Hydrogen Insights
A perspective on hydrogen investment,
market development and costcompetitivenessFebruary 2021

Published in January 2021 by the Hydrogen Council. Copies of this document are available uponrequest or can be downloaded from our website:www.hydrogencouncil.com.
„This report was authored by the Hydrogen Council in collaboration with McKinsey & Company.“
The authors of the report confirm that:
1. There are no recommendations and/or any measures and/or trajectories within the report that
could be interpreted as standards or as any other form of (suggested) coordination between
the participants of the study referred to within the report that would infringe EU competition law;and2. It is not their intention that any such form of coordination will be adopted.
Whilst the contents of the Report and its abstract implications for the industry generally can be
discussed once they have been prepared, individual strategies remain proprietary, confidential andthe responsibility of each participant. Participants are reminded that, as part of the invariable
practice of the Hydrogen Council and the EU competition law obligations to which membership
activities are subject, such strategic and confidential information must not be shared orcoordinated – including as part of this Report.

Hydrogen Insights Report 2021
Hydrogen Council, McKinsey & Company

Contents

Executive summaryiii

I. Introduction and methodology

2— Hydrogen Insights is a leading global perspective on hydrogen

2— The Hydrogen Insights report methodology

3

II. Deployment and investment

6— Tremendous momentum exists, with over 200 H2 projects announced worldwide

6— More than USD 300 billion in H2 investments through 2030

7

— Regulation and government support drive this momentum

8

III. Hydrogen supply

12— Renewable hydrogen could break even with gray H2 before 2030 in optimal regions

12— Electrolyzer capex savings can reduce costs quickly in a rapid global scale-up

15— Expected electrolyzer learning curves could be too conservative

15

IV. Hydrogen distribution and global supply chains18— The optimal H2 transport mode will vary by distance, terrain and end-use:
no universal solution exists

18— Hydrogen pipelines20— Hydrogen carriers

21— Hydrogen global transport can cost less than USD 2-3/kg

24

V. End applications

26— The cost competitiveness of hydrogen applications

26— Hydrogen production cost breakeven

27

A. Road transport and mining equipment
B. Ammonia
C. Steel
D. Sustainable shipping fuels
E. Aviation

28
31
32
34
37

VI. Implementation: bringing it all together to capture the promise of hydrogen

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42

iii

Executive summary

Hydrogen is gathering strong momentum as a key energy transitionpillarUnderpinned by a global shift of regulators, investors, and consumers toward decarbonization,hydrogen (H2) is receiving unprecedented interest and investments. At the beginning of 2021,
over 30 countries have released hydrogen roadmaps, the industry has announced more than 200
hydrogen projects and ambitious investment plans, and governments worldwide have committed
more than USD 70 billion in public funding. This momentum exists along the entire value chain andis accelerating cost reductions for hydrogen production, transmission, distribution, retail, and end
applications.
Similarly, having grown from 60 to over 100 members since 2020, the Hydrogen Council now
represents more than 6.6 trillion in market capitalization and more than 6.5 million employees globally.
This report provides an overview of these developments in the hydrogen ecosystem. It tracks
deployments of hydrogen solutions, associated investments and the cost competitiveness ofhydrogen technologies and end applications. Developed collaboratively by the Hydrogen Council and
McKinsey & Company, it offers a fact-based, holistic, quantitative perspective based on real industry
data. Along with the report, the Hydrogen Council is launching Hydrogen Insights - a subscription
service that provides granular insights and data about the hydrogen ecosystem and its development.

Deployment and investments: Announced hydrogen investments
have accelerated rapidly in response to government commitments
to deep decarbonization
More than 200 hydrogen projects now exist across the value chain, with 85% of global projects
originating in Europe, Asia, and Australia, and activity in the Americas, the Middle East and North
Africa accelerating as well.
If all projects come to fruition, total investments will exceed USD 300 billion in hydrogen spending
through 2030 – the equivalent of 1.4% of global energy funding. However, only USD 80 billion ofthis investment can currently be considered “mature,” meaning that the investment is either in aplanning stage, has passed a final investment decision (FID), or is associated with a project underconstruction, already commissioned or operational.
On a company level, members in the Hydrogen Council are planning a sixfold increase in their totalhydrogen investments through 2025 and a 16-fold increase through 2030. They plan to direct most of
this investment toward capital expenditures (capex), followed by spending on merger and acquisition(M&A) and research and development (R&D) activities.
The global shift toward decarbonization backed by government financial support and regulation
is supporting this momentum. For instance, 75 countries representing over half the world’s GDP
have net zero carbon ambitions and more than 30 have hydrogen-specific strategies. Governments
have already pledged more than USD 70 billion and included new capacity targets and sector level
regulation to support these hydrogen initiatives. For example, the EU has announced a 40-gigawatt(GW) electrolyzer capacity target for 2030 (up from less than 0.1 GW today) and more than 20
countries have announced sales bans on internal combustion engine (ICE) vehicles before 2035.
In the US, where federal emission standards for new vehicles have lagged behind those in the EU,
state-level initiatives in California and 15 other states have set ambitious targets to transition not
only passenger cars but also trucks to zero-emission status by 2035. In China, the 2021-24 fuel cell
support program will see the equivalent of USD 5 billion spent on fuel cell vehicle deployment, with astrong emphasis on the development of local supply chains.

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Supply: If scaled up with the right regulatory framework, cleanhydrogen costs can fall faster than expectedWith the advent of hydrogen giga-scale projects, hydrogen production costs can continue to fall.
For renewable hydrogen, the biggest driver is a quicker decline in renewables costs than previously
expected, driven by at-scale deployment and low financing costs. 2030 renewable costs could be
as much as 15% lower than estimated just a year ago. The strongest reductions are expected inlocations with optimal resources such as Australia, Chile, North Africa and the Middle East.
But lower renewable costs are not enough: for low-cost clean hydrogen production, value chains forelectrolysis and carbon management need to be scaled up. This will not happen on its own: a further
step-up of public support is required to bridge the cost gap, develop low-cost renewable capacities
and scale-up carbon transportation and storage sites. For the cost projections in this report, we
assume an ambitious development of the use of hydrogen in line with the Hydrogen Council vision.
For electrolysis, for example, we assume 90 GW deployment by 2030.
Such a scale-up will lead to a rapid industrialization of the electrolyzer value chain. The industry has
already announced electrolyzer capacity increases to over approximately 3 GW per year, and will needto scale rapidly beyond that. This scaling can translate into system costs falling faster than previously
estimated, hitting USD 480-620 per kilowatt (kW) by 2025 and USD 230-380 per KW by 2030. Systemcosts include stack and balance of plant but exclude transportation, installation and assembly, costs ofbuilding and any indirect costs.
At-scale deployment of renewable hydrogen will require the development of giga-scale hydrogenproduction projects. Such projects with purpose-built renewables can boost utilization by merging
multiple renewable sources, such as a combined supply from onshore wind and solar photovoltaics(PV), and by overbuilding renewables supply versus electrolyzer capacity.
In combination, projections show that renewable hydrogen production costs could decline to USD
1.4 to 2.3 per kilogram (kg) by 2030 (the range results from differences between optimal and averageregions).1 This means new renewable and gray hydrogen supply could hit cost parity in the best
regions by 2028, and between 2032 and 2034 in average regions.
In parallel to renewable hydrogen production, low-carbon hydrogen production from natural gas has
continued to evolve technologically. With higher CO2 capture rates and lower capex requirements,
low-carbon hydrogen production is a strong complementary production pathway. If carbon transportationand storage sites are developed at scale, low-carbon hydrogen could break even with gray hydrogenby the end of the decade at a cost of about USD 35-50 per ton (t) of carbon dioxide equivalent (CO2e)1.

