 3.9: ITM PEM electrolyzer, National Physics Lab, United Kingdom, 2019 (left) and Siemens Silyzer 3000, Mainz Park, Germany, 2019 (right). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 3.10: Stationary PEM fuel cell cost. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 3.11: Reported equipment cost decline curves from leading fuel cell suppliers . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 4.1: Examples of residential fuel cell systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 4.2: Phi Suea off-the-grid house, Thailand, hydrogen systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 4.3: Hydrogen boilers deployed at Shapinsey School, Kirkwall, United Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . 49 4.4: Snapshot of portable fuel cells for telecom applications: GenCell A5 2019 (right), SFC Energy methanol fuel cell 2019 (center), and SFC Energy methanol fuel cell back-up for lighting system 2019 (left). . . . . . . . . . . . . . . 51 4.5: Utility-scale fuel cell solutions: Solid oxide fuel cell units in the US . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 4.6: PEM fuel cell 1 MW unit using excess hydrogen from island refinery, Martinique, 2019 . . . . . . . . . . . . . . . . . 56 4.7: Illustrative levelized cost of energy of green hydrogen-based electricity, modeling under three scenarios, $/MWh. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 5.1: California monthly fuel cell electric vehicle market, January 2014–December 2019 (number of sold and leased units) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 5.2: Past and present fuel cell bus examples, 1993 (left) and 2014 (right). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 5.3: Declining cost of fuel cell electric buses, using Ballard Power Systems data. . . . . . . . . . . . . . . . . . . . . . . . . . 66 5.4: Fuel cell bus refueling in Wuhan, China. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 5.5: Current fuel cell truck concepts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 5.6: Green hydrogen refueling, with on-site hydrogen generation from rooftop photovoltaic: Freiburg, Germany, in 2012 (left) and Emeryville, California, in 2011 (right). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 5.7: Example of hydrogen refueling station configuration (no on-site production). . . . . . . . . . . . . . . . . . . . . . . . . . 71 5.8: Hydrogen forklift refueling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 6.1: Electrolyzer at an Indian iron production plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 6.2: HYBRIT concept image. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 6.3: World’s first wind-to-ammonia project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 6.4: Sunfire synthetic green fuels from hydrogen in Germany. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 vi GREEN HYDROGEN IN DEVELOPING COUNTRIES 7.1: Hydrogen compressors for refueling in China: Compressor for Zhangjiekhou bus station (left) and compressor for Zongshan Dayang hydrogen bus refueling station (right). . . . . . . . . . . . . . . . . . . . . . . . . . 85 7.2: Safety measures installed for hydrogen leak detection, protection, and mitigation: Kirkwall Harbour Hydrogen tanks venting line (left), Kirkwall Harbour PEM fuel cell gas leakage monitoring sensor (center), and Shapinsey School pressurized hydrogen canisters stored in blast wall–covered area, outdoors with an infrared camera. . . . . . . . . . 88 7.3: Warning system configuration for PEM electrolyzer at Shapinsey: PEM electrolysis unit infrared camera and warning alarms, Shapinsey, Orkney Islands, United Kingdom (left) and Shapinsey PEM electrolyzers on nonstatic concrete and with hydrogen ventilation shafts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 7.4: Shapinsey ferry hydrogen trailers and safety measures at sea: Orkney island hydrogen trailer (left); Orkney ferry to Shapinsey, United Kingdom (top right); and firehouse for hydrogen trailer (bottom right) . . . . . . . . . . . . . . . . . . 89 7.5: Pressurized hydrogen storage trailers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94 7.6: Liquid organic hydrogen carrier solution in operation, Tennessee, United States. . . . . . . . . . . . . . . . . . . . . . . 96 LIST OF BOXES ES.1: Hydrogen fundamentals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xxii 2.1: Hybrid energy storage systems in French Guiana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 2.2: Balancing wind in Thailand: Southeast Asia’s first megawatt-scale energy storage project. . . . . . . . . . . . . . . . 21 2.3: A strategic vision for Africa’s hydrogen economy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 2.4: Fuel cell buses in India . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 4.1: Displacing diesel in Indonesia’s telecommunications sector. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 4.2: Powering schools in South Africa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 4.3: Green hydrogen storage and batteries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 5.1: Fuel cell versus battery electric vehicles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 5.2: Hydrogen mobility in China. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 5.3: Clean mobility in Costa Rica using Central America’s first fuel cell bus. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 5.4: Hydrogen for mining mobility operations in Chile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 5.5: Energy storage and green hydrogen refueling on Singapore’s Semakau Island. . . . . . . . . . . . . . . . . . . . . . . . 72 7.1: Operations and maintenance challenges for green hydrogen in developing countries. . . . . . . . . . . . . . . . . . . 91 LIST OF TABLES BES.1.1: Energy content and energy price comparison of commonly used fuels. . . . . . . . . . . . . . . . . . . . . . . . . . . xxii 3.1: Estimated global manufacturing capacity for electrolyzers (PEM and alkaline), 2019 . . . . . . . . . . . . . . . . . . . 33 3.2: Estimated global manufacturing capacity for fuel cells across all technologies, 2019 . . . . . . . . . . . . . . . . . . . 37 3.3: Production cost estimates of hydrogen from steam methane reforming and coal gasification (excluding transport and storage costs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 3.4: Cost estimates of hydrogen generated via water electrolysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 3.5 Sample of electrolyzer capital expenditure estimates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 3.6: Overview of primary fuel cell technologies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 3.7: Methanol and ammonia fuel cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 4.1: Overview of stationary fuel cell applications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 5.1: Overview of notable currently available and announced passenger fuel cell electric vehicle models . . . . . . . . . 61 7.1: Hydrogen purity requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 7.2: Overview of hydrogen transportation methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 vii ABBREVIATIONS AND ACROYNYMS AEM anion exchange membrane IEA International Energy Agency AFC alkaline fuel cell IOC Indian Oil Company AHP African Hydrogen Partnership IPCC Intergovernmental Panel on Climate Association Change BEV battery electric vehicle IRENA International Renewable Energy Agency CAGR compound annual growth rate kg kilogram capex capital expenditure kW kilowatt CCGT combined cycle gas turbine LNG liquefied natural gas CCS carbon capture and storage LCOE levelized cost of energy CCU carbon capture and use LOHC liquid organic hydrogen carrier CEOG Centrale Électrique de l’Ouest Guyanais MCFC molten carbonate fuel cell (French Guiana) (Western Guiana MEA membrane electrode assembly Power Plant) MJ megajoule CHP combined heat and power Mtoe million tonnes of oil equivalent CSIRO Commonwealth Scientific and Industrial MW megawatt Research Organisation MWh megawatt-hour CNG compressed natural gas NASA National Aeronautics and Space CO2 carbon dioxide Administration DMFC direct methanol fuel cell NDC Nationally Determined Contribution DOE Department of Energy NREL National Renewable Energy Laboratory EGAT Electricity Generating Authority of OEM original equipment manufacturer Thailand PAFC phosphoric acid fuel cell EJ exajoule PEM proton exchange membrane ESMAP Energy Sector Management Assistance PPA power purchasing agreement Program PV photovoltaic EU European Union R&D research and development EV electric vehicle RD&D research, development, and deployment FCEB fuel cell electric bus SMR steam methane reforming FCEV fuel cell electric vehicle SOE solid oxide electrolysis FCH JU Fuel Cells and Hydrogen Joint SOFC solid oxide fuel cell Undertaking VRE variable renewable energy GHG greenhouse gas GW gigawatt HRS hydrogen refueling station HTAP Hydrogen Technology Advisory Panel All dollar figures denote US dollars unless HySA Hydrogen South Africa otherwise noted. viii GREEN HYDROGEN IN DEVELOPING COUNTRIES GLOSSARY OF TERMS Alkaline electrolyzer—This is the oldest established technology for creating hydrogen from water and electricity. The name is derived from the electrolyte used, which is typically based on either potassium hydroxide (KOH) or sodium hydroxide (NaOH). Alkaline fuel cell—This is one of the oldest and cheapest fuel cell technologies. Because of this fuel cell’s highly conductive electrolyte and highly reactive electrodes, manufacturers have been able to assemble larger units, and thus reduce losses and provide higher general electrical efficiencies than other fuel cells. Despite these fea- tures, relatively few have been deployed. Blue hydrogen—This term is used for hydrogen produced using low-carbon processes. It is almost exclusively used to refer to hydrogen produced via natural gas or coal gasification but combined with carbon capture storage (CCS) or carbon capture use (CCU) technologies in order to reduce carbon emissions significantly below their normal levels for these processes. It can, however, also refer to hydrogen produced via pyrolysis, by which hydrogen is separated into hydrogen and a solid carbon product colloquially called “carbon black.” Black hydrogen—Hydrogen produced from coal via coal gasification and extraction. Brown hydrogen—Hydrogen produced from lignite (see black hydrogen). CHP—An abbreviation that stands for combined heat and power. A term used to describe a technology that produces both heat and power for commercial uses. Coal gasification—A process through which coal is deconstructed into a gas via a combination of high pressure and high temperature steam, and by external heat. This process transforms the complex hydrocarbons from a solid state into a gaseous one, thus facilitating the reforming of the hydrocarbon gas and allowing hydrogen to be extracted. DMFC—An abbreviation that stands for direct methanol fuel cell. This technology is based on a PEM fuel cell design, which can accept methanol directly. Electrolyzer—A technology that converts water and electricity into hydrogen, oxygen, and heat. The technology has differing names depending on the electrolyte used to facilitate the chemical reaction. FC—An abbreviation for fuel cell, which is a technology that converts hydrogen into water, heat, and electricity through a chemical reaction that combines hydrogen with oxygen, usually from the filtered ambient air. The ab- breviation “FC” is frequently added to the end of a descriptor—for example, PEMFC stands for proton exchange membrane fuel cell. Fuel cells can range from a few watts in size to multimegawatt units. They can be used for stationary, mobile, and portable applications, with differing performance lifetimes, efficiencies, and operating temperatures available, depending on the specific fuel cell technology. FCEV—An abbreviation for fuel cell electric vehicle. The main body of the vehicle remains electric, but the primary propulsion fuel is hydrogen, which is consumed by a fuel cell within the vehicle. Frequently, a battery component is also included with the fuel cell for quick-start functions and actions when the vehicle is not running. FCEB—An abbreviation for fuel cell electric bus. These vehicles build on existing bus or even electric bus designs by adding a fuel cell and hydrogen fuel supply equipment, installed by a specialist systems integrator. GLOSSARY OF TERMS ix Green hydrogen—This term is used for hydrogen produced from 100 percent renewable sources. It most commonly refers to hydrogen created from a process called electrolysis, which can use 100 percent renewable power and water to create pure hydrogen and oxygen. Other green hydrogen production methods include hydrogen extraction from reformed biogas and hydrogen extraction from waste. Gray hydrogen—This term usually refers to hydrogen produced via steam methane reforming (SMR), and it is the most common type of hydrogen produced globally. Gray hydrogen can also refer to hydrogen that is created as a residual product of a chemical process—notably, the production of chlorine from chlor-alkali plants. Hydrides—A hydrogen storage technology that is able to absorb hydrogen into differing solids, including cer- tain metallic compounds and porous nanoparticles. The hydrogen stored in this form can then be released back via changes in pressure, decomposition over a catalyst, or an increase in heat. The storage unit can be recycled and does not require regular replacement. Hydrogen—The lightest element in the periodic table and the most common in the universe. Because of its natural tendency to form bonds with other molecules, it is rarely found unbounded in nature. It can therefore be considered as a storage of energy because the molecules can be easily encouraged to form bonds with other el- ements through either chemical or combustion processes. The products of these processes are water and energy (which, depending on the reaction, can be in the form of electricity and heat, or simply heat). It is a widely used commercial gas, with a broad range of applications in the energy transition. LOHC—An abbreviation for liquid organic hydrogen carriers, which are (usually) hydrocarbon molecules, such as methylcyclohexane or dibenzyltoluene and can be used to absorb large quantities of hydrogen for long-dura- tion storage or for transportation. MCFC—An abbreviation for molten carbonate fuel cell. This is a higher-temperature fuel cell that is predomi- nantly deployed in the Republic of Korea and the United States, largely running on natural gas from the grid. PAFC—An abbreviation for phosphoric acid fuel cell, which has been deployed globally and is considered to operate at intermediate temperatures, with a long operating lifetime. PEM—An abbreviation for proton exchange membrane, a chemical solution used for the electrolyte in either a fuel cell or an electrolyzer that shares the name. PEM fuel cells are the most widely deployed fuel cell technology today and are the overwhelmingly preferred technology for fuel cell mobility applications. PEM electrolyzers are much newer and less developed than alkaline electrolyzers are. However, they are showing fast signs of scaling and typically produce higher-purity hydrogen with greater flexibility in production than alkaline solutions. SMR —An abbreviation for steam methane reforming, a process by which hydrogen is extracted from natural gas or methane. SOFC—An abbreviation for solid oxide fuel cells. These are among the most efficient and longest-duration fuel cells commercially available. While there are emerging solid oxide electrolyzers (SOEs) that promise higher efficiencies and lifetimes than are available via PEM and alkaline electrolyzers, for now SOEs remain at the pilot stage with limited units in the field, all of which are below the 1 megawatt scale. x GREEN HYDROGEN IN DEVELOPING COUNTRIES EXECUTIVE SUMMARY KEY TAKEAWAYS nn In the future, green hydrogen—hydrogen produced with renewable energy resources—could provide devel- oping countries with a zero-carbon energy carrier to support national sustainable energy objectives, and it needs further consideration by policy makers and investors. nn Developing countries with good renewable energy resources could produce green hydrogen locally, gener- ating economic opportunities, and increasing energy security by reducing exposure to oil price volatility and supply disruptions. nn Green hydrogen solutions could decarbonize hard-to-abate sectors such as heavy industry, buildings, and transport while catalyzing renewable-based energy systems in developing countries. nn Electrolyzers and fuel cell technologies are experiencing significant cost, efficiency, and product quality improve- ments, with green hydrogen steadily closing the cost gap with fossil fuel-derived hydrogen in certain contexts and geographies. Still, further cost reductions are needed for green hydrogen to scale up. nn The technologies necessary to provide a systemic transition pathway for supplying hydrogen-based low-emis- sions heat, seasonal energy storage, firm power, and heavy-duty mobility solutions already exist today. nn Green hydrogen could provide energy systems with a long-term energy storage solution capable of mitigating the variability of renewable resources, thus increasing the pace and penetration of renewable energy. nn Deployment of green-hydrogen–based systems can facilitate “sector coupling” among different economic sectors, minimizing the cost of meeting sectors’ combined decarbonized energy needs. nn Fuel cells may have immediate applications in developing countries, particularly providing decentralized solutions for critical systems, powering equipment in emergency responses, and increasing energy access in remote areas. nn Despite the many years of experience handling hydrogen in industry, risks throughout the hydrogen value chain still require specific knowledge and capabilities to ensure the safe production, storage, transport, and use of hydrogen. nn In developing countries, there is a shortage of qualified engineers who can install, monitor, operate, and maintain integrated fuel cell and hydrogen systems. nn Support from development finance institutions and concessional funds could play an important role in deploy- ing first-of-a-kind green hydrogen projects, accelerating the uptake of green hydrogen in developing coun- tries, and increasing capacity and creating the necessary policy and regulatory enabling environment. Executive Summary xi OVERVIEW WHAT HAS CHANGED IN THE Hydrogen produced using electrolysis powered HYDROGEN TECHNOLOGY by renewable energy—green hydrogen—and its LANDSCAPE? use in fuel cells has a long history of promising At a global level, there are four key reasons that a pathway to a global clean energy economy yet hydrogen is now emerging as a viable energy failing to deliver. But mounting evidence sug- technology for the energy transition: gests that this time the script could be different. 1. Increased urgency to stop climate change: The As the costs of producing green hydrogen and global commitment to mitigate climate change its use in fuel cells steadily decreases, the global and focus on climate regulations is much urgency to deliver clean energy alternatives stronger now than at any time previously in and decarbonize is growing. Accordingly, green history. This commitment is gradually pushing hydrogen’s extraordinary versatility could play an countries to find and support low-emission important role in this transition, particularly in technologies that can reliably supply their developing countries where access to local fuels growing energy demands. Consequently, as and other firm1 low-carbon resources such as countries increase pressure on energy sup- geothermal and large hydro may be limited. pliers to find low- and zero-carbon solutions, The impact of scaling in the green hydrogen significant new funding is being allocated by companies, governments, and investors to market and improvements in the performance overcome the historic barriers that hydrogen of electrolysis and fuel cell technologies has yet technologies have faced. to be translated into actions and implications for developing countries. Despite a significant 2. Reduced renewable energy costs and volume of literature on the global hydrogen increased need to firm up renewable energy market, and the market’s latest progress in resources: Renewable energy costs have developed countries, the potential applications declined dramatically and are continuing for green hydrogen and fuel cells in develop- to fall, significantly reducing the price gap ing countries have not been fully explored. between hydrogen from electrolysis and Hydrogen is a complex technology to operate hydrogen derived from fossil fuels. Moreover, that requires specific knowledge and capabilities variable renewable energy (VRE) sources alone to ensure that its production, storage, transport, cannot provide firm energy solutions, which and use remains safe. In developing countries are necessary to guarantee that demand can these requirements may produce implementation be met at all times. Hydrogen storage could challenges that have to be well understood. This therefore emerge as a widely deployable report seeks to advance the understanding of solution to contribute to mitigating renewable opportunities and challenges of green hydrogen seasonal variability and to maximizing renew- in developing countries by describing examples able use in a national energy system. of green hydrogen pilot applications that have 3. Significant advancement in hydrogen and already been deployed in developing countries, fuel cell technologies: Hydrogen and fuel bringing to light potential use cases and strate- cell technologies have experienced signif- gic value, and highlighting technology risks and icant technical progress in their efficiency, implementation challenges. durability, reliability, and cost reduction. 1 The term “firm” refers to energy technologies whose availability is guaranteed at all times, in contrast with variable renewable energy resources such as wind and solar photovoltaics, whose availability is constrained by instantaneous wind speed and sunlight, respectively. xii GREEN HYDROGEN IN DEVELOPING COUNTRIES Despite requiring further cost reductions to hydrogen solutions to developing countries. scale up globally, modern fuel cells are now Green hydrogen is the only known clean energy considerably cheaper, more durable, and more molecule that can be produced at any scale and efficient than during the last fuel cell boom in almost any location on earth, a characteristic cycle in the early 2000s.2 Thus, companies that is not comparable for other synthetic green have begun to shift their focus away from fuels. Accordingly, green hydrogen could offer exclusively concentrating on research and almost any community, company, or country the development toward developing the capacity potential to generate their own fuels, with the to increase manufacturing output. In certain flexibility for multiple end uses, including appli- locations, these improvements are helping cations in industry, buildings, and transport. to close the price gap between electricity Despite its potential, hydrogen production today generated by fuel cells using green hydrogen is a fossil fuel–intensive process, and significant and electricity provided from fossil alternatives scaling up is needed to decarbonize existing such as diesel generators. production. The most common methods to 4. Global transition towards electric mobility extract hydrogen are through the reforming of solutions: The transition to electric mobility natural gas—a process that accounts for around has helped develop enabling technologies that 6 percent of global natural gas demand—and hydrogen and fuel cells are using to provide gasification—for which about 2 percent of total solutions for long-range zero-emission appli- coal production is allocated, most of which is in cations: trucks, trains, maritime shipping, China. Together, these processes are estimated to buses, commercial vehicles, and perhaps account for between 96 and 99 percent of global even aviation. With the use of electric drive- hydrogen production. Thus, hydrogen generation train architecture and supportive air quality from electricity and water through electrolysis requirements established by policy makers and is currently estimated to provide as little as 4 regulators, hydrogen and fuel cells soon could percent of global hydrogen supply. This situation, be well placed to reach the scale needed to however, is set to change as green hydrogen significantly drive down systems costs and costs fall further. mitigate the heavy pollution common in many Growing global demand for green hydrogen is cities in developing countries. driving significant cost declines for electrolyzer equipment. Global water electrolysis deploy- ments have risen from a cumulative 32.7 mega- GREEN HYDROGEN MARKET watts (MW) of installed capacity between 2000 TODAY and 2013 to over 260 MW of installed and com- While, the global market for green hydrogen mitted capacity between 2014 and 2019 (IEA remains nascent, it could play a more prominent 2019b). The size of electrolyzer orders is also role in the energy transition. The modular nature rising from ITM and Shell’s world-record proton of electrolysis and fuel cells combined with the exchange membrane (PEM) order of 10 MW in widespread availability of zero carbon renewable 2017 (ITM 2018) to Hydrogenics’s 20 MW order energy resources makes green hydrogen a partic- in February 2019, and new feasibility studies ularly interesting option for bringing sustainable announced since March 2019 for 250 MW 2 Current systems have demonstrated operating lifetimes of over 34,000 hours in the field, with certain technologies reporting electrical effi- ciencies over 60 percent and combined heat and power (CHP) efficiencies in the 90+ percent range. More generally, capital expenditures for proton exchange membrane (PEM) fuel cells have fallen from $4 per watt in 2003 to under $2 per watt today for stationary applications. Executive Summary xiii electrolyzer capacity in the Netherlands and natural gas exporting regions. If renewable en- 12 gigawatts (GW) in Pilbara, Australia. These ergy and electrolyzer costs continue to decline, new market developments indicate that scaling green hydrogen could eventually become cost is occurring at a significant rate. Manufacturing competitive in a larger number of locations and capacity (currently about 2.1 GW annually) is in a wider range of applications. responding to this growing demand and moving Fuel cells are also becoming cheaper, more to fully automated production lines, with future durable and more efficient, enabling low-carbon public manufacturing expansion commitments applications for transport, critical systems, and already exceeding 4.5 GW. This scaling is im- energy access in remote areas. The total capacity portant not simply for keeping up with demand. deployed of fuel cells worldwide is above 2GW, Crucially, the scaling of manufacturing is also with PEM and alkaline fuel cells reaching costs leading to significant cost declines, with the below $2,000 per kW and $700 per kW, respec- estimated cost of PEM electrolyzers falling from tively, and efficiencies above 50 percent and 60 over $2,400 per kilowatt (kW) in 2015 to under percent, respectively. These improvements are $1,100 per kW in 2019.3 Moreover, alkaline helping to close the price gap between electricity electrolysis costs are falling below $500 per generated by fuel cells using green hydrogen or kW for orders above 10 MW, and some market other green hydrogen–derived fuels and electric- sources suggest that costs below $300 per kW ity provided from fossil alternatives such as die- could now be realized from $800 per kW in sel generators. The transition to electric mobility 2017. has also helped develop enabling technologies Along with the cost reductions in electrolyzers, that vendors are integrating with fuel cells to the rapidly declining cost of renewable elec- provide solutions for long-range zero-emission tricity is translating into lower costs for green applications such as trucks, trains, maritime ship- hydrogen production. In markets where whole- ping, buses, and commercial vehicles. sale electricity prices fall below $45 per mega- The declining price of green hydrogen produc- watt-hour (MWh), the cost of green hydrogen tion and fuel cells opens the door to its wider production could range between $2.5 and $6.8 adoption as a decarbonization vector for energy per kilogram (kg). Although it may seem high sector transition. Significant cost declines compared with a range of $1–$3 per kg for hy- in green hydrogen production could help to drogen from steam methane reforming (SMR) for expand its market share in the existing $135.5 markets that can access natural gas below $8 per billion a year global industrial hydrogen market million British thermal units, this price excludes (Markets and Markets 2018), which is estimated transportation, distribution, liquefaction, and to release 830 million tonnes of carbon diox- gasification costs, which could add up to $4 per ide (CO2) per annum (IEA 2019b)—a figure kg of hydrogen, depending on the transportation equivalent to the combined annual emissions mode (pipeline or ship) and location of supply of Indonesia and the United Kingdom. Given and demand. Accordingly, local green hydro- the scale of emissions from existing industrial gen production could already be cost compet- demand sources for hydrogen, it is unsurprising itive in isolated locations with good renewable that one of green hydrogen’s greatest appeals is resources, particularly in those that do not have its ability to provide a zero-emission energy vec- local hydrocarbon resources and are far from tor for decarbonization of industrial feedstock. 3 Figures are an average from market data points and numbers cited in the broader literature. For a range of current estimates of alkaline and PEM electrolyzer prices, see table 3.6. xiv GREEN HYDROGEN IN DEVELOPING COUNTRIES This decarbonization path would also open the also lowering energy sector costs over time in door for green hydrogen production to expand countries that rely heavily on diesel. It could also into industrial heat displacing carbon intensive provide an array of decentralized services that fossil alternatives, as the early scaling brings could cover all energy needs in buildings, trans- green hydrogen costs toward (and eventually port, and industry, while helping to shield critical below) fossil parity. infrastructure from power supply disruptions, therefore bolstering climate and extreme weather The rapid proliferation of innovative green hydro- resiliency. gen applications is capturing the imagination of international media and policy makers, creating At the core of the appeal for developing coun- a feedback loop that is boosting awareness and tries is the versatility that green hydrogen and support for green hydrogen technologies. A its derived fuels offer as a clean energy vector. significant number of countries and companies Today, green hydrogen is a technological solu- have begun to develop policies and support tion that can facilitate sector coupling by en- pilot projects geared toward exploiting near- abling solar, wind, and other renewable sources term green hydrogen opportunities. These have to be converted into an energy vector that can focused largely on either decarbonizing existing decarbonize industry, mobility, and electric hydrogen applications or using green hydrogen power. Moreover, hydrogen and hydrogen- as an alternative to heavy fuels in transport and derived fuels are easier to store, transport, and more recently in industrial heat. In developed repurpose across an array of energy needs than countries, exploiting existing gas infrastructure, electricity. The existing infrastructure in develop- developing green hydrogen hubs and trade ing countries that supports the supply, storage, routes, and decarbonizing freight transportation and transportation of methanol and ammonia could represent transformational opportunities. could be leveraged by green hydrogen applica- Lessons from initial pilots could cascade into tions (figure ES.1). other sectors, increasing the experience with green hydrogen technology and further driving Existing demand for fossil-derived hydrogen in down costs. Development of the green hydrogen developing countries is concentrated in the pro- market could offer a particular advantage to de- duction of ammonia for fertilizers; the refining of veloping countries that have pressing infrastruc- petroleum products for domestic use, exports, or ture needs and exposure to high fuel prices—and both; the production of methanol; the produc- that also require solutions to address energy tion of iron, glass, and polysilicon in manufac- security and resiliency considerations. turing; and the treatment of certain food prod- ucts and other smaller industrial requirements. Given the existing demand, green hydrogen may GREEN HYDROGEN offer an economic opportunity for policy makers APPLICATIONS IN DEVELOPING to develop local industry through domestic green COUNTRIES hydrogen production. If fully exploited, domestic green hydrogen production could enhance food Green hydrogen could provide developing and energy security. countries with a powerful technology to support national sustainable energy objectives and de- Green hydrogen could also help address key carbonization strategies. Green hydrogen could challenges in bringing excellent- quality re- enhance national energy security by reducing newable resources to market while increasing the exposure to oil price volatility and supply renewable penetration rates. VRE resources such disruptions where it is produced locally, while as wind power (both onshore and offshore) and Executive Summary xv FIGURE ES.1 Primary hydrogen and fuel cell applications and ecosystem for developing countries GREEN HYDROGEN PRODUCTION WIND + – OXYGEN + HYDROGEN – SOLAR HYDROPOWER HYDROGEN ELECTROLYSIS GEOTHERMAL ORGANIC / BIO WASTE BIOGAS REFORMING ME Source: ESMAP. xvi GREEN HYDROGEN IN DEVELOPING COUNTRIES ODUCTION HYDROGEN FUEL APPLICATION TRANSPORTATION LIGHT DUTY VEHICLES HYDROGEN BUSES TRUCKS TRAINS SHIPS POWER and HEAT HYDROGEN DIRECT USE GRID BALANCING CO-FIRING THERMAL POWER PLANTS BASELOAD POWER INDUSTRIAL HEAT AND STEAM YSIS FERTILIZER FOR AGRICULTURE AND EXPORT AMMONIA PLANT NG UNINTERRUPTIBLE POWER SUPPLY TELECOMMUNICATIONS ENERGY ACCESS— REMOTE COMMUNITIES NATURAL DISASTER WARNING SYSTEMS BLACKSTART CAPABILITIES METHANOL PRODUCTION Executive Summary xvii solar photovoltaic (PV) are frequently located stationary fuel cell systems have also started to away from large population centers and not be piloted for residential and tourism consumers available on demand, making them costly to de- in Namibia and Thailand. Other larger hydrogen ploy and integrate into the power grid. The abil- or fuel cell projects are being piloted to provide ity to bypass these constraints by creating green stationary power solutions in Argentina, Mali, hydrogen on-site and either storing it for later Martinique, and Uganda. On the mobility side, use in a fuel cell or transporting it to demand fuel cell buses have been piloted in China, centers holds considerable appeal, especially if Costa Rica, and Malaysia, with orders placed in it can could be produced at sufficient scale and Bulgaria, Indonesia, and India. China and South use existing pipelines or transportation routes. Africa also have begun to pilot hydrogen and Exploiting the synergies between VRE resources fuel cell systems for forklifts used in material and green hydrogen production could help handling. The motivating benefits of these proj- leverage high-quality resources and significantly ects are context dependent, but they broadly re- increase VRE deployment rates. flect the fact that for some applications hydrogen could be more attractive than electricity-based Yet, further cost declines will be needed to meet storage systems given hydrogen’s higher energy existing hydrogen demand in developing coun- density (figure ES.2). tries. Harnessing the opportunities presented by green hydrogen to supply existing hydrogen The transition to modern fuels in industry could demand will require further electrolyzer cost also be a major area of potential near-term declines, particularly in countries with access to growth for green hydrogen. Developing countries natural gas or cheap coal. If long-term predic- that are in the process of building the means to tions are realized, green hydrogen costs could supply their rapidly growing industrial demand