GROUP TECHNOLOGY & RESEARCH – POSITION PAPER 2018 HYDROGEN AS AN ENERGY CARRIER An evaluation of emerging hydrogen value chains

SAFER, SMARTER, GREENER 2 Hydrogen as an energy carrier Table of contents 3

TABLE OF CONTENTS

1. EXECUTIVE SUMMARY 4

2. INTRODUCTION 6 2.1 Hydrogen value chains 7 2.2 Decarbonization context 10

3. HYDROGEN APPLICATIONS 12 3.1 Heating in buildings 12 3.2 Electricity valorization 15 3.3 Mobility 21 3.4 Industry 27

4. BUSINESS CASE FOR OFFSHORE HYDROGEN PRODUCTION 32 4.1 Concept descriptions 33 4.2 Assumptions 34 4.3 Results 38

5. UPTAKE IN 2030 AND 2050 40 Authors: Jørg Aarnes (lead author), Marcel Eijgelaar and Erik A. Hektor 5.1 2030 prognosis 40 5.2 2030—2050 scenarios 41 Contact details: [email protected] REFERENCES 48 Acknowledgements: We thank the following for contributing valuable insights: Ketil Aamnes, Sverre Alvik, Bent E. Bakken, Graham Bennett, Theo Bosma, Hendrik Brinks, Paul Gardner, Albert van den Noort, Ben Oudman, APPENDIX A: EXPLENERGY — ENERGY VALUE CHAIN EXPLORER 50 Frank Børre Pedersen, Pierre C. Sames, Bjørn-Johan Vartdal and Andrew R. Williams. APPENDIX B: 2050 SCENARIO ELEMENTS 54 In addition, we would like to thank Kathrine Ryengen and Nicola di Giulio from ZEG Power for providing data and insights. APPENDIX C: ABBREVIATIONS 58 4 Hydrogen as an energy carrier Executive summary 5

1. EXECUTIVE SUMMARY

Some 3% of global energy consumption today is used to produce hydrogen. Only 0.002% of BLUE HYDROGEN WILL IN MOST REGIONS HAVE A CHEAPER GREEN HYDROGEN AND FUELLING this hydrogen, about 1,000 tonnes per annum(i), is used as an energy carrier. Yet as this timely LOWER CARBON FOOTPRINT THAN HYDROGEN INFRASTRUCTURE WILL BOOST UPTAKE OF FROM ELECTROLYSIS FUEL-CELL ELECTRIC VEHICLES position paper from DNV GL indicates, hydrogen can become a major clean energy carrier in This assumes that the carbon footprint of the power We expect rapid decline in the cost of green(iv) a world struggling to limit global warming. for electrolysis is equal to the carbon footprint of hydrogen and continued development of refuelling the regional electricity mix(iii). However, large-scale infrastructure to trigger broader uptake of fuel-cell The company’s recently published 2018 Energy Transition Outlook(1) projects moderate uptake production of blue hydrogen, which is made from electric vehicles. The uptake of zero-emission fossil fuels with carbon capture and storage, vehicles will reduce carbon intensity per vehicle, of hydrogen in this role towards 2050, then significant growth towards 2100. Building on that, requires parallel development of large-scale CCS but the aggregated carbon emissions from road this position paper provides a more granular analysis of hydrogen as an energy carrier. infrastructure. This needs considering when transport will continue to rise to 2030 on growth designing policy measures to incentivize low-carbon in the overall vehicle stock. According to our hydrogen production. Energy Transition Outlook, most vehicles will be non-combustion models by 2050(1). We estimate that

DECARBONIZATION IS THE MAIN DRIVER FOR be adapted to hydrogen distribution and storage. WE FIND A POSITIVE BUSINESS CASE FOR more than 80% of H2 demand for mobility will then USING HYDROGEN AS AN ENERGY CARRIER This application requires substantial policy push OFFSHORE GAS REFORMING WITH CCS be for buses, trucks and other heavy vehicles. Hydrogen can be an effective decarbonization agent and public co-funding to materialize. We explore concepts for blue and green hydrogen if it is produced with a low carbon footprint. Such on an offshore platform. The variables include the HYDROGEN MAY ENABLE GREATER MARKET hydrogen can heat buildings, fuel transport, provide HYDROGEN USE FOR INDUSTRIAL FEEDSTOCK varying needs for power cables and pipelines/ PENETRATION OF RENEWABLES

heat to industry, and be a medium to valorize surplus WILL KEEP GROWING storage for hydrogen and/or CO2. We find a positive Surplus electricity from renewables can be valorized power from renewables(ii). Enabling and limiting We see demand for this application rising from about business case for offshore gas reforming with CCS; by electrolytic production of hydrogen. However, we factors for these applications include learning rates 55 Mtpa today(2) to 69–114 Mtpa in 2050. The iron this concept has higher net present value than a show that the cost of such hydrogen production can for technology, e.g. electrolysers and fuel cells; and steel industry may begin to use hydrogen in the corresponding onshore concept if the platform is be reduced widely by increasing operating hours regional natural gas consumption; development direct iron reduction steelmaking process. This may more than about 300 km from shore. We find further beyond those when surplus electricity is available. of hydrogen-distribution infrastructure, such as add 4–11 Mtpa of hydrogen consumption by 2050. that a business case for making hydrogen from Green hydrogen producers may therefore secure pipelines and fuelling stations; and, uptake of offshore wind requires a high hydrogen price. continuous supply of green electricity through, for carbon capture and storage (CCS). HYDROGEN WILL NOT SEE SUBSTANTIAL-SCALE The primary cost driver is the offshore wind farm. example, green certificates. USE FOR INDUSTRIAL PROCESS HEATING BY 2030 SEVERAL COUNTRIES MAY SEE HYDROGEN- We reach this conclusion because other ELECTROLYSIS CAN COMPETE ON COST AGAINST USING HYDROGEN FOR PEAK SHAVING IN HEATED BUILDINGS AS A GOOD decarbonization options are more mature and many GAS REFORMING WITH CCS IN 2030 ELECTRICITY SYSTEMS MAY BE VIABLE IN 2050 DECARBONIZATION OPTION are simpler. However, we expect hydrogen-fuelled This finding assumes significantly reduced capital This requires large-scale storage of hydrogen and Australia, Canada, the Netherlands, South Korea, UK heating to be established in industries such as costs for electrolysers and that they operate only hydrogen power generation systems that can be and US are the most likely to adopt this at significant cement and aluminium by 2050 in portfolios of when electricity prices are ‘low’, below a given deployed on-demand. However, the application has scale. These countries predominantly use gas for decarbonization measures. threshold, typically with some 3,000–5,000 annual significant energy losses; each MWh of output power heating buildings, and have infrastructure that can load hours. In this scenario, electrolysers operate requires 3 MWh input power to the electrolyser. This intermittently in step with fluctuating power prices, implies that the number of hours during a year when and hydrogen storage is available for matching hydrogen for peak shaving is cost effective is limited. supply and demand.

(i) Hydrogen is today used as an energy carrier only for mobility. According to h2tools.org/hyarc/hydrogen-consumption, there were about

10,000 active fuel-cell vehicles at end of Q3 2018, including 180 buses. Assuming an average fuel consumption of 100 kg hydrogen per (iii) Blue hydrogen will typically have a carbon footprint between 1 and 5 kgCO2e/kgH2 produced. This corresponds to hydrogen (3) vehicle per year, which may be a conservative assumption, this translates to 1,000 tonnes of hydrogen. production from electrolysis using electricity with 20–100 kgCO2e/MWh. According to the IEA World Energy Outlook 2013 , (ii) Here valorize means ‘creating value that could otherwise be lost’ insofar as hydrogen is a commodity that can be stored and sold, the carbon footprint of electricity production in 2011 was 532 kgCO2e/MWh globally and 345 kgCO2e/MWh in Europe.

whereas one alternative to hydrogen production is to curtail electricity generation output. (iv) Produced by electrolysis using an electricity mix with a low greenhouse gas footprint; for example, less than 100 kgCO2e/MWh. 6 Hydrogen as an energy carrier Introduction 7

The paper is organized as follows. Section 2.1 is compared with two related concepts for onshore intended to provide readers with an overview of production. Finally, in Section 5 we estimate the possible hydrogen value chain constellations. demand for hydrogen as an energy carrier in 2030, Section 2.2 describes the context for decarbonization and project the possible total demand for hydrogen through hydrogen. This section draws on the 2014 (as a feedstock and as an energy carrier) in 2050. Assessment Report by the Intergovernmental Panel on Climate Change (IPCC) on climate change mitigation(5) in order to describe the scale of the 2.1 Hydrogen value chains 2. INTRODUCTION decarbonization challenge for respective economic sectors. Next, in Section 3 we describe how Figure 1 provides an overview of options for hydrogen can contribute to decarbonization for production, transport and storage of hydrogen.

Hydrogen (H2) is, by any standard, a truly unique Hydrogen is already extensively used as a chemical the main application areas listed on page 6. Section The preferred option will depend on the application element. It is the lightest atomic element, was the feedstock in making products, principally for 4 contains a business case assessment for offshore (e.g. for mobility or as fuel for heating) and on first to be created after the Big Bang, represents an producing fertilizers and petrochemicals. According hydrogen production, where two concepts for regional circumstances such as existing infrastructure, estimated 75% of all mass in the universe, and has to the Hydrogen Council, the world currently producing hydrogen on an offshore platform are regional energy mix and national policy. the highest chemical energy content by mass consumes more than 55 Mtpa(2), of which some 95% (4) (4) of all gaseous and liquid fuels . It is therefore stem from fossil fuels . The bulk of this H2 is used for

unsurprising that H2 has been envisioned as having ammonia production (55%), in petroleum refining MAIN OPTIONS FOR PRODUCTION, TRANSPORT AND STORAGE OF HYDROGEN a prominent role in a future energy system. As far (25%), and for methanol production (10%). The

back as 1874, the author Jules Verne had a character energy required to produce 55 Mtpa H2 represents in his novel The Mysterious Island declare: “I believe about 3% of the global energy demand. Hydrogen HYDROGEN PRODUCTION OPTIONS that water will one day be employed as fuel, that production is therefore a large and thriving industry. hydrogen and oxygen which constitute it, used SOURCE oer aer ara gas oa ioass singly or together, will furnish an inexhaustible Hydrogen as an energy carrier source of heat and light, of an intensity of which Today, we are witnessing a revival of interest around coal is not capable.” prospective uses of hydrogen as an energy carrier, in HYDROGEN Gasification or which it is used as a fuel rather than as a feedstock. ecroysis eoring Gasification PRODUCTION iogas reoring This may be attributed mainly to the potential role HYDROGEN: THE CRUX OF THE DEBATE of hydrogen in global efforts to decarbonize. The main question addressed in this position paper is for DECARBONIZATION ocaron aron care aron care one nera On Earth, hydrogen is found only as part of a which applications, and under what circumstances, MEASURE eecriciy and sorage and sorage negaie compound, most commonly in the form of water can hydrogen emerge as a major energy carrier? To but also in, for instance, hydrocarbons such as answer this, we focus on the cost effectiveness of TRANSPORTATION STATE OF TRANSPORT STORAGE methane, gasoline and coal. decarbonization through using H2 as a fuel; i.e. we OPTIONS AND STORAGE OPTIONS ask when a fuel switch to H2 can be competitive To enable water to be part of Jules Verne’s energy with alternative decarbonization options. The main srace gas ieine utopia, hydrogen must temporarily be released applications considered are: sorage from its bond with oxygen. Similarly, it can be extracted from hydrocarbons through its separation ■■Hydrogen as fuel for mobility; oressed oressed from carbon, e.g. in the form of coal or natural gas. ■■Hydrogen for heating in buildings; rc ■■Hydrogen for decarbonization of ydrogen ydrogen ans This separation process requires energy, and the industrial processes; and, energy content of the output hydrogen is always ■■Hydrogen for valorization of excess electricity ieine i less than the energy content of the input fuel, plus from variable renewable power. inrasrcre the energy required for the hydrogen separation. This paper aims to raise understanding of the

Furthermore, hydrogen is generally more energy benefits and disadvantages of 2H for these ryogenic iid iid ydrogen intensive to store and transport than other applications, describe the circumstances required ydrogen ans conventional fuels. This implies that the value of for them to materialize, and to provide a basis for hydrogen in pure form to users or to society at analysing the scale of uptake. Accordingly, we have large must be sufficient to justify the energy losses also developed ExplEnergy, a web application for aiarge onia onia ans in its production, distribution and use. economic assessment of energy value chains.

This App can estimate the cost of various H2 This is the crux of the debate over hydrogen. production paths and associated transport and iid organic iid ydrocaron storage options. Appendix A provides a brief ydrogen carrier ans introduction to ExplEnergy. Figure 1: Overview of main options for production, transport and storage of hydrogen. Source: DNV GL 8 Hydrogen as an energy carrier Introduction 9

2.1.1 Production 2.1.2 Transport and storage Ammonia and liquid organic hydrogen carrier (LOHC) Ammonia has a higher energy density per volume Hydrogen can be produced in several ways, as shown in Figure 1. However, the primary driver for uptake of Hydrogen can be transported and stored in pure than liquid hydrogen, and can be stored and hydrogen as an energy carrier is decarbonization. This implies that emphasis will be placed on producing form or as an intermediate energy carrier that can transported as a liquid at low pressures or in

hydrogen in ways that allow hydrogen value chains to have a lower carbon footprint than alternative be charged and de-charged with H2, processes cryogenic tanks at around -33°C at 1 bar. This implies competing energy value chains, including alternative hydrogen value chains. referred to as hydrogenation and dehydrogenation that ammonia can be transported at low cost by respectively. Figure 1 on page 7 displays four pipelines, ships, trucks and other bulk modes. Hydrogen produced by gas reforming without carbon capture and storage (CCS), the most common method alternative states: The caveat is that the ammonia synthesis and its

today, has a carbon footprint of about 10–12 kgCO2e per kg hydrogen. Hydrogen can be produced from subsequent dehydrogenation to release hydrogen

electrolysis with a lower carbon footprint if the electricity used has a carbon footprint less than 250 kgCO2e/ ■■Liquid (cryogenic) hydrogen require significant energy. Hydrogenation and MWh, roughly 55% of the emission intensity of a modern combined cycle natural gas-fired power plant(6). ■■Ammonia dehydrogenation of a LOHC, such as toluene, ■■Hydrogenated liquid organic hydrogen carrier requires less energy, but the gravimetric density ■■Compressed gaseous hydrogen. of the hydrogen that can be extracted from the hydrogenated liquid (methylcyclohexane for the GREEN AND BLUE HYDROGEN The preferred or lowest-cost option for transport LOHC toluene) is 50%–70% lower than the and storage will depend on the state. gravimetric hydrogen density of ammonia.