Distribution: Cost-efficient transmission and distribution required to
unlock hydrogen applications
With hydrogen production costs falling, transmission and distribution costs are the next frontier whenit comes to reducing delivered hydrogen costs. Longer-term, a hydrogen pipeline network offers themost cost-efficient means of distribution. For example, pipelines can transmit 10 times the energy
at one-eighth the costs associated with electricity transmission lines and have capex costs similar
to those for natural gas. The industry can partially reuse existing gas infrastructure, but even newly
constructed pipelines would not be cost prohibitive (assuming leakage and other safety risks areproperly addressed). For example, we estimate the cost to transport hydrogen from North Africa

1

These costs reflect pure production costs and assume a dedicated renewable and electrolysis system for renewable hydrogen.
They do not include costs required for baseload supply of hydrogen (e.g., storage and buffers), costs for redundancies, services
and margins; they also do not include any cost for hydrogen transportation and distribution.

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to central Germany via pipeline could amount to about USD 0.5 per kg of H2 – less than the costdifference of domestic renewable hydrogen production in these two regions.
In the short- to medium-term, the most competitive setup for large-scale clean hydrogen applications
involves co-locating hydrogen production on- or near-site. The industry can then use this scaled
production to supply the fuel to other hydrogen users in the vicinity, such as refueling stations fortrucks and trains, and smaller industrial users. Trucking the fuel to such users typically offers themost competitive form of distribution, with costs below USD 1 per kg of H2.
For longer-distance transport by ship, hydrogen needs to be converted to increase its energy density.
While several potential hydrogen carrier approaches exist, three carbon-neutral carriers – liquidhydrogen (LH2), liquid organic hydrogen carriers (LOHC) and ammonia (NH3) – are gaining mosttraction.2 The cost-optimal solution depends on the targeted end-use, with deciding factors including
central versus distributed fueling, the need for reconversion, and purity requirements.
At-scale, international distribution could arrive by 2030 at total costs of USD 2-3/kg (excluding costof production), with the lion´s share of costs needed for conversion and reconversion. For example, if
the targeted end application is ammonia, shipping costs add only USD 0.3-0.5/kg to the total cost. If
the targeted end application is for liquid hydrogen or hydrogen with a high purity requirement, shipping
as liquid hydrogen might add only USD 1.0-1.2/kg, with additional benefits for further distribution fromport. These cost levels would enable global trade in hydrogen, connecting future major demand centerssuch as Japan, South Korea, and the EU to regions of abundant low-cost hydrogen production means
like the Middle East and North Africa (MENA), South America or Australia. Like hydrogen production,
carriers need substantial initial investments, and the right regulatory framework to bridge the cost delta
in the first decade.

End applications: Falling clean hydrogen costs and applicationspecific cost drivers improve the cost competitiveness of hydrogen
applications
From a total cost of ownership (TCO) perspective (including hydrogen production, distribution andretail costs) hydrogen can be the most competitive low-carbon solution for 22 end applications,
including long haul trucking, shipping and steel. However, pure TCO is not the only driver ofapplication adoption: future expectations on environmental regulations, demands from customers
and associated “green premiums,” as well as the lower cost of capital for ESG-compliant investments
will all influence investment and purchase decisions.
In industry, lower hydrogen production and distribution costs are particularly important for costcompetitiveness as they represent a large share of total costs. Refining is expected to switch to
low-carbon hydrogen over the next decade. For fertilizer production, green ammonia producedwith optimized renewables should be cost competitive by 2030 against gray ammonia producedin Europe at a cost of less than USD 50 per ton of CO2e. Steel, one of the largest industrial CO2
emitters, could become one of the least-cost decarbonization applications. With an optimized setup
using scrap and hydrogen-based direct reduced iron (DRI), green steel could cost as little as USD
515 ton of crude steel, or a premium of USD 45 per ton of CO2e by 2030.
In transport, lower hydrogen supply costs will make most road transportation segments competitive
with conventional options by 2030 without a carbon cost. While battery technology has advanced
rapidly, fuel cell electric vehicles (FCEVs) are emerging as a complementary solution, in particular forheavy-duty trucks and long-range segments. In heavy-duty long-haul transport, the FCEV option canachieve breakeven with diesel in 2028 if hydrogen can be made available for USD 4.5 per kg at the2viSynthetic methane produced from biogenic or air-captured CO2 represents a potential fourth candidate to be studied further.

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pump (including hydrogen production, distribution and refueling station costs). Furthermore, hydrogen
combustion (H2 ICE) offers a viable alternative in segments with very high power and uptime
requirements, including heavy mining trucks.
Hydrogen is likewise advancing in trains, shipping, and aviation. Clean ammonia as a shipping fuelwill be the most cost-efficient way to decarbonize container shipping by 2030, breaking even withheavy fuel oil (HFO) at a cost of about USD 85 per ton of CO2e.3 Aviation can achieve competitive
decarbonization via hydrogen and hydrogen-based fuels. The aviation industry can decarbonize
short- to medium-range aircrafts most competitively through LH2 directly, at a cost of USD 90-150
per ton of CO2e. Long-range aircrafts can be decarbonized most competitively using synfuels, at a
cost of about USD 200-250 per ton of CO2e, depending on the CO2 feedstock chosen.
Other end-applications such as buildings and power will require a higher carbon cost to become
cost competitive. However, as large-scale and long-term solutions to decarbonize the gas grid, they
will still see strong momentum. In the United Kingdom, for example, multiple landmark projects arepiloting the blending of hydrogen into natural gas grids for residential heating. Hydrogen as a backup
power solution, especially for high power applications like data centers, is also gaining traction.

Implementation: Capturing the promise of hydrogen
Strong government commitment to deep decarbonization, backed by financial support, regulationand clear hydrogen strategies and targets, has triggered unprecedented momentum in the hydrogen
industry. This momentum now needs to be sustained and the long-term regulatory framework set.
These ambitious strategies must now be translated into concrete measures. Governments, with
input from businesses and investors, should set sector-level strategies (e.g., for the decarbonizationof steel) with long-term targets, short-term milestones, and the necessary regulatory framework to
enable the transition. The industry must set up value chains for equipment, scale up manufacturing,
attract talent, build capabilities, and accelerate product and solution development. This scale up will
require capital, and investors will play an outsized role in developing and pushing at-scale operations.
All this will require new partnerships and ecosystem building, with both businesses and governments
playing important roles.
To get things started, strategies should aim at the critical “unlocks,” like reducing the cost ofhydrogen production and distribution. We estimate roughly 65 GW of electrolysis are required to bringcosts down to a break-even with gray hydrogen under ideal conditions, which implies a funding gapof about USD 50 billion for these assets. Support is also required to scale up carbon transport andstorage; hydrogen shipping, distribution and retail infrastructure; and the take up of end applications.
One place to support deployment is the development of clusters with large-scale hydrogen offtakers
at their core. These will drive scale through the equipment value chain and reduce the cost of hydrogenproduction. By combining multiple offtakers, suppliers can share both investments and risks while
establishing positive reinforcing loops. Other smaller hydrogen offtakers in the vicinity of such clusters
can then piggy-back on the lower-cost hydrogen supply, making their operations breakeven faster.
We see several cluster types gaining traction, including:— Port areas for fuel bunkering, port logistics, and transportation— Industrial centers that support refining, power generation, and fertilizer and steel production— Export hubs in resource-rich countries

3

Alternatives such as synthetic methane from biogenic or air-captured CO2 in current liquefied natural gas (LNG) vessels were notin the scope of this report and require further study.