fall below US$2 per kg by 2030 in countries for energy will also need to transition away from with high-quality renewable resources such as traditional fuel sources—notably, biofuels, coal, China, Bangladesh, the Arab Republic of Egypt, and petroleum-based fuels—toward clean energy India, Kenya, Mexico, Morocco, Nepal, Pakistan, sources. Given that 25 percent of global carbon Somalia, South Africa, and Turkey (IEA 2019b). emissions could come from industrial heat de- At such a price point, the cost of green hydrogen mand in 2040 (Bellevrat and West 2018), green production could be comparable, and in many hydrogen represents a significant opportunity for cases lower, than on-site hydrogen generation investors and policy makers seeking to lock out from natural gas using SMR. heavy CO2-emitting energy sources from becom- ing the foundation for industrialization in many developing countries. NEAR-TERM OPPORTUNITIES Island locations, remote communities, countries FOR GREEN HYDROGEN IN with existing gas infrastructure, areas with poor DEVELOPING COUNTRIES air quality, and areas with excellent renewable Opportunities exist today to pilot both green resources or with severe seasonal renewable vari- hydrogen for low-emission transport solutions ability could offer the most attractive opportunities and fuel cells for remote power provision in for near-term deployments of green hydrogen and developing countries. China, India, Indonesia, fuel cell projects. Given the high energy prices, the Philippines, and South Africa are starting synergies with other infrastructure, and environ- to gain experience using ammonia-based and mental challenges that these territories face, the methanol-based fuel cell systems for the tele- applicability of green hydrogen solutions could be communications sector. Meanwhile, smaller initially explored in these cases: xviii GREEN HYDROGEN IN DEVELOPING COUNTRIES Hydrogen South Africa solar plus battery, hydrogen electrolysis, FIGURE ES.2 and fuel cell system © HySA. 1. Islands and remote communities that are but leading to reduced emissions. Green energy importers could use green hydrogen hydrogen also offers countries a route to repur- as a decarbonization vector across heat, pose existing turbine base power systems, thus transport, and power. Given the ability to avoiding the need to retire assets early. produce and store hydrogen in large quantities 3. Heavily polluted metropolitan areas in devel- for long periods of time, as well as the limited oping countries could benefit significantly physical requirements for fuel cell systems, from fuel cell bus transport solutions. These islands and remote communities represent an obvious initial opportunity for green hydrogen. areas often have large public sector–owned Initial analysis suggests that green hydrogen transport fleets that could be repurposed to combined with fuel cells may already provide help improve local air quality and reduce cost-competitive power against diesel alterna- emissions. Because all fuel cell vehicles tives in certain conditions. require air filters, a citywide fleet could help reduce particulate emissions while emitting 2. Middle-income countries with existing gas only water. Fuel cell options also offer longer infrastructure have clear incentives to explore ranges than battery electric alternatives, cre- green hydrogen. Countries such as Argentina, ating alternative clean solutions for transport Egypt, Malaysia, and Thailand have made activities that rely on long-haul fleets. significant investments in gas and now risk stranding assets as they seek to decarbonize. Areas with excellent renewable resources or with However, existing natural gas assets could a high degree of seasonality in their renewable be repurposed to support green hydrogen power production profiles could consider green production, minimizing the risk of stranded hydrogen as a seasonal energy storage solution. assets. Short-term opportunities may also exist In this regard, green hydrogen could provide op- for blending green hydrogen into gas grids, portunities for increasing the deployment levels thereby requiring no changes to existing assets of VRE technologies in these locations, further Executive Summary xix reducing demand for fossil fuel alternatives and Integration of green hydrogen technologies and eventually enabling green hydrogen exports with labor capacity constraints are still significant bar- sustained declines in production cost. riers to the wider deployment of green hydrogen and fuel cell technologies, especially in develop- ing countries. Few engineering companies have REMAINING TECHNOLOGY AND experience in developing and installing green IMPLEMENTATION CHALLENGES hydrogen or fuel cell technologies, especially in developing countries. Lack of sufficient training Some significant safety and technical risks still programs on hydrogen installation is a constraint, need to be understood and addressed before especially when many of the suppliers have a countries can leverage all the opportunities limited number of staff members who can offer that green hydrogen could offer. Hydrogen is a installation support. The integration of hydrogen complex molecule to contain, store, and trans- technologies into other systems also poses a port. It has unique safety properties that can be challenge, as suppliers may have limited expe- challenging to address and that require techni- rience optimizing their units to fit within a new cal awareness that may be lacking in countries application. Electrolysis and fuel cell systems that do not have domestic hydrogen production require regular maintenance visits, which could capabilities. Even in countries that do have some pose a barrier in remote locations and even in expertise, knowledge of how electrolyzers oper- markets where the number of installed units is ate, how to maintain fuel cell systems, and how too low to justify a permanent resource from the to avoid leakages from high-pressure storage (or manufacturer. There is also a need to guarantee cryogenic storage) is essential. that maintenance work is done properly and to market specifications. Hydrogen technologies are capital intensive, and further cost reductions and efficiency gains The initial rollout of green hydrogen will require need to be realized to scale up green hydrogen countries to develop national strategies that solutions. High maintenance requirements in clearly identify both a pathway toward meeting some regions might also increase costs, because the infrastructure needs and the sectors where hydrogen technologies are very prone to damage green hydrogen solutions could become com- mercial. The development of green hydrogen and deterioration if input quality does not meet energy systems will require countries to think required specifications—for example, impuri- carefully about whether to make strategic in- ties in water for the electrolyzer or impurities in vestments into pipeline infrastructure or whether hydrogen for fuel cells. Moreover, as with some to rely on road transportation and storage existing battery technologies, few systems have across multiple locations. In some instances, been tested to their full anticipated stack lifetime the repurposing of existing infrastructure may and, as a result, performance has not been fully be possible, thus avoiding stranded assets and assessed at scale for all current technology pro- potentially lowering deployment costs. However, viders. Additional efficiencies could be gained that option will not be applicable in all develop- with current hydrogen storage systems, most of ing countries. Further, local capacity to install, which require pressurization or liquefaction. maintain, and handle hydrogen and its associ- Other hydrogen storage technologies based on ated technologies would have to be developed, a solid-state compounds are being explored and task that would require a long-term commitment eventually could bring more efficient solutions to to education programs in developing coun- store and transport hydrogen. tries. Consequently, the decision to initiate the xx GREEN HYDROGEN IN DEVELOPING COUNTRIES development of green hydrogen energy systems deployed in developing countries may pose should be considered within a clear framework higher risks. Innovative cofinancing and con- and roadmap that help all stakeholders (includ- cessional funds could play an essential role in ing consumers and government) plan and adjust supporting first-of-a-kind green hydrogen projects their investments and actions accordingly. in developing countries, in particular those with technology components that do not have a suffi- The equipment used in producing green hydro- cient scale or track record. For example, investors gen is capital intensive and, as such, requires could use commercial financing for renewable high utilization rates to economically justify power projects such as wind and solar assets investments. Accordingly, developing countries dedicated to producing green hydrogen, bene- must assess at a system level whether green hydrogen production is appropriate given the fiting from blending with concessional funds to existing resources available and the energy needs reduce the financing cost of the electrolysis plant. from different sectors. Strategies for large-scale Despite existing challenges, the potential uses for deployment of green hydrogen should also green hydrogen make it an essential area for fur- consider the systemwide impacts of a transition, ther consideration and analysis by policy makers notably where other energy storage solutions may and investors in developing countries (box ES.1). offer greater system efficiencies. Coordination Green hydrogen is increasingly drawing interest among all energy sector stakeholder, including from governments in all regions, with valuable the public sector to develop these strategies into near-term applications in some contexts and a favorable regulatory environment, and with de- a predominant decarbonization role in hard- velopment finance institutions working in tandem to-abate sectors. Over the next 5 years, early to provide concessional financing that mobilizes evidence suggests that mobility and power pro- private capital, will be essential to ensuring a suc- vision could provide the main source of growth cessful initial rollout of green hydrogen. for green hydrogen and fuel cell technologies Moreover, financial constraints derived from in developing countries. This forecast largely technology and regulatory risks may inhibit the reflects the fact that further cost declines are near-term development of green hydrogen in essential for green hydrogen production to reach developing countries. These constraints include commercial-equivalent cost points to alternative the insufficient scale or track record of some energy vectors in developing countries. Efforts hydrogen system components, investors’ lack of are therefore needed today to ensure that the op- awareness of green hydrogen’s potential role in portunities available to scale up green hydrogen the energy transition in developed countries, and and fuel cell deployments in developing coun- the lack of clear national strategies and regula- tries are researched and capitalized on before tory frameworks for some hydrogen applications, alternative carbon-intensive energy systems are coupled with a perception that new technologies locked in. Executive Summary xxi BOX ES.1 HYDROGEN FUNDAMENTALS Hydrogen is the most abundant molecule in the universe and the lightest element in the periodic table. It is rarely found unbounded in nature, and it is almost always extracted from another source. Hydrogen production typically comes from the extraction of hydrogen from water and electric power or from hydrocarbons, most notably by using natural gas and coal. As an energy carrier, hydrogen can be used for a wide array of energy and industrial applica- tions and can be stored for long periods of time in various forms. Hydrogen is already one of the most widely produced industrial gases in the world, and it is a significant source of carbon dioxide emissions because of its typical production through extraction from fossil fuels. However, the production of zero-emission hydrogen through renewable energy sources could become a commercial alternative to fossil fuel–derived hydrogen in a wide array of applications. Produc- ing hydrogen from renewable electricity is done through a process called electrolysis, in which electricity is channeled through a device called an electrolyzer, which splits oxygen from hydro- gen in water, creating pure oxygen and pure hydrogen with zero carbon emissions. Approxi- mately 50 kilowatt-hours of electricity and 9 liters of deionized water are required to produce 1 kilogram of hydrogen using an electrolyzer of 80 percent efficiency. Fuel cell technologies offer a method to generate electricity by combining hydrogen with oxygen in a chemical process. This is typically much more efficient than a combustion process, while also being considerably quieter and producing zero carbon emissions (if pure hydrogen) or zero nitrogen oxide emissions when using hydrocarbon fuels. When hydrogen reacts in a fuel cell to generate electricity, the only products are electricity, a small amount of heat, and water. Approx- imately, 42 kilograms of hydrogen are needed to produce 1 megawatt-hour of electricity using a fuel cell of 60 percent efficiency. Hydrogen’s specific energy is the highest among conventional fuels, but its energy density is the lowest, so pressurization or liquefaction is required for hydrogen to be used as a fuel. These fundamental characteristics of hydrogen are the primary drivers of its value as a fuel. Table BES.1.1: Specific energy and energy density comparison of commonly used fuels SPECIFIC ENERGY (MJ/kg) FUEL (1kWh = 3.6 MJ) ENERGY DENSITY (MJ/L) Hydrogen 142.0 0.01 (1 atm); 7.10 (1,000 bar); 10.00 (liquid) Methanol 20.0 15.90 Ammonia 22.5 15.60 Gasoline 47.1 35.00 Diesel 42.8 40.40 Heavy fuel oil 42.4 40.70 Biodiesel 42.2 33.00 Natural gas 50.0 0.04 LNG 50.0 22.20 Source: World Bank compilation of higher heating values obtained from multiple sources. Note: atm = atmospheres; kg = kilogram; kWh = kilowatt-hour; L = liter; LNG = liquefied natural gas; MJ = megajoule. xxii GREEN HYDROGEN IN DEVELOPING COUNTRIES 1: INTRODUCTION KEY TAKEAWAYS nn Green hydrogen, produced using electrolysis powered by renewable electricity, is emerging globally as an energy solution for a diverse array of challenges, including climate change mitigation and adaptation and energy security. nn Green hydrogen could contribute to the decarbonization of activities in industry (zero-emission industrial heat supply), transport (clean mobility solutions), and buildings (climate-resilient firm power generation), increasing the scalability of renewable energy use. nn The current hydrogen market is already significant and carbon intensive, thus providing an opportunity for investors and policy makers to reduce emissions and develop national strategies for green hydrogen’s future production and for uses that are compatible with Nationally Determined Contributions (NDCs). nn Green hydrogen could represent a clean alternative fuel for developing countries as they transition from a heavy reliance on fossil fuels and look for modern, low-emission, and locally produced energy vectors. nn Hydrogen production technologies and fuel cells are well established, with research and innovation efforts focusing mostly on cost reductions per unit. nn A number of technology challenges remain surrounding the cost efficiency of transport and storage of hydrogen, and further work on alternative hydrogen storage technologies (such as, solid-state storage, liquid organic hydrogen carriers [LOHCs], and small-scale hydrogen conversion technologies) is needed. nn Knowledge of green hydrogen as a potential energy vector in developing countries is low, making capacity building and training essential to support green hydrogen deployments in developing countries. 1: Introduction 1 Hydrogen is not a new commodity, nor are are ready. A rapid scaling up is now needed to fuel cells a new technology. The global hydro- achieve the necessary cost reductions and ensure gen market in 2018 was valued at over $135.5 the economic viability of hydrogen as a long- billion, with an estimated compound annual term enabler of the energy transition” (IRENA growth rate (CAGR) of 8 percent until 2023 2018). (Markets and Markets 2018). Estimates for the This report attempts to draw attention to areas volume of hydrogen produced vary, but a sig- of current success and areas in which green nificant number of documents suggest that 55 hydrogen could provide a compelling solution million tonnes4 to 70 million tonnes (IEA 2019b) to address the current and anticipated energy of hydrogen are commercially produced annual- challenges faced by developing countries. In this ly.5 Given its existing scale, hydrogen production way, this report focuses on how green hydro- and storage are well understood. But what is gen and fuel cell technologies could be initially new is the growing interest around a hydrogen rolled out in developing countries by presenting production process called electrolysis, which is a series of applications that could be initially reaching a point of cost parity with hydrogen de- deployed in some locations and that could scale rived from fossil fuel sources in certain contexts up in the future. and geographies. The prospect of producing a zero-emission energy vector through electrolysis This report also focuses on some of the tech- with a wide array of applications in many sectors nology risks, implementation challenges, and could be transformative to economic develop- knowledge gaps that are emerging as new hydro- ment that is aligned with national and global gen projects and technologies are being de- climate goals. ployed and tested in greater numbers. Crucially, the report seeks to draw attention to where these Consistent findings across available literature challenges are universal and where they are and consultations with market players indicate more specific to developing countries. that hydrogen technologies have been progres- sively improving throughout the past decade Although other methods of hydrogen produc- and systems have been developed that are more tion do exist, this report will focus largely on efficient and safer to operate than those in the hydrogen produced from electrolysis with past. If progress in cost and performance contin- renewable sources (figure 1.1).6 Electrolysis is ues, and the scaling up of electrolysis equipment simply the process of chemically separating over the next decade further pushes costs down, hydrogen and oxygen molecules from water green hydrogen production could eventually using electricity. When the source of electric- become a viable commercial alternative to ex- ity is renewable, this process is referred to as isting fossil-based solutions. As the International green hydrogen.7 The most obvious appeal of Renewable Energy Agency (IRENA) concluded green hydrogen is its ability to decarbonize in its 2018 hydrogen report: “The technologies the current global hydrogen market while also 4 While 55 million tonnes is a broad representation from the available literature, it has also been used recently by the Canadian Hydrogen Fuel Cell Association. See LePan 2019. 5 DNV GL’s 2019 paper for the Norwegian government quoted 55 million, as did the Hydrogen Council (2017), IRENA (2018), and Siemens (2019). World Energy Council—Netherlands cited 45 million–50 million using 2010 data in its 2019 report. 6 Other World Bank reports are under development that will address gray and blue hydrogen in more detail. 7 The term green hydrogen can also refer to hydrogen created from biogas; however, few projects or pilots have been proposed and devel- oped to date. This report therefore does not focus on that technology. 2 GREEN HYDROGEN IN DEVELOPING COUNTRIES FIGURE 1.1 Global hydrogen market, by production method 4% W t r l ctrol sis 30% Oil r formin 48% N tur l s st m m th n r formin (SMR) 18% Co l sific tion Sources: Ajayi-Oyakhire 2012 and IRENA 2018. creating a flexible clean energy carrier that can for ammonia production, followed by refining, be used for a wide array of energy applications. methanol production direct iron reduction, and The decarbonization potential of a broader use various other products (such as glass production of green hydrogen is significant. and hydrogenation of fats). Therefore, green hydrogen production (figure 1.2a) offers policy In 2019, about 96 percent of global hydro- makers a route to removing 830 million tonnes gen production came from fossil fuel sources, of carbon dioxide (CO2) (IEA 2019) from global with 4 percent from electrolysis, 48 percent annual emissions and preventing any increase from natural gas via steam methane reforming in emissions from this sector. Achieving this (SMR), and 48 percent from coal gasification, reduction is as crucial in the developed world oil, or other chemical processes (such as chlo- as it is in developing countries, especially where rine production).8 These types of hydrogen are hydrogen and hydrogen-derived products are es- typically referred to as gray, black, or sometimes sential for the health of local industries (notably, brown hydrogen. Today, hydrogen accounts ammonia used in the production of fertilizers). for 6 percent of global gas consumption and 2 percent of global coal consumption, a pri- Given the size and anticipated growth of the mary energy demand equivalent to 330 million existing hydrogen market, the development of tonnes of oil equivalent (Mtoe), which as the green hydrogen projects could present a sig- International Energy Agency (IEA) notes is larger nificant investment opportunity for investors than Germany’s primary energy demand (IEA in developing countries. Not only do many 2019b, 17). Moreover, this demand is growing as developing countries enjoy some of the most the world requires ever more hydrogen as an in- abundant renewable resources, but they also dustrial feedstock, the primary uses of which are are often the countries that are most in need 8 Ajayi-Oyakire 2012, citing Ogden 2004; IEA 2015, 10; IRENA 2018, 13; and Siemens 2019, slide 8. 1: Introduction 3 of new and clean forms of energy to support technologies such as electric battery storage, economic development. IEA data illustrate one for which fires from poor assembly are also a area of immediate interest: Roughly 4.5 percent concern. Indeed, the key takeaway is not that of the global energy supply in 2015 (approxi- safety is an insurmountable barrier or that the mately 28.24 exajoules, EJ9) was sourced from issues are not sufficiently understood; rather, the traditional biomass, which is entirely consumed knowledge around hydrogen needs to be more in developing countries. Further, all 28.24 EJ widely disseminated and practiced as these new of developing country energy consumption applications gain traction. that is currently derived from traditional uses Beyond the safety, cost, and convenience of of biomass must be replaced by more modern deployment remain the two key factors that alternative fuels as consumer purchasing power determine the pace of technology adoption in grows in these markets. Ensuring that the alterna- developing countries. It is notable that hydro- tive fuels create zero emissions, are affordable, gen and its derived products are already being and are convenient to use is essential to avoid used for a wide array of applications in some locking developing countries (and ultimately developing countries without the need for large- global CO2 emissions) into a trajectory that leads scale government support. The reasons for this to significant climatic warming by the middle of are explored in detail in chapter 2 of this report the century. but, broadly speaking, consumers in developing But hydrogen applications do not come without countries often pay higher than average prices challenges. Hydrogen is a notoriously complex for energy than their peers in developed coun- and expensive gas to store, with a range of prop- tries do, and commercial and industrial consum- erties that require careful consideration to ensure ers in developing countries often face problems safe usage (these are explored more in chapter with the reliability of the energy supply. These 7). Although technologies and procedures do factors can negate some of the challenges that exist to minimize leaks and to ensure that, where face hydrogen deployments in developed mar- necessary, hydrogen is released in a controlled kets, where green hydrogen in power-to-power manner, these elements are not universally applications has struggled to provide a commer- understood outside the petrochemical industry. cially compelling proposition at current costs. Furthermore, hydrogen production and fuel cell Indeed, where there have been safety incidents technologies are often deployed in prefabricated involving hydrogen, the cause has often been a containers at the distributed scale, making instal- fault in the assembly of the units, demonstrating lation relatively fast and reducing the construc- the importance of having access to experienced tion time. installers and engineers. Access to such skills is also important for the ongoing maintenance Further, some developing countries simply lack of fuel cell systems, notably those operating the ability to develop extensive domestic re- at higher temperatures for which suppliers are newable energy resources because of physical advising some form of basic maintenance every constraints such as the lack of access to land on three months. But storage and assembly con- which to deploy renewable plants or the poor cerns are not unique to hydrogen and are also quality of local renewable resources. In these considerations for the handling of other fuels cases, the ability to import a clean fuel from a such as ammonia—a toxic chemical—or new variety of suppliers and provide reliable power 9 This amount is the product of the 55.4 percent of traditional biomass used for energy in 2015 multiplied by 51 EJ. IEA, Bioenergy website, https://www.iea.org/topics/renewables/bioenergy/. 4 GREEN HYDROGEN IN DEVELOPING COUNTRIES without requiring large amounts of space is gigawatts (GW) of stationary fuel cell capacity essential. Green hydrogen can be produced and has been deployed globally (IEA 2019b). In stored for long periods of time, then dispensed developing countries, the bulk of deployed fuel when needed. Electrolyzers can even provide cell systems are small scale and have been used services to grid operators, adjusting their hydro- to provide an uninterruptible power supply for gen output as they do in markets such as the telecommunications and emergency services. United Kingdom, where six 330 kilowatt (kW) Although the size of each unit may be small (typ- electrolyzers will follow a demand optimization ically below 10 kW, but it can vary depending profile provided by a software provider called on the site) the absolute number of systems de- Open Energi (FuelCellWorks 2019c). ployed is significant and growing.10 On the larger stationary side, fuel cells are beginning to gain One significant barrier to the deployment of green hydrogen in developing countries is a traction for commercial uses (below 5 megawatts lack of awareness. Few business and utilities in [MW]) in developing countries, with countries developing countries have a clear understanding such as India and South Africa both deploying of the potential applications for green hydrogen high-temperature systems. Typically, these larger inside their businesses, and thus they have not units will make commercial sense where there sought to engage with suppliers, financiers, or is already access to natural gas, which remains the government to promote its use. Concurrently, globally the preferred fuel for stationary fuel many policy makers have not sought to de- cells. Nevertheless, current deployment levels velop a policy framework or national strategy to are low and further cost declines will likely support the uptake of green hydrogen and fuel be needed before stationary fuel cells in other cells because they may be unaware of the role markets are able to replicate the deployment hydrogen could play in their national energy scales achieved in the Republic of Korea and the strategy and industrial objectives. In addition, United States (figure 1.2b). the technical expertise for hydrogen systems On the mobility side, there are over 12,000 fuel is frequently low and in many cases nonexis- cell electric vehicles (FCEVs) globally,11 with hy- tent. Because training may take several years drogen buses, trucks, trains, drones, and bicycles for workers in developing countries to gain the all available for commercial purchase. Further, necessary skills to support these technologies, hydrogen and fuel cell prototypes have been de- developing countries will have to rely on a small veloped or first units ordered for ferries and small pool of qualified international workers who aircraft. Developing countries have gradually will be in high demand within their own mar- begun to deploy fuel cell buses, notably in Asia, kets. This requirement may increase short-term funded primarily through the support of either deployment costs and increase the timetables for local government or large national utilities. In deployment in developing countries. the long term, the appeal of hydrogen is clear, With regard to fuel cells, the technology itself with local governments in Indonesia (Borneo), was first developed in 1839, and today over 1.6 Brazil, China, Costa Rica, India, Malaysia, 10 One of the leading providers of methanol fuel cells, CHEM Corporation, stated that it has deployed over 3,000 systems, mostly located in the Caribbean, China, India, Indonesia, Japan, Malaysia, South Africa, and other smaller markets (Engineering News Online 2019). 11 The California Fuel Cell Partnership (CAFCP) reports 9,789 FCEVs in California as of September 2019 and 3,386 in Japan. This combined with over 500 FCEVs announced in the EU under the Hydrogen Mobility Europe initiative and the recently announced sales of 1,106 FCEVs for China in 2019 (from data provided by the Power Battery Application Branch of China Industrial Association of Power Sources) provides the basis for the greater than 12,000 figure. Including Australia, Korea, and other markets will increase the numbers modestly. Sources: CAFCP 2019, Sampson 2019, and Xinhua News Agency 2019. 1: Introduction 5 Green hydrogen generation and fuel cell examples: Electrolyzer and community FIGURE 1.2 wind site, Shapinsey, Orkney Islands, United Kingdom (left) and Bloom Energy commercial unit, United States (right) Source: ESMAP (left). © Bloom Energy (right). Nepal, Thailand, and South Africa all expressing with a 50 MW fuel cell in Korea being deployed interest or actively investing in fuel cell mobility to generate power for Daesan Industrial Complex projects. (Hanwha 2018), a hybrid renewable energy and energy storage system in French Guiana to pro- Although there are varying methods for classify- vide 24-hour dispatchable power, and a fuel cell ing the different applications for green hydrogen and fuel cell technologies, this report will group bus program announced in Borneo (Indonesia). potential uses into three core areas of interest: Nonetheless, these classifications do help pro- vide an analytical reference point, given that mo- nn Green hydrogen for power and heat, bility applications typically represent the most nn Green hydrogen for mobility, and, expensive form of energy, followed by power nn Green hydrogen for industry. and heat and then by hydrogen for industrial uses. Accordingly, the categories help influence Within these areas, the types of potential green assessments about when certain applications are hydrogen projects can be extremely diverse, likely to become commercially viable and com- both geographically and with respect to their petitive against alternatives, and what conditions application. For example, a 250 MW electro- are needed to achieve this. lyzer has been proposed by BP for refining gasoline for vehicles in the Netherlands, while a This report is structured to provide readers 20 MW electrolyzer project for producing green first with an overview of why green hydrogen ammonia is being deployed in Quebec and a has gained traction in recent years, why that 12 GW project is under consideration in Pilbara is relevant for developing countries, and what (Australia) for hydrogen exports to Asian coun- implementation challenges remain. In chapter tries. For fuel cells the uses are just as diverse, 2, the report offers a historical context to the 6 GREEN HYDROGEN IN DEVELOPING COUNTRIES development of the current global hydrogen respectively, illustrating the areas in which and fuel cell market and then explains what has developing countries have already begun to de- changed and provides examples of how these ploy hydrogen and fuel cell technologies. These technologies are being used by consumers in chapters also show the wider array of potential developing countries. That chapter, in turn, is applications as the technologies develop and designed to shed light on where current opportu- costs decline further. Chapter 7 provides a list of nities for market growth in green hydrogen exist implementation challenges for green hydrogen and to draw attention to applications that have and fuel cell projects—including safety, trans- been neglected. To help frame the discussion port, and storage—with the aim of helping of green hydrogen within the global context, readers understand some of the technical factors chapter 3 provides a recap of how hydrogen involved in developing projects and of assisting technologies work and details costs and the size policy makers, developers, and investors who are of global markets today. Chapters 4, 5, and 6 considering these types of projects in developing then explore the current array of applications countries. Finally, chapter 8 suggests areas for for green hydrogen and fuel cell technologies further research to help developing countries in power and heat, transport, and industry, assess the potential for green hydrogen projects. 1: Introduction 7 © ORKNEY COUNCIL 2: WHY GREEN HYDROGEN, WHY NOW, AND WHY DEVELOPING COUNTRIES? KEY TAKEAWAYS nn Hydrogen is a well-understood gas that could offer solutions to certain energy, climate, and public health requirements while contributing to decarbonizing economic activities. nn Historically the majority of hydrogen was green, produced from water and power from hydroelectric sites, but this method was subsequently replaced by hydrogen from fossil fuel sources. nn The historically high cost of electrolyzers and variable renewable energy technologies prevented green hydro- gen from emerging as a significant clean energy technology during its first major commercialization wave in the late 1990s and early 2000s, but the circumstances today are different. nn Electrolyzer costs have declined by over 50 percent in the past five years, while efficiencies and system lifetimes have also increased considerably. Meanwhile, the cost of renewable electricity has fallen dramatically, with solar PV power purchasing agreements (PPAs) signed for under $20 per MWh. nn There is an emerging national and corporate consensus that hydrogen is essential to supporting decarboniza- tion pathways in developed and developing countries. nn Developing countries that experience high electricity prices and reliability problems could provide more appealing commercial opportunities for green hydrogen and fuel cell technologies in the near term. nn Hydrogen is not a new technology for developing countries. Large-scale green hydrogen production has pre- viously occurred in developing countries, such as Egypt, India, and Zimbabwe, and its reestablishment could create local economic opportunities for industry while facilitating higher rates of VRE deployments. nn Energy storage solutions based on green hydrogen could help increase grid resiliency, addressing concerns that may arise from challenges posed by VRE integration, climate disasters, or challenges in managing grid load requirements. nn Long-term investment decisions taken today will define the design and structure of future energy systems, which must already consider how to reduce greenhouse gas (GHG) emissions. A failure to identify and develop strategies to incorporate green hydrogen today could lock fossil fuels in and green hydrogen out of national energy systems for decades, potentially hindering CO2 reduction efforts. 2: Why green hydrogen, why now, and why developing countries? 