Hydrogen applications and business models

Going blue and green? Kearney Energy Transition Institute June 2020 Compiled by the Kearney Energy Transition Institute applications and business models

Acknowledgements The Kearney Energy Transition Institute wishes to acknowledge the following people for their review of this FactBook: Dr. Brian Efird, program director at the King Abdullah Petroleum Studies and Research Center; Lucas Bertrand, Business Development Director for ITM Power in France and Benelux; as well as Dr. Adnan Shihab-Eldin, Claude Mandil, Antoine Rostand, and Richard Forrest, members of the board for the Kearney Energy Transition Institute. Their review does not imply that they endorse this FactBook or agree with any specific statements herein. About the FactBook: hydrogen applications and business models This FactBook seeks to provide an overview of hydrogen-related technologies, emerging applications, and new business models, covering the entire value chain and analyzing the environmental benefits and economics of this space. About the Kearney Energy Transition Institute The Kearney Energy Transition Institute is a nonprofit organization that provides leading insights on global trends in energy transition, technologies, and strategic implications for private-sector businesses and public-sector institutions. The Institute is dedicated to combining objective technological insights with economical perspectives to define the consequences and opportunities for decision-makers in a rapidly changing energy landscape. The independence of the Institute fosters unbiased primary insights and the ability to co-create new ideas with interested sponsors and relevant stakeholders. Authors Thibault L’Huby, Prashant Gahlot, and Romain Debarre

2 Hydrogen – H2 H2 role in the energy transition H2 value chain FactBook 1 2 This section provides a brief description of This section provides an overview of Overview the energy decarbonization challenge to production, storage, and transport mitigate climate change and gives an technologies—looking at their overview of hydrogen’s potential role and performances, limitations, and impact. environmental benefits and giving some perspective on their technology maturity and possible improvements. Hydrogen could help reduce GHG The deployment of Blue Hydrogen could emissions in multiple sectors, help develop large-scale infrastructures, representing about half of global GHG providing time for Green Hydrogen to emissions mature and scale up

This FactBook is structured Key H2 applications H2 business Models in four sections 3 4 This section looks at existing and This section looks at the emerging emerging hydrogen applications and business models, considering current assesses their maturity. Hydrogen market conditions and their possible long- applications are categorized into four term evolution assuming a potential types: industrial applications, mobility, technology cost reduction and power generation, and gas energy. performance improvement.

Hydrogen is broadly used in industries but Most hydrogen business models require remains immature in the broader set of policy support, with heavy-duty 3 applications, for which cost reduction and transportation being the most promising innovative business models are required one in the current context Some orders of magnitude in 2019 5 Executive summary 6 1. Hydrogen’s role in the energy transition 16 2. Hydrogen value chain: upstream and midstream 25 2.1 Production technologies 27 2.2 Conversion, storage, and transportation technologies 49 2.3 Maturity and costs 61 3. Key hydrogen applications 78 3.1 Overview 80 3.2 Feedstock 84 3.3 Energy 90 3. Business models 114 4.1 Policies and competition landscape 116 4.2 Business cases 125 Appendix (Bibliography & Acronyms) 187

4 Some orders of Annual production What does 1 ton of H2 represent? of hydrogen – Feedstock to refine about 285 barrels of crude oil magnitude – Global production: 118 Mt, of which 70 Mt is from – 3,000 to 5,000 km of autonomy for a train regarding dedicated sources hydrogen in 2019 – From fossil fuels: 69 Mt – From : 4 Mt, of which 3 Mt is a What does 1 kg of H2 represent? by-product of the chlorine industry – About 100 km of autonomy for a fuel cell car, equal to 6 to 10 liters of gasoline

Current largest plants – Fossil fuel plant: 450 kt per year How to store 1 ton of H2? – Alkaline electrolyzer: 165 MW – If uncompressed, about 56,000 bathtubs – PEM electrolyzer plant: 10 MW or 1.8 kt per year – If compressed at 700 bars, about 120 bathtubs – If liquefied, about 65 bathtubs

Annual use of global hydrogen production – Ammonia and methanol synthesis: 43 Mt per How much hydrogen would be required if the year (37%) hydrogen car fleet ... : – Oil refining: 38 Mt year (33%) – Reaches 100,000 vehicles: 15 kt per year – Steel manufacturing: 13 Mt per year (11%) – Reaches 5 million vehicles in the BEV fleet: – Other: 21 Mt per year (18%) 750 kt per year – Reaches 1.2 billion vehicles in the ICE car CO2 emissions from hydrogen production fleet: 180 Mt – 830 MtCO2 per year – About 2% of global CO2 emissions How will we possibly use hydrogen in 2050? – In industry: 245 Mt, of which 112 Mt will be Equivalence of 1 Mt of H2 in terms of oil for heating – About 21 Mboe – In transportation: 154 Mt, including synthetic – About a quarter the world’s daily oil consumption fuels – In power and gas: 140 Mt 5 The need for decarbonization Hydrogen (H2) 1 Anthropogenic CO2 emissions (excluding AFOLU ) have accelerated during the 20th century, rising to could play a major about 37 Gt per year in 2019, with global CO2 atmospheric concentration reaching 415 ppm. At current role in various emission levels, the remaining carbon budget to keep global warming below the +1.5 °C target could be energy applications, exhausted in 10 years, which would have dramatic consequences on ecosystems and societies. contributing Hydrogen: a potential candidate to global Most of the anthropogenic greenhouse gas (GHG) emissions (excluding AFOLU) comes from the decarbonization production and transport of energy (about 40%, including and heat production), industry (23%), buildings (21%), and transport (16%).

Hydrogen provides multiple pathways to reducing GHG emissions in these sectors and could address about half of their GHG emissions if produced, stored, and carried cleanly. Hydrogen can either be used as an energy carrier or as a feedstock for various industrial and chemical processes.

Hydrogen is a versatile energy carrier that can either be burnt to release heat or converted into electricity using fuel cells. Therefore, hydrogen offers a broad range of applications from energy production to Hydrogen’s role in the mobility services. But H2 is competing with other decarbonized solutions that tackle similar applications, energy transition such as solutions and carbon capture and storage.

(Section 1: pages 16–24) Hydrogen has high gravimetric energy density (MJ/kg) and can be stored under multiple forms (for example, gaseous, liquid, or converted to other molecules), which makes it a strong candidate for energy storage as an intermediary vector for the energy system (enabling coupling between electric grid, gas grid, transportation, and industries).

Executive summary (1/10)

6 1. AFOLU is agriculture, forestry, and other land use. Blue and green Main brown/grey production sources are steam reforming (SMR), gasification, and autothermal reforming (ATR). hydrogen sources In a Steam methane reforming reactor, natural gas is mixed with high-temperature steam and nickel offer potential catalysts in a endothermic reaction to form H2, CO and CO2, called a syngas. It requires 3 to 4 kg of CH4 per kg of H2 (about 65% of lower heating value efficiency). decarbonization In a coal gasification reactor, O2 is added to the high-temperature combustion chamber in solutions, requiring substoichiometric conditions, releasing syngas, tar vapors, and solid residues. About 8 kg of coal are required to produce 1 kg of H2 (70 to 80% LHV efficiency). either CCS Autothermal reforming combines both production methods, with a combustion and a catalytic zone within deployment or use the same chamber, also releasing a syngas. It requires 2.5 to 3 kg of CH4/kgH2 (80% LHV efficiency). of renewables (1/2) The syngas is a mixture of H2, CO, CO2, and other gases that can be used as is or purified. Syngas composition depends on reactor design and feedstock used. As H2 and CO are main syngas components, syngas quality is measured with H2/CO ratio in volumetric quantities. High ratio means high quantity of H2 in the syngas. Syngas can directly be consumed, such as for methanol synthesis or as a fuel. In other cases, purification is required. There are two main ways to purify syngas: – Pressure swing adsorption (PSA) purification: syngas first undergoes a –gas shift reaction, where Hydrogen value chain: water steam is added to convert CO into CO2 and H2. CO2 is then removed and released through upstream and midstream - selective adsorption process. Production technologies – Decarbonation and methanation purification: after a water–gas shift reaction, syngas undergoes decarbonation where amines are added to remove the majority of the CO and CO2. During (Section 2.1: pages 27–48) methanation, the remaining CO and CO2 reacts with H2 to create CH4.

Blue hydrogen requires the combination of brown sources with CCS value chain (capture, transportation, storage, and/or usage of CO2), for which multiple technologies are available. Within the energy value chain, CCS applied for hydrogen production is considered as pre-combustion capture: carbon is removed from fossil fuel to create hydrogen. Following on-site capture, carbon can be transported through pipelines or ships and is later stored in underground geological storage (for example, Executive summary (2/10) depleted oil and gas fields). Carbon can also be used for further processes, such as chemical feedstock (for example, for methanol or liquid fuels synthesis), enhanced oil recovery (EOR), or agriculture. 7 CCS can be deployed at different stages of the end-to-end production and purification process. Several technologies are available, such as amine capture or membrane separation. Blue and green Green hydrogen mostly relies on electrolysis technologies, involving an electrochemical reaction where electrical energy allows a water split between hydrogen and dioxygen. hydrogen sources An electrolysis cell is the assembly of two electrodes—a cathode and an anode—either immerged in an offer potential electrolyte (Alkaline) or separated by a polymer membrane (PEM). Direct current is applied from the anode to the cathode. For a potential difference above 1.23V, water is split into H2 and O2. An electrolyzer is an decarbonization assembly of cell stacks in parallel, a stack being an assembly of cells in serial connection. solutions, requiring Three electrolysis technologies are available, all based on the same electrochemical reaction but either CCS with differences in the materials used and the operating point: deployment or use – Alkaline electrolysis (AE) is the oldest technology. Potassium hydroxide electrolyte is often used of renewables (2/2) because it is a strong base (avoiding corrosivity caused by acid) with high mobility ions. Anode and cathode are separated by a thin porous foil enabling separation of H2 and O2 with a current density of 0.3 to 0.5 A.cm-2. AE efficiency is usually 52 to 69%. It is currently the cheapest electrolysis option since it does not use rare materials, and large-scale production plants (up to 150 MW) have already been built. – Proton exchange membrane (PEM) is a rapidly evolving technology and is being commercially deployed. The membrane used is a polymer membrane enabling higher current density (currently 1 to 3 A.cm-2). It is more expensive than AE technologies since rare materials are used (such as platinum for Hydrogen value chain: electrodes) but has higher flexibility and quicker response time, making it suitable for renewable energy upstream and midstream - integration. PEM efficiency is usually 60 to 77%. Production technologies – Solid oxide electrolysis cell (SOEC) is still in the R&D stage. The electrolyte used is high temperature steam water (650 to 1,000°C), which provides enough energy to decrease power consumption needs. (Section 2.1: pages 27–48) However, it is economically viable only if fatal heat is available for free or at low cost. Because of high temperature operations, ceramic membranes usually have a shorter lifetime than other technologies. SOEC efficiency is usually 74 to 81%, excluding the energy needed to heat steam.

The balance includes all other components required for the process before electrolysis (AC/DC power converter, water deionizer, and storage tank) and after electrolysis (dehydration unit to purify H2).

Executive summary (3/10) Other green hydrogen production sources include dark fermentation, microbial electrolysis, and photolytic conversion, which are still in laboratory stages. 8 Note: LCOH calculation: (present value of investments + present value of costs)/(present value of yearly hydrogen production), in $/kg Hydrogen can be Hydrogen is a versatile energy carrier that allows a broad range of conditioning options, which can be either a physical transformation or a chemical reaction, to increase volumetric energy density or converted into improve handling. multiple energy There are two major categories of conditioning. Physical transformation includes compression and carriers, offering liquefaction. Chemical combination includes metal hydrides, liquefied organic hydrogen carrier, and other a broad range of chemicals such as ammonia: – Compression increases hydrogen pressure (up to 1,000 bars) to improve energy volumetric density storage and and decrease storage and transportation costs. However, even at high pressure, energy density transportation remains much lower than other solutions. – Liquefaction is cooling gaseous hydrogen down to -253°C to increase volumetric energy density with options potential losses as a result of boil-off. – Metal hydrides is the binding of certain metals with hydrogen in a stable solid structure, which can be stored in cans. Metal hydride cans are particularly well-suited for transportation purposes, such as scooters and cars) as they can easily be replaced and do not require large recharging infrastructure deployment. – Liquefied organic hydrogen carrier (LOHC) is the addition of hydrogen atoms to toluene to convert it into methylcyclohexane (MCH). MCH is liquid in ambient conditions, which avoids boil-off losses and Hydrogen value chain: limits explosion risks. However, toluene needs to be shipped back to a production plant, and MCH upstream and midstream - toxicity is high. Conversion, storage, and – Hydrogen can also be converted into ammonia and leverage current ammonia production and transportation technologies transportation infrastructure. Ammonia can be used directly as a chemical for the fertilizer industry. However, reconversion to hydrogen process has a low efficiency. (Section 2.2: pages 49–60) Depending on conditioning, hydrogen can be stored and transported in different ways. Tanks are suited to store compressed gaseous hydrogen, liquefied hydrogen, LOHC, and ammonia and can easily be transported by trucks, trains, or ships. Hydrogen can also be stored in dedicated pipelines (in gaseous or as ammonia) or injected into gas pipelines (in gaseous form, if concentration does not exceed a certain limit, which depends on the infrastructure and consumption points). Finally, hydrogen can Executive summary (4/10) be stored in salt caverns for long-term reserves.

9 While brown Today, Hydrogen produced from Brown sources is two to ten times less expensive than from Green technologies are or Blue sources the most mature, The Levelized Cost Of Hydrogen is the average discounted cost of hydrogen generation over the lifetime of the considered plant. It is used to compare the production cost of hydrogen from the various sources. blue and green For brown hydrogen production sources, LCOH depends on technology and feedstock price, and should close the commonly range around 90¢ to $2.10 per kg. The SMR average estimated price is currently about $1.40 gap by 2030; per kg, with LCOH mainly driven by the price of natural gas (about 75% of LCOH) and capex (about 22%). conditioning For blue hydrogen production sources is ~50¢ per kg higher than brown sources, and is estimated to transportation range between $1.50 and $2.50 per kg. It is still cheaper than electrolyzer but requires carbon storage remains costly caverns. The cost of CCS highly depends on the technology used, which will all have different efficiency (1/2) (up to 90% capture rate). For green hydrogen production sources, LCOH depends on technology, electricity price, and electrolyzer size as it benefits from economies of scale. Electrolyzers LCOH is estimated to range between $2.50 to $9.50 per kg depending on technologies. Hydrogen value chain: – Alkaline electrolysis (AE) is currently the cheapest available technology with an average estimated upstream and midstream – LCOH of $4.00 per kg. Maturity and costs – The Proton exchange membrane (PEM) average estimated LCOH is $5.00 per kg, and SOEC $7.40 per kg. LCOH is mainly driven by electricity cost (71% for a PEM) and capex (21% for a PEM). (Section 2.3: pages 61–77) For green hydrogen, access to cheap renewable electricity could help reduce LCOH of electrolysis. However, renewable electricity from solar and wind power sources are not dispatchable and provide relatively low load factors. Thus, the capex part would dramatically increase. Reaching economical competitiveness with blue sources (LCOH of $2 to $3 per kg) requires low electricity prices and high load factor (commonly above 90%)

By 2030, LCOH of blue hydrogen is expected to go as low as $1.30 to $1.90 per kg, and between Executive summary (5/10) $1.60 to $3.80 per kg for green hydrogen, depending on the electrolysis technology used. R&D improvements will help reduce capex, increase lifetime and improve efficiency. The main focus will be 10 on increasing density, lowering catalysts, and scaling up the balance of system components. While brown Hydrogen LCOH is highly impacted by conditioning and transportation steps, which can double its LCOH cost. technologies are the most mature, LCOH from conditioning highly varies depending on technologies. blue and green – Compression and tank storage is the cheapest option (20¢ to 40¢ kg) with no associated reconversion should close the costs. – Liquefaction LCOH is $1.80 to $2.20 per kg, which could be reduced with improvements on boil-off gap by 2030; losses. As liquefied hydrogen naturally tends to become gaseous at ambient temperature, no associated conditioning reconversion process is required. – Ammonia conversion LCOH is $1.00 to $1.20 per kg, and reconversion LCOH is 80¢ to $1.00 per kg. transportation Finally, LCOH for LOHC is 40¢ per kg while reconversion can vary from $1.00 to $2.10 per kg. remains costly (2/2) LCOH from transportation depends on hydrogen conditioning, transportation mean used, and distance travelled: – For long ranges (more than 1,000 km), ships and pipelines are possible options. Pipelines can carry compressed gaseous hydrogen or ammonia, while ships can be used for liquefied hydrogen, LOHC, or ammonia. For a 3,000 km journey, transporting gaseous hydrogen through a pipeline is about $2.00 per Hydrogen value chain: kg. For the same distance but with liquefied hydrogen transported by ship, LCOH is about $1.50 per kg. upstream and midstream – However, below 2,000 km of travelled distance, pipelines appear to be cheaper. Maturity and costs – For short ranges (less than 1,000 km), trucks, rail, and pipeline are possible options. Compressed gaseous, liquefied, LOHC, and ammonia can be transported by trucks, while pipelines can carry only (Section 2.3: pages 61–77) compressed gaseous hydrogen and ammonia. For a 500 km journey, transporting compressed gaseous hydrogen by trucks costs about $2.00 per km versus about 40¢ to 80¢ for pipelines.

Decentralized production sources or on-site consumption allow skipping the midstream value chain.

Executive summary (6/10)

11 Hydrogen is Hydrogen versatility allows for multiple applications as a feedstock, as a gas, or for electricity generation (fuel cells). As of 2019, about 115 Mt of pure and mixed hydrogen are consumed annually, of being tested or which 94 Mt is for industrial processes. As a feedstock, hydrogen is mainly used in oil refining, ammonia implemented in a synthesis, and steel manufacturing. Hydrogen can also be mixed with in a fuel cell to deliver a direct current and release water and heat, with an efficiency of about 60%. Hydrogen can be burnt in a broad range of dedicated turbine coupled with an alternator to produce electricity or be injected into gas network or a industrial processes, dedicated pipeline network to release heat at consumption point. mobility solutions, Industrial processes mainly use hydrogen as a feedstock with on-site production power generation, In the chemicals industry, hydrogen can be combined with nitrogen to form ammonia (Haber–Bosh and gas energy process). Ammonia can be later converted into fertilizers. Hydrogen can also be combined with CO and CO2 to form methanol in a catalytic reaction. Methanol can be further converted into polymers or olefins or be used as a fuel. About 44 to 45 Mt of hydrogen are consumed annually for chemicals synthesis. In oil refining, hydrogen is used in hydrodesulfurization to remove sulfur contents in crude and in hydrocracking processes to upgrade the oil quality of heavy residues. About 38 MT of hydrogen are consumed annually for chemicals synthesis. In the steel industry, hydrogen is used in a basic oxygen furnace (BOF) and in direct reduction of iron (DRI) to convert iron ore into steel. Hydrogen can come as a by-product of BOF but needs to be produced Key hydrogen applications on-site in DRI. Annual consumption is about 13 MT.

(Section 3: pages 78–113) In mobility, hydrogen is converted to electricity through a fuel cell to power an electric engine. Several types of fuel cells exist and are characterized by various combination of electrodes and electrolytes, with different requirements and performance. As of 2019, hydrogen deployment in mobility has been limited to bikes, scooters, cars, trucks, buses, and trains. Hydrogen use for marine roads and aviation is still in early-stage development.

In power generation, hydrogen will be mainly used as a energy storage vector. In peak times, hydrogen can be supplied to stationary fuel cells or gas turbines that will provide clean electricity to the grid. Executive summary (7/10) By 2050, pure hydrogen consumption could grow eightfold to 540 MT per year, mainly driven by 12 transportation and industrial processes. Private companies Companies specialized in the hydrogen value chain are partnering with a broad range of other industrials to capture value. and governments M&A activity has been growing over the past few years, with companies from different industries partnering are investing more to develop new business models based on hydrogen. The Hydrogen Council was created in 2017 by 30 private companies from industry, transportation, and energy to accelerate investments in hydrogen and in the clean encourage key stakeholders to back hydrogen as part of the energy mix. Governments are putting in place regulations and mechanisms to promote hydrogen deployment. Multiple countries have launched support initiatives and incentives mechanisms to accelerate hydrogen deployment, mainly in the transportation sector. Countries have developed specific strategy cases based on their capabilities and economical situations:

– In Europe, Hydrogen Europe is partnering with the European Commission to identify legal barriers that could delay or deter investments in hydrogen. The objectives are to integrate more renewables and decarbonize mobility, heating, and industry. – In the United States, multiple incentives have been given to fund hydrogen R&D in public laboratories and private R&D departments. Between 2004 and 2017, the Department of Energy was granted $2.5 billion to develop fuel cell electric vehicles (FCEV), build a mature hydrogen economy, decrease oil Business models - Policies and dependency, and create a sustainable energy economy. competition landscape – In Middle Eastern oil-rich countries, a blue hydrogen economy is being studied as a transition from oil exports to hydrogen exports and the use of CO2 for enhanced oil recovery. (Section 4.1: pages 116–124) – Japan was the first country to adopt a "Basic Hydrogen Strategy" and plans to become a “hydrogen society”, targeting commercial scale capability to procure 300,000 tons of hydrogen annually. – Australia adopted a National Hydrogen Strategy in late 2019 to open up opportunities in domestic use as well as export market.

Executive summary (8/10)

13 Most hydrogen New business models are developing for both blue and green solutions to take advantage of decarbonization. Centralized blue production sources are being considered for industrial areas, such as business models the Port of Rotterdam, where hydrogen could feed local industries and power plants. Electrolyzer coupled require policy with renewable energy is being considered as it could both accelerate renewable energy integration on the support, with grid and decarbonize end applications such as gas energy, power generation, industry, and mobility. heavy-duty Hydrogen-based solutions provide decarbonization solutions that are not yet competitive with transportation traditional solutions. The relevance of business cases has been assessed based on three criteria: economical viability, environmental impact (end-to-end CO2 emissions), and other benefits, such as being the most reduced energy dependency, grid stabilization, job creation, and air-quality improvement in populated promising one areas. All hydrogen solutions appear to be more expensive than conventional solutions. However, in certain cases, CO2 emissions can be significantly reduced. The carbon abatement cost has been in the current calculated to assess the relevance of opportunities for hydrogen and is compared with the IPCC carbon context (1/2) price target of $220 per tCO2 by 2030 in a +2°C trajectory. For a centralized blue production source feeding nearby industries, which would require adjustments to accept hydrogen rather than conventional fuels and feedstocks, mainly in gas power plants and refineries, the carbon abatement cost would be $110 to $215 per tCO2 for 27 to 130 mtpa of CO2 avoided. Electrolyzer business models will be based on a power-to-x scheme. The surplus of electricity will be used Business models - Business to produce hydrogen, which will later be used as a fuel for gas heating, chemicals, power generation, or cases mobility. However, depending on the electricity source, the carbon impact and LCOH will differ. Electrolyzer can be connected to the grid and running at about 90% load factor, connected solely to a renewable (Section 4.2: pages 125–186) source and be dependent on the source load factor (maximum 40% for wind power plants) or combine both sources:

– Power-to-gas. Hydrogen is injected into gas networks, either blended with natural gas with a certain volumetric limit, which depends on gas grid specifications and tolerance to hydrogen, or undergoing a methanation process to form methane. Injection is easier and cheaper, with a carbon abatement cost of $220 to $320 per tCO2. Adding a methanation step adds complexity and costs, leading to an abatement cost of $1,100 to $2,800 per tCO2. Executive summary (9/10) – Power-to-power. Stored hydrogen is released in a fuel cell to deliver power at peak time rather than starting a coal or gas turbine. Compared with a coal turbine and depending on the electricity source that 14 powered the electrolyzer, 40 to 790 gCO2 per MWhe could be saved at an abatement cost between $120 and $3,000 per tCO2. Most hydrogen – Power-to-molecule. Electrolyzer is built on a refinery or a chemicals production plant in addition to a SMR and provides hydrogen when electricity surplus is available. However, scalability is limited: business models electrolyzer (pilot plant) in the Wesseling refinery in supplies only 1% of hydrogen needs to require policy the refinery but could spare about 9 kgCO2 per kgH2 at a cost of about $120 to $150 per tCO2. support, with – Power-to-mobility. Hydrogen is produced on site at the refueling station. If overall LCOH drops down heavy-duty to $4 to $5 per kg, making it competitive with gasoline, the vehicle acquisition cost is expected to remain higher, increasing total cost of ownership. The CO2 abatement cost is $570 to $2,000 per tCO2 for transportation passenger cars, $120 per tCO for buses, and $60 per tCO for trains. being the most 2 2 promising one Lithium–ion batteries for electricity storage and mobility are the main competitor to hydrogen on in the current its segments. context (2/2) – Lithium–ion batteries are suited for intra-day storage and frequency stabilization, whereas hydrogen is more suited for long-term seasonal storage. – Battery electric vehicles are the main competitor of hydrogen in the mobility segment, in particular for light-duty vehicles. (Heavy-duty BEV such as trucks and buses are limited by battery-size Business models - Business requirements.) However, BEV are limited in range (maximum of 650 km with an average of 100-200 km cases in real-life conditions) and long recharging time. A FCEV is expected to be more competitive than a BEV for a journey of more than ~300 km. For trains, hydrogen is the cheapest clean solution if the rail line is (Section 4.2: pages 125–186) not electrified, which avoids high capex. However, on electrified lines, electric trains are already cheaper than diesel and hydrogen trains. – The LCOE produced is expected to be comparable between the two technologies: $150 to $250 per MWhe.

Indirect value creation, such as local job creation and grid stabilization, should be considered for hydrogen valuation. Hydrogen business solutions generally provide additional indirect value that are not Executive summary (10/10) considered in its economic assessment. Developing a hydrogen economy would require gaining economies of scale and developing large production hubs that could supply multiple applications. To 15 prioritize investments, carbon abatement cost and carbon avoided, as well as favorable impact on local economies, could be used as metrics to assess hydrogen’s relevance compared with other solutions. Hydrogen’s role in the energy transition

16 Some orders of magnitude in 2019 5 Executive summary 6 1. Hydrogen’s role in the energy transition 16 2. Hydrogen value chain: upstream and midstream 25 2.1 Production technologies 27 2.2 Conversion, storage, and transportation technologies 49 2.3 Maturity and costs 61 3. Key hydrogen applications 78 3.1 Overview 80 3.2 Feedstock 84 3.3 Energy 90 3. Business models 114 4.1 Policies and competition landscape 116 4.2 Business cases 125 Appendix (Bibliography & Acronyms) 187

17 Global warming Key consequences of +1.5°C and +2°C global warming by 2100 can have a dramatic impact +1.5°C +2.0°C on ecosystems Global mean rise 0.26 to 0.77 m 0.36 to 0.87 m and societies sea level (medium confidence) (medium confidence)

8% of plants 16% of plants Biodiversity losses 6% of insects 18% of insects (among 105,000 species studied) 4% of vertebrates 8% of vertebrates “Climate-related risks for natural (medium confidence) (medium confidence) and human systems are higher for global warming of 1.5°C than at present but lower than at 2°C 70–90% More than 99% Decline of coral reefs (high confidence) (very high confidence) (high confidence). These risks depend on the magnitude and rate of warming, geographic location, levels of development Frequency of disappearance of Once per century Once per decade and vulnerability, and on the the Arctic ice cap (high confidence) (high confidence) choices and implementation of adaptation and mitigation options (high confidence).” Decrease in global annual catch 1.5 million tons 3 million tons (medium confidence) (medium confidence) – Intergovernmental Panel on for marine fisheries Climate Change

Average increase of heat waves +3°C +4°C (high confidence) (high confidence) Hydrogen’s role in mean temperature 1 energy transition

Sources: “Special report on the impacts of global warming of 1.5°C above pre-industrial levels and related global greenhouse gas emission pathways (SR1.5),” Intergovernmental Panel on Climate Change, 2018; 18 Kearney Energy Transition Institute analysis GHG emissions Remaining carbon budget At current emission (2018, GtCO eq per year) (2018, GtCO eq) levels, we only have 2 2 about 10 years left in the estimated Carbon GHG Other GHG

carbon budget for 55 53 4.500 global warming of 50 1.5°C 33 percentile 45 43 4.000 +2080 50 percentile Others 67 percentile 40 LUC(1) Already emitted (1850–2017) 35 3.500 +1500 30 Gas

25 3.000 20 Oil +840 +1.170 +580 15 2.500 10 +420 Coal 5 2.200

0 0 CO2 CH4 N2O F-gases Total 2.0°C target 1.5°C target

Hydrogen’s role in 1 energy transition

1 LUC : deforestation and other land use change 19 Sources: Global Carbon Budget 2018; IPCC (2018) “SR5–Chapter 2”; BP (2015) “Statistical review”; Kearney Energy Transition Institute analysis Current GHG emissions by segment Hydrogen potential use cases for decarbonization Hydrogen could (GT CO eq/y) partially address 2 GHG emissions as Use case Method of H2 substitution a fuel substitute in ~44 sectors 5% Others

responsible for Not substitutable Agriculture, more than 65% of 27% by H2 forestry & other global emissions. land use1

6% Building – Heating networks with H2 (blended or full H2) – Circular economy with CCU/CCS2 14% Industry – Clean feedstock for oil refining & chemicals

Partially – Full cell electric vehicle (passenger cars, trucks, substitutable by 17% Transport trains) H2 – Synthetic fuels (airplanes, ships) (Either as fuel for 9% Electricity & heat heat and power or as Oil & gas, others feedstock for – Integration of renewables: industry) – Large scale storage for inter-seasonal storage 22% Coal – Geographic balance – Grid stabilization

Hydrogen’s role in 1 energy transition

1. Includes land use, emissions from cattle, etc.; 2. Carbon Capture Utilisation/ Carbon Capture Storage 20 Sources: IEA; FAO; Kearney Energy Transition Institute analysis Hydrogen Overview of H2 value chain and technologies provides multiple pathways enabled by various Upstream Midstream and downstream Consumption Conversion, storage, Production technology End-use applications production transport, and distribution technologies • Steam methane reforming (SMR) • Hydrogen gas • Oil refining • Gasification • Chemicals production and applications • Liquid hydrogen across its value • Autothermal reforming (ATR) • Iron and steel production

• Pressurized combustion reforming • NH3 Industrial • High-temperature heat applications

chain Conversion • Food industry • Chemical looping • Liquefied organic hydrogen • Concentration solar fuels (CSF) carrier (LOHC) • Light-duty vehicles • Heavy-duty vehicles • Heat exchange reforming (HER) and • Trucks • Maritime Thermochemical gas heated reforming (GHR) • Pyrolysis • Trains Mobility • Rail • Aviation • Other technologies (such as microwave)