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Successful clusters will likely involve players along the entire value chain to optimize costs, tap into
multiple revenue streams and maximize the utilization of shared assets. They should be open to
additional players and infrastructure should allow for ready access where possible.
The next few years will be decisive for the development of the hydrogen ecosystem, for achieving
the energy transition and for attaining the decarbonization objective. As this report shows, progressover the past year has been impressive, with unprecedented momentum. But much lies ahead. The
companies in the Hydrogen Council are committed to deploying hydrogen as a critical part of thesolution to the climate challenge and Hydrogen Insights will provide a regularly updated, objective
and global perspective on the progress achieved and the challenges ahead.

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Hydrogen Insights Report 2021
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Hydrogen Insights
draws upon thecollective knowledgeof Hydrogen Council
members

109
companies>6.8 >6.5
tm market cap

1

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mn employees

I | Introduction and methodology

Hydrogen Insights is a leading global perspective on hydrogen
The 109 members of the Hydrogen Council represent over USD 6.8 trillion in market capitalizationand more than 6.5 million employees. Hydrogen Insights represents a collaborative effort between
Hydrogen Council members and McKinsey & Company to bring forth an objective, holistic andquantitative perspective on the use of hydrogen as a decarbonization option based on real industrydata.
As such, Hydrogen Insights aspires to offer the pre-eminent industry perspective on market
deployment, investment momentum and cost competitiveness within the hydrogen industry. Alongwith the report, the Hydrogen Council is launching Hydrogen Insights as a subscription service,providing granular insights and data about the hydrogen ecosystem and its development.

Exhibit 1: Hydrogen Council Members

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2

The Hydrogen Insights report methodology
Before explaining the results, the following provides a description of the methodological approach
used in this analysis.
Evaluating hydrogen investment, deployment, and market momentum
The report team estimated the total hydrogen investment through 2030 based on an analysis ofthree main investment funding categories: direct investment into private sector projects, government
production targets and public funding, and upstream/indirect investment required to support
announced project investments.
Direct private sector investment. The report team’s estimates of company investments inhydrogen projects came from a database of publicly announced projects across the globe, validated
by the members of the Hydrogen Council. Using public deployment information and internal
projections, the team estimated required funding for these projects. It also classified projects bymaturity level, depending on whether they were at an early stage, in the planning phase, or alreadyhad committed funding. By combining these insights with investment data from Hydrogen Council
members that an independent third-party clean team collected, processed, and aggregated, thereport team gained insights into the relevant investment trends in the market.
Government production targets and public funding. The report team reviewed announced
government targets and compared them with the project pipeline to quantify the additional
capacity required to reach the targets. This additional capacity was then costed and included in theinvestment total as ´announced´ investment. Countries such as China, Japan and Korea, which rely
more heavily on announced public funding targets instead of capacity targets, were considered asa special case. In these countries, the report team reviewed announced government funding andcompared it with announced private investment from the project pipeline. By assuming that theexisting private projects received on average one-third of their total investment from the government(in most cases this information is not made public), the team could quantify the additional investment
expected from these governments and include it in the ´announced´ investment category.
Upstream investment. Lastly, the team estimated the upstream investment required to realize
direct private sector investments using industry revenue multipliers. It treated fuel cell and on-roadvehicle platforms separately, with a bottom-up estimation of R&D and manufacturing costs.
Evaluating hydrogen cost-competitiveness: production, distribution and application
The cost competitiveness analysis in the report built on the Hydrogen Council Study 2020 report,“Path to hydrogen competitiveness: a cost perspective”. This year´s report focused on adding newtechnologies and applications (such as shipping and aviation) and revisited areas where technology,
costs and underlying assumptions have changed.
Data for both perspectives were provided by Hydrogen Council members through an independent
third party “clean team” who collected, aggregated and processed the data to preserve anonymity.
In addition to these data, the report builds upon McKinsey Energy Insights modelling of renewables
costs and capacity factors, McKinsey Hydrogen Supply modelling, other proprietary assets, andnumerous benchmarks from external data providers and databases. The report team also tested andvalidated the findings from these analyses via over 25 expert interviews before the results and key
findings were presented to the Hydrogen Council study group. The study group, which consisted of
20 members of the Hydrogen Council, then validated, co-developed and tested these findings. The
full steering group of the Hydrogen Council subsequently reviewed and approved the report.
Volume ramp ups. The study assumed several deployment scenarios for hydrogen technology.
While not forecasts, these scenarios provided a way to analyze the effect of scale on cost3

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competitiveness. Volume ramp up assumptions reflected the required low-carbon and renewablehydrogen production volume scales needed to meet 18% of global final energy demand by 2050 (inline with the 2°C goal).
Hydrogen production costs. Throughout this report, “low-carbon” and “renewable” hydrogenare used as shorthand to describe the production of hydrogen from natural gas through a reforming
process with carbon capture (low-carbon hydrogen) and/or the production of hydrogen via waterelectrolysis from renewable electricity (renewable hydrogen). The focus on these two main pathways
does not exclude other production pathways that can form part of a hydrogen economy, such as
the reforming of biogas, pyrolysis, coal gasification, and others. Where the report mentions thesealternative pathways, it describes them as such.
The report team analyzed hydrogen production costs using a specific production configuration thatreflected the “base costs” of clean hydrogen production. This production configuration includes
a dedicated renewable energy and electrolysis system (excluding grid connection fees or addedtransmission line infrastructure), and fully flexible production (zero minimum load requirements that
require storage and oversizing of the generation capacity). Furthermore, it considered only raw
production costs (distinct from supply prices that include services, redundancies and margins) for ascaled industry to support the cost-down (90 GW installed by 2030).
Carriers and application analysis. Carriers and applications with specific low-carbon andconventional alternatives underwent total cost of ownership (TCO) comparisons. For example, one
analysis compared fuel-cell electric vehicles with battery electric vehicles (BEVs) with diesel vehicles.
Likewise, fuels for aviation compared hydrogen versus synfuels versus kerosene (jet fuel).
The report team developed TCO trajectories for each hydrogen application and technology and its
competing low carbon and conventional alternatives to identify relevant cost components. Moreover,
the team pinpointed factors driving cost reductions and break-even points among competing
solutions. Generally, it based hydrogen cost estimations on the average of low-carbon hydrogen(produced from natural gas reforming with carbon capture and storage) and renewable hydrogen(produced via renewable power and electrolysis).
Nevertheless, for some specific applications, a particular production method was assumed to reflectvariations across regions and their respective settings.
CO2 analysis. Throughout the report, CO2 played two different roles. On one hand, it could function
as feedstock for applications such as methanol (MeOH) shipping fuel. On the other, it represented
greenhouse gas emissions that harm the environment. Although various ways exist to capture or
obtain CO2 feedstock (e.g., industrial capture or biogenic CO2), this report assumed it was extracted
from the atmosphere using direct air capture (DAC) technology. Hence, the report assumed theresulting product was produced in a carbon-neutral way.
The team conducted all analyses without assuming that implicit CO2 emission costs penalized
applications and technologies that emit CO2. However, for some specific cases it did apply CO2
costs. In those cases, the analysis clearly describes the implicit CO2 emission costs.
Currency. All financial figures are in US dollars (USD) and refer to global averages unless otherwise
indicated.