9 2.1. WHY GREEN HYDROGEN? consumers. Green hydrogen is one of the few technologies that currently offers the capability Given the increasing urgency to meet global climate commitments under the Paris Agreement of delivering seasonal energy storage in all mar- and to seek even faster reductions as reflected in kets—notably, in those that cannot develop large the Intergovernmental Panel on Climate Change pumped hydro solutions. Further, green hydrogen (IPCC) 1.5-degree scenario, the wide variety and its derivative fuels, such as ammonia and of applications for green hydrogen make it an methanol, are among the few technical solutions essential part of the decarbonization toolkit. that are capable of reducing emissions in heavy- Indeed, hydrogen is a flexible energy carrier duty transportation sectors such as rail, shipping, that can be transformed into electricity and heat trucking, and even aviation. Today there are fuel for use in decarbonizing activities in industry, cell trains actively deployed or under consider- transport, and buildings. Analysis conducted by ation in China, Japan, Korea, France, Germany, McKinsey for the Hydrogen Council in 2017 the Netherlands, Russia, the United Kingdom, suggested that a transition toward a hydrogen and the United States, while hydrogen-powered economy could lead to 7.5 gigatonnes of annual fuel cell ferries will begin operation in 2021 in CO2 abatement by 2050 (equivalent annually Norway and the United Kingdom. In trucking to 20 percent of the total emissions in 2018) and the urban mobility space, hydrogen is also (McKinsey & Company 2018). Further, as policy a powerful partner to battery-based electric makers seek to encourage a transition to clean solutions. Nearly all fuel cell electric buses energy, there is a growing awareness of the es- today operate in tandem with a battery, while the sential need to find technical solutions that allow flagship Nikola fuel cell trucks also incorporate for the decarbonization of economic activities lithium ion batteries alongside fuel cells. In this while leveraging existing assets whenever possi- context, green hydrogen and fuel cells should be ble. In this context, green hydrogen could offer a seen less as threats to the development of elec- value proposition to a wide array of stakeholders, tric mobility solutions and more as additional including gas companies, utilities, consumers, configurations that can help optimize solutions developers of renewables, and policy makers. for long-range or high-energy applications. Because hydrogen is a well-known industrial Since 2018, energy agencies such as IRENA gas that the world has produced for over 60 and the IEA have concluded that “clean hydro- years, there is significant global expertise on the gen is currently enjoying significant political production and handling of hydrogen, as well and business momentum, with the number of as regulatory guidance, safety standards, and policies and projects around the world ex- established training programs. Hydrogen can be panding rapidly. . . . now is the time to scale used through upgrades to existing gas networks, up technologies and bring down costs to allow adjustments to existing gas turbine technologies, hydrogen to become widely used” (IEA 2019b). and modifications of boilers and to existing The importance of scaling has thus become the commercial vehicles. Accordingly, hydrogen is focus for companies in this sector, driven by seen as particularly appealing to markets with assessments that by creating an enabling envi- sizeable existing gas infrastructure, notably in ronment for green hydrogen production, costs Argentina, China, Europe, the Gulf Cooperation could fall between 30 percent to 70 percent by Council countries, Japan, Korea, Indonesia, 2030 in aggregate (Hydrogen Council 2020; IEA Malaysia, North America, and Thailand. 2019b), and that prices could fall even further But hydrogen’s importance to the energy transi- in certain project contexts. At that level, green tion goes beyond its convenience for existing gas hydrogen could not only reach cost parity with 10 GREEN HYDROGEN IN DEVELOPING COUNTRIES fossil-derived hydrogen—thus becoming a pow- 2. The cost of producing hydrogen from clean erful mechanism for decarbonizing the existing sources has fallen dramatically. The advent of energy and carbon intensive industrial hydrogen solar PV and onshore wind prices that reach commodity market—but it could also become levelized cost of energy (LCOE) points below an important energy vector for decarbonizing the $25 per MWh in Chile, Portugal, Saudi Arabia, wider energy sector. the United States, and other leading markets is enabling some electrolyzer companies to quote a green hydrogen production total cost of 2.2. WHY NOW? below $3.50 per kg. Thus, decentralized green Deep decarbonization of economic activities hydrogen production could soon become cost will require a multifaceted technology approach competitive against delivered gray hydrogen to develop a holistic strategy that provides af- from trailer tubes or cryogenic tanks. fordable, reliable, low- or zero-emission energy 3. Hydrogen technologies have improved in for developing countries. Within these emerg- cost and performance. Electrolyzers and fuel ing frameworks, green hydrogen must now be cell solutions now have significantly better considered when previously it may have been operating lifetimes and system efficiencies discounted as too expensive. This is not the than their predecessors, while they also cost first time that hydrogen has been identified as considerably less and have been tested exten- a potential energy source for the future—and, sively in the field and across a wide array of accordingly, the rapid growth in interest and applications. This creates a powerful posi- investments in green hydrogen have been met tive feedback loop in which green hydrogen with some skepticism. However, four significant production costs continue to benefit from a differences in the market today contrast with the downward cost spiral on both the renewable conditions existing during the failed first hydro- power supply side and the electrolyzer equip- gen phase in the early 1990s and mid-2000s: ment side. This progress has unlocked new 1. Climate regulations are much stronger. funding streams for hydrogen technologies, The Paris Climate Agreement, the European which in turn enables suppliers to provide Union’s (EU) 2030 Climate and Energy more attractive solutions to end customers. Framework, and the commitment to Net Zero 4. The technological infrastructure to support a in 65 nations (United Nations 2019) are a hydrogen energy system is now available. The testimony to the transformation in public clearest example of this point would be the attitudes on climate change. Growing concern fuel cell mobility sector, in which the advent to avoid the IPCC’s 1.5-degree scenario has of battery electric vehicles has ensured that encouraged policy makers and companies to electric drivetrains are now widely available, find energy solutions that can decarbonize effective, and increasingly affordable. These hard-to-abate sectors and to invest resources drivetrains are essential for a fuel cell vehicle, to deploy them. In this context, few alternative which at its core is an electric vehicle that technologies can demonstrate such a breadth simply derives its power from hydrogen and of technically viable decarbonization solu- which frequently uses a battery alongside the tions as green hydrogen can to reduce emis- fuel cell system. sions in sectors such as maritime, rail, and trucking; to provide a route to seasonal energy The impact of these four changes has been storage; and to decarbonize the heating needs profound, and understanding them is key to for industrial and residential consumers. understanding why this time the discussions 2: Why green hydrogen, why now, and why developing countries? 11 FIGURE 2.1 OECD RD&D Spending, US$, millions, 2001–17 H dro n nd fu l c lls Sol r Wind En r stor $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Source: IEA, “RD&D Budget.” IEA Energy Technology RD&D Statistics (database), accessed March 7, 2019, https://doi. org/10.1787/data-00488-en. Note: OECD = Organisation for Economic Co-operation and Development; RD&D = research, development, and deploy- ment. The dataset includes statistics on energy technology research and development (R&D) and dissemination as well as R&D budget for International Energy Agency countries. It presents shifts in R&D expenditures associated with investments and further analyzes budget allocations in terms of flow. around hydrogen are different. To assist in this fuels in the near term and renewable energy process, this report reviews the context behind sources in the longer term, hydrogen can the first phase of using hydrogen as an energy contribute significantly to each of the five solution to explain the early barriers and market goals stated in the DOE’s Comprehensive failures. National Energy Strategy (April 1998) regard- ing energy efficiency, energy security, the environment, the expansion of future energy 2.2.1. Historical context choices, and international competitiveness” Although the dates are contested, the first signif- (HTAP 1998, 1). icant attempts to deploy hydrogen as an energy The authors of the HTAP report were not alone in solution began in earnest in the 1990s. In the their conclusions. Over the next decade gov- United States the best initial starting point is ernments around the world invested heavily in the 1998 Hydrogen Technology Advisory Panel research, development, and deployment (RD&D) (HTAP) review of the state of hydrogen technolo- of hydrogen and fuel cell solutions. The IEA gies, which was submitted to the US Congress. In estimates that between 2000 and 2010, the sector it, the authors wrote: received on average 7 percent of global energy “Hydrogen is an important energy option for RD&D (OECD 2019) (see figure 2.1). Yet, the the Nation and the world. Based on fossil technologies failed to gain commercial traction, 12 GREEN HYDROGEN IN DEVELOPING COUNTRIES FIGURE 2.2 World’s Largest Electrolyzer: Norsk Hydro 135 MW Electrolyzer, Glomfjord, Norway Source: Nel 2018c, slide 4. © Nel. and from 2009 to 2017 global funding roughly and other products was technically challeng- halved, falling from 9.2 percent of world energy ing and prohibitively costly, those markets that RD&D in 2009 to 5.2 percent in 2017. lacked access to coal and natural gas frequently turned to alkaline electrolyzers. Those electro- There are four key reasons why green hydrogen lyzers were often used in conjunction with large and fuel cell technologies failed to gain traction: hydropower resources and reached significant 1. There was no market demand for green hydro- sizes, notably Nel’s (Norsk Hydro) world record gen from industry. 135 MW electrolyzer in Glomfjord (Norway), which was built in 1953 and operated until 1991 2. Hydrogen from electrolysis was not cost com- (Nel 2018c) (figure 2.2). petitive against alternatives. This early market for green hydrogen lost its 3. Fuel cell technologies were still emerging, cost-competitive edge once the global maritime with short operating lifetimes, low efficiencies, industry expanded and vessel designs became and high system costs. more advanced. This development made it 4. Enabling technologies, such as electric drive- considerably easier and cheaper for smaller countries and consumers to import ammonia trains, were almost nonexistent. that had already been created elsewhere rather The lack of green hydrogen demand from indus- than to install electrolyzers and smaller-scale try was a function of both economics and limited Haber-Bosch units themselves.12 These changes regulatory incentives to switch to lower-carbon ensured that by the early 1990s to late 2000s, solutions. In the early years of the hydrogen sec- there was almost no cost advantage to using tor (pre-1950s), when transportation of ammonia hydrogen from electrolysis except in very 12 Haber-Bosch is the process of creating ammonia through combining hydrogen with nitrogen from the atmosphere to make NH3. A good explanation is on the Encyclopaedia Britannica website: https://www.britannica.com/technology/Haber-Bosch-process. 2: Why green hydrogen, why now, and why developing countries? 13 location-specific contexts. Accordingly, industry companies involved in the early efforts was that needed either a regulatory incentive to sup- fuel cell systems had poor stack system lifetimes ply green hydrogen or demand for an energy and low system efficiencies. Consequently, sub- service that only hydrogen could provide. In stantial amounts of investment in research and the early 1990s and 2000s, the sector found development (R&D) were needed to improve neither. lifetimes to the level expected for commercial operations. The scale of money sums involved The challenges faced by the green hydrogen sec- wiped out many early venture capital investors tor in finding an energy service to drive demand and inflicted heavy losses on some of the world’s for the product were amplified by the challenges largest industrial corporations. facing the development of fuel cell technologies, which were seen as the primary mechanism A good illustration of this challenge was the to consume hydrogen for energy applications. case of Siemens-Westinghouse’s funding for While fuel cells had existed since 1831 and had solid oxide fuel cell (SOFC) systems (figure 2.3). been deployed by the National Aeronautics and Early SOFC systems had very poor stack life- Space Administration (NASA) in the early Gemini times, making them unsuitable for most power, space programs, the considerable investments and many mobility applications. Improving the made between the 1990s and early 2000s were lifetimes of SOFCs required significant and sus- not able to create a minimally commercially vi- tained investment. Accordingly, it was estimated able product before hydrogen’s first phase ended that Westinghouse and the US Department of and it was overtaken by solar, wind, and elec- Energy (DOE) spent $150 million on SOFC re- trochemical batteries. A key challenge for many search from the late 1980s until the 1990s, when FIGURE 2.3 Lifetime Performance of Siemens-Westinghouse SOFC Units, Test Results 14,000 12,577 12,000 10,000 SOFC Op r tin Hours 8,000 6,000 4,000 2,000 1,666 0 1990 1992 1994 1996 1998 2000 2002 2004 2006 r Source: OECD/IEA 2005. Note: SOFC = solid oxide fuel cell. 14 GREEN HYDROGEN IN DEVELOPING COUNTRIES Siemens acquired the business for $1.53 billion as regenerative braking were far less efficient, the in 1998. Yet, despite additional investments and overall system efficiency was well below what is work with the DOE, Siemens closed its SOFC expected from a modern FCEV. unit and sold the assets in 2008, a decade later (Olson 2008). 2.2.2. Present day In addition, fuel cell systems required other en- While the decline in the cost of renewable abling technologies to be developed and scaled power is becoming essential to improving the in tandem, with the best example being the commercial viability of green hydrogen, other automotive sector. In the 1990s and early 2000s, changes are also playing a key role in facilitating most investors, policy makers, and researchers the initial deployment of green hydrogen and thought that the most attractive business case fuel cell technologies. Principally, the global for hydrogen and fuel cell scaling was light duty pressure for clean energy technological solutions vehicles. At the time, this was intuitive because and the emergence of enabling technologies— of rising fears about peak oil prices; concerns in such as batteries, electric drivetrains, the “inter- Europe, Japan, and the United States about reli- net of things,” and high-speed internet access— ance on the Middle East for petroleum products; are transforming the competitive landscape for and the potentially higher efficiencies promised green hydrogen and for fuel cell technologies. In by fuel cell systems. Yet, despite these consider- tandem to these changes, electrolyzer and fuel ations, manufacturers quickly realized that to run cell technologies are now better, with the bulk of a fuel cell, they also needed to build an electric initial technical challenges having been ad- car,13 which created a major problem because dressed and cost becoming the largest remaining the electric vehicle (EV) sector in the ’90s was barrier to widespread commercialization. nonexistent, and even in 2005 there were barely more than a few hundred electric vehicles glob- The results of these changes are becoming clear. ally (Plummer 2016). Currently there are more than 20 GW of glob- ally announced electrolyzer projects in varying The final issue was that fuel cells required origi- stages of project development, including from nal equipment manufacturers (OEMs) not only to prefeasibility to firm orders, covering almost every support additional R&D to improve the stack time continent. In less than three years, more than 82 of fuel cells but also to find and develop hydrogen of the world’s largest companies, controlling over storage, hydrogen compressors, and hydrogen $2.6 trillion in revenue, have joined the Hydrogen safety mechanisms for vehicles from scratch. For Council, the flagship industry initiative for in- the few that did persevere to develop fuel cell dustries fostering hydrogen as an energy solution electric vehicles (FCEVs), this process simply (FuelCellWorks 2019b). Although many of these created expensive vehicles that were considerably partners are focused on hydrogen generation less efficient than their potential.14 In part because from fossil fuels, possibly combined with carbon PEM fuel cells were much less efficient during this capture technologies, almost all of them are also period than they are today, but also because elec- exploring electrolyzer business models, including tric drivetrain technologies and innovations such those with existing and substantial natural gas 13 While there is some debate about why this shift occurred, the main issues appear to have been linked to safety concerns around gas leaks and questions about the costs of adding hydrogen storage and petroleum storage in a vehicle. 14 Research from the IEA in 2005 noted that the assumed fuel-to-wheel efficiency of FCEVs at that time was around 28 percent (IEA/OECD 2005), compared with figures that McKinsey & Company provided for FCEVs in 2017 that showed efficiencies above 44 percent (Hydrogen Council 2017). Indeed, Toyota in 2019 announced that its latest FCEV would achieve above 60 percent efficiency. 2: Why green hydrogen, why now, and why developing countries? 15 resources. Countries are now channeling signifi- future.” This report further proposed a draft of cant financial resources into this space, with China policy measures and identified areas in which alone allocating an estimated $12.4 billion in technological breakthroughs were essential to subsidies for deployments and R&D for fuel cell– see the sector flourish. These developments have powered vehicles in 2018 to be distributed across subsequently been built on during the second local, state, and central government budgets and Hydrogen Energy Ministerial in September through state-owned enterprises (Sanderson 2019). 2019 and further supported through the release of the report “Hydrogen: A Renewable Energy As a result of these developments, hydrogen to- Perspective,” which IRENA produced to provide day is recognized by many of the world’s leading countries with help developing supportive policy economies and corporations as a key component frameworks to accelerate the deployment of green in enabling the energy sector transition. In 2018 hydrogen (IRENA 2019). the world’s first Hydrogen Energy Ministerial summit was hosted in Tokyo, and a second event was held in September 2019. At the first ministe- 2.3. WHY DEVELOPING rial summit, participants announced the “Tokyo COUNTRIES? Statement,” which consisted of four actions: Developing countries are responsible for more (1) Promote technical collaboration and en- than half of the world’s GHG emissions, and courage standardization and harmonization their carbon footprint is growing in both ab- of standards and regulations between coun- solute and proportional terms.15 Accordingly, tries and businesses; (2) define the direction there is an increasing need to identify, assess, of research and development that countries and deploy low- to zero-emission fuels such as should collaborate to achieve hydrogen green hydrogen to support developing countries energy society including securing hydrogen in meeting their development targets and climate safety and development of hydrogen supply commitments. The reemergence of hydrogen as chain; (3) study and assess potential eco- a solution for the energy sector has largely been nomic effects of hydrogen energy use and discussed in the context of developed markets effects of CO2 reduction in order to attract such as Australia, the European Union, Japan, investment and create business; and (4) em- and the United States. While this is unsurprising phasize the importance of education and given investor familiarity with these markets and public relations activities which allows all the financial resources available to policy makers citizens in the world to widely understand in those countries, there are unique features that and accept hydrogen energy. (METI and make developing countries extremely enticing for investors in green hydrogen technologies NEDO 2018) and that perhaps have not been given sufficient Energy ministers also agreed that the outcome consideration. of the meeting would be an input for the G20 Summit in June 2019. At this second event in 2.3.1. Hydrogen can help increase 2019, the IEA launched its “Future of Hydrogen” energy security report (IEA 2019b), which concluded, “The time is right to tap into hydrogen’s potential to play a Green hydrogen allows developing countries key role in a clean, secure and affordable energy to locally produce an extremely versatile fuel 15 World Bank, “CO2 Emissions (kt),” dataset, https://data.worldbank.org/indicator/EN.ATM.CO2E.KT; Center for Global Development (CGD) 2015, https://www.cgdev.org/media/who-caused-climate-change-historically. 16 GREEN HYDROGEN IN DEVELOPING COUNTRIES that can be stored over long time periods and 2.3.2. Electric power in developing requires only renewable power and water. This is countries can be extremely expensive transformative for countries that are dependent In many developing countries electric power is on costly energy imports, typically petroleum, more expensive than in developed ones, a feature and that are exposed to both oil price volatility which is especially concerning given the lower and energy security risk if the fuel supply is par- relative purchasing power of consumers in these tially or fully disrupted. These fuel supply disrup- countries. Because of fuel price volatility and tions could be caused by regional conflicts, geo- additional costs incurred by many developing political tensions, the financial situation of local economies in importing natural gas, coal, and utilities, or corruption—all of which undermine petroleum products such as diesel, the econom- economic growth and development objectives. ics for green hydrogen and fuel cell solutions It is crucial that developing countries can count could be significantly more appealing in devel- on reliable and affordable resources to power oping countries than for developed ones. This is their economic activities and meet their national certainly the case in remote islands like Kiribati development objectives. Although renewable or Vanuatu, where retail power prices exceed resources are widely available in many devel- $400 per MWh (UNECLO Engie 2019), and even oping countries, they cannot be dispatched on countries with close proximity to large petroleum command and require storage to meet instanta- producers, such as Mali, can face electric power neous demand. Green hydrogen could thus help prices exceeding $230 per MWh (World Bank support the development of renewable energy 2018). Although solar PV, wind power, and other systems by providing the long-duration energy renewables could help reduce these prices and storage capability and flexibility that fossil fuels their underlying generation costs, the grid integra- have traditionally provided to the power sector. tion of VREs can be challenging at high penetra- Currently the import demand for oil-derived tion rates, and their value may be limited when fuels can be a source of significant economic it comes to providing firm capacity. Accordingly, and political instability, in part because of the there could be opportunities for countries to volatility of global oil prices combined with the provide dispatchable, renewable power leverag- low elasticity of fuel consumption, which can ing the flexibility of green hydrogen, particularly amplify price spikes and have a severe negative in systems in which access to low-cost fuels may local impact on competitiveness and economic be limited. In small diesel-based power grids, growth. While developing countries have hydrogen hybrid systems in conjunction with so- traditionally attempted to mitigate these issues lar power and batteries could also be a potential through subsidies, the consequences include solution for providing locally produced electricity significant fiscal pressure on finance ministries, and fuels, thus reducing cost and diversifying fuel economic inefficiencies, and political pressures supply to mitigate supply risk from any specific to maintain or expand the subsidies. Green company or country (box 2.1). hydrogen production could play a major role in providing a decentralized form of fuel produc- 2.3.3. Developing countries already tion that is driven not by the volatility of global have experience with large-scale prices, but rather by local renewable power pric- hydrogen projects ing and local supply and demand. This option could also reduce the need for subsidies and the Hydrogen is not a new commercial product need to draw from foreign exchange reserves to and electrolyzers are not new to developing pay for fuel imports. countries. Hydrogen has long been an important 2: Why green hydrogen, why now, and why developing countries? 17 BOX 2.1 HYBRID ENERGY STORAGE SYSTEMS IN FRENCH GUIANA Remote systems have long been attractive to renewable energy developers, owing to the high cost of imported power and the need to provide resiliency in the event of grid outages, whether from weather events, theft, or grid imbalances. Still, integrating VRE into small grids can be challenging, despite the compelling economics of solar PV compared with diesel alternatives. The past few years have seen the proliferation of hybrid solar PV, diesel, and battery solutions, operating concurrently in different configurations, as potential alternatives to decarbonize remote energy systems. But in French Guiana, HDF Energy believes that green hydrogen and fuel cells could be part of the answer to displacing diesel entirely and providing longer-duration storage than batteries alone. The Centrale Électrique de l’Ouest Guyanais (CEOG) project is seeking to deploy a 55 MW solar PV site, in conjunction with a 20 MW battery, a 20 MW electrolyzer, and a 3 MW fuel cell, to provide what the company calls a “RE-new stable” solution for its customers. In effect, the company will provide 10 megawatt-hours (MWh) of dispatchable power during peak daytime hours, dropping down to 3 MWh during the off-peak evening times. The project size is signifi- cant when compared to the country’s national grid capacity of just over 300 MW. The project has already secured 60 percent of the equity funding from French investment house Meridiam and was due for financial close in December 2019. While the project has not disclosed its pricing publicly, the company has confirmed that the project will not rely on subsidies and thus is expected to come in around (or below) the latest solar and battery project in the region, which secured a power purchase agreement at EUR 260 per MWh. Given the ability to provide dispatchable base load power at prices below or at least compa- rable with diesel, the CEOG project offers a unique approach to decarbonizing remote energy systems. Note: The project data is from HDF Energy 2019. The source of the greater than 300 MW installed ca- pacity figure for French Guiana is U.S. Energy Information Administration data for 2016, https://www. eia.gov/opendata/qb.php?category=2134409&sdid=INTL.2-7-GUF-MK.A. industrial gas for developing countries, owing to at the Aswan dam in Egypt in 1960 (Buttler its role in the production of ammonia for fertiliz- and Spliethoff 2018). Given these experiences, ers. In the period before the advent of advanced hydrogen electrolyzer projects are not a new modern ship designs, which made ships capa- concept for the development finance commu- ble of storing and transporting large volumes of nity. To meet the need to produce local fertiliz- ammonia, hydrogen production from domes- ers, often from ammonia (via hydrogen), multi- tic sources was essential to helping emerging lateral organizations like the World Bank were markets increase domestic food production. extensively involved in projects that required the Accordingly, there have been units as large as consumption and production of hydrogen from 106.0 MW installed in India (1958), 74.6 MW domestic sources. Examples of projects financed in Zimbabwe (1975), and 115.0 MW installed by the World Bank in the fertilizer sector include 18 GREEN HYDROGEN IN DEVELOPING COUNTRIES FIGURE 2.4 World’s largest current electrolyzer (25 MW), polysilicon plant, Sarawak, Malaysia © Nel 2018a, slide 5. © Nel. Note: ESMAP research suggests that this is the largest currently operating unit as of 2019. the IGSAS fertilizer project in Turkey in 1980 is used in Malaysia in the production of polysil- (World Bank 1980), the Talkha II fertilizer project icon. In Costa Rica, hydrogen from renewable in Egypt in 1983 (World Bank 1983), and the power and electrolysis is also used for certain Fauji fertilizer plant in Pakistan in 1986 (World commercial applications. These experiences Bank 1986). create a starting base from which a scaling up Even today, countries like Malaysia, which have of green hydrogen production for industrial access to natural gas and SMR, still use alkaline decarbonization can be built into the policy electrolyzers to support manufacturing. In the discussion and in the national green hydrogen case shown in figure 2.4, a 25 MW electrolyzer strategies in developing countries. 2: Why green hydrogen, why now, and why developing countries? 19 2.3.4. Integrating large shares of that can mitigate the long-term variability of re- variable renewable energy requires newable resources (weekly and seasonal) because long-duration storage hydrogen can be stored for long periods of time and subsequently used for power generation in Although many developing countries have sig- a fuel cell (or turbines). This feature could create nificant renewable resources, integrating large opportunities to develop firm renewable-based amounts of VRE into local grids can be techni- solutions or renewable microgrids that can meet a cally complex for any power system. As electric predefined generation profile, or fully adapt to the power systems grow, so does their peak demand, variability of electricity demand. Although this op- requiring countries to increase the amount of tion may be a longer-term ambition, the existence generation capacity available during the peak of hydrogen gas caverns in the United Kingdom or when it is needed most. This type of capacity and the United States and pilots to use hydrogen is known as “firm.” The amount of firm capacity for seasonal renewable energy storage in Austria16 provided by VRE technologies (also known as show that green hydrogen could be an option capacity value) is very limited given the technolo- worth exploring for developing countries that are gies’ uncontrolled variability. In countries with no planning the future of their energy systems over access to firm generation technologies (typically the next 30 or even 50 years. The ability to firm large hydro or generators running on fossil fuels), up renewable generation, or to develop what one meeting peak demand with renewables requires developer has called, “a re-new stable solution,”17 the deployment of different forms of long-duration therefore can unlock markets for VRE technolo- energy storage to “firm up” the output from VRE gies that have thus far been reluctant to scale up plants and guarantee that there will be sufficient deployments or can further increase renewable energy available to meet the peak. use in locations that have reached their maximum Integrating VRE into grids is difficult regardless of penetration levels. location, but developing countries face partic- Additionally, electrolyzers are already providing ular difficulties posed by unreliable grids with grid-balancing services in a number of territories, insufficient back-up generation capacity and a and the early experiences can serve as case stud- lack of automated supervisory control and data ies for how hydrogen can support further VRE de- acquisition systems. Grids in developing coun- ployments. In Canada, for example, the Markham tries can be more sensitive to sudden changes Energy Storage project uses a 2.5 MW electrolyzer in demand and supply and less able to main- to provide secondary frequency control for the tain grid stability than in developed countries. Independent Electricity System Operator, while Further, regulators and utilities in these markets in the United Kingdom ITM Power’s 3 MW bus often have limited technical capacity to address refueling station in Birmingham provides demand the impacts of VRE on their systems, and so in- response services to the utility, National Grid. vestors may experience an aversion to deploying large VRE projects. 2.3.5. Green hydrogen offers local In this context, energy storage, including batteries industry development opportunities and green hydrogen, can help provide additional balancing mechanisms to support VRE integration. One of the most compelling reasons that green Green hydrogen is one of the few technologies hydrogen has significant potential as a resource 16 This was derived from discussions with Verbund staff members about the company’s hydrogen plans in 2019. 17 Comments from Jean-Noël de Charentenay of HDF Energy, July 2019. 20 GREEN HYDROGEN IN DEVELOPING COUNTRIES BOX 2.2 BALANCING WIND IN THAILAND: SOUTHEAST ASIA’S FIRST MEGA- WATT-SCALE ENERGY STORAGE PROJECT Thailand has emerged as one of the most dynamic markets for renewable energy, driven by the relative lack of domestic oil and gas resources and the relative abundance of wind and solar re- sources. Nevertheless, like many countries, Thailand has been managing the challenges associ- ated with balancing variable renewable energy within a national grid system that was designed for dispatchable power resources. While batteries provide grid operators and developers with a powerful resource to address a number of these challenges, the Electricity Generating Author- ity of Thailand (EGAT) has also been exploring the role that hydrogen and fuel cell integrated solutions can play in grid balancing. In 2016 the Lam Takhong Wind Hydrogen Hybrid Project was announced. The project com- bines a 22 MW onshore wind site in Nakhon Ratchasima Province, Thailand, with a 1 MW proton exchange membrane (PEM) electrolyzer and a 300 kilowatt PEM fuel cell. The elec- trolyzer converts excess power from the wind site during off-peak hours, allowing the fuel cell to provide clean power to EGAT’s Learning Center building, as needed. In total, the system provides 3 megawatt-hours of compressed hydrogen storage (250 bar), allowing for up to 10 hours of continuous power supply. The cost for the electrolyzer and fuel cell system was EUR 4.3 million. in developing countries is that nations without the use of water and renewable-generated elec- access to fossil fuel resources—such as natural tricity to produce green hydrogen, which could gas, oil, or coal— but with good renewable in turn be used in the synthesis of ammonia. As resources could use locally produced green the cost of electrolysis continues to decline and hydrogen to develop both their national energy renewable energy costs continue to fall, it would system and an industrial market simultaneously be reasonable to anticipate in the future an (box 2.2). Green hydrogen could thus hold out increase in the volume of green hydrogen pro- the possibility for some developing countries duction within emerging markets, a process that to create a domestic, renewable fuel that could could transform domestic industries and disrupt contribute to local job creation (such as in major established markets. As noted previously, hydrogen infrastructure, transport, construction, many developing countries did historically pro- and agriculture) and new social opportunities (by duce their own hydrogen and ammonia domes- providing access to heat, reducing local pollu- tically, before production moved to lower-cost tion, enhancing the livelihood of local communi- markets as global pricing became linked to the ties, and addressing existing gender gaps). ability to access cheap domestic natural gas resources. Green hydrogen also offers developing nations the ability to exploit sector coupling opportuni- A key challenge for developing countries has ties, in which greater economic efficiencies are been that the unit sizes that have been ordered achieved by using the same assets in processes for electrolyzers, fuel cell vehicle fleets, and that belong to different sectors. For example, stationary power solutions in the first projects the agricultural sector, the water sector, and the have been smaller than in developed markets power sector could be interconnected through (with China being an exception). That scale 2: Why green hydrogen, why now, and why developing countries? 