Assessment of the greenhouse gas mitigation potential of green hydrogen. An implementation roadmap for Mexico/Oportunidades del hidrógeno verde para México. Una revisión de tecnologías y experiencias a nivel internacional
Green hydrogen opportunities for Mexico. An international review of technologies and experiences
Oportunidades del hidrógeno verde para México. Una revisión de tecnologías y experiencias a nivel internacional
Mexico City, 1st of June 2021. Without doubt, to decarbonise the Mexican economy, several greenhouse gas mitigation technologies are needed. Among these alternatives, green hydrogen will play a fundamental role in the future. Even though green hydrogen costs are still high for some technologies, this alternative is gaining momentum globally and it is expected a rapid deployment of projects and costs reductions. Mexico cannot stay behind and for this reason the country has to take advantage of its abundant natural resources and of the existing infrastructure and capacities. Because of this, the Mario Molina Center, with the support of the UK Pact Programme of the Department for Business, Energy and Industrial Strategy (BEIS) organised a Webinar that presented the “Assessment of the greenhouse gas mitigation potential of green hydrogen. An implementation roadmap for Mexico” project which is part of the portfolio of projects of the UK Pact Programme in Mexico and is currently developed by the Mario Molina Center. The project will evaluate the economic and greenhouse gas mitigation potential of green hydrogen in Mexico and will also design a roadmap for the implementation of pilot projects. The Webinar had the participation of the Embassy of the United Kingdom in Mexico, the National Institute of Ecology and Climate Change (INECC) and the presentations from experts in green hydrogen from Imperial College London, BP, Camnexus and the World Bank.
Ciudad de México, 1 de junio de 2021. Sin duda, para alcanzar la descarbonización de la economía mexicana, se requieren de distintas tecnologías de mitigación de gases de efecto invernadero, dentro de las cuales el hidrógeno verde jugará un papel fundamental en el futuro. Si bien, los costos del hidrógeno verde siguen siendo altos para algunas tecnologías, el gran interés a nivel internacional por esta alternativa y su rápida adopción obligan a México a no quedarse atrás. Por ello se deben de aprovechar los abundantes recursos naturales con los que cuenta el país, así como la infraestructura y capacidades existentes. Para ello, el Centro Mario Molina, con el apoyo del Programa UK Pact del Departmento de Negocios, Energía y Estrategia Industrial del Gobierno del Reino Unido, organizó un Webinar en el que se presentó el proyecto: “Assessment of the greenhouse gas mitigation potential of green hydrogen. An implementation roadmap for Mexico”. Este proyecto es parte del portafolio de proyectos del Programa UK Pact en México y es desarrollado por el Centro Mario Molina. El proyecto evaluará el potencial de mitigación de gases de efecto invernadero y la economía del hidrógeno verde en México. Asimismo, diseñará una ruta crítica para la implementación de proyectos piloto. El Webinar contó con la participación de la Embajada del Reino Unido en México y el Instituto Nacional de Ecología y Cambio Climático (INECC); así como con la exposición del trabajo y experiencia en el tema de hidrógeno verde de expertos internacionales del Imperial College London, BP, Camnexus y el Banco Mundial.
The need to find alternatives for the decarbonisation of the world economies has positioned hydrogen (H2) as an attractive solution for bringing greenhouse gas (GHG) emission reductions and energy security. The versatility of hydrogen has promoted projects targeting all areas of energy consumption (mobility, heat in buildings and the industry, power generation) and as a feedstock in industry (refining, chemical, iron and steel, mining). These applications are emerging, and their adoption is accelerating around the world as decarbonisation efforts towards net-zero emissions strengthen. However, hydrogen decarbonisation efforts in the long run will need a strong commitment to invest in zero-carbon hydrogen production and use from 2020 to 2035, so that costs can be reduced. Between 2035 and 2050, structural shifts based on available and near-mature technology need to emerge, and research and development efforts for hydrogen production and use must continue so that between 2050 zero-carbon H2 production and use are widespread in areas such as heavy industries (Rissman, et al., 2020). The International Energy Agency (IEA) (2020) expects a substantial increase in hydrogen and hydrogen-related products (hydrogen, ammonia, synthetic fuels, electricity from hydrogen, among others) between 2019 and 2070, with a demand for hydrogen-related energy sources 12 times higher in comparison to oil and gas. Moreover, hydrogen and hydrogen-based fuels may account for 8% of global CO2 emission reductions (6% from transport and 2% from industry).