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4Hydrogen Insights
Investments
into
draws
upon
thegatheringhydrogenarecollective
momentumknowledgeof Hydrogen Council
members>200
109

projects have been announced globally withcompanies

>6.8
>6.5
>80
bn
tm marketin cap
mn employees
mature hydrogen investment

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II | Deployment and investment

Tremendous momentum exists, with over 200 H2 projects announced worldwide
Globally, there are 228 hydrogen projects across the value chain (see Exhibit 2). Of these, 17 arealready-announced giga-scale production projects (i.e. more than 1 GW4 for renewable and over 200
thousand tons a year for low-carbon hydrogen), with the biggest in Europe, Australia, the Middle East
and Chile.

Exhibit 2: Global hydrogen projects across the value chain

Projects per region:

126 Europe
46 Asia
24 Oceania
19 North America
8 Middle East and Africa

228

5 Latin America
17
Giga-scale production:
renewable H2 projects>1GW and low-carbon H2
projects>200 kt p.a.

90
Large-scale industrial
usage: refinery, ammonia,
power, methanol, steel,and industry feedstock

announced projects

53

45

Transport: trains, ships,
trucks, cars and otherhydrogen mobility
applications

Integrated H2 economy:cross-industry, andprojects with different
types of end-uses

23
Infrastructure projects:
H2 distribution,transportation,
conversion, and storage

Europe leads globally in the number of announced hydrogen projects, with Australia, Japan, Korea,
China and the USA following as additional hubs. Of all announced projects, 55% are located inEurope. While Europe is home to 105 production projects, the announced projects cover the entire
hydrogen value chain including midstream and downstream.
In expected major demand centers like Korea, Japan and Europe, the focus is on industrial usage
and transport application projects. While Japan and Korea are strong in road transport applications,green ammonia, LH2, and LOHC projects, Europe champions multiple integrated hydrogen economy
projects. These latter initiatives often feature close cross-industry and policy cooperation (e.g., theHydrogen Valley in the Northern Netherlands).

4

Equivalent to 175 thousand tons at 100% load factor.

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6

More than USD 300 billion in H2 investments through 2030
A tally of project announcements, investments required to reach government production targets andspending projections across the value chain adds up to more than USD 300 billion through 2030. Given
the industry’s early stage, the vast majority (75%) of these investments involve announcements but
not committed funding. To date, we estimate USD 80 billion of mature investments until 2030. These
include USD 45 billion in the planning phase, which means companies are spending sizable budgets
on project development. Another USD 38 billion involves either committed projects or those underconstruction, commissioned or already operational (see Exhibit 3).

Exhibit 3: Breakdown of announced investments by maturity
Projected hydrogen investment through 2030
USD bn262

End-useapplication

Distribution~80bn ‘mature’ investment

Production

45

38

Announced

Planning

Realized

Projects in press announcements
or preliminary study stage. Also
includes required investment toreach national targets andgovernment funding pledges

Projects that are at the feasibility
study or front-end engineeringand design stage

Projects where a final investment
decision (FID) has been taken,
under construction,commissioned and operational

The largest share of investments is projected in Europe (about 45%), followed by Asia, where Chinais leading with around half of total investments.
Looking at the hydrogen value chain split, the production of hydrogen accounts for the largest shareof investments. End-application investments have a higher share in mature projects due to funding forfuel cells and on-road vehicle platforms. In analyzing private investments among Hydrogen Council
members, we see a clearly accelerating trend. Members expect to increase investments six times
through 2025 and 16 times through 2030, compared with 2019 spending.
Companies tend to target their investments in the hydrogen space toward three specific areas: thecapex of announced or planned projects, R&D, or M&A activities. The future investments of Hydrogen
Council members trend heavily toward capex investments (80%) compared with spending on R&D or
M&A activities.

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Regulation and government support drive this momentum
Governments have plans to support strategies to transition to hydrogen, with USD 70 billion in play.
The increasing governmental support stems from a global shift to decarbonization: 75 countries,
representing half the world’s GDP, have a net zero ambition and 80% of global GDP is covered bysome level of CO2 pricing mechanisms (see Exhibit 4).

Exhibit 4: Regulation supporting decarbonization and hydrogen
Share of global GDP covered by respective regulatory support mechanism%, 100% = USD 88 Trillion

Number ofcountries

49

75

31

100%
GDP not covered

20

27
50

GDP covered

80

73
50

CO2 pricing initiatives

Net zero targets

H2 strategies

Hydrogen is a crucial element in most strategies to achieve net zero standing, and more countries
are developing hydrogen plans. In fact, over 30 countries have created such strategies on a national
level, and six are drafting them.
Besides the national hydrogen roadmaps, sector-level regulation and targets underpin the shift tohydrogen. In transport, more than 20 countries have announced sales bans on ICE vehicles before
2035. More than 35 cities covering over 100 million cars are setting new, stricter emission limits, andover 25 cities have pledged to buy only zero-emission buses from 2025 onwards. Globally, countries
anticipate having 4.5 million FCEVs by 2030, with China, Japan and Korea leading the roll-out. In parallel,
stakeholders are targeting 10,500 hydrogen refueling stations (HRS) by 2030 to fuel these vehicles.
For industry, the goalposts are also shifting. For example, the European Union has suggested that
Member States incorporate low-carbon hydrogen production renewable fuel targets (REDII Directive),
which could give a significant boost to hydrogen adoption in refining and by fuel retailers. In addition,
four European countries (France, Germany, Portugal and Spain) have recently announced industry-

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8specific clean hydrogen consumption targets in their national strategies. Likewise, quotas for aviationand shipping fuel are in advanced discussions among these four EU nations. Other countries haveestablished incentives for low-carbon hydrogen by means of tax benefits, as in the case of the 45Q
program in the United States. Similarly, in France, industrial users can avoid carbon costs by using
renewable hydrogen, and in the Netherlands, investments into large-scale electrolyzer capacity
connected to offshore wind power and the retrofitting of the natural gas grid are being made to
replace fossil fuels by hydrogen.
Driven by a growing focus on hydrogen and increasing governmental support, the announced
production capacity for clean hydrogen for 2030 increased to 6.7 million tons a year from 2.3 million
tons previously. In other words, players have announced two-thirds of the clean hydrogen production
capacity over the course of the past year (see Exhibit 5).