21 FIGURE 2.5 Fuel cells for critical infrastructure in Indonesia © Cascadiant Indonesia. leads to higher costs and puts further pressure Kenya, while today there are already over 800 on the commercial appeal of the technologies. fuel cell systems providing power to telecommu- Accordingly, greater commercial hydrogen nications and other critical systems in Indonesia deployment in developing countries will require (figure 2.5). The number of fuel cell systems broad strategic pathways and wide partnerships deployed in China and India is harder to track, to aggregate demand and justify investments but some market participants estimated it to be at scale. Initiatives that have begun to develop in the low thousands and growing. Suppliers are these elements are under way. An example is the also commenting that fuel cell systems are being African Hydrogen Partnership, which is helping used to provide power for applications such as investors, policy makers, and companies view wildlife surveillance systems to prevent poach- hydrogen production as part of a wider energy ing and for powering wind meter measurement ecosystem that can underpin regional economic towers in developing countries across Asia and development, regional transportation, and Africa. Some systems are even being used in deeper economic integration (box 2.3). drones to monitor deforestation. Fuel cells could offer significant benefits for 2.3.6. Reliable power supply for critical developing countries that are seeking climate-re- systems, climate resiliency, and industry silient energy solutions, because they can provide Power supply interruptions are a major inhibitor long-duration power supply (in some cases up of economic growth in developing countries. to six months without refueling if ammonia or Accordingly, fuel cells are a technology that methanol is used) as well as minimal required could help reduce the risk of power losses to maintenance and lower risk of theft. These at- crucial sectors, even when the grid experiences tributes are particularly relevant in settings that disruption. Fuel cell systems are due to supply face fragility, conflict, and violence, where fuel over 800 telecommunications stations in Kenya cells could address some of the impacts derived through the local telecom company Adrian from the fragility of the situation. In the aftermath 22 GREEN HYDROGEN IN DEVELOPING COUNTRIES BOX 2.3 A STRATEGIC VISION FOR AFRICA’S HYDROGEN ECONOMY Ensuring that Africa is able to obtain affordable, reliable, and clean energy resources is essen- tial not only to the continent’s economic development but also to the world’s ability to stay under the 1.5 degrees increase threshold set by the IPCC. Energy access remains a pressing concern for policy makers, businesses, and communities, while even consumers with access to electricity can still suffer from frequent blackouts. Energy is also expensive for many African consumers, who may have a heavy reliance on imported petroleum even in countries that might be net exporters of crude oil products. Given these challenges, the African Hydrogen Partnership (AHP) believes that hydrogen might be the key to address some of Africa’s energy problems.. Working in partnership with governments, private sector companies, and financial institutions, the AHP has drafted a series of high-level stra- tegic documents to help policy makers and investors visualize an Africa-wide hydrogen strategy. The core challenge is achieving significant scale as soon as possible. Accordingly, the AHP recom- mends a strategy of establishing “landing zones/bridgeheads,” where initial green hydrogen proj- ects could be developed before expanding into other clusters (figure B2.3.1). The first nine markets include Djibouti, the Arab Republic of Egypt, Ethiopia, Ghana, Kenya, Morocco, Nigeria, South Africa, and Tanzania. Specific plans are set for each city and use cases for each market, most no- tably the coordinated procurement of fuel cell buses across several cities to reduce costs. To finance this vision, the AHP is proposing a green bonds program for Africa and is working alongside stock exchanges in Africa and Europe to design a framework for investors and gauge initial appetite. While the AHP initiative might appear abstract, evidence from other markets has shown that developing strategic concepts is essential to helping policy makers, investors, and consumers understand the role that hydrogen might play. Figure B2.3.1. African Hydrogen Partnership landing zones and operational planning outline Trans African-Highways & Cities • Cities — Aligiers to Lagos — Cairo to Dakar — Cairo to Mogadishu — Dakar to Djibouti — Dakar to Lagos — Lagos to Mombasa — Lagos to Luanda — Beira to Luanda — Cape Town to Djibouti — Gaborone to Lüderitz — Durban to Dar es Salaam — Mombasa to Dar es Salaam Pipelines, existing & future (new usage) t Hubs — Gas existing (Hydrogen) - - - - Gas future (Hydrogen) — Oil existing (LOHC) - - - - Oil future — Products existing (ammonia, LOHC/MCH) - - - - Products future (ammonia, LOHC/MCH) Railways, past & existing — Railways Source: African Hydrogen Partnership 2019. 2: Why green hydrogen, why now, and why developing countries? 23 of Hurricane Katrina, the U.S. DOE noted that provide a model for developing countries in the fuel cells had played an essential role in ensuring future. Notable among these are the Raglan Mine backup power provision for critical communica- project in Canada, the Cerro Pabellón minigrid tions equipment and substation functions. Indeed, in Chile, and the Daintree hydrogen microgrid in in 2012 fuel cells were credited with keeping the Australia (Maisch 2019). emergency 911 service functional in Barbados after Hurricane Sandy (Renewable Energy Focus 2.3.7. Urban mobility solutions to 2012). Fuel cell systems have also been deployed reduce air pollution for monitoring earthquake tremors and for ensur- ing that medical supplies—critically, those that Hydrogen for mobility is a growing area of focus require cooling—have access to reliable power. for countries. The IEA’s latest research illustrates Similarly, GenCell (a leading provider of fuel cells that only 2 countries in the world have policies to for resiliency applications) recently announced incentivize hydrogen in industry, but 5 have pol- its entry into the Philippine market with a specific icies to promote fuel cell trucks, 10 have policies focus on ensuring business continuity and support for fuel cell buses and refueling stations, and 15 for critical infrastructure during severe storms and have policies to encourage hydrogen in passenger earthquakes (GenCell 2019). vehicles (IEA 2019b). Indeed, for urban mobility applications fuel cell buses provide a comple- While large-scale stationary fuel cells may take mentary solution for urban planners seeking to longer to arrive in emerging markets, several reduce localized air pollution and also to integrate notable examples have already been deployed. battery-electric solutions into a congested grid. Bloom Energy has sold its first units in India (fig- Hydrogen for mobility has long been of interest ure 2.6), while HDF Energy has installed a 1 MW to developing countries with bus programs; it was unit in Martinique (France). Hybrid renewable considered in Brazil in 2012, while New Delhi minigrids in developed countries include hy- had a fleet of fuel cell rickshaws developed around drogen and other storage technologies and may 2012 (Yee 2012). Between 2008 and 2012, the FIGURE 2.6 Commercial fuel cell installation in India © Bloom Energy. 24 GREEN HYDROGEN IN DEVELOPING COUNTRIES BOX 2.4 FUEL CELL BUSES IN INDIA India has been closely monitoring hydrogen as a domestic alternative to lithium ion battery– based systems for mobility. Given the abundance of domestic biowaste that can be converted into biomethane (and reformed for hydrogen), coupled with significant local air quality chal- lenges and the desire to promote local manufacturing, hydrogen has become a logical route for policy makers to explore. One of the most prominent actors in this move toward hydrogen for mobility in India is the Indian Oil Company (IOC), which has already trialed Tata buses using Ballard fuel cells on its R&D Campus. Recently IOC has also submitted a bid to provide hydro- gen and to develop four Indian-manufactured fuel cell buses for operation in Delhi, following a tender by the Ministry of New and Renewable Energy (Gupta 2019). India is exploring blending hydrogen into existing buses that already run on compressed natural gas (CNG), with a pilot commissioned in Delhi to run up to 50 buses on an 18 percent hydro- gen/22 percent CNG blend. IOC estimates this could cut carbon dioxide emissions from these CNG buses by up to 70 percent (Gupta. 2019). United Nations Development Programme was technically appealing to developing countries involved in a series of activities to bring hydrogen in the near future. But despite the significant mobility solutions to Turkey, which was followed potential for green hydrogen deployments in by a $10 million grant to the program in China in developing countries over the medium and long 2017 to advise the local government of Rugao. term, in the short term observers anticipate that Today, five developing countries have either the deployment of electrolyzers and large-scale ordered or deployed fuel cell mobility solutions, production of green ammonia could be slow, including Indonesia, China, Costa Rica, India (box particularly in countries with access to low-cost 2.4), and Malaysia. The development finance com- natural gas. This situation is largely due to the munity has also supported some of these efforts. low cost of hydrogen derived from natural gas For example, the Interamerican Development and to the expectation that companies will focus Bank provided financial support to the fuel cell on lower-hanging opportunities elsewhere in the energy sector of developed markets and will wait mobility provider Ad Astra to support a local fuel for green hydrogen prices to fall further before cell bus and hydrogen refueling station project in expanding into developing countries. Yet, devel- Costa Rica, while the Asian Development Bank oping countries may start deploying green hydro- invested in 10 fuel cell electric buses for the 2022 gen systems early if they have excellent renew- Beijing Winter Olympics. able resources, unique energy requirements, or a high level of synergy between the development of green hydrogen for industry, mobility, power, 2.4. SHORT-TERM, MEDIUM-TERM, and heat. These early deployments or first-of- AND LONG-TERM OPPORTUNITIES a-kind projects may be considered in regions FOR GREEN HYDROGEN with exceptionally good renewable resources A wide array of compelling reasons explain and where the lack of preexisting infrastructure why green hydrogen production and fuel cell creates a clear incentive to engage policy makers technologies may become commercially and and investors sooner rather than later to avoid 2: Why green hydrogen, why now, and why developing countries? 25 technology lock-in to high-carbon-emitting en- supply, local air quality issues, high cost of diesel ergy alternatives. or other fossil fuels, and the need for long-dura- tion power supply. It also remains likely that fuel Similarly, fuel cell deployments are likely to ac- cell mobility solutions will continue to interest celerate in developing countries, as the systems developing countries. continue to decline in cost and provide a num- ber of key benefits to consumers who face an array of energy challenges, such as reliability of 26 GREEN HYDROGEN IN DEVELOPING COUNTRIES 3: STATE OF THE MARKET KEY TAKEAWAYS nn In 2019, the global hydrogen market was worth $135 billion, with over 70 million tonnes produced that year and 10 million tonnes of the demand coming from China. nn Global electrolyzer manufacturing capacity is currently above 2 GW per annum, and it is forecast to exceed 4.5 GW on the basis of current expansion commitments. nn Global fuel cell manufacturing capacity is currently about 1.5 GW per annum. Fuel cell demand has grown dramatically, to 1.6 GW stationary installed capacity and over 300,000 units deployed, most of which are based on proton exchange membrane (PEM) systems. nn Similar to development of the lithium-ion battery market, PEM fuel cell manufacturing capacity and cost declines are being driven by the transport sector. However, the market focus for fuel cell in transport is mov- ing toward larger uses—trucks, buses, trains, and ships—rather than light-duty cars. nn In some contexts and geographies the production of green hydrogen could already be cost competive with fossil alternatives. nn If hydrogen demand were to scale at the pace anticipated by analysts, the likely consequence would be to have a short-term increase in coal and natural gas demand for hydrogen production. nn In the medium to long term, demand for fossil fuel–produced hydrogen will depend on whether expected electrolysis and renewable power cost declines are realized. nn Key factors that will drive green hydrogen prices are the quality of the renewable resource, renewable and electrolyzer capital expenditures, and load factors that extend above 3,500 hours per annum. nn Fuel cell technologies come with different costs, efficiencies, operating temperatures, and lifetimes. Therefore, capital exenditures alone will not always be the key driver of technology choice. 3: state of the Market 27 3.1. HOW FUEL CELL AND cells (AFC). Two core components of a fuel cell ELECTROLYZER TECHNOLOGIES are the membrane electrode assembly (MEA) and WORK the plates that are used to enclose them, which typically are either steel or ceramic. The MEA 3.1.1. Fuel cells is where most companies hold their intellectual property, and it remains the most complex part Fuel cells are energy conversion devices that of the unit. A fuel cell system can use multiple combine hydrogen with oxygen to produce types of electrolytes to facilitate a chemical re- water and energy (electricity and heat). Inside action, and individual fuel cell technologies gain the fuel cell, hydrogen is passed through the their names from the types of electrolytes used. anode, where hydrogen is oxidized producing hydrogen ions and electrons that move to the Fuel cells can be used for a wide range of ap- cathode through an electric circuit. An electro- plications, including stationary power, portable lyte solution allows hydrogen ions to move from power, and mobility. They are commercially the anode to the cathode, where they react with deployed in a range of geographies and appli- oxygen and electrons from the anode, producing cations, with a current scale range of several water (figure 3.1). watts up to 50 MW (under consideration). Today there are five core fuel cell technologies that are The first fuel cell was invented in 1831 in the commercially available. These are PEM, AFC, United Kingdom, and fuel cell systems were molten carbonate fuel cells (MCFCs), solid oxide deployed in several of the early NASA space fuel cells (SOFCs), and phosphoric acid fuel cells programs in the 1950s and 1960s—notably, in (PAFCs). In the stationary power market, units the Gemini missions. The earliest and most es- above 1 MW are typically PAFC or MCFC, while tablished fuel cell solutions are proton exchange units between 100 kW and 1 MW are typically membrane (PEM) fuel cells and alkaline fuel SOFC or PAFC. The two key differences between the primary Simple diagram of a proton fuel cell technologies are their input fuel(s) FIGURE 3.1 and their operating temperatures. Typically, exchange membrane fuel cell PEM and AFC solutions operate under 100oC, thus limiting their usage for combined heat EN EN OG and power (CHP) services, but other fuel cells YG DR LOAD OX e– e– HY can operate between 500oC and 650oC. High- temperature fuel cell systems typically have e– e– higher electrical (and thermal) efficiencies and H + run almost continuously, making them better ANODE CATHODE suited for baseload power provision and well FLOW AREA e– e– FLOW AREA suited for CHP applications. By contrast, PEM and AFC can provide more adaptive power provision, making them suitable for balancing ELECTROLYTE applications. For mobility applications, only ELECTRICITY SOLUTION WATER and HEAT PEM fuel cells have been used commercially, with SOFC considered thus far only as a poten- tial source of auxiliary power for larger mobility Source: ESMAP, adapted from various sources. applications. 28 GREEN HYDROGEN IN DEVELOPING COUNTRIES Four primary fuel sources are used in fuel cells: and then uses an electrolyte and a membrane to hydrogen, ammonia, methanol, and natural gas facilitate the separation of hydrogen molecules (and biogas).18 All fuel cells ultimately consume (generated in the cathode) from oxygen mole- hydrogen, but most applications (except for PEM) cules (generated in the anode). A typical electro- extract their hydrogen from another feedstock lyzer consists of 100 plate cells that are grouped first. This is important because the extraction together to form a stack, which also includes process often reduces the overall system effi- the anode and cathode. These stacks are added ciency below the fuel cell system’s quoted elec- together to reach the required nameplate capac- trical efficiency, leading to a trade-off between ity for the unit and are then added to a system efficiency and convenience in the fuel source that adjusts the heat, moisture, and pressure of chosen. Today almost all SOFC, MCFC, and PAFC the hydrogen to suit the specific application. units run on natural gas, with some also consum- Because the stacks can be mounted in parallel ing biogas. using the same balance of plant infrastructure, costs decline quickly with scale, thus making PEM fuel cells can only run on hydrogen, but electrolyzers highly modular systems (IEA 2015, many systems have been adapted to use other 29) (figure 3.2). hydrogen-derived fuels, such as methanol and ammonia. This allows the operator to store and Other mechanisms to produce hydrogen—nota- transport the fuel (methanol or ammonia) easily bly through steam methane reforming (SMR) or and at lower cost than hydrogen. These solutions, coal gasification—are not covered in this report. however, appear to have shorter lifetimes and This is primarily because those technologies higher upfront capital expenditures (capex) than create what is called gray hydrogen, which has other PEM solutions that directly use hydrogen or significant carbon emissions associated with it. alternative fuel cell technologies. Although a third type of hydrogen called blue hydrogen exists, it is essentially the same pro- duction process as gray hydrogen, but it relies on 3.1.2. Green hydrogen generation— carbon capture and use (CCU) or carbon capture electrolyzers and storage (CCS) so the production process The electrolysis process uses water and elec- could be considered carbon neutral. The poten- tricity to produce hydrogen and oxygen. It does tial applications for blue hydrogen in developing so by using a device called an electrolyzer, in countries are not covered in this report but re- which a molecule of water is split into oxygen main a significant area of interest for developed and hydrogen using an electric current. This pro- and some developing countries, particularly cess is the only commercially proven technology those with access to natural gas resources. that has been deployed widely and that can The most established electrolyzer technology produce green hydrogen—hydrogen produced is the alkaline electrolyzer, which has existed entirely from renewable energy sources.19 commercially since the 1940s. Despite its long Electrolyzers perform essentially the opposite existence, the technology has experienced a chemical reaction of that of a fuel cell. An sharp cost decline curve in recent times as sys- electrolyzer takes electrical power and water tem efficiencies have improved and interest in 18 Some fuel cells can also run on other hydrocarbons; however, because these are not created as derivatives from the SMR hydrogen produc- tion process, they are outside the scope for this report. 19 There are preliminary pilot projects under way that seek to create hydrogen from waste and that could theoretically be considered as green hydrogen generation sources. However, they are not considered significant in the broader literature on the sector at this time. 3: state of the Market 29 FIGURE 3.2 Simplified diagrams of a PEM and alkaline electrolyzer POWER SUPPLY POWER SUPPLY CATHODE ANODE CATHODE ANODE – + – + HYDROGEN – + OXYGEN HYDROGEN – + OXYGEN OH CATHODE REACTION ANODE REACTION CATHODE REACTION ANODE REACTION MEMBRANE DIAPHRAGM PEM ELECTROLYZER ALKALINE ELECTROLYZER Source: ESMAP, adapted from various sources. Note: OH = hydroxide ions; PEM = proton exchange membrane. hydrogen from electrolysis has grown, increasing (AEM) technology and solid oxide electrolysis orders. Nonetheless, the fastest-growing electro- (SOE). AEM technology is seen as a potential lyzer technology is based on PEM electrolysis, breakthrough, given its ability to achieve alkaline which is considered to be more dynamic and electrolysis–level efficiencies with the flexibility of responsive to changing power input require- PEM and with the use of platinum, a key compo- ments than alkaline units are. While the largest nent in most PEM designs. Yet, few units have been currently deployed PEM unit is a 6 MW unit deployed and today only two companies offer this in Austria, units for 20 MW have already been product. Meanwhile, SOE, a high‑temperature ordered in Germany and Canada, with feasibil- electrolysis technology, has displayed the highest ity studies and concept designs under way to theoretical efficiency across electrolysis technolo- examine the deployment of a 250 MW unit in gies and is being closely studied by large industrial the Netherlands and a project of up to 12 GW consumers. SOE, however, still remains a very-ear- in northern Australia. Typically, PEM units have ly-stage emerging technology, with a total installed been small, and the interest has largely focused capacity below 300 kW globally as of September around their role as either a mechanism to ab- 2019; the bulk of these deployments are at two pi- sorb constrained power in an area with signifi- lot sites operated by Sunfire GmbH with German cant renewable resources or a form of distributed and EU grant funding. generation for hydrogen refueling stations. This Last, several companies have advocated for tech- picture may change in the future if PEM units nologies that reform or extract hydrogen from can reach lower capex costs than alkaline elec- waste. Although such technologies hold out an trolyzers as the market expands. attractive option for municipal authorities seek- Two additional electrolyzer technologies have ing to reduce waste and provide low-cost fuel for become commercially available in the past two public transit, none of these technologies have years—namely, anion exchange membrane been deployed outside of testing environments. 30 GREEN HYDROGEN IN DEVELOPING COUNTRIES FIGURE 3.3 Projections and roadmaps for global hydrogen demand in the energy sector McKins /H dro n Council (2017) Sh ll Sk Sc n rio (2018) Acil All n (2018) 250 million ton s of H₂ p r nnum 200 M rk t si , 150 109.0 100 Tot l h dro n d m nd from industr nd n r (H dro n Council 2017) 34.8 50 20.1 19.6 2.8 8.9 3.0 8.5 1.4 0 2025 2030 2040 3.2. MARKET SIZE 2050. It is worth noting though that other analysts have come up with significantly smaller figures. 3.2.1. Hydrogen and electrolyzers Four of the most often cited growth scenarios The global hydrogen market is valued at over for the hydrogen sector are from the Hydrogen $135.5 billion, with an estimated CAGR of 8 Council (2017), Acil Allen (2018), IRENA (2018), percent until 2023 (Markets and Markets 2018). and Shell’s Sky Scenario (2018). Although the While exact figures for the volume of hydrogen studies do not compare like for like, they do produced vary, the literature suggests 55 million illustrate the scale of hydrogen as a potential fuel tonnes up to 70 million tonnes (IEA 2019b) of source. Given that in their modeling Acil Allen, hydrogen are produced annually.20 As previously IRENA, and Shell do not appear to account for illustrated in figure 1.1, around 96 percent of nonenergy uses of hydrogen (such as ammonia global hydrogen production comes from fossil production and use as a process agent in refining), fuel sources, with 48 percent from natural gas via an assumption for the value of the global hydro- SMR and 48 percent from either coal gasification gen market for chemical and process applications or other chemical processes (such as chlorine must also be made to arrive at a global hydrogen production). Only 4 percent comes from electrol- market demand in 2050. Consumption of hy- ysis.21 Given the wide range of potential applica- drogen for energy and mobility is assumed to be tions, determination of the potential market size below 1 percent of total demand, so about 99 for hydrogen is extremely contentious. Assessing percent of hydrogen demand today is for chemi- this myriad of use cases, McKinsey & Company in cal and industrial process applications. This figure a report for the Hydrogen Council (2018) deter- can then be subtracted from these estimates to mined that the future hydrogen energy market produce an estimate of global hydrogen demand could amount to up to $2.5 trillion a year by for energy applications (see figure 3.3). 20 The IEA (Philibert 2017) quoted 60 million tonnes in 2017. DNV GL’s paper for the Norwegian government (2019) quoted 55 million tonnes, as did Siemens (2019), the Hydrogen Council (2020), and IRENA (2019). In its 2019 report, WEC Netherlands cited 45 million tonnes–50 million tonnes using 2010 data. 21 Hydrogen Council 2020, citing IEA 2017; Ajayi-Oyakhire 2012, citing Ogden 2004; IRENA 2018, 13; Siemens 2019, slide 8; and IEA 2015, 10. 3: state of the Market 31 FIGURE 3.4 Power to gas, wind to hydrogen in Germany © Energiepark Mainz, Siemens. Despite a wide variation in estimated annual hy- clear data on the current size of the market to- drogen demand from the energy sector, it is clear day, which is very challenging. that the demand for hydrogen in industrial appli- For pure electrolysis solutions, current research cations will remain significantly larger than the estimates that global electrolyzer sales in 2017 market for hydrogen in the electric power sector. reached 100 MW for the year (DOE 2018), with This observation not only illustrates how quickly 2018 sales estimated at $286 million for wa- the market could absorb additional hydrogen ter-based electrolyzers and growth forecast at demand, but it also illustrates the potential scale a CAGR of 5.67 percent during 2019–25 (GIl of investment for green hydrogen to decarbonize existing hydrogen demand. (See figure 3.4 for an Research 2019). The most recent publicly available example of a renewable power to gas investment.) estimate for water-based electrolysis deployments globally is from the IEA (2019b), which estimates None of these scenarios provide an explicit split that the global installed-water electrolysis capacity between what would be green hydrogen, gray today is over 100 MW electrical, while current or- hydrogen, and blue hydrogen at each milestone, ders for water electrolysis (alkaline and PEM) will so it is more difficult to provide an indication of see the installed capacity reach 285 MW by the how large the market for green hydrogen could end of 2020. By geography, Asia appears to be the be. However, current estimates suggest that be- world’s largest market for electrolyzers, with China tween 0.7 million tonnes and 2.8 million tonnes assumed to have a market share of about 47 per- of hydrogen come from electrolysis today. cent (Market Watch 2019). It is worth noting that The obvious questions raised by the growing China’s annual electrolyzer demand has grown interest in the potential use of hydrogen are from roughly 160 units in 2013 to 2,014 units by where the hydrogen will come from and whether 2017, although no information is available on electrolysis companies will be able to meet the whether the average size of units has changed scale of demand at a cost-competitive level. (GII 2018). If chlor-alkali electrolysis plants are Answering these questions requires obtaining included, then certain sources indicate global 32 GREEN HYDROGEN IN DEVELOPING COUNTRIES TABLE 3.1 Estimated global manufacturing capacity for electrolyzers (PEM and alkaline), 2019 FUTURE COMMITTED MANUFACTURING CAPACITY, CURRENT MANUFACTURING ESTIMATED DELIVERY 2025 AND TECHNOLOGY CAPACITY (MW PER ANNUM) AFTER (MW PER ANNUM) PEM electrolysis > 300 MW > 1,500 MW Alkaline electrolysis > 1,800 MW > 3,000 MW Source: ESMAP research and correspondence with suppliers. Note: MW = megawatt; PEM = proton exchange membrane. installed electrolysis capacity could be between decarbonize the existing hydrogen market in the 1.5 and 3.0 GW.22 Other higher-end estimates by industrial sector (IEA 2019a). BNEF have suggested that global installed capacity Today, exact global electrolyzer manufacturing could be as high as 20 GW of electrolysis, but capacity figures are challenging to obtain. In with only 2 GW installed since 2000 (BNEF 2019). early 2019 Nel, a market leader in the elec- Public sources estimate that 4 percent of global trolysis market, claimed that the global market hydrogen production comes from electrolysis, so manufacturing capacity was around 90 MW green hydrogen will have to scale up significantly per annum (Nel 2018b). Yet, this figure did not or CCU technology will have to grow rapidly, appear to reflect the considerable manufacturing or both, to ensure that emissions from hydrogen capacity of electrolyzer companies in China and production are reduced. To put this challenge in the existing capacity in Europe. Accordingly, context, if the market demand for hydrogen in ESMAP analysis suggests that current market ca- 2018 stood at 55 million tonnes until 2050 and pacity across alkaline and PEM is above 2.1 GW current production from electrolysis was 2.2 mil- per annum and is scaling fast (table 3.1). lion tonnes in 2018, then the electrolysis market would have to grow by 11 percent annually to These figures are subject to a number of assump- achieve 100 percent hydrogen generation from tions, but what is clear is that the global market electrolysis by 2050. Thus, given the significant is scaling rapidly. Two examples of electrolyzer scale-up of green hydrogen required to decar- manufacturing are Nel, which has committed bonize existing hydrogen demand, a number of to increasing its current manufacturing capacity analysts have become concerned that the devel- 10-fold to 360 MW (with a 1 GW site identified opment of a hydrogen market may perpetuate the in August 2019), and ITM Power, which also use of natural gas reforming or coal gasification, has publicly committed to a 10-fold increase in albeit combined with CCU. The IEA, for exam- its manufacturing warehouse space (figure 3.5). ple, notes that less than 0.4 million tonnes of Thyssenkrupp also has publicly acknowledged it hydrogen is produced with CCU and less than has 1 GW of alkaline electrolysis capacity, while 0.1 million tonnes from renewables, amounts John Cockerill also has confirmed its capacity that illustrate the scale of the challenge to simply increased to 350 MW as of Q4 2019. 22 This estimate is informed by data from an H21 (2018) study, which claims that about 5.5–7.0 GW of hydrogen production capacity is installed per year over the last 40–50 years. This amount would average to 137 MW per annum of hydrogen electrolyzers. If the maximum electrolyzer lifetime is assumed to be 20 years, the theoretical ceiling of global installed capacity is thus implied to be a spread of between 1.5 GW and 3.0 GW (H21 2018). However, the H21 study also includes chlor-alkali and sodium/chlorate units, which have longer life- times. Nouryon, for example, already has a 1 GW electrolysis portfolio. 3: state of the Market 33 FIGURE 3.5 Electrolyzer gigafactory under construction in Sheffield, United Kingdom © ITM Power Ltd. Despite this growth, research conducted for this 3.2.2. Fuel cells report indicates that under current practice a Sources complied by ESMAP suggest that the significant scale-up of hydrogen demand glob- global fuel cell market exceeds $2 billion per ally is still likely to increase short-term demand annum and that more than 2 GW of fuel cell for fossil fuel–based hydrogen production, systems have been shipped since 2000. To place though the medium- to long-term outlook will be this pace of deployment in context, note that determined by the pace of growth, green hy- the growth rate of various technologies in the drogen scale-up and the dynamics of hydrogen five years after they reached 100 MW installed production pricing across the available technol- or shipped per annum indicates that fuel cells ogies. Even taking a longer time horizon, current (portable, stationary, and mobility applications) evidence suggests that to achieve the Hydrogen have scaled faster than solar PV and onshore Council’s vision of hydrogen demand reaching wind (figure 3.6). 18 percent of final energy demand by 2050 while minimizing the carbon footprint of hydro- The big drivers of this change have been the gen production, significant scale-up of green rapid improvements in the cost of fuel cell units, hydrogen will need to occur.23 The implication combined with improvements in efficiencies and to policy makers considering hydrogen applica- in the operational lifetimes of fuel cell stacks tions, especially in developing countries, is that (figure 3.7). For example, the previous SOFC it is essential to develop a clear roadmap for how lifetime record was under 20,000 hours in 2005. the hydrogen can be sourced in a climate-sus- Today, Bloom Energy, which produces SOFC tainable manner to ensure that zero-emission technology, estimates that its systems can operate sources of hydrogen production are scaled up. for 40,000 hours before the stacks may need 23 This figure assumes that by 2050 hydrogen will provide 550 terawatt-hours of seasonal power storage, fueling 400 million light-duty vehi- cles, 15 million to 20 million trucks, and 5 million buses (Hydrogen Council 2017). 