Transport • Pipeline • Co-firing NH3 in coal power • Alkaline electrolysis (AE) plants - • Tankers • Proton exchange membrane (PEM) • Flexible power generation Power Power

lysis • Geological storage • Back-up and off-grid power • Solid oxide electrolyzer cell (SOEC) generation Electro • Other technologies (such as chlor-alkali) supply • Storage tanks • Long-term, large-scale storage • Dark fermentation • Blended H2 • Microbial electrolysis Storage • Chemical reconversion

Gas • Methanation Energy Other • Photoelectrochemical • Liquefaction and regasification • Pure H2

Hydrogen’s role in 1 energy transition Brown H2 Blue H2 Green H2

21 Sources: Kearney Energy Transition Institute analysis Hydrogen will Simplified value chain of hydrogen-based energy conversion solutions1 potentially play a major role in the Energy Transition Gas network Hydrogen network Power network Liquid fuel network as a link between Power grid multiple energy Power-to-mobility Fuel cell electric vehicle Water Oxygen Refueling sources and Power-to-power stations industrial Internal combustion Wind turbine Electrolysis Hydrogen engine vehicle applications storage Upgraded and Green hydrogen synthetic fuels Solar PV Natural gas vehicle

H2 Fuel cells Refineries

Blue hydrogen Power-to-chemical Combustion Blended gas turbines Processing2 CCS Petroleum products Power-to-gas Chemical Ammonia plants CO2 Methanation Blending

CH4 H2 Coal and oil

Natural Gas Grid

Hydrogen’s role in 1 energy transition

Simplified value chain. End uses are non-exhaustive; 2. Several possible options (e.g. Steam methane reforming; autothermal reforming; chemical looping, etc.) 22 Sources: Kearney Energy Transition Institute Hydrogen is Hydrogen substitution matrix competing with Potential application of other decarbonisation technologies Potential role of hydrogen other low carbon (2030+ time horizon) solutions that Total oil Overall score for Sector Biomass Electrification consumption Carbon Capture decarbonisation Hydrogen Opportunity for (consuming (Bio-fuels and (renewables + tackle similar usage Storage1 solutions (other Applicability Hydrogen fossil fuels) biogas) storage) applications (Mtoe3, 2018) than hydrogen)

Aviation & 2 1 0 ++ 1 Shipping 600 ▼ Rail2 29 2 1 0 ++ 3 ▲ Trucks 4 2 0 +++ 3 ▲ 2,110 Road 4 4 0 +++ 3 ► Industry & 0 0 2 ++ 2 petrochem 915 ►

Heat & 4 3 2 +++ 2 power 615 ▼

– Hydrogen not mature for commercial aviation application, more progressing for shipping (small boats)

– H2 application for rail is relevant to replace diesel engine in non-electrified rails – H2 relevant for heavy duties vehicle (trucks and buses, for which battery weight is a major issue) – H2 is required for petrochemicals, and is generally produced by reforming of methane (Brown) – Relevant for heat and power but expensive and already addressed by Renewables

Hydrogen’s role in 1 Maturity of Commercial stage Research stage Maturity of +++ At least one commercial option energy transition ++ At least one pilot project technologies: Pilot stage Not an option decarbonisation options: + Ongoing R&D investment

Use of CO2 from CCS is not considered in the range of possible solutions 2. Based on 2017 figures 3. Million tonnes oil equivalent 23 Sources: IEA WEO 2019; Kearney Energy Transition Institute Hydrogen is the Description lightest molecule – Name: Hydrogen (“water former” in ancient Greek) with the highest – State in ambient conditions: gaseous, diatomic (H2) – Properties: gravimetric energy – Smallest, lightest, oldest, and most abundant element in the universe density – Mainly found in combination with carbon (hydrocarbons), oxygen (water), or nitrogen (ammonia) – Colourless, odourless, tasteless, non-toxic, and non-metallic – Highly diffusive and oxidizing – Reactants: Reacts spontaneously with oxygen, chlorine, and fluorine – Combustion: Comparison of specific energy (energy per mass or gravimetric 2H + 2O 2 H O + 572 kJ = 286 kJ/mol density) and energy density (energy per volume or volumetric density) for several fuels based on lower heating values 2 2 → 2 ΔH −

Hydrogen fact card Advantages Disadvantages Physical properties

– High energy density – Rare in natural Density (kg/m3) 0.089 (gas) – No CO2 emissions H2 form 71 (liquid)1 during combustion – High CO2 – Abundant on earth emissions for Boiling point (°C) -253 °C (water and industrial Lower heating value (MJ/kg) 120 hydrocarbons) production Specific energy, liquefied – Multiple – Large ignition range (MJ/kg) 8.5 applications in – Corrosive industrial and Ignition range (% of gas 4–77% energy sectors in air volume) Hydrogen’s role in 1 energy transition

1 Gas: 0°C, 1 bar; liquid: -253°C, 1 bar 24 Sources: “,” US Department of Energy; Kearney Energy Transition Institute Hydrogen value chain: upstream and midstream

25 Some orders of magnitude in 2019 5 Executive summary 6 1. Hydrogen’s role in the energy transition 16 2. Hydrogen value chain: upstream and midstream 25 2.1 Production technologies 27 2.2 Conversion, storage, and transportation technologies 49 2.3 Maturity and costs 61 3. Key hydrogen applications 78 3.1 Overview 80 3.2 Feedstock 84 3.3 Energy 90 3. Business models 114 4.1 Policies and competition landscape 116 4.2 Business cases 125 Appendix (Bibliography & Acronyms) 187

26 Global hydrogen production Key About 118 Mt of H2 (2018, Mt H2, % of total production) considerations are produced each 118 48 year and release (33.1%) – H2 production has Consumed reached 118 Mt per about 830 Mt of onsite 18 year, 59% of which 3 0 (12.1%) comes from (2.0%) (0.2%) CO2, mainly from 9 MT dedicated sources. Industrial 48 consumed – Use of fossil fossil fuels onsite 13 by-product (41%) (9.2%) fuels for H2 production 14 represented (9.7%) about 6% of

Steel Refinery2 Chlorine3 From RES Others Total global demand for natural gas and about 2% of global demand 0 17 0 0 0 for coal. (0.3%) (0.2%) (0.0%) (0.1%) (14.2%) – Global CO2 emissions from H2 represented 830 Mt CO2 Dedicated 70 equivalent. – Overall, 0.6% of production (59%) 16 (13.6%) H2 is from renewable or fossil fuels plants equipped with CCS. – About 3 Mt of H2 Coal Oil2 With CCS3 Electrolysis Electrolysis Total are lost or not from RES recovered (for Hydrogen value chain - 1 example, during 2.1 Total Production technologies Clean production purification). 1 1 Mtoe = 0.35 Mt H2 pathway 2 35% of refinery H2 needs come as a by-product. 3 World chlorine production: about 100 MT per year – ratio of 1/35 tH2/tCl2 27 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute H production technologies overview H2 conversion 2 technologies H2 can be split into Primary source Conversion technology category Steam methane reforming (SMR) thermochemical, No electrolysis, Oil and gas Gasification microbial, and Autothermal reforming (ATR) C Pressurized combustion reforming C photolytic S Yes Thermochemical Chemical looping

Coal Concentration solar fuels (CSF)

Gas heated reforming (GHR) and heat exchange reforming (HER)

Pyrolysis Brown1 Biomass, Other technologies (such as microwave process) H2 biofuels, and organic Alkaline electrolysis (AE) matter Water Proton-exchange membrane (PEM) No V and brine R Solid oxide electrolyzer cell (SOEC) E electrolysis Blue1 Other technologies H2 Brine Dark fermentation Yes Microbial Microbial electrolysis

Other technologies

Photolytic Photoelectrochemical and other technologies Hydrogen value chain - Water 2.1 Green Production technologies Other technologies H2

CCS Optional CCS to reduce carbon footprint VRE Use of VRE to produce electricity Technologies subject to in-depth analysis 28 1 Only for fossil fuels: renewable biomass-based thermochemical production can be considered as green H2. Sources: Shell; International Energy Agency; Kearney Energy Transition Institute Natural production Description Overview The only exploited natural source: Mali sources of H2 have – In the 1970s, scientific research highlighted a natural H2 presence mainly in the following: been found at – Mid-ocean ridges and hydrothermal vents, where different places hydrothermal fluids contain up to 36% of H2 – Volcano gases, such as at Etna, Augustin, and but are not Kliuchevskoi, with H2 concentration varying from 50 to 80% exploited – Peridotite mountain (Oman, Philippines, and Turkey) – Some mines and in very deep wells – Hundreds of geological structures emitting H2 have recently been found in deep oceans, in mountains where oceans used to be million years ago, and in continental crust. – Depending on the production site, H2 is formed differently: – In ocean rifts or mountains (which were formerly an ocean), ferrous minerals are oxidized by water to form Fe3O4—water is reduced and releases H2. Fact card: Natural H2 – The origin of H is still unclear for volcanoes. Bourakebougou field production sources 2 City Bourakebougou Exploitation Hydroma (Petroma) Operation Discovery 1980 start 2011 Number of Number of reservoirs 5 wells 18 Pros Cons Deep (m) 100–1.700 Electricity and light Usage for about 100 H2 content ~98% families 1 – Non-polluting, free – Unclear view on Key features estimates source global resources Below manufactured – Non-mature Current cost estimate ($ per kgH2) Hydrogen value chain - H2 2.1 Production technologies exploitation H emission rate (kgH per day) Up to 2,400 per technologies 2 2 structure

1 Depending on factors such as location and available resources, estimates of the exploitation price at the Bourakebougou field are below manufactured hydrogen, either from fossil fuels or electrolysis. 29 Sources: Afhypac; International Journal of Hydrogen Energy (2018); Kearney Energy Transition Institute Electrolysis was History of H2 production technologies the first H2 production technology deployed but was Discovery of First SMR First commercial First commercial Water photo- electrolysis by commissioned in 30-bar electrolyzer gasification plant electrolysis overtaken by W. Nicholson the United States (Lurgi) in the United efficiency reaching and A. Carlisle by Standard Oil States 18% fossil fuel-based First First naphtha First solid Electrolysis Syngas production technologies in gasification reforming plant oxide production capacity from coal patent by in the United electrolyzer capacity gasifier reaches 250 the early 1970s Robert Gardner Kingdom cell reaches 8 GW GWth

1800186119001913 1930 1939 1951 1962 1966 1972 70s 1997 2005 2006 2008 20172018 2020

BASF patent First 10,000 Largest SMR Largest PEM for a nickel Nm3/h AE plant electrolyzer catalyst for electrolyzer commissioned to be built at reforming (315 tpd) Shell refinery (1.3 kT per First gasifier year) unit by First microbial Market size for Siemens First PEM Take-off of SMR electrolyzer, technologies due electrolysis cell electrolyzers: First bipolar built by G.E. to natural gas approach +100 MW/y electrolyzer by Oerlikon discovery Hydrogen value chain - 2.1 Production technologies Fossil fuel based Electrolysis

30 Sources: Johnson Matthey; Norsk H Hydroydro; SRI (2007); FuelCellToday (2013); Afhypac; Royal Society of Chemistry; Kearney Energy Transition Institute Among production Comparison of H2 production technologies technologies, LCOH Efficiency Advantages and risks thermochemical 2019, kWh per $ per kg % LHV Feedstock Emissions Scalability Footprint Other sources benefit kg Fossil fuel 11 kgCO / 200 to 500 Steam methane 0.9–1.8 52 64% 2 n.a. n.a. from lower reforming (SMR) Biomass kgH2 tpd cost and high Fossil fuel 20 kgCO / 500 to 800 Gasification 1.6–2.2 41–47 70–80% 2 n.a. n.a. efficiency but are Biomass kgH2 tpd Fossil fuel 9 kgCO / 500 to GHG emitters Autothermal reforming n.a. 40–42 78–82% 2 n.a. n.a. Biomass kgH2 1000 tpd

Fossil fuel n.a. 2.2–3.4 47–66 50–70% 50 tpd n.a. n.a. Pyrolysis Biomass (lower3) Thermochemical sources

Water Waste 2.6–6.9 48–64 52–69% <70 tpd 200m2/tpd Alkaline electrolysis (AE) Electricity water mgt. Depends Proton-exchange 60–77% Water on Rare 3.5–7.5 43–60 <300 tpd2 50m2/tpd membrane (PEM) up to 86% Electricity electricity materials electrolysis source World Electrolysis Steam avg. 19-21 High T° Solid oxide electrolyzer 5.0–8.5 40–441 74–81%1 n.a. n.a. cell (SOEC) electrolysis Electricity kgCO2/ heat kgH2 Water n.a. n.a. n.a. n.a. n.a. Microbial electrolysis Electricity

Water Research Biomass dark n.a. 47 70% - n.a. n.a. Microbial fermentation Biomass stage

Hydrogen value chain - Water 2.1 Photoelectrical synthesis n.a. n.a. n.a. - n.a. n.a. Production technologies P.S. Sunlight

1 Excluding the energy required for heat to vaporize water 2 Expected maximum size of PEM electrolyzers 3 Carbon products are mainly solid carbon residues. 31 Sources: IEA, “The Future of Hydrogen,” June 2019; Commonwealth Scientific and Industrial Research Organisation; Institute of Energy Economics Japan; D.B. Pal et al (2018); S. Reza et al (2014); IEA Greenhouse Gas R&D Programme; Foster Wheeler; Nel; Kearney Energy Transition Institute Power Description H2 is separated Condensates – Step 1: Desulfurization treatment from CH4 at a high Steam Export steam – Natural gas is naturally mixed with sulfur, which is turbine removed thanks to H . temperature in a 2 Flue gas – Step 2: Reforming Natural steam methane gas H – CH4 and high-temperature steam under 3–35 bar 2 reformer while pressure are mixed with nickel catalyst to produce 1 2 3 4 H2, CO, and a small amount of carbon CO2. Heat for Desulfu- Pre- Reformer HT shift PSA producing CO the highly endothermic reaction is provided by rization reformer (~900 °C) reactor system burning fuel gas. and CO2 (1) CH + H O CO + 3 H = +206 MJ/kmolCH Recycled H2 – Step 3: Water–gas shift reaction 4 2 2 4 Hydrogen plant Tail gas – The carbon⇌ monoxide and ΔHsteam are then reacted to Combustion Fuel produce and more hydrogen in what air is known as water–gas shift reaction. Iron-chromium and copper-zinc are used as catalysts. (2) CO + H O CO + H = 41 MJ/kmolCH

– Step 4: 2Pressure2 swing2 adsorption 4 Fact card: Steam ⇌ ΔH − Key feature estimates – In the final step, H2 is separated from the tail gas methane reforming through a selective adsorption. Current cost estimate ($ per kgH ) 0.9–1.9 (1)+(2) C + O CO + 4H = 165 MJ/kmolCH 2 50% of the H2 Typical plant size (kgH per day) 200,000 produced comes 2 𝟒𝟒 𝟐𝟐 2 2 4 from water 𝐇𝐇 𝟐𝟐𝐇𝐇 ⇌ ΔH Feedstock use (kgCH4 per kgH2) 3.43 Water use (L per kgH2) 4.5 Pros Cons Operating CO2 emissions 9–12 (kgCO2 per kgH2) – Established – High temperature Efficiency (%, LHV) 64 technology required – Integration potential – Requires purification Temperature (°C) 750–1,100 Hydrogen value chain - 2.1 Purity of H Production technologies with refineries by PSA 2 99.9% – CO2 emissions Primary energy source Natural gas – Dependence on natural gas 32 Sources: Commonwealth Scientific and Industrial Research Organisation; Institute of Energy Economics Japan; D. B. Pal et al (2018); S. Reza et al (2014); International Energy Agency Greenhouse Gas R&D Programme; Foster Wheeler; Kearney Energy Transition Institute Gasification is a Description Overview of technologies

substoichiometric – Step 1: Coal (or other feedstock1) is heated in a Moving-bed Fluidized-bed Entrained-flow reaction occurring at pyrolysis process at 400°C, vaporising volatile gasifier gasifier gasifiers component of feedstock in H2 , CO, CO2 , and CH4. a high temperature – Biomass tends to have more volatile component than coal. where fossil fuel is – Step 2: Oxygen is added in the combustion chamber, converted to syngas and char undergoes gasification releasing gases, tar vapors, and solid residues. containing mainly H2 – Dominant reaction is a partial oxidation: oxygen is and CO at sub-stoichiometric level—at a high temperature (800°–1,800 °C). C H + n/2 O n CO + m/2 H MJ/kmol n n = 1 = 36 – Step 3: Water–gas shift reaction to convert CO in CO m 2 2 − 2 nCO + n H O ⇌n CO + n H ΔH MJ/kmol 2 n = 1 = 41 – Step 4: Purification through methanation or PSA 2 2 − – Operating conditions⇌ dependΔH on coal type, properties of resulting ash, gasification technology: Fact card: Gasification — high temperature favors H2/CO, high pressure Key feature estimates favors H /CO . partial oxidation 2 2

Current cost estimate ($ per kgH2) 1.6–2.2

Typical plant size (kgH2 per day) 500.000

Feedstock use (kg coal per kgH2) 8.0

Water use (L per kgH2) 9.0 Pros Cons Operating CO emissions 2 20 (kgCO2/kgH2) – Abundant fuel, adaptable to – Purification required Efficiency (%, LHV) all hydrocarbons, biomass, 70 – 80% and waste Temperature (°C) 800 – 1,800 °C Hydrogen value chain - – Easy capture of CO2 from 2.1 Purity of H2 More than 99.5% Production technologies the syngas, especially in integrated gasification Primary energy source Coal, biomass, oil, combined cycle and gas

33 1 Feedstock may include coal, biomass, solid waste, heavy oil, oil sands, oil shale, and petroleum coke. Sources: “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; “Syngas Production from Coal,” International Energy Agency Energy Technology Network, 2010; Black & Veatch; Afhypac; Kearney Energy Transition Institute Autothermal Description Overview of technologies reforming is a – ATR is mainly used with natural gas and combines endothermic reaction of steam reforming and combination of a exothermic reaction of oxidation. exothermic POX – Feedstock, steam, or sometimes carbon dioxide and dioxygen are directly mixed before pre-heating. reaction and a – ATR is described with two reaction zones: endothermic – Combustion zone, where partial oxidation occurs producing a mixture of carbon monoxide and steam reforming hydrogen (syngas) – Catalytic zone where the gas leaving combustion zones reach thermodynamic equilibrium – Reaction can be described in the following equations: – Using steam: 4 CH4 + O2 + 2 H2O 4 CO + 10 H2 – Using CO2: 2 CH4 + O2 + CO2 3 CO + 3 H2 + H2O + Heat → – Water–gas shift reaction happens→ after ATR reaction CO + H O CO + H – CO at exit is less than in SMR because of a higher Key feature estimates Fact card: Autothermal 2 2 2 2 reforming (ATR) operating temperature that⇌ restricts exothermic water gas shift reaction. Current cost estimate ($ per kgH2) w. CCS n.a. Typical plant size (kgH2 per day) Up to 1,500,000

Feedstock use (kgCH4/kgH2) 2.8

Pros Cons Water use (L/kgH2) n.a. Operating CO emissions 2 9 – Compact design and low – Non-uniform axial temperature (kgCO2/kgH2) investment distribution with “hot-spots” Efficiency (%, LHV) 78–82 – Variable H2/CO ratio, fitting – Fuel evaporation Hydrogen value chain - gas-to-liquid requiring a 2:1 – Coke formation Temperature (°C) 980–1200 2.1 Production technologies ratio Purity of H2 95.5% Primary energy source Hydrocarbons 34 Sources: “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Air Liquide; Haldor Topsoe, International Energy Agency Greenhouse Gas R&D Programme; “Blue hydrogen as accelerator and pioneer for energy transition in the industry,” H-vision, July 2019; Afhypac; Kearney Energy Transition Institute analysis Syngas usual composition per production method Key takeaways Syngas is a (% of volume) mixture of H2, – Syngas has been used for many CO, and other years for lighting, 100% 100% 100% 100% 100% cooking, and to gases that 0% 0% 2% 1% some extent 8% 5% 5% comes out 13% heating before 6% 8% 21% electric lightning of SMR, ATR, and natural gas and gasification 16% infrastructure were 22% 20% deployed. reactors – During World War 49% II, syngas was used to power cars in 39% Europe as a replacement for gasoline. – Syngas composition 70% 65% 67% depends on feedstock and the production methods 44% 40% used. Its energy density is half natural gas one. – Syngas is often used as an SMR Reformer Gasification ATR ATR intermediate for (natural gas) (naphtha) (heavy oils) (low steam) (high steam) hydrogen, ammonia, H2 CO CO2 CH4 Others methanol, and Hydrogen value chain - liquid fuels 2.1 Production technologies production.

Note: Others include N2, Ar, H2S, and COS 35 Sources: IFP–Afhypac; Kearney Energy Transition Institute Syngas applications Depending on (Volume for 100 m3 of syngas, % of volume) purity, syngas Steam can either (14.8) H2 purity 99.9% undergo multiple H2 (74.8) processes to Water–gas shift Pressure swing Others CO + H O CO + H H adsorption (0.1) 2 extract H or be Residual CO: 1 – 3% Residual CH : recovery 2 2 ⇌ 2 2 4 converted into 0.1% - 0.2% 85-90%

PSA purification PSA Tail gas liquid fuels (39.9)

Steam (16.3) H2 purity Syngas Methanation H2 (87.0) 95-98% (100) Water–gas shift Decarbonation CO + 3H CH + H O Others Non-Exhaustive CO + H O CO + H CO + 4H CH + 2H O Amines (MDEA/MEA) 2 H2 Residual CH4: 2 4 2 (4.3) Residual CO: 0.3 – 0.8% Residual CO/CO2 <0.1% Residual CO/CO⇌ 2 < 10 3–8% 2 2 2 2 4 2 Residual CH4: recovery ⇌ ppm⇌ 4.4% - 9.4% methanation 98% CO (22.1) Decarbonation and 2

Methanol Gasoline Gasoline synthesis DME synthesis CO + H CH OH 2CH OH C H O + H O synthesis treatment and 3 2 2 Carbon number: 6 to 10 H2/CO ratio: 2 separation 2 ⇌ 3 ⇌ 6 Hydrogen value chain - Liquid fuels 2.1 Production technologies

Note: DME is dimethyl ether. 36 Sources: IFP; Afhypac; Kearney Energy Transition Institute H2/CO ratio range per production mean Key comments The H2/CO ratio (% of volume/% of volume, before water–gas shift) has a high impact on end-application – The H2/CO ratio depends on the feedstock used, operating performance and temperature, and technology. – Some applications require potential uses, 6.0 Adding steam into the reactor enables higher specific H2/CO ratio and controlling it – In the gas-to-liquid pathway, H2/CO ratio. allows greater H2 and CO react in stoichiometric proportions to flexibility produce synthetic fuels. The Light oil distillates optimal H2/CO ratio is 2. gasification leads – For pure H2 applications, syngas requires purification. to higher H2/CO. 3.5 The higher the H2/CO ratio, the easier the purification.

1.9

Hydrogen value chain - 2.1 SMR Gasifier ATR Production technologies

37 Sources: IFP–Afhypac; B. Sahoo, N. Sahoo, and U. Saha, Applied Thermal Engineering, 2011; Kearney Energy Transition Institute analysis Carbon capture Carbon Capture and Storage – CCS - value chain and storage (CCS) refers to a set of CO2 technologies that are put together to abate emissions from stationary CO2 sources

Hydrogen value chain - 2.1 Production technologies

38 Source: Kearney Energy Transition Institute, CCS FactBook Combining Overview of SMR and CCS options CCS with thermochemical 3 CO2 capture production Heat sources could recovery 1 H Reformer reduce CO2 Natural Desulfurization Shift conversion CO capture PSA system (~900 °C) 2 H2 emissions gas (CH4) Syngas 2 Fuel Burner Heat CO2 capture Tail gas

Option Description Maturity Capture rate

State-of-the art technology, Non-Exhaustive Capture of CO from shifted 2 MDEA + CO + H O MDEAH+ + HCO - with twice the carrying 54% 1 a syngas with MDEA 2 2 3 capacity of MEA ⇔ Capture of CO2 from shifted State-of-the art technology, + - 1 b syngas with MDEA with H2- MDEA + CO2 + H2O MDEAH + HCO3 with twice the carrying 64% rich burners capacity of MEA ⇔ State-of-the art technology, Capture of CO from PSA 2 MDEA + CO + H O MDEAH+ + HCO - with twice the carrying 52% 2 a tailgas with MDEA 2 2 3 capacity of MEA ⇔ Capture of CO from PSA 2 CO liquefied and purified to food-grade Pilot scale, under tailgas using low temperature 2 53% 2 b quality deployment and membrane separation

Hydrogen value chain - Capture of CO2 from SMR 2.1 MEA + CO2 H2O + C3H5NO2 - N2 + H2O Standard technology 89% Production technologies 3 fuel gas using MEA ⇔ 1 USD = 0,89 € 39 Sources: International Energy Agency Greenhouse Gas R&D Programme, Global CCS Institute, Air Liquide; Kearney Energy Transition Institute analysis Pyrolysis Description Overview of technologies requires a lower – Hydrocarbons waste undergoes heating without air Bubbling fluidize bed Circulating fluid bed combustion to break chemical bonds.1 pyrolizer pyrolizer temperature than + + 2 – There are four types of pyrolysis: other technologies 4 2 – Slow pyrolysis:𝐶𝐶𝐻𝐻 low𝐻𝐻𝐻𝐻𝐻𝐻𝐻𝐻 temperature→ 𝐶𝐶 𝐻𝐻 increase (0.1 to and happens in a 2°C per second) to reach about 500°C. Residence vacuum chamber time of gas over 5 sec per biomass minutes to days. Tar and char are released. – Flash pyrolysis: rapid heating rate, from 400°C to 600°C. Vapor residence time less than 2 seconds, less gas and tar produced – Fast pyrolysis: mainly for bio-oil and gas. Rapid Residence time of vapors controlled by fluidizing gas Fast residence time due to heating from 650 to 1,000°C. Large quantities of flow rate high gas velocities char must be removed. – Microwave pyrolysis: lower time and temperatures required – However, hydrogen production yield of 25% makes it Fact card: Pyrolysis difficult to establish a business case for H2 production. Key feature estimates – Research is focusing on using microwaves to heat crude oil and produce H2. Current cost estimate ($ per kgH2) 2.2–3.4

Typical plant size (kgH2 per day) 10,000–50,000

Water use (L/kgH2) – Operating CO emissions 2 – Pros Cons (kgCO2/kgH2) Efficiency (%, LHV) 50–70% – Simple technology – Low H2 content Temperature (°C) 200–760 °C – Low capex – Low scalability – Graphitic carbon as Primary energy source Hydrocarbons Hydrogen value chain - 2.1 Current cost estimate ($ per kgH2) 2.2–3.4 Production technologies by-product – Low to no CO2 Typical plant size (kgH2 per day) 10,000–50,000 emissions 40 1 Methane pyrolysis is also called methane cracking. Sources: “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Afhypac; Kearney Energy Transition Institute analysis Electrolysis Description Electrolyzer and cell overview (PEM example) produces H2 – A direct current passes through an ionic substance, producing chemical reactions at the electrodes by applying a Electrolyzer stacks (cathode and anode) and decomposing materials. Electricity Power direct current to – Electrodes are immerged in electrolyte and converter O2 an electrolyte separated by a membrane where ions can move. AC/DC – Hydrogen ions move toward the cathode to form H2. solution, which – Receivers collect hydrogen and oxygen in gaseous Water forms. Deionizer H2 allows high purity – Reactions that happen at anode and cathode in a unit Dehydration of hydrogen water electrolysis are: – Anode: H O 2H + O2 + 2 e (E0 = 1.23V vs. + Water 1 1 − SHE ) 2 storage tank → 2 1 – Cathode: 2H + 2 e H2(E0 = 0.00V vs SHE ) + – Overall reaction of water− electrolysis is → 1 Heat H O H + O2 (E0 = -1.23V vs SHE ) – For water electrolysis,1 approximately 9–15 L of water 2 → 2 2 Fact card: Electrolysis and 50–60 kWh of electricity are required to produce Cell 1 kg of H and 8 kg of O (depends on technology). 2 2 Direct current (I) Electron flow (e-) + -

H2O X - Pros Cons Anode Cathode Electrolyte – High purity hydrogen – More expensive than O2 H2 – Oxygen as a by- most of thermochemical product, often not solutions Hydrogen value chain - 2.1 used – High emitter of CO2 if Production technologies H2 production rate – No dependency on electricity is not clean = proportional to I fossil fuels = Input power * ηcell 41 1 Standard hydrogen electrode Sources: “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Kearney Energy Transition Institute analysis Water alkaline Description Overview of technology electrolysis is – Alkaline technology is a very mature technology one of the oldest thanks to the chlorine industry. – A strong base with high-mobility ions solution is used electrolysis as electrolyte: KOH (potassium hydroxide) is normally used to avoid corrosion problems caused by acid technology, used electrolytes and because of high conductivity. in large-scale – Electrochemical reactions that happen are: – Anode: 2 OH H2O + O2 + 2 e (E0 = 0.40V vs projects − SHE1) 1 − → 2 – Cathode: 2 H2O + 2 e H2 + OH (E0 = -0.83V vs SHE1) − − – Overall reaction remains →similar to the general one. – It differs from chlor-alkali/chlorate electrolyzers used in the chlorine industry (using brine water instead of fresh water)

– Yearly production is about 80-100 MT of Cl2 and 4 MT of NaClO3 leading to ~2 MT of H2 as by-product: Fact card: Alkaline Key feature estimates electrolysis (AE) + 2 + 2 + 2 − − + 2 + 3 Current cost estimate ($ per kgH ) 2.6 – 6.9 2 2 2𝐶𝐶𝐶𝐶 2𝐻𝐻 𝑂𝑂 → 𝑂𝑂𝑂𝑂 𝐻𝐻 𝐶𝐶𝐶𝐶 Typical plant size (kgH per day) Up to 70,000 𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁 3𝐻𝐻2 𝑂𝑂 → 3𝐻𝐻 𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁 2 Efficiency (%, LHV) 52 – 69% Pros Cons Temperature (°C) 60-80 Operating pressure (bars) 1-30 – Cheapest option for – Low flexibility Current density (A/cm2) 0.3 – 0.5 electrolyzers, with – Recovery/recycling of KOH large-scale proven – Corrosive electrolyte Purity of H2 99.7% - 99.9% (up to 150 MW) – Inefficient at high current Primary energy source Electricity Hydrogen value chain - 2.1 Production technologies – Higher durability density Current cost estimate ($ per kgH2) 2.6 – 6.9 – Efficient but only at – Maintenance complex high temperature 42 1 Standard hydrogen electrode Sources: “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; “The Future of Hydrogen,” International Energy Agency, June 2019; KTH Royal Institute of Technology; Kearney Energy Transition Institute PEM is rapidly Description Overview of technology developing thanks – The PEM electrolyzer uses a ionically conductive solid to its compacity, polymer. – H+ ions travel through polymer membrane toward the its improved cathode when a potential is applied to form H then H2. current density – Reactions that happen at anode and cathode are: – Anode: H O 2H + O2 + 2 e (E0 = 1.23V vs. and flexibility but 1 + 1 − SHE ) 2 requires precious – Cathode: 2H→_++2 e−→H22 (E0 = 0.00V vs SHE1) – Overall reaction of water electrolysis is: materials 1 H O H + O2 (E0 = -1.23V vs SHE ) 1 – The PEM2 electrolyzer2 has a short response time: below 2 seconds→ and2 a cold start time below 5 minutes. – Most commercial PEM water electrolyzers use self- pressurized PEM cells

Fact card: Proton exchange Key feature estimates membrane (PEM)

Current cost estimate ($ per kgH2) 3.5–7.5

Typical plant size (kgH2 per day) 50–500, up to 50,000 Pros Cons Efficiency (%, LHV) 60–77% Temperature (°C) 50–80 – Low plant footprint, – High capex and OPEX Operating pressure (bars) 20–50 compacity – Presence of platinum for Current density (A/cm2) 1–3 – Self-pressurized H2 electrodes well-suited for Purity of H2 99.9–99.9999% storage facilities Primary energy source Electricity Hydrogen value chain - 2.1 – Short response time Production technologies (less than 2 seconds) Current cost estimate ($ per kgH2) 3.5–7.5

43 1 Standard hydrogen electrode Sources: “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; “The Future of Hydrogen,” International Energy Agency, June 2019; Hydrogenics; Kearney Energy Transition Institute analysis SOEC, the Description Overview of technology electrolysis of – SOEC technology is still at an early stage of steam, is still in development but could benefit from high efficiency. – SOEC is based on steam water electrolysis at high the R&D stage temperature, reducing needs for electrical power. – Molar Gibbs energy of the reaction drops from about but is more 1.23 eV (237 kJ/mol) at ambient temperatures to efficient than about 0.95 eV at 900 °C (183 kJ/mol). – High temperature for heat can be obtained from other electrolysis nuclear power or waste heat from industrial technologies process—part of it being already supplied by Joule effect in the cells. – Heat is only needed to vapor water. Operating point can be chosen slightly exothermic to recycle exhaust gas and heat input gases from 150°C to 700°C without additional electricity.