Exhibit 5: Announced clean hydrogen capacity through 2030
Cumulative production capacity
Mt p.a.
Projections
from 2020 6.7
Announced1
Low carbon
Mature2

Announced1

Projections
from 2019 2.3

Renewable

Mature2

2020

21

22

23

24

25

26

27

28

29

2030

1. Includes projects at preliminary studies or at press announcement stage
2. Includes projects that are at the feasibility study or front-end engineering and design stage or where a final investment decision (FID)
has been taken, under construction, commissioned or operational

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10Hydrogen production
costs are declining
faster than previously
thought

60%
production cost reduction projected forrenewable hydrogen by 2030 vs. 2020 baseline

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III | Hydrogen supply

Renewable hydrogen could break even with gray H2 before 2030 in optimal regions
Renewable hydrogen production costs continue to fall more swiftly than previously expected.
Compared with the Hydrogen Council Study 2020 report, “Path to hydrogen competitiveness: acost perspective”, this year’s update resulted in even more aggressive cost-down expectations forrenewable hydrogen production.
Three factors are driving this acceleration. First, capex requirements are dropping. We expect asignificant electrolyzer capex decline by 2030 – to about USD 200-250/kW at the system-level(including electrolyzer stack, voltage supply and rectifier, drying/purification and compression to 30
bar). That is 30-50% lower than we anticipated last year, due to accelerated cost roadmaps and afaster scale-up of electrolyzer supply chains. For example, several electrolyzer manufacturers haveannounced near-term capacity scale-ups for a combined total of over approximately 3 GW per year.
Second, the levelized cost of energy (LCOE) is declining. Ongoing reductions in renewables costto levels as much as 15% lower than previously expected result from the deployment of at-scale
renewables, especially in regions with high solar irradiation (where renewables auctions continue
to break record lows). The strongest reductions are expected in locations with optimal resources,
including Spain, Chile, and the Middle East.
Third, utilization levels continue to increase. Large-scale, integrated renewable hydrogen projects areachieving higher electrolyzer utilization levels. This performance is driven largely by the centralizationof production, a better mix of renewables (e.g., onshore wind and solar PV) and integrated design
optimization (e.g., oversizing renewables capacity versus electrolyzer capacity for optimized utilization)(see Exhibit 6).

Exhibit 6: Hydrogen production costs by production pathway
Production cost of hydrogen
USD/kgAverage location

Optimal location

6.0
Breakeven between gray and renewable requires …

2019 average
location

5.0
2020~65GW of electrolyzer capacity
-62%

4.0

~50bn gap to be bridged

3.0

2.0
Renewable
Low-carbon
Gray

1.0

2020

2030

Renewable hydrogen• Dedicated renewable/electrolyzer system• Fully flexible production• Scale up of renewable hydrogen production• Additional costs to reach end supply price

2040

2050

Low-carbon hydrogen• Development of CO2 pipelines and at-scale sites• Scale-up of low-carbon hydrogen production• Scale-up of CCS outside of hydrogen production

Key assumptions• Gas price 2.6–6.8 USD/Mmbtu• LCOE USD/MWh 25–73 (2020), 13–37 (2030) and 7–25 (2050)

Hydrogen Insights Report 2021
Hydrogen Council, McKinsey & Company

12Strong low-carbon hydrogen production momentum and more cost reductions
The production of low-carbon H2 also continues to gain momentum. Improvements include increased
CO2 capture rates for autothermal reforming (ATR) from 95% in last year’s report to 98%, coupled withpotential capex reductions from smaller capture installations and lower compression requirements.
Conducting ATR at higher temperatures can also increase methane-to-hydrogen conversion rates,
resulting in lower methane content in the product gas, further reducing emissions (see Exhibit 6).
Introducing CO2 costs can bring the earliest breakeven for clean hydrogen to 2028-2034
Including carbon costs for emissions related to gray and low-carbon hydrogen production greatly
influences the breakeven dynamics between gray and renewable hydrogen. Assuming a carbon costof about USD 50 per ton of CO2e by 2030, USD 150 per ton CO2e by 2040, and USD 300 per ton
CO2e by 2050, can bring the earliest breakeven for renewable hydrogen forward to a 2028 to 2034
timeframe. The exact year will depend on the availability of local resources.
In countries with optimal renewables but average cost natural gas (e.g., Chile) breakeven could occur
as soon as 2028. In locations with average resources for both pathways (e.g., Germany), breakeven
could come by 2032. At the same time, locations with abundant and optimal resources for both
pathways (e.g., selected regions in the US) could see the breakeven of gray and renewable hydrogenby 2034. Low-carbon hydrogen could breakeven with gray by 2025-2030, subject to at-scale CO2
storage and transport infrastructure, and an expected cost of about USD 35-50 per ton CO2e (seeExhibit 7).

Exhibit 7: Hydrogen production pathways, including carbon costs
Production cost of hydrogen
USD/kgAverage location

Optimal location

Net
importer

6.0

2.5

5.0

4.0
? 1,2
Gray

2.0

3.0

2.0
Lowcarbon
Renewable

1.0

2020

2030

2040

Key assumptions• Gas price 2.6–6.8 USD/Mmbtu• Cost USD/Ton CO2 30 (2020), 50 (2030), 150 (2040) and 300 (2050)• LCOE USD/MWh 25–73 (2020), 13–37 (2030) and 7–25 (2050)

13

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2050

Net
exporter

1.5

Together, these drivers are pushing down the cost curve for renewable hydrogen by as much as 20%
for average locations and potentially 30% for optimal locations compared with the Hydrogen Council
Study 2020 report, “Path to hydrogen competitiveness: a cost perspective”.
For average projects such as offshore, wind-based electrolysis in Central Europe, renewablehydrogen production costs could decline from USD 5.4/kg in 2020 to USD 2.3/kg in 2030, withLCOE declines having the greatest cost-down impact. Due to the higher relevance of electricity
cost, efficiency gains also have a slightly higher impact compared with locations using lower-cost
renewables.
For projects using low-cost renewables like solar PV-based electrolysis in the Middle East, the cost of
renewables-based hydrogen production could decline to USD 1.5/kg in 2030. In this case, declining
capex costs will have the most impact in driving cost-down effects due to lower electrolyzer utilization
rates compared with offshore wind setups. Both the Central Europe setup and the Middle East setup
configurations can also benefit from integrated design optimization, striking a balance between higher
utilization due to renewables capacity oversizing and a LCOE penalty due to curtailed electricity.
Truly optimal locations will likely include a combination of wind and solar resources for an additional
upside. Countries like Australia, Chile or Saudi Arabia have the potential to benefit from suchcombined resources (see Exhibit 8).

Exhibit 8: Breakdown of renewable hydrogen production cost trajectory
Average region example
6.0
5.4
1.0

1.9
0.2

2.3

Optimal region example
5.4

3.9
1.6

Previous1

2020

CAPEX2

0.6

0.3

Energy cost

Other O&M

1.4

2030

1. 2020 Projection from 2020 Hydrogen Cost Roadmap Report
2. Includes learning rate on CAPEX and impact of larger electrolyzer size class (from ~2 MW to ~80 MW)

Hydrogen Insights Report 2021
Hydrogen Council, McKinsey & Company

14Electrolyzer capex savings can reduce costs quickly in a rapid global scale-up
Electrolyzer system costs could drop from about USD 1,120/kW in 2020 to an estimated USD 230/
kW in 2030. This calculation includes the stack as well as the balance of plant (e.g., transformer andrectifier, drying/purification to 99.9% purity, compression to 30 bar). It excludes transportation of theelectrolyzer to the site, installation, and assembly (including grid connection), the cost of the building(for indoor installations), and indirect costs such as project development, field services and “first fills.”
Depending on project specifics, these could double total costs by 2030.
Because electrolyzer system capex should decline sharply, other cost elements (including installation,assembly, and indirect costs) will take a larger share of costs over time. That’s because learning
curve effects regarding the engineering, procurement and construction (EPC) part of the value chain
will be limited after the deployment of the first few large-scale projects.
The total cost of an electrolyzer project also includes financing costs. A contribution margin in line with the
project’s weighted average cost of capital (WACC) requirements should scale with other capex elements.
Financing thus becomes an important way to reduce hydrogen production costs. For instance, reducing
WACC from 7% to 5% would reduce a project’s overall capex commitment by almost 20%.
Expected electrolyzer learning curves could be too conservative
Current learning curve expectations for electrolyzer scale-ups range from 11-12% between 2020 and
2030 for polymer electrolyte membrane (PEM) and alkaline technologies. However, these learning
curves appear conservative compared with the early development of other low-carbon technologies
like batteries, solar PV or onshore wind, which saw learning rates of approximately 20-40% between
2010 and 2020. Potentially higher learning rates of 15%, 20% or 25% would drive additional cost
reductions of 10-20%, 40-50% or 60-70%, respectively, by 2030 (see Exhibit 9).