34 GREEN HYDROGEN IN DEVELOPING COUNTRIES FIGURE 3.6 Technology deployment curves for fuel cells versus wind, and solar photovoltaic Wind Sol r PV Fu l c lls ( ll) 2,500 2,228 2,000 1,930 1,746 Inst ll d c p cit MW 1,500 1,000 500 210 173 165 0 Y r1 Y r2 Y r3 Y r4 Y r5 Y r6 Y r7 Y r8 Sources: U.S. Department of Energy market analysis reports, https://www.energy.gov/eere/fuelcells/market-analysis- reports; E4tech, “Fuel Cell Industry Review,” various years; and Klippenstein 2017, compiled by ESMAP. Note: MW = megawatt; PV = photovoltaic. replacement. Meanwhile, Ballard, which special- publicly available sources for global fuel cell izes in PEM fuel cells, has provided a warranty manufacturing capacity is extremely challeng- that its latest stationary fuel cell systems will ing, especially because many companies are perform for over 34,000 hours, while Doosan privately held and few public market reports pro- fuel cells have reported over 70,000 hours of vide granular information. Notwithstanding these operational lifetime for their PAFC units. challenges, by using publicly available sources Increasing system efficiencies also has played an and making reasonable assumptions, one can important role in improving the economics of establish a “baseline” production capacity. fuel cell applications. These efficiencies include Analysis conducted for this report suggests that not only general improvements to the chemistry significant capacity for PEM fuel cell manufactur- but also commercial innovations such as adapt- ing already exists and that plans are in place for ing units to provide CHP solutions in station- a significant expansion. Other fuel cell technol- ary contexts and recycling heat in vehicles to ogies seem to be considerably more constrained improve efficiency. (table 3.2), and that situation may lead to supply issues if these technologies experience a short- These incremental gains in efficiency and rapidly term surge in demand. declining costs (figures 3.7 and 3.11) have there- fore led some industry analysts to ask whether The ability to provide PEM fuel cell solutions the market has sufficient manufacturing capacity to the mobility sector is a key driver of scaling to meet the rapid increases in demand. This is capabilities and, in turn, will likely drive costs an important but complex question. Finding down and increase uptake, despite the potential 3: state of the Market 35 FIGURE 3.7 Average fuel cell electrical efficiencies between 2005 and 2019 2005 2019 70% 60% 50% 40% 30% 20% 10% 0% DMFC MCFC PEMFC SOFC AFC Sources: IEA, OECD 2005 and data from multiple sources compiled by ESMAP. for other fuel cell technologies to provide solu- hydrogen from electrolysis is more expensive tions with higher efficiencies and longer stack than from steam methane reformation and from lifetimes. Further, because the MCFC, SOFC, coal gasification. Yet that observation is far too and PAFC markets are dominated by one or two simplistic. As noted by the EU’s Fuel Cells and companies, the success of these applications will Hydrogen Joint Undertaking (FCH JU in Fraile likely be far more closely tied to the companies’ and others 2015), hydrogen prices can vary from own decisions than to the fate of the broader fuel EUR 1.5 per kg to EUR 60 per kg in the EU mar- cell industry. This may create another driver for ket, a range that remains true today, according to consumers to focus on PEM technology, where ESMAP’s discussions with current market par- they are more likely to be able to find alternative ticipants. This range is also noted in other large suppliers. hydrogen markets outside the EU. The most commonly quoted figure for hydrogen pricing is derived from steam methane reform- 3.3. COSTS ing technologies, which can produce hydrogen from natural gas at around $1.00–$1.50 per kg. 3.1.1. Hydrogen and electrolyzers But this price is typically linked to large-scale The actual cost of hydrogen production and the SMR units, with access to low-cost natural gas price paid by most end consumers are difficult such as those in the United States and Northern to determine because of the lack of publicly Europe. Further, these costs often refer to available data. Reports frequently state that already existing assets and do not reflect the 36 GREEN HYDROGEN IN DEVELOPING COUNTRIES TABLE 3.2 Estimated global manufacturing capacity for fuel cells across all technologies, 2019 FUTURE COMMITTED FUEL CELL CURRENT MANUFACTURING MANUFACTURING CAPACITY (MW TECHNOLOGY CAPACITY (MW PER ANNUM) PER ANNUM) PAFC 126a > 126 MCFC 100b > 200 SOFC > 120 c > 120 PEM > 1,100 d > 12,000 Note: MCFC = molten carbonate fuel cell; PAFC = phosphoric acid fuel cell; PEM = proton exchange membrane; SOFC = solid oxide fuel cell. a. Moon 2017; Doosan Fuel cell website, http://doosanfuelcell.com.en/intro/manufacturing. b. FuelCell Energy 2018. c. Public filings show that Bloom Energy has deployed over 300 MW since 2011, which on a linear scaling would equate to at least 30 MW a year. It is also known that Bloom’s manufacturing site is over 210,000 square feet and, given the capacity of competitor FuelCell Energy—which reports a 64 MW capacity from a 60,000 square foot site—and Ballard Power Systems (Ballard 2017)—which reported that its Synergy Ballard JVCo could achieve an annualized production capacity of approxi- mately 20,000 fuel cell stacks (80 MW) from 50,0000 square foot—it could be estimated that Bloom Energy can produce at least 120 MW per annum. Bloom data, Bloom Energy 2011; FuelCell Energy 2018. d. Hyundai currently can produce 3,000 fuel cell stacks per year. It could scale to 40,000 annually by 2022 and aim for 700,000 per annum by 2030. Each Toyota Mirai is 114,000 kW; therefore, there is 342 MW current capacity, due to reach 4,560 MW by 2022. Toyota currently can produce 3,000 fuel stacks per year, with plans to reach 30,000 by 2020 (Toyota 2018). Given that Toyota’s fuel cell stack is around 100 kW, scaling is from 300 MW to around 3 GW. Plug Power is quoted as having capacity in 2019 to produce 20,000 fuel cell units per annum. In 12 months, from September 2017 to Septempber 2018, it produced more than 5,000 stacks. The average unit is 2 kW to 4 kW. It could be estimated that the company produces around 40 MW to 80 MW per annum, averaged to 60 MW. These numbers are comparable with those given in correspondence with the company. Longer term, Zhongshan Broad-Ocean Motor Co., al- ready Ballard’s largest shareholder, is building three manufacturing facilities using Ballard technology. Thus three assembly lines will make 10,000 units of 35 kW to 85 kW (or 3.5 GW–8.5 GW) (Broad-Ocean Motor Group 2017, slide 13). So 5 GW additional capacity is assumed. In addition to these sources, market intelligence from various suppliers has helped inform the baseline. costs of capital expenditure in their pricing. As smaller-scale consumers is that hydrogen costs shown in table 3.3, sources suggest that hy- vary considerably, and calculating what the drogen production costs from SMR are closely pricing should be of hydrogen delivered to cus- correlated to moves in natural gas prices, with tomers is challenging. The simple reason is that a recent study by WEC Netherlands observing transportation and storage of hydrogen remain that natural gas costs correspond to 70–80 expensive and cost varies depending on the vol- percent of the total hydrogen production cost. ume of hydrogen demanded by customers and According to this source, a EUR 6 per gigajoule their distance from the hydrogen production price increase in natural gas corresponds to a site. How broad the spread can be is illustrated hydrogen production cost increase of EUR 1 per by the publicly available Hydrogen Demand kilogram (WEC Netherlands 2019). and Resource Analysis tool (HyDRA) from the National Renewable Energy Laboratory (NREL) Nevertheless, these figures are in many senses (figure 3.8). limiting because they almost exclusively provide the cost only for consumers who are As can be seen from figure 3.8, the cost of colocated and who represent the primary delivering hydrogen to customers is consider- off-taker for the SMR operator. The reality for ably more than the production cost; thus there 3: state of the Market 37 Production cost estimates of hydrogen from steam methane reforming and coal TABLE 3.3 gasification (excluding transport and storage costs) ORGANIZATION/LOCATION PRODUCTION METHOD COST (US$/KG) IGEM 2012, United Kingdom SMR 3.00a IGEM 2012, World SMR 0.80–6.00b IEA 2015, United States SMR 0.90 IEA 2015, Europe SMR 2.20 IEA 2015, Japan SMR 3.20 IEA 2017, World SMR 1.00–3.00c WEC 2018, Netherlands SMR (Large scale) 1.10–1.70d WEC 2018, Netherlands SMR (Small scale)e 4.60–-5.75f CSIRO 2018, Australia SMR + CCS 2.27–2.77g CSIRO 2018, Australia Brown coal gasification +CCS 2.57–3.14g Note: CCS = carbon capture and storage; SMR = steam methane reforming; IGEM = Institution of Gas Engineers and Managers; IEA = International Energy Agency; WEC = World Energy Council; CSIRO = Commonwealth Scientific and Industrial Research Organisation. a.Ajayi-Oyakhire 2012. b. Ajayi-Oyakhire 2012. c. Philibert 2017. d. WEC 2019. e. Producing 200 kg–600 kg per day. f. WEC Netherlands 2019. g. Bruce and others 2018. FIGURE 3.8 Spread in United States hydrogen prices from HyDRA, April 2019 Industri l for court SMR Comm rci l for court SMR 10 8 n $ cost p r k h dro 6 4 2 V ld -Cordov , P rkins, G lv ston, N wport N ws, Atl ntic Count , Al sk South D kot Tx s Vir ini N w J rs Source: NREL 2019. Note: HyDRA = Hydrogen Demand and Resource Analysis (tool); NREL = National Renewable Energy Laboratory; SMR = steam methane reforming. 38 GREEN HYDROGEN IN DEVELOPING COUNTRIES remains a significant cost advantage to being efficiency values and (b) considerations around able to produce hydrogen on-site. This dynamic the LCOE of electricity used and load profile/ has underpinned much of the growing inter- capacity factor of the electrolyzer, reflecting est in electrolyzers, and it is worth noting that the use of the asset. One source of discrepancy as early as 2015 the IEA, citing the US DOE, on cost assumptions is whether the capex fig- argued that the cost of distributed hydrogen ure given includes only the electrolyzer, or the production via electrolysis using off-peak elec- balance of plant, installation, or both. Yet, even tricity could be $3.90 per kg (IEA 2017). On with these considerations, the pricing range this basis, hydrogen created from an electro- remains large. lyzer on-site could be cheaper than the price Evidence from projects that are publicly avail- of commercial forecourt hydrogen from SMR in able appears to corroborate feedback from all the locations shown in figure 3.8 except in suppliers, suggesting that alkaline units above Alaska. 20 MW can be expected to cost below $700 The question then is what drives the cost of hy- per kW on an equipment-only basis. For PEM drogen from electrolysis, and can these solutions electrolyzers the deployment amounts have been consistently deliver green hydrogen at prices much smaller and therefore pricing remains that are below those prices currently accessible extremely varied (table 3.5). However, equip- to existing hydrogen consumers, excluding the ment costs below $1,200 per kW appears to largest captive producers (for whom there is no be an accepted benchmark for these solutions. need to transport hydrogen because it is pro- The other aspect to note is that literature sources duced and consumed on-site). Historical analy- and suppliers commonly assume electrolyzer sis of the cost of hydrogen from electrolyzers has efficiencies to be at least 65 percent today, with typically considered capex and electricity costs many using 70 percent as the base case. See to be around 50:50 with regard to their impact figure 3.9 for examples of PEM electrolyzer units on the cost of hydrogen. That is especially true for mobility applications. for units below 1 MW. Yet, as the market has From the evidence available it is reasonable expanded and electrolyzer costs have fallen, to conclude that hydrogen from electrolysis companies have begun to argue that electricity cannot be currently produced more cheaply costs now account for around 75 percent of than from large existing-scale SMR in areas hydrogen’s cost (Nel Asa 2017). Nevertheless, with access to low-cost natural gas. Yet, cost capex clearly is still an important consideration, estimates shown in table 3.4 suggest that, for especially at the smaller, decentralized scale. customers with access to the grid and falling Thus, achieving load factors above 3,500 hours wholesale power prices, hydrogen from on-site per annum is essential to securing low hydrogen electrolysis can be cheaper than the cost from prices, even when the cost of power might be large-scale SMR facilities plus transport costs. low (or free when curtailed). It also appears to be the case that even where To illustrate some of the current green hy- off-takers have access to natural gas at low drogen cost estimates, table 3.4 consolidates prices, smaller SMR units (those producing assessments from a wide array of sources, less than 4.5 kg of hydrogen per hour) would under differing sets of assumptions. As the only be able produce hydrogen at a cost that table shows, there is considerable variation in would be comparable to that produced via hydrogen pricing points. That variation reflects electrolysis (IEA 2015; WEC Netherlands two sources of uncertainty: (a) considerable 2019). Looking forward, if wholesale power variation in electrolyzer cost assumptions and prices, renewable costs, and electrolyzer costs 3: state of the Market 39 TABLE 3.4 Cost estimates of hydrogen generated via water electrolysis ELECTROLYSIS COST ORGANIZATION RANGE ($/KG) ASSUMPTIONS Based on data analysis from the Siemens 2016 4.40–7.70a Energiepark Mainz project. Alkaline electrolyzer, $850/kW capex, WACC 7%, IEA 2017 2.00 lifetime 30 years, efficiency 74%, 4,500 full load hours Alkaline electrolyzer, capex below $700/kW, Nel ASA 2017 2.70–4.00b and a solar PPA $40–$60/MWh Alkaline electrolyzer, capex below $500/kW Nel ASA 2017 1.30–2.70b and solar PPA is $20/MWh–$40/MWh Alkaline electrolyzer; 2017 Danish electricity prices that IRENA 2018 5.00–6.00c include all grid fees, levies, and taxes; load factor above 40% PEM electrolyzer, Chile; wind + solar, with an LCOE $20/ IRENA 2018 4.20–5.80 MWh–$50/MWh and 6,840 full load hours Tractebel Engie and CORFO Northern Chile, 2023; 1.80–3.00 2018d electricity cost $28.40–$56.20/MWh Alkaline electrolyzer, 44 MW, 85% capacity factor, CSIRO 2018 (base case)e 4.80–5.80 57% efficiency, $60/MWh, capex $1,347/kW PEM electrolyzer, 1MW, 85% capacity factor, CSIRO 2018 (base case)e 6.10–7.40 62% efficiency, $60/MWh, capex $3,496/kW Alkaline electrolyzer, 1 MW, 75% capacity factor, ESMAP 2020 (base case) 4.5–4.8 80% efficiency, $30/MWh, capex at $800/kW PEM electrolyzer, 1 MW, 95% capacity factor, ESMAP 2020 (base case) 5.00 – 5.80 72% efficiency, $30/MWh, capex at $1,100/kW Alkaline electrolyzer, 1MW, 95% capacity factor, ESMAP 2020 (lowest price) 3.70 – 4.00 80% efficiency, $30/MWh, capex at $800/kW Source: As shown, and ESMAP. Note: All sums have been converted to U.S. dollars at prevailing exchange rates. capex = capital expenditure; CSIRO = Commonwealth Scientific and Industrial Research Organisation; CORFO = Chilean Economic Development Agency; ESMAP = Energy Sector Management Assistance Program; IEA = International Energy Agency; IRENA = International Re- newable Energy Agency; LCOE = levelized cost of energy; PEM = proton exchange membrane; PPA = power purchasing agreement; WACC = weighted average cost of capital. a. Siemens 2016—converted from EUR to US$. b. Nel Asa 2017. c. IRENA 2018. d. Tractebel and Chilean Solar Com- mittee 2018. e. Bruce and others 2018. continue to decline, it appears conceivable 3.1.2. Fuel cells that electrolysis could become a commercial One of the best illustrations of the historic de- alternative to SMR or coal gasification for cline in the cost of fuel cell technologies comes large-scale centralized production. from observing the cost declines for PEM fuel These findings suggest avoiding the assumption cell systems (figure 3.10). That is because PEM that most of the growth in global hydrogen systems have been developed since the 1950s demand will be met by SMR deployments, and remain the most commonly procured fuel because green hydrogen prices may well reach cell technology in aggregate across sectors (largely driven by mobility applications). parity with fossil-derived hydrogen sooner than anticipated in locations with exceptionally It is important to note that costs for PEM fuel good renewable resource. cells in mobility have always been lower than 40 GREEN HYDROGEN IN DEVELOPING COUNTRIES TABLE 3.5 Sample of electrolyzer capital expenditure estimates ORGANIZATION TECHNOLOGY CAPEX (US$/KW) IEA (2015) PEM 2,650a CSIRO (2018) PEM 3,496b H2I (2018) PEM 2,800 –3,400c IRENA (2018) PEM 1,380d ESMAP (2020) PEM 1,100 IEA (2015) Alkaline 1,150e IEA (2017) Alkaline 850f CSIRO (2018) Alkaline 1,347g H2I (2018) Alkaline 1,300–1,700h IRENA (2018) Alkaline 860i ESMAP (2020) Alkaline 800 Source: As shown, and ESMAP. Note: PEM = proton exchange membrane. a. IEA 2015. b. Bruce and others 2018. c. H2I 2018. d. IRENA 2018. e. IEA 2015. f. Philibert 2017. g. Bruce and others 2018. h. H2I 2018. i. IRENA 2018. ITM PEM electrolyzer National Physics Lab,United Kingdom, 2019 (left) FIGURE 3.9 and Siemens Silyzer 3000, Mainz Park, Germany, 2019 (right) © ITM Power Ltd (left). © Siemens (right). 3: state of the Market 41 FIGURE 3.10 Stationary PEM fuel cell cost per kW $600,000 $10,000 $8,000 $500,000 $6,000 $4,000 $400,000 $2,000 $0 2005 2007 2009 2011 2013 2015 2017 2019 $300,000 $200,000 $100,000 $0 1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 Source: ESMAP. Note: PEM = proton exchange membrane. for stationary applications, owing to different But not all fuel cell system costs are starting from stack lifetime requirements. Therefore, there are the same position. Fuel cell technologies have PEM fuel cells available today that suppliers different applications, stack lifetimes, electrical will quote for below $2,000 per kW. Typically, efficiencies, and fuel sources that drive their the higher stack lifetime requirements for all overall cost structures (tables 3.6 and 3.7). stationary fuel cells lead to higher costs, part of Assessing fuel cell costs, therefore, requires more the reason that stationary systems have a higher than a simple analysis of capital expenditures. capex than mobility solutions. For example, PEM fuel cells rely on high-purity PEM fuel cell suppliers are not the only ones hydrogen, which is more expensive and more seeing significant cost declines. Publicly available complicated to transport and store than other data also show that manufacturers across other fuel alternatives such as ammonia, methanol, or fuel cell technologies are reporting significant cost natural gas. Further, it is important to consider declines as orders scale up (figure 3.11).24 These the application. Where fuel costs are cheap companies are often well-established businesses, or maintenance is a concern, there may be an a fact that indicates not only the time it has taken incentive to switch toward longer-duration and to develop products that are commercially avail- lower-cost systems, such as PAFC or MCFC units able to go to market, but also the importance of instead of SOFCs. For customers who may value achieving scale to drive down costs and improve a CHP application, high-temperature fuel cells the economics of fuel cell projects. can provide a more compelling solution and a 24 The figures are derived from annual reports that indicate declines in price over a fixed period but do not provide exact prices for each year. Accordingly, the “midyear” data has been extrapolated between the start year and 2017 figures. 42 GREEN HYDROGEN IN DEVELOPING COUNTRIES FIGURE 3.11 Reported equipment cost decline curves from leading fuel cell suppliers Bloom En r Fu l C ll En r Plu Pow r B ll rd 100 R l tiv cost d clin s (% f ll ov r p riod) 90 80 70 60 50 40 30 20 10 0 2009 2010 2011 2012 2013 2014 2015 2016 2017 Source: Extrapolated from company-reported declines 2018/19. much higher system efficiency than lower-tem- of assessments and judgments when scoping the perature fuel cells. For example, Transport technology solution and the application for the for London installed a CHP (PAFC) unit in its end customer. Capex alone is not always the key Palestra building to help provide power as well driver of technology choice. as heating and cooling. In short, choosing the most appropriate fuel cell solution requires companies to make a variety 3: state of the Market 43 TABLE 3.6 Overview of primary fuel cell technologies SYSTEM TECHNOLOGY SYSTEM STACK LIFETIME LIFETIME PRIMARY TYPE $/kW EFFICIENCY (%) (HOURS) (YEARS) APPLICATIONS Proton exchange Stationary: Stationary: 45–58 Stationary: 20 All mobility, UPS, residential membrane fuel cell 1,400–4,000 20,000–40,000 power, peaking power (PEM) provision. Mobility: Mobility: 45–60 Mobility: 1,000–3,000 6,000–20,000 Molten carbonate Stationary: Electric only: 45–55 Stationary: 20 Baseload power genera- fuel cell (MCFC) 3,000–4,000 60,000–80,000 tion, UPS, CHP uses. CHP: 70–85 Alkaline fuel cell Stationary: Electric only: 55–65 Stationary: 20 Baseload power generation (AFC)a 700 5,000–6,000 and UPS. CHP: 80–90 Solid oxide fuel cell Stationary: Electric only: 45–65 Stationary: 20 Baseload power generation, (SOFC) 3,000–6,500 25,000–40,000 UPS, range extender for CHP: 80–90 larger mobility applications, CHP uses. Phosphoric acid Stationary: Electric only: 45–55 70,000–80,000 20 Baseload power genera- fuel cells (PAFC)a 4,000–5,000 tion, UPS, CHP uses. CHP: 85 Source: IEA, ESMAP, various suppliers. Note: CHP = combined heat and power; kW = kilowatt; UPS = uninterruptible power supply. a. IEA 2015. TABLE 3.7 Methanol and ammonia fuel cells SYSTEM COST PER SYSTEM STACK LIFETIME LIFETIME FUEL SOURCE KW ($) EFFICIENCY (%) (HOURS) (YEARS) WHERE USED? Methanol fuel cell 4,000–10,000 Electric only: 50, Stationary: 20 Uninterruptible Whole system 35–40 5,000–10,000 power supply Ammonia fuel cell 10,000 Electric only: ~50 Stationary: 20 Uninterruptible Whole system: 35-40 5,000–8,000 power supply Source: ESMAP. Note: kW = kilowatt. 44 GREEN HYDROGEN IN DEVELOPING COUNTRIES 4: ENERGY APPLICATIONS AND COMMERCIAL SOLUTIONS KEY TAKEAWAYS nn Variable renewable energy deployments, balanced by electrolyzers, hydrogen storage, and fuel cells, can achieve a levelized cost of energy for the provision of power that could be below the cost of diesel alterna- tives in some developing countries and remote areas. nn There is an abundance of applications for which green hydrogen could provide solutions for industries, com- merce, utilities and policy makers to help decarbonize existing fossil-based energy systems. nn Not every application for green hydrogen will be appropriate in every country context, and careful analysis will be needed to ensure the solutions are suitable. nn Developing countries are already ahead of developed countries in the use of certain hydrogen and fuel cell applications today because they make commercial sense in their contexts. nn Green hydrogen and fuel cells could become a building block of fully decarbonized grids, complementing existing renewable energy technologies and facilitating their further deployment by addressing constraints such as long-duration storage and transportation. nn Green hydrogen storage, electrochemical batteries, and other forms of energy storage offer different value propositions and in most cases can be regarded as complementary. 4: Energy Applications and Commercial Solutions 45 Hydrogen and fuel cell technologies are aleady industrial customers, with the overwhelming being used in a wide array of stationary power majority of these units using natural gas as their applications at the utility, industrial, com- primary fuel. While fuel cells remain the pri- mercial, and residential level (table 4.1). On mary consumer of hydrogen for energy, there is the fuel cell side, the applications range from also growing interest in retrofitting or designing sub-1 kW units to systems over 50 MW, and by combustion turbines and reciprocating engines late 2019 there were estimated to be 363,000 to also run on hydrogen. stationary fuel cells in operation globally (IEA 2019b). A significant proportion of stationary power applications below 3 kW are located in 4.1. RESIDENTIAL APPLICATIONS developing countries—notably in Asia, where One of the areas of focus for hydrogen tech- they play an increasingly important role in nologies in the residential sector is the installa- power provision for off-grid sites that require tion of residential fuel cell combined heat and high availability and are at risk from diesel power units, which have transitioned in recent thefts. These applications typically include years from PEM to SOFC because of the higher telecommunications towers, but in Japan efficiency and operating temperature of SOFC. customers also include residential CHP units. The largest of these rollouts is the Japanese The majority of units of 100 kW or larger are Ene-Farm project, which in over a decade has located in Korea and the United States, largely seen more than 300,000 units deployed domes- for commercial consumers and a few large tically, making it the largest market by far. Other TABLE 4.1 Overview of stationary fuel cell applications COMPLIMENTARY APPLICATION TECHNOLOGY UNIT SIZE (kW) TECHNOLOGIES EXAMPLES Residential com- PEM and SOFC <5 Solar PV, batteries Ene-Farm, Ene-Field bined heat and power Back-up power PEM, methanol and < 100 Solar PV, batteries, Adrian Kenya, PT ammonia micro-wind Telekom, U.S. state of Maryland, Bahamas, Danish emergency broadcast system Off-grid power PEM fuel cells, mostly. <1 Solar PV, wind, batteries, Tiger Power, Cerro provision geothermal Pabellón geothermal plant, Raglan Mine, BIG HIT Commercial office Mostly SOFC and <5 Solar PV, batteries, Apple HQ, Morgan power PAFC micro-wind Stanley Manhattan, PG&E campus, South African Ministry of Mines Baseload power SOFC, PAFC, MCFC, > 400 Power grid Daesan Green Energy generation retrofit gas turbine JV, CEOG, North Chungcheong Province (Korea Western power) Note: MCFC = molten carbonate fuel cell; PAFC = phosphoric acid fuel cell; PEM = proton exchange membrane; PV = photovoltaic; SOFC = solid oxide fuel cell. 46 GREEN HYDROGEN IN DEVELOPING COUNTRIES Sunfire GmbH 2019 Residential SOFC (left) and Ceres Power Ltd 2019 residential FIGURE 4.1 SOFC (right) © Sunfire (left). © Ceres Power Ltd. (right). Note: SOFC = solid oxide fuel cell. suppliers in Europe, notably CERES Power the grid and provides 100 percent renewable and SunFire GmbH, are due to begin rollouts power 24/7, using 86 kW of solar PV and four of their residential SOFC CHP units as part modular electrolysis units, to convert excess so- of a grant from the EU called Ene-field. These lar PV into stored energy for use during the day innovations could be particularly interesting and in the evening.25 for developing countries in Europe and Central Recently a number of schools and office Asia whose existing gas grid could be repur- buildings have also begun to look at green posed accordingly. hydrogen production and fuel cell systems, Fuel cells are being considered primarily as res- alongside on-site (typically rooftop-mounted) idential power sources to help promote distrib- solar PV, to provide 24-hour renewable power. uted generation and enhance system resiliency In Singapore a local company, SP Group, has (figure 4.1). Japanese and EU programs that converted its training center at Woodleigh Park already provide feed-in tariffs to support mi- to a 100 percent renewable, off-grid, hydro- cro-CHP include support for fuel cell units. gen-based system. This pilot is unique not only While some of these systems are focused on nat- for being the first fully zero-emission office in ural gas consumption for the present, in Thailand Southeast Asia, but also because it uses sol- a company called Enapter has already built the id-state hydrogen storage on the premises. This world’s first 100 percent renewable home with system significantly reduces concerns around green hydrogen and fuel cells. The Phi Suea storage and leakage of hydrogen gas (SP Group house in Chiang Mai (figure 4.2) is entirely off 2019). 25 Information provided courtesy of correspondence with the supplier in September 2019. 4: Energy Applications and Commercial Solutions 47 FIGURE 4.2 Phi Suea off-the-grid house, Thailand, hydrogen systems © Enapter. Another area of interest is the distribution of pathway to achieve emission reductions in their green hydrogen through the existing gas grid to residential sectors. be used by existing heating technologies such as boilers, burners, and CHP fuel cells. One method is to simply blend hydrogen with natural 4.2. BACK-UP POWER gas inside the grid, a process that is being piloted APPLICATIONS by Keele University in the United Kingdom The primary market for back-up power has been (HyDeploy n.d.). The other concept is to con- the telecommunications sector, which has long vert gas grids to 100 percent green hydrogen been a popular focus area for fuel cell systems. and convert appliances accordingly. Although The need for continuous operation of telecom- that conversion may seem dramatic, it is worth munication towers, the frequent lack of access noting that from 1967 to 1977, 14 million cus- to power from the grid, and significant security tomers and 40 million appliances in the United issues related to theft of diesel have encouraged Kingdom were converted from town gas (about many developed and developing countries to 50 percent hydrogen and 50 percent methane) to deploy these solutions. While early fuel cell natural gas (Bruce and others 2018). A number of solutions for the telecommunications industry of- hydrogen appliances and hydrogen upgrade kits ten focused on providing PEM units that required are commercially available to enable residential pure hydrogen, initial operating experience has consumers to use grills and ovens, water heat- shown that this combination creates significant ers, cook tops, and gas heaters. As an example, logistical and performance issues for early adopt- hydrogen boilers have already been installed at a ers. Those issues were almost entirely related school on the island of Shapinsey in the United to securing hydrogen of sufficient purity and Kingdom (figure 4.3). These applications could having it delivered consistently to the telecom offer developing countries—particularly those sites when needed, a challenge compounded by with an existing gas infrastructure—an interesting the complexity of storing pure hydrogen in large 48 GREEN HYDROGEN IN DEVELOPING COUNTRIES FIGURE 4.3 Hydrogen boilers deployed at Shapinsey School, Kirkwall, United Kingdom Source: ESMAP. quantities over long periods. Accordingly, most be stored for longer periods of time than hydro- telecom tower systems today use methanol- or gen, and thus they are more appealing for tele- ammonia-based fuel cell solutions, with com- communications companies (box 4.1). By way panies such as GenCell and Cascadiant leading of illustration, the two plastic containers in the the rollout in emerging markets. In Indonesia image of the SFC Energy unit in figure 4.4 (center there are already over 800 fuel cell systems in and right) can provide up to 30 days of power at the telecom space, including more than 40 units continuous operation. This ability has enabled in Papua New Guinea, whereas Adrian Kenya fuel cells to overcome some of the initial fuel recently ordered more than 800 ammonia fuel supply issues that hampered the early adoption cells to replace diesel gensets (GenCell 2018). In of fuel cells for telecom providers in the early Europe companies such as Ballard, SFC Energy, 2000s. and Siqens have deployed various solutions, ranging from airport systems in Norway to the Danish emergency broadcasting frequency 4.3. OFF-GRID POWER systems.26 These projects remain small in ab- APPLICATIONS solute numbers, but the number of projects is Providing power to remote areas through min- increasing. igrids has long meant an increased reliance on The key to expansion is the ability to combine diesel generators. Historically, these generators green hydrogen with direct air capture/carbon have provided the only reliable means of firm capture techniques to produce ammonia. This energy supply, through the use of a multifaceted capability is important because ammonia (and fuel that could be used for both power genera- methanol) can be more easily procured and can tion and transport. But today green hydrogen and 26 In 2007 Ballard was chosen the start providing solutions for the Danish TETRA Network alongside Motorola. Additional details can be found on Ballard’s website, https://blog.ballard.com/motorola-fuel-cell-backup-power. 4: Energy Applications and Commercial Solutions 49 BOX 4.1 DISPLACING DIESEL IN INDONESIA’S TELECOMMUNICATIONS SECTOR Indonesia is one of the world’s fastest-growing telecommunications markets, with the number of mobile phones in the country rising from 124 million in 2014 to an estimated 184 million in 2018. Yet, ensuring that the world’s fourth most populous nation stays online is not easy. A report by PWC in 2016 (PWC 2016) concluded that grid blackouts cost Indonesian businesses $415 million every year, while the country’s electricity consumption per capita stood at 1.02 MWh in 2018, below Vietnam but slightly above the Philippines. Although the national electrifi- cation rate stood at 98.0 percent in 2017, the existence of 18,000 separate islands means that access can vary, from 59.9 percent to 99.9 percent. To ensure that Indonesians can stay connected, the country’s telecom operators have typically resorted to back-up diesel generators to guarantee continuity during grid blackouts and coverage in off-grid areas. These assets are frequently targeted for diesel theft and contribute to local air and noise pollution. However, one company is addressing this problem. Cascadiant develops and operates methanol-based fuel cells for Indonesia’s largest telecom provider, PT Telkom Indonesia (figure B4.1.1). The fuel cells enjoy efficiencies above 40 percent and run continuously in all con- ditions, with a 99.6 percent uptime reported across 815 sites in Indonesia and Timor-Leste since 2010 and extremely limited maintenance required. Cascadiant’s fuel cell units rely on methanol, which is produced from domestic hydrogen and then blended partially with water. The blending has a limited effect on efficiency but makes the methanol undesirable for thieves, in contrast to the challenges faced by diesel operators. Since 2013, the company has deployed 800 fuel cell units across Indonesia and Timor-Leste, with no reported thefts since its first contract in 2013. Cascadiant’s use of methanol instead of diesel also has avoided over 17,000 tonnes of carbon dioxide emissions and prevented the import and use of over 6 million liters of diesel fuel by replacing it with domestically produced hydrogen and methanol fuel stocks. Although Indonesia produces its hydrogen from reforming natural gas, this method could be replaced or comple- mented by the production of green hydrogen from domestic renewable resources. Figure B4.1.1 Methanol fuel cells in Indonesia’s telecommunications sector © Cascadiant. 50 GREEN HYDROGEN IN DEVELOPING COUNTRIES Snapshot of portable fuel cells for telecom applications: GenCell A5 2019 (left), SFC FIGURE 4.4 Energy methanol fuel cell 2019 (center), and SFC Energy methanol fuel cell back-up for lighting system 2019 (right) © GenCell (left). © SFC Energy (center and right). its derived fuels are increasingly seen as poten- Desert, where hydrogen is used as a long-dura- tial alternatives. tion storage solution, and Australia’s Daintree microgrid project. Some projects, such as In Uganda, a Belgian company called Tiger Hychico in Patagonia, have also used green Power has provided off-grid power via a hybrid hydrogen production to blend with an existing solar PV and green hydrogen solution, with natural gas turbine to provide another form the hydrogen produced from excess PV and of renewable energy storage in a remote area stored for use by a fuel cell during the evening. (Hychico n.d.). Within the mining sector, NRCAN worked with GlenCore to develop a hybrid energy By combining the different elements in hybrid storage system at Raglan mine in Canada applications, these projects maximize the use that incorporated hydrogen and fuel cells. of the capex invested and provide enhanced The minigrid forms only part of the mining services (box 4.2). site’s total demand of 20 MW capacity, but it reduced diesel demand by 3.4 million liters and avoided the release of 9,110 tons of GHG 4.4. COMMERCIAL during its first 18 months of operation (NRCAN APPLICATIONS 2019). The full system combines a 3 MW tur- Because most fuel cells in the commercial bine with a 200 kW flywheel, a 200 kW Li-Ion segment run on natural gas, they are considered battery, a 315 kW electrolyzer, and a 198 kW similar to conventional boiler and CCGT tech- fuel cell (NRCAN 2019). Other remote areas nologies and therefore have been established in have included national parks, such as Cerro urban environments for many years (figure 2.7). Pabellón geothermal plant in Chile’s Atacama Noteworthy projects include a 300 kW CHP fuel 4: Energy Applications and Commercial Solutions 51 BOX 4.2 POWERING SCHOOLS IN SOUTH AFRICA South Africa is a major proponent of green hydrogen production and fuel cell technologies through its Hydrogen South Africa (HySA) program. The country is estimated to hold 75 percent of global platinum group metal resources globally, an important component of proton exchange membrane technology. Thus, South Africa sees green hydrogen as a solution to provide clean power solutions domestically while creating a new market for platinum group metals. At Poelano High School in Ventersdorp, HySA has partnered with multiple organizations, includ- ing the Council for Industrial and Scientific Research, North-West University, University of Cape Town, Mintek, and University of the Western Cape, to develop a 2.5 kW hydrogen fuel cell system (figure B4.2.1). The unit derives its power from a rooftop solar photovoltaic array at the school and provides continuous renewable power to the currently off-grid location, allowing the 486 students to have access to reliable communication technologies and lighting. The South African Ministry of Science and Technology launched a ZAR 10 million ($590 thou- sand) renewable energy program in April 2018 to expand energy access to approximately 5,000 schools and clinics that have little to no access to reliable electricity. The program aims to help reduce the costs of providing electricity access to facilities that are often located more than 20 kilometers from the Eskom grid and thus require costly transmission expansions in the absence of a compelling distributed generation alternative. Figure B3.2.1. Pressurized hydrogen storage (left) and Rooftop solar PV system (right) Source: Courtesy of Hydrogen South Africa. 