Hydrogen produced by electrolysis or from biomass with emissions less than 8 kgCO2e /kgH2, based on a lifecycle analysis, will henceforth be called green hydrogen(i) in this paper. This can be explored by using the ExplEnergy web Pipeline hydrogen gas application described in Appendix A, which also sets Pipeline transport of compressed gaseous hydrogen We use blue hydrogen to refer to that produced from fossil fuels with CCS. Hydrogen produced from out some example comparisons. is in general the most cost-effective way of transporting

fossil fuels with CO2 capture, where the CO2 is used for enhancing oil recovery, does not qualify large volumes of it over long distances. This can as blue hydrogen. Liquid hydrogen be done in pure form, or blended into natural gas For instance, while liquid hydrogen has a higher in gas pipelines, up to limits prescribed by the Production of blue hydrogen is less modular than for green hydrogen, represents a major investment, energy density than compressed hydrogen, more relevant regulations or imposed by contract or other and has longer lead times than green hydrogen production. In addition to building the hydrogen energy is required to liquefy hydrogen than for restrictions. Small volumes, such as those required

production and CO2-capture facility, blue hydrogen production requires a permit for injection and compressing it to relevant pressures. today at hydrogen fuelling stations, would generally

storage of CO2 into a qualified site for geological storage of CO2. Getting this permit can take 3–10 years, be most cost-effectively transported in bulk by truck. depending on site characteristics. It is therefore likely that investments into large-scale blue hydrogen Furthermore, liquid hydrogen has different safety production towards 2030 will be made only as part of government-supported initiatives. characteristics than compressed gaseous hydrogen. These considerations, along with those regarding For example, a leak into open air from compressed selection of production method, show that the hydrogen tanks will rise due to buoyancy, and will lowest cost or preferred value chain depends on the generally dissipate quickly. In contrast, a leak of application and context. No single solution would Hydrogen production method will depend In contrast, we expect that hydrogen used for liquid hydrogen into open air will freeze the be equally applicable in all circumstances. This is the on application transport before 2030 will predominantly be green surrounding air, become a heavy gas, and may rationale for developing the ExplEnergy web We argue further that the preferred production hydrogen. This is due to several factors, including accumulate on the ground for some time. This is application, which allows users to configure and method for a given application will depend greater consumer pressure for a non-fossil hydrogen relevant when, for instance, transporting hydrogen compare alternative energy value chains under

on context. source and the capability to develop on-site H2 either by ship or truck, or when storing it in tanks. circumstances relevant to the case being considered. production by electrolysis, thereby avoiding the For instance, we argue that hydrogen used for need for its transport. heating in buildings will predominantly be blue hydrogen for two reasons: Fuelling stations will seek to secure certified green hydrogen. This will, in turn, make producers certify

■■The main driver for this application is that the H2 is produced from renewables. This can be decarbonization of gas-based heating. achieved through power purchase agreements or the A gas infrastructure that can be repurposed or purchase of green electricity certificates, for example. upgraded for hydrogen will therefore often exist where this application is relevant. ■■Electric heating is much more efficient than the power-to-hydrogen-to-heat value chain, particularly if heat pumps are used. This implies that it would generally be much cheaper to use electric heating rather than hydrogen produced from electricity.

(i) This is in accordance with TÜV SÜD Standard CMS 70 (Version 12/2011) — Generation of green hydrogen, which states that “A certificate for green hydrogen can be issued if the greenhouse gas reduction potential is at least 35% compared to fossil fuels or conventionally produced hydrogen”. 10 Hydrogen as an energy carrier Introduction 11

2.2 Decarbonization context renewable energy sources, nuclear, or gas- or When used as an energy carrier, hydrogen can ■■Power generation: coal-fired power with CCS. support decarbonization of buildings, transport, - Decarbonize electricity generation source, e.g. Figure 2 shows carbon emissions for 2010 by industry and power generation, provided that the by replacing a fossil fuel-fired plant with turbines (i) economic sector . The current production of It can be noted that CCS on industrial-scale production, storage and distribution of hydrogen fired by 2H , or by H2 fuel-cell systems. hydrogen represents approximately 0.5 Gt of direct hydrogen production has been demonstrated. Two comes with a low carbon footprint. The principal - Pave the way for greater penetration of carbon emissions (not including indirect emissions large-scale projects — Air Products’ steam methane means to achieve this are: renewables by providing an effective way of from electricity consumption, or upstream emissions reforming (SMR) plants at Port Arthur, Texas, US, valorizing (and storing) surplus power from from production of fossil fuels). This represents about and Shell’s oilsands upgrader in Scotford, Alberta, ■■Buildings: Replace natural gas used for heating variable renewables, i.e. excess electricity during 5% of total direct industry carbon emissions. Canada — and one demonstration project in Japan (boilers, gas fires and cookers) with hydrogen. periods when production output from variable are currently in operation. ■■Transport: Replace internal combustion engines renewables alone exceeds demand. These emissions can be reduced by capturing with fuel cells and electric drivetrains(ii).

and storing the direct emissions from the hydrogen The scale and cost advantage of H2 production from ■■Industry: Replace fossil fuel for medium and high Section 3 will discuss and analyse the circumstances production unit, or through fuel switching, i.e. by fossil fuels today suggest that a major fraction of heat production (by combustion) with hydrogen. required for each of these applications to scale. replacing the fossil feedstock with biomass, or by hydrogen production will continue to be produced producing hydrogen from water and electricity (by from fossil fuels in the near term, requiring CCS to electrolysis), where the electricity comes from achieve decarbonization.

GREENHOUSE GAS EMISSIONS IN 2010 BY ECONOMIC SECTOR

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Figure 2: Greenhouse gas emissions in 2010 by economic sector. Source: IPCC(5). © Shutterstock

Hydrogen can valorize and store surplus power from variable renewable electricity sources such as wind. Photo: Shutterstock.

(i) PBL Netherlands Environmental Assessment Agency and the European Commission’s Joint Research Centre (JRC) issued in 2017 an (7) updated dataset estimating global GHG emissions in 2010 to have been 46.1 GtCO2e, and to have risen 7% to 49.3 GtCO2e in 2016 . The estimates are based on production data from the Emissions Database for Global Atmospheric Research (EDGAR) developed (ii) As discussed in Section 3.3.2, the lifecycle carbon emissions of fuel-cell electric vehicles are about 30% lower than for internal jointly by PBL and JRC. combustion-engine vehicles, and comparable to the lifecycle carbon emissions of battery electric vehicles. 12 Hydrogen as an energy carrier Hydrogen applications 13

3. HYDROGEN APPLICATIONS

3.1 Heating in buildings This transformation will require mechanisms that can Approximately 85% of energy consumption, 74 PJ These emissions from heating buildings can be cater for greater variability in electricity production. in 2010, in the residential sector is from heating mitigated by the following options: Buildings account for about a third of global final The role of hydrogen as a potential medium to and cooking. For commercial buildings, heating energy use, and about one fifth of greenhouse gas valorize electricity during periods where the output represents 45% of the energy consumption, 14 PJ 1. Energy-efficiency measures, such as (GHG) emissions(5). This implies that energy efficiency from variable renewable energy sources (VRES) in 2010 (Figure 4). improved insulation. measures and options to decarbonize building exceeds the demand for it will be addressed 2. Fuel switching to electricity or biomass energy consumption are of critical importance in in Section 3.2. Using these percentages, we estimate that (if electricity-to-heat or biomass-to-heat energy worldwide efforts to reduce GHG emissions. direct emissions from heating in residential and value chains have lower carbon footprints than The current section considers hydrogen’s commercial buildings in 2010 were about gas-to-heat energy value chains).

Indirect emissions from electricity used in potential to reduce direct GHG emissions, which 2.2 GtCO2e/yr. 3. Using hydrogen gas with a low carbon footprint buildings represent about two-thirds of their in 2010 accounted for 6.4% of global GHG instead of natural gas to fuel boilers, cookers, (5) emissions. Achieving significant cuts in these emissions, or 3.2 GtCO2e/yr . Figure 3 shows Many countries with cold winters rely on natural gas fires and/or residential fuel cells. emissions requires a fundamental transformation that residential and commercial buildings account gas for heating(2), and a major component in the 4. Heat networks and geothermal. of the power sector, in which increased use of solar for 69% and 26% respectively of these emissions. direct emissions from buildings stems from 5. Use of biogas, bio-SNG or methane produced photovoltaic (PV) and wind will have a pivotal role. combustion of this gas. from green hydrogen.

BREAKDOWN OF ENERGY USE IN BUILDINGS BY APPLICATION GREENHOUSE GAS EMISSIONS IN 2010 BY ECONOMIC SECTOR Residential Commercial

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Figure 3: Greenhouse gas emissions from buildings. Source IPCC(5). Figure 4: Breakdown of energy use in buildings by use. Source: IPCC(5). 14 Hydrogen as an energy carrier Hydrogen applications 15

The preferred option, or mix of options, among has been studied extensively for one or more 3.1.1 What investments are needed to switch from natural gas to hydrogen? these alternatives will depend on country concrete projects, and that possible storage sites circumstances and policy context, such as existing have been identified. The deployment of hydrogen for heating implies significant investment, and will require substantial policy gas infrastructure, electricity mix, and national push and public co-funding to materialize. This applies particularly to the development of a fit-for-purpose emission targets. Option 3 involving a partial In this analysis, we assume that Conditions 1 and 2 hydrogen pipeline infrastructure, and the conversion of heating and cooking appliances. switch from natural gas to hydrogen gas can be are met if gas provides at least 40% of the energy a particularly cost-effective option in countries input to space heating. For countries that meet this where the following conditions are present: criterion, we also assume that gas provides a similar share of energy input to cooking and water heating, CONVERTING A CITY TO HYDROGEN 1. Gas-based heating represents a significant and that energy consumption for the heating fraction of the country’s building energy use(i). applications shown in Figure 4 is representative for The Leeds City Gate project, proposing how to convert the UK city's gas supply from natural gas to 2. Fuel switching from gas to electricity requires a nations with high gas consumption for heating. hydrogen with a proposed extension to the North of England, illustrates the required scale and scope of substantial scale-up (e.g. more than doubling) of infrastructure investment for deploying hydrogen for heating. electricity generation capacity, and significant Figure 5 depicts the gas consumption for space investments in associated infrastructure. heating and the respective CCS readiness. Gas It assumes(8) that the hydrogen will come from steam methane reforming (SMR), and that it will be stored

3. There is medium or high carbon capture and provides more than half of total energy input to in salt caverns. The project envisages a new built-for-purpose 40 bar H2 transmission pipeline, and a new (ii) storage (CCS) readiness . ‘Medium CCS space heating in only seven countries, of which five built-for-purpose 17 bar H2 transmission ring around Leeds. It proposes conversion of the medium- and readiness’ is when at least one medium- to have medium or high CCS readiness. This implies low-pressure gas distribution system to hydrogen; replacing boilers, cookers and gas fires in residential large-scale, full-chain project has progressed that circumstances promoting a fuel switch from buildings; and, replacing or converting gas appliances in commercial and public buildings. through early development stages, and no natural gas to hydrogen gas for decarbonization of major barriers to near-term deployment exist. heating is present in only a handful of countries, with Driven by the need to decarbonize heating in buildings for the UK to meet its pledges under the COP 21 ‘High CCS readiness’ indicates large-scale CCS Australia, Canada, the Netherlands, South Korea, UK Paris Agreement, the Leeds City Gate project receives government funding. operations in the country, or that the technology and US having the most favourable circumstances.

While the proposed change to H2 may be cost effective compared with electrification, Leeds City Gate requires businesses and residents to commit to changing heating appliances. This will be difficult to SPACE HEATING SHARE OF BUILDING ENERGY DEMAND achieve without governments leading and funding processes for changing all gas-based heating VERSUS GAS SHARE OF ENERGY INPUT TO HEATING appliances(iii). The same challenge would, however, apply for the alternative option, to electrify heating, as this would require significant upgrading and reinforcement of the power grid, and installation of new electric heating appliances. s shre o eer ut to sce het h S reess Read more on Leeds City Gate at: https://www.northerngasnetworks.co.uk eu S reess o S reess

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3.2 Electricity valorization

The production of hydrogen gas from renewable electricity through electrolysis has a very low carbon footprint since there are virtually zero GHG emissions during operations. Such hydrogen production is t South ore promoted as a clean and cost-effective way to valorize excess electricity generation from variable renewables, and thereby enable greater fractions of renewables, principally solar PV and wind, in the electricity mix. ustr ethers Hydrogen is also promoted as a medium for longer-term (e.g. seasonal) storage of electricity, suggesting that er eu it will later be used to generate electricity during periods of high electricity prices. Such storage of hydrogen would take place in salt caverns, or depleted oil or gas fields. rce

S uss In this section, we will test the following three main assumptions regarding the applications above:

1. Green hydrogen can be produced cost effectively. 2. Hydrogen production by electrolysis has a low carbon footprint. Sce het shre o u eer e 3. Hydrogen is a cost-effective medium for longer-term storage of electricity.

Figure 5: Plot of gas share of energy input to space heating versus space heating share of building energy demand. The size of each bubble represents the size of the country’s total energy demand. Source: Hydrogen Council(2). Graphic: DNV GL

(i) It is assumed that countries that meet this condition also have a well-developed gas infrastructure, including gas storage sites. (ii) This reflects the assumption that the hydrogen will generally be produced by gas reforming with CCS, which may have a lower carbon footprint than hydrogen produced through electrolysis. Production of hydrogen by electrolysis is not considered since this counters Condition 2, i.e. that one of the main arguments for the use of hydrogen for heating is to avoid upscaling of the electricity generation capacity. (iii) This represented more than 50% of the capital expenditure for the proposed conversion of Leeds in the H21 Leeds City Gate project(8). 16 Hydrogen as an energy carrier Hydrogen applications 17

3.2.1 Can green hydrogen be produced hydrogen production cost would be about USD60/ CALIFORNIA 2016: COST OF HYDROGEN FROM ELECTROLYSIS cost effectively? MWh, or USD2/kg. We also see that a further reduction in the cost of hydrogen can be obtained rice curve COH Guaranteed green hydrogen can be produced by continuing to produce hydrogen up to about Estimated COH from inimal H price electrolysis in two ways: 4,100 load hours. This is because the annuity 2 SR without CCS payments on the capital expenditure (CAPEX) per kg Optimal load 1. By physically connecting production to specific of hydrogen decrease with increasing load factor.

sources, such as a local solar farm or wind park. Producing hydrogen for more than 4,100 load hours 2. By sourcing electricity from the grid and results in a slight increase in its cost as increasing S/Wh purchasing real-time green electricity electricity costs outweighs the reduction in annuity 2

certificates or establishing real-time power payments per kg. We note also that the lowest purchase agreements. achievable cost of hydrogen production in California in 2016 was still almost twice the cost of producing In case 1 above, the hydrogen production will be hydrogen by SMR. variable, with periods of little or no production.