Fact card: Solid oxide Key feature estimates electrolysis cell (SOEC)

Current cost estimate ($ per kgH2) 5.8–7.0

Typical plant size (kgH2 per day) Pilot scale Efficiency (%, LHV) 74–81% Temperature (°C) 650–1.000 Pros Cons Operating pressure (bars) 1 Current density (A/cm2) 0.5–1 – High efficiency and – High temperature required low electricity – Limited flexibility Primary energy source Electricity consumption – Low ceramic membrane Current cost estimate ($ per kgH ) 5.8–7.0 Hydrogen value chain - 2 2.1 lifetime due to extreme 2 Production technologies Typical plant size (kgH2 per day) Pilot scale operating conditions

44 1 Standard hydrogen electrode Sources: “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; “The Future of Hydrogen,” International Energy Agency, June 2019; Hydrogenics; Kearney Energy Transition Institute analysis These electrolysis Electrolysis production technologies technologies exist with different AE (Alkaline) PEM SOEC characteristics Operating pressure (bar) 1–30 20–50 1 which make them Operating temperature (°C) 60–80°C 50–80°C 650–1,000°C suitable for Current density 0.3–0.5 A/cm² 1–3 A/cm² 0.5–1 A/m² Load range (% of nominal 10–110% 20–100%, up to 160% 20–100% different load1) applications System efficiency (% LHV) 52–69% 60–77% 74–81% Response time Start: 1–10 minutes; shut: 1–10 Start: 1 second–5 minutes; shut: High minutes few seconds Reverse mode (fuel cell No No Depends on design mode) Stack lifetime (hours) 60,000–90,000; 30,000–70,000 (80, 000 achieved 10,000–30,000, 100,000–150,000 expected by ITM); 75,000–100,000 expected 100,000–120,000 expected Expected R&D – Scaling benefits and lower – Scaling benefits, smaller – Improvement in component improvements cost of BoP footprint of stack, and lower lifetime (especially ceramic – Improved lifetime of cost of BoP membrane) by improving components through R&D – Improvement in materials resistance to high temperatures – Improved heat exchangers and components lifetime (such as lower resistance – Improve response to membrane, catalyst fluctuating energy inputs coating, and current density) through R&D

Hydrogen value chain - Mature technology with track Highly reactive technology High potential of economical 2.1 Production technologies records of large scale with small land footprint benefits if coupled with heat Pros and cons projects but from old alkaline thanks to high current density source, geothermal, or CSP technologies

45 1 Depends on design and size Note: BoP is balance of plant. Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; National Renewable Energy Laboratory; Kearney Energy Transition institute analysis Dark fermentation Description Overview of technology is the conversion – Dark fermentation happens in a tank with no light. of organic matter Bacteria will trigger a series of biochemical reactions. – Anaerobic bacterial and microalgae reacts with to hydrogen carbohydrate (refined sugars, raw biomass) and water (even with waste water) to produce H2 and through CO2. biochemical C6H12O6 + H O 2 CH3CO2H + 4 H2 + CO2 C6H12O6 + H O CH3CH2CH2CO2H + 2 H2 + 2 CO2 2 reactions – Operating temperature→ is mainly between 25 and 2 40°C even if operations→ can be conducted at temperature above 80°C. – Temperature has a significant impact on hydrogen production rate as it affects growth rate of microorganisms. If the temperature exceeds optimum value, it can lead to thermal inactivation of enzymes. – Dark fermentation is followed by photo fermentation. Fact card: Dark fermentation Key feature estimates

Current cost estimate No industrial use yet ($ per kgH2) Hydrogen production yield Pros Cons 0.03–0.04 (kgH2 per kg) – Simple reactor – Low yield of production Efficiency (%, LHV) 30–40% design – Production of CO2 and CO – Abundant resource requiring a purification step Operating temperature (°C) 25–40 – Scaling issues – Early-stage technology Primary energy source Biomass already addressed by Hydrogen value chain - 2.1 biofuel industry (for Production technologies fermentation)

46 Sources: Renewable Hydrogen Technologies, Luis M. Gandía, Gurutze Arzamendi, and Pedro M. Diéguez, 2013; Afhypac, Department of Energy; Kearney Energy Transition institute analysis Microbial Description Overview of technology electrolysis – Microorganisms are attached to the anode and bacteria consume acetic acid to release e- and combines electrical + protons combining into H and CO2. energy with – A power source provides additional energy (~0.2 V to 0.8 V), below typical water electrolysis technologies microorganisms (1.23 V – 1.8 V). – Electrode reactions are as follows: activation to + – Anode: C2H4O2 + 2 H O 2 C02 + 8 H +8 e + produce H2 with – Cathode: 8 H +8 e 4 H − 2 2 low energy inputs – Overall, reaction can be− summarized→ as follows: C2H4O2 + 2 H →O 2 CO2 + 4 H2

2 →

Fact card: Microbial Key feature estimates electrolysis Current cost estimate 1.7–2.6 in laboratory ($ per kgH2) conditions

Pros Cons Typical plant size (kgH2 per day) No industrial use yet About 70% (up to 300% – Carbon neutral – No comprehensive review Efficiency (%, LHV) if only considering technology1 on reactor configurations electrical input) – Abundant resource – Early stage technology Current density (A/cm2) 8.10-4 –11.10-4 – Ongoing Primary energy source Biomass development of Hydrogen value chain - 2.1 membrane-free Production technologies reactors with high production rates 47 1 Not including emissions from electricity generation Sources: Alexandria Engineering Journal, 2016; Afhypac; Department of Energy; Kearney Energy Transition institute analysis Photolytic Description Overview of technology technologies – Microorganisms are attached to the anode and bacteria consume acetic acid to release e- and directly converts + protons combining into H and CO2. sun energy into – A power source provides additional energy (~0.2 V to 0.8 V), below typical water electrolysis technologies hydrogen (1.23 V – 1.8 V). – Electrode reactions are as follows: + – Anode: C2H4O2 + 2 H O 2 C02 + 8 H +8 e + – Cathode: 8 H +8 e 4 H − 2 2 – Overall, reaction can be− summarized→ as follows: C2H4O2 + 2 H →O 2 CO2 + 4 H2

2 →

Fact card: Photolytic Pros Cons Key feature estimates conversion technologies

– Can be developed in – Low lifetime of materials Current cost estimate ($ per kgH2) n.a. (laboratory stage) thin films – Need to protect the Typical plant size (kgH per day) n.a. (laboratory stage) – Able to operate at semiconductor from water 2 low temperatures Efficiency (%, LHV) ~15% (max. 23%) – One-step process, Current density (A/cm2) ~10-2 offering cost- Primary energy source Sunlight reduction potential – Efficiency rapidly increasing (3% in 2000 vs. 19% in Hydrogen value chain - 2.1 Production technologies 2018 reached in laboratory)

48

Sources: Afhypac, ACS Energy; Kearney Energy Transition institute analysis Storing and Hydrogen midstream value chain transporting hydrogen adds Purification and Transportation Storage and complexity to conversion reconversion the value chain – Hydrogen needs to purified, – Depending on transformation – Depending on the either to remove other method, hydrogen can be transportation method, components from syngas transported by different means. hydrogen can be stored in (including CO and CO2) out of – Long-distance transportation tanks, salt caverns, cans gasifier and reformers or means include pipelines and (hydrides only), or a pipeline remaining water out of vessels, but infrastructure has network (even in natural gas electrolyzer. not yet been deployed. pipelines, up to a limit)1 – These steps are conducted – Last-mile hydrogen delivery – Reconversion might be needed at the production stage. includes road, rail, and pipeline. if the new product is not suited – To increase energy density – Generally, hydrogen is for further application. and/or improve stability and consumed on-site, requiring – Ammonia can be used as safety, hydrogen can be short pipeline networks, and feedstock for multiple transformed before being when needed is transported applications, especially stored. by trucks (about 200 kg per fertilizers. – Compression in gaseous truck). – LOHC does not have proper form to increase energy – Hydrogen pipeline network application. density length is around 5,000 km – Liquefaction at -252°C to globally, compared with 1.3 increase energy density million km for natural gas. – Material-based transformation, either in liquid form (ammonia and Hydrogen value chain - LOHC) or solid form 2.2 Conversion, storage, and (hydrides) to improve stability transportation technologies and energy density Note: LOHC is liquefied organic hydrogen carrier. 1 The limit depends on gas infrastructure and consuming applications connected. 49 Source: Kearney Energy Transition Institute analysis To increase H2 Conditioning energy density, hydrogen conditioning Conditioning

is a prerequisite Physical transformation Chemical combination before storage Chemical H2 and transport On-site Compression Liquefaction (for example, To storage, consumption ammonia) transport, and

Gaseous consumption Liquid H2 LOHC H2

Cryo- Interstitial compressed H2 production hydride unit H2

Complex hydride

Adsorbent

Hydrogen value chain - 2.2 Conversion, storage, and transportation technologies Note: LOHC is liquefied organic hydrogen carrier. Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; US Department of Energy; 50 Kearney Energy Transition Institute analysis Depending on H2 storage and transport the conversion Long-distance Short-distance Storage process, H2 can transportation distribution be stored and Transformation transported in method multiple ways Pipeline Tankers Pipeline Trucks Trains Tank Pipeline Can Cavern

Compression         Physical Physical

transformation Liquefaction    

Ammonia       

LOHC     Chemical combination

Hydrides    

Hydrogen value chain - Small to Small to 2.2 Conversion, storage, and ~2,000 >3,000 <500 <500 <1,000 Small Large mid mid transportation technologies Scale km km km km km scale scale scale scale 1. Note: LOHC is liquefied organic hydrogen carrier. 51 2. Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis There are multiple H2 conversion and reconversion key facts opportunities to carry hydrogen: Technology advantage Low Medium High Energy input Material- Technology Density Process either in gaseous, Advantages Disadvantages based description (kg/m3) maturity liquid or in (kWh/kg H2) (% LHV) Compression of – PEM produces H at 35 another molecule 35 3 -1 - High 2 H2 at desired bars pressure form pressure to 150 increase energy 11 ~1 >90% High density – Flammable Gas 350 23 ~4 >85% High – Compression at 25 °C

700 38 ~6 80% High

Liquefied Cooling of H2 at High for – High energy losses, esp. hydrogen -253°C through small scale – Economically viable compared to LNG cryo- 71 ~9 65-75% where space is limited conversion compression Low for large and high H2 demand – Boil off losses (up to 1% scale per day) Ammonia Reaction with 3 kWh/kg at 82%-93% at High for nitrogen – Mature industry, potential – Toxicity and air polluter conversion, conversion, conversion, 121 to leverage current up to 8 at ~80% at medium for – High energy req. for infrastructure reconversion reconversion reconversion reconversion

Mixing with Exothermic LOHC to Exothermic – Toxicity and flammability 2 MCH and conversion, MCH conversion, of toluene converted back 110 ~12 kWh/kg Medium – No need for cooling ~65% at – Price of toluene to hydrogen at reconversion reconversion – Back-shipping of toluene Metal Chemical – Heavy storage unit – Lower costs and losses Hydrogen value chain - hydrides bonding with – Long 86 – Higher safety 2.2 Conversion, storage, and metals, reheat 4 88% Medium charging/discharging (MgH ) transportation technologies back to 2 – Higher energy density times hydrogen than compression – Low lifetime 52 1. 1 PEM produces H2 at this pressure with no additional need for compressor. 2. 2 Methylcyclohexane (C7H14) 3. Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Kearney Energy Transition Institute analysis Trucks are most Key hydrogen transport methods suited for short distances and small Technology advantage Low Medium High Key data Range Process Storage type Advantages Disadvantages throughputs; (kms) maturity pipelines are Sub-type Metrics Low pressure – Capex/km (MUSD): 0.3 preferred for point- (shorter – Gas density (kg/m3): 0.55 – Lowest-cost option distances) – Gas velocity (m/s): 15 for continuous – Higher capital costs to-point transport of 1,000– because of Compression High delivery 4,000 infrastructure – Capex/km (MUSD): 0.5 – Low operation large quantities Pipeline High pressure requirements – Gas density (kg/m3): 6.4 costs (longer distances) – Gas velocity (m/s): 15

– Capex ($ thousand): 185 – Lower capacity (truck), 650–1,000 (trailer) – Delivery to multiple compared with other Compression, Less – Loading/unloading time locations before options liquefaction, than n.a. (trailer, hours): High they are connected – 3 (LH ), 1.5 (GH ) – Boil-off rate requiring Trucks ammonia 1,000 2 2 to a pipeline – Net capacity (trailer, kgH ): rapid delivery of liquid 2 hydrogen 4300 (LH2), 670 (GH2)

– Lower operational costs, larger Compression, 800– quantities, and liquefaction, n.a. n.a. Medium – Limited route flexibility 1,100 distances

Trains ammonia compared with trucks

– Unlikely to use – Capacity/ship (tH2): compression storage More 11,000 – Likely option for Liquefaction, because of the cost of Hydrogen value chain - than n.a. – capex/ship (MUSD): 412 Low exporting huge ammonia operation, distance, 2.2 Conversion, storage, and 4,000 – Fuel use (MJ/km): 1487 volumes transportation technologies Tankers and lower hydrogen density

Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Kearney Energy Transition 53 Institute analysis Pressurized tanks Description Overview of technology are the most – To increase its energy density, hydrogen can be compressed and stored in pressurized vessels, mainly mature and tanks, but also bottles. In general, pressurized tanks common hydrogen operate at pressures ranging from 200 to 700 bar. – Tanks storage compressed or liquefied hydrogen have storage technology high discharge rates and efficiencies, making them appropriate for smaller-scale applications where a local stock of fuel or feedstock needs to be readily available. – Pressurized tanks need a high operational cycling rate to be economically feasible. If the storage time, relative to the power rating, increases beyond a few days, the capital costs of vessels and compressors become a drawback for this technology. Outdoor storage infrastructure consisting of bulk storage – Research is continuing with the aim of finding ways to tank, compression pumps, and gaseous storage tubes reduce the size of tanks for densely populated areas.

Fact card: Pressurized tanks Key feature estimates Pros Cons

– Mature technology – Low volumetric and $6,000–$10,000 per Current cost estimate – Fast charge and gravimetric density, MWh (storage tank) recharge time resulting in large and 100 kWh–10 MWh Typical size – Easy to transport heavy tanks per tank – Low storage capacity 3 per vessel Volumetric density (kWh/m ) 670–1,300 89–91% (350 bar); Efficiency (%) Hydrogen value chain - 85–88% (700 bar) 2.2 Conversion, storage, and transportation technologies

Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Kearney Energy Transition 54 Institute analysis Salt caverns, Description Overview of technology depleted natural – Hydrogen gas is injected and compressed in underground salt caverns, which are excavated and gas, or oil shaped by injecting water into existing rock salt reservoirs and formations. – Withdrawal and compressor units extract the gas aquifers are when required. potential options – Salt caverns have been used for hydrogen storage by the chemical sector in the since the for large-scale and 1970s and the United States since the 1980s. long-term – Depleted oil and gas reservoirs are typically larger than salt caverns, but they are also more permeable hydrogen storage and contain contaminants. – Water aquifers are the least mature of the three geological storage options. There is mixed evidence for their suitability, although they were used for years to store town gas with 50–60% hydrogen.

Fact card: Geological storage Key feature estimates Pros Cons

– Allows for high- – Geographical specificity, Current cost estimate ($ per Less than 0.6 volume storage at large size, and minimum kgH2) lower pressure and pressure requirements Typical size 1–1,000 GWh cost – Less suitable for short- – Seasonal storage term and smaller-scale Volumetric density (kWh/m3) 65 (at 100 bar) – Low risk of storage Efficiency (%) 90–95% contaminating the Hydrogen value chain - stored hydrogen 2.2 Conversion, storage, and transportation technologies

Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Praxair (2009); Kearney Energy 55 Transition Institute analysis Compressed Description Overview of technologies hydrogen storage – In the form of compressed gas stored in salt caverns, hydrogen could also become a long-term storage option to in salt caverns balance seasonal variations in electricity demand or generation from renewables. offers the most – However, compressed hydrogen suffers from a low round economic option trip efficiency (60% of the original electricity is lost). – Other hydrogen-based storage alternatives include: at discharge – Underground hydrogen storage options, such as pore durations longer storage and storage in depleted oil and gas fields – Storing hydrogen-based fuels, such as methane, liquid than 20 to 45 organic hydrogen carriers (LOHCs), and ammonia produced from electricity via electrolysis, in respective hours storage mediums, including methane (gas grid) and ammonia (steel tanks) – Prospective customers: utilities

Preliminary

Comp- Fact card: Long-term H2 Market trends Para- Units PHES CAES Li-ion ressed energy storage meter H2 Early prototype and Market maturity Capex $ per demonstration 1130 870 95 1820 (power) kWe Market size (number 3 salt caverns (United Capex $ per of units) States and United Kingdom) 80 39 110 0.25 (storage) kWh Few alternatives for long- Future growth duration, large-scale Opex $ per 8 4 10 73 storage (power) kWe

Pumped hydro, batteries, Opex $ per 1 4 3 0 Hydrogen value chain - Competing technologies thermo-mechanical storage (storage) kWh 2.2 Conversion, storage, and technologies transportation technologies Round- trip % 78 44 86 37 efficiency 56 Lifetime Years 55 30 13 20 Source: Kearney Energy Transition Institute analysis Description Overview of technology Liquefying H2 must be cooled down to – George Claude’s cycle to liquefy H2 is a three-step -253°C, with process: – H2 is first cooled with a liquid nitrogen heat exchanger. potential losses – Then, H2 is compressed and expanded in adiabatic conditions, which cools down the gas and the system from boil-off itself. – To avoid liquid presence in the system and mechanical troubles, isenthalpic Joule-Thomson expansion allows to recover liquid H2. – As natural H2 is a mixture of ortho-hydrogen (75%) and para-hydrogen (25%), liquefying transforms all ortho into para-hydrogen, which is an exothermic reaction. – In addition to thermal losses as a result of the non- Linde’s liquefaction plant perfect insulation of the system, boil-off also happens because of the reaction heat emissions.

Key feature estimates Fact card: Liquefaction of H2 Pros Cons

– Easy – Flammable Current cost estimate ~1.0 reconversion – Not mature for large- ($ per kgH2)

– High energy scale systems Typical plant size (kgH2 per day) 5,000–25,000

density – Boiling off, with 0.3% Energy required (kWh/kgH2) 10–13 – Already used in to 1% losses per day Energy consumption (% of LHV 20–25%, potential aerospace of Hydrogen) to 18% industry

Hydrogen value chain - 2.2 Conversion, storage, and transportation technologies

Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Afhypac; Linde; Kearney Energy 57 Transition Institute analysis Ammonia is Description Overview of technology Air CH4 synthetized – Synthetized through the Haber–Bosch process: through the Unreacted recycledgases N2 + 3H 2NH3 = 92 kJ/mol SMR ASU Haber–Bosch – Reaction temperature is set at about 500°C process and can at 20 MPa to2 →accelerateΔH the −reaction. Haber tower be reconverted to – The catalyst used is iron and potassium hydroxide. H2 or used as a – At each pass of gases through the reactor, Gas cooler feedstock for only 15% of N2 and H2 are converted to fertilizers ammonia. Therefore. gases are recycled to increase conversion rate to 98%. Haber tower Liquid ammonia

Key feature estimates Fact card: Ammonia Pros Cons conversion – High hydrogen – Flammable Conversion: 0.98–1.2 Current cost estimate density – Acute toxicity ($ per kgH ) Reconversion: – Low energy – Air pollutant 2 0.80–1.0

requirements – Corrosive Typical plant size (kgH2per day) About 200,000 – Mature industry – Inefficient and non- Conversion: 2–3 Energy required (kWh/kgH ) thanks to mature reconversion 2 Reconversion: 8 fertilizers, process Conversion: 7–18% Energy consumption (% of LHV with existing Reconversion: Hydrogen value chain - of hydrogen) 2.2 Conversion, storage, and infrastructures Less than 20% transportation technologies

Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Afhypac; Linde; Kearney Energy 58 Transition Institute analysis LOHC is a liquid Description Overview of technology hydrogenated – Hydrogen is loaded on organic liquid through carrier, which hydrogenation and dehydrogenated at the use point. enables easier – The hydrogenation process releases heat, and safer handling which can be used for alternative applications and do not require or for dehydrogenation if the plant can support both. cooling – Toluene is a potential carrier for hydrogen by converting it to methylcyclohexane (MCH) – Dibenzyltoluene (DBT) is an alternative to MCH and is reported to be safer, easier to Hydrogenious LOHC reconversion unit handle, and cheaper.

Fact card: Liquefied Organic Pros Cons Key feature estimates Hydrogen Carrier (LOHC) – Liquid in ambient – MCH is a toxic Current cost estimate Conversion: 1.0 3 conditions, substance ($ per kgH2) Reconversion: 2.1 opportunity to – Energy intensive for Typical plant size 2 About 10,000 leverage current dehydrogenation to (kgH2 per day) oil infrastructures reach 250–350°C Reconversion: Energy required (kWh/kgH ) – Fluid carrier – Need to ship back 2 about 10 reusable once the carrier has Energy consumption (% of LHV 35–40%, potential – No boil-off losses been dehydrogenated of hydrogen) to 25% Hydrogen value chain - 2.2 Conversion, storage, and transportation technologies

59 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” VTT; Hydrogenious; Kearney Energy Transition Institute analysis Metal hydrides Description Overview of technology operate at low – Certain metals bind very strongly with hydrogen, pressure and forming a metal hydride compound. Under low temperature or at high pressure, hydrogen gas Pabsorption improve hydrogen- molecules adhere to the surface of the metal and break down into hydrogen atoms, which penetrate the handling safety metal crystal to form a solid metal hydride. When the MgH2 metal hydride is heated, the metal–hydrogen bonds Pdesorption

but must still Pressure (bar) break, and hydrogen atoms migrate to the surface Mg+H2 demonstrate their where they recombine into hydrogen molecules. – To minimize the energy penalty, heat released during Temperature (°C) economic absorption can be captured and stored for use during feasibility desorption. The combined use of metal hydrides and thermal storage, known as adiabatic metal hydrides, is Hydrogenious LOHC reconversion unit already on the market. – Currently, they are being re-examined for niche applications where stability is a key requirement, such as the military.

Fact card: Metal hydrides

Pros Cons Key feature estimates

– Low pressure – Attaching hydrogen to metal Current cost estimate operation mode results in a heavy storage unit NA implies lower costs – Long charging and ($ per kgH2) 10–20 (United States), and losses. discharging times Typical size – Safety than – Low lifetime 1 (United Kingdom) compressed gas / Volumetric density (kWh/m3) 4,200 Hydrogen value chain - liquified hydrogen 2.2 Conversion, storage, and – Larger energy Efficiency (%) ~80-90% transportation technologies capacity than compressed tanks 60 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Kearney Energy Transition Institute analysis Multiple new Hydrogen technology maturity curve H2 production technologies are being developed, Metal hydrides brown Methane cracking / Pyrolisis Blue technology technologies SMR with CCS being the most SOEC PEM Green technology mature Microbial electrolysis Alkaline electrolysis CSF Chemical looping Complex hydrides Photocatalytic water splitting Chlor-alki electrolysis Micro- Membrane based / Offshore ammonia synthesis wave Microbial biomass conversion Photobiological water splitting Brown technology Electrochemical ammonia synthesis Coal gasification Synthetic methane SMR

“Valley of Death” Capitalrequirement technology x risk

Large- and commercial-scale projects Lab work Bench scale Pilot Scale with ongoing optimization Widely deployed commercial-scale projects

Research Development Demonstration Deployment Mature Technology Time

Hydrogen value chain - Thermochemical production Electrolysis production Other Storage and transportation 2.3 Maturity and costs (Photolytic, microbial, microwave) . Sources: IEA – The Future of Hydrogen (2019), Csiro – National Hydrogen Roadmap (2018), IRENA – Hydrogen from Renewable Power (2015); Kearney Energy Transition Institute “Hydrogen Applications and 61 Business Models” (2020) Estimated LCOH per production technology The levelized (2019, $ per kg, average from multiple sources) cost of hydrogen is an average of 10.0 two to four times 9.5 9.0 higher for green 8.5 sources than for 8.0 hydrocarbon-based 7.5 7.4 solutions 7.0 6.5 6.0 5.5 5.0 5.0

Not Exhaustive; Indicative 4.5 4.0 4.0 3.5 3.0 2.5 2.1 2.0 1.9 1.9 Thermochemical 1.6 1.5 1.4 sources LCOH 1.2 1.0 range 0.5 0.0 SMR Coal Gasification ATR SMR + CCSCoal Gas. + CCS ATR + CCS AE PEM SOEC

Hydrogen value chain - Green only if coupled with 2.3 Brown H2 Blue H2 Green H2 Average Maturity and costs renewable electricity sources

Note: All hypotheses are detailed in the appendix. Sources: International Energy Agency Greenhouse Gas R&D Programme, Commonwealth Scientific and Industrial Research Organisation, International Renewable Energy Agency, Foster Wheeler, 62 McPhy, Areva H2Gen, Rabobank, TOTAL, Department of Energy, Air Liquide; Kearney Energy Transition Institute analysis LCOH breakdown: SMR example LCOH for ($ per kg, purity: 99.5%) thermochemical production 2% -7% 100% sources is driven 4% 3% by fuel costs and 0% 0% capex, accounting for about 96% of total LCOH

74%

Illustrative

2%

22%

Hydrogen value chain - Capex Start-up Fuel Water Catalysts Labor Maintenance Insurance Electricity LCOH 2.3 Maturity and costs costs and overhead selling

Note: Obtaining higher purity requires further investments that are not detailed in this study. All hypotheses are detailed in the appendix. 63 Sources: International Energy Agency Greenhouse Gas R&D Programme, Foster Wheeler; Kearney Energy Transition Institute analysis CO capture rate per case Brown H2 sources 2 (SMR, kg CO2/kg H2, % of base case, $ per kg) can be coupled CO2 released CO2 avoided Extra CO2 captured with CCS to reduce emissions, but 9.9 10.0 9.5 Extra CO emitted and captured LCOH could jump 9.4 0.8 0.9 2 9.1 0.3 0.4 9.1 Additional CO2 emitted to provide by 64¢ per kg energy for CCS solutions, captured by the CCS solution

4.9 4.7 4.9 (54%) 5.8 (52%) (53%) (64%)

8.1 (89%) CO avoided Illustrative 2 CO2 captured and avoided compared with the base case

4.2 4.3 4.2 (48%) (46%) 3.3 (47%) CO2 emitted (36%) CO2 effectively released in the 1.0 atmosphere (11%) Base case Case 1a Case 1b Case 2a Case 2b Case 3 (SMR)

LCOH ($ per kg) 1.44 1.70 1.84 1.79 1.76 2.08

Hydrogen value chain - Delta 2.3 - 0.26 0.40 0.35 0.32 0.64 Maturity and costs ($ per kg)

2 Note: CO emissions could go up to 11 kg/kgH2. $1 = €0.89 64 Sources: International Energy Agency Greenhouse Gas R&D Programme; Kearney Energy Transition Institute analysis LCOH breakdown - PEM example Electrolyzer cost is ($ per kg) mainly driven by electricity costs 100% 2% and capex 3% 3%

71%

Illustrative

21%

Hydrogen value chain - 2.3 Capex Electricity Water Maintenance Insurance LCOH Maturity and costs

Note: All hypotheses are detailed in the appendix. 65 Sources: AREVA H2Gen; Kearney Energy Transition Institute analysis Two factors Factors to improve electrolysis LCOH can improve electrolysis LCOH: Capex Electricity price LCOH reducing capex (size and technology) (local market) (load factor and size) and optimizing + = electricity price – Capex varies with – Spot prices are market – Capex highly impacts and load factor technology and plant size. dependent, and average LCOH when the utilization – Electrolyzer size is prices vary with time. rate is low. expected to increase – REN have a specific – Average electricity prices driving marginal capex functioning point and increase with load factor. down. range. – Optimum not at 100% utilization