52 GREEN HYDROGEN IN DEVELOPING COUNTRIES cell in London’s 20 Fenchurch Street building, and major suppliers have suggested that it is called the “Walkie Talkie” skyscraper (Logan reasonable to have a ceiling of about 10 percent Energy 2019), and a 750 kW fuel cell on the of deployed stationary commercial fuel cell units roof of Morgan Stanley’s New York office (Bloom using biogas. Energy 2016). As previously discussed, fuel It is important to note that stationary fuel cells cells that run on pure hydrogen require higher can be retrofitted at low cost to run on pure pressures and more exhaustive safety measures hydrogen solutions. That option could enable to store and may require more developed infra- countries to future-proof investments by using structure to deploy than other fuels. fuel cells with natural gas or biogas today, then The majority of fuel cell units in Korea and the transitioning the fuel cells to consume green United States operate under a leasing structure hydrogen in the future. in which the manufacturer has entered into a relationship with an existing equipment finance provider or the manufacturer has raised debt to 4.5. UTILITY-SCALE provide the service to the commercial client. The APPLICATIONS other alternative is one in which manufacturers One of the main appeals of stationary fuel cells offer an equipment-only PPA to commercial is their ability to provide utility-scale firm power customers. These PPAs mirror a lease model to in low-carbon grids to complement renewable an extent, with modifications to terms of use, energy output, including ancillary services, given duration of contract, and other parts of the agree- their fast response. As was shown with commer- ment. In both cases the manufacturer will usually cial applications, power grids with access to also sign a service contract with the commercial natural gas (figure 4.5) could achieve lower elec- off-taker in which the manufacturer agrees to tricity costs with fuel cells running on natural gas operate the fuel cell system. The fuel is typically than with generators running on heavy fuel oil. then provided separately, with most off-takers in Korea and the United States working with their These fuel cells can rapidly adapt their output to existing natural gas provider. At this time some complement renewable variability and contrib- specialized gas companies, such as Air Liquide, ute to meeting instantaneous electricity demand. Air Products, or Linde, can provide hydrogen if Yet, despite having lower carbon emissions than requested, but there has been limited interest in electricity generated by a CCGT, natural gas– this at the commercial level to date. based solutions are not emissions free. Fuel cell suppliers contacted in the preparation Conversely, fuel cells running on green hydrogen of this report corroborate the estimate that fuel could demonstrate the same performance and cell systems using natural gas can deliver power could complement renewable variability to meet at between $103 and $152 per MWh, with instantaneous demand, but without produc- natural gas currently accounting for $25–$28 per ing any carbon emissions (box 4.3). Moreover, MWh of the cost (Lazard 2018). Other interesting green hydrogen could provide power grids with applications include the use of fuel cell units in a long-term energy storage solution, capable of conjunction with waste sites, such as wastewa- mitigating the long-term and seasonal variabil- ter treatment plants. For SOFC and MCFC units, ity of renewable resources, and could become the systems have a higher tolerance for carbon a building block of fully decarbonized power dioxide and therefore can run biogas mixtures of grids, particularly in countries without access to more than 40 percent carbon dioxide. This appli- other firm low-carbon resources such as large cation does reduce the efficiency of the systems, hydro projects or geothermal or thermal plants 4: Energy Applications and Commercial Solutions 53 FIGURE 4.5 Utility-scale fuel cell solutions: Solid oxide fuel cell units in the US © Bloom Energy. with carbon capture and storage. By storing Some PEM electrolyzer units also operate on green hydrogen for long periods of time and excess hydrogen production from industrial subsequently using it for power generation in sites, by consuming the hydrogen for power and a fuel cell (or even in turbines adapted to run feeding it back into the grid. An example is HDF on hydrogen), countries gain opportunities to Energy’s 1MW unit at Sara refinery in Martinique develop firm clean power solutions. (figure 4.6). The hybridization of solar power generation, Ambitious plans have been announced to wind power generation, or both with electro- convert large existing natural gas turbines to lyzers, fuel cells, green hydrogen storage, and run on hydrogen, in an attempt to use existing batteries could provide firm generation solutions hydrogen production from SMR sites in the that rely solely on renewables as the primary short term, before transitioning to green hydro- energy source. One of the largest examples of gen once the market has developed. The best- such hybrid configuration is the CEOG project known example of this use case is the 400 MW in French Guiana, which will combine a 55 Magnum CCGT site operated by Equinor in the MW solar PV generator with a 20 MW battery, Netherlands, which is due to be 100 percent 20 MW electrolyzer, and 3MW fuel cell (HDF hydrogen by 2023. Energy n.d.), with the goal to provide a dispatch- able green power source for the utility. Another example is Electricity Generating Authority of 4.6. LEVELIZED COST OF ENERGY Thailand’s (EGAT) wind-hydrogen system, which ILLUSTRATIVE MODELING: GREEN consists of a 1 MW electrolyzer linked to a 24 HYDROGEN PRODUCTION AND MW onshore wind site, with a 300 kW fuel cell to help balance the variable power output from FUEL CELL SYSTEM the wind farm and to help EGAT manage the To illustrate the current economics of fuel cell impact of variable output on the grid. and green hydrogen hybrid power systems, 54 GREEN HYDROGEN IN DEVELOPING COUNTRIES BOX 4.3 GREEN HYDROGEN STORAGE AND BATTERIES Energy storage is a fundamental component of fully decarbonized power systems, particularly those relying on variable renewable energy resources, to meet firm power needs. Energy stor- age allows for the increased use of wind and solar power, which not only can increase access to power in developing countries, but also increase the resilience of power systems, improving grid reliability, stability, and power quality. Improvements in battery technologies driven primarily by the transport sector have lowered battery costs to the point at which they have become cost competitive in many stationary power applications. However, most commercial battery technologies can deliver their rated power only during a few hours (such as two-to-four hours in the case of lithium ion). This characteristic is not a limitation when it comes to mitigating the short-term variability of renewables, but it requires oversizing the battery pack to address daily or weekly variability phenomena and to guarantee power availability during longer periods without renewable resource. The economic implication of oversizing batteries is that their average utilization is lower, and their average cost increases. The question then arises about whether it is more cost efficient to use green hydrogen or batter- ies to meet the storage needs in a fully decarbonized power system. The answer to this question requires evaluating the energy storage needs in the system on the basis of load profile and the renewable resources available. Because the spectrum of demand and renewable variability is broad, the most likely outcome is that power systems could simultaneously benefit from all forms of storage. Batteries would address short-term and medium-term renewable variability and green hydrogen or other forms of long-term storage, such as hydro reservoirs, would address long-term and seasonal variability, particularly in systems that lack other firm low-carbon resources. The optimal share between these and other forms of storage will depend on their relative perfor- mance and their relative cost, and it is analogous to determining the optimal share of different thermal generation options in a thermal-dominated system. This optimal share will be a moving target as fuel prices and technologies evolve, with cost curves decreasing at different paces. ESMAP has constructed an illustrative LCOE With the rapid scaling of both fuel cell tech- analysis of a hydrogen electrolyzer unit linked nologies and electrolyzers, the economics of to a PEM fuel cell system to provide a reference green hydrogen hybrid systems are expected to point for system costs (figure 4.7). This power-to- become increasingly favorable when viewed power application could be used to complement against diesel generation alternatives. a VRE plant, thus providing a stationary power Assumptions supply for periods of low or zero output from the primary VRE source. The model is driven by nn 1 MW PEM fuel cell and a 1.2 MW a fixed MWh output from the fuel cell, and thus electrolyzer the electrolyzer utilization is driven by the role of nn 1 tonne of on-site pressurized storage (canis- the fuel cell in meeting demand. At low levels of ters) assumed for each scenario utilization, the system shows signs of providing peaker capacity, while at 55 percent or above it nn Installation costs are 1.6 × equipment capex is providing a residual base-level generation. nn Weighted average cost of capital is 10 percent 4: Energy Applications and Commercial Solutions 55 FIGURE 4.6 PEM fuel cell 1 MW unit using excess hydrogen from island refinery, Martinique, 2019 © HDF Energy. Illustrative levelized cost of energy of green hydrogen-based electricity, modeling FIGURE 4.7 under three scenarios, $/MWh Sc n rio 1 Sc n rio 2 Sc n rio 3 Alk lin El ctrol r $196 PEM El ctrol r $208 Alk lin El ctrol r $244 PEM El ctrol r $259 Alk lin El ctrol r $433 PEM El ctrol r $452 $0 $100 $200 $300 $400 $500 Note: PEM = proton exchange membrane. 56 GREEN HYDROGEN IN DEVELOPING COUNTRIES nn Amortizing initial capex in 10 years and stack a 40 MW electrolyzer, and a 7 MW fuel cell replacements over a project life of 20 years system, which estimated an LCOE of $360 per nn $30 per MWh price of power. MWh (Hinicio 2016). These results appear ready to be tested by a French developer called HDF nn PEM fuel cell capex is $3,450 per kW Energy, whose project for the Centrale Électrique nn Alkaline electrolyzer capex is $800 per kW de l’Ouest Guyanais (CEOG) will install a 55 nn PEM electrolyzer capex is $1,200 per kW MW solar PV unit with a 20 MW battery, 20 MW electrolyzer, and 3 MW fuel cell in French The modeling operates under three scenarios, all Guiana. Although HDF Energy has not officially of which have assumed access to the grid. released economic information for this CEOG nn Scenario one: fuel cell utilization at 70 percent project, it has been stated that the project will not require subsidies, and we have thus assumed —— Alkaline electrolyzer utilization at 50 that the analysis must have arrived at an LCOE percent equivalent to or below the utility rate. —— PEM electrolyzer utilization at 50 percent Because a core consideration in assessing the nn Scenario two: fuel cell utilization at 55 percent economic feasibility of green hydrogen in power —— Alkaline electrolyzer utilization at 40 systems applications is to see if such a hydrogen percent hybrid system can displace diesel and heavy fuel oil as a firm generation solution, a benchmark —— PEM electrolyzer utilization at 40 percent target to beat is around $140–$440 per MWh nn Scenario three: fuel cell utilization at 30 for heavy fuel oil and $250–$440 per MWh for percent diesel. Set against this benchmark, it appears —— Alkaline electrolyzer utilization at 20 that green hydrogen production and fuel cell percent hybrid solutions today could provide power at comparable or lower cost than diesel gensets in —— PEM electrolyzer utilization at 20 percent certain contexts, while also complementing VRE Several benchmark reference points inform deployments for developing countries. Important the LCOE analysis. For example, CSIRO 2018 contextual considerations for early deploy- research suggests that under that study’s base ments of these systems include areas where VRE case modeling for a green hydrogen and fuel resources can be deployed below $50 per MWh cell system in 2018, LCOE would be $330–$410 (ideally below $30 per MWh), grid resiliency per MWh, which could be expected to fall and climate resiliency are areas of concern, the to $120–$150 per MWh by 2025 (Bruce and locations are not too remote from air access (es- others 2018). Another reference was Hinicio’s pecially for maintenance work), and there is the 2016 study of a hybrid 115 MW solar PV unit, ability to access (or produce) water. 4: Energy Applications and Commercial Solutions 57 © GROVE HYDROGEN AUTOMOTIVE 5: MOBILITY APPLICATIONS KEY TAKEAWAYS nn Green hydrogen offers an immediately deployable technological solution toward achieving decarbonization of heavy-duty and freight transport sectors in developing countries. nn Fuel cell and green hydrogen mobility solutions could address immediate air quality issues while improving system energy efficiencies and reducing the strain on power grids. nn Batteries and fuel cells are complementary to each other in the mobility sector, especially in heavy-duty appli- cations in which both technologies could be used in tandem. nn The use of existing infrastructure in green hydrogen and fuel cells transportation systems could reduce the risk of generating stranded assets. nn As deployments grow in China and other countries—notably, the United States, Korea, and Japan—the cost of fuel cell mobility solutions will rapidly decline. nn A significant constraint for the initial scale-up of hydrogen mobility applications is the availability and cost of refueling stations. 5: Mobility Applications 59 Mobility has long been seen by hydrogen and current market participants in the heavier-duty fuel cell proponents as the key sector to gen- use cases (that is, greater than 2 tons carrying ca- erating significant market demand and scaling pacity) and freight transport, including maritime technologies so that costs can fall. Currently a shipping. While fuel cells are often portrayed wide array of hydrogen-based mobility applica- as competitors to battery electric solutions, it is tions is available across the sector—including more helpful to consider them as partner tech- cars, buses, trucks, trains, planes, and ships— nologies that complement one another. Most fuel with the most attractive market segment for cell vehicles use batteries to provide immediate BOX 5.1 FUEL CELL VERSUS BATTERY ELECTRIC VEHICLES The question of whether fuel cells or batteries will dominate the electric vehicle market often emerges during discussions of the future of electric transport. Battery electric vehicles (BEVs) have come a long way, representing a non-negligible share of total passenger car sales in many countries, while the number of FCEVs on the road remains much lower, with only a few models available. Yet, the relative strengths and weaknesses of these two electric vehicle types indicate that they will likely have complementary roles in the future. Technically, the main difference between storing electricity in a battery and storing hydrogen in a tank lies in their different specific energy and energy density. Although batteries can store a large amount of energy in a small volume, batteries are heavy and require more energy to be transported with the vehicle. Achieving long ranges with BEVs therefore involves carrying an increasingly heavy battery that reduces the overall fuel efficiency of the vehicle. Conversely, hy- drogen has a much higher specific energy (approximately 150 times more energy than batteries for the same weight) but very low energy density (it takes a larger volume and requires very high pressures to be contained in a small volume). Another important difference is the current availability of recharging and refueling stations and the recharging/refueling time. BEVs can be recharged at home, and public charging infra- structure has improved continuously over the past decade, with a network of charging stations already available in many countries. In contrast, FCEVs cannot be refueled at home, and the number of public refueling stations is much more limited than for BEVs (for a reference, in 2017 it was 328 versus 90,000, according to Unicredit 2019). However, a growing number of coun- tries have ambitious plans to develop new hydrogen refueling stations in the near future. Also, FCEVs can be refueled in just a few minutes, whereas it might take hours to recharge a BEV. In terms of cost, BEVs offer a lower total cost of ownership than FCEVs (4.44 cents/km for BEVs versus 9.50 cents/km for FCEVs, according to Unicredit 2019). However, this factor is directly dependent on the use of the vehicle, and vehicles that are meant to operate over longer distanc- es, such as FCEVs, could see this figure reduced. Because of these factors, the current expectation is that, for most passenger cars, BEVs will continue to significantly outnumber fuel cell vehicles, but for longer-range applications, freight transportation, buses, maritime, and air transport, FCEVs could have a strong competitive edge in the future. 60 GREEN HYDROGEN IN DEVELOPING COUNTRIES Overview of notable currently available and announced passenger fuel cell electric TABLE 5.1 vehicle models RELEASE RANGE MODEL COMPANY COUNTRY DATE CONFIGURATION (km)a COST ($)b Mirai Toyota Japan 2014 114 kW 499 57,500 Kangoo Renault France 2017 varies 100 (est.) Order dependent iX-35 Hyundai Korea, Rep. 2015 100 kW 594 65,000 Clarity Honda Japan 2018 130 kW 616 60,000 GLC F-Cell Mercedes Germany 2019 155 kW 475 Not released Nexo Hyundai Korea, Rep. 2019 135 kW 795 58,000d 5 Seriesc BMW Germany 2020 180 kW 480 Not released i8 BMW Germany 2020 Unknown 496 Not released a. Converted into kilometers. b. All converted into U.S. dollars at XE rate on September 17, 2019. c. Hydrogen Cars Now n.d. d. Crosse 2019 power response, especially for heavier-duty ap- vehicle (BEV) market, FCEVs are gaining pop- plications. Fuel cells, however, can have higher ularity among users who either have consid- specific energy than batteries and can extend the erably longer average driving distances (such range of vehicles more effectively than batteries as California) or customers whose high rate of because of their lower total system weight and vehicle use places a premium on the availabil- quicker refueling time. Additionally, fuel cells are ity of power. less affected by external temperatures and thus A clear example of the second group is the are less likely to experience range reductions taxi industry, with FCEV taxis now being used owing to abnormal conditions. At the time of in China, Denmark, France, Germany, the writing this report, it is estimated that there are Netherlands, and the United Kingdom. Another 3,000 fuel cell buses and trucks deployed glob- example is the ride-sharing industry. The first ally (Obiko Pearson 2019) and over 12,000 fuel such program announced publicly was by cell passenger vehicles. Grove—a Chinese automotive company—which announced a 200-vehicle first run in the Chinese city of Rugao in 2019 that will expand to 10,000 5.1. FUEL CELL ELECTRIC FCEVs by 2020–21 (New Mobility 2019). Grove VEHICLES has also announced initial discussions with part- Today more than 12,000 FCEVs are on the ners in Minas Gerais, Brazil (Green Car Congress roads globally, with the overwhelming majority 2019) and with DSM Global to deploy FCEVs in Japan and the United States. Most of these to Nepal (Kreetzer 2019). Recently, FCEVs have units are purpose-built hydrogen models, but also been deployed in British Columbia as a ride-share solution, with early signs that the cars in some markets, such as Europe, a significant have proved popular with consumers (McCredie number of FCEVs are essentially modified 2019). electric vehicles in which the fuel cells function as a range extender (table 5.1). While a consid- The growing interest in passenger FCEVs erably smaller market than the battery electric is driven by several factors. The first is the 5: Mobility Applications 61 recognition that low-emission technologies are dealerships see sufficient demand to train their essential for the automotive sector. FCEVs have staff to service FCEVs, it is anticipated that more no tailpipe emissions—only water. The second is FCEVs will be purchased directly by consumers. customer experience. Although FCEVs today may California offers one example of the growth of lack a wide refueling network, they do provide the FCEV market over the past five years in an significantly longer ranges than can typically be early-adopting market (figure 5.1). found in battery electric vehicles, and they refuel in under five minutes. 5.2. FUEL CELL ELECTRIC BUSES FCEV manufacturers have also identified other The number of fuel cell applications for buses is benefits to highlight. For example, because fuel currently significantly larger than the number of cells require access to clean oxygen to react FCEVs deployed globally. Ballard Power Systems with hydrogen, all FCEVs require some form of delivered its first fuel cell bus in 1993. Today air purifier on board. On that account, Hyundai there are several hundred fuel cell buses (FCEBs) has recently begun to market its latest FCEV in operation, notably in Europe, with increas- sport-utility vehicle, the “Nexo,” as “an air puri- ing growth in China, Japan, Korea, and North fier on wheels” that claims to leave the air even America (figure 5.2). The advantages of fuel cell cleaner than it was when it entered the car. The buses are their range, quick refueling times, and, vehicle has a filter system to separate the oxygen increasingly, their declining cost versus battery before it is compressed and filtered into the fuel alternatives. Developing countries are catching cell (The Wheel Network 2018), thus Hyundai up quickly, with Brunei, Costa Rica, India, and argues that the Nexo is actually better for ad- Malaysia among the first movers. dressing localized air pollution than BEVs are. As of 2019, FCEBs have demonstrated operating Declining fuel cell vehicle costs are also likely times above 20,000 hours in multiple coun- to be a significant contributing factor in rising tries. In fact, Transport for London’s eight FCEBs global FCEV deployments. For example, the procured for the Olympics in 2012 have ex- cost of a Toyota FCEV launched in 2015 was ceeded 34,000 hours operating time and remain expected to be 95 percent lower than an equiv- on the roads today. In Aberdeen, Scotland, the alent model available in 2008 (Millikin 2014) 10 FCEBs procured in 2014 have demonstrated . Nevertheless, fuel cell vehicle sales are still remarkable performance, with all units exceed- starting from a low base, with no fuel cell vehi- ing 1 million miles and demonstrating ranges of cle ever having entered the top 50 most popular up to 250 miles per day, refueling in only five to models (JADA 2019), despite strong government seven minutes (Ballard Power Systems 2019a). support (box 5.2). Consequently, the Aberdeen City Council con- Few FCEVs are purchased directly today because firmed financial support for an additional five of the limited number of refueling stations and FCEBs in 2019 (FuelCellWorks 2019a) on the the lack of widespread technical capability to basis of the performance of the existing units, address car servicing needs, both of which make which tests suggest have proved to be almost four individual ownership challenging. To address times more fuel efficient than their diesel equiv- those issues, manufacturers have ensured that alents (IMechE 2016). Newer units are targeting almost all FCEVs are leased today, with the even higher performance. For the 2022 Winter Toyota Mirai available for lease in the United Olympics in China, Toyota is partnering with States at $349 per month (IEA 2017). As refueling Beiqi Foton Motor and Yihuatong Technology to capacity is rolled out further and as automotive provide a fleet of FCEBs. These will have a 60 kW 62 GREEN HYDROGEN IN DEVELOPING COUNTRIES BOX 5.2 HYDROGEN MOBILITY IN CHINA Following China’s rise to become the world’s premier market for battery electric mobility solu- tions, the battery electric transport leasing market is switching its focus increasingly toward fuel cell mobility solutions. In 2018 alone, China is reported to have invested over US$12 billion in research, development, and deployment of hydrogen and fuel cell solutions, almost exclusively within the transportation sector. All of China’s major car companies have announced fuel cell vehicles under development, while the city of Rugao, backed by technical support through a US$10 million program with the United Nations Development Programme, has committed to purchasing 10,000 fuel cell vehicles from Chinese start-up Grove. The fastest-moving sectors of the fuel cell industry in China have been in the bus and logistics segments. Alibaba has already begun to use fuel cell vehicles to support its logistics operations in and around its vast warehouses, while several Chinese cities have procured and are expand- ing their fleets of fuel cell buses. In Beijing, the government recently procured 10 fuel cell buses to support the 2022 Olympics, with financing partly provided by the Asian Development Bank. Meanwhile in Shanghai, SAIC and the Shanghai Chemical Industry Park opened the world’s largest hydrogen refueling station in June 2019. The site supports the refueling of 74 fuel cell buses, dispensing around 1.5 tonnes of hydrogen daily on a 24/7 basis. As of December 2019 alone, it was reported that Ballard and its joint venture partners in China (Foshan Feichi Bus and Yunnan Wulong Bus) secured 354 fuel cell bus orders. State support has proved to be essential in accelerating deployments. SAIC’s Maxus FCV80 was originally launched at a price tag of RMB 1.3 million, but with subsidies the actual cost was estimated to come in closer to RMB 300,000. Meanwhile, fuel cell buses were expected to receive a subsidy worth in excess of US$100,000, reducing the cost of fuel cell buses from US$500,000 to below US$400,000 before local and regional subsidies. Further, most of China’s hydrogen is sourced from hydrogen produced as a non-core product of another chemi- cal or industrial process and thus it is often sold below the price point of US$10–US$14 per kg commonly seen in developed markets. Furthermore, fuel cell costs and electric vehicle costs are clearly falling, suggesting that the Chinese government’s planned phaseout of subsidies by 2023 could mark the point at which fuel cell vehicles will reach commercial viability in the domestic market. Sources: Sanderson 2019 and ESMAP correspondence with suppliers. fuel cell, and Foton claims that its fourth-genera- Existing experiences show that the costs of tion buses will provide a range of 450 kilometers FCEBs are a constraint in certain markets, as is (Xu 2019). It is important to note that FCEBs are access to refueling units. For example, electric not limited to developed markets. Indeed, Ad buses in the United States appear to be less Astra deployed the first FCEB in Central America expensive than the most recent publicly quoted in 2018, using solar PV and electrolyzers to gen- price for an FCEB, at roughly $1.1 million for erate green hydrogen on-site for its two refueling an FCEB in California versus $750,000 per stations (Kazmier 2018) (box 5.3). battery electric bus (Stromsta 2019). Further, 5: Mobility Applications 63 California monthly fuel cell electric vehicle market, January 2014–December FIGURE 5.1 2019 (number of sold and leased units) 10,000 fu l c ll l ctric v hicl s on th ro ds 8,000 6,000 4,000 2,000 0 Ap 14 Ju 4 Oc 4 J 14 Ap 15 Ju 5 Oc 5 J 15 Ap 16 Ju 6 Oc 6 J 6 Ap 17 Ju 7 Oc 17 J 17 Ap 18 Ju 8 Oc 8 J 18 Ap 19 Ju 9 Oc 9 19 1 1 l-1 1 l-1 1 l-1 1 1 l-1 1 l-1 n- r- t- l- r- t- n- r- t- n- r- t- r- t- n- r- t- n- n- J Source: Energy.gov and California Fuel Cell Partnerships, compiled by ESMAP 2020. FIGURE 5.2 Past and present fuel cell bus examples, 1993 (right) and 2014 (left) © Ballard Power Systems. 64 GREEN HYDROGEN IN DEVELOPING COUNTRIES BOX 5.3 CLEAN MOBILITY IN COSTA RICA USING CENTRAL AMERICA’S FIRST FUEL CELL BUS Costa Rica is frequently recognized as a global leader in sustainability, ecotourism, and clean power, but decarbonizing the country’s transportation sector has remained a challenge. Local grids are often ill suited to rapid charging requirements that battery electric drivers expect (as of April 2018 there were 20 electric vehicle charging stations in the entire country). Further, the country’s population depends on the bus network to commute to work and school, particularly in poorer communities. In this context, U.S.-based Ad Astra Rocket deployed Central America’s first fuel cell electric bus (FCEB), hydrogen refueling station, and green hydrogen electrolysis unit. The project was partly funded by IDB Invest, the private sector arm of the Inter-American Development Bank, and is intended to demonstrate that fuel cell buses can be a serious solution to help decarbonize the transportation sector in Costa Rica, throughout the wider Latin America region, and beyond. At a cost of $4.4 million to date, the project has demonstrated that the technology is technically viable, that it is clean, and that it could be a powerful contribution to Costa Rica’s decarboniza- tion efforts. The bus itself was deployed in 2017 in Liberia, Guanacaste, and has a range of up to 340 kilometers (210 miles) on 38 kg (83 lbs.) of compressed hydrogen. The capacity of the vehicle is about 35 passengers, and it can reach a speed limit of up to 110 km per hour (68 mph). As a public-private partnership, the project has benefited from the collaboration of the government of Costa Rica, Ad Astra Rocket Company, Air Liquide, Cummins Inc., Sistema de Banca para el Desarollo, Relaxury S.A., and US Hybrid Corporation. The power is generated by a combination of solar photovoltaic panels and an onshore wind turbine located next to the company’s Costa Rican office. The site now also refuels the country’s first four fuel cell electric ve- hicles, three of which are leased to tourists at a local ecotourist hotel, as a zero-emission solution capable of driving long distances without range concerns. Source: ESMAP correspondence with suppliers. significantly fewer hydrogen refueling stations FCEBs now are delivered alongside hydrogen than electric charging locations have been refueling stations at their base of operations, installed. Yet, the cost advantage of batteries thus addressing some of the concerns around over FCEBs does not hold in all markets. For access to fuel supply (figure 5.4). Nevertheless, example, in public filings Ballard provided cost with respect to charging or refueling, hydrogen estimates of US$500,000 per FCEB in China, refueling stations remain more expensive to while sources all suggest that EU target prices of install than pure electric alternatives. EUR 650,000 (GBP 520,000) set in 2016 have been met in the United Kingdom market today 5.3. Fuel Cell Trucks (Pocard and Reid 2016). At these price points, FCEBs may look attractive even compared with Fuel cell trucks are one of the most promising conventional diesel buses in certain markets areas of growing demand for fuel cell solutions (figure 5.3), particularly where diesel bus prices in the mobility sector. As of 2020, government of US$500,000 per unit have been reported agencies and companies in China, Japan, Korea, (Stromsta 2019). It is also the case that most Norway, and Switzerland all have pledged to 5: Mobility Applications 65 FIGURE 5.3 Declining cost of fuel cell electric buses 2,500,000 $2,000,000 2,000,000 Cost p r VCEB, $ 1,500,000 $950,000 1,000,000 $500,000 500,000 $417,000 0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Source: Ballard data 2019 and Bloomberg 2019, reconstructed by ESMAP. FIGURE 5.4 Fuel cell bus refueling in Wuhan, China © Grove Hydrogen Automotive. 66 GREEN HYDROGEN IN DEVELOPING COUNTRIES procure and deploy over 1,000 fuel cell trucks practices and that Nikola’s solution, at least in the over the next decade. United States, will operate under an integrated leasing structure, in which a single monthly Thus far China has been the dominant market payment will cover vehicle rental, hydrogen for actual deployments of fuel cell trucks. As of refueling, warranty, and maintenance. The pricing December 2019, Horizon Fuel Cells through its is based on an estimated distance traveled, and joint venture with Ford Motor Company in China owners will have the option to trade in for a new had deployed over 400 fuel cell trucks (ranging Nikola vehicle every 700,000 miles or 84 months, 8 tons to 42 tons), notably the first 42-ton hy- whichever comes first (Nikola n.d.). drogen trucks delivered in the world (Gu 2019). Meanwhile, Ballard and its partners have deployed Despite the potential for Nikola to transform over 1,400 fuel cell trucks in China, ranging from US trucking, the only deployed hydrogen and 500 three-ton trucks in Shanghai to larger 12-ton fuel cell trucks in the US today are run in Long units (Ballard 2018, 2019b). Numerous other com- Beach, California, where Toyota is using two panies are now entering the sector, contributing to hydrogen trucks for drayage operations, with an estimated 4,000 fuel cell commercial vehicles Shell providing the hydrogen for refueling (PR in China by 2018 (Ballard 2018). Newswire 2018). Toyota has partnered with Kenworth for the project, and their two pilot However, although China is the largest current market for fuel cell trucks, the rise of a company trucks are due to expand to 10 units by 2020. called Nikola in the United States has captured Thus far the trucks have logged more than the bulk of investor and media interest recently. 14,000 miles of testing and drayage operations Nikola Corp. is currently one of the market (Babcock 2019). Mike Dozier, the general leaders in terms of orders and scale for hydrogen manager of Kenworth, stated, “The performance trucks, and it has plans to offer three truck prod- of the 10 Kenworth Class 8 trucks being devel- ucts: Nikola One, Nikola Two, and the Nikola oped under this program … is targeted to meet Tre (European model). The flagship model is the or exceed that of a diesel-powered truck, while Nikola One, which offers up to 2,000 pounds of producing water as the only emissions byprod- torque, up to 1,000 horsepower, a 500–700 mile uct” (Babcock 2019). In addition to those units, range, and a 15–20 minute refueling time. Across Toyota/Kenworth have orders from UPS, whose all three models, Nikola claims to have a backlog first three deliveries were due at the end of 2019 of 13,000 orders (Wiles 2019). Powerful strategic (Abt 2019) (figure 5.5). Box 5.4 describes a partnerships underpin the Nikola proposition. heavy transport case involving green hydrogen. Electrolyzers have been ordered from market leader Nel, for a 1 GW initial order, to provide initial 50 x 20 MW electrolyzer units for refuel- 5.4. SHIPPING AND TRAINS ing. Bosch is the OEM provider (with fuel cells Two of the largest potential sources of green hy- likely to be from Ballard, though that is not yet drogen demand in the mobility sector are freight confirmed). Confirmed clients include Anheuser and maritime applications. Busch, which has already committed to taking The first hydrogen vessel was a retrofitted German more than 600 trucks. In total, Nikola claims to ferry for internal waterways commissioned in have $11 billion in preorders and has raised over 2006, and new ocean-capable vessels being $450 million in financing in the past five years. designed today have received provisional classi- It is important to note that Nikola’s business fications and may be in service by 2021. These model differs significantly from current market new vessels include a green hydrogen ferry for 5: Mobility Applications 67 Current fuel cell truck concepts: Kenworth/Toyota fuel cell electric truck (top), FIGURE 5.5 Nikola One (bottom left), and Horizon fuel cell in JMC truck (bottom right) Sources: a. Courtesy of Toyota via Toyota newsroom. b. Courtesy of Nikola Corp. c. Courtesy of Horizon Fuel Cells. 