This implies that the electrolyser will not operate Figure 6 also projects a significant fall in the cost of continuously at full load, and that storage of producing hydrogen by electrolysis from 2016 to hydrogen will generally be required to balance 2030, for two main reasons: supply and demand of hydrogen, unless the H per unit of from Cost energy hydrogen produced is fed into a hydrogen market ■■The electricity cost in the lower end of the price where the balance of supply and demand is met by curve will drop significantly. This is due mainly to a Hours of production other mechanisms. higher fraction of electricity from renewables with e S cro cture store hroe eee cost o hroe zero marginal cost. h ett hours S ste ethe reor Source A cost analysis of hydrogen from electrolysis ■■The CAPEX for the electrolysers is expected to We do not account for the cost of storage in the reduce by more than 30%(9). This has a double CALIFORNIA 2030: COST OF HYDROGEN FROM ELECTROLYSIS analysis that follows, which looks at only the impact: the annuity payments fall and the optimal production. We examine the cost of hydrogen from load factor decreases. rice curve COH electrolysis as a function of the load factor for the Estimated COH from inimal H electrolyser. To this end, we do not enforce the We see that the minimum cost of hydrogen has 2 price electrolysis SR without CCS constraint that hydrogen is produced only from dropped from just above USD50/MWh to less than Optimal load

zero-carbon power. We assume instead that USD30/MWh (from USD1.7/kgH2 to USD1.0/kgH2) hydrogen production occurs only during the hours from 2016 to 2030, with the load factor reducing of the year with lowest electricity price. Since solar PV from 47% to 37%. This implies that hydrogen and wind have no fuel cost, the marginal electricity production by electrolysis can be cost competitive S/Wh generation cost for these technologies is zero. with gas reforming in 2030. We also note that zero 2

marginal cost technologies (renewables) account Figure 6 illustrates DNV GL’s analysis of the cost of for all electricity generation for a few hundred load producing hydrogen from electrolysis in California hours. If hydrogen is produced only during these in 2016 and 2030. The orange curve is a conceptual hours, then the corresponding hydrogen cost will be electricity price curve, indicating the cost of electricity very high. We conclude therefore that in California it

generation. For instance, Figure 6 indicates that the will not be cost effective in 2030 to produce electricity generation cost was less than USD20 for hydrogen only during hours with surplus generation 2,000 hours of 2016. If hydrogen was produced from from renewables, unless there is a significant carbon electrolysis only during these hours of 2016, then the price that penalizes non-green hydrogen production. H per unit of from Cost energy Hours of production

e S cro cture store hroe eee cost o hroe h ett hours S ste ethe reor

Figure 6: Cost of H2 production by electrolysis in California in 2016 (top) and 2030 (bottom). The orange line is a smoothed merit-order curve representing the cost of producing electricity hour-by-hour from lowest to highest production cost. The solid grey line shows the LCOH if the electrolysers operate only during hours with a lower USD/MWh cost than for the corresponding point on the orange curve. Dashed grey line shows the estimated LCOH from SMR without CCS. Source: DNV GL. 18 Hydrogen as an energy carrier Hydrogen applications 19

3.2.2 How clean is hydrogen production by electrolysis? CARBON FOOTPRINTS OF FOUR HYDROGEN PRODUCTION OPTIONS

The analysis in the previous section shows that the cost of producing hydrogen is generally reduced by increasing the operating hours of electrolysers beyond the number of hours with surplus production from variable renewables. We assume therefore that electricity from other sources is also used to produce SR: ste ethe reor CCS: cro cture store hydrogen. The carbon footprint of the produced H2 will then depend on the carbon footprint of the electricity mix. This may be the real mix in the regional electricity system. 2 e/kgH A producer of hydrogen can secure a green electricity mix through real-time power purchase agreements or, 2 for instance, real-time green certificates.

The developer will then use the contracted electricity mix as a basis for computing the carbon intensity of produced hydrogen. The carbon intensity of this mix will generally be different from the carbon intensity of the electricity mix in the regional power system.

Emissions kgCO

POWER GENERATION TYPE IMPACTS ON THE CARBON FOOTPRINT OF HYDROGEN PRODUCTION SR CCS Coal gasification Electrolysis Biomass gasification The IEA World Energy Outlook 2013 estimates that the carbon footprint of electricity production in 2011 was (3) 532 kgCO2e/MWh globally, and 345 kgCO2e/MWh in Europe . The carbon footprint of electricity generation tur s roucto S S to oer roucto oss roucto roucto technologies ranges from about 5–20 kgCO2e/MWh for wind power and hydropower and 20–50 kgCO2e/ (6) MWh for solar PV, to more than 800 kgCO2e/MWh for electricity from coal-fired power plants . S S to Coal gasification oer to Biomass gasification

S to to In the current analysis, we assume that the electrolyser has an efficiency of 67% based on the lower ectross ro eectrct th cro ootrt o keh heating value (LHV) of hydrogen(i). We also disregard the carbon footprint of the production, delivery and ** Biomass gasification without CCS decommissioning of the electrolyser plant. The carbon footprint of hydrogen production by electrolysis is

then 0.05 kgCO2e/kgH2 for every kgCO2e/MWh in the carbon footprint of the electricity mix used. Figure 7: Carbon footprint per kgH2 of four hydrogen production options: SMR + CCS; coal gasification with CCS;

electrolysis from an electricity mix with a carbon footprint of 180 kgCO2e/MWh; and biomass gasification without CCS.

Thus, hydrogen produced from a coal-dominated electricity mix may have a carbon footprint of more than The carbon footprint does not include emissions from the construction and decommissioning of the H2 production

40 kgCO2e/kgH2, whereas the carbon footprint of hydrogen produced from wind power or hydropower facilities. Graphic: DNV GL.

can be less than 1 kgCO2e/kgH2.

3.2.3 Will hydrogen be used for peak shaving? that cannot be sold, stored, or otherwise valorized

Comparing the carbon footprints of hydrogen would need to be as low as 75 kgCO2e/MWh. Hence, is currently curtailed. This implies that the value of production methods it would have to be produced predominantly from A current lack of economically viable options to store the excess generation capacity is lost. Hydrogen For comparison, note that Figure 7 on page 19 nuclear and/or renewables. large quantities of electricity limits the scale-up of production has therefore been proposed as an shows the emissions profile of four different generation from solar PV and wind. This need arises attractive option to valorize the electricity. The hydrogen production options. From this, we observe Although green hydrogen can be produced with a when more electricity than is required to meet economics of this was discussed previously in that even though the electricity mix has a carbon very low carbon footprint, we note that the use of demand can be generated from VRES alone, Section 3.2.1. (ii) footprint of 180 kgCO2e/MWh , the carbon footprint electricity from VRES for hydrogen production may principally solar PV and wind. This situation typically

of production by electrolysis is more than twice that displace the use of green electricity in the rest of the starts to arise for shorter periods when VRES account We further argue that H2 can be a medium for storing

of the other options. electricity system. This implies that reductions in for about 25–30% of energy base in the annual electricity, implying that H2 produced from electricity carbon emissions from production and use of green electricity mix. The duration and frequency of these will later be converted back. While this is possible, To beat SMR with CCS, assuming about 87% carbon hydrogen can potentially be offset by an increase periods increase as this percentage rises. the roundtrip electrical efficiency is low, typically capture, the GHG footprint of the electricity mix (or slower decrease) in power sector emissions. about 40%. This implies that the final electricity Because electricity generation must be in balance output from this value chain has a very high cost

with the demand, and limited options for storage of per MWh. Electricity generation from H2 will, in large volumes of electricity exist, any excess general, be applied only when the electricity price generation potential from variable renewables exceeds this cost.

(i) The LHV is determined by subtracting the heat of vaporization of the water from the higher heating value (HHV). The energy required to vaporize the water therefore is not released as heat. The HHV (or gross calorific value) is determined by bringing all the products of combustion back to the original pre-combustion temperature, and condensing any vapour produced(10). (ii) This is equivalent to a third of the global average in 2011, and half the average in Europe in 2011(2). 20 Hydrogen as an energy carrier Hydrogen applications 21

(i) A caveat with the use of H2 for peak shaving is that it for longer-duration storage of electricity . Note that 3.3 Mobility decarbonization potential of battery electric vehicles requires fuel cells or turbines with adequate capacity pumped hydro and subsurface hydrogen storage (BEVs) and fuel-cell electric vehicles (FCEVs) in the for short-term production. If these systems are used require availability of hydropower reservoirs and The main drivers for use of hydrogen as a transport road transportation segment in Section 3.3.3. This only for peak shaving, then the low capacity factor suitable subsurface formations. Such availability fuel are reduction of tail-pipe pollution and lowering segment accounts for more than 70% of global GHG implies very high cost contribution from CAPEX per varies by region. of carbon emissions. We will examine the emissions in the transportation sector (see Figure 9). MWh generated. Sufficiently low CAPEX may thus be

a precondition for the use of H2 for peak shaving. The We assume that the hydrogen is stored in a business case depends then on expensive capacity subsurface salt cavern, and that the amount of GREENHOUSE GAS EMISSIONS BY TRANSPORTATION SEGMENT in hydrogen power generation systems that can be electricity stored corresponds to 10 days of deployed on-demand. production. The lifetime of the pumped hydro system is assumed to be 80 years, whereas the ot rect rect rect essos ro eectrct eerto tot rect Figure 8 compares the cost of electricity from lifetime of the electrolyser and H2 fuel cell and o hydrogen with the cost of electricity stored by turbine is 20 years. The input electricity cost pumped hydro. This is the main alternative option is USD36/MWh. ee etc

Hydrofluorocarbons and indirect N

e/yr terto to ot rect rect 2 tot rect COST OF ELECTRICITY FROM ELECTRICITY STORAGE FOR THREE ENERGY VALUE CHAINS oestc to terto cost sh Domestic waterborne H topower CE/GT/CCGT 2 ot rect rect H topower fuel cell tot rect 2 Subsurface hydrogen storage

owertoH2 umped hydro Electricity from grid

Greenhouse gas emissions GtCO Greenhouse

Cost of S/Wh ofCost energy electricity umped hydro 2 fuel cell 2 turbine

Details of energy value chains Figure 9: Greenhouse gas emissions by transportation segment. Graphic: IPCC(5) * Roundtrip greenfield pumped hydro ** P2P fuel cell: Electrolysis, hydrogen storage in salt cavern, and a hydrogen fuel-cell system *** P2P turbine: Electrolysis, hydrogen storage in salt cavern, and hydrogen gas turbine

Figure 8: Cost of electricity from electricity storage for three energy value chains: roundtrip greenfield pumped hydro; electrolysis, hydrogen storage in salt cavern, and hydrogen gas turbine; and, electrolysis, hydrogen storage in salt cavern, and a hydrogen fuel-cell system. Graphic: DNV GL

Despite the much lower energy loss from pumped Finally, Figure 8 shows that the hydrogen P2P hydro than for the two power-to-hydrogen-to-power systems add about USD120–130/MWh to the input

(P2P) value chains, we note from Figure 8 that electricity cost. This gap suggests that H2 can electricity storage by pumped hydro has a higher cost. potentially be used for peak shaving if the electricity This is due to the much higher CAPEX of pumped price is significantly above the electricity price used hydro than the P2P options. We also note that the gas to produce hydrogen. turbine option has a lower cost than the fuel-cell option, despite the latter’s higher efficiency. Again, this is due principally to the much higher CAPEX per energy unit for the fuel-cell system.

(i) Subsurface storage of natural gas is a way to buffer electricity generation, since electricity can later be produced from this gas in gas-fired power plants; but this is not storage per se since the gas is not produced from excess electricity. 22 Hydrogen as an energy carrier Hydrogen applications 23

Although the driver for deployment of H2 fuel cells ■■Range — FCEVs have longer range; and, 3.3.1 Cost of FCEVs compared to BEVs FUEL COST PER 100 KM IN 2015 AND 2030 and battery electric powertrains is by and large the ■■Charging/fuelling infrastructure availability — and ICEVs same, they have different characteristics that under development, depends on region. ue costs S k suggests that preferences, battery or fuel cell, FCEV capital costs are today higher than for will vary by both application and region. Key These differences indicate that we should expect equivalent BEVs and internal combustion engine ue costs S k differences include: to see a greater preference towards FCEVs for vehicles (ICEVs). However, fuel-cell capacity and large-vehicle segments requiring long range or hydrogen tanks come increasingly at lower cost ■■Fuel cost — BEVs have lower fuel cost with heavy loads. Indeed, Figure 10 adapted from than adding battery capacity. (2) (see Section 3.3.1); Hydrogen Council source material illustrates that H2 Gas reforming ■■Fuelling/recharging time — FCEVs have shorter fuel cells will see the highest uptake in the large cars, In 2030, the breakeven point for vehicle CAPEX is fuelling times; trucks and buses segments of road transportation. predicted to be at about 55 kWh battery capacity(2). FCEV ■■Volume — the space for the H2 tank and fuel cell This is equivalent to the battery capacity of high-end combined is less than that for BEV batteries with Fuel-cell engines are also an attractive BEVs on the market today, such as the Chevrolet Electrolysis equivalent output; decarbonization option for trams and railways, Bolt/Opel Ampera-e, Hyundai KONA, Tesla Model 3, ■■Weight — fuel cells and hydrogen tanks weigh but the replacement cycle is longer than in the and the low-end battery options for the Tesla less than BEV batteries; vehicle segment. Model S and Model X. S The fuel costs of FCEVs are also higher today than PROJECTED DEPLOYMENT OF HYDROGEN FUEL CELLS BY TRANSPORTATION SEGMENT IN 2050 for BEVs and ICEVs (Figure 11). While FCEVs cannot compete with BEVs in this regard due to greater China EV efficiency loss(i), the retail cost of hydrogen is set to drop significantly with the developing hydrogen infrastructure, and lower costs of hydrogen Europe production by electrolysis.

For instance, cost analysis performed by the

k International Council for Clean Transportation S (ICCT)(12) assumes the hydrogen retail price will drop from USD12/kg today to USD4–7/kg in 2030. In addition, improved fuel-cell efficiency is rs rs eu uses coches expected by 2030 to reduce hydrogen China (2)

heut trucks consumption by 20–35% per km travelled . diesel CEV This compares to projected fuel-efficiency (2) improvements for ICEVs of 6–12% by then . Europe Range requirement Range Consequently, FCEVs are expected to have lower fuel costs per km than ICEVs in 2030 (Figure 11).

Figure 11: Comparison of fuel costs for FCEVs, BEVs and ICEVs in 2015 and 2030. The fuel efficiency of a new C-segment compact car is assumed, i.e. 4.1 litres of diesel/100 km for an ICEV and 13 kWh/100 km for BEVs and FCEVs. The electricity-to-wheel efficiency is assumed to S crs re crs s s be 80% for BEVs(11). Fuel costs are from Table A6 in an ICCT s trucks analysis(12) and include taxes (hydrogen prices are in USD per gallon of diesel equivalents). Hydrogen FCEVs as % of total fleet for each vehicle type in 2050

Figure 10: Projected stock in 2050 of hydrogen fuel-cell electric vehicles as percentage of total fleet at year end by vehicle type. Source: Hydrogen Council(2).