PEM French market (2018) $1123 per kW $ per kWe $ per MWh Spot prices $ per kg AE $787 per kW Wind 1,500 90 14 $450 per kW 80 Solar 12 70 1,000 60 10 50 8 Optimum 40 500 30 6 20 4 10 0 0 0 0,00 2,00 4,00 6,00 8,00 10,00 0% 20% 40% 60% 80% 100% 0% 20% 40% 60% 80% 100% Hydrogen value chain - 2.3 Maturity and costs MW Time (%) Utilization rate (%)

Note: Other factors include efficiency, operations and maintenance, and stack replacement and are expected to be improved as technology becomes more mature and the system size grows. Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; European Network of Transmission System Operators; International Renewable Energy Agency; Kearney Energy Transition Institute 66 analysis Capex relative LCOH for various capex Key comments weight is offset at $ per kg – Increasing full load hours a high load factor, 27 26 decreases the impact of but LCOH can 25 $1,200 per kWe capex on LCOH. dramatically 24 $1,000 per kWe – At 90% utilization rate, 23 $800 per kWe increasing capex from increase when 22 $600 per kWe $400 per kWe to $1,200 utilization is low 21 $400 per kWe per kWe increases 20 LCOH by $1.10 per 19 18 kgH2. 17 – However, at 10% 16 utilization rate and 15 similar power prices, 14 LCOH jumps by $8.10 13 per kg for the same 12 capex increase. 11 10 – Moreover, marginal capex 9 decreases with the size of 8 the electrolyzer. 7 Economies of scale are 6 achievable in the future. 5 4 3 2 SMR LCOH 1 1.4 0 Hydrogen value chain - 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2.3 Maturity and costs Utilization rate (%) $1 = €0.89 Hypotheses: Electricity price: $52/MWh, WACC: 8%, lifetime: 20 years 67 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis Power price has LCOH function of electricity price LCOH breakdown ($ per kg; electricity price: $ per MWh) 3.44 a high impact on 0.34 1 LCOH; securing 0.01 LCOH 1.21 favorable PPA 8.5 load factor: 89% would improve 8.0 LCOH 7.5 7.0 6.5 1.88 2 6.0 5.5 5.0 6.29 4.5 4.0 0.01 0.34 2 1.21 Reaching a competitive cost 3.5 of $2 to $3 per kg requires 1 low-cost electricity with high 3.0 load factors. 2.5 90% of hourly spot 2.0 prices between 4.73 1.5 $31 per MWh and $79 per MWh 1.0 (France, 2018) 0.5 0.0 Hydrogen value chain - 0 10 20 30 40 50 60 70 80 90 100 110 120 Electricity Capex Water Maintenance Total 2.3 Maturity and costs depreciation Electricity price

Note: PPA is power purchase agreement. Hypothesis: 1MW, capex: €1,000 per kW. 68 Sources: Areva H2Gen; “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis Electricity spot price LCOH per load factor Minimal LCOH (January–December 2018, $ per MWh, France) ($ per kg) occurs at load factors between 300 13.5 Spot prices (ascending order) 13.0 Electrolyzer 70 and 90%, but Spot prices (cumulated average) • Stack: 70,000 hours lifetime, 36% capex 12.5 • Electricity consumption: 60 kWh/kg the spot price Spot prices (chronological order) 12.0 $1,124 per kWe 250 range is too 11.5 $450 per kWe narrow to impact 11.0 10.5 LCOH at a high 10.0 utilization rate 200 9.5 9.0 8.5 8.0 Illustrative 150 7.5 7.0 6.5 6.0 100 5.5 5.0 4.5 4.0 50 3.5 3.0

Hydrogen value chain - 2.3 0.5 Maturity and costs 0 0.0 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 69 Sources: European Network of Transmission System Operators; Kearney Energy Transition Institute Upcoming R&D Key cost drivers and improvement per technology initiatives will help improve the efficiency of applications while reducing LCOH of blue hydrogen Steam methane reforming + CCS Black coal gasification + CCS Capacity factor – No change expected – No change expected

– Secure export offtake agreements – Successful demonstration at scale Scale and capacity – Export offtake agreements

– Scaling benefits, – R&D process intensification Capex – Process intensification – Scaling benefits

– Scaling benefits – Scaling benefits Opex – Improvements in build-up of slag and ash

– R&D process improvements, reused heat, – R&D improvements of purification, ASU, Efficiency membrane separation and CO2 removal

Risk – Reduced risk of CO2 capture – First of kind demonstration

Cost of capital – Support for CCS – Support for CCS

Hydrogen value chain - 2.3 Maturity and costs

70 Sources: “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Kearney Energy Transition Institute analysis RD&D efforts Key innovation themes in research and development Proton exchange membrane (PEM) required to lower LCOH for electrolyzers are primarily focused Reduced capital cost Longer lifetime Higher efficiency on lowering – Increase current density – Improved catalyst durability – Thinner membranes capital costs and – Lower loading of platinum group – Structural improvements in metal catalysts, new and improved electrodes increasing the catalysts Cell – Higher physical stability of lifetime of the – Improved coating of electrodes membrane system – Thinner membranes, advanced – Higher impurity tolerance of chemistry membrane

– Electrochemical pressurization, – Slower H2 embrittlement – Higher operating temperatures increased stack size through more suitable coating leading to stack and cooling efficiencies Stack – Reduction of titanium use – Optimized diffusor set-up – Scale up of system components – Improved water purification – More efficient rectification through more expensive – Efficient water purification – Avoidance of impurity diodes penetration – Improved component integration System – More efficient hydrogen – Optimized operation set points purification – Alkaline polymer systems – New low-cost stack designs – Design for high-pressure operation

Hydrogen value chain - 2.3 Maturity and costs

Note: Bold terms refers to the higher priority with in the impact area. Efficiency improvements are not prioritized. Non-continuous operations mean that operating costs are small, so reduction of capital costs is a higher priority. Efficiencies are maximized at low current density, but to reduce capital costs, research is focused on increasing current density instead. 71 Sources: “Future Cost and Performance of Water Electrolysis: An Expert Elicitation Study,” International Journal of Hydrogen Energy, 28 December 2017; Kearney Energy Transition Institute Capital cost Mechanism of capital cost reductions - Proton exchange membrane (PEM) reduction will become more Key levers Description Impact area: Cell important as – High current density allows the stack size to be smaller with increased efficiency. Hydrogen production rate is approximately low-cost electricity Increasing current proportional to the current density. from renewables density – Increase up to 3 A/cm2 (by 2020) and further (>3A/cm2) through better electrode design, catalyst coatings, and thinner becomes possible membranes Impact area: Cell – Better catalysts can lead to increased current density and reaction rate. Catalysts – Reduction in usage of expensive precious metals-based catalysts through the introduction of new and improved catalysts (telluride, Non-Exhaustive nano-catalysts, and mixed metal oxides such as RuOx and IrOx)

Impact area: Stack Reduction in – Titanium in bipolar plates (up to 51% of the stack cost) is costly, using a high-conductivity coating on low-cost substrate instead titanium use (such as stainless steel).

Impact area: System Scale-up – Enhance combination and scale-up (for example, safe operation with more than 200 cells) of system components due to system of system design de-risking and increased operational confidence; leads to better system integration and operation at optimized set points Hydrogen value chain - components 2.3 Maturity and costs

Sources: “Future Cost and Performance of Water Electrolysis: An Expert Elicitation Study,” International Journal of Hydrogen Energy, 28 December 2017, “Membraneless Electrolyzers 72 for Low-Cost Hydrogen Production in a Renewable Energy Future,” Joule, 20 December 2017; Kearney Energy Transition Institute Capex for AE capex evolution PEM CAPEX Evolution (2010–2030, $ per kW) (2010–2030, $ per kW) electrolyzer is expected to dramatically Capex ($ per kW) Capex ($ per kW) decrease by 2,500 2,500 2030

2,000 2,000

1,500 1,500

R&D initiatives on AE and PEM could drive capex 1,000 1,000 down to about €400 per kW for both technologies by 2030. 500 500

0 0 Hydrogen value chain - 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2.3 Maturity and costs

73 Sources: E4Tech, ITM Power; Kearney Energy Transition Institute LCOH evolution Blue hydrogen and ($ per kg, min–max. average) green hydrogen costs are expected to decline and close the gap with Blue technologies Green technologies brown sources by SMR + CCS Coal Alkaline PEM SOEC gasification electrolysis electrolysis electrolysis 2030 + CCS 9.6

7.5 6.9

Illustrative

5.0 3.8 3.5 2.5 2.5 2.6 1.9 2.6 2.2 1.6 1.9 2.1 1 1.5 1.3 1.4 1.6 1.6 Brown technologies

2019 2025–30 2019 2025–30 2019 2025–30 2019 2025–30 2019 2025–30

Green only if coupled with renewable electricity sources

Hydrogen value chain - 2.3 Maturity and costs

1 AUD = 70¢ 1 Thermochemical sources LCOH range 74 Note: All hypotheses are detailed in the appendix. Ranges are indicative ranges. LCOH highly depends on fossil fuel prices, electricity prices, and asset utilization. Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; International Energy Agency Greenhouse Gas R&D Programme; Commonwealth Scientific and Industrial Research Organisation; McPhy; Areva; Foster Wheeler; Department of Energy; International Renewable Energy Agency; Rabobank; TOTAL; CEA; Kearney Energy Transition Institute analysis Conversion and Conversion ($/kg) 2.2 reconversion 2.2 2.0 increase LCOH, 1.8 1.8 with compression 1.6 1.4 Further reduction potential being the cheapest 1.2 1.2 with salt caverns storage Improvement opportunities in option but with the 1.0 insulation1.8 and 1.0 lowest energy 0.8 vaporization rates 0.6 density once 0.4 Scaling1.0 benefits 0.4 0.4 0.3 0.3 stored 0.2 0.4 0.3 0.2 0.2 0.0

H2 conversion and Reconversion reconversion LCOH, ($/kg) 2.2 High costs for 2.1 including 2.0 decentralized on-site storage 1.8 applications 1.6 1.4 1.2 1.0 1.0 1.0 0.8 0.6 0.8 0.4 Hydrogen value chain - 2.3 0.2 Maturity and costs Negligible Negligible Negligible Negligible 0.0 Gas tanks - 35 bars Gas tanks - 150 bars Gas tanks - 350 bars Liquefaction Ammonia LOHC

75 Note: 1 AUD = 0.7 USD Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; Kearney Energy Transition Institute H2 transmission LCOH H2 distribution LCOH Transportation ($ per kg, km) ($ per kg, km) costs depends on $/kg $/kg the hydrogen 2.0 2.0 form, carrier, and distance traveled

1.5 1.5

1.0 1.0 100 tpd

0.5 0.5

500 tpd

0.0 km 0.0 km 0 1000 2000 3000 4000 0 100 200 300 400 500

Hydrogen value chain - 2.3 Gaseous H Liquefied H Ammonia LOHC Maturity and costs 2 2 Shipping Pipeline Truck

Note: 1 AUD = 70¢ 76 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis Case study: shipping H2 from A to B Conversion and (2019, $ per kg, base case) transportation of H2 can double LCOH, which could be avoided

with decentralized SMR + CCS Liquefaction Shiping: H2 Pipeline: Storage tanks: End production 3,000 km reconversion 50 km 350 bars consumer sources 100% 6% 7% 5% 0% 2% 6%

Illustrative 48% 48%

Transportation Storage 39% 39% Conversion Production

Hydrogen value chain - 2.3 Maturity and costs

Notes: The main hypotheses are detailed in the appendix. 1 AUD = 70¢ Sources: “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition 77 Institute analysis Key hydrogen applications

78 Some orders of magnitude in 2019 5 Executive summary 6 1. Hydrogen’s role in the energy transition 16 2. Hydrogen value chain: upstream and midstream 25 2.1 Production technologies 27 2.2 Conversion, storage, and transportation technologies 49 2.3 Maturity and costs 61 3. Key hydrogen applications 78 3.1 Overview 80 3.2 Feedstock 84 3.3 Energy 90 3. Business models 114 4.1 Policies and competition landscape 116 4.2 Business cases 125 Appendix (Bibliography & Acronyms) 187

79 Key applications Main H2 applications include chemicals and steel H2 use Application areas End-use application manufacturing, Oil refining Sulphur removal, heavy crude upgrade gas energy, power Chemicals production Feedstock for ammonia and methanol Feedstock Industrial Iron & steel production Direct reduction of iron (DRI) generation, and applications mobility Food industry Hydrogenation High temperature heat Fuel gas Light-duty vehicles Fuel cells Heavy duty vehicles Fuel cells Mobility Maritime Synthetic fuels / Fuel cells Rail Fuel cells Aviation Synthetic fuels / Fuel cells Energy Co firing NH3 in coal power plants Additional fuel for coal power plant

Power Flexible power generation Combustion turbines / Fuel cells generation Back-up / off-grid power supply Fuel for fuel cells Long-term / large scale energy storage Energy storage in caverns, tanks,… Blended H2 5-20% H2 mixed with CH4 Gas energy Methanation Transformation into CH4 Key hydrogen applications - 3.1 Overview Pure H2 100% H2 injected on network

80 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis Most H today is Hydrogen consumption by category 115 2 (2018, MtH per year) (100%) consumed by the 2 chemicals, oil 21 (18%) refining, and 94 steel industries (82%) 12 0 (10%) (0%) 73 Pure H2 13 (63%) (11%)

31 (27%)

42 Mixed 38 (37%) gases (33%)

Key hydrogen applications - 3.1 Oil Ammonia Steel Methanol Raw Transport Other Total Overview refining production production production materials applications production

81 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy transition Institute Applications will 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 mature at different Oil refining rates; some of them already have Chemicals production Decarbonized industrial feedstock

Iron and steel production

High-temperature heat High-temperature heat Low- to mid-temperature heat Industrial applications Industrial

Light-duty vehicles Berlines, SUVs City cars Forklifts

Heavy-duty vehicles Buses Trucks Coaches

Maritime Passenger ships Merchant navy Expected commercial maturity per application Rail (2020–2050)

Aviation Mobility

Power generation

Key hydrogen applications - Gas energy 3.1 Overview

82 Commercialization start Market maturity, defined as 1% of total sales

Sources: Afhypac; Kearney Energy Transition Institute analysis Possible hydrogen consumption by 2050 Hydrogen (pure hydrogen, MTH ) consumption 2 could reach X8 540 Mt per 539 year by 2050, 63 77 driven by (14%) industrial 63 63 processes and (12%) ~400mn cars transportation ~20mn trucks ~5mn buses 77 ~25% of diesel trains replaced ~5% of airplanes 154 and freight ships (29%) 112

Dedicated 154 hydrogen Industrial feedstock 245 production Mobility (45%) Power generation Gas energy

Key hydrogen applications - 70 3.1 Overview 2020f Mobility Industrial energy Building heat Industrial Power generation 2050f and power feedstock and buffering 83

Sources: Hydrogen Council, Kearney Energy Transition Institute analysis Oil refining is the Description Overview of technologies second main H2 Hydrotreatment and hydrodesulfurization: HDS unit Hydrocracking plant consumption – 70% of sulfur content in crude oil is removed through this process to reduce SO2 emissions when oil is burned.

source, with 38 Mt – H2S generated is captured and burned in an SRU to form SO2 and elemental sulfur. or about 33% of – By 2020, new regulations will impose to reduce sulfur global production content by 40% from 2005 levels.

used for Hydrocracking: hydrotreatment – Hydrocracking is the process to upgrade heavy residual oils into higher-value products — light and distillate with and hydrocracking less bonds. Capacity: 32,000 BPD Hydrocracking plant from – The majority of H2 is supplied by on-site production Yaroslavl Petroleum refinery sources.

Preliminary

Fact card: Oil refining H2 Market trends H2 source in oil refining

On-site production: about 80% Market maturity Mature Market size 38 (MtH2/year) Expected growth Less than +1% (CAGR 19-30) 38% 37% 2% 23% Competing technologies - Key hydrogen applications - 3.2 Feedstock

Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Phoenix Equipment Refinery On-site On-site External 84 Corporation; Tokyo Engineering; Kearney Energy Transition Institute analysis by-product SMR coal gasification supply The chemicals Description Overview of technologies industry consumes Ammonia synthesis: Ammonia production Methanol production – H2 is combined with N2 extracted from a air separation unit about 45 Mt of H2 through the Haber–Bosch process. + a year for ammonia 2 3 – About 80% of global NH production is used in fertilizer 𝑁𝑁 3 3𝐻𝐻2→ 2𝑁𝑁𝑁𝑁 and methanol production ((NH2)2CO, NH4NO3). synthesis Methanol production:

– H2 is combined with CO and CO2 to form methanol in a catalytic reaction. Ammonia production plant in Methanol production plant 2 + 3 + 2 Slovakia for Duslo + 3 2 𝐶𝐶𝐶𝐶 23𝐻𝐻+ → 𝐶𝐶𝐶𝐶 𝑂𝑂+𝑂𝑂 2 𝐻𝐻 𝑂𝑂 𝐶𝐶𝐶𝐶 2𝐻𝐻2→ 𝐶𝐶𝐶𝐶 𝑂𝑂𝑂𝑂 – Methanol can be converted2 into polymers and hydrocarbon olefins and used as𝐶𝐶𝐶𝐶 fuel𝐻𝐻 for→ ICE,𝐶𝐶𝐶𝐶 even𝐻𝐻 𝑂𝑂 if this technology is in an early stage. Preliminary

Fact card: Chemicals industry H2 Market trends H2 source in chemical industry

Market maturity Mature Market size 44–46 (MTH2 per year) Expected growth +2% 65% 30% 5% (CAGR 19–30) Traditional fuels Competing technologies Key hydrogen applications - vs. methanol 3.2 Feedstock

Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Natural gas Coal Oil 85 Norway Exports; Kearney Energy Transition Institute analysis The steel industry Description: Basic oxygen furnace Description: Direct reduction of iron consumes about – About 75% of production comes from primary sources – About 75% of production comes from primary sources where iron ore is converted to steel. where iron ore is converted to steel. 13 Mt H2 per year, – 90% is made through a blast furnace–basic oxygen furnace – 7% is made through direct reduction of iron-electric arc 4 of which is (BF–BOF) producing hydrogen as a by-product of coal furnace (DRI–EAF), using H2 and CO as reducing agent. mixed with other gases, such as CO. H2 is produced in dedicated facilities (SMR/gasification plants) and not as a by-product. dedicated for direct – Global annual production reaches about 14 MTH2 per year. 3 2 3 + 3 4 + 2 reduction of iron + 3 + – About 65% of this gas is used on-site for various 3 4 2 𝐹𝐹𝐹𝐹 𝑂𝑂 +𝐻𝐻2→ 2𝐹𝐹𝐹𝐹+𝑂𝑂 𝐻𝐻 𝑂𝑂 applications (9 MTH year), and the remaining (5 MTH 2 2 2 𝐹𝐹𝐹𝐹 𝑂𝑂 2𝐻𝐻2→ 𝐹𝐹𝐹𝐹𝐹𝐹 𝐻𝐻 𝑂𝑂 year) is used in other sectors, such as power production 𝐹𝐹𝐹𝐹𝐹𝐹 𝐻𝐻2→ 𝐹𝐹𝐹𝐹 𝐻𝐻 𝑂𝑂 and methanol production).

Basic oxygen furnace Electric arc furnace from from Nippon Steel Acciaieria Arvedi SpA

Preliminary

Fact card: Steel industry H2 Market trends H2 source in oil refining

BF–BOF: about 69% DRI-EAF: ~31% Market maturity Mature Market size 13 (MtH2/year) Expected growth +6% (CAGR 19-30) 69% 23% 8% Recycling of scrap steel Competing technologies Key hydrogen applications - (25% of total prod.) 3.2 Feedstock

Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Nippon Steel Engineering; Acciaieria Arvedi SpA; Kearney Energy Transition Institute Furnace by-product SMR Gasif. 86 analysis Adopting low Hydrogen based Direct Reduction proposed process design1 carbon energy sources and Use of Hydrogen to lower reducing agents, emissions such as Hydrogen, can help – To reduce carbon emissions in steel making, two fundamental options include decarbonize steel – continued use of fossil fuels but with production carbon capture and storage (CCS) – the use of renewable electricity for producing hydrogen as reduction agent or directly in (yet undeveloped) electrolytic processes – Blast furnace – basic oxygen furnace (BF/BOF) production route, which is the dominant production pathway currently, relies on the use of coking coal making it Fact card: Steel industry difficult to switch to other reduction agents in the blast furnace – Key concept is to use a hydrogen direct reduction process to produce direct reduced iron (DRI) which is then converted to steel in an electric arc furnace (EAF) – Ideally Hydrogen should be produced from renewable sources. However, as an intermediate solution, fossil fuels (mainly natural gas) are used to produce Hydrogen until sufficient carbon free electricity will be Key hydrogen applications - 3.2 available at competitive prices Feedstock

87 1. HBI – Hot-briquetted iron, EAF - Electric arc furnace Sources: Assessment of hydrogen direct reduction for fossil-free steelmaking (Vogi, Ahman, Nilsson 2018), Steel Institute VDEh Estimated costs of steel for selected greenfield production routes1 Currently 100% Levelized costs (USD/t), 2018 estimates Hydrogen based

steel production is 1.100 1 084 Range Feedstock Fixed OPEX 1.000 not cost CCUS Fuel CAPEX competitive 900 859 800 630 compared to the 700 587 378 more established 600 563 500 163 479 170 0 0 alternatives 398 14 132 400 52 0 111 197 0 121 138 14 300 121 90 62 49 159 52 200 21 166 24 166 166 100 145 156 104 87 0 59 54 57 46 66 BF-BOF DRI - EAF DRI - EAF w/CCUS Oxy-SR-BOF 100% Hydrogen 50% Hydrogen w/CCUS DRI - EAF DRI - EAF Commercial Demo2 Pilot3

The economic viability of the hydrogen-based steel production pathways is highly dependent on the low cost clean electricity or higher carbon prices

Key hydrogen applications - 3.2 Feedstock

1. BF = Blast furnace, DRI = Direct reduced Iron, EAF = Electrical arc furnace, Oxy. SR-BOF = oxygen-rich smelt reduction, CCUS = Carbon capture and storage 88 2. Hisarna project 3. HYBRIT project for 100% Hydrogen DRI - EAF Sources: IEA – The Future of Hydrogen (2019) Demand for Energy and hydrogen requirements for DRI-EAF production route dedicated Strong Coal (Mtoe) Gas (bcm) Electricity (TWh) Hydrogen (MT) demand in Hydrogen medium and production in steel 12 31 230 long term 62 is expected to grow at a rapid 20 pace over the next decade 10 13 4 0 2018 2030 2018 2030 2018 2030 2018 20301 20502

– Without any policy intervention and projecting on the current trends, the demand for dedicated hydrogen production (derived chiefly from natural gas) in steel-making is expected to track growth of gas based DRI-EAF production route – DRI-EAF tends to be deployed in geographies with low natural gas prices (i.e. Middle East) or low coal price (i.e. India) and could supply 14% of primary steel demand by 2030 – For an accelerated rate of emission reduction in steel making process, the following technological breakthroughs are required which would further increase the demand for hydrogen: – 30% of the natural gas consumed in DRI-EAF to be replaced by hydrogen produced from electrolysis (renewable sources) – Commercial-scale 100% Hydrogen based DRI-EAF plant by 2030 Key hydrogen applications - 3.2 Feedstock

Based on trends in total crude steel production, the split between primary & secondary steel production and the share of the DRI-EAF route in primary steel 89 1. Assumption - share of secondary production in total steel production in 2030 = 25%, gas based DRI maintains current growth in primary production 2. Assumption - share of secondary production in total steel production in 2050 = 29%, gas based DRI accounts for 100% primary production Sources: IEA – The Future of Hydrogen (2019) Among Fuel Cells, Fuel cell technologies comparison PEM seems to be the most promising Electri Current applications fuel cell technology, cal Tempe Slack Improvement perfor Advantages Challenges with the widest rature size mance potential utility power power power Space Military Electric Backup vehicles Portable Auxiliary Auxiliary Specialty Transport generation range of application (LHV) Distributed – Low corrosion and – Expensive catalysts Polymer and demonstrated electrolyte management – Sensitive to fuel electrolyte <1– <120°C – Low temperature impurities high-power membrane 100kW 60% (PEM) – Quick start-up and load efficiency following – Lower cost components – Sensitive to CO2 in fuel – Low temperature and air – Electrolyte Alkaline 1- – Quick start-up <100°C management 100kW 60% (AFC) (aqueous) – Electrolyte conductivity (polymer) – Suitable for CHP – Expensive catalysts Phosphoric <150 – 5- – Increased tolerance to – Long start-up time acid 40% 200°C 400kW fuel impurities – Sulfur sensitivity (PAFC)

– High efficiency – High temperature Molten 600- 300kW – Fuel flexibility – Long start-up time carbonate 50% 700°C – 3MW – Suitable for CHP – Low power density (MCFC) – Hybrid–gas turbine cycle – High efficiency – High temperature – Fuel flexibility – Long start-up time Solid oxide 500- 1kW- 60% – Solid electrolyte – Limited number of (SOFC) 1000°C 2MW Key hydrogen applications – – Suitable for CHP shutdowns 3.3 Energy (fuel cells) – Hybrid/ gas turbine cycle

90

Sources: US Department of Energy, 2015; Kearney Energy Transition Institute analysis Fuel cell is a reverse Description Overview of Technology electrolysis in which – Fuel cells are made of an anode and a cathode in an Main technologies electrolyte solution. Anode and H is combined Type Ions 2 – Fuel-cell reaction can be described as: cathode 1 with O to produce H + O H O + We + - 2 2 2 2 AFC PT/Pt–Ag OH electricity, heat, where We is electrical2 power and Q heat generated → ΔQ PEMF Pt/Pt H+ – Fuel cells generate DC current. An AC/DC converter might C and water be needed depending on the end application.Δ PAFC PT/Pt H+ – As for electrolyzer, there are multiple categories of fuel cells based on the electrolyte and electrodes used: MCFC Ni/Ni–LiO CO 2- – AFC is the oldest available technology, but efforts are 3 now focusing on PEMFC used in electric vehicles. Ni-YSZ/ Fuel cell principle O2- – Microbial fuel cells are being developed, based on SOFC LaxSr1- bacteria metabolism. xMnO3

– Application types for fuel cells can be portable (consumer Expanded in following slides Perovskite/ + PCFC + H electronics), mobile (vehicles), or stationary. Pr2NiO4

Fact card: Fuel cell H2 Market trends Key features

Market maturity Depend on technology Efficiency (%) 55–60% Market size +1,000 Power (W/cm2) 0.3–0.4 (MW per year) (about 75% for mobility) Lifecycle (hours) Up to 100,000 Historical growth +33% in MWe Compacity (kW/kg) About 3 (CAGR 10–17) Capex (€ per kWe) 500–1,000 – Electricity production Key hydrogen applications – 3.3 sources Energy (fuel cells) Competing technologies – Internal combustion engines 91 Sources: Afhypac, Areva; Kearney Energy Transition Institute analysis Alkaline fuel cells Description Overview of Technology were one of the – Alkaline fuel cell (AFC) uses a solution of potassium hydroxide in water as the electrolyte and can use a variety first fuel cell of non-precious metals as a catalyst at the anode and technologies cathode. – Fuel cell reaction can be described as: 2H2 + O 2H2O

– The high performance of AFC2 is due to the rate at which electro-chemical reactions take→ place in the cell. – Closely related to polymer electrolyte membrane (PEM) fuel cells, except they use an alkaline membrane instead of an acid membrane

– Suffers from the poisoning by CO2, which can be addressed through alkaline membrane fuel cells (AMFC)

– However, CO2 still affects performance, and performance and durability of the AMFCs still lag that of Alkaline fuel cell principle PEMFC. – Key application areas: military, space, backup power, and transportation Fact card: Alkaline fuel cell Key features

Advantages Disadvantages Efficiency (%) 60% – Wider range of – Sensitive to CO2 stable materials in fuel and air Operating temperature (°C) Less than 100 allows lower cost – Electrolyte Typical stack size 1–100 kW components management Aqueous potassium – Low temperature (aqueous) hydroxide soaked in a Common electrolyte – Quick start-up – Electrolyte porous matrix or alkaline Key hydrogen applications – conductivity polymer membrane 3.3 Energy (fuel cells) (polymer) Anode/Cathode PT / Pt-Ag

92 Sources: US Department of Energy; “Introduction to Hydrogen Technology,” Introduction to Transfer Phenomena in PEM Fuel Cell, Bilal Abderezzak, 2018; Kearney Energy Transition Institute analysis Polymer electrolyte Description Overview of Technology membrane fuel cells – Polymer electrolyte membrane (PEM) fuel cell uses solid polymer as an electrolyte and porous carbon electrodes deliver high power containing a platinum or platinum alloy catalyst. – Fuel cell reaction can be described as: density and lower + H2 2H + 2e weight and volume – PEM fuel cells exhibit high efficiency− and power density in vehicle engine size class.→ – Among different fuel cells, PEM fuel cell has been found to be most suitable for automobiles end use. – Hybrid vehicle can be run by pairing PEMFC with rechargeable batteries. – A variant that operates at elevated temperatures is known as the high-temperature PEMFC (HT PEMFC) as electrolyte shifts to a mineral acid-based system from Polymer electrolyte membrane fuel cell principle water-based. – Key application areas: backup power, portable power, Fact card: Polymer distributed generation, transportation, and specialty electrolyte membrane vehicles. fuel cell

Advantages Disadvantages Key features

– Solid electrolyte – Expensive platinum 60% direct H ; Efficiency (%) 2 reduces corrosion catalyst that is 40% reformed fuel and electrolyte sensitive to CO management poisoning Operating temperature (°C) Less than 120 issues – Requires cooling Typical stack size Less than 1–100 kW – Low temperature Common electrolyte Perfluoro sulfonic acid Key hydrogen applications – – Lower weight and 3.3 Energy (fuel cells) volume Anode/Cathode Pt / Pt – Quick start-up and load following 93