68 GREEN HYDROGEN IN DEVELOPING COUNTRIES BOX 5.4 HYDROGEN FOR MINING MOBILITY OPERATIONS IN CHILE Mining is an energy-intensive business. The World Bank’s Climate-Smart Mining Facility re- ports that mining operations consume around 11 percent of total energy demand worldwide, with 4 percent used for crushing rocks alone. Yet, the sector’s heavy reliance on diesel for mobility and remote power provision indicates that the sector’s emission profile may be even worse than the headline numbers. In Chile, a country where mining accounts for 10 percent of gross domestic product and copper alone accounts for 50 percent of exports, the desire to replace expensive fuel imports for mining operations by lower-cost locally produced energy is encouraging early investments. In 2017 the country’s leading research agency, CORFO, announced that a consortium of leading mining, fuel cell, hydrogen, and renewable project development companies would work together to develop hydrogen mobility solutions for mining operations in Chile. The approxi- mately $6 million investment, backed by up to $6 million of investment from the project’s private sector partners, is designed to help examine the technical and economic viability of hydrogen as a clean fuel source in the large mining vehicles that operate in the country’s northern regions. Alongside this effort in Chile, AngloAmerican has invested in 900 kW of proton exchange membrane fuel cells from Ballard to power a retrofitted Ultra heavy-duty mining truck in South Africa that will begin its pilot operations in 2020 (Ballard 2019c). Further on, hydrogen may also be able to help provide remote energy storage, as it does in one of Chile’s microgrids in the Atacama Desert, and it may even be able to help with processing ore after its extraction. A key reason that Chile has emerged in recent years as a hotspot for green hydrogen projects is the country’s exceptional renewable resources, complemented by a strong regulatory framework and investment environment. A study by Tractebel and the Chilean Solar Committee (2018) concluded that green hydrogen could be produced at between $1.80 per kg and $3.00 per kg as soon as 2023, making the fuel competitive with hydrogen from natural gas imports, if not cheaper. This forecast further aligns with research conducted by the International Renewable Energy Agency in 2018, which concluded that Chile could produce hydrogen from renewable resources today at between $4.00 per kg and just under $6.00 per kg, declining to between $2.50 per kg and $4.00 per kg by 2030. Given these anticipated cost declines, and market ex- pectations that hydrogen in mobility can compete with diesel at below $7.00 per kg at the point of delivery, Chile appears well positioned to lead the deployment of low-emission technologies to reduce heavy transport emissions in the mining sector. Source: Tractebel and Chilean Solar Committee 2018; ESMAP correspondence with suppliers. the Orkneys, being developed under the HySeas Today 2013). During the trial, the fuel cell logged III program in Scotland, and several projects in 18,500 successful operating hours, providing Norway. Initially, the focus for hydrogen in ship- supplementary power to the ship at an electrical ping has been to provide auxiliary power. During efficiency of over 52 percent at full load (Fuel Cell the FellowSHIP program in Norway in 2009, the Today 2013). Now the sector is looking to power Viking Lady installed a 330 kW molten carbon- all operations via hydrogen, with some configu- ate fuel cell from MTU Onsite Energy that ran rations using pure PEM units and others consid- on natural gas without pre-reforming (Fuel Cell ering PEM to power the turbines while auxiliary 5: Mobility Applications 69 power might be handled by other technologies stations. Relatively few stations are in place such as SOFC units. For example, Bloom Energy globally, with the IEA estimating that 432 has announced a partnership with Samsung stations were operating at the end of 2019. Heavy industries to examine SOFC use in ship- But this situation is forecast to change rapidly, ping as of September 2019 (Business Wire 2019). and as of 2017 global cumulative announce- Noteworthy partnerships in this space include ments for hydrogen refueling stations (HRSs) PowerCell and Siemens (Siemens 2018), Ballard exceeded 1,100 new units by 2020, 3,000 by and ABB (Green Car Congress 2018), as well as 2025, and about 15,000 by 2030 (Hydrogen Nedstack and General Electric (Terpilowski 2019). Council 2017). These figures are being revised Given the intensive use of heavy and light hy- upward, with Agrola, AVIA, Migros, Migrol, and drocarbons as bunker fuels in maritime shipping Coop in Switzerland committing to support the and the large potential environmental benefits of deployment of 1,500 HRSs alone, and KOGAS decarbonizing this sector, the World Bank through committing over $4 billion to hydrogen produc- its trust fund Problue has begun a program to tion and refueling station infrastructure in Korea support developing countries in their ambitions between 2019 and 2030. Hydrogen refueling to switch to zero-carbon bunker fuels, and to stations are also moving out from traditional develop sustainable marine resources. Initial steps markets like China, France, Germany, Japan, have been taken to explore the potential demand Norway, the United Kingdom, and the United for zero-carbon bunker in the ports of a few States (figure 5.6). In 2018 the first HRS units selected countries, and the resources required to were installed in Austria, Canada, Costa Rica, meet that demand. Iceland, Spain, and the United Arab Emirates; meanwhile, Malaysia announced plans to With respect to trains, only two countries currently expand its hydrogen refueling station network operate them: one hydrogen train in Germany and from one to seven in December 2019, mak- a hydrogen tram in China (Yang 2017). Germany’s ing it one of the largest networks in the world train is developed by Alstom and Hydrogenics announced outside of Japan, Germany, France, (Railway Technology n.d.). But other companies the United Kingdom, and the United States are catching up, with Ballard and Siemens working (FuelCellWorks 2020). together on a hydrogen train based on the Mireo platform. Ballard already received an order from In addition to the number of stations deployed, Porterbrook (a leading participant in the UK rail hydrogen refueling stations are also scaling in leasing market) to provide fuel cells for 100 car- their capacity. While early sites may have been riages that will operate in the United Kingdom un- able to refuel only a small number of cars per der the “HydroFLEX Train” banner (Songer 2018). day, new stations can provide fueling for po- Interest in hydrogen trains has also been expressed tentially hundreds of vehicles, with the world’s in Canada and North Carolina (United States) and largest refueling station in China providing in France and other EU markets. hydrogen for 74 fuel cell buses a day, dispensing 1.5 tonnes of hydrogen (Haskel 2019). Possibly the largest constraint for HRS units is 5.5. HYDROGEN REFUELING their cost. Estimates suggest that without on-site STATIONS refueling (hydrogen brought in externally), HRS A significant constraint for hydrogen mobil- can be developed for around $1.1 million in ity applications is the availability of refueling the United States27 and for around $1.5 million 27 ESMAP discussions with suppliers, 2019. 70 GREEN HYDROGEN IN DEVELOPING COUNTRIES Green hydrogen refueling, with on-site hydrogen generation from rooftop photovoltaic: FIGURE 5.6 Freiburg, Germany, in 2012 (left) and Emeryville, California, in 2011 (right) Source: Courtesy of Nel. FIGURE 5.7 Example of hydrogen refueling station configuration (no on-site production) system electronics high and low pressure storage compressors IR detection dispenser and chiller Note: IR = infrared. © NREL. Notes added by ESMAP. 5: Mobility Applications 71 in China (Wanyi 2018). (See figure 5.7.) A study service provision under the UK’s “demand on” by the Hydrogen Council noted that the CEP/ program run by National Grid, which may pro- H2Mobility program in Germany saw HRS vide an additional revenue stream to improve costs fall from EUR 2 million (US$2.4 million) the commercial viability of on-site generation per station in 2008 to EUR 1 million (US$1.2 for HRS locations. million) as of 2017 (Hydrogen Council 2017). The same year, the IEA reported, “The cost of early market HRS ranges from US$2.1 million 5.6. MATERIAL HANDLING AND to US$3 million in California” (IEA 2017). HRS FORKLIFTS units today employing on-site green hydrogen One of the world’s leading companies in generation can add US$2 million–US$4 million material handling units is Plug Power, a US- to the site’s cost depending on the electrolyzer listed fuel cell manufacturer with over 30,000 size and the technology used (box 5.5). It has fuel cell forklift trucks deployed globally, been noted that PEM electrolyzer units in mostly in the United States (Plug Power 2020). the United Kingdom can qualify for ancillary Currently, hydrogen and fuel cell technologies BOX 5.5 ENERGY STORAGE AND GREEN HYDROGEN REFUELING ON SINGAPORE’S SEMAKAU ISLAND The island of Semakau in Singapore lies 8 kilometers away from the mainland and operates as an entirely separate microgrid. While the island is largely used as a landfill site for ashes from Singapore’s waste incineration plant, it has also deployed several renewable resources, includ- ing an onshore wind turbine, and is now the pilot site for the REIDS initiative (Renewable Energy Integration Demonstrator—Singapore). The island is a test case for the government to show that hydrogen and fuel cells can help work alongside the other renewable technologies on the island to enhance grid stability and provide innovative solutions to the island’s energy needs. Led by Engie via its Sustainable Powering of Off-Grid Regions (SPORE) project, Semakau has deployed a specially designed onshore wind turbine, supported by a 200 kW Ineo battery, which functions as the primary energy storage solution for the island. To provide additional storage beyond the several-hour timeframe and to provide an energy solution for vehicles on the island, an electrolyzer provided by McPhy that can store up to 2 MWh (80 kg) of hydrogen has been deployed. This hydrogen can then be used either by the hydrogen refueling station on the island to power a modified Renault Kangoo electric van or to provide additional energy storage for periods that exceed the storage capacity of the battery. Although Semakau is small island with only 2 square kilometers, the project itself has demon- strated that green hydrogen can be a useful contributor to maintaining grid stability, mitigating renewable variability, and providing multiple energy end applications for off-grid or remote energy systems. 72 GREEN HYDROGEN IN DEVELOPING COUNTRIES FIGURE 5.8 Hydrogen forklift refueling © Grove Hydrogen Automotive. are extremely appealing to material handling in Plug Power) and Walmart, both of which are businesses because they require significantly estimated to use Plug Power units in over 25 less space than battery alternatives and they percent of all their US warehouses. Outside have a higher operational availability (figure of the United States, Carrefour, Alibaba, and 5.8). Major customers of hydrogen and fuel Toyota are also scaling up their use of hydrogen cell forklift units include Amazon (an investor and fuel cell forklifts. 5: Mobility Applications 73 © PDC MACHINES 6: INDUSTRIAL APPLICATIONS KEY TAKEAWAYS nn Gray hydrogen is widely used in industry today. The scaling up of green hydrogen provides companies and policy makers with a powerful tool to decarbonize existing and new sources of industrial energy demand and industrial processes. nn Ammonia production, refining processes and methanol production constitute over 90 percent of the total hydrogen demand today. nn Green hydrogen could be a clean alternative to coal in the reduction of iron ore, and could replace natural gas as a source of high-temperature heat in the iron and steel industry. nn Hydrogen carriers such as methanol, ammonia and synthetic methane are easier to store and transport than hydrogen but come with higher efficiency losses. Still, their physical properties make them more appropriate than hydrogen for specific industrial applications nn Producing green ammonia in developing countries, using low cost renewable energy and electrolysis, create a more distributed production model, reducing transport costs and creating opportunities for local industrial development. 6: Industrial Applications 75 6.1. IRON AND STEEL industry to prevent partial oxidation of iron ore while the ore is in the furnace. Some sites will Industrial and chemical uses remain the core flood the furnaces with hydrogen, so that it will market for hydrogen today. Broadly, the current react with any fugitive oxygen molecules and market can be split into production of ammonia, prevent oxidation (figure 6.1). refining of gasoline, and production of metha- nol. However, as industries increasingly look to The bigger question that researchers are attempt- decarbonize their industrial heat requirements, ing to assess is whether hydrogen can play a a number of companies are examining the role greater role by replacing coal and other heating of green hydrogen in processes such as steel and fuels. Three flagship projects operate in this space: glass manufacturing. Tata, ThyssenKrupp, Nouryon, and the Port of Amsterdam project; HYBRIT in Sweden; and Steel production is a particularly interesting H2FUTURE in Austria. By far the largest of these area for hydrogen because of the process’s high is the Port of Amsterdam, which is at the feasibility carbon emissions and the relative lack of viable study phase and is looking at a 100 MW electro- alternatives. Currently hydrogen is already partly lyzer that would produce 15,000 tonnes of green used in metal processing to yield iron reduction, hydrogen a year and create oxygen for the steel and Air Liquide estimates that the typical hydro- site as well. The first pilot that is actually installed gen consumption in this type of plant is between and operating is H2FUTURE in Austria, where a 36 tonnes per year and 720 tonnes per year 6 MW PEM electrolyzer provided by Siemens is (Fraile and others 2015). Thus, steel represents working on a Voestalpine steel site, using power an addressable market by electrolysis and green from Verbund’s almost entirely renewable-based hydrogen. Indeed, there are companies using portfolio (Voestalpine 2018). hydrogen as the protection gas in the produc- tion of steel plate, with a unit supplied by THE For the HYBRIT project, SSAB, LKAB, and China providing this service to a site in Bulgaria Vattenfall are using a 4.5 MW alkaline electro- (THE n.d.a.). Hydrogen is also used in the iron lyzer to operate in Luleå, Sweden, from 2021 until FIGURE 6.1 Electrolyzer at an Indian iron production plant © EnerBlue. 76 GREEN HYDROGEN IN DEVELOPING COUNTRIES FIGURE 6.2 HYBRIT concept image © Hybrit Development, 2019. 2024, before the project enters a demonstration 6.2. AMMONIA phase with the goal to have an industrial process As previously indicated, ammonia is the largest in place by 2035. The HYBRIT process is based demand source for hydrogen today and a prime on direct reduction of iron ore using renewable option for decarbonization efforts with green energy and hydrogen; the hydrogen reacts with hydrogen. Two large-scale projects that are the oxygen in the iron ore, thus creating metallic being considered for investment are a 20 MW iron and water (Cision 2019) (figure 6.2). At this electrolyzer unit at Air Liquide’s ammonia site time, in the absence of supporting policies, evi- in Quebec (Air Liquide 2019) and a 100 MW dence from HYBRIT studies suggests that the costs solar PV combined with a 50 MW electrolyzer from electrolysis remain too high. The capital for YARA’s ammonia site in Western Australia expenditure required for setting up a direct iron (ENGIE 2019). These projects are following processor, an electrolyzer, and a hydrogen storage pilot hydrogen-from-wind to ammonia projects facility is estimated at EUR 1,000 per tonne of that already have been deployed and which crude steel, comprising almost 80 percent of the provide evidence of the technical feasibility total production costs and yielding a steel price of and cost considerations for such an application EUR 1,200 per tonne (WEC Netherlands 2019). (figure 6.3). 6: Industrial Applications 77 FIGURE 6.3 World’s first wind-to-ammonia project Source: Nel electrolyzer at Morris, Minnesota, United States. Courtesy Nel. Ammonia as a market for green hydrogen is greater volumes of ammonia domestically, particularly appealing because of the scale of de- creating jobs. It is for this reason that companies mand. A study for the FCH JU in 2015 estimated such as Thyssenkrupp have begun to market that a typical ammonia plant has the capacity to smaller-scale ammonia solutions based on produce between 1,000 and 2,000 tonnes of am- systems that can run on a 20 MW power input, monia per day, thus requiring 57,500 to 115,000 with modular scaling up to 120 MW. Regarding tonnes of hydrogen per year (Fraile and others the use cases for smaller designs, the company 2015), while Thyssenkrupp suggests a traditional noted, “at landlocked locations with low power plant would produce closer to 3,000 tonnes per costs, installation of a green ammonia plant may day (Thyssenkrupp n.d.). Such a level would well be an interesting option, not least for the require electrolyzer units significantly larger than fertilizer or chemical industry. Not surprisingly, those currently commercially deployed, and a economies of scale favor conventional plants single site would likely absorb many manufac- at higher production capacities. But besides its turer’s annual capacity for several years, given economically feasible existence as a niche prod- the current installed capacity of electrolyzer uct, green ammonia is becoming increasingly suppliers. interesting to renewable energy producers as a suitable energy storage and carrier medium.” The other appeal is that if the cost of hydrogen (Thyssenkrupp n.d.). from electrolysis were to fall below the cost from SMR, it would be conceivable that the While the primary interest in ammonia is its use centralized ammonia production process itself as a fertilizer, it can also be used as a mechanism would change and move toward a more distrib- for storing energy hydrogen cheaply and for long uted production model. Such a situation would periods of time, before the hydrogen is extracted reduce transport costs and would also create out of the ammonia again. Although this process the opportunity for many countries to produce entails high efficiency losses, with round-trip 78 GREEN HYDROGEN IN DEVELOPING COUNTRIES efficiency figures around 20–30 percent, depend- of green hydrogen can be counted toward reduc- ing on the initial efficiency of the electrolyzer/ tion in national transportation emissions. Thus, SMR used, it may still be viable in areas where the first big test is likely to be ITM Power’s 10 the production of hydrogen is low. In addition, MW unit inside Shell’s Rhineland factory, closely more recent research has examined whether followed by BP’s 250 MW feasibility study in the ammonia can be used directly as a fuel, whether Port of Rotterdam that is looking at producing up with a reformer on a fuel cell or combusted in a to 45,000 tonnes of green hydrogen per annum turbine. Some companies in the power sector al- (Port of Rotterdam 2019). ready use ammonia. The largest user of ammonia for fuel cell applications is GenCell, whose units provide off-grid power supply using ammonia 6.4. GLASS, FOOD, AND OTHER with a reformer (GenCell n.d.). These units have AREAS lower system efficiency than typical hydrogen or Other segments of interest for green hydrogen SOFC cells, but they can store ammonia easily in industry include the food industry and glass on-site for up to six months at a time. Companies industry. Hydrogenation of fats is the core area such as Baker Hughes and MAN Group have of application for the food industry, with the also been working to develop and commer- demand profile suitable for electrolyzer units be- cialize turbine technology that could generate tween 0.5 MW and 2 MW. This amount is based power from 100 percent ammonia fuel. This is on estimates from the FCH JU that on average being closely monitored by officials in coun- hydrogenation of fats sites require hydrogen pro- tries with existing natural gas turbines installed, duction of up to 28 kg per hour,28 corresponding who see green ammonia as a potentially more to 672 kg a day if operating 24 hours. convenient hydrogen-derived fuel for zero-car- bon-emission power. Glass manufacturing is also a growing area of interest for green hydrogen, with suppliers indicating growing awareness in Asia, Europe, 6.3. REFINING and North America. Given the low demand for hydrogen from a typical glass plant, around 3.95 One of the most immediate sources of potential kg per hour, this market segment is well suited to industrial demand for green hydrogen is refining. on-site generation via electrolysis.29 In Slovenia, A typical refinery might require between 7,200 one company is using rooftop solar PV to create tonnes and 108,800 tonnes of hydrogen per year, hydrogen that is blended with natural gas into with new and complex large-scale refineries the glass site furnaces (Willuhn 2019). A com- requiring up to 288,000 tonnes per year (Fraile pany in Vietnam has been using hydrogen within and others 2015). Accordingly, a growing area of its glass processes (THE n.d.b.). interest for industry in the short to medium term is whether emissions from refining and gasoline Other notable areas not explored here are the consumption in mobility can be reduced by use of green hydrogen in the semiconductor using green hydrogen. Although the economics industry as a heat transfer fluid (when kept in a at this time appear challenging, the segment may vacuum) and as rocket propellant for the aero- be driven by policy if it is accepted that the use space industry. 28 Converting 320 normal cubic meters per hour at 0.08988 kg per 1 normal cubic meter per hour, using http://www.uigi.com/h2_conv.html with source data from Fraile and others 2015, 16. 29 Converting 44 normal cubic meters per hour at 0.08988 kg per 1 normal cubic meter per hour, using http://www.uigi.com/h2_conv.html with source data from Fraile and others 2015, 16. 6: Industrial Applications 79 FIGURE 6.4 Sunfire synthetic green fuels from hydrogen in Germany © Sunfire GmbH, Dresden/Rene Deutscher, 2019. Note: Units in the photo are marked raw naphtha, raw diesel, and raw wax. 6.5. OTHER HYDROGEN FUELS hydrogen. Nonetheless, the fuel is a very light liquid and can be easily stored and carried. Although hydrogen itself is a valuable and Further, it is readily available across both emerg- effective fuel, several alternative fuels can also ing and developed markets, making it attractive be created from green hydrogen. These fuels for locations where hydrogen infrastructure have differing properties from hydrogen that and safety capabilities are low. Today, metha- can sometimes be more attractive than pure nol is largely created via natural gas and is the hydrogen for specific use cases and applica- result of a two-stage process that requires both tions. Examples commonly include methanol, the production of hydrogen and its subsequent ammonia, and, increasingly, synthetic methane, bonding with carbon inside a new molecular all of which are considerably easier to store and structure. The average plant capacity is around transport than hydrogen but come with higher 5,000 tonnes per day with a yearly hydrogen efficiency losses in generation (figure 6.4). consumption of 266,104 tonnes. Key industrial players include Methanex and Sabic (Fraile and 6.5.1. Methanol others 2015). By some estimates, methanol production ac- counts for around 10 percent of global hydrogen 6.5.2. Synthetic Methane demand. Although it is used in a wide array of One of the largest areas of interest, particularly applications, methanol is particularly useful for for European companies and policy makers who fuel cell units that provide uninterruptible power are exploring green hydrogen applications, is the supply services, especially in off-grid areas. One ability to synthesize hydrogen with carbon to cre- liter of methanol is approximately 4.8 kWh, ate methane. Creation of synthetic methane can or 1 kg is about 5.6 kWh. This is a significant be enormously appealing because it allows for the reduction from the 33.33 kWh held in a kg of continued use of current natural gas infrastructure 80 GREEN HYDROGEN IN DEVELOPING COUNTRIES and avoids the need to replace or retire existing combine solar PV with a 13 MW alkaline natural gas assets. Synthetic methane also has the electrolyzer. The project will produce and store added advantage of being easier to generate at synthetic methane in an underground cavern and larger scales and across a wider range of locations will then release the methane directly to custom- than biogas, which has long been seen as a means ers as needed (McPhy 2017). Two other flag- of “greening” the gas supply. ships are in Germany and France. This includes Uniper’s “STORE&GO” project in Germany, Only a few pilot projects are currently gener- which uses wind power and electrolysis to ating synthetic methane. Most of them extract produce up to 1,400 cubic meters of synthetic their carbon from anaerobic digesters linked to methane a day, or approximately 14,500 kWh of agricultural waste or landfill waste. But a pilot energy (Eckert 2019). In France, the Jupiter 1000 in Italy sources its carbon from direct air capture program aims to use a hybrid of alkaline and technology, and both options can be considered PEM electrolysis, with carbon capture storage, to carbon neutral. create and distribute synthetic methane (Jupiter The largest approved project is the Underground 1000 n.d.). Sun Conversion project in Austria, which will 6: Industrial Applications 81 © ENAPTOR 7: IMPLEMENTATION CHALLENGES KEY TAKEAWAYS nn Hydrogen is a well-established industrial gas, but leveraging the full potential of green hydrogen in devel- oping countries requires building local capacity and increasing access to expertise that, at the global level, remains limited. nn Safety is paramount for all green hydrogen applications: although hydrogen has been safely produced, stored, handled and used for decades, it is a gas with unique properties and specific safety considerations. nn Hydrogen-derived fuels like ammonia and methanol can be easier to transport and store than hydrogen but pose additional safety and environmental considerations that should be clearly understood and factored in when designing projects. nn Costs of transporting small volumes of hydrogen can potentially double or triple the end-user cost of hydro- gen. Demand aggregators that exploit economies of scale and distributed production closer to demand locations could in many instances reduce transportation cost. nn Green hydrogen storage will likely remain focused on gaseous storage—either pressurized, pipeline or gas cavern—unless significant breakthroughs reduce the cost and increase the efficiency of alternative storage methods. nn Use of liquid organic hydrogen carriers (LOHCs) is a promising storage method to meet larger-scale hydro- gen transportation needs, such as those from international hydrogen transport; and solid state hydrogen (hydrides) could offer interesting solutions for urban areas and for mobility applications. nn High-purity water is an impotant input for green hydrogen production, and access to it might pose a barrier in many countries. 7: Implementation Challenges 83 7.1. IMPLEMENTATION CAPACITY value chain. Applications using green hydrogen AND INFRASTRUCTURE as an energy storage medium require different REQUIREMENTS technologies and systems to work in tandem to procure, store, and deliver the hydrogen to One of the most important factors in determining an end solution. It is thus essential that project a country’s existing capacity to implement green sponsors work with companies that are able to hydrogen solutions is its access to individuals with integrate all the different system components, the technical knowledge and expertise to handle, while also accepting the engineering liability install, and maintain hydrogen and hydrogen risk if the system they have designed does not systems. Given the widespread use of hydrogen perform. as an industrial gas, some countries already have the technical capacity to implement and operate For standalone electrolysis plants or fuel cell ap- hydrogen projects. This is the case particularly plications, most of these systems integration30 is- in countries, such as Argentina, Indonesia, or sues can be addressed by the equipment supplier Malaysia, that also possess natural gas resources. and rarely appear to pose significant challenges Yet, the availability of individuals with the techni- for end customers. However, multisectoral ap- cal skills needed to assemble, install, and main- plications and country strategies involving large tain hydrogen-associated equipment is usually projects need to carefully plan how all the differ- confined to a few large companies that consume ent systems will be working together. Examples large volumes of hydrogen and are less common might include systems in which electrolyzers are in regions that are looking to deploy smaller and combined with a renewable power resource or more remote hydrogen solutions. a combination of battery, fuel cell, or hydrogen refueling infrastructure for mobility applications. Moreover, while there are standards, procedures, Others include the retrofit or development of and regulations already in place that govern the hybrid fuel cell and battery solutions for buses, production, storage, and transportation of hy- trucks, or large industrial needs. It could also drogen in many developing countries, these are include incorporating hydrogen into existing much less common for smaller-scale (decentral- internal combustion engine vehicles to provide ized) solutions and for fuel cells. The difference a hybrid solution with a lower vehicle emission is that hydrogen is already an industrial market, profile. with significant scale and several decades of development, that has created a pool of skilled Systems integration is therefore important be- workers and training resources, whereas the cause although the individual components may commercial fuel cell market is only now begin- work well individually, some configurations may ning to emerge, and green hydrogen production not be appropriate, and the trade-offs between is scaling from a small base. cost, sizing of different equipment, and system availability are complex and need to be better understood. For example, incorrectly sizing 7.1.1. Systems integration the compressor with the electrolyzer and using The most significant technical challenge facing the wrong piping to connect the compressor, the implementation of green hydrogen-based storage vessel, and fuel cell nozzles could create solutions is the integration of the hydrogen leakages and reduce the efficiency of the over- system with other systems that are part of the all system. Similarly, in the Clean Hydrogen in 30 Systems integration here refers to the development of energy solutions that use a range of individual technologies that may not have been initially designed to work in tandem but that have been adapted to meet a specific need. 84 GREEN HYDROGEN IN DEVELOPING COUNTRIES Hydrogen compressors for refueling in China: Compressor for Zhangjiekhou bus station FIGURE 7.1 (left) and compressor for Zongshan Dayang hydrogen bus refueling station (right) © PDC Machines. European Cities final summary report (Müller the method and equipment the project uses to and others 2017, 29), the authors noted that pressurize hydrogen. The most common storage “compressors are the single biggest cause of sta- solution is to pressurize at least part of the hydro- tion failure,” with several causes listed, including gen between 200 and 1,000 bar, so the original compressor head cracks, membrane failures, and pressure at which hydrogen is released from the connection leaks. electrolyzer is too low for immediate use and thus requires additional compression. Typically, A common issue with stationary applications is the need to produce, store, and release green electrolyzers produce hydrogen at between 1 hydrogen within a system. Typically, hybrid sys- and 2 bar, but some systems produce at up to 35 tems store hydrogen generated on-site for later bar or higher, which can significantly reduce the use. This approach requires the hydrogen to be cost of the compression process but will affect released from the electrolyzer and then either the overall system capex. pressurized or liquefied for storage. At all points The four main types of compression technolo- in the process, the failure of a compressor, poor gies then used are piston, hydraulic, diaphragm, welding or configuration of the hydrogen piping, and electromagnetic, with piston being the and lack of access to on-site basic spares—not most common solution (figure 7.1). Most system to mention, a lack of local engineers—all could integrators choose piston compressors because create significant risks for the successful imple- of their low cost. Yet, this comes with a trade-off mentation and operation of a hybrid hydrogen because these units frequently have a lifetime of system. under 1,000 hours, because the seals are quickly For both mobility and some stationary appli- worn out and will need replacing, which can cations, early findings from projects suggest significantly reduce the availability of the unit. that the single largest factor that affects the This situation is especially true when the loca- operational availability of a hybrid system is tion is remote and an engineer needs to travel 7: Implementation Challenges 85 from outside the immediate vicinity to replace acute in developing countries and it is an area the seal. The design problem is that diaphragm that will require further investment to ensure the compressors, which have much better lifetimes successful uptake of these solutions. (over 5,000 hours), are more expensive and add to the initial project capex. Hydraulic compres- 7.1.2. Safety considerations sors represent a hybrid option, while electromag- netic compressors are in their early deployment As with any other flammable fuels, safety is of phase. Accordingly, some hybrid systems today paramount importance for all hydrogen appli- have experienced lower availability than antici- cations. Yet, hydrogen has unique properties pated as a result of maintenance issues related to that require special treatment compared with compression. conventional fuels used for energy purposes. The first is that hydrogen is colorless and odorless. It Creating new fuel cell mobility applications burns with an invisible flame that releases little powered by green hydrogen is extremely chal- heat, and it can be challenging to handle for lenging in part because most manufacturers first responders who have not received adequate offer only a one-year warranty as standard and training. Hydrogen has a very wide flammability in general cannot offer long-term warranties at range, and the energy required to start a hydro- commercial rates, combined with the issue that gen/air explosion is considered low. It has also most manufacturers are unable to offer lease been noted that even small sparks produced from financing solutions. It is thus important to note dropping a plastic-based pen would be sufficient that, excluding Nikola’s trucks, Symbio’s Renault to ignite hydrogen-air mixtures (Ajayi-Oyakhire Kangoo retrofits, and Arcola/Wrightbus’s FCEBs 2012). Hydrogen also burns around eight times in Liverpool, almost all mobility applications faster than natural gas, making it extremely today are provided by major corporations that difficult to contain especially in closed environ- absorb risks on their balance sheets. ments.31 In its pure form, it burns no carbon and Understanding the needs of customers, the produces no hot ash and very little radiant heat, cost considerations required to make a project while burning fossil fuel produces hot ash, creat- bankable, the ways that warranties of different ing radiant heat (Hydrogen Europe n.d.). components can be integrated to guarantee the As a result of these special properties and unique adequate operation of new systems, and the safety considerations, hydrogen safety remains level of resiliency required to meet regulatory a concern, as indicated by a survey conducted requirements are essential skills that quali- by the World Economic Council in 2019. In fied systems integrators can bring to projects. this survey only 49.5 percent of respondents However, even in developed markets, very few considered hydrogen and its potential use as an system integrators possess an established track energy source to be “safe,” and 31.4 percent record in deploying these types of hybrid green still considered hydrogen to be either danger- hydrogen production and fuel cell technologies, ous/unsafe or extremely dangerous/very unsafe and most manufacturers now provide system (WEF Netherlands 2019). This perception of integration services to customers as a means to hydrogen as a dangerous technology is often address this shortage. This scarcity may be more exemplified by the Hindenburg disaster in 1937 31 Alternatively, this attribute can often enhance safety, because a rapid deflagration means that less heat is conveyed to surrounding areas than with other gaseous fuels. In a famous test when a conventional internal combustion engine car with gasoline was punctured with a 16 milimeter hole and an internal combustion engine car with hydrogen was also punctured, the gasoline car suffered severe damage while the hydrogen car was largely unphased (Ajayi-Oyakhire 2012). 