For the latter reasons, it is vital to promote technologies and policies to give shape to a rapid adoption and development of hydrogen solutions based on a careful assessment of each potential project. As an important member of the international community, Mexico cannot stay behind these efforts and must increase the promotion and adoption of green hydrogen. The generation, transport, storage, distribution, and use of green hydrogen in Mexico could represent an opportunity for not only reducing GHG emissions but for increasing the energy security of the country and taking advantage of its vast renewable resources. Green hydrogen in Mexico could also bring new job opportunities and the reduction of atmospheric pollutant emissions. The IEA (2021) considers that low-carbon hydrogen could represent the next step for Latin America’s clean energy transition reaching sectors that are not feasible for direct electrification. While it is considered that hydrogen will be required for decarbonising the transport sector of the entire region, the potential for decarbonising heavy industry would be concentrated in few countries such as Mexico. The study highlights the fact that there are still significant challenges for low-carbon hydrogen in the region, but it is recommended that the initial efforts to be focused on research and development, pilot projects and their preparation for a large-scale deployment. Recommendations for policy makers include the definition of the long-term role of hydrogen in the energy system; the identification of opportunities for the development of key technologies, the support of early financing schemes and the reduction of investment risk; focus on research and development; the use of certification schemes to incentivise production of low-carbon hydrogen and the regional cooperation and the positioning of Latin America in the global landscape (IEA, 2021).
The potential for green hydrogen in Mexico is high and initial estimates by HINICIO (2021) consider that the country has the total potential to install 22 TW of electrolyser capacity by 2050. Furthermore, green hydrogen could avoid the emission of 40 MtCO2e per year and create 90,000 new jobs by 2050. In addition to this, it was also estimated that the levelised cost of hydrogen (LCOH) could be between 2.55 US Dollars per kg in 2030 and 1.22 US Dollars per kg in 2050. HINICIO (2021) considers that the largest opportunities for green hydrogen are within the transport sector, and particularly for public transport buses and freight trucks. The production of synthetic fuels for the aviation industry is another area of application for green hydrogen meeting 12% of the aviation’s fuel demand by 2050. In the case of industry, it is considered that the mining industry could use green hydrogen for fuelling mining vehicles and for steel production and thermal applications. According to the study, PEMEX and CFE are other important players that could serve as initial adopters of green hydrogen in the production of ammonia and for oil refining. Finally, thermal applications in the chemical industry and for cement production was also considered having a moderate participation. Mexico could also become an important exporter to Europa and particularly to the United States and could closely compete with Chile and Australia (HINICIO, 2021).
The geographical location of Mexico not only provides vast renewable resources but also provides a unique commercial position that has not been fully exploited yet. Green hydrogen is a technological alternative that could bring environmental, social, and economic benefits. However, to adopt this alternative, more efforts are still required to bring together all the interested actors and adopt a common strategy. The interest in green hydrogen in Mexico is relatively new and this work complements the existing work regarding the estimation of the greenhouse gas mitigation potential of hydrogen and tis costs. However, it takes a different perspective by focusing on the potential demand of green hydrogen and specific alternatives for implementing a pilot project considering commercially available technologies and scales. The objective of the project was to estimate the GHG mitigation potential and costs for green hydrogen in Mexico and design an implementation roadmap for demonstrative projects. (…)
GESI guidelines for project implementation
The social dimension of a new green economy is one of the three pillars of the sustainable development model—social, economic, and environmental development. As humanity makes enormous efforts to sustain itself, we must ensure that everyone can live dignified lives (Schlör, et al., 2017). The 17 UN Sustainable Development Goals (SGDs) recognize the interdependency between the three spheres; gender equality and social inclusion, also known by the acronym GESI, are two cross-cutting principles represented in goals 5 and 10 of the SDGs. The two goals emphasize the relationship between the environment, the economy and the society, particularly for women and other marginalized groups that do not have uniform access to rights and opportunities across the world and thus will experiment the negative impacts of climate change on a more severe extent (UN, 2016; UK PACT, 2021b), also known as asymmetrical impacts (Cameron, et al., 2013), which in turn could unfold into greater inequality (UK PACT, 2021a). In other words, the relationship between social inequality and climate change is characterized by a vicious cycle (Islam & Winkel, 2017). Developing countries must overcome the great challenge of developing and lifting people out of poverty while acting on climate change, a demand that wealthy countries did not have to meet when their economies grew and the middle class could meet aspirations based on consumerism and fossil fuel energy production (Edward, et al., 2013).
Marginalized groups are any group of people that has been historically and systematically subject to discrimination and exclusion derived from stereotypes and prejudice towards the individual gender identity, ethnicity, physical ability, income, or religion, among other aspects. Marginalization is a multi-dimensional and structural phenomenon that results in negative impacts to the individuals that belong to marginalized groups, mainly a higher risk of inequalities, due to unequal distribution of development and power relationships (NCCDH, 2021; EIGE, 2021; CONAPO, 2013). Inequality is multidimensional and can take many forms, from a global to a household scale. For example, it can be seen in income and assets disparities across regions—in 2016, the top 1% received 22% of global income— and also among people of different age, sex, abilities, ethnicity, origin or religion, to name the main characteristics that can define the opportunities of an individual in a society, including capabilities, assets and activities that make up livelihoods and participation in public decision making and public resources (UNDP, 2021; Islam & Winkel, 2017), as well as the capacity to acquire or generate such opportunities (CONAPO, 2013).