Sources: US Department of Energy; Kearney Energy Transition Institute analysis Phosphoric acid Description Overview of Technology fuel cell is one of – Phosphoric acid fuel cells (PAFC) use liquid phosphoric acid as an electrolyte—the acid is the most mature contained in a Teflon-bonded silicon carbide matrix— cell types and the and porous carbon electrodes containing a platinum catalyst. first to be used – Fuel cell reaction can be described as: 1 commercially H + O H O 2 2 2 – Typically used for stationary2→ power generation, but some PAFCs have been used to power large vehicles: – More than 85% efficient when used for the co- generation of electricity and heat but they are less 2D model of PAFC efficient at generating electricity alone (37–42%) Phosphoric Acid Fuel cell principle – PAFCs are also less powerful than other fuel cells, given the same weight and volume. – Key application areas: Distributed generation and heavy vehicle transport, such as public buses Fact card: Phosphoric acid fuel cell

Advantages Disadvantages Key features

– Suitable for CHP – Expensive catalysts Efficiency (%) 40% – Increased tolerance – Long start-up time Operating temperature (°C) 150–200 to fuel impurities – Sulfur sensitivity Typical stack size 5–400 kW Phosphoric acid soaked in a Common electrolyte porous matrix or imbibed in Key hydrogen applications – 3.3 a polymer membrane Energy (fuel cells) Anode/Cathode Pt / Pt

94

Sources: US Department of Energy; Kearney Energy Transition Institute analysis Molten carbonate Description Overview of Technology fuel cells are being – Molten carbonate fuel cells (MCFC) use a molten carbonate salt suspended in a porous ceramic matrix developed for as the electrolyte. natural gas and – Fuel cell reaction can be described as: 1 H + O H O coal-based power 2 2 2 plants for electrical – When coupled with a turbine,2→ MCFC can reach efficiencies approaching 65%. utility applications – Overall efficiencies can be more than 85% in CHP or CCP applications where the process heat is also utilized. – Unlike alkaline, phosphoric acid, and PEM fuel cells, MCFC do not require an external reformer to convert Molten carbonate fuel cell principle fuels such as natural gas and biogas to hydrogen. – As they operate at high temperatures, non-precious metals can be used as catalysts reducing costs. – Key application areas: electric utility and distributed Fact card: Molten generation carbonate fuel cell

Advantages Disadvantages Key features

– High efficiency – High temperature Efficiency (%) 50% – Fuel flexibility corrosion and Operating temperature (°C) 600–700 – Suitable for CHP, breakdown of cell hybrid–gas turbine components Typical stack size 300 kW–3 MW cycle – Long start-up time Molten lithium, sodium, Key hydrogen applications – 3.3 – Low power density and/or potassium Energy (fuel cells) Common electrolyte carbonates, soaked in a porous matrix 95 Anode/Cathode Ni / Ni – LiO

Sources: US Department of Energy; Kearney Energy Transition Institute analysis Solid oxide fuel Description Overview of Technology cells are the most – Solid oxide fuel cells (SOFC) use a hard, non-porous sulfur-resistant ceramic compound as the electrolyte. – Fuel cell reaction can be described as:

type of fuel cell CO + O + H2 H2O + CO +

– SOFCs are 2around 60% efficient2 at converting fuel to electricity. → ΔE – In applications designed to capture and utilize the system's waste heat (co-generation), overall efficiencies could be more than 85%. – High-temperature operation removes the need for precious-metal catalyst reducing costs, but development of low-cost materials with high durability remains a challenge. Solid Oxide Fuel cell principle – SOFC are not poisoned by carbon monoxide, and this allows them to use natural gas, biogas, and gases made from coal. – Key application areas: auxiliary power, electric utility, Fact card: Solid oxide and distributed generation fuel cell

Advantages Disadvantages Key features

– High efficiency – High temperature Efficiency (%) 60% – Fuel flexibility corrosion and Operating temperature (°C) 500–1,000 – Sulfur resistant breakdown of cell – Suitable for CHP, components Typical stack size 1 kW–2 MW Hybrid/gas turbine – Long start-up time Common electrolyte Yttria stabilized zirconia Key hydrogen applications – 3.3 cycle Energy (fuel cells) Anode/Cathode Ni-YSZ / LaxSr1-xMnO3

96

Sources: US Department of Energy; Kearney Energy Transition Institute analysis Fuel cell research Technical targets and system cost reduction projections for 80 kWe (net) integrated transportation fuel cell power systems operating on direct hydrogen1, 2 is focused on -82% achieving higher 165 100,000 systems per year 25 efficiency, increased 500,000 systems per year durability, and Present cost of automotive PEMFC system basis deployed reduced costs commercial technology at current manufacturing rates (1,000 systems per year) = $210 kWnet

-5% 140 65 63 59 60 -3% 11 10 7 7 49 50 5 5 40 30 54 53 52 53 44 45

2006 …. 2013 2014 2015 2016 2017 2018 ….. 2025 …. Final stage

2015 2020 Final stage Peak energy efficiency (%) 60 65 70 Power density (W/L) 640 650 850 Specific power (W/kg) 659 650 650 Key hydrogen applications – 3.3 2 Energy (fuel cells) Durability (hours) 3,900 5,000 8,000

97 1 Polymer electrolyte membrane (PEM) fuel cell-based systems 2 8,000 hours (equivalent to 150,000 miles of driving) with less than 10% loss of performance Sources: US Department of Energy Fuel Cell Technologies Office; Kearney Energy Transition Institute analysis Fuel cell R&D funding1 Reducing costs and Key (Total $ million, improvement Areas improved Benefits and challenges improving durability % breakup) levers while maintaining 32 For platinum group metal Current state-of-the-art MEAs with performance (PGM) based catalysts, both very low cathode PGM loadings a reduction in PGM loading experience a higher-than-expected continues to be and an increase in membrane reduction in performance when electrode assembly (MEA) operating at high power. a key challenge 44% areal power density are required to reduce material costs.

Non-Exhaustive Improving high-current State-of-the-art electrode structures density performance at low are hindered by severe mass- Catalyst PGM loadings (≤0.125 transport limitations during high- mgPGM/cm2) power operation, in part because of 12% transport resistance induced by the ionomer, particularly as the PGM 3% loading decreases. Catalyst developments are Development of low PGM Initial results show PtCo/HSC-f crucial to future fuel cell catalysts such as accessible catalyst matches or surpasses the technology 23% porous carbon-supported performance of a catalyst used in PtCo catalysts, ultrathin-film commercial FCEVs despite having catalysts (to stabilize Pt) less than one-fifth the platinum loading.

19% Potential benefits of favorable Higher efficiency as a result of the Intermediate- kinetics and decreased production of useful waste heat Temperature sensitivity to fuel impurities, and/or the elimination of balance-of- such as CO, also reduce plant components Membranes 2018 PGM catalyst usage. RFC provides easily Viability and cost competitiveness of Catalyst and electrodes Reversible dispatchable power and is RFC technology require continued Performance and durability sufficiently flexible to address improvements to target round-trip Testing and technical assessment fuel cells Key hydrogen applications – grid and microgrid reliability efficiency and capital cost targets. 3.3 (RFC) Energy (fuel cells) Membrane and electrolytes and resiliency. Membrane electrode assembly, cells, and stack components 98 1 US Department of Energy Fuel Cell R&D subprogram budget Sources: US Department of Energy Fuel Cell Technologies Office; Kearney Energy Transition Institute analysis Bikes powered by Description fuel cells offer an – Fuel-cell electric bikes use stored compressed hydrogen gas cylinders as a fuel source to generate easy mobility option electricity via an energy converter (fuel cell) to power for intra-city travel an electric motor but still needs human muscular energy to be in motion. Hydrogen cylinders can be Fuel cell purchased from refueling stations and other retail outlets. – Benefits: – Lower battery size, superior operability at low temperatures, longer range, and shorter refueling

time compared with battery-powered bikes H2 – No emissions of pollutants and greenhouse gases cylinders – Prospective customers: private consumers, bike- sharing operators and rental providers, tourism players, last-mile delivery specialists, corporate staff mobility, and municipalities

Fact card: Hydrogen bike

H2 Market trends Key features

Advanced prototype/ Power output (kw) 0.1–0.25 Market maturity demonstration Fuel consumption .035 Market size (number (Kg H /100 km) More than 200 in France 2 of units) Range (km) 100–150 Multiple orders of hundreds of Capex/acquisition cost ($) 5,000–7,500 Future growth bikes expected in European cities Lifetime (years) 5 Key hydrogen applications – 3.2 Energy (mobility) Competing technologies Electric bikes

99 Source: Kearney Energy Transition Institute analysis Scooters and bikes Description Overview of technologies powered by fuel – H2 is stored in compressed tanks and then converted into Compressed H2 tank Hydrogen can electricity through a PEMFC, powering an electrical motor. cells offer emission- – Refueling of a compressed H2 tank is performed in dedicated free and low-noise stations. – The latest research focuses on metal hydrides, where H2 is mobility options for stored as a powder in 2 cans, which facilitate refueling as no H2-dedicated infrastructure is needed. intra-city travel – H2 can could be bought in petrol stations and supermarkets. – Metal hydrides are easy to refuel and can operate at low temperature but are more expensive. Hydrogen is stored in – H2 scooters offer multiple benefits, such as no pollutant powder in a 2.5 L can emissions, lower noise, and operability at low temperatures. – Potential users include private consumers, company and public entity fleets, or vehicle sharing companies. – Large-scale deployment will require refueling infrastructure and compliance with local regulations.

Fact card: Hydrogen scooter H2 Market trends Key features Market maturity Deployment 0.3–0.8/2 cans for Fuel consumption (gH /km) 2 200 km More than 100, demonstration projects in Range (km/tank) 120–200, up to 350 Market size Europe (such as the ZERE (number of vehicles) Lifetime (years) 5 project in the United Kingdom) Capex/acquisition cost ($) 3,400–13,000 Public services to lead the Output (kW) 3–4 kW Expected growth demand due to high price (CAGR 19–XX) premiums Key hydrogen applications – 3.2 Energy (mobility) Petrol and diesel, battery Competing technologies EV, compressed natural gas (CNG) 100

Sources: The Fuel Cells and Hydrogen Joint Undertaking (FCH JU); Kearney Energy Transition Institute analysis Fork lifts powered Description Overview of technologies by fuel cells are – Forklifts use gaseous hydrogen compressed in a 350 bars tank. already in use since – Hydrogen is then converted into electricity through a fuel they don’t need cell– electric engine system. – Potential users include logistics companies, warehouses, capex-intensive and other industrial plants. – A hydrogen forklift does not release toxic gases during infrastructure for operations, which makes it a candidate for indoor recharging operations. – Tanks are recharged every eight hours. Quick refueling time (less than three minutes) allows operation continuity for industrial users. – Performances are maintained even when the tank is half depleted. – The operating perimeter is relatively limited. Single refueling stations with multiple plants can be enough to supply hydrogen.

Fact card: Hydrogen forklift

H2 Market trends Key features

Market maturity Commercialization Fuel consumption 0.15 (kgH per hour) Market size 2 25,000 (number of vehicles) Range (km per tank) 8 Expected growth (CAGR $14,000–$30,000 (fuel n.a. Capex/acquisition cost ($) 19–XX) cell system) Petrol and diesel, battery Output (kW) 2.5–4.5 Key hydrogen applications – Competing technologies EV, compressed natural 3.2 Fuel consumption (kgH2 per Energy (mobility) gas (CNG) 0.15 hour)

101

Sources: Toyota; BallardThe Fuel Cells and Hydrogen Joint Undertaking (FCH JU); “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute Fuel-cell hydrogen Description Overview of technologies cars are – As with scooters, H2 is stored in compressed tanks (700 bars) and then converted into electricity through a PEM fuel cell, commercially powering an electrical motor and refueled in dedicated stations. available as an – A rechargeable (Li–ion or lead–acid) battery is added to provide additional power for the engine—mainly for alternative to diesel- regenerative braking and acceleration (1.6–9 kWh capacity). based internal – H2 stored in metal hydride cans is also under development (a car requiring about nine cans), which could offset a low combustion engine number of refueling stations. – H2 cars offer multiple benefits, such as no pollutant emissions, cars lower noise, and operability at low temperatures. – Potential users include private consumers, company and public entity fleets, or vehicle-sharing companies. – Large-scale deployment will require refueling infrastructure and compliance with local regulations, especially on tank safety. Preliminary

Fact card: Hydrogen car

H2 Market trends Key features

Market maturity Commercialization Fuel consumption (kgH2/100km) 0.8–1.0 Market size Range (km per tank) 500–700 11,200 (number of vehicles) Lifetime (years) 5 Expected growth 18% (+56% 17–18) Capex/acquisition cost ($) 56,000–86,000 (CAGR 2025f) Output (kW) 70–130 kW Petrol and diesel, petrol and Key hydrogen applications – Competing technologies diesel–electric hybrid, 3.2 Energy (mobility) battery powered cars

102 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute Vans and utility Description Overview of technologies

trucks powered by – Vans can also be equipped with a H2 tank–PEM fuel cell– Li-ion battery–electric motor combination. fuel cells can be – Battery packs have a 22 to 80 kWh capacity (vans). used for short- – Potential users include company fleets (such as parcel delivery companies) and public fleets (such as garbage distance, cyclical trucks and sweepers). – Large-scale deployment will require refueling infrastructure trips and compliance with local regulations, especially on tank safety. – However, because of the cyclical nature of trips, a refueling station for public applications could be centralized and shared between all city vehicles. – Hydrogen–diesel hybrid trucks are also commercialized, where H2 is powering non-vital applications, such as for garbage trucks or a power box for a loader and compactor.

Fact card: Hydrogen van

H2 Market trends Key features

Market maturity Deployment Fuel consumption (kgH2/100km) 3–9 Market size Range (km per tank) 300–400 About 100 vans (number of vehicles) Capex/acquisition cost ($) n.a. Expected growth n.a. Output (kW) 45–150 kW (CAGR 2019f) Total cost of ownership Petrol and diesel, petrol and n.a. ($ per km) Key hydrogen applications – Competing technologies diesel-electric hybrid, 3.2 Energy (mobility) battery powered vans

103 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute Hydrogen buses Description Overview of technologies powered by fuel – Fuel-cell electric buses, including hybrids with range extenders, use compressed hydrogen gas as a fuel to cells are a zero- generate electricity via the fuel cell. emission – Benefits: – No emissions of pollutants and greenhouse gases alternative to – Lower noise pollution – Potential to be more cost effective than electric biofuels diesel buses or diesel based variants – Prospective customers: public transport authorities, bus service operators, airports (minibuses), hotels, and resorts

Fact card: Hydrogen buses

H2 Market trends Key features

Market maturity Deployment Fuel consumption (Kg H2/100km) 8–14 Market size Range (km per tank) 250–450 More than 500 (number of vehicles) Power output (kW) 100 Several thousand buses CAPEX/Acquisition cost ($) 680,000 Future growth expected in China, Japan, Total cost of ownership and 4 ($ per km) Key hydrogen applications – Electric, diesel, diesel- 3.2 Energy (mobility) Competing technologies electric hybrid, biofuels, CNG

104

Source: Kearney Energy Transition Institute analysis Hydrogen trucks Description Overview of technologies and buses powered – Buses and trucks can be equipped with a H2 tank–PEM fuel cell–Li-ion battery–electric motor combination. by fuel cells are – The Li-ion battery can be used to regenerate energy from braking or can be recharged with plug-in solutions to expected to gain deliver power during acceleration phases or to extend market share, range. – Hydrogen tank has a capacity of about 150 kgH2, making mainly in China it lighter than the battery part from a BEV truck.

Fact card: Hydrogen truck

H2 Market trends Key features

Market maturity Deployment Fuel consumption (kgH2/100km) 7.5–16 Market size Range (km per tank) 1,200 About 400 trucks (number of vehicles) Fuel cell efficiency 55% Expected growth Several thousand trucks Output (kW) 250–750 kW (trucks) (CAGR 2019f) expected in China Capex/acquisition cost ($) 350,000 Diesel, diesel-electric Key hydrogen applications – Competing technologies hybrid, battery-powered Total cost of ownership 3.2 0.95–1.75 Energy (mobility) trucks ($ per km)

105

Sources: The Fuel Cells and Hydrogen Joint Undertaking (FCH JU); “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute Hydrogen can be Description Overview of technologies the main power – Fuel-cell ships, boats, and ferries use stored compressed Excess warm vapor output hydrogen gas as a fuel source to generate electricity via an source for small energy converter (fuel cell) to power an electric motor. – This is a viable low-carbon fuel for smaller marine vessels. boats or supply For larger vessel, fuel cells can supplement the main Hydrogen power. and air electricity to on- react to – Hydrogen can also be converted in synthetic fuels through form board applications methanol. electricity Hydrogen – Existing infrastructure in industrial ports (such as SMR from fuel tanks to providing hydrogen to nearby factories) can be leveraged. fuel cells – Benefits: – Depending on the crude prices and clean fuel Atmospheric regulations, potentially lower total cost of ownership in air from the future exterior – No emissions of pollutants and greenhouse gases Water output (re-used on board) – Lower noise pollution and beneficial to marine wildlife

Fact card: Marine applications H2 Market trends Key features

Market maturity Concept or early prototype Power output (kw) 12–2,500 (ferries) Demonstration projects Fuel consumption (Kg H /nm) 3.4 (ferries) Market size 2 under way in the European (number of units) 50–90, 8–12 Union Range (km, hours) (smaller boats) Medium-term Future growth 12–16.5 million commercialization unlikely Capex/acquisition cost ($) (ferries) Key hydrogen applications – Hydrocarbon fuels, diesel- 3.2 Lifetime (years) 25 Energy (mobility) Competing technologies electric hybrid, battery electric

106

Source: Kearney Energy Transition Institute analysis Hydrogen trains Description Overview of technologies powered by fuel – Hydrogen trains use multiple H2 storage tanks combined with PEMFC and electric engines. cells can offer a – Hydrogen trains also have Li-ion batteries to regenerate low-carbon brake energy. – Large autonomy makes it suitable for regional routes, with alternative to diesel cyclical trips (100–200 km) and a refueling station. – No electric lines are required, which makes it suitable for locomotives different topographic profiles, such as tunnels and mountains. – Potential uses include non-electrified lines for diesel trains replacement, city trams, and trains for industrial applications, such as mining.

Alstom’s hydrogen train

Fact card: Hydrogen train

H2 Market trends Key features

Market maturity Deployment Fuel consumption (kgH2/100km) About 33 Market size Multiple projects worldwide Range (km per tank) 600–800 (number of vehicles) Two trains in Germany Output (kW) 400 Expected growth n.a. 13 million for a regional (CAGR 2019f) Capex/acquisition cost ($) 150-coach train Diesel, electric, Competing technologies Total cost of ownership Key hydrogen applications – battery-powered – 3.2 ($ per km) Energy (mobility)

107

Sources: The Fuel Cells and Hydrogen Joint Undertaking (FCH JU); “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute Hydrogen aircrafts Description Overview of technologies powered by fuel – Small aircraft powered by fuel cells can use stored compressed hydrogen gas to generate electricity via an cells could offer a energy converter (fuel cell) to power an electric motor. The focus is on using it as a propeller powertrain for smaller solution to reduce aircraft or as an auxiliary power unit (APU) on large aviation-based conventional aircraft. – Pure hydrogen or hydrogen-based liquid fuels also offer emissions alternative pathways, subject to further R&D. – Benefits: – Reduced costs as a result of lower OPEX (engine) and increased efficiency – No emissions of pollutants and greenhouse gases – Prospective customers: airlines, national and local governments, airport operators, and private fleets

Fact card: Aviation

H2 Market trends Key features

Market maturity Concept or early prototype 80 (based on Power output (kw) HY4 project) Limited to demonstration Market size projects for small aircrafts, 170 (based on (number of units) Fuel consumption (Kg H ) such as HY4 2 HY4 project) Short-range non-essential 750–1,500 (based Range (km) Future growth uses, unmanned missions, on HY4 project) and drones Key hydrogen applications – Capex/acquisition cost ($) n.a. 3.2 Energy (mobility) Petroleum-based aviation Competing technologies Lifetime (years) n.a. fuel, battery powered

108

Source: Kearney Energy Transition Institute analysis. Co-firing ammonia Description Overview of technologies in coal-power – Hydrogen-based fuel ammonia can be co-fired in coal-fired power plants to reduce coal usage and plant carbon plants could emissions. – IHI Corporation successfully co-fired a ammonia–coal reduce carbon mix with 20% ammonia in a 10 MW furnace (% of energy emissions at low content). – The previous test conducted by Chugoku Electric in a cost; special 150 MW furnace reached a 0.8% (% of energy content). attention needs to – Boiler’s energy conversion efficiency is maintained. – Ammonia feeding pipe design allows to control NOx be given to NOx emissions, which are similar to regular coal plant. – In small furnaces (less than 10 MWth), reaching 20% of emissions ammonia in the combustion zone does not pose any particular problems, and no slippage of ammonia into exhaust gas was detected. – Technology can be retrofitted into existing coal-fired boilers. – The economics of projects will depend on availability of Mizushima coal plant, operated by Chugoku Electric low-cost ammonia. Fact card: Ammonia co-firing in coal power plants

H2 Market trends Key features

Ammonia marginal consumption Market maturity Early stage 26,800 (kgNH3/%ammonia/MW per y) Market size 2,100 Hydrogen marginal consumption (2019, GW, coal-fired) 4,800 (kgH2/%ammonia/MW per year) Expected market size 1,650 (including combined (2030, GW, coal-fired) heat and power) Key hydrogen applications – Competing technologies CCS, decarbonized sources 3.3 Energy (power generation)

109 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; IHI Corporation; Chugoku Electric; Kearney Energy Transition Institute analysis Flexible power Description Overview of technologies generation is the – Hydrogen can be used as a fuel in existing gas turbines and CCGTs, which can handle a 3 to 5% share of use of hydrogen to hydrogen, up to 30% for some turbines. – Ammonia can also be used as a fuel in gas turbine. produce electricity However, NOx emissions and flam stability needs to be on demand and controlled. – Fuel cells have efficiencies close to CCGTs but suffer from operating at low a shorter lifetime than turbines and have smaller output (less than 50MW). load factors – It offers low-carbon flexibility on power system, can be coupled with intermittent renewable sources, and can generate power during peak hours. – Competitiveness is to be assessed against other low- BHGE NovaLT gas turbine reconfigured for 100% hydrogen carbon technologies, such as gas turbines with CCS and biomass gas turbines.

Fact card: Flexible power H2 Market trends Key features

Market maturity Early stage Competitive price for H vs. 2 15% load factor: 1.5 gas turbine ($ per kgH ) Market size 2 n.a. (GW of VRE) Competitive price for H2 vs. gas turbine + CCUS1 15% load factor: 2.5 Expected market size n.a. ($ per kgH ) (2050, GW of VRE) 2 Competitive price for H vs. Batteries, biomass turbines, 2 15% load factor: 4 Competing technologies biomass turbine ($ kgH ) gas + CCUS turbines 2

Key hydrogen applications – 3.3 Energy (power generation)

110 1 Hypothesis: CO2 price of $100 per ton; natural gas price of $7 per mmbtu; biomass gas price of $14 per mmbtu. Sources: BloombergNEF; “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis Description Overview of technologies H2 can be blended

with CH4 before – Blending low shares of H2 in most gas networks would have little impact for the end-use applications, such as being injected on boilers and cookstoves. the gas grid – Blending H2 into the current gas network allows clean energy to be distributed while saving capex for a new H2 network. – Multiple challenges still need to be addressed: – Lower energy density in a gaseous form, leading to a reduction in transported energy through the pipeline – Increasing risk of flames spreading as a result of high flame velocity – Variability in hydrogen volumes, negatively impacting end equipment designed to operate in certain conditions – Many industrial gas applications have a low upper limit of H2 blend in natural gas, which will set the upper limit for the whole network.

– Current regulations allow a H2 blend limit up to 6% (for GRHYD project in Dunkirk example, in France). Fact card: Hydrogen blending H2 Market trends Key features

Market maturity Development Compressors: H2 tolerance in gas networks about 10% Natural gas demand 3.900 (min/max, % vol) (bcm per year) Distribution: 50–100% Expected market size H tolerance for end-applications Gas turbines: 5% 2 – 4 2 (2030, MtH2 per year) (min/max, % vol) Boilers: 30% Natural, gas, Methanation, Key hydrogen applications – Competing technologies H , fuel cells and 3.3 2 Energy (gas energy) cogeneration, Biogas

111 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Usine Nouvelle; Kearney Energy Transition Institute analysis Description Overview of technologies H2 can be converted into – Methanation is a exothermic catalytic process operating at 320–430°C to produce synthetic CH4 through Sabatier natural gas to be reaction: CO2 + 4H 2 H2O + CH4 = 165 MJ/kmol injected or directly – Reaction can be split in two steps: CO + 3H2→ H O + CH ΔH= −206 MJ/kmol combusted onsite 2 4 CO2 + H H2O + CO = 41 MJ/kmol 2 for power – Higher saturated→ hydrocarbonsΔH and solid− carbon deposits 2 can be found in the→ products. ΔH generation – The main advantage of methanation is its use of fatal CO and CO2: – If coupled with low carbon H2 and CO2 inputs, there is a potential for full decarbonisation of gas.

– Synthetic CH4 may be injected on the gas network for residential and industrial applications (gas heating, electricity generation), stored or as a fuel for NGV. Methanation plant in Falkenhagen

Fact card: Hydrogen methanation H2 Market trends Key features

Market maturity Development H2 consumption (kgH2/kgCH4) 0.5 n.a. CAPEX/Acquisition cost 210–445 for Market size (Germany: ~2.5 kTCH4 ($ per kW) methanation plant only per year) Energy efficiency (%) 83% Expected market size n.a. Marginal cost ($ per kWh) 0.10–0.451 (2030) Key hydrogen applications – Natural, gas, blending, H , 3.3 2 Energy (gas energy) Competing technologies fuel cells and cogeneration, biogas

112 1 Considering H2 through electrolysis coupled with PV plant and CO2 sources from exhaust gas of cement factory Sources: Afhypac, Frontiers, GRTgaz; Kearney Energy Transition Institute analysis Description Overview of technologies A 100% H2 network can also be – A 100% hydrogen network could be coupled with fuel cells and other systems at the end user’s consumption site to considered for meet demand for heating, cooling, and electricity. – Worldwide, there are 4,500 km of pipelines, mostly providing energy operated by hydrogen producers. to end users – Investment costs are high but may pay off only with large shipping volume of hydrogen. through fuel cells, – H2 transported through pipeline could also find other applications, such as refueling stations and industrial co-generation, or use. other hybrid – Developing micro-networks with decentralized production sources could reduce infrastructure costs. systems – By 2030, final energy prices for hydrogen would need to be in the range of $1.50 to $3.00 per kg to compete with Domestic fuel cell natural gas and electricity.

Fact card: Pure hydrogen H2 Market trends Key Fuel cell Gas boiler consumption features m-CHP (+ grid) Market maturity Commercial 1 kW / 1.5 kW m-CHP 20 kW boiler Technical el th th Market size (number of 1,046 units in a trial project specification and 20 kWth auxiliary connected to the units) in the European Union boiler, heat storage grid 0.3 million units (2020) and Capex (€) 16,600 4,000 Future growth 5.3 million units (2050) as Opex (€) 140 per year 110 per year per ENE–FARM Japan Lifetime 10 years with 2 FC Competing technologies Heating systems, power grid 15 (years) replacement Net 37% electrical, Key hydrogen applications – 90% thermal 3.3 efficiency 52% thermal Energy (gas energy)

113 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Hydrogen Europe; Kearney Energy Transition Institute analysis Hydrogen’s role in the energy transition

114 Some orders of magnitude in 2019 5 Executive summary 6 1. Hydrogen’s role in the energy transition 16 2. Hydrogen value chain: upstream and midstream 25 2.1 Production technologies 27 2.2 Conversion, storage, and transportation technologies 49 2.3 Maturity and costs 61 3. Key hydrogen applications 78 3.1 Overview 80 3.2 Feedstock 84 3.3 Energy 90 3. Business models 114 4.1 Policies and competition landscape 116 4.2 Business cases 125 Appendix (Bibliography & Acronyms) 187

115 M&A, joint ventures, Main M&A, JV, and partnership agreements on H2 (2016–19) and partnerships have increased, Eon acquires Shell, Honda, and EDF Nouveaux Air Liquide Ballard and ABB Hyundai and highlighting large stakes in Toyota partner to Business invest acquires partner to design domestic FC develop H2 $16 million in stake in an FC river boat. partner on FC corporations’ provider Elcore. refueling stations. McPhy. Hydrogenics. powertrains. interest in hydrogen Hexagon and Agility Nel and Deokyang ABB and Ballard PowerCell and Ballard and Home Duke Energy Fuel Systems partner form joint venture sign MoU to Scania partner Power Solutions acquires FC to develop clean fuel to develop H2 develop FC to build a refuse partner on FC for project portfolio of solutions, including H2. refueling stations, marine systems. FC truck. domestic use Bloom Energy.

2016 2017 2018 2019

Non-Exhaustive Hydrogenics and Altran acquires Ballard and Audi Bosch Hyundai and H2 Bosch and Hanwha Energy form joint invest more than SinoHytec partner stake in H2 sign MoU for FC acquires to develop FC for sensor-maker passenger cars. stakes in FC venture n buses $230 million in Nikola buses and trucks. H2Scan. maker Ceres. and trucks mobility. (H2 truck maker).

Hydrogenics and Faurecia and PowerCell and Faurecia and Cummins StratosFuel partner CEA partner to Siemens sign MoU Michelin partner acquires stake in to develop power- develop fuel- to develop FC on hydrogen Hydrogenics. to-gas. cell stacks. marine systems. mobility.