86 GREEN HYDROGEN IN DEVELOPING COUNTRIES and the explosion of the Challenger spacecraft The principle is similar for hydrogen electrolyz- in 1986.32 Despite these two famous accidents, ers. Infrared cameras combined with warning the safety risks associated with hydrogen are well alarms are essential to notify those in the sur- known and well understood. Hydrogen has been rounding area that a leak has been detected. The effectively regulated by national and interna- electrolyzer units are installed on nonstatic con- tional standards for over 50 years, and there crete and have ventilation lines that head straight are established safety measures, protocols, and above the assets (figure 7.3). guidelines that can be implemented to address For mobility applications, the question is these aspects.33 whether hydrogen is stored in a pressurized unit, The most significant safety considerations for in a cryogenic form, or in a hybrid of both. Most hydrogen revolve around how the molecule tanks are covered with carbon fiber to increase is stored, how gas leaks are monitored, and the protection of hydrogen canisters against how venting is conducted when a leak occurs. crashes. In 2018, for example, the Hyundai Because hydrogen has a very high diffusion Nexo secured a maximum five-star Euro New coefficient, considered to be roughly four times Car Assessment Programme safety rating for its that of methane, a common safety procedure is fuel cell vehicle (Attwood 2018). Even in ex- to vent hydrogen. Venting is a safe and practi- treme puncture events such as bullets piercing cal safety measure because when hydrogen is the tanks, evidence from the Toyota Mirai bullet released into the atmosphere, it quickly rises and tests shows that passengers remain safe.35 The dissipates. Thus, the primary safety mechanism critical issue comes when hydrogen storage units for the majority of hydrogen units is to “vent” are exposed to fires from an external source. in the case of a major breach incident. The fact For hydrogen stored in very-high-pressure tanks, that hydrogen is not hazardous, nor radioac- the biggest concern is that the external tem- tive, corrosive, carcinogenic, or self-igniting, perature rises and causes hydrogen to expand. These issues have been known and addressed further supports that venting is a sensible and by the industry in a myriad of ways since 2006. environmentally friendly safety procedure. For For example, in a study by BMW on its BMW 7 on-site hydrogen storage, it is standard practice hydrogen model: to store the hydrogen outside, with minimal amounts kept indoors. The hydrogen storage tanks filled with hydrogen were fully en- tanks themselves should be placed on nonstatic compassed by flames at a temperature of concrete and combined with fire walls, vent more than 1,000 °C (1,830 °F) for up to 70 stacks, sensors, pressure-relieving devices, and minutes. Even under such conditions, tank clear labeling of equipment (tanks) and electrical behavior did not present any problems, with devices for engineers (figure 7.2).34 the hydrogen in the tanks escaping slowly 32 In the case of the Hindenburg, the German Hydrogen and Fuel Cell Association has argued that the extremely flammable paint on the blimp was the key challenge, burning in 90 seconds and triggering the catastrophe. Meanwhile, for the Challenger aircraft, it has been argued that a defective seal in the auxiliary boosters was the cause of the flame damaging the fuel tanks, an issue that is not unique to hydrogen (Ajayi-Oyakhire 2012). 33 The primary international ISO is TC197, which comprises the technical committee that develops standards on hydrogen vehicles, fuel deliv- ery, storage, measurement, and use of hydrogen (IEA 2017). There are also multiple national regulations that govern safety procedures and operations with hydrogen. 34 Feedback from asset operators, system integrators, and suppliers. 35 Toyota, 2016 YouTube demonstration, https://www.youtube.com/watch?v=jVeagFmmwA0. 7: Implementation Challenges 87 Safety measures installed for hydrogen leak detection, protection, and mitigation: FIGURE 7.2 Kirkwall Harbour Hydrogen tanks venting line (left), Kirkwall Harbour PEM fuel cell gas leakage monitoring sensor (center), and Shapinsey School pressurized hydrogen canisters stored in blast wall–covered area, outdoors with an infrared camera (right) © Kirkwall Harbour. Warning system configuration for PEM electrolyzer at Shapinsey: PEM electrolysis FIGURE 7.3 unit infrared camera and warning alarms, Shapinsey, Orkney Islands, United Kingdom (left) and Shapinsey PEM electrolyzers on nonstatic concrete and with hydrogen ventilation shafts (right) Source: ESMAP. 88 GREEN HYDROGEN IN DEVELOPING COUNTRIES Shapinsey ferry hydrogen trailers and safety measures at sea: Orkney island hydro- FIGURE 7.4 gen trailer (left); Orkney ferry to Shapinsey, United Kingdom (top right); and firehouse for hydrogen trailer (bottom right) Source: ESMAP. and almost imperceptibly through the safety hour to keep the pressurized containers cool and valves. Following these most demanding to eliminate the need for venting (figure 7.4). tests and examinations, both TÜV South Germany and the fire brigade specialists 7.1.3. Infrastructure considerations acting as consultants arrived at the conclu- sion that the hydrogen car is at least as safe Whether used in a small distributed application, or as a part of a large industrial scale system, as a conventional gasoline car. (BMW 2006, green hydrogen has a number of essential infra- 15–16.) structure implications that must be considered For larger mobility applications such as ships, and assessed at the very early stages of project trucks, and trains, safety procedures can be design. These include avoiding physical dam- more complex. The current understanding is that age to the equipment in place, assessing the hydrogen will continue to vent where possible impact on existing transportation and electricity during a fire safety event, with cryogenic hydro- networks, considering the potential of repurpos- gen warmed by the ambient air temperature and ing some of the existing infrastructure to avoid vented. In confined spaces, an alternative solu- generating stranded assets, and complying with tion is to use existing firefighting systems to keep the maintenance requirements of the hydrogen storage units cool. For example, for transit by equipment. ferry of a custom-built hydrogen trailer carrying Ensuring the availability and use of appropriate 250 kg of hydrogen in the Orkneys (UK), the unit equipment to handle hydrogen is key. Hydrogen is connected to the ferry sprinkler system. This can embrittle metals, and its buoyancy and unit can release up to 2,400 liters of water an molecular size require careful attention to 7: Implementation Challenges 89 potential leakages, including the deployment of existing asset owners. For example, most pipe- the necessary systems to monitor and respond line infrastructure today cannot support 100 to potential leaks. Incorrect use of compression percent hydrogen without risk of leakages and technologies (typically in situations where natu- embrittlement. Similarly, natural gas storage ral gas assets are simply repurposed with little to tanks in their current state are not appropriate for no modifications) can also provoke the degrada- storing pure hydrogen. However, green hydrogen tion of materials, potentially leading to reduced can be blended into existing gas grids without efficiencies and safety issues. Another key aspect further changes to existing assets, with several to consider is the correct assembly of hydrogen EU studies suggesting blends of up to 20 percent units, particularly the connections between pres- hydrogen are acceptable. Green hydrogen also surized storage tanks used for hydrogen refueling can be blended into natural gas caverns. But the systems and the refueling nozzles. most significant potential for repurposing oil and gas assets may come from the successful devel- Given the benefits of colocating electrolyzers opment and rollout of liquid organic hydrogen next to renewable energy plants, it is essential to carriers (section 7.3.2). LOHCs can be stored consider how the water required in the electrol- in existing oil facilities, bunkers, pipelines, and ysis and the green hydrogen produced will be tanks. They can hold green hydrogen for months transported to and from the production site if (or years) and do not require high pressure or the hydrogen is not to be consumed on-site. In low temperatures to keep hydrogen stable. In this remote areas with low activity, a large green-hy- way, LOHCs could provide a crucial lifeline for drogen project may lead to increased road traffic developing countries that intend to decarbonize and noise, as well as increased congestion and their energy consumption and whose primary roadwork in the local road system that might ul- energy infrastructure is not the power grid, but timately require upgrades to the local infrastruc- rather fuels. ture. These upgrades could be justified if there is a clear local benefit, such as the prospect of Box 7.1 examines operations and maintenance local job creation, energy security and resiliency, challenges that developing countries may and additional revenue for local businesses and encounter. municipalities. These aspects must be addressed at an early stage to avoid unnecessary costs and delays as the project develops. It is also import- 7.2. GETTING THE RIGHT INPUTS ant to anticipate what impact a large green-hy- drogen production facility may have on the local 7.2.1. Hydrogen purity grid and on the existing water infrastructure, Not all hydrogen is created equal. The purity especially if further enhancements or upgrades of hydrogen is very important for a number are required, and who should cover these costs. of applications, especially for fuel cells, and Last, as the world transitions toward a zero-emis- failure to ensure that the correct hydrogen purity sion energy system, a significant consideration is used can have negative consequences. The will be the treatment of existing oil and natural most sensitive issue is the use of hydrogen that gas assets that may become stranded. Green is not of a high enough purity grade in PEM fuel hydrogen in this regard can help mitigate some cells. This can severely damage the stacks and of the risk associated with stranded assets, by shorten equipment life, as well as reduce system using some transportation and storage assets efficiency. In the European Union, the transport developed for the oil and gas sector. This does sector purity quality standards are specified in not mean that hydrogen is a silver bullet for ISO 14687, with a level of 99.995 percent purity 90 GREEN HYDROGEN IN DEVELOPING COUNTRIES BOX 7.1 OPERATIONS AND MAINTENANCE CHALLENGES FOR GREEN HYDROGEN IN DEVELOPING COUNTRIES Unlike thermal generators, green hydrogen production and fuel cell systems have relatively few constantly moving parts that are subject to wear and tear. Those few moving parts, however, are sensitive components of the system and could provoke system failure if not operated and main- tained correctly. Fans that drive the movement of gases, compressor valves, and components as- sociated with the movement of water in the asset are among the most sensitive components and, while not necessarily expensive to replace, they can be highly disruptive where local capacity does not exist. Many companies have partially mitigated this exposure by developing modular systems, such that a fault in one unit does not incapacitate the entire system. This can be useful where larger multistacked systems are deployed, but this is less common for remote or distributed systems that are likely smaller and harder for technicians to access. Another challenging issue is handling hydrogen fuels. Although hydrogen canisters are widely available in developed countries and considered safe to use, in remote areas of developing countries there is a greater likelihood that hydrogen fuels like ammonia or methanol will be used. The virtue of not using hydrogen is the fact that methanol and ammonia are less likely to escape containment. The tradeoff, however, is that these fuels are more hazardous to handle—notably ammonia, which is toxic and can be extremely problematic if leaked. A major ammonia leak would require coordination between local emergency services to ensure that as the ammonia is vaporized, members of the public are not exposed to the fumes and those who are can be treated carefully (Maryland Department of Agriculture n.d.). needed (Fraile and others 2015). This quality can be purified to achieve up to 99.999 percent requirement is higher than in the United States, purity requirements, either with modification where companies will provide hydrogen for made to the electrolyzer unit (if alkaline) or fuel cells at more than 99.97 percent (United through a clean-up process after the hydrogen Hydrogen n.d.). has been produced. Typically, industrial grade hydrogen is the least sensitive with respect to purity and is supplied at 7.2.2. Water 99.95 percent in both the European Union and All fuel cells require some water to achieve the the United States. But ultra-pure applications humidity inside the stacks to optimize their oper- (such as PEM fuel cells) require hydrogen purities ations, while electrolyzers require water as their of greater than 99.999 percent (table 7.1). primary feedstock. Access to water is therefore a It is important to note that different hydrogen commonly cited concern by some analysts who production technologies deliver different purities are evaluating the viability of hydrogen applica- of hydrogen. Typically, a standard PEM electro- tions. However, discussions with fuel cell and lyzer will deliver the highest hydrogen purity, fol- electrolyzer suppliers and project developers lowed by alkaline electrolysis and then SMR. For suggest that the volume of water required for a standard alkaline electrolyzer, 99.95 percent operations is in general less of a concern than purity from production is reasonable, while SMR typically assumed. Instead, water quality is a can be as low as 95.00 percent. Still, hydrogen greater issue than is often understood. 7: Implementation Challenges 91 TABLE 7.1 Hydrogen purity requirements TYPE OF HYDROGEN TYPICAL USES HYDROGEN PURITY NEEDED (%) Gaseous General and industrial 99.950 Gaseous Hydrogenation and water chemistry 99.990 Gaseous Instrumentation and propellant 99.995 Gaseous Semiconductor and specialty applications 99.999 Liquid Standard industrial, fuel and standard propellant 99.995 Liquid High purity: industrial, fuel and propellant 99.999 Liquid Semiconductor 99.9997 Source: Fraile and others 2015. The electrolysis process requires 9 liters of water required is comparable to producing hydrogen to generate 1 kg of hydrogen. However, if the from coal gasification. water is straight from the public water system, it For fuel cells the picture is more complex. must be deionized first. This means that actual Because many fuel cells run on natural gas or water demands can be between 15 and 30 liters methanol (often mixed with water), their actual to filter 9 liters of deionized water for electroly- water consumption is extremely low. Indeed, sis. The remaining water can then be consumed several suppliers claim that their units may or used as needed, but it cannot be used by require only a few liters per 100 kW every year. the electrolyzer. Accordingly, there is a signifi- Other technologies such as PAFC require around cant difference between actual water demand 2,000 gallons a year for a 460 kW unit, with for electrolysis and actual water consumption. water use peaking at a gallon or two per hour Given that the water is reusable after purifica- during a 40°C day. Even assuming 2,000 gallons tion, the more reasonable assessment of water a year, a 460 kW fuel cell unit with 98 percent needs is water consumed; on that basis, hydro- availability will consume only 4.8 liters per gen electrolysis has a fairly reasonable water megawatt-hour (MWh) generated.36 On a pure water demand basis, fuel cells therefore require demand profile relative to many alternative fuels. less water for water withdrawal than all other By means of comparison, hydrogen produced via forms of thermal power. On a consumption basis SMR requires 4.5 liters of water per kg of hydro- only, fuel cells require much less water than gen and coal gasification requires 9 liters of wa- natural gas steam turbines or CCGT units, which ter per kg (Bruce and others 2018). This does not consume between 757 and 1,461 liters per MWh include the water actually required to extract the and 150 to 400 liters per MWh, respectively coal or gas, but it does reflect the water demands (Union of Concerned Scientists 2013). Even for for hydrogen production technologies on-site. fuel cells consuming green hydrogen, the life-cy- Thus, electrolysis production may require more cle water demands are between 545 liters per water in its pure production than SMR does, MWh and 725 liters per MWh, depending on depending on country context, but the amount system efficiencies.37 An average nuclear plant 36 Assumes a 460 kW PAFC running at 98 percent availability and 48 percent electrical efficiency and consuming 2,000 gallons a year (converted to liters at a ratio of 1 gallon = 4.54609 liters). 37 Assumes 33.33 kWh per kg of hydrogen, requiring about 30 kg to reach 1 megawatt-hour, electric storage. At an electrical efficiency of 92 GREEN HYDROGEN IN DEVELOPING COUNTRIES consumes 700–1,200 liters per MWh (Union of the main constraints for broad-based applica- Concerned Scientists 2013). tions. These constraints are fundamentally rooted in hydrogen’s low energy density at atmospheric In general, water quality is an underappreciated pressure, the efficiency losses associated with concern. PEM technologies remain the most sensi- hydrogen pressurization and liquefaction, and tive to water quality issues, and PEM electrolyzers the special conditions required to ensure that require deionized water that is usually processed hydrogen transportation and storage are safe. through an additional built-in water-purification unit inside the electrolyzer.38 For alkaline electro- lyzers, water quality is also an issue, with certain 7.3.1. Transport suppliers setting a clean water target of conduc- There are four modes of transport and four stor- tivity lower than 20 microsiemens per centimeter. age mediums to transport hydrogen. Depending Most electrolyzer units include an option to add on the specific market, hydrogen modes of water purifiers to their solutions. These are a rela- transport today can include roads, rail, shipping, tively low additional capex cost, and most manu- or pipeline. The storage mediums for transport facturers claim that water purity issues are address- include compressed hydrogen, liquid hydro- able, providing the source of water is not heavily gen, converted hydrogen (either to ammonia or contaminated. Typically, most electrolyzer units methanol), or absorbed hydrogen (hydrides and have no problems accepting water from a public LOHCs). supply and then purifying it through the unit. The most common method of transport is for hy- For fuel cells, although PEM units remain sensi- drogen to be pressurized between 200 and 500 tive, other technologies such as SOFC, PAFC, and bar and moved via road (figure 7.5). Australia’s MCFC are less sensitive to water and can add re- CSIRO suggests that for journeys under 1,000 verse osmosis purifiers if needed. Most manufac- km or where demand is below 1.5 tonnes of turers of these technologies report that they have hydrogen, pressurized hydrogen is most suitable not faced noticeable water challenges in their op- (Bruce and others 2018), with cryogenic (liquid) erations thus far. Similar to electrolyzer units, most hydrogen preferred for larger volumes and longer units will access water through a public source, distances.39 Hydrogen transit is less common though water can also be added externally where by rail except when converted into ammonia. there is no access to a public water source. Hydrogen pipelines today can usually be found only in markets with established petrochemi- cal infrastructure, such as China, Japan, Korea, 7.3. TRANSPORT AND STORAGE and the United States, certain Gulf states, and One of the main strengths of liquid fossil fuels Europe. Even in these markets, infrastructure is that they can be relatively easily transported remains limited. The longest hydrogen pipeline and stored. Conversely, transporting and storing in Europe, which lies between Belgium and hydrogen has been for several decades one of France, is only 400 km, while in 2011 the United 50 percent, this doubles to 60 kg, requiring between 10 and 12 liters per kg. Using an electrical efficiency of 60 percent for the fuel cell reduces demand to 54 kg. 38 One supplier, Peak Scientific, requires less than 1 microsiemens per centimeter or more than 1 megaohm-centimeter for their water purity. 39 Several reasons for this preference include convenience, ease of access to suppliers, and the fact that costs and risks are already known and regulations have already been drafted. Further, it is typically the case that at shorter distances, a lower amount of hydrogen will be needed (because for larger amounts, a company would typically consider building generation on-site). Thus pressured containers are a more logical choice. 7: Implementation Challenges 93 FIGURE 7.5 Pressurized hydrogen storage trailers © Hexagon. Kingdom had only 25 km of hydrogen pipeline heat at their point of use. There are two current (Ajayi-Oyakhire 2012, 19). Ammonia shipping commercial pilots using these solutions, one in is common and has been established for many Japan and one in Tennessee, United States. Other years. Companies have also begun to explore the areas actively exploring the technology include technical and commercial viability of liquefied Botswana (H2-Industries 2018) and Germany. hydrogen shipping, with Kawasaki committed to In Germany there are several pilot sites in developing at least one vessel for this purpose operation, but most appear to be for research (Crolius 2017). purposes. Transporting hydrogen is expensive. Using a See table 7.2 for an overview. Hinicio 2016 analysis, IRENA estimated that hydrogen compression, logistics, and distribution 7.3.2. Storage could add $6–$10 per kg for a hydrogen refuel- ing station unit (IRENA 2018, 28). Hydrogen can be stored in pressurized, liquid, converted, or absorbed mediums. Most large One of the most anticipated innovations in industrial users consume hydrogen as it is pro- hydrogen transportation lies in the ability to duced, with SMR or gasification often colocated transport hydrogen by absorbing it into either a near the demand source, and most significant metallic composition (called a hydride) or into storage capacity is for either wholesale distribu- a liquid composition (liquid organic hydrogen tion or smaller on-site generation. carriers). Of the two, LOHCs are showing the greatest progress toward commercializing their By far, the most common storage method for solution. LOHCs are usually heat transfer fluids, distributed hydrogen is pressurized containment. such as toluene or dibenzyltoluene, which ab- This process includes a series of tanks that are sorb hydrogen in a process that creates heat en- usually linked together to release pressure si- ergy and then release hydrogen when exposed to multaneously as needed. For hydrogen refueling 94 GREEN HYDROGEN IN DEVELOPING COUNTRIES TABLE 7.2 Overview of hydrogen transportation methods ENERGY REQUIRED VOLUME OF TRANSPORT CAPEX (KWH PER KG HYDROGEN PER (US$),TRACTOR AND HYDROGEN, EXCL. BOIL OFF TECHNOLOGY TRUCK TRAILER TRANSPORT) (%) LOHC–Hydrogenious LOHC Up to 1,800 kg 180,000 1.5–10.0 0 Technologies Compressed gas hydrogen Up to 350 kg >440,000 1.5–2.0 0 (@250 bar) Compressed gas hydrogen Up to 1,100 kg 1.0 million–1.2 million 4.0–5.0 0 (@500 bar) Liquid hydrogen (@ −250°C) Up to 3,300 kg 750,000–1.7 million 10.0 1–3 per day Pipeline Size dependent Initial Investment: n/a 0 300,000–1.2 million per km (rural) and 700,000– 1.3 million (urban) Source: IEA 2015; ESMAP discussions with Hydrogenious LOHC Technologies; and market feedback. Note: capex = capital expenditure; LOHC = liquid organic hydrogen carrier. n/a = not applicable. systems, a hybrid of containerized and liquid hy- safety considerations for stationary use cases as drogen is also attractive. In these configurations, well as for mobility, especially in built-up areas. the majority of hydrogen is held in a liquefied A recent example of the interest in solid-state tank that may be pressurized up to 30 bar. This hydrogen has been the announcement that SP is then converted from its liquid to gaseous form Group will use solar PV, electrolysis, and sol- using ambient heat from the surrounding area. id-state hydrogen storage for its training center in (Hydrogen needs to be below −423.17°F to Woodleigh Park, Singapore (Mohan 2019). stay fully liquid.) The hydrogen is then fed into a compressor to bring the pressure up to the Conversely, it appears that LOHCs are starting requirement for nearby compressed storage tanks to move toward commercialization and greater that usually distribute the hydrogen. Smaller sites competition, with several leading LOHC providers may avoid this process by simply using pressur- already offering commercial solutions, including ized hydrogen only, especially where on-site Chiyoda, Hydrogenious LOHC Technologies, compression would add significant costs. Covalion, and H2-Industries (figure 7.6). Very few providers of hydride storage exist—only For mobility applications, the most common Ardica, Hydrogen in Motion, and H2GOPower. method today is to pressurize hydrogen into But most have not deployed a large-scale pilot, carbon fiber tanks, in contrast to early hydrogen let alone a commercial project to date, and all cars, such as the BMW 7, that used cryogenic three companies have largely focused on storage hydrogen storage. Nonetheless, cryogenic hydro- applications for either the military, unmanned gen storage is now being reviewed for ferries,40 autonomous vehicles, or both. Nevertheless, in ships, and trucks.41 There are two advantages the long run the ability to store hydrogen in a to cryogenic hydrogen for mobility platforms solid state could be transformative to addressing that require significant amounts of storage. The 40 Discussions with Orkney Islands Council Marine Services, part of the HySeas III hydrogen ferry delivery team, April 2019. 41 Correspondence with system integrators suggests that this may be optimal given refueling time priorities, April 2019. 7: Implementation Challenges 95 FIGURE 7.6 Liquid organic hydrogen carrier solution in operation, Tennessee, United States © Hydrogenious LOHC Technologies. first is that cryogenic hydrogen is considerably refueling time of hydrogen low, some engineers more energy dense than pressurized hydrogen, have suggested that cryogenic hydrogen would which saves space (and weight) on the platform. be faster than pressurized hydrogen because it The second is refueling time. To meet safety would avoid the temperature constraint that is standards, the flow rate of hydrogen refueling created by trying to push hydrogen into a fixed is set by temperature bands, with 80oC being space (a process that generates heat). the upper safety limit, although most refueling Another area of research in hydrogen storage is stations aim to keep the temperature around the around the use of ammonia as an energy storage refueling nozzle to 50oC or lower. To keep the method. Although this process leads to higher 96 GREEN HYDROGEN IN DEVELOPING COUNTRIES efficiency losses, ammonia is considerably easier exist in the United Kingdom and United States, to transport and store, making it a compelling with a number of projects now examining the proposition in an environment where the cost use of salt caverns to store hydrogen in and of diesel and other forms of stored energy may around the North Sea. In some developing be comparatively expensive. The first pilot of countries this may be an existing opportunity for this approach began in 2018 in Oxford, where large-scale and low-cost green-hydrogen storage, Siemens, the Science and Technology Facilities particularly where existing oil and gas fields Council (STFC), the University of Cardiff, and exist. Despite this potential, there is extremely the University of Oxford have developed a limited public research available to date on the demonstrator that creates green hydrogen from availability, technical challenges, and cost con- electrolysis in an on-site 12kW wind turbine and siderations of hydrogen caverns for green-hydro- then combines it with oxygen to make ammonia gen storage in developing countries. (STFC. 2018). In some environments, this could become a compelling solution for off-grid renew- ables seeking an easy-to-store and easy-to-trans- port fuel, with no carbon emissions. The largest storage application being considered is the use of hydrogen caverns. These already 7: Implementation Challenges 97 © PDC MACHINE 8: AREAS FOR FURTHER RESEARCH This report has sought to illustrate current and data on current hydrogen production in different potential areas of deployment for green hydro- countries and because of the uncertainty around gen production and fuel cell technologies in whether the green hydrogen market will become developing countries. While the current focus in export driven like the global oil market is today developing countries appears to be split between or whether it will be more like natural gas, in hydrogen applications for mobility, ammonia which some international trade occurs but largely and methanol from remote power fuel cell markets are regional not global. Further research systems, and some industrial uses, this scope and analysis of the drivers that would encourage will evolve as hydrogen technologies decline in domestic production versus imports of green cost and their complexity is better understood. hydrogen will be needed and could perhaps build Hydrogen is not and will not become a silver on methodologies already adopted for assessing bullet for all energy challenges in develop- the scale of hydrogen and its sources for devel- ing countries. But what green hydrogen could oped countries. provide is another powerful technological lever It is also important to consider further research that policy makers and investors could use to that can help quantify nonmonetized benefits develop clean solutions that are tailored to the that green hydrogen can provide for developing energy context and to the unique challenges that countries. These include the ability to switch to a the country is seeking to address. fuel with a wide diversity of potential suppliers, For developing countries to be able to fully ben- thus reducing the risk of concentrated energy efit from the investment opportunities that could supply among a few entities. Further, it could be brought by green hydrogen, it will be increas- allow small-island developing nations to obtain a ingly important for organizations to work with versatile, easy to store, and green energy source investors and governments on developing national for their energy needs without inhibiting eco- roadmaps to highlight areas of national focus nomic growth. The World Bank through ESMAP is supporting developing countries in factoring and to assess the applications in which green in these and other considerations in the develop- hydrogen can deliver gains. These roadmaps will ment of national strategies that explore the role need to establish how hydrogen can be sourced that green hydrogen could play in decarbonizing in a climate-sustainable manner, leveraging local economic activities and pathways to leverage its renewable resources whenever available. At the full benefits. broader level, an area of work that has not been addressed in this report is a more in-depth assess- This report also focused on hydrogen produced ment of how large the potential green hydrogen via electrolysis using variable renewable en- market might be in developing countries. This is ergy sources such as onshore wind and solar a difficult endeavor partly because of the lack of PV. Future studies may wish to consider what 8: Areas for Further Research 99 green hydrogen development could look like in renewable developers to consider PEM. If such countries that are endowed with other renewable solutions were technically feasible, they could power sources, such as geothermal, hydroelec- provide a route to both reduce total system costs tric power, or offshore wind that typically have and reduce efficiency losses through the conver- higher capacity factors than onshore wind and sion to a hydrogen process. solar PV. Last, this report has focused exclusively on green Understanding how green hydrogen technologies hydrogen production via electrolysis. There are could be integrated within a blended portfolio of a number of pilots now under consideration renewable energy distributed resources should to generate green hydrogen from waste, which also be a focus for multilateral development are being piloted in some countries such as in agencies and other energy organizations that are Bangladesh. This pilot project funded by the seeking to identify solutions for off-grid energy government of Bangladesh will provide 5 MW of access. Notably, the use of batteries in tandem power to the grid from green hydrogen generated with variable renewables could help optimize from waste in 2020 (Saha 2019). This is therefore the size of an electrolyzer by ensuring a consis- another area worth exploring, especially given tent quality of power. Such solutions may also the potential economic benefits for municipal allow more developed alkaline technologies to governments of turning waste into a resource for overcome some of the concerns around their clean, local power provision. response speed that have typically encouraged 100 GREEN HYDROGEN IN DEVELOPING COUNTRIES BIBLIOGRAPHY Abt. 2019. “Kenworth, Toyota present electric fuel cell truck to UPS.” https://www.fleetowner.com/running-green/ article/21703733/kenworth-toyota-present-electric-fuel-cell-truck-to-ups. 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