Women experience constraints, both social and cultural, that place them in inferior social positions, limit their access to income, education, public voice, and survival mechanisms (Edward, et al., 2013). Nevertheless, it is proven that empowering women and girls helps economic growth and development, and while remarkable progress has been made in the past 20 years, women in many regions still undergo problems such as lower education, less access to the labour market, unequal division of unpaid care and domestic work, discrimination in leadership positions, less rights on land and property, poorer healthcare, violence based on gender, etc., in comparison to boys and men (UNDP, 2021). Any effort directed towards the achievement of Gender Equality should also address inequalities that affect non-binary individuals, while social inclusion must ensure that every individual takes part in society and a Just Transition for workers and communities effectively occurs (UK PACT, 2021b).
The GESI framework aims to actively challenge existing gender norms, promote positions of social and political influence. The shift from a fossil-based energy matrix to a renewable-based energy matrix must incorporate the GESI perspective in the assessments, plans and actions. GESI-centred interventions are intersectional—the idea that all inequalities are linked—, which leads to better designed climate actions as intersectionality allows a more comprehensive understanding of community needs, and community prosperity needs the input from everyone (UK PACT, 2021c; UK PACT, 2021b). Critical intersectionality means to pay attention to how power and social and political relations shape the world to avoid falling into oversimplified dichotomies such as men-versus-women or victim-or-steward issues (Djoudi, et al., 2016). It is worth to note that the concept of community is frequently used to refer to a homogenous body, but in practice, communities are constituted by individuals with specific interests regarding economic position, age, gender, ethnic backgrounds, etc., so approaching the communities to understand their unique position is key, instead of making assumptions (SDG Fund, 2017).
Social inclusion must build resilient and accountable societies and expand opportunities for everyone, helping individuals overcome obstacles to fully participate in society and being able to shape their own future. This requires participation from all areas of society: governments, communities, civil society, the private sector, and other stakeholders. People should be able to drive their own solutions, which can be boosted by building on participatory approaches and the own values of communities, which provides more engagement. Any project should stand for transparency, accountability, non-discrimination, and public participation (The World Bank , 2021).
Assessment of the greenhouse gas mitigation potential of green hydrogen. An implementation roadmap for Mexico
Hydrogen offers important benefits in terms of greenhouse gas (GHG) mitigation and energy security for the world. Several applications of hydrogen are currently being explored in pilot-scale projects from the private sector, sometimes with the support from national and regional funds. The versatility of hydrogen has promoted projects targeting all areas of energy consumption (mobility, heat in buildings and the industry, power generation) and as a feedstock in industry (refining, chemical, iron and steel, mining). These applications are emerging, and their adoption is accelerating around the world as decarbonisation efforts towards net-zero emissions strengthen. For this reason, it is vital to locate resources for research and development (R&D) of technologies and policies to foster and give shape to a rapid adoption and development of hydrogen solutions. Moreover, a solution for a problem in one location may not be the perfect fit for another, so a careful assessment of each case will ensure the best solutions are implemented.
Hydrogen decarbonisation efforts from 2020 to 2070 will need a strong commitment to invest in zero-carbon hydrogen production and use from 2020 to 2035, so that costs can be reduced. Between 2035 and 2050, structural shifts based on available and near-mature technology need to emerge, and R&D efforts for hydrogen production and use must continue so that in the last 20 years of the period (2050-2070), zero-carbon H2 production and use are widespread in areas such as heavy industries (Rissman, et al., 2020). The IEA (2020d) expects a substantial increase in hydrogen and hydrogen-related sources (hydrogen, ammonia, synthetic fuels, electricity from hydrogen, among others) between 2019 and 2070, reaching a 12 times higher demand for hydrogen-related power sources in comparison to oil and gas. Moreover, hydrogen and hydrogen-based fuels may account for 8% of global CO2 emission reductions (6% from transport and 2% from industry)
Today, hydrogen is mainly used in oil refining and as a feedstock in the chemical industry and the majority is produced and used on-site using fossil fuels, emitting more than 800 MtCO2. Hydrogen is expected to emerge as a fuel during the 2020’s, mainly for the transport and industry sectors. Liquid synthetic hydrocarbon fuels made from H2 and CO2 will start to be used in road freight trucks and aircraft during the second half of the 2020s, and will continue growing until 2070. Hydrogen demand will come from shipping, aviation, road transport, buildings, power-applications, refining, the iron and steel industry, the chemical industry and other activities (IEA, 2019b; IEA, 2020d)
considering all aspects involved, such as greenhouse gas (GHG) emissions, energy security, economic aspects, among others; long-term decisions for investment in green hydrogen now are advisable for developing countries; in doing so, an accelerated socioeconomic development would be achieved, as well as an important reduction in the negative environmental impact.
It is worth mentioning that green hydrogen is not a new technology for developing countries. Egypt, India, and Zimbabwe, among other developing countries, have already produced green electrolytic hydrogen on a large-scale in the past because of its role in the production of ammonia for fertilisers. Its inclusion could create local opportunities for different economic, industrial, and social sectors (ESMAP, 2020). Optimal locations for hydrogen production include a combination of wind and solar resources (Hydrogen Council, McKinsey & Company, 2021).