Exhibit 9: Electrolyzer capex learning rate scenarios
Electrolyzer system capex1 for different learning rates
USD/kW~660–1,050

Hydrogen Insights
Learning rate

2010–20 learning rates ofcomparative technologies

39% for batteries
35% for solar PV
19% for wind onshore~230–380~200–310~130–190

20202

2030
(12% learning rate)

2030(15% learning rate)

1. Only includes stack and balance of plant. No installation and assembly, building, indirect cost or transportation site
2. Range based on different electrolyzer size classes of 2–20 MW

15Hydrogen Insights Report 2021
Hydrogen Council, McKinsey & Company

2030(20% learning rate)

Hydrogen Insights Report 2021
Hydrogen Council, McKinsey & Company

16Low shipping costs
from major hydrogen
supply centers could
unlock demand

USD

2-3

/ kg

total shipping costs assuming at-scale production andtransportation infrastructure

17

Hydrogen Insights Report 2021
Hydrogen Council, McKinsey & Company

IV | Hydrogen distribution and global
supply chains
With hydrogen production costs falling, costs for hydrogen distribution are becoming increasingly
more important. For production and distribution, three types of value chains are emerging. Largescale hydrogen offtakers that are in close proximity to favorable renewables or gas and carbon
storage sites will use onsite production. Smaller offtakers, for example refueling stations orhouseholds, will require regional distribution. In regions without optimal resources, both large- andsmall offtakers may rely on hydrogen imports (see Exhibit 10).

Exhibit 10: Emerging hydrogen distribution chains

H2 valuechain

OnsiteRegional

Exampleend user(Europe, 2030)

Example value chain steps
Production

Conversion/transmission

Industrial, large
scale offtaker Renewable/lowcarbon production

 On-site storage foraverage of 1 day

1.6–2.3
USD/kg

0.5
USD/kg Renewable/lowcarbon production

 Conversion to LH2 andstorage for average of
1 day or
 Storage as GH2 foraverage of 1 day andcompression to 700 bar

 Trucking as LH2 for
300km + operating of
1,000kg LH2 HRS or Piping as GH2 for
300km and operatingof 1,000kg GH2 HRS1

1.6–2.3
USD/kg0.7–1.0
USD/kg

1.0–2.0
USD/kg Renewable/ lowcarbon production

 International pipeline
for ~9,000km andstorage at port for
average of 2 weeks or Carrier conversion/reconversion, shippingfor ~9,000km andstorage at port for
average of 2 weeks

 Trucking as LH2/GH2
for 300km and onsite
storage for average of
1 day or
 Piping as GH2 for
300km and onsite
storage for average of
1 day

1.0–1.4
USD/kg

0.6–3.5
USD/kg0.1–2.0
USD/kgH2 refuelingstations (HRS)International Industrial, large
scale offtaker

Cost,
USD/kgDistribution

~2–3

~3–5

~2–7

1 Refers to usage of existing pipeline to industrial hub

The emergence of international distribution is driven by cost differences for hydrogen production
stemming from renewables endowment, the availability of natural gas and carbon storage sites,
existing infrastructure and the ease and time requirements for its build-out, land use constraints,
and the assignment of local renewables capacity for direct electrification. Many expected hydrogen
demand centers, including Europe, Korea, Japan, and parts of China, experience such constraints.
In some of these cases, H2 suppliers will meet this demand more effectively by importing hydrogenrather than producing it locally (see Exhibit 11).

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Exhibit 11: Distribution of global hydrogen resources and demand centers
Demand centers

PV/wind resources
for renewablehydrogen production
Least

Most

Natural gas resources
for low-carbonhydrogen production
Least

Most

The optimal H2 transport mode will vary by distance, terrain and end-use: no universal
solution exists
Hydrogen can be transported globally using three forms of transportation – trucks, pipelines or ships –using a range of different carriers.5 Currently, liquid hydrogen, liquid organic hydrogen carriers6
and ammonia are the carbon-neutral solutions with the most traction.7 While the optimal choice oftransportation depends heavily on the targeted end-use and the terrain to be covered, some generalrules on preferable solutions for different distances apply.
For short and medium range distances, retrofitted pipelines can achieve very low H2transportation costs (less than or equal to USD 0.1/kg for up to 500km). However, these costs are
realizable only if existing pipeline networks are available and suitable for retrofitting (e.g., ensuring
leakage prevention), and high volumes of H2 are transported, guaranteeing high utilization rates. For
lower or highly fluctuating demand, or to bridge the development to a full pipeline network roll-out,trucking hydrogen – in gaseous or liquid form – is the most attractive option. It can achieve costs ofaround USD 1.2/kg per 300km. End applications as well as demand size are decisive for choosing
between liquid or gaseous hydrogen trucking options.

5

6

7

19

Gaseous hydrogen, liquid hydrogen LH2, liquid organic hydrogen carriers (LOHC), ammonia (NH3), methanol, LNG/LCO2 (dualuse vessels carrying liquefied natural gas on one trip and liquid CO2 on the return trip) and solid hydrogen storage.
Various liquid organic hydrogen carrier materials are available, e.g. n-ethylcarbazole, methyl-cyclohexane, benzyltoluene –benzyltoluene used for analysis in this report
Synthetic methane produced from biogenic or air-captured CO2 being a possible fourth candidate to be studied more in-depth

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For longer distances, both new and retrofitted subsea transmission pipelines provide cheaperat scale transportation than shipping, but are not relevant for all regions. Where pipelines are notavailable, the transportation choice involves a range of different carriers. The three modeled here
– LH2, LOHC and NH3 – are the most discussed. Since all three carriers fall into a comparable cost
range, the optimal choice depends on the targeted end-use and requirements concerning hydrogen
purification and pressure levels, as discussed in greater detail below (see Exhibit 12).

Exhibit 12: Overview of distribution options<0.1 USD/kg

0.1–1 USD/kg 1–2 USD/kg>2 USD/kg

Costs
Distribution
0–50 km
Pipelines1

Retrofitted

1.
2.
3.