GM and Honda NEL and Nikola Weichai Power Air Liquide and Plug Power and M&A form joint venture partner to acquires stakes in FC Houpu form joint Engie partner on venture to develop to produce fuel develop H2 maker Ceres Power hydrogen use in Joint ventures cells. refueling stations. and Ballard. H2 stations in logistics sectors. China. Partnerships Business models - Policies 4.1 Linde gas strategic ITM LINDE and competition landscape investment in ITM ELECTROLYSIS (ILE), a POWER (20%) 50-50 JV between ITM POWER and Linde Note: FC is fuel cell. MoU is memorandum of understanding. Engineering to address Source: Kearney Energy Transition Institute analysis 116 large scale electrolyser Launched in 2017, Hydrogen Council overview Steering members the Hydrogen – Established at the World Economic Forum 2017 in Davos – Airbus – Honda – Global initiative of leading energy, transport, and industry companies to: – Air Liquide – Hyundai Council regroups – Air Products – Iwatani – Accelerate investments in the development and commercialization of – Alstom Corporation companies from hydrogen and fuel cell-related topics – AngloAmerican – Johnson Matthey – Encourage key stakeholders to back hydrogen as part of the future energy – Audi – JXTG Nippon Oil various industries – BMW Group and Energy Corp. mix with appropriate policies and support schemes – Bosch – Kawasaki in North America, – Investment plan of $1.9 billion over five years, mainly for market introduction, – BP – Kogas deployment, and R&D – CHN Energy – Linde Asia, and Europe – Cummins – Plastic Omnium – Daimler – Shell – EDF – Sinopec – Engie – Thyssenkrupp – Equinor – Total Hydrogen Council vision: The hydrogen economy in 2050 – Faurecia – Toyota – GM – Weichai Power – Great Wall – 3M Motors Hydrogen demand targets Expected outcome Transportation – 18% of final energy demand – 400 million passengers vehicle, – 6 GT year of CO2 abatement Supporting members 5 million trucks, and 15 million buses (20% of the required CO2 – 20% of diesel trains replaced by abatement), mainly from – AFC Energy – Nel ASA hydrogen trains transportation thanks to 20 – AVL – NGK NTK million barrels of oil replaced – Ballard – Plug Power Industry and building heat – Market size of $2,500 billion, – Faber cylinders – Power Assets including hydrogen and fuel-cell – W. L. Gore Holdings – 12% of global energy demand, mainly – Hexagon – Re-fire in steel, chemicals, and cement equipment – Hydrogenics Technology – 10% of crude steel production, 20% – 30 million jobs created – Itochu Corp – SinoHytec of methanol and ethanol derivatives – Liebherr – SoCalGas – Marubeni – Sumitomo recycling CO2 and decarbonized existing feedstock – McPhy – Toyota Tsusho – Mitsubishi – True Zero – 8% of global energy demand Heavy – Vopak Business models - Policies 4.1 industries and competition landscape Power generation – 500 TWh of excess power converted to about 10 MTH2 of hydrogen Sources: Hydrogen Council; Kearney Energy Transition 117 Institute analysis – About 126 MTH2 stored in strategic reserves Multiple countries Hydrogen support initiatives Transportation (number of countries) Electrolyzers have launched Gas energy 15 supportive Power generation initiatives to Industrial use accelerate hydrogen deployment, mainly in 10 10 transportation …

6 5

2 2 2

FCEV Refueling FCEV buses Electrolyzers FCEV trucks Building heat Power Industrial use passenger stations and power generation Business models - Policies cars 4.1 and competition landscape

Note: FCEV is fuel cell electric vehicle. 118 Sources: International Energy Agency; Kearney Energy Transition Institute analysis … and developing Business cases specific strategy use case Industrial feedstock    

FCEV manufacturing  

Use of H2 for FCEV passenger cars        

Use of H2 for heavy vehicles        

Electricity generation    

Combined heat and Non-Exhaustive power generation   

Long-term energy storage    

Blending and methanation in gas      networks

Household heating     

Industrial heating   

Hydrogen production Business models - Policies 4.1    and competition landscape for export

Note: FCEV is fuel cell electric vehicle. Sources: “Advancing Hydrogen: Learning from 19 Plans to Advance Hydrogen from Across the Globe,” Australia 119 Department of Industry, Innovation, and Science, July 2019; Kearney Energy Transition Institute analysis In partnership Objectives Policy change proposition with the European Integrate more – Integration of the power sector – Recognize different pathways of electricity rather than Commission, renewables, within transport, industry, heating, using the average EU greenhouse gas emissions from and cooling via energy carriers power or from new plants: Hydrogen Europe and enable (electricity and hydrogen) – Through the use of guarantee of origins and renewable sectoral – Commission’s proposal to PPAs launched HyLaw integration integrate more renewable energy – Considering period when energy surplus is available as to identify the in other economic sectors, such “zero-emissions” period for hydrogen as in transport via the use of, legal barriers renewable gaseous, and liquid fuels of non-biological origin to hydrogen (hydrogen) and carbon-based deployment streams Decarbonize – Air-quality issues in multiple cities – Developing a hydrogen infrastructure on the model of mobility because of particle emissions — current gas stations to preserve jobs and capital assets not only CO2, but also NOx and – Opportunity to store electricity surplus or renewable SOx electricity as zero-emission fuel – Electrification of transportation Focus on European Union means (BEV and FCEV) to reduce emissions at the consumption point

Decarbonize Replace current brown hydrogen – Through the new Industrial Policy Strategy, support green industry production sources with green hydrogen pilots and projects while keeping the industry hydrogen production sources in competitive. steel, chemical, and oil refining industries.

Decarbonize Replace current carbon-intensive – Support hydrogen blending and methanation to keep heating sources (mainly from fossil using gas grid assets as renewable energy transportation Business models - Policies heating 4.1 fuels) to electrification or via the and storage mean. and competition landscape introduction of renewable gases – Support projects that value by-product hydrogen in such as biogas and hydrogen. industrial areas that could be used as a low-grade Note: BEV is battery electric vehicle; FCEV is fuel cell electric vehicle; PPA is power purchase agreement. 120 Sources: Hydrogen Europe; Kearney Energy Transition Institute analysis heating solution. The United States Funding and incentives Policy acts has launched R&D – Between 2004 and 2017, about $2.5 Title VIII act objectives: incentive Funding billion was granted to the Department – Promote development, demonstration, and of Energy for hydrogen R&D activities commercialization of hydrogen and fuel-cell technologies programs to across its energy efficiency and renewable energy, coal, nuclear in partnership with industries. accelerate energy, and science departments. – Make investments in building links between private – In 2005, OEMs and oil majors industries, institutions of higher education, national hydrogen partnered to create FreedomCAR laboratories, and research institutions to expand within the Department of Energy to innovation and industrial growth. deployment “examine and advance the pre- – Build a mature hydrogen economy creating fuel diversity competitive, high-risk research in the transportation sector. needed to develop the component and infrastructure technologies – Decrease US dependency on imported oil, eliminate necessary to enable a full range of emissions from transportation sector, and enhance affordable cars and light trucks, and energy security. the fueling infrastructure for them that – Create, strengthen, and protect a sustainable national will reduce the dependence of the energy economy. nation's personal transportation system on imported oil and minimize The Energy Policy Act of 2005 calls for a wide R&D harmful vehicle emissions, without sacrificing freedom of mobility and program at each step of the hydrogen value chain to Focus on the United States freedom of vehicle choice,” identifying demonstrate the use of hydrogen in multiple applications. FCEV as potential venue for R&D. – By 2020, OEMs must offer at least one FCEV to the mass consumer market. Incentives – At the federal and state level, 280 incentive programs support hydrogen, The Fuel Cell Technical Task Force is responsible for which includes grants, tax incentives, planning a safe, economical, and ecological hydrogen loans, leases, exemptions, and infrastructure and establishing uniform hydrogen codes, rebates, and apply for private businesses (fuel producers, OEM, fuel standards, and safety protocols. infrastructure operators and others), government entities and personal Cash prizes are awarded competitively to individuals, vehicle owners. universities, and small and large businesses that advanced – Clean cities, clean ports, clean the research, development, demonstration, and Business models - Policies 4.1 agriculture, and clean construction commercialization of hydrogen technologies. and competition landscape initiatives have developed private– public partnerships to promote Note: BEV is battery electric vehicle; FCEV isalternative fuel cell electric fuelsvehicle; andPPA isprovide power purchase agreement. 121 Sources: Hydrogen Europe; Kearney Energy informationTransition Institute on analysis financial opportunities.

Note: OEM is original equipment manufacturers; FCEV is fuel cell electric vehicle. Sources: Department of Energy; Kearney Energy Transition Institute Japan was the first Objectives Policy initiatives country to adopt a Realize low- – Developing commercial scale Financial support basic hydrogen cost hydrogen capability to procure 300,000 tons The Japanese government has dedicated $1.5 billion over of hydrogen annually the past six years to promote research development, strategy and plans use demonstration, and commercialization of hydrogen – Cost at 30 yen/Nm3 (2030) and technologies and subsidies. to become a 20 yen/Nm3 (beyond) – In 2018, the Japanese government allocated $272 million “hydrogen to hydrogen research and subsidies that is 3.5% of its Develop – Developing energy carrier energy budget society” international technologies – The R&D efforts are channeled through the government hydrogen – Demonstrating liquefied hydrogen research institution the New Energy and Industrial supply chain by mid-2020 Technology Development Organization (NEDO), which supply chains – Better handling of ammonia and oversees the national program on new technologies. methanation process – Japan H2 Mobility (JHyM), a joint venture of more than 20 participating companies, was established in 2017 to Decarbonize – Carbon-free hydrogen to be used accelerate the deployment of hydrogen filling stations industry and in energy areas where electricity throughout Japan with the help of government subsidies. power use is difficult and replace fossil In cooperation with the Japanese government, JHyM fuel-based hydrogen in industrial plans to build 80 new hydrogen filling stations by early Focus on Japan generation applications 2022. – Commercialize hydrogen power generation and cut hydrogen Japan intends to lead international standardization through power generation cost to 17 international frameworks in cooperation with relevant yen/kWh by 2030 organizations.

Proactively promoting hydrogen to citizens and local Decarbonize – FCV targets: 40,000 units (2020), governments to share information and facilitate adoption mobility 200,000 units (2025), and 800,00 units (2030) Japanese companies are already involved in international – Hydrogen stations targets: 160 hydrogen projects such as in Brunei, Norway and Saudi (2020) to 320 (2025) Arabia. Kawasaki Heavy Industries has also announced the Business models: policies and 4.1 – Specific focus in developing fuel construction of a liquefaction plant, storage facility, and competition landscape cell-based buses, forklifts, trucks, loading terminal for hydrogen export to Japan in the and small ships Australian state of Victoria as a pilot project for 2020–2021. Note: BEV is battery electric vehicle; FCEV is fuel cell electric vehicle; PPA is power purchase agreement. 122 Sources: Hydrogen Europe; Kearney Energy Transition Institute analysis

Note: FCV is . Sources: Ministry of Economy, Trade and Industry (Japan); Kearney Energy Transition Institute analysis Australia adopted Focus areas Policy initiatives a national Develop a Australia would take an adaptive Since 2015, the Australian government has committed hydrogen strategy strong approach to capitalize on the growth more than $146 million to hydrogen projects along the in domestic and global hydrogen supply chain. in late 2019 to hydrogen demand: – R&D: $67.83 million industry and Foundation and demonstration – Feasibility:$4.88 million open up capabilities that – Early actions will focus on – Demonstration: $5.04 million opportunities in will support the developing clean hydrogen supply – Pilot: $68.57 million chains to service new and existing country’s low The support is provided though the Australian Research domestic use as uses of hydrogen, such as emission Council, CSIRO, the Australian Renewable Energy Agency ammonia production, and (ARENA), the Clean Energy Finance Corporation, and the well as the export energy developing capabilities for rapid Northern Australia Infrastructure Fund. market transition and industry scale-up. local job – Demonstration scale hydrogen National Energy Resources Australia (NERA) will support creation hubs will help prove technologies, SMEs to take advantage of opportunities in the hydrogen test business models, and build industry by forming an industry-led hydrogen cluster. The capabilities. hydrogen industry cluster will help build capabilities and Large-scale market activation drive industry collaboration across the hydrogen value – Scale up the end use of the clean chain. Focus on Australia hydrogen in the domestic market, The Australian government has supported nine projects in such as industrial feedstock, the past two years alone. The state and territory heating, blending of hydrogen in governments have also made early moves through the gas network, and use of supporting specific projects and, in some cases, releasing hydrogen in heavy-duty transport their own hydrogen strategies. along with refueling infrastructure. The Australian government will establish agreements with Transform Australia has significant competitive key international markets to underpin investment. It has Australia into a advantages for developing a already signed a cooperation agreement with Japan and a substantial hydrogen export industry. letter of intent with Korea. clean hydrogen The country has abundant natural exporter The four year (2018–2021) HESC Pilot Project comprises resources needed to make clean multiple stages to produce and export hydrogen (from Business models: policies and 4.1 hydrogen and has a track record in competition landscape brown coal) to Japan from the Latrobe Valley, using building large-scale energy established and scientifically proven technologies. The Pilot industries. It has an established Project is the world’s largest hydrogen demonstration. 123 reputation as a trusted energy project and includes the transportation of liquified hydrogen supplier to Asia. in a world-first, purpose-built liquified hydrogen carrier Sources: Australia’s National Hydrogen Strategy (2019); Kearney Energy Transition Institute Oil-rich countries Business case overview Actions taken Saudi Arabia are looking into – Several options can be used to convert H to export as hydrocarbons into clean H2 (see Part 2): – Agreement between Air Products and Aramco 2 – Either from natural gas (e.g. SMR) or from to build the country’s first compressed a clean fuel any hydrocarbon sources (e.g. gasification; hydrogen refueling station for fuel cell electric alternative to ATR, Pyrolysis), and combining with CCS vehicles – Using non-emitting technologies (e.g. – Development of a blue hydrogen production oil and gas microwave) strategy with planned pilots – Blue hydrogen provides a clean opportunity for Arab countries to extend the useful life of their reserves: – Gulf Cooperation Council countries have a United Arab Emirates proven track record of brown hydrogen production thanks to their refineries. – Test of Toyota Mirai FCEV on roads to – CO2 from CCS can be stored more easily in evaluate the potential of hydrogen as depleted oil and gas fields or be used for road fuel enhanced oil recovery and nearby – Al Reyadah CCUS plant at Emirates Steel Focus on Gulf Cooperation industries. plant in Abu Dhabi, used for EOR in Council countries – Value from heavy oil resources can be ADNOC oilfields enhanced. – Carbon emissions targets from Paris agreement can be met. – Blue hydrogen production costs are half of green hydrogen, but the gap is expected to Kuwait close by 2030. – However, renewable electricity – Discussions on CCUS and H2 production infrastructure in Gulf Cooperation Council by KPC Business models - Policies 4.1 countries is not big enough to scale up and competition landscape hydrogen production.

Sources: Kuwait Foundation for the Advancement of Sciences; 124 Kearney Energy Transition Institute analysis Well-to-wheel energy efficiency example Converting fossil (Energy in kWhe) fuels into hydrogen through SMR is almost as efficient Oil & gas Fossil fuels Charging Mechanical energy as a ICE and BEV, Energy storage leading to no processing conversion infrastructure conversion extra fossil fuel Hydrogen Fuel consumption SMR 64% 55 Compressor 90% 50 Tank 100% 50 Cell 55%

28

Electric drive 90% 25 Illustrative Turbine Electrolyzer Fuel 34 Tank Grid 39% Compressor 59% 20 100% 20 Cell 55% Fossil fuels 11 100 Electric 90% 10 Extraction drive 86 Refining 86%

Electric Motor Battery Electric Charger 31 93% 28 26 X% Conversion efficiency 90% Full charge drive 90% X% Energy content ICE Gasoline 30% 26 Business models – Business ICE 4.2 cases

125

Source: Kearney Energy Transition Institute analysis Well-to-wheel energy efficiency example The battery (Energy in kWhe) pathway also appears more efficient than Electricity Electricity Vehicle Mechanical energy hydrogen when the production & Energy storage conversion infrastructure conversion primary source transmission comes from Fuel-cell vehicle pathway renewable sources

Electro- Compre- Fuel 65% 60 90% 54 Tank 100% 54 55% Illustrative lyzer ssor Cell

30 However, efficiency Electric 27 considerations could be put drive 90% aside if renewable sources Renewable are considered as not production limited. 100 Battery electric vehicle pathway Transmission Battery Electric Charger 93% Distribution 92% 92 90% 83 Full charge 77 drive 90% 69

X% Conversion efficiency X% Energy content Business models – Business 4.2 cases

126

Source: Kearney Energy Transition Institute analysis CO2 intensity of hydrogen production CO2 emissions (kgCO /kgH includes full life cycle of power plant) related to hydrogen 2 2, production vary Primary source Conversion depending on the Lower emission limit World average from electrolysis production pathway Gasification without CCS 20

Coal Gasification with CCS1 2 7 9

Electricity Electrolysis2 45

SMR without CCS 11

Natural gas SMR with CCS1 1 4 5

Electricity Electrolysis2 27

Nuclear fuel Electricity Electrolysis2 1

Solar Electricity Electrolysis2 2

Wind Electricity Electrolysis2 1

World grid (475g CO2/kWhe) Electrolysis2 26

Business models – Business 4.2 cases Other hydrocarbons, such as oil, can be used to produce hydrogen, the resulting CO2 intensity is generally comprise between those of coal and natural gas 1 Considering 54 to 89% of capture rate. More details on CCS are in production technologies section. 2 Considering energy consumption of 55 kWhe/kgH2 for an electrolyzer 127 Sources: “Hydrogen Roadmap Europe,” International Energy Agency, 2019; RTE; Kearney Energy Transition Institute analysis A. Thermochemical production Economical competitiveness Centralized production from ATR to serve local industries – What is the net present A Seven business value and the LCOX with heat and H2 cases, based on of the investment?1 – What is the net present B. Electrolysis real-life situations, value of other alternatives, including carbon-intensive have been studied and low-carbon solutions? Power-to-gas: how to value fatal electricity to assess their – LCOH converted either in $ B1 production into gas or heat energy per kg, $ per MWh, $ per B1: overview; B1a - blending; B1b: methanation competitiveness km, or $ per passenger with other depending on the business case Power-to-X available solutions Power-to-power: how to store electricity and Evaluation criteria B2 discharge it when needed Business cases Environmental impact

– How many tons of CO2 can be avoided thanks to the Power-to-molecule: how to optimize refinery hydrogen solution, and B3 what is the avoidance cost? B power consumption and reducing footprint – How many tons of CO2 would have been avoided with other solutions, and what is the avoidance cost? Hydrogen cars: economic assessment of main B4 H2 cars

1 Levelized cost of X: levelized cost of hydrogen, energy, or Mobility depending on the end-use application. Other benefits Calculation methodology does not differ, and the denominator is adapted (for example, energy produced or – Will the solution contribute number of passengers). to an economic Green Source: Kearney Energy Transition Institute analysis mobility Hydrogen buses: additional cost vs. development at local or B5 global level? impact for local economy – Will the solution reduce Business models – Business 4.2 dependency on fossil fuels cases imports and improve energy

supply security? Hydrogen trains: how to value local H2 fatal 128 – Will the solution help REN B6 production and avoid large investment for rail integration on the electric electrification grid? Business cases (2030) Extra Cost Carbon abatement costs Carbon abatement costs vary widely MIN MAX 1. Centralized Convert fossil fuels into A +12–30% vs. 100 215 depending on the hydrogen, and capture production av. electricity price business case from ATR carbon at production point.

+60–100% injection 220 320 Convert electricity into hydrogen for heat B11. Power-to-gas +250–400% generation. 1100 methanation vs. gas 2800

Convert electricity into +35–35% 110 3000 hydrogen for electricity B22. Power-to-power vs. coal turbine peak management.

Convert electricity into 130 150 +35–110% B33. Power-to- hydrogen for further vs. SMR molecule industrial applications.

570 2000 Create clean fuel to power +150–215% Note: The carbon abatement cost is equal to (LCOX(H2) – B44. Hydrogen cars LCOX(Ref))/(Avoided CO2), with the LCOX(H2) being the cars. vs ICE car LCOX of the H2 solution, LCOX(Ref) being the LCOX of the reference solution, both in $ per unit, and the (avoided CO2) being the CO2 avoided between the H2 solution and Ref solution, in ton per unit. Source: Kearney Energy Transition Institute analysis 120 B55. Hydrogen buses Create clean fuel to power +10–15% (Pau example) buses. vs. diesel bus Business models – Business 4.2 cases

6. Hydrogen trains 0 60 B6 Create clean fuel to power +1–15% 129 (Cuxhaven trains. vs. diesel train example) A A. The Rotterdam Production of H2 Distribution of H2 End use CO2 storage port is investigating and CO2 capture Technology – High pressure ATR unit – Pipeline – Power plants: new gas – Storage in North Sea the benefits of H – Centralized production of – No storage turbines to enable H2 depleted oil and gas fields 2 firing, power generation H2 from CH4 with CO2 in its H-vision plan, capture with Rectisol from ATR steam which would physical absorption – Furnace heat in refineries combine fossil fuel- based production and CCS Illustrative

Main – Up to 1,500 kt H2 per day – Diameter: 12–28 inches – Power plants: 2x147 – Multiple sites identified, Hydrogen hub produce from – H purity of 96% – Operating pressure: MWe H2 turbines + 2x100 with total capacity of characteristics 2 MWe gas/H turbines: 470 Mt SMR – CCS: 88% capture rate about 70 bars 2 1.9 GW of H2 – Stored quantity over 20 (8 kg CO2 captured per kg H ) – Refinery: H2-rich refinery years: 120–288 MT 2 fuel gas

Cost – Capex: up to €910 million – Cost: €0.5 million to – Total capex: €0.8 billion – Transport and storage: components – Opex: 2.5% of capex €1.5 million per km to €2.8 billion €17–€30 per ton

Business models – Business 4.2 cases

130

Sources: "Blue Hydrogen as Accelerator and Pioneer for Energy Transition in the Industry," H-vision, July 2019; Kearney Energy Transition Institute analysis A Objective Value chain and possible partners A. H-vision projects – Reaching a carbon- have multiple neutral industry in Supply Rotterdam by – Supply of natural gas, – Equinor partners from 2050 refinery fuel gas, and – Shell oxygen – BP various industries – Air Liquide Context – Industries in Rotterdam

port areas consumption 1. Production – Production of H2 – Uniper of about 400 ktH2 per – Shell year, half of the – BP Netherlands production – Air Liquide – H2 mainly produced from – Gasunie SMR without CCS

– Almost all production 2. Distribution used for oil refineries – Transportation and – Vopak storage of blue H2 – Gasunie

H-vision business H-vision scope – Developing a blue

model overview 3. End use hydrogen economy – Power plant – Uniper – Development of new – Refineries – Shell applications for H2, – Chemical sites – BP including power, heat – ExxonMobile generation, chemicals – Air Liquide – Development of new production sources for Evacuation 4. – Transportation and – Vopak H2, preferably ATR storage of CO combined with CCS 2 – Port of Rotterdam – Gasunie Business models – Business – FID by 2021 and project 4.2 cases start-up by 2025

131 Sources: "Blue Hydrogen as Accelerator and Pioneer for Energy Transition in the Industry," H-vision, July 2019; Kearney Energy Transition Institute analysis A A. Multiple Hydrogen demand (GW) Details scenarios have Minimum – 10% hydrogen co-firing in coal power plants been developed scope 0.6 0.6 – 25% co-firing in natural gas turbines – Adjustments to replace RFG with hydrogen fuel with various – Replacement of natural gas imported to balance the fuel gas grid carbon impacts 1.1 (excluding gas turbines)

Reference – 4x147 MWe hydrogen turbines (36.5% efficiency) added scope – 50% co-firing of hydrogen in natural gas turbines – Maximum adjustments to replace RFG with hydrogen-rich fuel – Replacement of natural gas imported to balance the fuel gas grid, excluding gas turbines 1.9 1.3 3.2

H-vision scenarios overview Maximum – 4x147 MWe hydrogen turbines (36.5% efficiency) added scope – 15% co-firing of hydrogen in power plants or direct firing in boilers 0.5 – Maximum adjustments to replace RFG in all refineries with hydrogen-rich fuel – Replacement of natural gas imported to balance the fuel gas grid, 2.8 1.9 5.2 excluding gas turbines – Additional potential to replace natural gas of other end users Power plants Refineries Business models – Business 4.2 cases Additional users

132 Sources: "Blue Hydrogen as Accelerator and Pioneer for Energy Transition in the Industry," H-vision, July 2019; Kearney Energy Transition Institute analysis A H-vision project NPV build-up A. In the reference (€ billion, reference scope, economical world) scenario, a total subsidy of €0.7 2.1 billion is required to 3.4 make the H-vision project profitable Mainly natural gas cost given avoided ETS 5.8 certificates of 7.7 €3.4 billion 0.1

3.1 0.0 0.8 0.7 0.0 Power plants Refineries H2 production H2 production H2 CO2 transport Retrofitting Subsidy NPV revenue avoided ETS capex opex transportation and storage costs certificates

Main hypotheses

CO2 emissions price From €22 per ton in July 2019 to €149 per ton in 2045 Gas price €34 per MWh

CO2 captured and stored About 6 MT per year

Total H2 demand 3 207 MW, only for power plants and refineries H storage No storage Business models – Business 2 4.2 cases WACC 3%

133 Sources: "Blue Hydrogen as Accelerator and Pioneer for Energy Transition in the Industry," H-vision, July 2019; Kearney Energy Transition Institute analysis A CO2 impact of H-vision A. The H-vision (Avoided CO in Mtpa, abatement cost in $ per tCO ) project could help 2 2 avoid 27 to 130 Avoided CO2 emissions (Mtpa) Abatement cost range ($ per tCO2eq) Mtpa of CO2 over 20 years with an Minimum 1 164 49 213 abatement cost of scope CO2 $97 to $213 per tCO2 Reference 4 97 67 164 scope

Maximum 7 102 67 170 scope

IPCC 2°C carbon price recommendation, 2030

– A CCS unit on the ATR has a capture rate of 88%. Therefore, CO2 emissions from hydrogen production for refinery use would be cut by 88%. – For power generation, efficiency losses imply an overall emission reduction rate of about 80%. Natural gas turbines are slightly more efficient, and converting to hydrogen adds an intermediary step with additional losses.

Business models – Business 4.2 cases

134 Sources: "Blue Hydrogen as Accelerator and Pioneer for Energy Transition in the Industry," H-vision, July 2019; Kearney Energy Transition Institute analysis B.B Power-to-X is Simplified value chain of hydrogen-based energy conversion solutions1 the process of converting electricity into Gas network Hydrogen network Power network Liquid fuel network hydrogen for Power grid additional Power-to-mobility Fuel cell electric vehicle Water Oxygen Refueling applications Power-to-power stations Internal combustion Wind turbine Electrolysis Hydrogen engine vehicle storage Upgraded and Green hydrogen synthetic fuels Solar PV Natural gas vehicle

H2 Fuel cells Refineries

Blue hydrogen Power-to-chemical Combustion Blended gas turbines Processing2 CCS Petroleum products Power-to-gas Chemical Ammonia plants CO2 Methanation Blending

CH4 H2 Coal and oil

Natural Gas Grid

Business models – Business 4.2 cases

135 1 End uses are non-exhaustive. 2 There are several possible options. Source: Kearney Energy Transition Institute analysis B.B Analyses have Configuration description for P2G project (based on France electrical mix) been conducted for multiple Configurations 2019 2025f 2030f scenarios, Size 1 MW 10 MW 100 MW with optimistic Capex €1,000 per kW €800 per kW €450 per kW Electrolyzer assumptions Stack 70,000 hours, 36% capex 80,000 hours, 28% capex 90,000 hours, 28% capex on renewable Elec. Cons 60 kWh/kg 55 kWh/kg 50 kWh/kg production Load Factor 90% sources Grid utilization Elec. Price $48.60 per MWhe evolution CO2 475g per kWhe Load Factor 34% 35% 36% Wind Elec. Price $56 per MWhe $45 per MWhe $31 per MWhe

CO2 11g per kWhe Assumptions used for Load Factor 21% 23% 25% business cases Solar Elec. Price $85 per MWhe $60 per MWhe $22 per MWhe VRE average VRE CO2 42g per kWhe Load Factor 90% (Wind 34–36% of time and grid 54–56% of time) Grid + Elec. Price $53.6 per MWhe $49.30 per MWhe $43.60 per MWhe wind CO2 300g per kWhe 294g per kWhe 289g per kWhe Load Factor 90% (Solar 25–30% of time and grid 60–65% of time) Grid + Elec. Price $59.70 per MWhe $54.10 per MWhe $43.70 per MWhe

Business models – Business VRE and grid 4.2 solar cases CO2 373g per kWhe 365g per kWhe 354g per kWhe

Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; International Renewable Energy Agency; Oxford Institute for Energy Studies; French Environment and Energy Management Agency 136 (ADEME); RTE; expert interviews; Kearney Energy transition Institute analysis B.B In the long-term, LCOH for P2X project: 2019: 1 MW 2025f: 10 MW 2030f: 100 MW electrolyzer only Current fossil fuel- as capex goes (2019–2030, $ per kg) dependent sources down, electrolyzer LCOH range(1)

powered from Grid utilization 5.6 4.2 3.1 renewables could be competitive with Wind grid-connected 7.1 4.9 2.7 At optimal rate, LCOH would be about $2.50 per kg at 64% use rate. However, it Solar 10.9 6.9 2.7 does not include other components that can be capex- intensive and require a high Grid wind 5.9 4.2 2.9 load factor. H2 electrolysis cost from various power sources Grid solar 6.2 4.5 2.9

As of today, the cheapest LCOE reduction from Reduction in LCOE for option is to produce H2 with a renewable and improvement renewable sources, which grid-connected electrolyzer. of electrolyzer capex and opex is expected to become lower However, coupling grid with is not expected to make green than average grid prices, will wind to reduce the carbon H2 competitive compared with make green H2 competitive Business models – Business 4.2 footprint is close to becoming grid-connected electrolysis by out of the electrolyzer. cases competitive. 2025. 1. Current LCOH of brown hydrogen commonly ranges between 1$/kg to 2$/kg (more details slide 62) Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; GRHYD; International Renewable Energy Agency; Oxford Institute for Energy Studies; French Environment and Energy Management 137 Agency (ADEME); RTE; Kearney Energy transition Institute analysis B Avoided CO2 and abatement cost vs. SMR B. The carbon (2030, kgCO /kgH , $ per tCO ) footprint from 2 2 2 electrolysis would Avoided CO2 emissions Avoidance cost vs. SMR Net CO2 emissions be reduced only emitter reduction

if powered by Grid utilization -13 CO2 neutrality: about renewable sources, 200g per kWhe at an abatement cost of $125 to $145 Wind 10 124 per tCO2 Solar 9 144

CO2 neutrality: about Grid wind -4 350g per kWhe

CO2 neutrality: about Grid solar -7 275g per kWhe

IPCC 2°C carbon price recommendation, 2030 Considering only hydrogen production As LCOH from electrolysis is expected to (excluding additional infrastructure, storage, decline sharply, green hydrogen could and consumption end points that might be become competitive with SMR if CO2 Business models – Business needed), only electrolyzers powered by prices reach $124 to $144 per tCO2. 4.2 cases renewable would have a positive impact on CO2 emissions compared with SMR. Note: Hypothesis detailed in the appendix. CO2 neutrality is defined as the maximum CO2 footprint from the power sector to reach carbon neutrality between SMR and electrolysis. 138 Sources: Intergovernmental Panel on Climate Change; Kearney Energy Transition Institute analysis B.B Electrolyzer Overview of grid services from electrolysis (2022, Business case opportunity wind and solar generation) could also provide With coordinated operations between electrolyzers, a fixed services to the High variability of renewable production Wind and is injected to the grid from generation solar and wind power plant. grid to support Wind and solar production in NREL 2022 renewable business case integration while Variable energy production from solar and wind sources directly injected on the grid can offsetting impact operations (for example, demand variability and lower than production, frequency variations) improve LCOH

Quick response time and flexibility of PEM

45 MW of electrolyzers with advanced control is considered in the Electrolyzer performance National Renewable Energy Laboratory 2022 business case

PEM can operate at higher rates than nominal load for a certain period of time without impacting its lifetime, which can provide negative power control to the grid.