Advanced technologies allow the conversion of domestic bio-waste into biomethane, which in turn can be converted into green hydrogen; this process being simultaneously beneficial for power generation, waste treatment and socioeconomic sectors, represents a special opportunity for developing countries, which frequently have high electricity prices, as well as reliability issues and poor waste treatment. Therefore, in these cases, green hydrogen and fuel cell deployment could simultaneously bring down electricity prices and increase power availability and reliability, thus enhancing their economic development. However, the number of projects today that seek to create green hydrogen from waste are not currently considered significant in the broader literature and need to be deployed outside of testing environments. A pilot-scale project funded by the government of Bangladesh was planned to produce and incorporate 5 MW of power to the grid by 2020 (ESMAP, 2020).
According to the study performed conducted by Rissman and colleagues (2020) on different technologies for decarbonise iron and steel, cement, chemicals and plastics as well as different policies to support the emissions shift by 2070, zero-carbon (electrolysis) hydrogen has a great potential to reduce CO2 emissions in light and heavy industries as a heat source and a chemical feedstock given the declining costs of renewable electricity. The authors mention that hydrogen appears in many scenarios that assess the opportunities to achieve net-zero and limit global warming below 2°C even when each scenario considered a different approach.
The present challenges for hydrogen to succeed are the high cost of electrolysers, competition with low cost natural gas (this is a significant challenge in the short term for some developing countries), embrittlement of metals (which asks for new process heating equipment), the problem of developing supply infrastructure in tandem with end-use equipment, the moderate technology readiness levels of industrial technologies such as hydrogen-reduced steel and low technology readiness levels of some low-carbon hydrogen production technologies. Technical and trade regulations have also played an important role, impeding development in some cases. Developing countries may be early hydrogen adopters if they have excellent renewable resources, unique energy requirements, or a high-level of synergy in hydrogen demand from all sectors (industry, mobility, power, and heat). The TRL of hydrogen production technologies is expected to rise in the upcoming years, but in cases such as hydrogen production from nuclear power, further development is needed (ESMAP, 2020; Rissman, et al., 2020; IEA, 2020d).
Hydrogen and hydrogen-based fuels represent one of the most important alternative fuels. According to IEA’s projections for 2070, hydrogen and hydrogen-based fuels alone will account for 13% of all final energy needs (IEA, 2020d). A rapid expansion is a considerable challenge. In the case of LNG, its adoption started in the 1960s and took around 50 years to position itself (today, global LNG trade accounts for 2.5% of global energy supply), and for renewable electricity, market-creating feed-in-tariffs needed 25 years to achieve a point where solar PV accounts for 1% of global electricity output. Decarbonisation efforts to comply with the Paris agreement—zero emissions within the next 30-50 years— will need the help strong investment in hydrogen R&D and infrastructure to expedite H2 adoption. R&D is needed even after a technology is materialised to drive down costs and improve performance—at this point in technology development, the private sector is most likely to contribute (IEA, 2019a; Rissman, et al.). International hydrogen distribution is driven by cost differences, renewables availability, infrastructure, and land use constraints, among others. With hydrogen production costs falling, costs for hydrogen distribution are becoming increasingly important. For production and distribution, three types of value chains are emerging (Hydrogen Council, McKinsey & Company, 2021).
- Large-scale hydrogen buyers near favourable renewables or gas and carbon storage sites will use onsite hydrogen production.
- Smaller buyers (e.g. refuelling stations or households) will require regional distribution of hydrogen.
- In regions without optimal resources, hydrogen buyers may rely on imports.
In the following paragraphs the trends and expected shifts in hydrogen use and production are presented.
The rapid adoption of hydrogen in the industry will require an equal rate for scaling hydrogen production, distribution, and storage infrastructure. For those facilities with access to low cost electricity, the most feasible option is to produce hydrogen on-site, but the rest of industrial facilities may have to purchase this hydrogen—this requires an extensive and solid distribution system that can also serve the mobility sector (Rissman, et al., 2020).
- Iron and steel
In current primary steel production using direct reduced iron plus an electric arc furnace (DRI-EAF), methane is transformed in syngas, containing hydrogen and carbon monoxide, so H2 reduces iron. Around 6% of steel is made from this route, while the blast furnace/basic oxygen furnace (BF/BOF) route uses coal to reduce the iron ore and secondary EAF production uses electricity to melt the metal scrap—the source of electricity determines the emissions. Modern steel facilities already operate within the limits of thermodynamic efficiency, so to lower the emissions the options are to replace carbon with hydrogen or use direct electrolysis (Rissman, et al., 2020).