>1,000 km>5,000 km

Regional distribution
pipelines

Onshore transmission
pipelines

Onshore/Subsea
transmission pipelines

N/A

City gridRegional distribution
pipelines

Onshore transmission
pipelines

Onshore/Subsea
transmission pipelines

N/A

N/A

N/A

N/A

LH2 ship

LH2 ship

N/A

N/A

N/A

NH3 shipNH3 ship

N/A

N/A

N/A

LOHC ship

LOHC ship

LH2
trucking

Distribution truck LH2

Distribution truck LH2

Distribution truck LH2

N/A

N/A

Gaseoustrucking

Distribution truck CH23

Distribution truck CH23

Distribution truck CH23

N/A

N/A

LH2

NH32

Trucking

101–500 km

City grid

New

Shipping

Transmission
51–100 km

LOHC2

Assuming high utilization
Including reconversion to H2; LOHC cost dependent on benefits for last mile distribution and storage
Compressed gaseous hydrogen

Hydrogen pipelines
Hydrogen pipelines are cheaper than electricity transmission lines
Hydrogen pipelines can effectively transport renewable hydrogen across long distances. They cantransport 10 times the energy at one-eighth the cost associated with electricity transmission lines.
Furthermore, hydrogen pipelines have a longer lifespan than electricity transmission lines and offer
dual functionality, serving as both a transmission and storage medium for green energy.
Pipelines enable both international and regional/ last-mile transport, moving H2 up to
5,000km at low cost…
While distribution networks cover regional and last-mile transport, onshore and subsea transmission
pipelines could move hydrogen across distances that range from 500 to 5,000 or more kilometers.
Pipelines can achieve extremely low-cost H2 transport compared with alternative transportation
modes, especially where retrofits of existing infrastructure are possible.8 For example, retrofitting
pipelines can save 60-90% of the cost of greenfield pipeline development.
8

The option to retrofit depends on the existing pipeline (material, age, location), operating conditions, and availability, which might
be limited due to long-term natural gas transmission agreements.

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…but not all hydrogen pipelines are equal
While hydrogen pipelines provide cheaper transportation compared with many alternatives, theactual costs of hydrogen networks vary by type, length of network, and the condition of the retrofitted
pipeline itself. Typical capex costs for onshore transmission networks including compression will range
between USD 0.6 and 1.2 million per km for retrofit and USD 2.2 and 4.5 million per km for newly built
H2 pipelines, resulting in H2 transport costs of USD 0.13-0.23/kg/1000km (see Exhibit 13).

Exhibit 13: Comparing hydrogen pipelines

Description

Onshore transmission pipelines

Subsea transmission pipelines

Distribution pipelines

Large, high pressure transmission
pipelines transporting gas on land

Large, high pressure transmission
pipelines transporting gas throughoceansSmaller, lower pressure pipelines forlast-mile gas delivery to end users

Ease ofretrofitting
High

Low

Potential availability constraints due tolong-term natural gas commitments andcapacity contracts

High compression requirements andsubsea transmission network may
be challenging

Cost estimation
Capex in Million
USD/kmMediumDistribution network location indensely populated areas could be
problematic~1.3–2.3x
costs of onshoretransmission
pipelines~15% of costs of onshore~3x

4.7–7.1

transmission pipelines

2.2–4.5

1.3–3.1
0.3–0.7
0.6–1.2
Retrofit

0.1–0.2
New

Retrofit

New

Retrofit

New

For offshore/subsea transmission pipelines, costs are a factor 1.3 to 2.3 higher, given the specificchallenges and conditions of subsea pipeline construction and operation for both new projects andretrofits. Distribution pipelines are substantially cheaper than transmission pipelines (roughly 15% oftransmission pipeline costs), given their smaller diameter and lower pressures. However, distribution
pipelines will likely become relevant only in the runup to 2040, when demand for hydrogen in
residential and commercial buildings exceeds the threshold that the blending of up to 20% hydrogen
into the natural gas grid can supply.
The costs of retrofitting versus building new pipelines depend on a variety of factors including
diameter and pressure, the quality of the materials used, the pipeline’s overall condition, the existenceof cracks, the social costs of construction, and other considerations. Many of these factors arelocation-specific and thus give some regions and countries an advantage for retrofitting the naturalgas grid. For example, in the Netherlands, parallel natural gas grid infrastructure allows companies toretrofit for hydrogen usage while gradually phasing out natural gas.
The costs of retrofitting can change based on pipeline upgrades and the presence of connected
equipment such as metering stations, valves, and compressor stations.

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Hydrogen carriers
Beyond pipelines, three carbon neutral H2 carriers are competitive for long distancehydrogen transportation
As gaseous hydrogen is not suitable for long-distance shipping, suppliers can liquefy hydrogen, convert
it to ammonia, or bind it to a liquid organic hydrogen carrier. If every step of the value chain uses green
energy (fuel and/or electricity) and the hydrogen is produced from low-carbon sources, all threecarriers can be considered low carbon.
The optimal carrier depends on the intended end-use, purity requirements and the needfor long-term storage
The long-term optimal choice of carrier depends on a range of factors. LH2 is most efficient if thedestination requires liquid or high-purity hydrogen, and has benefits if hydrogen needs to be
distributed with trucks after landing at port. This is typically the case for hydrogen refueling stations
for cars or trucks, for example. In contrast to NH3 and LOHC, LH2 does not require dehydrogenation
or cracking to convert into gaseous hydrogen, which not only saves costs but also avoids purity

Case example: Low-cost H2 pipeline transport can unlock hydrogen demand
By 2030, our projections indicate that clean hydrogen from North Africa could be piped to demandcenters in Central Europe (e.g., the Ruhr area in Germany) at a cost of about USD 2 per kg of H2.
Of that, transport costs will constitute roughly USD 0.5 per kg of H2. (see Exhibit 14).

Exhibit 14: Landed costs of renewable H2 transported from Algeria toCentral Europe using a pipeline
Costs for at scale production and pipeline transportation1 in 2030
Pipeline from Algeria to Central Europe, 2,800km Costs, USD/kg
Pipelines

~0.4

~1.9

~0.1

1.5

Ruhr area

Clean
production

Ideally
retrofitted
pipeline

75% retrofit
25% new

Subseapipeline

Onshoretransmission
pipeline

Cost atdestination

Algeria

1. Assuming route will be built out by 2030; full rollout of backbone (2035–40) depicted here

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challenges caused by carrier residues. LH2’s main drawback is its relatively low volumetric energy
density compared with ammonia, which limits the amount of hydrogen per ship, and the boil-off
losses that occur with every day of storage. While liquefaction is a proven and commercialized
technology, liquid hydrogen shipping and large-scale storage – which requires suppliers to manage
the boil-off losses – remain in the early stages of deployment.
Ammonia is the straightforward answer for end-uses that need ammonia as a feedstock and cantherefore avoid the need to crack NH3 back into hydrogen (such as for fertilizer, shipping fuel,co-firing or ammonia combustion for power generation). However, suppliers are also considering
this approach for other hydrogen use cases. Ammonia benefits from a higher volumetric energy
density than does liquid hydrogen and thus suppliers can ship it more cost effectively than LH2
using commercially available ammonia ships. However, the two drawbacks of using ammonia as ahydrogen carrier are the high costs of cracking it back into hydrogen and the achievable purity levels.
Furthermore, because ammonia is toxic, it may face handling and storing restrictions in residential
areas as well as limited options for in-land distribution.
Liquid organic hydrogen carriers can use existing diesel infrastructure and safely store hydrogen overlong periods without loss. When using non-flammable and non-toxic carrier materials such as BT,9
LOHC can use existing industry-scale diesel infrastructure without any additional safety regulations.
The main drawbacks of LOHC are the novelty of the dehydrogenation process, which requires large
amounts of heat to release the hydrogen from the carrier, and the limited hydrogen carrying capacity
compared with LH2 and NH3. The ability to use cheaper storage tanks than those needed for othercarriers partly outweighs these issues.