It can also operate below its nominal rate (to Business models – Business 20%) to provide positive power control to the 4.2 cases grid.

139

Sources: National Renewable Energy Laboratory, adapted from Siemens (2013) and Mansilla et al. (2012); Kearney Energy Transition Institute analysis B Positive power control TAC power output (GW) Remuneration system, based B. There is opportunity on Austria tender prices: potential for a 2.0 – €10 per MW available per hour In France, TAC (“turbines à – €120 per MWh delivered Maximum power capacity H2 producer combustible”) provide 1.5 electricity during peak times to monetize this to maintain grid frequency. service, which 1.0 In 2018, TAC delivered could further power above 60MW for 0.5 reduce LCOH about 467 hours.

Negative power control Solar and wind power output (GW) Remuneration system, based opportunity on Austria tender prices: – €10 per MW available per hour Variability in renewable – - €120 per MWh consumed production can lead to excess 14 supply on the electric grid, 12 which may require switching off other sources or 10 incentivizing consumers to 8 use the surplus if switch-off 6 time is too long, too risky, or too expensive. 4 2 In 2018, renewable production growth occurring at the same time as a Business models – Business decrease of other production 4.2 cases sources happened for 2,451 hours.

Note: Grid stabilization with electrolysis (2018 example, France) 140 Sources: National Renewable Energy Laboratory, RTE, Smarten.eu; Kearney Energy Transition Institute analysis B LCOH could be LCOH reduction from grid servicing (2030, $ per kg, 100 MW electrolyzer) reduced by up Positive power control Negative power control Combined power control to 60% if grid servicing provided Electrolyzer running at Electrolyzer running at Electrolyzer running at 100 MW, with the possibility 80 MW, with the possibility 80 MW, with the possibility by electrolyzers to run at 20 MW when power to run at 100 MW when to run at 100 MW when are considered on the grid is required, which electricity needs to be electricity needs to be would have happened for absorbed on the grid, which absorbed on the grid or at and managed 440 hours per year would have happened for 20 MW when power is 2,451 hours required on the grid -33% -30% -59% 3.1 3.1 3.1

2.1 2.2

1.3

Grid only With power Grid only With power control Grid only With power control control

Business models – Business 4.2 Because these mechanisms are still in preliminary stages for electrolyzers, the cases following analyses will not include power control remuneration.

141 Sources: National Renewable Energy Laboratory, RTE, Smarten.eu; Kearney Energy Transition Institute analysis BB1 Power-to-gas Power-to-gas overview

is the process of B1a AE converting surplus Blending electrolyzer electricity into H2

through electrolysis Compression B1b Electricity PEM Gas storage Methanation for further supply electrolyzer network applications, such as heating and SOEC mobility electrolyzer

Pure H2 applications

Power-to-gas: overview Start-up time per technology – Electrolyzer is a key component in a P2G (10 MW per minute) business case and needs to be flexible enough to adapt to sudden power 30 30 changes and multiple switch-on and switch-off. – PEM, even if more expensive than AE electrolyzers, is currently the preferred solution thanks to its quick reaction time and its capability to operate at 160% of 10 nominal power for a short period of time. Business models – Business 4.2 cases AE PEM SOEC 142 Sources: International Renewable Energy Agency; Kearney Energy transition Institute BB1 P2G has been Key advantages of P2G 2050 P2G potential, year of study identified as a tool – Wind and photovoltaic have (TWh, France) to enable high Value electricity high potential to penetrate production electricity grids with fast penetration of surplus declining LCOE. 150 renewable on the – These generation sources are from RES dependent on weather changes Higher values for electricity grid high renewable and a high level of integration penetration will require more flexibility.

Multiple studies – Existing gas networks are able conducted to store energy, either as H or Store at different 2 CH4 if there is a methanation time scale and step. transport energy – In France, gas network storage capacity is about 140 TWh, Power-to-gas: overview through gas grid compared with 0.4 TWh on the electricity network. NegaWatt scenario

35 – Hydrogen—or methane— produced can be used 30 Use renewable as a fuel for mobility, feedstock electricity for chemicals, or heat for 20 Business models – Business 4.2 for multiple industry or be converted back cases applications to electricity if needed. 2011 2018 143

Sources: GRDF; Kearney Energy Transition Institute analysis BB1 Multiple projects Power-to-gas project examples (2015, Europe) are being launched to test the viability Non-Exhaustive of the system Project Storage and End-use Production Budget name injection applications

11. GRHYD – 50 kW PEM – Stored in – Residential €15 million electrolyzer metal district hydrides (50 heating m3) – Hythane (H2 – Blended and CH4 with CH4 mixed) fuel before for city injection (up buses to 20% H2) 3 22. Jupiter 1000 – 500 kW AE – Blended – Industrial €30 million electrolyzer with CH4 and 1 – 500 kW before residential PEM injection (up applications electrolyzer to 6% H2) in Fos-sur- Power-to-gas: overview – Methanation Mer district , with CO2 2 injection from CCS plant 33. Audi e-gas – 3x 2 MW AE – Methanation – Synthetic n.a. electrolyzers , with CO2 gas used for injection vehicles fuel from CCS plant

1 to 5 P2G projects More than 5 P2G projects Business models – Business 4.2 cases

As of 2017, 49 P2G projects were launched, 44 of which were in Europe. 144 Sources: GRHYD, Jupiter 1000, L’Usine Nouvelle, Oxford Institute for Energy Studies, ENEA Consulting; Kearney Energy Transition Institute analysis BB1 The GRHYD GRHYD project example project was Objective Value chain and possible partners launched in – Value fatal electricity production Electricity from renewable sources through – Fatal electricity production from VRE Dunkirk to inject green H2. up to 20% of green Context H2 on residential – France’s objective is to have – CEA gas network for renewable energy representing 23% Electrolysis – Engie of final energy consumption by – PEM electrolyzer producing heating and – McPhy 2020. H2 and O2 (released) mobility – AREVA H2GEN – According to ADEME, up to 30 TWh – Dunkerque Grand of hydrogen could be produced by Littoral power-to-gas by 2035, and a full – INERIS conversion to a 100% renewable Storage – Storage in metal hydrides gas-based scenario by 2050 is feasible. Power-to-gas: overview

GRHYD scope Injection – Blending up to 20% – Experiment with power-to-gas at – Injection of mixed gas project scale: (hythane1) on gas network – Test reactivity of PEM electrolyzer. – GRDF – Test gas network adaptability to – CETIAT hydrogen injection. End use – Determine upper limit of injection – Heating for new residential Business models – Business buildings 4.2 (currently at 20% on new cases – Fuel for Hydrogen buses networks). – Engie – Test metal hydrides storage option. – DK Bus 145 1 Hydrogen and methane Sources: GRHYD; Kearney Energy Transition Institute analysis B1aB Production P2G: injection value chain of H2 and injection on gas network systems (blending) include electricity Illustrative generation, electrolyzer, and Grid connection and infrastructure Electrolyzer Injection station injection station

Year 2019: 1 MW 2030f: 100 MW 2019: 1 MW 2030f: 100 MW Capex Transformer: $0.013 Power-to-gas: blending ($ million) Line: $0.112 1.46 3.10 business case Pipeline: $0.3 All hypotheses are described in Electrification: 0% OPEX slide 134 8% 8% (% capex) Pipeline: 2% (more details Electricity slides 65 to 69) required 3% (losses) 3% (losses) – – (% losses)

Business models – Business 4.2 cases

146 Sources: expert interviews; Kearney Energy Transition Institute B1aB The levelized Levelized cost of 2019: 1 MW 2025f: 10 MW 2030f: 100 MW energy: injection cost of energy ($ per MWh–LHV) (blending) could go down to $86 to $99 71 6 1 Grid utilization 168 254 126 136 95 99 per MWh by 2030, 15 3 2 making it 16 3 214 36 180 430 149 170 81 86 competitive with Wind 5 2 biomass gas 23 4 331 57 284 672 210 241 81 87 Solar 7 1

71 6 1 177 264 128 137 88 91 Grid wind 16 3 2 Power-to-gas: blending business case 71 6 1 189 276 136 146 88 91 Grid solar 16 4 2

Injection plant Infrastructure – As of today, injection on the – As production grows, capex – By 2030, gas injection Electrolysis gas grid is not competitive for infrastructure and on the grid would be compared with natural gas injection plant is amortized competitive with biogas. or biomass. faster. Current natural gas price range(1) – The capex required for an – Production from grid Current biogas price range(2) injection plant is not electricity is now competitive Business models – Business 4.2 amortized because of low with biomass but may have cases production levels. CO2 impact. 1. Current natural gas price range: 25-50 $/MWh; 2. Current biogas price range 100-150$/MWh Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; International Renewable Energy 147 Agency; Kearney Energy Transition Institute analysis B1aB Only injection Avoided CO2 and abatement cost (2030, kgCO2/kgH2, $ per tCO2)

plants connected Avoided CO2 emissions Abatement cost @ NG = $50 per MWh Net CO emissions to REN without emitter 2 grid back-up reduction would help reduce CO2 neutrality: about Grid utilization -538 125g per kWhe CO2 emissions at a cost of $200 to Wind 182 198 $270 per tCO2

Solar 135 273

CO2 neutrality: about Grid wind -250 220g per kWhe

Power-to-gas: blending CO2 neutrality: about business case Grid solar -351 160g per kWhe

IPCC 2°C carbon price recommendation, 2030 – Natural gas emissions in combustion are – The carbon abatement cost from wind around 200 kg per MWh. powered electrolysis and H2 injection – On average, if electrolyzer is connected through P2G system would be in line with to the grid to ensure a 90% service rate, the IPCC recommendations on carbon P2G Injection systems will be net price upper limit ($220 per tCO2). emitters of CO2. – Other benefits, such as frequency Business models – Business – However, when purely coupled with balancing, jobs creation, and lower 4.2 cases renewables, 130 to 180 kg of CO2 per dependency to fossil fuels, are not MWh LHV could be avoided. included in the calculation and could further reduce the avoidance cost. 148 Notes: The hypothesis is detailed in the appendix. CO2 neutrality is defined as the maximum CO2 footprint from the power sector to reach carbon neutrality between natural gas and injection. Sources: Intergovernmental Panel on Climate Change; Kearney Energy Transition Institute analysis B1aB Top natural gas CAC vs. CO2 emissions from electricity generation (2030) Heading Abatement cost consumers would ($ per tCO2) – For most countries, as the CO2 intensity not be able to 1,200 of the power sector Countries with no potential for carbon emissions reduction from grid coupling: reduce carbon 1,150 is above 200g per 1,100 kWhe (LHV of emissions if 1,050 natural gas), the electrolyzer is 1,000 injection of H2 from 950 the grid would generate more CO coupled with 900 2 emissions. 850 the grid – Among the top 10 800 OECD natural gas 750 consumers, only 700 could 650 reduce its CO2 600 emissions with 550 injection and grid + 500 wind coupling, but 450 at a higher cost Power-to-gas: blending 400 than wind or solar business case only. 350 CAC from solar 300 – In countries with a 250 IPCC price low carbon intensity recommendation / in the power sector, 200 CAC from wind 150 such as France, Switzerland, or 100 Norway, which are 50 not top natural gas 0 0 25 50 75 100 125 150 175 200 consumers, could reduce their CO2 Business models – Business Grid emissions emissions from 4.2 cases Grid Grid + wind Grid + solar (kgCO2 per MWhe) natural gas at a cost of between

Note: CAC is carbon abatement cost. The hypothesis is detailed in the appendix. $180 and $400 per Sources: Intergovernmental Panel on Climate Change, Organisation for Economic Co-operation and Development; Kearney Energy Transition Institute analysis 149 ton of CO2. B1aB The hydrogen Limits of hydrogen injection on gas networks (% of volume) injection potential is limited in Tolerance of selected elements volume by end Distribution 50% 100% Safety issues

applications for grid Gas Gas meters 50% – High flame velocity increasing safety and risk of spreading and requiring performance new flame detectors for high Transmission 20% blend ratios reasons – Corrosivity on old gas networks Compressors 10%

Underground 2% Injection on highly connected storage grids will be limited by end use applications. However, Boilers 30% injection on local networks Performance issues has greater potential . Cooking 30% – Lower energy density (in Applications Engines 5% volume) than methane, requiring end users to burn Gas 2% higher volume of gas turbines – Industrial sectors that rely on carbon content in natural gas CNG tanks 2% 30% (e.g. steel) needing to use higher volumes Business models – Business 4.2 cases Allowable under certain circumstances

150 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis B1bB Methanation P2G: methanation value chain is the process of Illustrative converting Grid connection Electro- LP storage CO2 capture and Methanation Injection hydrogen into and infrastructure lyzer (60 bars) storage reactor station synthetic methane before injection on the gas grid

Year 1 MW 100 MW hypothesesAll107. are describedslide in 1 MW 100 MW 1 MW 100 MW 1 MW 100 MW 1 MW 100 MW

Capacity 400,000 54 million 3 0.78 t H 94 t H (tH2/m per - - 2 2 - - m3 per m3 per - - 2 days 2 days year) year year

Capex Transfer: $0.013 ($ million) Power-to-gas: methanation Line: $0.112 $0.53 $31.8 - - $0.9 $76.7 1.46 3.10 business case Pipeline: $0.3 OPEX (% capex/$ Electrification: 0% $0.01 $1.2 - - 8% 8% 8% 8% million per Pipeline: 2% year) Electricity required 0.88 0.88 0.21 0.21 (% losses 3% (losses) - - kWh/kW kWh/kW kWh/kW kWh/kW - - per kWh) hCH4 hCH4 hCH4 hCH4

CO2 cost1 Business models – Business - - - - $76 $71 - - 4.2 ($ per ton) cases

1 Includes capture and storage. Supposed on-site capture, not requiring transportation and operated independently from the rest of the plant delivering CO2 at constant cost 151 Sources: TM Power, expert interviews; Kearney Energy Transition Institute analysis B1bB The levelized Levelized cost of 2019: 1 MW 2025f: 10 MW 2030f: 100 MW energy: methanation cost of energy (for ($ per MWh – LHV) methanation) could go down to $175 to 76 15 8 11 1 Grid utilization 199 84 397 150 242 186 20 65 113 58 $264 per MWh by 18 4 2 2030, which would 47 35 19 2 4 Wind 253 152 213 708 176 357 224 make it 43 6 121 96 99 uncompetitive with 23 51 2 5 biogas (or injection) 391 67 74 229 336 1,097 248 171 28 507 264 Solar 9 96 129 32

77 15 8 11 1 Grid wind 210 84 409 151 243 175 20 65 104 57 19 4 2 Power-to-gas: methanation business case 78 15 8 11 1 224 84 424 161 254 175 Grid solar 20 66 104 57 19 4 2 Electrolysis Infrastructure Storage Methanation and methane Higher production requires a Overall process efficiency is Methanation injection are highly capex- higher quantity of CO2 and lower because methane Injection intensive, which increases the electricity, which would make carries less energy density for LCOE at low utilization rates, methanation costs decline the same weight of hydrogen, such as for solar and wind. slower than injection costs. and methanation is power Business models – Business (1) 4.2 Current biogas price range cases intensive.

1. Current biogas price range: 100-150$/MWh Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; International Renewable Energy 152 Agency; ENEA Consulting; Kearney Energy Transition Institute analysis B1bB The carbon cost Avoided CO2 and abatement cost (2030, kgCO2 per MWh, $ per tCO2) would need to be Avoided CO2 emissions Abatement cost @ natural gas $50 per MWh

Net CO2 emissions priced at $1,100 to emitter reduction $3,000 per tCO2 to -1,209 CO2 neutrality: about 65g make a methanation Grid utilization per kWhe solution competitive with natural gas Wind 160 1,089 prices Solar 71 2,994

Grid wind CO2 neutrality: about 120g -661 per kWhe

Grid solar CO2 neutrality: about 75g Power-to-gas: methanation -853 per kWhe business case IPCC 2°C carbon price recommendation, 2030 – Natural gas emissions in combustion are – Wind-powered electrolysis and around 200 kg per MWh. methanation could be competitive with methane if CO were priced around – With a low-carbon electrical mix, CO2 2 emissions are always below when $1,300 per ton, which is unlikely to hydrogen is produced, even if connected happen as the IPCC CO2 price scenario to the electrical grid. varies from $15 to $220 per ton in the – If CO emissions for electricity 2°C scenario to more than $6,000 per t in Business models – Business 2 4.2 the 1.5°C scenario. cases production are above 65 g per kWh, hydrogen from grid would be a net emitter. 153 Note: Hypothesis detailed in the appendix. CO2 neutrality is defined as the maximum CO2 footprint from the power sector to reach carbon neutrality between SMR and electrolysis. Sources: Intergovernmental Panel on Climate Change; Kearney Energy Transition Institute analysis B1b The carbon CAC vs. CO2 emissions from electricity generation (2030) Heading abatement cost – For most countries, because the CO Abatement cost 2 appears to always intensity of the ($ per tCO2) power sector is be higher than above 200g per 8,500 Countries with no potential for carbon emissions reduction from grid coupling: the IPCC kWhe (LHV of 8,000 natural gas), recommendation, 7,500 methanation of H2 7,000 from the grid would even if electrical generate more CO2 mix is fully 6,500 emissions. 6,000 – Because decarbonized methanation is 5,500 power intensive, a 5,000 carbon intensity 4,500 below 120 g per kWh is required to reduce 4,000 CO2 emissions if 3,500 connected with the grid. Power-to-gas: methanation 3,000 CAC from solar – For France, carbon business case 2,500 avoidance cost is 2,000 cheaper with a fully wind-powered 1,500 electrolyzer with no CAC from wind 1,000 grid connection but still higher than the 500 IPCC price IPCC’s 0 recommendation recommendation. 0 25 50 75 100 125 150 175 200 – Countries with a Grid emissions carbon intensity below 25 g per kWhe Business models – Business (kgCO2 per MWhe) 4.2 would benefit from cases Grid Grid + wind Grid + solar connecting the electrolyzer to the Notes: CAC is carbon abatement cost. The hypothesis is detailed in the appendix. 154 Sources: Intergovernmental Panel on Climate Change, Organisation for Economic Co-operation and Development; Kearney Energy Transition Institute analysis grid. BB2 Power-to- P2P value chain Illustrative power requires Grid connection Electro- LP storage HP storage Compression Stationary fuel cell high-pressure and infrastructure lyzer (60 bars) (900 bars) storage to feed the fuel cell for electricity generation

1 MW 100 MW 1 MW 100 MW 1 MW 100 MW 1 MW 100 MW 1 MW 100 MW Year hypothesesAll107. are describedslide in

Capacity 0.78 t H 94 t H 16 kg H 2 t H (tH2 per MW) - - 2 2 - - 2 2 1 MW 100 MW 2 days 2 days 1 hour 1 hour

Capex Transfer: $0.013 ($ million) P2P: Energy Storage Line: $0.112 $0.53 $31.8 0.3 17.6 $0.045 $3.4 $1.1 $50.6 System business case Pipeline: $0.3 Opex (% capex/$ Electrification: 0% $0.01 $1.2 $0.01 $0.9 6% 6% 4% 2% million per Pipeline: 2% million million million million year) Electricity required 8.3 3.0 (% losses 3% (losses) - - - - per kWh) kWh/kg kWh/kg

Efficiency (%) Business models – Business - - 65% 70% 4.2 cases

155 Sources: ENEA Consulting; ITM Power; “The Future of Hydrogen,” International Energy Agency, June 2019; expert interviews; Kearney Energy Transition Institute analysis BB2 The levelized Levelized cost of 2019: 1 MW 2025f: 10 MW 2030f: 100 MW energy: Power cost of electricity ($ per MWhe) from power-to- power could vary 70 44 136 21 Grid utilization 259 421 181 272 192 30 22 17 from $180 to $270 24 38 5 21 3 15 per MWhe by 2030 56 69 34 108 116 51 329 178 701 213 411 228 Wind 70 48 33 7 2 25 1,092 88 106 69 33 509 281 300 161 590 72 268 Solar 109 49 116 11 2 45

70 44 125 21 273 437 182 274 180 Grid wind 30 22 17 24 40 5 21 3 15 P2P: Energy Storage System business case 70 44 125 21 291 458 194 287 180 Grid solar 30 22 17 25 42 5 22 3 15

– Low-pressure tanks could – High-pressure tanks and fuel – P2P systems are capital- store up to two days of cells delivers electricity to Fuel Cell intensive as they require production to ensure the grid, with a capacity of Storage (LP & HP) electrolyzer, fuel cell, business continuity even 70 MWhe and a maximum storage tanks, and Compression during renewable power output of 100 MW. compressor. Infrastructure disruptions. If needed, – Additional capacity and Business models – Business Electrolysis 4.2 trailers could supply power output would increase cases additional H2 to the plant HP storage and fuel cell Current ESS battery price range (not included in capex and overall LCOE. calculations). 156 1. Current ESS battery price range: 100-200 $/MWh Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; International Renewable Energy Agency; Lazard; Kearney Energy Transition Institute analysis B2 EPEX spot prices: selected countries Heading B Selling P2P (2018, highest prices on 1,000 hours, $ per MWh) electricity on the 88 hours – Spot prices are per year 300 below $100 per spot market MWh 99% of the appears to be very time. – Producing opportunistic as 250 hydrogen during low spot prices prices are over Wind 2030 and providing LCOE less than electricity to the 200 grid when prices 1% of the time are higher than Grid 2030 production costs Grid + solar appears to have 150 2030 low potential as LCOE from P2P may always be higher than spot 100 prices, except for a few hours per P2P: Energy Storage year. System business case – P2P systems can 50 also provide grid flexibility and help load management.

0 88% 89% 90% 91% 92% 93% 94% 95% 96% 97% 98% 99% 100%

France Germany DK1 NO2 SE3

Business models – Business 4.2 cases

Sources: Energi Data Service; European Network of Transmission System Operators; “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; International Renewable Energy Agency; Kearney Energy 157 Transition Institute analysis B2 Avoided CO2 and abatement cost vs. coal turbines Illustrative B Converting coal (2030, kgCO2/MWh, $ per tCO ) turbines to P2P 2 Avoided CO2 emissions Abatement cost (min–max) systems coupled Net CO2 emissions with renewable emitter reduction IPCC 2°C carbon price could save 800 Grid utilization -305 CO2 Neutrality ~ 340g/kWhe recommendation, 2030 gCO2 per kWh at a cost of $100 to Wind 785 108 322 1,200 per tCO2

Solar 714 175 466

Grid wind 131 284 1,203 P2P: Energy Storage System business case Grid solar -22

– Coal turbines are among the highest polluting electricity sources, with about 820gCO2 per kWhe emitted. – While many countries use coal turbines as a baseload for electricity generation, some use coal turbines as reserve capacity to meet demand at peak times

– Coupling electrolyzer with renewables and store H2 to ensure operations during peak times – In 2019, coal power plants generated more than 10,000 TWh of electricity (about 38% of global electricity production). Business models – Business 4.2 – Shifting all coal power plant to P2P H sources would require electricity generation from wind turbines of about 16,500 TWh (at cases 2 least 5,000 GW of installed capacity only dedicated to H2 production). As of 2018, worldwide wind production capacity was about 600 GW, growing 55 GW per year over the past three years. 158 Note: CO2 neutrality is defined as the maximum CO2 footprint from the power sector to reach carbon neutrality between coal turbine and P2P solution. Sources: Bilan Electrique 2018; RTE; Lazard; International Energy Agency; Kearney Energy Transition Institute analysis BB2 The top coal CAC vs. CO2 emissions from electricity gen. (2030) Heading consumers would Avoidance cost – P2P systems ($ per tCO2) connected to the not reduce CO2 grid and REN could 400 save CO2 emissions emissions by Countries with no potential for carbon emissions reduction from grid coupling: Grid from coal turbines if Grid + wind coupling electrolyzer CO2 intensity from 350 Grid + solar power sector does with grid, except the not exceed 500g (grid + wind case). United States and 300 – For top coal consumer countries, Russia, but at a coupling electrolyzer with the grid would higher cost than 250 not allow for RES IPCC price reducing CO2 recommendation emissions, except 200 for Russia and the Solar 2030 United States. – However, the P2P: Energy Storage 150 carbon avoided Wind 2030 cost is higher than System business case a wind-powered 100 electrolyzer. – Countries with an average low carbon 50 footprint from electricity generation (below 200g per kWh) could reduce 0 0 50 100 150 200 250 300 350 400 450 500 550 600 CO2 emissions from coal turbines at an Grid emissions abatement cost of Business models – Business 4.2 (kgCO2 per MWhe) $45 to $100 per cases tCO2.

Note: CAC is carbon abatement cost. The hypothesis is detailed in the appendix. 159 Sources: Intergovernmental Panel on Climate Change, Organisation for Economic Co-operation and Development; Kearney Energy Transition Institute analysis BB3 Green H can REFHYNE project overview Shell refinery in Wesseling Business case review 2 (Pilot project) Current situation be produced in – Electrolyzer will be chemical plants – The refinery supplies 10 to connected to the grid with 15% of Germany’s fuel the following revenue or refineries to needs. streams: provide a – Hydrogen produced by – Supply of hydrogen to decarbonized steam methane reforming, refinery (1% of refinery with about 180 kTH2 every demand) feedstock year – Load management for – CO2 emissions from SMR refinery site at Wesseling amounts to – Grid balancing Berlin about 1.6 to 2.0 mtCO2 – If produced from RES, per year. electrolyzer could save up Dusseldorf to 16 ktCO2 per year at the refinery. Shell – In the future, hydrogen will Frankfurt also be supplied to other Power-to-chemical: business local users, such as bus case refining networks. Stuttgart Integration of a 10 MW – Total investment is about Munich PEM electrolyzer €20 million, with financing from the European Union. – Test economical, – To achieve 100% green technical, and hydrogen production, the environmental electrolyzer size needs to impact of the solution reach 1 GW.

Business models – Business 4.2 cases

160 BB3 Green hydrogen Levelized cost of 2019: 1 MW 2025f: 10 MW 2030f: 100 MW energy: feedstock as a feedstock ($ per kg) includes a low number of steps Grid utilization 5.6 0.5 6.1 4.2 0.1 4.3 3.1 0.1 3.2 and could become competitive in certain situations Wind 7.1 1.2 8.3 4.9 0.2 5.1 2.7 0.1 2.7

Solar 10.9 1.9 12.8 6.9 0.2 7.2 2.7 0.0 2.7

Grid wind 5.9 0.5 6.4 4.2 0.1 4.3 2.9 0.1 3.0

Power-to-chemical: business case refining Grid solar 6.2 0.5 6.8 4.5 0.1 4.6 2.9 0.1 3.0

– Hydrogen for industrial use – Hydrogen from REFHYNE – A 100 MW electrolyzer is currently much more electrolyzer (10 MW PEM) running at about 90% expensive than brown is probably more expensive would supply only 10% Infrastructure sources. than onsite SMR, but of Wesseling refinery Electrolysis services provided to refinery needs. Business models – Business power grid could help reduce 4.2 cases Current SMR LCOH range(1) LCOH.