The hydrogen DRI-EAF process, also known as HYBRIT, has a TRL of 5 according to IEA. The process directly uses low-GHG H2, instead of syngas, to produce water and sponge iron which is fed to EAF and melted. The shift from syngas to pure hydrogen can be done without major equipment changes. Excluding H2 losses, the process would require an estimate of 51 kg H2 per tonne of steel and 3.5 MWh or 12.5 GJ of energy per tonne of steel. Hydrogen-DRI has been used in Trinidad, using SMR hydrogen. SSAB, LKAB and Vattenfall are building a HYBRIT plant in Luleå, Sweden (pilot trials will be completed in 2024, industrial process will be in place in 2035) and ArcelorMittal plans to build a facility in Hamburg, Germany. Hydrogen-DRI appears as the most promising zero-carbon steel production route, compared with electrowinning (aqueous electrolysis) and blast furnace with and without CCS. The process would be competitive in regions with carbon price policies implemented and carbon prices of 40 to 75 US Dollars per tCO2e, assuming electricity costs of 0.05 US Dollars per kWh (levelised cost of electricity, LCOE, for utility-scale solar and wind energy has achieved 0.03-0.05 US Dollars per kWh in some regions and is likely to drop further) (Rissman, et al., 2020; ESMAP, 2020; IEA, 2019a; IEA, 2020d).
In the long-term, according to IEA (2019), hydrogen-DRI and traditional DRI coupled with CCUS will compete with direct electrification. An interesting potential application of green steel is the direct reduction of haematite, a constituent of iron ore, a process demonstrated in Japan at a laboratory scale (IEA, 2019a).
- Oil refining
Traditional hydrogen production in oil refining releases significant volumes of carbon dioxide and is closely integrated within the refining processes. An option to lower the emissions is to capture the CO2 and to combine it with hydrogen to produce synthetic fuels. Carbon capture technologies like calcium- and iron-based chemical looping are well established. To 2030, IEA expects hydrogen demand in oil refining to increase 7% under existing policies and pollutant regulations, but also affected by lowering demands of oil and production of lighter and sweeter oil in recent years, at least in the US. After 2030, oil demand for transport fuels, increased efficiency of hydrogen recovery in refineries and electrification will slow the growth rate of hydrogen production. If zero-carbon electricity, green hydrogen production is scaled and widely available, and a substantial technological innovation takes place, the industry could even become carbon-negative (sequestering more carbon than is produced) (IEA, 2019a; Rissman, et al., 2020).
- Chemical industry
Demand for hydrogen for primary chemical production is expected to increase to 57 Mt per year by 2030, driven by ammonia and methanol demand, and will continue growing after 2030 mainly because of the growth in methanol-to-olefins/methanol-to-aromatics demand from China, while demand for nitrogen-based fertilisers may plateau or decline due to specific policies to limit use and improve agricultural practices. Recycling and reusing plastics and other materials may decline, impacting demand for primary chemicals like ethylene. An increased demand for ammonia and methanol could arise if they are used as energy carriers or fuels (IEA, 2019a).
The main advantage of converting hydrogen into other chemicals like ammonia and synthetic fuels (methane, diesel, kerosene, methanol, etc.) is their lower volumetric energy density, which allows easier storage, transport and energy trade, as well as the reduction of fuel volume for vehicles. Furthermore, several synthetic fuels are compatible with the existing fuel infrastructure (IEA, 2020d). The market of hydrogen-based chemicals will include urea-based fertilisers, amines, fibres, and plastics. However, the use of carbon dioxide is energy intensive and energy losses are the main disadvantage of transforming hydrogen into other substances; it is unlikely that hydrogen-derived fuels and chemical products will be important contributors to carbon abatement in the next 20 years. Energy can be used in a more efficient manner to provide direct services (electricity in vehicles) until the zero-carbon hydrogen infrastructure develops (Rissman, et al., 2020; IEA, 2020d).
For hydrogen to be a cost-competitive alternative, it must overcome the low prices of natural gas. This will most likely occur if a carbon pricing scheme is implemented, renewable energy costs continue dropping (0.03-0.06 US Dollars per kWh today) and electrolysis capital costs at least halve. However, fossil-based ammonia and methanol are more competitive when coupled with CCUS at locations with higher electricity prices, so electrolysis would require electricity prices to be 10-40 US Dollars per MWh for ammonia and 5-50 US Dollars per MWh for methanol to be competitive (Rissman, et al., 2020; IEA, 2019a). According to ESMAP (2020), the key to expand the number of hydrogen projects is to couple green hydrogen production with direct air capture/carbon capture techniques to produce ammonia or methanol, which can be stored for longer periods than hydrogen (an attractive characteristic for applications such as telecommunication). However, the process has a low overall energy efficiency (around 40%) (IEA, 2020d).
By 2070, IEA (2020d) projects that 380 Mtoe of hydrogen-based fuels will be produced per year, requiring 390 Mtoe of electrolytic hydrogen (9% of total energy generation) and 700 Mt of CO2 obtained from biomass or direct air capture. This fuel production will be distributed as follows:
○ 250 Mtoe of hydrocarbons. Kerosene meets 40 % of aviation energy demand. 50% of synthetic kerosene will be traded globally.
○ 130 Mtoe of ammonia, meeting 50 % of fuel demand for maritime shipping, and obtained 70 % from natural gas with CCUS and the rest from electrolytic hydrogen. 60% of ammonia will be traded on a global scale.