(i) The tank-to-wheel efficiency may be 30–45% for FCEV and 67–81% for BEV(11). If the hydrogen is produced from electricity, then the electricity-to-wheel efficiency for FCEV is 20–30%. This implies that 3 kWh input is used by a FCEV for every kWh used by a BEV. A similar gas-to-wheel efficiency is achieved if the hydrogen is produced by gas reforming with CCS. Similarly, the gas-to-wheel efficiency of BEV (electricity produced from natural gas) would be some 30–40%, so that only 1.5 kWh is used in a FCEV for every kWh used in a BEV. 24 Hydrogen as an energy carrier Hydrogen applications 25

For passenger cars, it is expected that the total cost Europe is not shown since this is almost identical to 3.3.2 Emission intensity of FCEVs compared We similarly compare the lifecycle emissions of an of ownership (TCO)(i) will in 2030 remain lower for the curve for the US. with BEVs and ICEVs FCEV assuming that the hydrogen is produced

ICEVs than for FCEVs. For some heavy vehicle with a carbon footprint of 4 or 12 kgCO2e/kgH2, segments, we may see the TCO for FCEVs equal Hydrogen fuel costs for the results shown in Here we compare the lifecycle emissions of FCEVs corresponding to hydrogen produced by SMR the equivalent cost for ICEVs before 2030. This can Figure 12 are based on data in an ICCT table on with those of gasoline and diesel ICEVs, and with with and without CCS respectively. be attributed to the higher mileage and fuel hydrogen from renewable pathways(12). This cost is BEVs under two different assumptions:

consumption, giving fuel costs a greater 60% above the same study's projected cost of A carbon footprint less than 4 kgCO2e/kgH2 may contribution to the TCO. hydrogen from natural gas in 2030(ii). 1. The BEV, including its battery, is manufactured be achieved with coal gasification and CCS, with using only renewable electricity, or from an biomass gasification, and by electrolysis using Figure 12 compares the TCO of ICEV diesel and Since fuel costs for FCEV tractor-trailers generally electricity mix with an equivalent carbon electricity with a lower carbon footprint than

FCEV tractor-trailers over the first year following represent more than 50% of the TCO, the use of footprint; and 80 kgCO2e/MWh. the vehicles' purchase in 2015, 2020, 2025 and hydrogen from natural gas could lower the TCO of 2. The BEV is manufactured using an electricity

2030 in the US, China and the current (2018) 28 FCEV tractor-trailers in 2030 by more than 30%. It mix with a carbon footprint of 345 kgCO2e/MWh, The results shown in Figure 13 illustrate the European Union member states (EU-28). The data should be noted, however, that the TCO alone is not which corresponds to that of the European per-km lifecycle emissions of FCEVs under these for these calculations is sourced from the ICCT(12). decisive; other factors also play into customers’ electricity mix in 2011(3). assumptions compared with lifecycle emissions The curve for the TCO of FCEV tractor-trailers in car preferences. of ICEVs and BEVs. The electricity used for charging the BEV is assumed to come from an electricity mix with a carbon

footprint of 345 kgCO2e/MWh. COST OF OWNERSHIP: FCEV TRACTOR-TRAILERS IN YEAR 1 (USD/100 KM)

LIFECYCLE GHG EMISSIONS BY VEHICLE TYPE 129.0

113.3 108.7

98.2 95.0 93.5 91.8 89.9 80.8 77.6 75.7 70.7 71.9 70.8 65.3 63.665.0 emissions g/km 59.1 59.4 2

50.4 CO

er er er er Gasoline iesel FCEV ow FCEV SR EV Green EV i Tanktowheel S ese S h ese h ese Welltotank

Car manufacturing Figure 12: Cost of ownership of FCEV tractor-trailers in the first year after purchase in the US, China and the EU-28. The attery and FC manufacturing total tractor-trailer capital cost is amortized over 10 years at a 10% interest rate. The maintenance and repair costs are USD0.12/km and USD0.11/km for diesel and fuel-cell tractor-trailers respectively. The distance travelled in the first year ue ce after purchase is from Table A4 in the ICCT's 2017 analysis(12). Source: DNV GL

Figure 13: Lifecycle CO2 emission intensity (g/km) for gasoline, diesel, FCEV and BEV versions of a C-segment compact car with fuel efficiencies of 4.1 litres per 100 km for diesel, 4.8 l/100 km for gasoline, and 13 kWh/100 km for BEV and FCEV. The tank-to-wheel efficiency is assumed to be 80% for the BEV and 40% for the FCEV(13). Emissions from recycling and disposal are not included. The vehicle is assumed to have 120,000 km lifetime. Source: DNV GL from Hydrogen Council data(2).

(i) Total cost of ownership (TCO) is a financial estimate of all direct and indirect ownership costs of a product or system. For vehicles it includes depreciation of vehicle purchase cost or leasing cost, and running costs such as fuel, parking, insurance, repair and maintenance. (ii) These are fuel costs at pump, and include taxes and tariffs associated with transport and delivery. Also recall that our analysis in Section 3.2.1, which indicated that hydrogen production by electrolysis may reach cost parity with gas reforming in 2030, does not assume that the hydrogen is produced from renewable electricity. 26 Hydrogen as an energy carrier Hydrogen applications 27

(13) (5) 3.4 Industry energy consumption and a third of CO2 emissions . Figure 14 illustrates the energy consumption and Hydrogen is today broadly used as a feedstock in energy carrier per industry sector. The key options for many industries, including ammonia, methanol and decarbonizing these industries are the deployment of refining. This paper focuses on emerging uses of energy efficiency measures, CCS, and fuel switching hydrogen, including as an energy carrier for heat from fossil-based fuels to low-carbon hydrogen, generation, and its novel applications as a feedstock. bio-based fuels or renewable electricity. Here we review opportunities for using hydrogen in the After the power sector, industry is the biggest cement and iron and steel industries, and for heat consumer of energy; it accounts for a third of final generation in other energy-intensive industries.

FINAL ENERGY CONSUMPTION BY SECTOR AND FUEL IN 2015

E E E E

Feedstock

Electricity from grid/ heat from eternal source

Other incl. bioenergy

atural gas

Oil

Coal

A B C D

A B C D ©RUTER

Hydrogen could fuel tens of thousands of heavy vehicles like buses and trucks in 2030. Photo: RUTER Figure 14: Energy consumption by fuel for different industries. Graphic: DNV GL from McKinsey & Company data(14).

3.3.3 Decarbonization potential of FCEVs and For the LV segment, we expect 120 million more cars BEVs in road transport on the road globally in 2030(1). Using the lifecycle emission results in Figure 13, we find that the uptake Here, we aim to estimate the decarbonization of about 115 million BEVs and 2-5 million FCEVs 3.4.1 Cement industry biomass, or waste, from which they choose based on potential of FCEVs and BEVs in the light and heavy gives a decrease of about 3% in the global average availability and price. Whereas changing fuel from vehicle segments (LV and HV), where buses are emission intensity per vehicle compared with the The worldwide production of cement emitted coal or petcoke to biogas or biomass would require (6,13) included in the HV category. same measure in 2020. However, because the global approximately 2.2 GtCO2 in 2014 , nearly all of it a modest retrofit of the kiln, the replacement of coal stock of light vehicles is expected to increase from from the fuel combustion to heat cement kilns and with hydrogen requires redesign of the furnace. DNV GL analysis(1) indicates that the vehicle stock will 1,090 million in 2020 to 1,210 million over the same the limestone calcination. The main options for This is due to the differences in heat transfer from increase in both the LV and HV segments. The uptake decade, the carbon footprint of this vehicle segment decarbonization in the cement industry are(14): hydrogen burners compared to fossil-fuel burners of non-combustion vehicles (FCEV and BEV) in 2030 is projected to rise by about 8%. and to safety considerations. In addition,

is projected to be less than the estimated increase ■■Switching to a low-carbon fuel to mitigate CO2 industrial-scale electric cement kilns are not in the respective vehicle stocks. This implies that the We observe a similar picture for the HV segment. emissions from fuel combustion. yet available, requiring further research and total emissions from both segments will increase. Twenty-three million heavy BEVs and 20,000–40,000 ■■Applying CCS to the exhaust gases of cement kilns development. Installing an electric or hydrogen

heavy FCEVs (with gross vehicle weight above 3.5 to prevent CO2 emissions resulting from both fuel furnace at existing cement plants would likely Hence, rather than deliver decarbonization, the tonnes) will give about a 2% decrease in the global combustion and limestone calcination. require extensive retrofitting of these sites. uptake of FCEVs and BEVs will reduce the increase average emission intensity per vehicle compared ■■Replacing limestone or clinker with other minerals,

in emissions. We will estimate the contribution of with 2020, but the total carbon footprint of the which could help reduce process emissions. Given the challenges and limited CO2-reduction non-combustion vehicles to lessen emissions in 2020 vehicle segment is projected to increase by potential from using hydrogen in cement making, and 2030 relative to a trajectory where all about 27%. Today, cement producers fire kilns with a wide variety we believe that CCS is a more attractive option for new vehicles are ICEV. of fuels, such as coal, petroleum coke (petcoke), decarbonizing this industry. 28 Hydrogen as an energy carrier Hydrogen applications 29

There are several options for decarbonizing steel HYBRIT is a project under planning in Luleå in production(14): Sweden to pilot the use of hydrogen from electrolysis in a DRI-based steelmaking process(19). ■■Applying CCS at existing BF-BOF production sites. It is a joint venture between SSAB, LKAB and ■■Using charcoal instead of coal as a feedstock and Vattenfall. The production route is similar to existing

fuel in BF-BOF production. DRI processes, except that H2 reacts with iron oxides

■■Using biogas or H2 instead of natural gas as a to form water instead of CO2. HYBRIT’s proposed reductant in DRI production. DRI process is shown in Figure 15. The pilot concept

■■HIsarna, a DRI process for converting iron ore is designed to have sufficient 2H storage capacity to (18) almost directly into liquid iron or hot metal . balance the H2 demand for the DRI process and the ■■Using low-carbon electricity in an EAF. hydrogen supply from intermittent power generation by, for example, wind or solar PV.

THE BF-BOF AND HYBRIT STEELMAKING PROCESSES

BLAST FURNACE ROUTE HYBRIT ROUTE

ro ore cocetrte

oss ues ooss ues

© Shutterstock Iron ore Iron ore o pellets PELLETIZING pellets Efforts are underway to pilot use of hydrogen in the production of steel. Photo: Shutterstock.

oke t 3.4.2 Iron and steel industry resulting pig iron is then reacted with oxygen roe in a basic oxygen furnace (converter) to remove ter ectrct The iron and steel industry used around 36 EJ(i) of excess carbon content from the iron and to energy in 2014 when the average global energy generate liquid steel. roe t intensity of crude steel production was 21 GJ/t(15). IRONMAKING In 2016, 1.9 tCO was emitted on average for Electric arc furnace 2 ot st co oe roe every tonne of steel produced(16). Production Another process is employed to produce recycled roe store of both virgin steel and recycled steel emitted steel and the remaining fraction of virgin steel. In

approximately 3.2 GtCO2 that year, equivalent to this case, electric arc furnaces (EAF) are either fed (5) about 10% of energy related CO2 emissions . with scrap steel to make recycled steel or fed with direct-reduced iron (DRI) to produce virgin steel. Steel companies use two main production Syngas produced from coal or natural gas is usually STEELMAKING processes for steel: used as the reducing agent to reduce iron ore at Hot metal Sponge iron temperatures below the melting point of steel. e Scr Blast furnace to basic oxygen furnace Recycled steel produced in an EAF tends to be of

The blast furnace to basic oxygen furnace (BF-BOF) lower quality than virgin steel because it retains process accounts for about 95% of the world’s virgin whatever contaminants that were present in the steel and some 70% of total steel production(17). It is scrap steel, such as copper. a process in which iron ore is reduced and melted at temperatures around 1,200°C. Coke, coal and/or The EAF and DRI-EAF processes have much lower Crude steel

natural gas are used as reducing agents. The CO2 emissions per produced tonne of steel than the coal-based BF-BOF production route. Figure 15: Schematic of the BF-BOF and HYBRIT processes. Source: Hybrit Development AB(19)

(i) An exajoule (EJ) is one quintillion joules (J) 30 Hydrogen as an energy carrier Hydrogen applications 31

3.4.3 Industrial heating HYNET NORTH WEST In many energy-intensive industries requiring high-grade heat, using hydrogen as a heating fuel could be a This UK hydrogen energy and carbon capture, utilization and storage (CCUS) project aims to reduce

feasible and efficient route to decarbonization. Figure 16 illustrates the energy consumption and grade in carbon emissions from industry, domestic heat and transport. It provides H2 distribution and CCUS different industries. Certain processes require combustion-based heaters, in which solids, liquids or gases are infrastructure across Liverpool, Manchester and parts of Cheshire. Hydrogen produced from natural gas burned as the heat is transferred to the material. For low- and medium-grade heat, from below 100°C up to will go via a new pipeline to industrial sites, for injection blending into the existing natural gas network,

400°C, hydrogen could complement electrification and heat pumps. Hybrid boilers, which switch between and for use as transport fuel. Produced CO2 will be captured and stored in nearby gas fields with CO2

electricity and hydrogen, could allow factories to exploit price or supply differences. from local industry. HyNet forecasts use of H2 for heat in the local industries in 2030 will be 15% of the project’s target demand for this purpose in 2050(14). For more information see: hynet.co.uk

FINAL ENERGY CONSUMPTION BY SECTOR AND TYPE OF HEAT IN 2014 (EJ/YR) Parameter Key data

Peak displacement of natural gas use by industry 510 MW Likely number of industry sites converted to hydrogen 10

owgrade heat Peak displacement of natural gas in the distribution network 380 MW

ediumgrade heat Number of homes and businesses receiving a hydrogen blend >2 million 1.1 Mt Highgrade heat Total CO2 saved per annum Total cost of project infrastructure GBP920 million Electricity

A B C D E F

A uu B u er C ceet D, chemicals, petrochemicals and refining; E ro stee F other ustres

Figure 16: Energy consumption for heat in different industries. Graphic: DNV GL from Hydrogen Council data(2).

Alternative options to decarbonize the heat supply include electrification (using low-carbon electricity), use of

biomass, and CCS. Most of these are more mature and less complex than H2 when it comes, for example, to

retrofitting equipment and safety. That said, H2 for industrial heating can be an interesting option in regions

with a large push for it, and development of H2 distribution infrastructure. However, we expect uptake of H2 will probably be slow compared with other sectors due to the cost sensitivity and long equipment lifetime in these industries (e.g. see forecast from HyNet North West on page 31). © Shutterstock

Hydrogen-fuelled heating could assist decarbonization of industries like cement by 2050. Photo: Shutterstock. 32 Hydrogen as an energy carrier Business case for offshore hydrogen production 33

The study recognizes that operational platforms will not have sufficient available space for any significant installation. A key assumption is therefore that the platform is non-operational, and that its decks are re-built to host the necessary equipment. We consider, as the Energy Delta Institute (EDI) did(20), that the platform to be re-built is the G17d-A complex consisting of the G17d-AP production platform, and the satellite well-protector platform G17d-A. The platform characteristics are described in Table 1.

Table 1: Characteristics of platforms G17d-AP and G17d-A(20) 4. BUSINESS CASE FOR Characteristic G17d-AP G17d-A Dimensions (m) 35 x 30 x 27 NN OFFSHORE HYDROGEN Levels 4 2 Topsides weight (t) 2,450 1,310 Water depth (m) 38.7 PRODUCTION Costs to design and rebuild platform decks (EUR million) 176 Decommissioning costs (EUR million) 20 Platform operational expenditure (EUR million) 8.8 This section explores two concepts for hydrogen production on an offshore platform (Figure 17):

H2 production by electrolysis using power from an offshore wind-farm; or, offshore H2 production by gas reforming and carbon capture and storage (CCS). These concepts are compared with their respective 4.1 Concept descriptions counterparts where the power or gas is brought to shore and the hydrogen is produced onshore. Concepts C1 and C2 produce hydrogen by electrolysis; C3 and C4 instead use sorption-enhanced reforming

(SER) with integrated CO2 capture. The electrolysis concepts are dimensioned to use the same power output from the offshore wind farm, while maximizing the hydrogen production capacity on the platform, which is constrained by the available space. The gas reforming concepts are similarly dimensioned to use the same amount of gas, while maximizing the gas reforming capacity on the platform. This implies that the hydrogen production from C3 and C4 is more than twice the output from C1 and C2(i), see details in Table 2.