1. Current SMR LCOH range: $1-$2/kg Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; International Renewable Energy 161 Agency; Lazard; Kearney Energy Transition Institute analysis B3 Avoided CO2 and avoidance cost vs. SMR B Reducing (2030, kgCO /kgH , $ per tCO , based on world electrical mix) carbon emissions 2 2 2 Avoided CO2 emissions Avoidance cost vs. SMR is only possible IPCC 2°C carbon price Net CO2 emissions recommendation, 2030 with renewable emitter reduction

CO2 neutrality: sources coupling, Grid utilization -13 about 200g per kWhe with an abatement cost of $129 to $150 per ton Wind 10 129

Solar 9 150

CO2 neutrality: Grid wind -4 about 350g per kWhe Power-to-chemical: business case refining

CO2 neutrality: Grid solar -7 about 275g per kWhe

– Only electrolyzers powered by renewable – The abatement cost is similar to the one from sources would have a positive impact on centralized ATR blue production in business CO2 emissions compared with SMR. case n°1 (100 to 150 $ per tCO2). However, it might be more competitive for existing chemical plants and refineries to add CCS Business models – Business to existing SMR. 4.2 cases – Further services provided by electrolyzer, such as power consumption optimization, might help reduce the abatement cost. 162 Notes: The hypothesis is detailed in the appendix. CO2 neutrality is defined as a maximum CO2 footprint from the power sector to reach carbon neutrality between SMR and electrolysis. Sources: Intergovernmental Panel on Climate Change; Kearney Energy Transition Institute analysis BB3 Hydrogen CAC vs. CO2 emissions from electricity gen. (2030) Heading from grid-powered – Industrial processes electrolyzer could Abatement cost such as oil refining ($ per tCO2) require large volumes reduce emissions of hydrogen. 1,400 – Converting all current at low cost if the Countries with no potential for carbon emissions reduction from grid coupling: hydrogen production 1,300 for industrial carbon footprint is applications (about 70 1,200 below 50g per kWhe Mt) to electrolyzers 1,100 Grid would require about Grid + wind 500 GW of 1,000 Grid + solar electrolysis capacity running at 90%. 900 Blue H CAC – Blue production 2 sources could also be 800 considered to reduce 700 carbon emissions at lower cost but has 600 associated risks, such as carbon leakage, Power-to-chemical: business 500 and is still dependent case refining on fossil fuels. 400 – The carbon avoidance 300 cost from electrolysis IPCC price is higher than blue 200 recommendation sources, but large- scale electrolyzers 100 could provide additional services to 0 0 50 100 150 200 250 300 350 400 the plant grid, such as power consumption Grid emissions management. Business models – Business 4.2 (kgCO2/MWhe) cases

Note: CAC is carbon abatement cost. The additional cost of blue H2 has been studied in the production section of this factbook. The hypothesis detailed in the appendix. 163 Sources: Intergovernmental Panel on Climate Change, Organisation for Economic Co-operation and Development; Kearney Energy Transition Institute analysis B4 B5 B6 Power to Mobility value chain Hydrogen could Electro- LP storage HP storage Electricity Compression Dispenser also be the vector lyzer (60 bars) (900 bars) to couple power and mobility with local electrolyzer and refueling stations Year 1 MW 100 MW 1 MW 100 MW 1 MW 100 MW 1 MW 100 MW 1 MW 100 MW All hypothesesAll107. are describedslide in

Capacity 0.78 t H 94 t H 48 kg H 6 t H (tH2) - - 2 2 - - 2 2 - - 2 days 2 days 3 hours 3 hours

Capex1 Transfer: Transfer: ($ million) $0.013 $0.30 $0.53 $31.8 $0.3 $17.6 $0.15 $10.2 $0.078 $2.4 Power-to-mobility: business Line: Line: cases car, bus and train $0.112 $0.112 Opex (% capex/$ $0.01 $1.2 $0.02 $2.7 0% 0% 6% 6% 8% 8% million per million million million million year) Electricity required 8.3 3.0 (% losses 3% 3% ------per kWh) kWh/kg kWh/kg

Capacity 0.78 t H 94 t H 48 kg H 6 t H - - 2 2 - - 2 2 - - Business models – Business (tH2) 4.2 2 days 2 days 3 hours 3 hours cases

1 Includes capture, storage, and transportation costs 164 Sources: ENEA Consulting; ITM Power; “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis B4 B5 B6 Levelized cost of 2019: 1 MW 2025f: 10 MW 2030f: 100 MW hydrogen: mobility Overall LCOH could ($ per kg) 0 5 10 15 20 0 5 10 15 20 0 5 10 15 20

go as low as $4 to 1 0 1 0 Grid utilization 6 8 4 5 3 4 $5 per kg by 2030 1 1 0 0 and become more 0 0 0 0 1 0 1 0 competitive than Wind 7 1 1 2 0 12 5 7 3 4 0 1 0 1 ICE fuels (however

total cost of 1 1 0 Solar 11 2 2 3 1 18 7 2 0 10 3 5 ownership should 0 0 1 also be considered) 1 0 1 0 6 8 4 5 3 4 Grid wind 1 1 0 0 0 0 0 0

Power-to-mobility: business 1 0 1 0 6 9 4 6 3 4 cases car, bus and train Grid solar 1 1 1 0 0 0 0 0 Dispenser LP and HP storage Compression – P2M systems are capital- – Storage tanks are – Grid-connected electrolyzer Infrastructure intensive as they require designed to store two could be considered as a Electrolysis electrolyzer, dispenser, days of production at 100% business case if electricity storage tanks, and utilization rate. When the generation emissions do not Current internal combustion compressor. utilization rate is low, overcome emissions from engine fuels price storage costs are high. internal combustion engines. Business models – Business 4.2 range1 cases

1 Considering 6 to 10L/100km of fuel consumption at $1 per L, equivalent to 6-10 $/kg of hydrogen. Full comparison between ICE and FCEV also presented in the following slides. Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; “National Hydrogen Roadmap,” Commonwealth Scientific and Industrial Research Organisation, 2018; International Renewable Energy 165 Agency; ENEA Consulting; Kearney Energy Transition Institute analysis B4 B5 B6 Space requirements and investment costs for HRS Average Estimates Faster refueling Refueling speed Space requirements Investment costs time for hydrogen- Refueling speed Space required to service Investment costs per based vehicles (s per 100km of (same number of vehicles, refueling ($/refueling) also leads to less refueling) comparative basis) space 1,000 8.5 requirements and lower investment 2x

costs 15x 10-15x 4.0

0.7 48 65

Power-to-mobility: business Petrol H2 station Electric fast HRS Fast charger Petrol HRS Fast charger cases car, bus and train (HRS) charger

– Hydrogen refueling takes one – Fast-charging stations handling – When fully utilized, HRS are tenth to one fifteenth of the the same number of vehicles estimated to cost only half of time fast charging demands. need 10 to 15 times the space the capex per refueling – Charging times (HRS vs EV) of a comparable HRS. compared with fast chargers. – Bus: 7–15 mins vs. several – One HRS with four dispensers – Lower costs present an hours could potentially replace 60 attractive business case for – Car: 3–4 mins vs. 4 hours fast-charger stations. operators. – Forklift: 1–3 mins vs. 25 mins – Beneficial to the customer and – Scooter: less than 1 minute for municipalities with space Business models – Business 4.2 cases vs 4–8 hours constraints – Train: 15 minutes vs. 45 minutes 166 Note: HRS is hydrogen refueling station. Source: Kearney Energy Transition Institute analysis B4 Total cost of ownership: cars (2019–long term, $ per 100 km) Investment costs

– About 24 to 32% of costs are TCO for a H2 car 2019 Long-term driven by fuel cells. Cost could compete reduction will help improve FCEV cars’ competitiveness. with a traditional – Today’s FCEVs have a broader ICE engine if range per tank than most BEV +16% (400–600 km vs. 250–400 km). refueling stations 65 However, TCO is higher. – Acquisition and infrastructure Base car cost are not under-used 5 cost are higher. Battery, fuel cell – Utilization of infrastructure is Operations and maintenance key for competitiveness of 4 Electricity, fuel 56 FCEV. For example, a 200 kg 1 Refueling, charging H2 station at 10% adds a 2 marginal LCOH of $13 per 6 100km vs. $4 per 100 km if 5 50 utilized at 33%. – In the long term, the TCO for 46 46 FCEV will be comparable with Power-to-mobility: business 2 2 1 BEV, which would have by case car 44 2 5 0 3 then an extended range as 5 41 well. 21 – Consumers could also value 18 8 6 5 qualitative benefits in addition to TCO, such as charging time 11 9 and infrastructure deployment. 5 6 6

0 30 30 30 30 30 30 30 Business models – Business FCEV BEV BEV ICE Hybrid FCEV BEV ICE Hybrid 4.2 cases 400 km 400 km 250 km 400 km 400 km

Note: The hypotheses are detailed in the appendix. 167 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis B4 LCOM and range for selected models (2019; X axis: range in km; Y axis: LCOM in $ per km) Non-Exhaustive Hydrogen cars Luxury model with high have ranges close LCOM performances (acceleration and ($ per km) speed), comparable or higher range to high-end BEVs than FCEV and high TCO 2.3 and at a lower cost, Porsche Taycan Turbo S but TCO remains Tesla Model S FCEV mid-class models have a higher than mid- 1.1 range higher than entry-level BEV but are still slightly more expensive. Huyndai Nexo end BEVs 1.0 Hyundai Tucson FCEV 0.9 Toyota Mirai GER Honda Clarity FC 0.8 Entry level BEV, with low TCO but Toyota Mirai JAP low operating range 0.7

0.6 Kia e-NIRO Power-to-mobility: business 0.5 Nissan LEAF Hyundai IONIQe case car Renault ZOE 0.4 ICE car reference1

0.3

0.2

H2 price: $7.40 per kg (refueling LCOH, grid, 2019) 0.1 Electricity price: $52 per MWhe + 30% for charging station

0.0 0 200 220 240 260 280 300 320 340 360 380 400 420 440 460 480 500 520 540 560 580 600 620 640 660 680

Business models – Business Range (km) 4.2 FCEV BEV cases

1 Car price: $20,000; fuel consumption: 6.0L/100km 168 Sources: BNEF; “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis B4 Competitiveness FCEV vs. BEV How to read (X axis: range in km; Y axis: FC cost in $ per kW) In the long term, – In 2024, lithium–ion batteries for vehicles are expected to cost $94 per kWh. FCEV is expected Fuel cell capex ($ per kW) – To be competitive, fuel cells in FCEV will have to be more to be below the red-line boundary. 100 competitive than 2024 LIB price – For a 400-km range vehicle, fuel cell costs BEV if the vehicle 95 $94 per kWh have to be lower than $50 per kW. 90 – In 2030, LIB cost is expected to go as low as range is 200 to 400 85 $62 per kWh. 80 km BEV – For a 400-km range vehicle, fuel cell costs 75 cheaper have to be lower than $25 per kW. 70 – By 2030, the Department of Energy expects 65 that the cost of fuel cells will go down to $30 60 per kW. 55 FCEV 2030 LIB price 50 cheaper $62 per kWh Power-to-mobility: business 45 case car 40 35 Long-term Further considerations 30 projected cost of fuel cell 25 – Charging time: See slide 130. 20 – CO2 emissions: End-to-end CO2 emissions 15 have to be evaluated, including battery and 10 fuel cell production and recycling as well as 5 fuel production (either H2 or electricity). 0 – For a 500 km range, the FCEV car price could Business models – Business 100 200 300 400 500 600 700 800 4.2 cases reach about $30,000 by 2030 compared with Vehicle range $35,000 for a BEV. (km)

169 Note: Hypotheses from the International Energy Agency are detailed in the appendix. Sources: BNEF; “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute Analysis 1 B4 CO2 avoided CO2 avoidance cost (2030, kgCO2/100km) (2030, $ per ton) Carbon abatement cost is lower for short-range BEVs FCEV car BEV car1 BEV Car1 FCEV car BEV car1 BEV car1 Price: $28,000 Price: $30,000 Price: $34,000 Price: $28,000 Price: $30,000 Price: $34,000 Range: 600 km Range: 400 km Range: 600 km Range: 600 km Range: 400 km Range: 600 km if charging Consumption: 0.8kg/100km Consumption: Consumption 18.1 kWh Consumption: 0.8kg/100km Consumption 17.1 kWH Consumption: 18.1 kWh stations are 17.1 kWH coupled with wind 15 6,875 and grid, but FCEVs would save more CO2 at a lower cost for long 3,410 4 2,159 ranges 3 Power-to-mobility: business 619 1 1 471 case car Grid Grid + Wind Grid Grid + Grid Grid + wind wind wind Net emitter of CO2 -3 -5 Grid Grid + Wind Grid Grid + Grid Grid + wind wind wind

Business models – Business 4.2 cases

1. Including battery manufacturing footprint Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Commonwealth Scientific and Industrial Research Organisation; Pau; ITM Power; RTE; CRMT; Kearney Energy Transition Institute 170 analysis B4 CAC vs. CO2 emissions from electricity generation Key comments (2030, selected countries) As emissions from – Wind-powered Avoidance cost electrolyzer has a the grid grow, ($ per tCO2) lower CAC than Countries with no potential for carbon emissions reduction from grid coupling: grid-connected FCEV would save 5,500 hydrogen stations more CO2 than 5,250 FCEV: grid unless grid 5,000 FCEV: grid + wind emissions are 600-km range BEV, 4,750 BEV: 400 km–grid below 200g per but for 400 km, 4,500 BEV: 600 km–grid kWhe. 4,250 BEV: 400 km–grid + wind – However, a 400- km range BEV BEV would still be 4,000 BEV: 600 km–grid + wind 3,750 has a lower carbon avoidance better 3,500 cost until grid 3,250 emissions reach 3,000 300 to 550 g per 2,750 kWhe. 2,500 2,250 – A 600-km range Power-to-mobility: business 2,000 BEV has high case car 1,750 avoidance cost due 1,500 to higher battery 1,250 carbon footprint and 1,000 higher electricity 750 consumption per 500 FCEV Wind 2030 km. 250 IPCC price recommendation 0 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 Grid emissions Business models – Business 4.2 (kgCO2/MWhe) cases

Note: CAC is carbon abatement cost. The hypothesis is detailed in the appendix. 171 Sources: Intergovernmental Panel on Climate Change, Organisation for Economic Co-operation and Development; Kearney Energy Transition Institute analysis B5 Total cost of ownership: trucks (2019–long-term, $ per 100km) Fuel-cell trucks Key comments 2019 Long-term are expected to – Long-haul trucks have high range and power compete with Base truck cost requirements. +13% Battery, fuel cell other low-carbon – FCEV long-haul trucks solutions, such as 96 Operations and maintenance Electricity, fuel tend to be more immediately competitive BEV trucks and 12 Refueling, charging 85 than BEV compared hybrid catenary 82 with cars (13% TCO 6 80 delta vs. 18% for cars). – BEV trucks face many 71 17 71 challenges, such battery 68 8 6 weight (limiting payload 36 5 37 transportation), long 37 recharging time, and 10 Power-to-mobility: business 17 15 additional recharging case bus 23 infrastructure. – FCEV could be 10 10 competitive with BEV 16 in heavy-duty applications 15 32 in a range of more than 15 10 600 km. 19 18 – A H2 price below $7 per 12 8 10 kg and a fuel-cell cost of about $95 per kW is Business models – Business 20 20 20 20 20 20 20 4.2 required to make FCEV cases FCEV BEV Diesel ICE FCEV BEV Hybrid Diesel trucks competitive with Catenary hybrid Note: The hypothesis is detailed in the appendix. ICE. 172 Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Kearney Energy Transition Institute analysis B5 Pau, France zero-emission public transportation project, FEBUS

A city in France is Key characteristics experimenting with €74.5 million (of which H2 buses for its city Project investment €14.5 million is for bus fleet and has and recharging station) promised no cost Commissioning date Autumn 2019 increase for Fuel cell power 100 kW passengers Consumption 10–12 kgH2 per 100 km Autonomy More than 240 km PEM: up to 268 kgH per Electrolyzer 2 day Number of passengers 125 Illustrative per bus

Power-to-mobility: business case bus Key project partners

– ITM Power – Pau Porte des Pyrénées – Ville de Pau – Idelis – Engie Gnvert – VanHool Business models – Business 4.2 cases

Note: The hypothesis is detailed in the appendix. 173 Sources: Pau, ITM Power; Kearney Energy Transition Institute analysis B5 Levelized cost of mobility3 per passenger Capex (2019, $ per passenger) Operations, maintenance, and warehouse Fuel An H2 bus network comes Electricity and infrastructure at an extra cost +0.9 +1.2 2.5 of 90¢ to $1.20 per 2.2 0.9 2.0 passenger and is 0.6 0.1 1.5 0.1 more expensive 0.1 1.3 0.4 0.6 0.6 0.1 than battery 0.4 electric buses 0.5 1.3 0.4 1.0 1.0 1.0 0.4 Illustrative ICE bus Grid Wind Same number of buses + 2 additional buses

Power-to-mobility: business Fuel cell buses BEV buses case bus Fuel price $1.30 per L $7.80 per kg2 $11.80 per kg2 $52 per MWh Capex bus $675,000 per bus $675,000 per bus $294,000 x 6 buses $730,000 per bus x 6 buses x 6 buses x 8 buses Operations & maintenance: 30¢ per km 60¢ per km 30¢ per km drivetrain Operations & maintenance: $112,000 per year per bus warehouse Business models – Business 4.2 cases Passengers 489,000 per year

1. Including driver wages and bus-stop infrastructure 2 The price calculation is detailed on slide 136. 174 3 Defined as present value of costs divided by present value of number of passengers Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Commonwealth Scientific and Industrial Research Organisation; Kearney Energy Transition Institute analysis B5 Levelized cost of mobility3 per passenger Capex (2030f, $ per passenger) Operations, maintenance, and warehouse Declining LCOH Fuel and acquisition Electricity and infrastructure cost reduction 1.8 +0.1 0.1 triggered by mass 0.1 1.4 1.4 1.5 production could 1.3 0.1 0.4 0.3 0.3 0.1 make FCEV buses 0.5 0.4 competitive with 0.4 0.4 BEV and ICE 0.4 1.2 0.9 0.7 0.7 0.4

Illustrative ICE bus Grid Wind Same number of buses + 2 additional buses

Power-to-mobility: business Fuel cell buses BEV buses case bus Fuel price $1.30 per L $3.80 per kg2 $4.40 per kg2 $52 per MWh Capex bus $617,000 per bus $617,000 per bus $294,000 x 6 buses $450,000 per x 6 buses x 6 buses x 8 buses Operations & maintenance: 30¢ per km 60¢ per km 30¢ per km drivetrain Operations & maintenance: $112,000 per year per bus Business models – Business warehouse 4.2 cases Passengers 489,000 per year

1 Including driver wages and bus-stop infrastructure 2 The price calculation is detailed on slide 136. 175 3 Defined as present value of costs divided by present value of number of passengers Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Commonwealth Scientific and Industrial Research Organisation; Kearney Energy Transition Institute analysis CO2 avoided1 CO2 avoidance cost B5 (2030, kgCO2/100km) (2030, $ per ton) Under the current electrical mix, only Fuel cell buses BEV buses Fuel cell buses BEV buses refueling stations 104 IPCC 2°C carbon price 1,539 powered by recommendation, 2030 renewables would reduce CO2 emissions at a 41 38 cost below $220 per ton

Illustrative Station connected to 429 the grid Power-to-mobility: business Net emitter of CO case bus 2 126

-75 FCEV FCEV BEV bus BEV bus Grid Wind Same +2 additional bus: grid bus: wind + 2 buses number buses of buses However, because of the intermittency of production, an emergency supply of hydrogen might be needed Business models – Business (for example, by trailer), which would increase the overall cost. 4.2 cases

1 Including battery manufacturing footprint Sources: “The Future of Hydrogen,” International Energy Agency, June 2019; Commonwealth Scientific and Industrial Research Organisation;; Pau; ITM Power; RTE; CRMT; Kearney Energy Transition Institute 176 analysis B5 CAC vs. CO2 emissions from electricity generation Key comments (2030, selected countries) – Wind-powered While FCEV buses electrolyzer has the lowest carbon powered by wind Avoidance cost avoidance cost for city H appear to have ($ per tCO2) buses, except for 2 countries with 1,700 the lowest CAC, Countries with no potential for carbon emissions electricity carbon 1,600 reduction from grid coupling: FCEV: grid intensity below grid-powered BEV BEV: grid 140g/kWhe. 1,500 – However, because BEV +2: grid buses are the 1,400 of the limiting load factor, this solution second best 1,300 might not be always 1,200 feasible as it alternative requires a minimum 1,100 service rate. – Grid-connected 1,000 electrolyzer can be a 900 sustainable solution over grid-charged BEV 800 Battery carbon footprint buses in countries with has a high impact when Power-to-mobility: business 700 low an electricity grid emissions are low. carbon intensity below case bus 600 175g/kWhe, as battery 500 manufacturing footprint weight is higher. 400 – Countries with carbon intensity 300 IPCC price below 700g/kWhe 200 recommendation when no extra BEV Wind 2030 bus is needed and 100 580 g/kWhe when 0 33% extra buses are 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 needed would reduce their CO2 Business models – Business 4.2 Grid emissions emissions by cases (kgCO2/MWhe) switching to BEV buses.

177 Notes: CAC is carbon abatement cost. IPCC is Intergovernmental Panel on Climate Change. The hypothesis is detailed in the appendix. CO2 neutrality is defined as the maximum CO2 footprint from power sector to reach carbon neutrality between natural gas and injection. Sources: Intergovernmental Panel on Climate Change, Organisation for Economic Co-operation and Development; Kearney Energy Transition Institute analyses B5 Overview of H2 buses project (Number of projects per country) Non-Exhaustive Cities around the world are launching H2 buses projects to evaluate the potential 2 1 3 1 13 5 12 5 1 1 227 12 1 1 4 7 31 2 4 10

2 Power-to-mobility: business case bus 1 1

2

1

Business models – Business 4.2 cases

178 Source: Kearney Energy transition Institute analysis B6 H2 train example: Germany

Hydrogen- – The Local Transport Authority of Lower powered trains The current option Saxony has already ordered an additional available is H2 are a robust production from Dow 14 hydrogen trains from Alstom, which are chlorine plant and scheduled to start driving this route by 2021. truck transportation. alternative to – RMVs issued a tender for 27 fuel cell trains, electrification and Alstom will deliver the vehicles by the for replacing timetable change in 2022. Alstom also manages the supply of hydrogen in diesel trains cooperation with Infraserv GmbH & Co. Höchst KG, with the filling station located on the premises of the Höchst industrial park., H could also be Air product built the 2 produced on-site with mobile maintenance and the provision of reserve refueling electrolyzer coupled near station to windfarms or the capacities for the next 25 years for €500M. Bremervörde. grid. – The Coradia iLint trains can run for about 600 Power-to-mobility: business 20 km miles (1,000 km) on a single tank of case train hydrogen, similar to the range of diesel trains that represent 40% of the lines in Germany. – Lower Saxony is Germany’s leading wind- “Switching to hydrogen-powered trains is a power state producing 20% of Germany’s quickly feasible alternative to expensive wind-generated electricity and has plans to electrification” increase this to 20,000MW by 2050. Tarek Al-Wazir, Minister of Economics, Energy, – At a later stage, green hydrogen will be Transport, and Regional Development for Hesse produced by on-site electrolysis powered Business models – Business 4.2 by a wind turbine cases

179 Source: Kearney Energy transition Institute analysis B6 Levelized cost of mobility1 (2019, $ per passenger) H2 trains on non- electrified lines are more H2 from chlorine H2 from Electric ICE Key competitive than plant electrolysis trains trains comments electrification but 20.1 Trains: capex – Fuel costs for more expensive Trains: operations and maintenance hydrogen trains than diesel trains Fuel costs include production Electrification to refueling costs, including storage, compression, and refueling stations. – Hydrogen is 16.6 currently more competitive if it comes as a by- Power-to-mobility: business product from the case train 7.6 chlorine production plant, even if it is 6.3 priced at SMR cost or $1.40 5.1 3.9 5.0 4.6 2.6 0.0 per kg. 1.3 0.9 3.5 0.0 1.8 – However, diesel 1.0 1.0 1.0 1.0 0.4 0.4 trains remain more 1.0 1.0 1.2 competitive. 2.8 2.8 2.8 2.8 2.2 2.2 2.0 Base costs1 Business models – Business FC train: FC train: FC train: FC train: E-train: E-train: Diesel train 4.2 cases "free" H2 SMR price grid wind electrified non-electrified line line

1 Not including base costs, such as driver, rail, and station-related costs 180 Sources: Deutsche Bahn; Usine Nouvelle; Bloomberg; EESI; “The Future of Hydrogen,” International Energy Agency, June 2019; RTE; Kearney Energy Transition Institute analysis B6 Levelized cost of mobility1 (2030f, $ per passenger) H2 trains on non- electrified lines are more H2 from chlorine H2 from Electric ICE Key competitive plant electrolysis trains trains comments than electrification 20.1 Trains: capex No capex reduction but more Trains: operations and maintenance for FCEV trains has expensive than Fuel costs been considered. Electrification – As hydrogen diesel trains production costs will become cheaper, including related 16.6 infrastructure, fuel- cell trains could become more Power-to-mobility: business competitive than case train diesel trains if H2 is purchased at free cost or SMR price and 5.1 5.1 5.0 4.6 0.0 transported to 4.2 1.3 1.4 0.4 0.9 3.5 0.0 1.8 refueling station. 1.0 1.0 1.0 1.0 0.4 0.4 1.0 1.0 1.2 2.8 2.8 2.8 2.8 2.2 2.2 2.0 Base costs1 Business models – Business FC train: FC train: FC train: FC train: E-train: E-train: Diesel train 4.2 cases "free" H2 SMR price grid wind electrified non-electrified line line

1 Not including base costs, such as driver, rail, and station-related costs 181 Sources: Deutsche Bahn; Usine Nouvelle; Bloomberg; EESI; “The Future of Hydrogen,” International Energy Agency, June 2019; RTE; Kearney Energy Transition Institute analysis 1 B6 CO2 avoided CO2 avoidance cost (2030, kgCO2/100km) (2030, $ per t) Using 244 122,764 by-product H2 213 213 IPCC 2°C carbon price from the chlorine recommendation, 2030 industry appears to have the cheapest 9 9 1 avoidance cost

Excludes emissions related to chlorine production (and H2 as by-product)

Refueling station powered by grid Power-to-mobility: business Already Net Cheaper than cheaper case train emitter of 56 Net emitter of CO2 diesel trains than diesel CO2 trains

-381 FC train: FC train: FC train: FC train: E-train: E-train: Grid + FC train: FC train: FC train: FC train: E-train: E-train: non "free" H2 SMR price grid wind electrified non wind "free" H2 SMR price grid wind electrified electrified line electrified line line line

Business models – Business 4.2 cases

1 Not including base costs, such as driver, rail, and station-related costs 182 Sources: Deutsche Bahn; Usine Nouvelle; Bloomberg; EESI; “The Future of Hydrogen,” International Energy Agency, June 2019; RTE; Kearney Energy Transition Institute analysis 1 B6 CAC vs. CO2 emissions from electricity generation Key comments (2030, selected countries) An FCEV train with – Electrifying lines is very expensive – H2 by grid could CAC is therefore always higher than save CO2 Avoidance cost $4,500 per ton. if grid emissions ($ per tCO2) – FCEV trains appear as a strong are below alternative to Countries with no potential for carbon emissions reduction from grid coupling: railway 300g/kWhe at a electrification at a lower avoidance lower carbon 100,000 avoidance cost. cost than FCEV - Grid – However, FCEV trains with H Electric Train - With Electrification 2 electrification produced from grid 10,000 are sustainable only if grid intensity is below 200gCO2/kWhe. – A wind-powered Power-to-mobility: business 1,000 production plant is case train the cheapest IPCC price alternative when recommendation Wind 2030 grid emissions are 100 above about 100gCO2/kWhe.

10 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800 Grid emissions Business models – Business 4.2 (kgCO2/MWhe) cases

Note: CAC is carbon abatement cost. The hypothesis is detailed in the appendix. 183 Sources: Intergovernmental Panel on Climate Change, Organisation for Economic Co-operation and Development; Kearney Energy Transition Institute analysis Carbon abatement cost vs. grid emissions for business cases Benefits of (2030; Y axis: CAC in $ per tCO log scale; X axis: CO emissions in kg/MWhe) electrolysis vary 2 2 by application Avoidance cost and depend on ($ per tCO2) the country’s 10,000 energy mix Methanation B1a FCEV car B4

Injection B1b Industrial feedstock B3 FCEV bus B5

FCEV train B6 Power-2-Power B2 IPCC CO2 price recommendation ($220/tCO2)

100

10 0 50 100 150 200 250 300 350 400

Carbon intensity of Countries (gCO2/kWhe)

Business models – Business 4.2 cases

Note: IPCC is Intergovernmental Panel on Climate Change. 184 Source: Kearney Energy Transition Institute analysis Power-to-mobility, Carbon reduction potential vs. Carbon abatement cost (CAC) power-to-power, CAC ($ per tCO2) Blue H2 P2G P2P P2M and Injection 10,000 coupled with renewable Methanation: solar production have P2M: car - grid + wind high potential to decarbonize their Methanation: wind 1,000 P2P: grid + solar sector at low cost P2M: car - wind P2P: grid + wind Injection: solar Injection: wind P2P: solar P2P: wind H-Vision: ref 100 P2M: bus - wind

P2M: train - wind

10 Business models – Business 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% 4.2 cases CO2 reduction potential (%)

Note: P2M: Power to Mobility; P2P: Power to Power 185 Source: Kearney Energy Transition Institute Illustrative H -electrolysis hub Large-scale H2 2 production that can serve multiple users to maximize P2G Feedstock load factor is vital (for O&G and to competitiveness Chemicals)

H2 hub Transport Power

10-100 MW electrolysis

Heat

Business models – Business 4.2 cases

186 Source: Kearney Energy Transition Institute Some orders of magnitude in 2019 5 Executive summary 6 1. Hydrogen’s role in the energy transition 16 2. Hydrogen value chain: upstream and midstream 25 2.1 Production technologies 27 2.2 Conversion, storage, and transportation technologies 49 2.3 Maturity and costs 61 3. Key hydrogen applications 78 3.1 Overview 80 3.2 Feedstock 84 3.3 Energy 90 3. Business models 114 4.1 Policies and competition landscape 116 4.2 Business cases 125 Appendix (Bibliography & Acronyms) 187

187 Bibliography (1/2)

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Appendix Bibliography & Acronyms

189 Acronyms – (1/2) AC/DC Alternating/Direct current HENG Hydrogen enriched natural gas AFC Alkaline fuel cell H-Gas High calorific gas AFOLU Agriculture, Forestry and Other Land Use HHV Higher heating value API American Petroleum Institute HT High temperature BoP Balance of plant ICE Internal combustion engine BTU British thermal unit (Btu) IEA International Energy Agency BEV Battery electric vehicle IPCC Intergovernmental Panel on Climate Change CAES Compressed air energy storage IRR Internal rate of return CAGR Compound annual growth rate K Kelvin (unit of measurement for temperature) CAPEX Capital expenditure kWh Kilowatt hour CCS Carbon capture & storage LCA Life cycle analysis CHP Combined heat and power LCOE Levelized cost of electricity CNG Compressed natural gas LCOH Levelized cost of hydrogen Light duty vehicle CO2 Carbon dioxide LDV DH District heating L-Gas Low calorific gas DME Dimethyl ether LHV Lower heating value DSO Distribution system operator LOHC Liquid organic hydrogen carrier E Electricity LPG Liquefied petroleum gas EPEX European Power Exchange MCFC Molten carbonate fuel cell FC Fuel cell MEA Membrane electrode assembly FCEV Fuel cell electric vehicle MtG Methanol-to-gas FCHJU Fuel Cell and Hydrogen Joint Undertaking NG Natural gas FIT Feed-in tariff NH3 Ammonia GHG Greenhouse gas NPV Net present value GtCO2eq Giga tonnes of CO2 equivalent NREL National Renewable Energy Laboratory H2 Hydrogen O&G Oil and gas H2ICE Hydrogen internal-combustion-engine vehicle O&M Operation and maintenance OPEX Operating expenditure Appendix HDS Hydrodesulfurization Bibliography & Acronyms

190 Acronyms – (2/2) Pa Pascal (Unit of measurement for pressure) URFC Unitized regenerative fuel cell P2G Power-to-gas USDOE US Department of Energy P2P Peer-to-peer VRB Vanadium Redox Batteries P2S Power-to-synfuel W Watt PAFC Phosphoric acid fuel cell Zn/Br Zinc-bromine PCM Phase change material PEM Proton exchange membrane PES Primary energy source PGM Platinum group metal PHS Pumped-hydro Storage PV Solar photovoltaic R,D&D Research, Development & Demonstration RE Renewables REC Renewable energy certificate RES Renewable electricity source SMES Super-conducting magnetic energy storage SMR Steam methane reforming SNG Synthetic natural gas SOEC Solid oxide electrolyzer cell SOFC Solid oxide fuel cell STES Seasonal thermal energy storage T&P Temperature and pressure T&D Transmission and distribution TCM Thermo-chemical material TCNG Turbocharged natural gas TEPS Total primary energy supply TSO Transmission system operator Appendix Bibliography & Acronyms

191 Kearney Energy Transition Institute

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