- Energy vector in power and heat
Green hydrogen and fuel cells will likely become a building block of fully decarbonised grids, complementing existing renewable technologies, and promoting their growth and deployment, ensuring energy security, boosting socioeconomic and industrial development, improving air quality, and increasing access to mobility, among other benefits (ESMAP, 2020). Electricity is the most popular energy vector, but some difficulties in its storage have turned the attention to hydrogen and hydrogen derived chemicals like ammonia, methane, and methanol, known substances for which supply chains are already established and could be scaled. An energy penalty is associated with the production of ammonia (70% efficiency) and methanol (64%) (Rissman, et al., 2020).
Today, hydrogen is obtained mainly from fossil sources without CCUS, but by 2070, nearly 60% of hydrogen will be obtained from electrolysis, around 40% from fossil sources coupled with CCUS and 1% from unabated fossil fuels (as a by-product of catalytic naphtha reforming in refineries). Alkaline electrolysis is the preferred route of hydrogen production today, mainly to produce hydrogen for fertilisers. However, solid oxide fuel cells (SOFCs) and proton exchange membrane fuel cells (PEMFCs) (used in vehicles thanks to their small, modular mobile units) show improved efficiencies, around 50% higher than alkaline electrolysers and will continue their development. Other alternatives are the direct use of sunlight to split water and bubble column reactors with liquid metal. The economics of electrolysis depend on capital cost, the cost of electricity and the efficiency of the system, elements that are expected to fall in the next years (Rissman, et al., 2020; IEA, 2020d).
By 2070, global water electrolysis capacity is expected to reach 3.3 TW or 60 GW per year, with an average cost below 300 US Dollars per kWe, supported by a mixture of grid electricity and renewables-based power plants (IEA, 2020d). A rapid improvement in the cost of fuel cell units combined with improved efficiency have greatly benefitted the electrolyser market —for example, a SOFC lifetime in 2005 was under 20,000 hours and in 2020 the lifetime doubled. Electrolyser CAPEX is expected to achieve 200-250 US Dollars per kW by 2030, including electrolyser stack, voltage supply, rectifier, drying/purification and compression to 30 bar. The total cost of an electrolyser includes financing, which is an important way to reduce hydrogen production costs. For example, reducing the weighted average cost of capital (WACC) from 7% to 5% would reduce a project’s overall CAPEX commitment by nearly 20% (Hydrogen Council, McKinsey & Company, 2021; ESMAP, 2020).
Estimated global manufacturing for proton exchange membrane (PEM) electrolysers is above 300 MW per year, and it is expected to achieve 1,500 MW per year or more in 2025; for alkaline electrolysers, current capacity is more than 1,800 MW per year and will surpass 3,000 MW per year in 2025. PEM fuel cell manufacturing capacity is in place as of 2020, and the industry will expand in the future. However, under current practice it is likely that the scale-up for hydrogen will drive an increase in demand for fossil-fuel based hydrogen in the short term, and green hydrogen scale-up in the medium- to long-term will be determined by the dynamics of production pricing across technologies. For molten carbonate fuel cell (MCFC), SOFC and phosphoric acid fuel cell (PAFC), the market is dominated by a few companies, so the success of these technologies will depend on the success of the companies rather than on the fuel cell industry behaviour (ESMAP, 2020). An attractive application of fuel cells is in waste management sites. SOFC and MCFC units have higher tolerance for carbon dioxide than other fuel cells and can run on biogas mixtures of more than 40% carbon dioxide, making them suitable to use in conjunction with wastewater treatment plants (ESMAP, 2020).
Electrolysis demands electricity and water. The main issue with water use may not be the quantity but the quality. Access to high purity water, is needed to maintain humidity in the fuel cell stacks, which can hinder hydrogen production. However, most electrolysers can include a purifying unit in the system making them compatible with the public water supply system. Currently, water and electricity consumption is approximately 9 L per kg H2 and 51 kWh per kg H2, respectively. If brackish water or seawater is used, an additional 3-4 kWh per m3 is needed for desalinisation via reverse osmosis. If the water comes from the public water system, a deionisation system will be needed, elevating water consumption to 15-30 litres to obtain 9 litres to yield a kilogram of hydrogen. In comparison, hydrogen from steam methane reforming (SMR) requires 4.5 L per kg H2 (not including the water consumption from coal or gas extraction) and coal gasification uses approximately the same volume of water. Moreover, water consumption is not a synonym of water demand, as the water is reusable after purification (ESMAP, 2020; Rissman, et al., 2020). In off-grid locations that require high power availability, stationary fuel cell applications below 3 kW have become an attractive option, especially in sites in Asia where diesel thefts are common (ESMAP, 2020).
Hydrogen can be used to provide heat and electricity in buildings. One option is to blend hydrogen with natural gas in the natural gas network, which is a low-cost solution and allows to keep the existing infrastructure and equipment if the hydrogen is blended at 5 to 20%. Another option is to use 100% hydrogen, requiring a higher investment to upgrade the network and equipment, which can be challenging if the market has various gas suppliers and distributors. Last, fuel cells and co-generation technologies for residential use have appeared as an attractive alternative. Stationary fuel cell combined heat and power units have transitioned from PEM to SOFC (higher efficiency and operating temperature), as is seen in Japan with the Ene-Farm project (more than 300,000, 5 kW or less units have been deployed in the last 10 years) (Rissman, et al., 2020; IEA, 2019a).