Table 2: Description of considered concepts

C1: Offshore wind farm, C2: Offshore wind farm, C3: Gas reforming and full C4: Gas reforming and

power to shore, electrolysis offshore, CCS chain offshore, CO2 capture onshore,

electrolysis onshore hydrogen to shore hydrogen to shore CO2 storage offshore

25 ktH2/yr 23.6 ktH2/yr 50 ktH2/yr 50 ktH2/yr delivered @ 60 bar delivered @ 60 bar delivered @ 60 bar delivered @ 60 bar - 250 MW offshore wind - 250 MW offshore wind - 29 kSm3/h slip stream - 20”, 100 bar, gas pipeline farm 5 km from platform farm 5 km from platform from existing gas to shore (G17d-AP) (G17d-AP) pipeline - 29 kSm3/h slip stream - Substation converts - 200 kW desalination unit - 20”, 100 bar, 5 km gas from onshore gas 66 kV AC electricity to on G17d-AP pipeline terminal 320 kV DC - 200 MW electrolysis unit - 210 MW SER with CO2 - 210 MW SER with CO2

- DC cable to shore on G17d-AP capture and CO2 capture and CO2 compression on G17d-AP compression on G17d-AP - Onshore substation - 3 MW H2 compressor

converts 320 kV DC to and auxiliary systems - 3 MW H2 compressor - 8”, 110 bar offshore

low or medium voltage on G17d-A and auxiliary systems CO2 pipeline at onshore connection on G17d-A - 7”, 80 bar H2 pipeline - 475 ktpa CO2 storage

- 200 MW onshore to shore - 10”, 80 bar H2 pipeline electrolysis unit to shore

- 3 MW H2 compressor - 8”, 5 km, 110 bar

and auxiliary systems offshore CO2 pipeline

- 475 ktpa CO2 storage

Key:

Photo: Michel Jansma MarineTraffic.com Jansma Photo: Michel 3 ktH2/yr, kilotonnes of hydrogen per year; 1 bar = 100 kilopascals; MW, megawatts; kW, kilowatts; km, kilometre; kSm /h, thousand standard cubic metres per hour; ”, inch; kV AC, kilovolts alternating current; kV DC, kilovolts direct current; Figure 17: Our concepts use characteristics from the G17d-A complex in the Dutch sector of the North Sea. Photo credit: SER, sorption-enhanced reforming; ktpa, kilotonnes per annum MarineTraffic – Global Ship Tracking Intelligence (www.marinetraffic.com). Photo: Michel Jansma.

(i) The nominal capacity of electrolysers is defined based on the maximal power input, whereas the nominal capacity of gas reforming units is based on the hydrogen production capacity per hour. Thus, an electrolysis unit will have a hydrogen production capacity per MW nominal capacity that is only some 70% of the production capacity per MW of a gas reforming unit. 34 Hydrogen as an energy carrier Business case for offshore hydrogen production 35

The material difference between concepts C1 and C2 existing wells for injection and monitoring. We also is that C1 requires a HVDC cable to shore whereas C2 assume that the gas feed is a slip stream of an has a hydrogen pipeline instead. In addition, concept existing gas transmission pipeline. C1 has a small platform for the substation. For concept C3, the reforming capacity that we can The material difference between concepts C3 and C4 is fit on a platform depends on the size of the that C4 has two pipelines to shore (one to take natural modules and other aspects. For instance, 1 MW

gas to shore and one to take CO2 back), whereas C3 container-sized modules (7.5 m x 3.0 m x 3.3 m) requires only one pipeline to shore, for hydrogen. capable of producing 300 Nm3/h are commercially available: examples include HyGeia-A from 4.2 Assumptions Mitsubishi(22) and HYSERVE-300 from Osaka Gas(23). One could potentially put 4x7 such modules on each For concept C1 we assume that any wind farm platform level, with extra space for pipes to collect power output that exceeds the power demand for the produced hydrogen. The combined capacity electrolysis, compression and auxiliary systems is fed would then be some 112 MW, and the same to the grid. For concept C2, no grid connection is cumulative production capacity as the platform assumed. This implies that any generation capacity concept with electrolysers can be achieved. exceeding the maximum demand from the platform will need to be curtailed. Matching Larger, compact hydrogen production units are, electrolysis capacity with maximum output from however, being researched and piloted. The Gas the wind farm would imply under-utilization of the Technology Institute (GTI) has estimated that the electrolysis capacity and would be uneconomic. building for a 300 MW unit (based on the LHV of hydrogen) using its SER technology would require a For concept C2, we assume, in alignment with EDI(20), ground area of only 6 m x 6 m, and would be 13.7 m that the hydrogen producer needs to compensate high. The weight of such an installation is not for curtailed power. Based on this assumption, EDI's given. It should be noted that this estimate carries Jepma and van Schoot(20) derive that the optimal significant uncertainty, and GTI has piloted the capacity of the electrolyser unit is about 80% of the technology only for a 65 kW unit. However, if this nominal wind-farm capacity. This ratio between compactness could be realised for a 300 MW unit, electrolyser capacity and wind-farm capacity implies, then it should be possible to fit 1 GW or more according to the same source(20), that 6% of the production capacity on the G17-AP platform. possible annual electricity output will be curtailed. This implies a 6% penalty to the electricity cost for We asked the Norwegian company ZEG Power, which concept C2. is developing gas reforming units based on the SER technology, to provide a preliminary estimate of the In this study, and following Douma(21), the wind farm capacity that can be built on the platform, and the is assumed to have a capacity factor of 58%. This associated cost. It estimated that it would be possible factor is based on wind analysis of meteorological to build 210–260 MW on one platform deck(24). In data from the IJmuiden wind farm offshore this study, we assume conservatively that additional Netherlands containing 10-minute mean wind capacity is not built on other decks. We therefore speeds over a three-year period (2012–2014). With assume that concepts C3 and C4 each have a 210 this capacity factor, a 250 MW wind farm will have an MW SER unit that operates with an average annual

average annual output of 145 MW. For concept C1, load of 90%, producing 50 ktH2/yr. To account for the we assume a 2% transmission loss so that the annual added complexity of building the unit offshore, we delivery to the electrolyser plant is about 1,245 GWh. assume a 20% cost penalty to the capital expenditure Since 6% of the power is curtailed for concept C2, (CAPEX) of the SER on the platform. the average power utilized by the electrolysis unit is 136 MW. We assume that the electrolysis unit has For concept C4, we assume a dedicated gas 67% efficiency based on lower heating value (LHV). pipeline is built to take the gas slip stream from the The annual hydrogen production is then 25.0 kt and platform area to shore. This may be a conservative 23.6 kt for concepts C1 and C2 respectively. assumption. However, from a greenfield investment perspective, our current concept C4 represents the For the gas reforming concepts, we assume that option of taking gas to shore, whereas the C3

captured CO2 will be stored in a depleted oil or gas concept represents the opportunity to do gas © Shutterstock field near the platform, using converted, re-purposed reforming offshore, and thereby avoid one pipeline. 36 Hydrogen as an energy carrier Business case for offshore hydrogen production 37

Financial implications of the concepts Table 4: OPEX of components for the respective concepts Tables 3 and 4 present the estimated CAPEX and operational expenditure (OPEX) of the components of the Component C1 C2*** C3 C4 respective concepts. We assume 20 years remaining life of the platform. This implies that all projects costs Wind-farm(a) 4% of CAPEX 4% of CAPEX - - for concepts C2 and C3 need to be depreciated over that time. For this comparison, we also assume that concepts C1 and C4 need to be depreciated over the same period. This may be reasonable. Concept C4, AC cable to platform(b) - 0.15% of CAPEX - - for instance, relies on gas feed from an existing gas pipeline. For Concept C1, the lifetime of the offshore DC cable to shore(b) 0.15% of CAPEX - - - substation may be 20–25 years. This lifespan is also representative for offshore wind turbines. The only Offshore AC-DC conversion 1.18% of CAPEX - - - components assumed to have a shorter lifetime than 20 years are the water desalination unit and the cell and transformer*(b) stack for the electrolyser unit. We assume each of these to have a lifetime of 10 years, so that they must Onshore DC-AC conversion(b) 0.29% of CAPEX - - - therefore be replaced once. Onshore transformer 1% of CAPEX - - -

(a) Electricity for electrolyser 50 kWh/kgH2 50 kWh/kgH2 - - Table 3: CAPEX of components for the respective concepts – all costs include installation Electrolyser(b) 2% of CAPEX 2% of CAPEX - -

(a) Component C1 C2 C3 C4 Electricity for desalination - 48 kWh/tH2 - - (a) (a) Wind farm EUR2.9/W EUR2.9/W - - Water 10 EUR/tH2 8% of CAPEX - - (a) (a) AC cable to platform - EUR771/m - - Electricity for H-compressor 0.67 kWh/kgH2 0.67 kWh/kgH2 0.67 kWh/kgH2 - DC cable to shore(a) EUR500/m - - - Hydrogen compressor(a) 3% of CAPEX 3% of CAPEX 3% of CAPEX - Offshore AC-DC conversion EUR708/kW - - - Hydrogen pipeline(c) - 2% of CAPEX 2% of CAPEX - and transformer*(b) Gas feed(d) - - 8.0 bcf 8.0 bcf (b) Onshore DC-AC conversion EUR142/kW - - - (d) SER + CO2 capture** - - 225 EUR/kW 225 EUR/kW (a) Onshore transformer EUR31/kW - - - (e) CO2 pipeline - - 2% of CAPEX 2% of CAPEX (a) Water desalination - EUR2.9/W - - (f) CO2 injection and storage - - 6 EUR/t 6 EUR/t Electrolyser(a) EUR1.17/W EUR1.17/W - - Gas pipeline - - 2% of CAPEX 2% of CAPEX (+40% every 10 yr) (+40% every 10 yr) Key: Hydrogen compressor(c) EUR2.8/W EUR2.8/W EUR2.8/W - kWh/tH , kilowatt hours per tonne of hydrogen; kWh/kgH , kilowatt hours per kilogram of hydrogen; EUR, euros; Hydrogen pipeline(b) - EUR625/m, 7” EUR700/m, 10” - 2 2 bcf, billion cubic feet; kW, kilowatts; t, tonnes SER + CO capture**(d) - - EUR0.54/W EUR0.45/W 2 Notes: (e) CO2 pipeline - - EUR650/m, 8” EUR650/m, 8” *, Includes OPEX for platform hosting substation; **, includes CO2 compression and auxiliary systems, and hydrogen (f) CO2 injection and storage - - EUR1.1/t EUR1.1/t compression to 60 bar; ***, concept C2 applies a 6% penalty to the power price Gas pipeline(c) - - EUR1,000/m, 20” EUR1,000/m, 20” Data sources: Key: a, Douma(21); b, DNVGL(25); c, EDI(20); d, ZEG Power(24); e, ZEP(27); f, ZEP(28) EUR, euros; W, watts; MW, megawatts; m, metre; t, tonne; ”, inches Notes:

*, includes CAPEX for platform hosting substation; **, Includes CO2 compression and auxiliary systems, and hydrogen compression to 60 bar Data sources: a, Douma(21); b, DNV GL(25); c, EDI(20); d, ZEG Power(24); e, Mallon et al(26); f, ZEP(27) 38 Hydrogen as an energy carrier Business case for offshore hydrogen production 39

4.3 Results Furthermore, the NPV of both concepts is generally BREAKEVEN HYDROGEN PRICE always negative unless we assume a very low When calculating the net present value (NPV), we electricity price and a very high hydrogen price. apply an inflation rate of 1.6% to the hydrogen price For instance, if the CAPEX of the electrolyser is and all OPEX components (including the gas price EUR0.91/W (including installation), and the electricity and electricity price). We apply a discount rate of 7%. price is as low as EUR30/MWh, then concept C1 gets

a positive NPV at EUR7.05/kgH2, whereas concept C2

requires EUR7.71/kgH . Since the market price for 2 2 4.3.1 Electrolysis green hydrogen may be around EUR5/kgH2 at the plant gate(20), we confirm the initial observation that The transport of power or hydrogen to shore the concepts can only be economically viable in very ER/kgH adds a significant cost penalty relative to onshore special circumstances. electrolysis from onshore electricity. This implies that concepts C1 and C2 can only be cost competitive with onshore value chains under special 4.3.2 Gas reforming circumstances. However, the interesting aspect of this analysis is if it is more economical to perform Next, we consider the two concepts C3 and C4 with electrolysis on the platform or onshore. gas reforming. We assume an electricity price of istance from shore km EUR60/MWh, which is comparable to recent tenders (21) We find that concept C2 has a slightly lower CAPEX in the North Sea , and a gas price of EUR per oncet oncet than concept C1 (the offshore substation and the thousand cubic feet (kcf) of natural gas(i). The main onshore converter and transformer is more factor that differentiates the NPV for the two expensive than rebuilding the G17d-A complex); concepts is distance to shore. Figure 18 shows Figure 18: Hydrogen prices giving zero NPV for concepts C3 and C4 assuming a gas price of EUR6/kcf. Graphic: DNV GL but the OPEX for concept C2 is higher than that for breakeven hydrogen prices as a function of distance the OPEX for concept C1, primarily due to the from shore. The curves cross at 295 km, indicating OPEX for the G17d-A complex. This implies that the that the platform solution is cost competitive for NPV for concept C1 is always slightly higher than distances longer than this. Since this is blue

for concept C2. hydrogen with a low CO2 footprint, it can serve the same market as green hydrogen. This suggests that there may be a good business case for these concepts if the breakeven price is less than about (20) EUR4/kgH2 to EUR5/kgH2, for instance . This holds true for both concepts if the distance to shore is less than 500 km. Photo: Simon Mockler

(i) Since 8 bcf of gas is used to produce 50 ktH2, we find that each extra euro per kcf of gas adds EUR0.16 to the hydrogen price for both concepts. 40 Hydrogen as an energy carrier Uptake in 2030 and 2050 41

hydrogen as a reducing agent, then this would Table 6: Strength of presence in scenario consume about 140 ktH /yr(ii). In comparison, we note 2 Ref Low High that the Hydrogen Council has estimated that 100 An era of energy autonomy - - 0 ktH2 may be used in this process by 2030. Hydrogen supply is for big players + + 0 The estimated demand for hydrogen as an energy Electrolysis displaces gas reforming + - 0 carrier in 2030 is summarized in Table 5. Industry is forced to decarbonize 0 - + 5. UPTAKE IN 2030 Fuel cells are No. 1 for heavy 0 - + Table 5: Estimated demand for hydrogen in 2030 electric vehicles Light vehicles are largely + + + Application Hydrogen demand (Mtpa) battery electric AND 2050 Building heating 3.6 No more gas/hydrogen-based 0 + - Light vehicles 0.3–0.8 building heat Heavy vehicles 0.0–0.1 Infrastructure enables hydrogen - - + In this section, we estimate the hydrogen demand for corresponding gas demand. Furthermore, by doing Industry heat 0 prosumer economy heating in buildings, mobility, and industry in 2030 a bottom-up analysis for the UK, we estimate that 3% DRI steelmaking 0.1 based on our assessments in Section 3, and develop of the estimated gas demand for heating in Total 4.0–4.6 three continued development scenarios for the buildings may be replaced by hydrogen by 2030. 5.2.1 Reference scenario (i) period 2030 to 2050. These scenarios represent a This corresponds to 380 ktH2 . Applying the same central case, and two futures with lower and higher percentage to the other four countries with high 5.2.1.1 Production demand respectively than the central case. Finally, carbon capture and storage (CCS) readiness 5.2 2030–2050 scenarios In 2050, hydrogen will still be predominantly we attempt to quantify global demand for H2 in 2050 (Australia, Canada, the Netherlands and US), and produced by large facilities, but some 20% of H2 under each scenario. applying a lesser fraction of 1% to South Korea Taking the projections for 2030 described above as for mobility and domestic use will be from (with medium CCS readiness), we derive the result a starting point, we aim to estimate the hydrogen small-scale production. A large fraction of this will

that about 3.58 Mtpa H2 may be used for heating in demand in 2050. These scenarios were developed be for hydrogen fuelling stations with integrated 5.1 2030 prognosis buildings in 2030. This is likely to prove an optimistic based on a qualitative expert opinion-based process electricity generation from renewable sources, e.g. projection, as it would require all relevant countries with internal experts in DNV GL. The process from a local dedicated solar photovoltaic (PV) unit, Our analysis in Section 3.3.3 indicates that less than to implement a policy push equivalent to the level comprised the following two tasks. through a power purchase agreement with a local one million tonnes of hydrogen will be used for currently seen in UK. solar or wind farm, or from electricity sourced from mobility applications in 2030. This is based on a 1. Discuss eight predefined elements (described the local grid with green electricity certificates. projected stock of two to five million light fuel-cell Hydrogen can be used in several industries to in Appendix B) of a possible hydrogen future, electric vehicles (FCEVs) and 20,000 to 40,000 generate low-, medium- or high-grade heat. The and evaluate the degree to which they will Hydrogen production by large-scale electrolysis

heavy FCEVs. Hydrogen Council estimates that 4 Mtpa of hydrogen shape the H2 demand in 2050 assuming a plants will be the cheapest method of production, on can be used in 2030 for this purpose(2). This assumes ‘business-as-usual’ extrapolation of our 2030 an annual basis. Consequently, most new production To estimate the demand for hydrogen for heating in that a tenth of steel and chemical plants in Europe, prognosis. This evaluation will be used to capacity is electrolysis facilities. The switchover from

buildings, we use the following formula: North America, and Japan will use hydrogen for formulate a reference scenario. fossil fuel-based H2 to electrolysis is further production of heat. However, and as discussed by accelerated by carbon regulations and carbon Gas demand for heating = Total energy demand McKinsey and Company(14), there are many other 2. Discuss circumstances by which hydrogen pricing that contributes to a phase-out of gas x Building share of total energy demand options, including electrification, use of biomass, demand may shift significantly downward or reforming and coal gasification facilities. x Heating share of building energy demand and CCS, which are more mature and involve less upward relative to the reference scenario. x Gas share of energy input to heating. complexity regarding, for example, retrofitting These circumstances are used to define a More than half of global hydrogen production will equipment and safety. We therefore estimate that low-uptake scenario and a high-uptake be decarbonized (with a carbon footprint less than (5) From IPCC data we have that buildings accounted the use of hydrogen for heat in industry in 2030 scenario respectively. 5 kgCO2e/kgH2). This is achieved through a mix of for 32%, or 32.7 PWh of global energy demand in will be insignificant. gas reforming or coal gasification with CCS, and 2014, and that heating represents 24.4 PWh (75%) of The scenario elements in Appendix B describe a electrolysis using an electricity mix with a carbon

this demand (Figure 4). This gives: To estimate the potential demand in 2030 for certain state of play for a feature in a hydrogen footprint less than 100 kgCO2e/MWh. hydrogen as a reducing agent in the direct reduced future. The experts were asked to score each Eqn. 1 Gas demand for heating = Total energy iron (DRI) steelmaking process, we first note that element according to its expected strength of Because CCS will not always be practical or demand x 0,24 x gas share of energy 86.3 Mt of steel were produced globally through the presence in each scenario. Table 6 summarizes the economic, some existing carbon-intensive hydrogen input to heating. DRI process in 2017 using natural gas as a reducing result of this scoring process. Here "-", "0" and "+" production facilities will replace part of their agent. This represents a 2.6% production increase indicate respectively a weak, moderate or strong production with electrolysis-based production.

Figure 5 indicated the fraction of energy input to per year since 2010. If the production by DRI presence. The storyline for the scenarios was The H2 production capacity from electrolysis may heating in buildings supplied by gas in select continues to grow at this rate, then the output in developed based on this table. be sized to achieve compliance with carbon countries. Putting this and the total energy 2030 will be 120 Mt. If 20% of the global production regulations, and to allow cost-optimal operation of demand in these countries into Eqn. 1 we find the additions from DRI in 2025–2030 is produced using the electrolysis facility (i.e. operate only when

(29) (19) (i) The energy consumption for 2016 (188.1 MTOE) reported in the BP Statistical Review of World Energy 2017 was used. (ii) About 50 kgH2 is required to produce one tonne of steel . 42 Hydrogen as an energy carrier Uptake in 2030 and 2050 43

electricity prices are low). It is possible, or even likely, We expect, however, that a rather small fraction of that many industrial users will produce hydrogen solar PV installation owners will invest in hydrogen by both gas reforming and by electrolysis to have electricity storage systems (electrolyser, compressor, redundancy, and to hedge against price fluctuations. storage tanks, and fuel cell), and that the electricity stored globally by such systems will be negligible 5.2.1.2 Demand compared with the electricity storage delivered by Buildings (residential demand) the global battery stock.

Replacing natural gas with H2 gas in building heating applications, such as space heating and cookers, Mobility contributes to early demand for hydrogen as an DNV GL(1) projects that there will be 1.6 billion light energy carrier, but demand will peak before 2035 vehicles in 2050, and that the energy consumption and then slowly decline as heating, and the world of this fleet will be 32 EJ. Our Energy Transition at large, is increasingly electrified(i). Outlook(1) further projects that 1.4 billion light vehicles will be battery electric vehicles (BEVs), and The hydrogen infrastructure built by 2035 will, that BEVs and internal combustion engine vehicles

however, drive continued use of H2 for heating in (ICEVs) will consume on average 17 (GJ) and 40 GJ the areas where such infrastructure exists. We per vehicle per year, respectively. The model does therefore expect the hydrogen demand in 2050 not include light fuel-cell electric vehicles (FCEVs) to be about 4 Mtpa. in its projections.

Increasing the share of distributed solar PV in the A BEV may have some 67–81% tank-to-wheel electricity mix(ii) implies a need for substantial efficiency, whereas a FCEV may have only 30–45% © Shutterstock electricity storage capacity. This electricity can be efficiency(11). A BEV will, however, require more stored locally by producers in the form of batteries power to deliver the same vehicle performance due Battery electric cars will far outnumber hydrogen ones in 2050. Photo: Shutterstock. or hydrogen, or electricity can be fed to the grid. to the higher weight of a BEV compared with a FCEV. Thomas(31) estimates that a light FCEV requires 35%

Hydrogen offers a flexible and possibly value-adding more energy input than a comparable light BEV with about 5% of the light vehicle stock will be FCEVs in One kilogram of H2 has about the same energy

alternative to feeding electricity to the grid, longer a range of 320 km. Using this ratio, we estimate the 2050. This translates to 13 Mtpa H2 demand for light content as four litres of diesel. However, due to duration storage capacity compared to batteries, average annual fuel consumption of a light FCEV vehicles in 2050. higher efficiency, we get more mileage per energy and redundancy. It also provides homes with an in 2050 to be 23 GJ (162 kg) of hydrogen per year. unit from hydrogen than from diesel. The instrument to disconnect from the electricity grid. Extrapolating from our 2030 estimate, we expect that To convert the figures from the text box above International Council on Clean Transportation into hydrogen demand, we deploy the following estimates that diesel tractor-trailers will, in 2030, numbers from the IEA(30): consume 178 million joules (equivalent to about 5 l of diesel) to go the same distance as FCEV EXPLAINING THE BASIS OF OUR PROJECTIONS The IEA divides freight transport vehicles into three ■■Global annual mileage: 37,000 km for MFT tractor-trailers can go on a kg of hydrogen. Assuming FOR FREIGHT VEHICLES AND THE RELATED broad groups based on gross vehicle weight (GVW) and 52,000 km for HFT. this ratio is representative in 2050, we find that one

DEMAND FOR HYDROGEN measured in tonnes: ■■Average fuel efficiency (2017): 25 litres (l) of diesel per FCEV MFT will, on average, consume 1,110 kgH2/yr, 100 km for MFT and 38 l diesel per 100 km for HFT. and one FCEV HFT will, on average, consume 2,370 (30) The IEA has developed two alternative scenarios for ■■Light Commercial Vehicles (LCVs) of less than 3.5 t. ■■Average fuel efficiency in 2050: Fuel consumption kgH2/yr. This gives the following estimates for the development of freight transport towards 2050: ■■Medium Freight Trucks (MFTs) of 3.5–15.0 t. per 100 km 40% below 2017 levels. hydrogen demand in 2050 (Table 7). ■■Heavy Freight Trucks (HFTs) of greater than 15 t. ■■A Reference Scenario (RS) accounting for current or announced policies affecting the outlook for LCVs represent about 70% of freight vehicles today, Table 7: DNV GL calculation of hydrogen demand (Mt) for IEA Reference Scenario and Modern Truck Scenario road freight transport. a percentage that is slightly more than in 2050 in the Reference Scenario Modern Truck Scenario ■■A Modern Truck Scenario (MTS) based on RS and MTS scenarios. implementation measures to modernize and raise 20% of heavy freight trucks (MFT+HFT) are FCEVs 41.7 31.2 the efficiency of road freight transport. In our analysis of uptake of FCEVs for heavy vehicles 50% of heavy freight trucks (MFT+HFT) are FCEVs 104 78.0 we include only MFT and HFT, i.e. freight vehicles of We deploy these scenarios as a basis for projecting GVW above 3.5 t. the number of heavy vehicles in 2050, and the Buses represent about 5.5% of total energy demand for road transport(32). If this percentage is the same corresponding hydrogen demand. The IEA’s RS projects 115 million such vehicles in in 2050, and we apply the projected energy consumption for road transport in 2050 in our Energy Transition 2050 (64 million HFT; 51 million MFT), while its MTS Outlook(1), which is 62 EJ, then we find that the total energy consumption by buses in 2050 is 3.4 EJ. projects 86 million heavy freight vehicles (48 million Assuming also that fuel efficiency (MJ/km) of FCEV buses is roughly equal to the average fuel efficiency of HFT; 38 million MFT). the bus vehicle stock, then the corresponding annual hydrogen demand in 2050 is 4.8 Mt if 20% of the global bus fleet are FCEVs, and 12 Mt if 50% are FCEVs.

(i) We predict that electricity will increase its share of total energy demand from 19% in 2016 to 45% in 2050(1). (ii) In 2050, solar PV is projected to supply 27 PWh, 40% of global electricity generation output(1). 44 Hydrogen as an energy carrier Uptake in 2030 and 2050 45

(2) Industry: Ammonia production through DRI in 2050 . If all DRI processes use H2 5.2.1.3 Market We describe below the panel’s evaluation of the

About 27 Mtpa H2 was used for ammonia production as a reducing agent, this would lead to hydrogen The hydrogen market in 2050 will still be closed, main impact of these factors on the hydrogen (2) in 2015 . Over the past 20 years, the annual growth demand of about 11 Mtpa. A more realistic scenario with less than 10% of global H2 production for demand in 2050 relative to the reference scenario. (33) rate in ammonia production have been around 2% . is that around half the DRI processes will use H2 as a industry use being freely traded by then.

If this continues, the H2 demand for ammonia will reducing agent in 2050. First, a deep decarbonization of hydrogen be 36 Mt in 2030 and 54 Mt in 2050. Ammonia The large producers will have supply agreements production for industry use does not occur. This is demand is, however, correlated with global Industry: Heating with principal buyers, and will often own or operate primarily because the upscaling and adoption of

agricultural production. The UN's Food and Just like heating in buildings, industrial heating will be the H2 transmission infrastructure (e.g. transmission CCS will be slow without a strong push from Agriculture Organization projects that cereals increasingly electrified as electricity grows its share pipelines and subsurface gas storage). regulations or carbon pricing. CCS will not be production will increase 38% between 2005 and of world energy supply. We therefore believe that the mandated for hydrogen production in industry, and

2030 at a rate of 1.1%/yr, and will then grow at only H2 demand for industrial heating will be marginal in Big buyers, will often control or operate distribution the carbon price is not high enough to trigger broad 0.5%/yr from 2030 to 2050 (See Table 4.1 in UN 2050. We do expect, however, some deployment of infrastructure (e.g. distribution pipes, refuelling implementation of CCS or a broad shift away from (34) projections ). If we assume these growth rates hydrogen in regions with early development of H2 stations, and storage tanks). Limited pipeline fossil fuel-based hydrogen production. In this

for ammonia production, then we estimate the H2 infrastructure. Since there are some synergies with distribution infrastructure will exist for domestic scenario, we therefore assume that less than 200

demand for this purpose to be 32 Mt in 2030 and H2 supply for heating in industry and heating in or commercial delivery of hydrogen. Mtpa of CO2 is captured and stored or used for 35 Mt in 2050. The IEA has estimated that ammonia buildings, we project that these two applications will enhanced oil recovery in 2050. (35) production will grow about 50% to 2050 , have, approximately, the same level of penetration. Broader uptake of H2 as an energy carrier will be corresponding to a hydrogen demand of 41 Mt. Since the energy demand for heat in buildings is hindered by consumer preferences and the added This development is compounded by a lack of about two-thirds of that for heat in industry, this complexity of hydrogen solutions. For instance, expected cost compression for electrolysis. While

Industry: Petroleum refining translates to a demand for 6 Mtpa in 2050. while H2 use for heating in the cement industry is technology developments have significantly reduced

About 17 Mtpa H2 was used for petroleum refining possible, several complexities must be handled, the CAPEX of electrolyser plants, the penetration in 2015(2). IEA(36) estimates that this demand will grow Industry: Reference scenario including explosion risk. Cement producers will of variable renewables has struggled to go much by about 3%/yr to reach 26 Mt in 2030. Since crude This reference scenario applies the estimated therefore prefer electrification and CCS as beyond 40% in many countries. This implies that oil production is expected to remain relatively flat at demand for the industry applications described decarbonization measures. the periods with surplus electricity from variable current levels to 2030, this reflects mainly growth in above. For ammonia and methanol, three estimates renewables are generally rare, and their impact on (1) H2 consumption per refined unit . We expect that are provided, of which the middle one is used in this For domestic use of H2 for electricity storage, the average annual electricity price is quite minor.