Back-up power with PEM fuel cells using units of 100 kW or less is also being used (e.g., Adrian Kenya, PT Telekom); off-grid power provision is mostly driven by PEM fuel cell units of less than 1 kW (Tiger Power, Raglan Mine, BIG HIT); commercial office power is accomplished mainly with SOFC and PAFC of less than 5 kW (Apple HQ, Morgan Stanley Manhattan); and baseload power generation has a more varied range of technologies, with SOFC, PAFC, MCFC and retrofit gas turbine units of more than 400 kW (Daesan Green Energy JV, CEOG, North Chungcheong Province). The presence of hydrogen fuel cells is most likely to continue and grow in the sector. Stationary fuel cells today operate with natural gas but can be retrofitted at a low cost to run on pure hydrogen, which could enable countries to future-proof investments using widely available natural gas today or biogas, and then shift to green hydrogen fuel cells (ESMAP, 2020).
The primary market for back-up power has been the telecommunications sector, which has been a focus for fuel cell power systems due to the continuous energy consumption of the equipment. Early solutions used PEM units using pure hydrogen, creating logistic and performance issues for the early adopters. Today, the systems use methanol- or ammonia-based fuel cells (ESMAP, 2020).
Fuel cells can provide utility-scale firm power in low-carbon grids, complementing renewable energy output and providing ancillary services thanks to their fast response. If natural gas has a low cost, the cost of operating natural gas fuel cells can be lower than fuel oil generators or diesel generators. Green hydrogen fuel cells can deliver the same performance as fuel cells running on natural gas without the emissions and can provide power grids with a long-term energy storage solution. As for large natural gas turbines, plans exist to convert them to run on hydrogen in order to use the hydrogen produced in SMR sites in the short term and prepare for the green hydrogen transition (for example, the 400 MW Magnum CCGT operated by Equinor in the Netherlands is due to run on 100% hydrogen by 2023) (ESMAP, 2020).
- High-temperature heat
High-temperature heat is delivered at 450°C or above, with specific applications using temperatures over 1,000°C. Heavy industries consume high-temperature heat in many processes where the main source of high temperature heat are fossil fuels: 65% is obtained from coal, 20% from natural gas and 10% from oil, with minimal contributions of biomass. The use of high-temperature heat in the industry accounts for around 1.1 GtCO2 per year of direct emissions. Electricity is another source of energy in electric arc and induction furnaces in steelmaking (direct use), and in aluminium smelting (indirect use). CCUS is an alternative to lower emissions, but combustion of hydrogen or hydrogen-based fuels like ammonia can help reduce emissions. Today, however, the use is virtually non-existent, although it has been demonstrated. In 2020, a performance trial successfully heated steel using hydrogen before rolling in Sweden, performed by Ovako and Linde. The IEA considers that the TRL of hydrogen use for high-temperature heat is 5. Bioenergy is a direct competitor, showing lower costs than hydrogen and competing with natural gas. In addition, pure hydrogen cannot replace coal or natural gas directly due to the specific transformations that occur in kilns, furnaces, boilers and reactors, requiring solutions such as incorporating clinker dust into fuel streams, redesigning burners, and using corrosion- and brittleness-resistant materials (IEA, 2019; IEA, 2020d).
Around 0.01% of the pure hydrogen produced worldwide is used by fuel cell electric vehicles (FCEV) (Figure I.5). PEMFCs are used in vehicles because they perform better than other fuel cells for small applications and the market share will grow in the next decades (Rissman, et al., 2020). Fuel cells in vehicles are likely to experience an accelerated growth in developing countries given the lowering costs and benefits to consumers. FCEVs are gaining popularity among users that need autonomy for longer average distances than the distances provided by electric vehicles (like in California, US) or those whose high rate of vehicle use places a premium on the availability of power, like taxis (the Chinese company Grove has announced a 200 FCEV fleet in China and is also discussing another fleet for Minas Gerais in Brazil) (ESMAP, 2020). The lack of refuelling infrastructure and technical capability for car service may present a challenge for individual FCEV ownership. This has been addressed by some manufacturers, like Toyota with its Mirai model in the US, by only offering leasing agreements (in 2017, IEA reported 349 US Dollars per month for a Mirai) (ESMAP, 2020).
Fuel cell electric buses (FCEB) are more numerous than fuel cell cars; several hundred of FECBs are in operation in Europe, China, Japan, Korea, and North America. They compete directly against electric battery buses and offer greater ranges (more than 20,000 hours), quicker refuelling times and their cost is declining. Developing countries like Brunei, Costa Rica, India, and Malaysia are starting to implement this solution. FCEB can help improve local air quality in heavily polluted metropolitan areas (ESMAP, 2020).
The market for fuel cell powered trucks is one of the most promising areas of growing demand. Government agencies and companies in China, Japan, Norway, and Switzerland have pledged to procure and deploy more than 1,000 fuel cell trucks over the following decade (ESMAP, 2020).