H2 consumed per refined unit will not change much scenario. Figure 19 shows the market share of the consumers need an electrolyser, a compressor, a Consequently, the opportunity to produce low-cost

from 2030 to 2050. Hydrogen demand for petroleum total H2 demand (94 Mt) in the respective industries. storage tank, and a fuel cell, in addition to batteries, hydrogen when the electricity price is low does not refining will then decrease to 13 Mtpa by 2050 on a thus limiting hydrogen's uptake for this application. materialize at significant scale. projected 50% decline in crude oil production from today’s level(1). Finally, uptake of light FCEVs outside urban centres FCEVs do not become the preferred low-carbon INDUSTRY HYDROGEN DEMAND is expected to remain limited by lack of adequate alternative for heavy vehicles (buses and heavy

Industry: Methanol production infrastructure for H2 fuelling. Other low-carbon fuels, freight trucks). This is due to a mix of circumstances,

About 5.6 Mtpa H2 was used for methanol such as biofuels and potentially ammonia, are also but the dominant factor is rapid battery technology production in 2015(2). IHS(37) projects 4.3%/yr growth increasing their market shares in the transportation development. In this scenario, it is assumed that the in methanol demand to 2026. If this rate continues, Other sector, benefitting from existing or more easily battery energy density more than tripled from 9 then the hydrogen demand for methanol production available infrastructure. 2018 to 2030, while battery charging time Heat will be 10.5 Mtpa in 2030 and 24 Mtpa in 2050. This 6 experiences an equivalent decrease over the may be realised if methanol achieves substantial same period. This counteracts early growth in uptake in the transport sector. However, we expect Steel 5.2.2 Low-uptake scenario heavy FCEV stock to 2030, and results in a slower a more modest growth of 1–3% from 2030 to 2050, 7 development of hydrogen fuelling infrastructure. Ammonia which translates to a hydrogen demand for methanol Our panel of experts identify five factors that can This, in turn, hinders significant further growth in the 44 production of 13–19 Mtpa in 2050. most strongly reduce demand for hydrogen heavy FCEV fleet to 2050, as well as any substantial relative to the expected trend underpinning the uptake of light FCEVs.

Other current uses of H2 as a feedstock in industry reference scenario: represent 10% of total industry demand. We expect ethanol Finally, the limited uptake of FCEVs results in less this percentage to be about the same in 2050. 20 ■■Less reduction in the cost of green consumer familiarity with hydrogen. This contributes hydrogen production; to enhance a preference among consumers for Industry: Steelmaking ■■A weaker influence from carbon regulations electricity-based solutions, i.e. BEVs instead of Global steel production of approximately 1,700 Mt in Refining and carbon pricing; FCEVs, batteries instead of hydrogen for electricity 2017(16) is projected to grow to 2,100 Mtpa by 2050, 14 ■■Greater improvement in battery energy density; storage, and electric heating instead of hydrogen with virgin steel production remaining near 1,200 ■■Less hydrogen infrastructure developed; and boilers and cookers. Consequently, the general Mtpa while recycled steel production more than ■■Greater consumer hesitancy over public has not adopted hydrogen as an energy doubles(14, 16). The Hydrogen Council estimates Figure 19: Market share of demand for hydrogen in 2050 hydrogen solutions. carrier, despite its appeal as a low-carbon fuel. that about 10% of virgin steel could be produced for different industries. Source: DNV GL 46 Hydrogen as an energy carrier Uptake in 2030 and 2050 47

5.2.3 High-uptake scenario A distributed hydrogen economy emerges from 5.2.4 Total hydrogen demand 2050 these two characteristics. Businesses, hydrogen

In our expert-panel’s opinion, the five factors fuelling stations, communities and even households Tables 8 and 9 show estimated demand for H2 in 2050 under the low-, medium-, and high-uptake scenarios. that can most strongly increase the demand for have small-scale, modular electrolysers. These units We note that 200 Mtpa represents about 6% of the global energy consumption in 2050 projected by(1).

hydrogen relative to the expected trend produce H2 to cover their own consumption, but can Nearly a twelfth (8%) of the global energy demand would be required to produce this amount of hydrogen. underpinning the reference scenario are: also deliver it to the grid in the same way that power prosumers can feed in electricity. This market may ■■Faster development of hydrogen develop hand-in-hand with a growing electricity Table 8: Estimated demand for hydrogen as an energy carrier in 2050 (Mtpa). Source: DNV GL distribution infrastructure; prosumer market, where electricity producers Application Low-uptake scenario Reference scenario High-uptake scenario ■■Quicker cost reductions for green (typically from solar PV) can choose to deliver hydrogen production; electricity to the grid, or use surplus electricity Building heating ~0 4 8 ■■Higher deployment of CCS; to produce hydrogen. Building CHP* (fuel cell) ~0 ~0 1.2 ■■Less improvement in battery energy density; and Light vehicles ~0 13 26 ■■Stronger policy incentives for distributed, More access to power and hydrogen grids Heavy vehicles 36** 68 116 small-scale production of green hydrogen. Hydrogen DSOs enable easy, non-discriminatory Heat for industry 3 6 10 access to the grid for consumers and producers. Total 39 91 161 The high-uptake scenario is perhaps characterized Some users, such as small communities and first and foremost by a massive deployment of businesses, also invest in sufficient on-site electricity * CHP, combined heat and power; ** This corresponds to the number of heavy FCEVs projected by DNV GL's 2018 Energy (1) electrolysis, which is driven by the low cost of generation capacity and H2 production and storage Transition Outlook . We have, however, applied a higher fuel consumption per vehicle since we assume here that the production and the availability of low-carbon capacity to achieve full electricity autonomy. We heavy FCEV fleet consists only of MFTs, HFTs and buses. electricity. The latter is due to large penetration of predict in this scenario that such systems will account solar PV and wind in the electricity mix in many for some 10% of the electricity storage delivered regions, combined with growth in nuclear power by the global battery stock. This implies that the Table 9: Estimated demand for hydrogen as a feedstock in 2050 (Mtpa). Source: DNV GL and broad application of CCS to gas- and coal-fired corresponding H demand will be about 1.2 Mtpa(i). 2 Application Low-uptake scenario Reference scenario High-uptake scenario power plants. This latter driver has principally been a result of strong carbon regulations, and a carbon In the high-uptake scenario, 10% of the total energy Ammonia 35 41 54 Petroleum refining 11 13 15 price averaging more than EUR100/tCO2 in the consumption from the light vehicle stock is supplied power sector in most highly-industrialized countries. by hydrogen, and 50% of buses and heavy freight Methanol 13 19 24 trucks above 3.5 tonnes are FCEVs. While significant Other feedstock industry 6 8 10 Hydrogen infrastructure opens up markets battery developments have occurred, weight, range, DRI steelmaking 4 7 11 Another main characteristic is the development of and refuelling time remain differentiating factors Total 69 88 114 large H2 transmission and distribution infrastructures that spur a continuing increase in the market enabling easy access for large and small consumers. share of FCEVs.

An open hydrogen market is created where H2 is freely traded, resembling the current market for Finally, the hydrogen infrastructure has provided Concluding remarks

natural gas in regions with well-developed gas momentum for increased use of H2 for heating in This paper reaffirms the exciting potential for hydrogen as an energy infrastructure, with national hydrogen transmission buildings. The momentum for switchover to electric carrier. It could play a significant role in decarbonizing the gas that will

system operators (TSOs) and distribution system heating is slow, since blue H2 is broadly available, be delivered to our homes and businesses, while transforming operators (DSOs). Businesses and residential users and generally has a lower carbon footprint than the carbon footprint of mobility. pay a fee to be connected to the hydrogen grid, and electric heating. However, a switchover to electric

a tariff is paid per kgH2 delivered. Industries with a heating frequently occurs when blue hydrogen For hydrogen to become a decarbonization agent, it must be either high consumption tend to have dedicated on-site production facilities reach end-of-life. green (produced from renewable energy) or blue (produced from

H2 production. fossil fuels with CCS). These methods have comparable carbon footprints and may achieve cost parity in the 2030s. They will broadly serve different markets, however. Blue hydrogen will be used largely for heating in buildings and industry, while green hydrogen will be used principally for mobility.

As our industry sharpens its focus on decarbonization for the long-term supply of sustainable and affordable energy, DNV GL continues to work in close partnership with our clients to make hydrogen a safe and cost-effective contributor to the world energy mix.

LIv A. Hovem CEO, DNV GL - Oil & Gas

(i) Bloomberg New Energy Finance(38) expects that USD548 billion will be invested in battery capacity by 2050, adding nearly 1.3 GW of new battery capacity by then (1.9 GW cumulative capacity was installed by 2017(39)), and where some 40% of this will be placed behind-the-meter. This implies that the global capacity behind-the-meter will be about 500 GW. If we assume that the battery storage capacity is 2.5 load hours, and one full cycle daily with 90% roundtrip efficiency(40), then the global behind-the-meter battery stock will ** This corresponds to the number of heavy FCEVs projected by the DNV GL 2018 Energy Transition Outlook(1). We have, however, applied deliver some 400 TWh. a higher fuel consumption per vehicle since we assume here that the heavy FCEV fleet consists only of MFTs, HFTs and buses. 48 Hydrogen as an energy carrier References 49

REFERENCES

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4 ‘Shell hydrogen study: Energy of the future? Sustainable mobility through fuel cells and H2’, Shell (2017). 24 Nicola Di Giulio, personal communication. https://www.shell.com/energy-and-innovation/the-energy-future/future-transport/hydrogen.html 25 ‘Power-to-hydrogen IJmuiden Ver, Final report for TenneT and Gasunie’, DNV GL (2018). 5 ‘Climate change 2014: Mitigation of climate change. Contribution of working group III to the fifth assessment report of https://energeia-binary-external-prod.imgix.net/BpYcGn72X6yptV0GnP90H-qLaSI.pdf?dl=Power-to-Hydrogen+I- the Intergovernmental Panel on Climate Change’, IPCC (2014), Cambridge University Press, Cambridge, UK, and New Jmuiden+Ver.pdf York, NY, US. www.ipcc.ch/report/ar5/wg3 26 ‘Costs of CO2 transportation infrastructures’, W Mallon et al (2013). Energy Procedia 37, 2969-2980. 6 ‘Life cycle assessment harmonization’, National Renewable Energy Laboratory, US. https://www.researchgate.net/publication/269942108_Costs_of_CO2_Transportation_Infrastructures https://www.nrel.gov/analysis/life-cycle-assessment.html 27 ‘The costs of CO2 storage. Post-demonstration CCS in the EU’, ZEP (2011). https://hub.globalccsinstitute.com/sites/

7 ‘Trends in global CO2 and total greenhouse gas emissions’, PBL Netherlands Environmental Protection Agency (2017). default/files/publications/119816/costs-co2-storage-post-demonstration-ccs-eu.pdf www.pbl.nl/en/publications/trends-in-global-co2-and-total-greenhouse-gas-emissions-2017-report 28 The costs of CO2 transport: Post-demonstration CCS in the EU’, ZEP (2011). 8 H21 Leeds City Gate (2017). https://www.northerngasnetworks.co.uk/wp-content/uploads/2017/04/H21-Report-In- www.zeroemissionsplatform.eu/downloads/813.html ter¬active-PDF-July-2016.compressed.pdf 29 ‘BP statistical review of world energy 2017’, BP (2017). 9 ‘Development of water electrolysis in the European Union’, Fuel Cells and Hydrogen Joint Undertaking (2014). https://www.bp.com/content/dam/bp-country/de_ch/PDF/bp-statistical-review-of-world-energy-2017-full-report.pdf https://www.fch.europa.eu/sites/default/files/study%20electrolyser_0-Logos_0_0.pdf 30 ‘The future of trucks: Implications for energy and the environment’, IEA (2017). 10 ‘Heat of combustion’, Wikipedia. https://webstore.iea.org/the-future-of-trucks https://en.wikipedia.org/wiki/Heat_of_combustion 31 ‘Fuel-cell and battery electric vehicles compared’, CE Thomas, H2Gen Innovations, Alexandria, Virginia, US. 11 ‘Tank to oil efficiency, D Serpa, AfterOil EV SM. https://www.energy.gov/sites/prod/files/2014/03/f9/thomas_fcev_vs_battery_evs.pdf www.afteroilev.com/Pub/EFF_Tank_to_Wheel.pdf 32 ‘Global transport scenarios 2050’, World Energy Council (2018). 12 ‘Transitioning to zero-emission heavy-duty freight vehicles’, M Moultak et al, ICCT (2017). https://www.worldenergy.org/wp-content/uploads/2012/09/wec_transport_scenarios_2050.pdf https://www.theicct.org/sites/default/files/publications/Zero-emission-freight-trucks_ICCT-white-paper_26092017_vF.pdf 33 ‘What drives new investments in low-carbon ammonia production? One million tons per day demand’, Ammonia 13 ‘Energy technology perspectives: Tracking clean energy progress 2017 – Industry’, IEA (2017). Industry (2018). https://ammoniaindustry.com/what-drives-new-investments-in-low-carbon-ammonia/ www.iea.org/etp/tracking2017/industry 34 ‘World agriculture towards 2030/2050: The 2012 Revision’, ESA working paper no. 12-03, Food and Agriculture 14 ‘Decarbonization of industrial sectors: The next frontier’, McKinsey & Company (2018). Organization of the United Nations (2012). www.fao.org/fileadmin/templates/esa/Global_persepctives/world_ https://www.mckinsey.com/~/media/mckinsey/business%20functions/sustainability%20and%20resource%20produc- ag_2030_50_2012_rev.pdf tivity/our%20insights/how%20industry%20can%20move%20toward%20a%20low%20carbon%20future/decarboniza- tion-of-industrial-sectors-the-next-frontier 35 ‘Producing ammonia and fertilizers: new opportunities from renewables’, IEA (2017). http://www.ee.co.za/wp-content/ uploads/2017/06/Producing-ammonia-and-fertilizers-new-opportunities-from-renewables.pdf 15 ‘Iron and steel: tracking clean energy progress’, IEA (2018). www.iea.org/tcep/industry/steel 36 ‘Technology roadmap: Hydrogen and fuel cells’, IEA (2015). https://www.iea.org/publications/freepublications/publication/TechnologyRoadmapHydrogenandFuelCells.pdf 16 ‘World steel in figures 2018’, World Steel Association (2018). https://www.worldsteel.org/en/dam/jcr:f9359dff-9546-4d6b-bed0-996201185b12/World+Steel+in+Figures+2018.pdf 37 ‘Methanol industry overview’, IHS Markit (2017). https://ngi.stanford.edu/sites/default/files/Alvarado_Stanford_Methanol_Meeting_2017.pdf

17 ‘Global energy & CO2 status report 2017’, IEA (2018). https://www.iea.org/publications/freepublications/publication/GECO2017.pdf 38 ‘New energy outlook 2018’, BNEF (2018). https://bnef.turtl.co/story/neo2018 18 ‘HIsarna ironmaking process’, Wikipedia. https://en.wikipedia.org/wiki/HIsarna_ironmaking_process 39 ‘Global battery storage pipeline hits record 10.4 GW in first quarter of 2018’, Energy Storage Networks, 16 April 2018. https://www.energystoragenetworks.com/global-battery-storage-pipeline-hits-record-10-4-gw-in-first-quarter-of-2018/ 19 ‘Summary of findings from HYBRIT pre-feasibility study 2016–2017’, HYBRIT (2017). https://www.hybritdevelopment.com 40 Website for Tesla home battery product Powerwall. https://www.tesla.com/no_NO/powerwall 20 ‘On the economics of offshore energy conversion: Smart combinations’, Energy Delta Institute (2017). https://www.gasmeetswind.eu/wp-content/uploads/2017/05/EDI-North-Sea-smart-combinations-final-report-2017.pdf 50 Hydrogen as an energy carrier Appendix A: ExplEnergy — energy value chain explorer 51