Hydrogen-fuelled forklifts are increasingly popular in the world, with more than 30,000 units in operation, mainly in the US. They are attractive because they require significantly less space than battery alternatives and have a higher operational availability. Hydrogen forklift users include Amazon, Walmart (both of which use units from Plug Power, an American company), Carrefour, Alibaba and Toyota (IEA, 2019; ESMAP, 2020).
Another large potential source of green hydrogen demand are freight and maritime applications, with maritime projects in Scotland (HySeas III) and Norway. Two countries operate hydrogen trains: Germany has one hydrogen train (operated by Alstom and Hydrogenics) and China one hydrogen tram. Other companies like Ballard and Siemens have shown interest in developing train hydrogen solutions (ESMAP, 2020).
Finally, hydrogen refuelling stations (HRS) are key elements for the hydrogen use in mobility. 432 HRS were in operation by the end of 2019, but many more have been announced, with 15,000 HRS expected by 2030 installed in China, France, Germany, Japan, Norway, the UK, the US, Austria, Canada, Costa Rica, Spain, Iceland, Malaysia and the UAE (ESMAP, 2020).
Due to its low density, storage is one of the most significant barriers to scale-up hydrogen. Liquefaction and compression are two processes used for gas storage, but in the case of hydrogen are very energy consuming and hydrogen boiling-off losses occur (larger for smaller tanks and smaller for larger tanks). Storage using solid-state compounds is an emerging technology for smaller scale storage in urban areas and for mobility applications, while pressurised underground storage in geological sites like salt caverns is a solution for large storage in seasonal and inter-seasonal periods. For example, clusters of industrial facilities can include wind and solar electricity using high voltage transmission lines, transform the surplus to hydrogen and store for later use (this model is under assessment in North Rhine Westphalia, Germany), or convert it to other chemicals like ammonia and methane. Another promising novel technology for large-scale transportation and storage are liquid organic hydrogen carriers (LOHCs), which can be stored in oil facilities, bunkers, pipelines and tanks, and can store hydrogen for months or years without needing low temperatures, making them ideal for countries with an ample fuel infrastructure (Rissman, et al., 2020; ESMAP, 2020).
85% of the hydrogen that is consumed today is produced on-site and the remaining 15% is transported by pipelines or truck (Rissman, et al., 2020). Transporting small volumes of hydrogen can greatly increase the end-user cost of hydrogen, which is why it will often be more convenient to produce the hydrogen closer to demand locations (ESMAP, 2020). The transport options for a larger market are the following (Rissman, et al., 2020; IEA, 2020d; ESMAP, 2020; Hydrogen Council, McKinsey & Company, 2021).
- Building new infrastructure that is embrittlement, corrosion and diffusion resistant to avoid losses and accidents. This includes pipelines, kilns, boilers, and burners.
- Using the hydrogen-compatible existing infrastructure, such as the polyethylene low-pressure distribution and service pipes installed.
- Using the natural gas network with 5-20% hydrogen blended with natural gas. Due to material incompatibility, it cannot replace natural gas completely in the grid or end applications like boilers or burners. An example of this strategy is the HyDeploy project in the UK. In middle-income countries with existing gas infrastructure, such as Argentina, Malaysia, Egypt and Thailand, the network can be repurposed to support green hydrogen production with a minimised risk of stranded assets.
- Transforming hydrogen to other chemicals (NH3, CH4, LOHCs, etc.). This can be convenient for international hydrogen transport.
- For short and medium range distances, pipelines can achieve very low H2 transportation costs (up to 0.1 US Dollars per kg for up to 500km), only if existing pipeline networks are suitable for retrofitting (e.g., ensuring leakage prevention), and high quantities of H2 are transported.
- For lower or highly fluctuating demand, or to bridge the development to a full pipeline network, trucking hydrogen (gas or liquid) is the most attractive option, since it can achieve costs of nearly 1.2 US Dollars per kg per 300km.
- For longer distances, subsea transmission pipelines provide cheaper transportation. Where pipelines are not available, a range of different carriers may be used, being liquid H2 (LH2), liquid organic hydrogen carriers (LOHC) and ammonia (NH3) the main alternatives, since all three have comparable costs.
Studies suggest that natural gas pipeline transport would lead to losses of 20%, so there is room for improvement. Policies and regulations need to be formulated and implemented to regulate blends, and harmonisation across regions will be an important aspect of the market development (Rissman, et al., 2020).
Some transportation applications (mainly heavy-duty) and industry are “in the money” at a hydrogen production cost of 1.6 and 2.3 US Dollars per kg, without considering the costs for carbon emissions. Considering costs of carbon at 100 US Dollars per tCO2e could push the breakeven for applications like steel, ammonia, and refining. Other transportation (shipping or aviation) need costs of carbon higher than 70 US Dollars per tCo2e. As for applications in buildings and power, even higher carbon costs are needed (approximately 200 US Dollars per tCO2e) (Hydrogen Council, McKinsey & Company, 2021).
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