Example: Production paths Here we compare the following paths for producing low-carbon hydrogen:

■■Steam methane reforming (SMR) with carbon capture and storage (CCS); ■■Coal gasification with CCS;

■■Electrolysis (carbon footprint of electricity = 50 kgCO2e/GJ); and APPENDIX A: ■■Biomass gasification (without CCS). The feedstock amount is calibrated to let each production path deliver 100 ktH2 per year. For the investment annuity factor, we assume a 7% interest rate and an asset lifetime of 20 years. The remaining input parameters EXPLENERGY — are shown in Table 10. Table 10: Parameters for hydrogen production paths. Graphic: DNV GL ENERGY VALUE Parameter SMR + CCS Coal gasif. + CCS Electrolysis Biomass gasif. Fuel cost (USD/GJ) 6.0 2.5 20.0 10.0 GHG emissions Fuel: 16.0 Fuel: 7.5 Fuel: 50.0 Fuel: 3.0 CHAIN EXPLORER (kgCO2e/GJ) SMR+CCS: 10.0 CG + CCS: 10.0 Electrolysis: 0 Biomass G.: 5.5 Loss (%) 27 49 33 54 CAPEX (USD/W) 0.80 2.40 1.25 0.80 ExplEnergy is a web application that enables users to customize energy value chains and estimate the OPEX (USD/GJ) 1.83 5.81 0.80 4.44 associated energy flow, capital expenditure (CAPEX), operational expenditure (OPEX), greenhouse gas SMR, steam methane reforming; gasif., gasification; CCS, carbon capture and storage; USD, US dollars; GJ,

(GHG) footprint and cost of output energy. The application interfaces to a DNV GL-hosted database with low, gigajoules; kgCO2e/GJ, kilogram of carbon dioxide equivalent per GJ; CAPEX, capital expenditure; W, watts; typical and high values for energy loss, CAPEX, OPEX and GHG emissions for a selection of value chain OPEX, operational expenditure. components, and allows easy visual comparison of two or more value chains within the same chart.

The methodology for computing the cost of hydrogen delivered is based on these assumptions: Figure 20 illustrates the costs per kgH2 output for the four production paths involving the inputs above. The lower and upper segments of each bar represent respectively the fuel cost and the cost contribution

■■GJinit = Lower heating value (LHV) energy content of annual supply of the initial energy carrier. from the production facility. Section 3.2.1 found that the electrolysis cost is expected to decline because of a

■■GHGinit = GHG emissions associated with the production and delivery of the initial energy carrier. substantive drop in the CAPEX per watt cost of electrolysers accompanied by lower electricity prices.

■■CoEinit = Annual cost of the initial energy carrier.

Furthermore, for a component X in an energy value chain: OUTPUT COST OF ENERGY FROM FOUR HYDROGEN PRODUCTION METHODS

■■EX = Component energy efficiency based on the LHV energy content. ■■GHGX = GHG emissions associated with the component. oss > syngas > ■■OPEXX = The component’s annual OPEX.

2 Internationally-traded biomass ■■CAPEXX = The component’s CAPEX. L L Power-to-H ■■AX = Annuity factor for the component = ((1+I) - 1) / (I*(1+I) ), where L = lifetime of asset, and I = interest rate. No inflation or discount rates are applied. Electricity from grid Coal gasification with CCS Let E = ∏X EX. The cost of delivered hydrogen from the energy value chain per gigajoule (LHV) is then: Other S S CoH = [CoEinit + ∑all components (CAPEXX/AX + OPEXX)]/(GJinit * E), Natural gas (production)

and the accumulated GHG emissions from the energy value chain is GHG = GHGinit + ∑X GHGX. Cost of S/kgH Cost energy

The value chain components are dimensioned to allow processing, transport or storage of the input energy flow (output from previous component). For bulk transport options, such as ships and trucks, the input energy S S o Electrolysis oss flow is converted to total bulk capacity of fleet based on user-provided data on transit speed and utilization gasification gasification S factor. For storage components, the user must provide the maximum number of required days of storage per ‘filling’. The storage system is then dimensioned to allow storage of an amount of energy equivalent to the defined number of days input energy flow. Figure 20: Comparison of output cost of energy from four hydrogen production methods. Source: DNV GL 52 Hydrogen as an energy carrier Appendix A: ExplEnergy — energy value chain explorer 53

Example: Transport and storage options produced H2 to location B. This trade-off may COST-OF-ENERGY PENALTY BY SHIPPING AND PIPELINE TRANSPORT The modes of transport and storage considered be relevant if there is a need to invest in either a OF HYDROGEN IN DIFFERENT STATES were depicted in Figure 1. ExplEnergy has been power transmission infrastructure or a hydrogen used to arrive at the following general conclusions transmission infrastructure, such as for the cases

regarding transport and storage of hydrogen: considered in Section 4. The choice between these two options will therefore depend on trsort sh ■■If subsurface salt caverns are available, or if project-specific considerations and opportunities o trsort sh existing pipeline infrastructure can provide buffer for cost saving, such as the available infrastructure. u hroe trsort sh storage of H , then these are by far the lowest-cost 2 roe ees options for storing hydrogen. In Figure 21, we provide two examples comparing Pipeline is onshore the cheapest mode of transport four different fuel-state changes (compression, ■■ for large quantities of H2 (tens to hundreds of liquefaction, ammonia synthesis, hydrogenation)

kilotonnes per year). and different modes of ocean H2 transport. For these ■■Transmitting electricity from location A to comparisons, the interest rate is set to 5% and the location B and performing electrolysis at location lifetime of all assets is 20 years. The hydrogen is B is generally cost comparable with doing produced by electrolysis using grid electricity at of S/G Cost energy the electrolysis at location A and piping the USD15/GJ (USD54/MWh). o ee sh sh sh COST-OF-ENERGY PENALTY FROM HYDROGEN FUEL-STATE CHANGES

Figure 22: Cost-of-energy penalty from 1,000 km transport by ship of hydrogen in three different states, and by pipeline for CGH. We assume that the ship has an average speed of 14.7 knots (27.2 km/h) and is in transit 35% of the time. We toto e touee note that transport of LH by ship is slightly cheaper than transmitting CGH by pipeline, and that transporting ammonia and

oto LOHC by ship are the least-costly options. The difference between LOHC and ammonia primarily reflects the latter’s greater

too higher hydrogen density. Graphic: DNV GL uecto o hroe COST-OF-ENERGY PENALTY FROM FOUR HYDROGEN VALUE CHAINS oresso o ro to r

Store rsort

Cost of S/G Cost energy oerso

oresso uecto o coerso coerso

Figure 21: Cost-of-energy penalty from hydrogen fuel-state changes. Here, LOHC (liquid organic hydrogen carrier) conversion refers to hydrogenation of toluene to methylcyclohexane and its subsequent dehydrogenation. The cost of

electrolysis is factored. Graphic: DNV GL of S/G Cost energy

As the bar for liquid hydrogen (LH) in Figure 22 indicates, transporting pure H2 by ship is very costly, primarily o e coresse seous hroe owing to the high CAPEX required. The cost of transporting compressed H2 is even greater. Therefore, rather than including a cost comparison for compressed hydrogen (CGH) by ship we consider its transport by ue ch ue ch ue ch ue ch u hroe u orc hroe crrer submarine pipeline. Figure 23: Cost-of-energy penalty from four hydrogen value chains. Graphic: DNV GL Since conversion is a significant part of the costs for storage and transport of LH, ammonia and LOHC, and this is generally only done once, it may also be instructive to consider some broader value chains involving These results indicate that transport and storage of liquid hydrogen has a high cost, in part due to high both transport and storage. Figure 23 compares the following energy value chains: energy losses from liquefaction and high cost of hydrogen ships. For the example considered, transport and storage of CGH and ammonia have similar costs. But the cost components are very different. For ammonia, ■■CGH: 1,000 km by submarine pipeline > compression to 350 bar > 50 km by truck > storage. the major cost components are the ammonia synthesis and reforming. For longer distances, or increased ■■LH: Liquefaction > 1,000 km by ship > 50 km by truck > storage. need for storage, ammonia may be the better option. The main cost components in the CGH value chain are ■■Ammonia: Ammonia synthesis > 1,000 km by ship > 50 km by truck > storage > reformation. the hydrogen pipelines and the storage in tanks. It should be noted that subsurface storage is another and ■■LOHC: Hydrogenation > 1,000 km by ship > 50 km by truck > storage > dehydrogenation. less costly option for storage of CGH when suitable formations are available. The clearly cheapest option overall is transport and storage of hydrogen as a hydrogenated LOHC. 54 Hydrogen as an energy carrier Appendix B: 2050 scenario elements 55

APPENDIX B: 2050 SCENARIO ELEMENTS

An era of energy autonomy Electrolysis displaces gas reforming As distributed solar photovoltaic (PV) becomes The expansion of renewable electricity generation commonplace, and electricity consumers become and decline in the capital expenditure for prosumers, more battery capacity is required. electrolysers has made electrolysis the cheapest Hydrogen offers greater electricity storage way of producing hydrogen. Production capacity capacity, and the opportunity to use surplus additions are predominantly electrolysis facilities, electricity for fuel-cell electric vehicles, thereby with units varying from home modules to achieving energy autonomy. large-scale plants.

Typical residential concepts include PV and battery Hydrogen production from fossil fuels without pack, electrolysis, compression, storage, and carbon capture and storage (CCS) is generally not fuel-cell. A hydrogen dispenser may be on the permitted, and hydrogen production with CCS is premises, or at a neighbourhood dispenser station. uncompetitive. Existing fossil hydrogen production plants are replaced by electrolysis at end-of-life, Developers of this concept include homes, or retired when continued production businesses, and communities. becomes uneconomic.

Hydrogen supply is for big players Industry is forced to decarbonize While the share of hydrogen production by Industry represents more than 25% of greenhouse electrolysis is increasing, most production of it is gas emissions. Carbon pricing proved difficult to still from gas reforming. implement effectively on a global scale.

Due to substantial benefits of scale, the majority Decarbonization is driven by a mix of regulation, of electrolysis facilities are large scale. industry-specific emission standards, and carbon price. Measures deployed depend on context Hydrogen producers usually have bilateral supply (e.g. CCS readiness, gas/coal availability, electricity agreements with principal buyers. Less than 10% mix, cost of hydrogen production, etc.). of global hydrogen production is freely traded. Blue or green hydrogen is used in hydrogen The producer often owns the transmission feedstock industries. infrastructure (e.g. transmission pipelines and seasonal gas storage), whereas the big buyers own New steel plants deploy direct reduced iron process distribution infrastructure (e.g. distribution pipes, using hydrogen as the reductant. refuelling stations, and storage tanks). Other industries (e.g. cement and aluminium) opt for CCS and electrification. 56 Hydrogen as an energy carrier Appendix B: 2050 scenario elements 57

Fuel cells are No. 1 for heavy electric vehicles No more gas/hydrogen-based building heat Heavy fuel-cell electric vehicles (FCEVs) have lower Despite some early, albeit slow, uptake of hydrogen capital expenditure and longer range than heavy for heating in buildings in the late 2020s and early battery electric vehicles (BEVs), principally because 2030s, investment in further infrastructure tailed off it is cheaper to increase the size of a hydrogen tank as heating was gradually electrified in countries with than to add battery capacity. gas-based heating.

Hydrogen fuelling infrastructure is well developed on The need for CCS and hydrogen storage in the major highway grid. The shorter refuelling time subsurface formations constrained the uptake of is also a key differentiator over battery electric hydrogen for heating solutions. There is limited solutions for heavy trucks and buses. pipeline infrastructure for hydrogen distribution, and few subsurface formations for seasonal hydrogen BEVs have lower fuel costs than FCEVs, but the total storage. Hydrogen transmission pipelines exist in cost of ownership of heavy FCEV trucks and buses is countries with high uptake of fuel-cell electric vehicles. roughly on a par with that for corresponding BEVs. Biomass (e.g. wood), biogas for combined heat and power (CHP), and fuel cells for CHP are still commonly deployed.

Light vehicles are largely battery electric Infrastructure enables H2 prosumer economy BEV technology has a satisfactory range and fuelling Hydrogen is produced by a mix of large and small time for light vehicles, and a lower total cost of suppliers. Infrastructure companies provide ownership than for cars with internal combustion indiscriminate access to a hydrogen infrastructure, engines or fuel cells. and charge tariffs for hydrogen transport and storage costs. Lack of adequate hydrogen infrastructure constrains uptake of FCEV options in rural areas and some Much infrastructure is local, unconnected to a geographies. Recharging infrastructure for BEVs is transmission network, thereby feeding hydrogen almost universally accessible. only to local consumers, such as a neighbourhood, campus, or some fuelling stations. In line with forecasts in DNV GL's 2018 Energy Transition Outlook, there are 1.6 billion (bn) light A hydrogen prosumer economy has developed in vehicles in 2050, of which 1.4bn are BEV or FCEV. parallel with a power prosumer economy. 58 Hydrogen as an energy carrier Appendix C: Abbreviations 59

PWh Petawatt hour t Metric tonne TWh Terawatt W Watt yr Year APPENDIX C:

ABBREVIATIONS Technical, scientific and financial terms AC Alternating current BF-BOF Blast furnace to basic oxygen furnace Units BEV Battery electric vehicle “ Inches CAPEX Capital expenditure bar 1 bar pressure = 100 kilopascals CCS Carbon capture and storage bcf Billion cubic feet CCUS Carbon capture, utilization and storage °C Degree Celsius CGH Compressed gaseous hydrogen

CO2e Carbon dioxide equivalent CHP Combined heat and power

EJ Exajoule CO2 Carbon dioxide g Gram DC Direct current GJ Gigajoule DRI Direct reduced iron Gt Gigatonne DSO Distribution system operator GWh Gigawatt hour EAF Electric arc furnace h Hour FCEV Fuel-cell electric vehicle J Joule GHG Greenhouse gas

kcf Thousand cubic feet H2 Hydrogen (in general) kg Kilogram HFT Heavy freight truck km Kilometre HV Heavy vehicle kn Knot ICEV Internal combustion engine vehicle kt Kilotonne LCOH Levelized cost of hydrogen kSm3 Thousand standard cubic metres LOHC Liquid organic hydrogen carrier kV Kilovolt LCV Light commercial vehicle kW Kilowatt LH Liquid hydrogen KWh Kilowatt hour LHV Lower heating value l Litre LV Light vehicle m Metre MFT Medium freight truck MJ Megajoule NPV Net present value Mt Megatonne OPEX Operational expenditure MTOE Million tonnes of oil equivalent P2P Power-to-power Mtpa Million tonnes per annum PV Photovoltaic MW Megawatt SER Sorption-enhanced reforming MWh Megawatt hour SMR Steam methane reforming Nm3 Normal cubic metres TCO Total cost of ownership pa Per annum TSO Transmission system operator PJ Petajoule VRES Variable renewable energy sources SAFER, SMARTER, GREENER

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