Exhibit 15: Landed costs at port of renewable H2 shipped from Saudi Arabia
to Europe
Cost for at scale production and shipping transportation in 2030
Shipping route from Saudia Arabia
to Europe through Suez Canal, 8,700km

Costs, USD/kg H2
To decentral
user(HRS)1

+2.0

+0.7

+1.5

3.2–3.8~0

3.1–4.2

1.0–1.4

1.0–1.8

Dehydrogenation

0.3–0.4

Shipping
including terminals

3.7–4.8

1.0–2.0(if necessary)

Rotterdam~0.4
To port

0.8–0.9

0.7–1.0~1.5

Ammonia

0.3–0.5

Conversion
to carrier

~1.5

~1.5

Clean production

LH2

LOHC

Saudi Arabia
High maturity

Medium maturity

1. Assumes liquid (for LH2) or gaseous (for ammonia, LOHC) distribution with truck for 300km, also includes: purification to FCEV
standard using a PSA for LOHC and NH3, boil-off losses for LH2, storage costs at port and HRS operating costs

923

While BT includes toluene, it is does not fall under toxicity regulations given the limited toluene content per ton of BT.

Hydrogen Insights Report 2021
Hydrogen Council, McKinsey & Company

Exhibit 15 shows a comparison of carriers for transporting renewable hydrogen from Saudi Arabia
to Western Europe assuming at-scale hydrogen production and shipping infrastructure. If the end
application requires ammonia, transporting hydrogen as ammonia could result in landed costs as low
as USD 3 per kg of hydrogen. If hydrogen is required in the end application, landed costs are
between 3 and 5. The optimal choice of a carrier for this example would thus ultimately depend on
the targeted end-use, a resulting need for further overland transportation, and the projected storage
time.
Hydrogen global transport can cost less than USD 2-3/kg
By 2030, assuming at-scale production and transportation infrastructure, hydrogen could be shippedfrom locations such as Australia, Chile or Middle East to projected demand centers at costs of USD
2-3/kg of hydrogen. This cost, coupled with very low hydrogen production costs, unlocks demandin many key sectors (e.g., in transportation, industry, feedstock and others) at the point of usage (seeExhibit 16).

Exhibit 16: Landed costs of hydrogen at port for selected global transport routes
COSTS FOR AT SCALE PRODUCTION AND TRANSPORTATION (9,000–10,300 TONS H2)
COSTS ACCOUNTING FOR LOSSES DURING TRANSPORTATION

1

3

2

8,200 km8,700 km7,000 km

Illustrative routes modeled, USD/kg H2
1
Clean
production
Ammonification

NH3

1.5
0.8–0.9

Shipping

0.9-1.61
1.5

Clean
production

1.5

Liquefaction

0.7–1.0

Shipping

0.3–0.4

Cracking
Cost at port

32

1.9–2.4

Cost at port

1.7

Hydrogenation

0.3–0.5

1.9–2.4

3.2–3.8

Cost at port

LOHC

0.3–0.4
1.2–1.81

Dehydrogenation

0.2
1.5

Clean
production

Shipping

1.0–1.2

Import terminal
3.5–4.4

LH2

1.7

1.8–2.7

3.5–4.4

1. Dependent on whether hydrogen feedstock or heat from grid is used for dehydrogenation heating requirement

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Falling clean hydrogenand application specificcosts will drive greater
cost-competitiveness inhydrogen end applications

22hydrogen end applications are projected to be
the most competitive low-carbon solution by 2030
representing 36% of global emissions

25

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V | End applications

The cost competitiveness of hydrogen end applications
The Hydrogen Insights report analyzes the competitiveness of hydrogen applications across sectors
through 2030 compared with conventional and low-carbon alternatives. Lower hydrogen production
and distribution costs across all regions will improve the cost competitiveness of all end applications,as reflected in the shift to the right in the cost competitiveness matrix compared to Hydrogen Council
Study 2020, “Path to hydrogen competitiveness: a cost perspective”.
In addition to hydrogen’s role as an overarching cost driver, the Hydrogen Insights report identifies
three additional cost drivers with implications for individual end applications. They include optimized
routes for green steel through the combination of DRI and scrap, which help green steel achieve costcompetitiveness; improvements in battery technology that influence hydrogen breakeven with lowcarbon alternatives in the transport sector; and new applications for hydrogen or hydrogen-based
fuel usage (see Exhibit 17).

Exhibit 17: Hydrogen competitiveness per end application in 2030

Biofuel(transitionary fuel)In regions where
CCS is not available

Significant
improvement vs.
conventional

Refinery1Long-range
flights2
Methanol1

Cruise Short-range
ship2
flights2

Backup generator

Boilerwithexisting
network

Combinedcycle
turbineMediumduty truck

Heavy
duty Fork
truck lifts

Steel
Large
passenger
car/ SUVMid
grade
heatingHigh grade
heating

Longdistancebus/coachMiningtruck

Simplecycle
turbineCompared
to lowcarbon
alternatives

Taxi fleet

Regional
train

Fertilizer1

Blending
of H2

Significant
improvement vs.
low-carbon alternative

Container
ship2

Mid-sizelong range
vehicleBoilerwith new
networkCompact
urban carShortdistanceurban bus

Remotegenerator

RoPax

Short-range
flights2
Long-range
flights2

Combinedcycle
turbineCruiseships2
CHP forsmall
buildings

High grade
heating

Mid gradeheatingSmallregional
ferry

Urban
deliveryvanCompared to conventional alternatives
1. Clean hydrogen is the only alternative
2. Carbon breakeven cost represents average cost over lifetime of asset
3. Biofuel is a complementary solution to hydrogen/ synfuels particularly used in heavy to decarbonize sectors such as shipping and aviation; usage will be subject tosupply constraints

The updated cost outlook shows that 22 hydrogen applications can be the most competitive
low-carbon solutions from a total cost of ownership perspective (including hydrogen production,
distribution and retail costs). In addition to the applications that were previously competitive, includingcommercial vehicles, trains, long-range transport applications and boilers, today´s improved outlook
adds fertilizer, refinery, steel, aviation, and shipping applications.
While this analysis focuses on the cost competitiveness of the end-use applications, other factors
also drive the purchase decisions of companies and customers. Some of these include government
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customers on carbon-free solutions, and investor preferences for ESG-compliant business models.
For example, aviation, cruise ships, container shipping and steel are experiencing a push toward agreener restart post-COVID-19 from both customers and governments.
Hydrogen production cost breakeven
At a hydrogen production cost of USD 1.6-2.3/kg, most road transportation applications andhydrogen feedstock for industry are “in the money” (see Exhibit 18). With hydrogen costs between
the blue and green hydrogen cost targets for 2030 and without any costs for carbon emissions,hydrogen is only competitive in heavier road transportation applications (not including passengercars). A cost of carbon at USD 100/t of CO2e could push industry feedstocks for applications likesteel, ammonia, and refining to breakeven and beyond. Other forms of transportation like shipping
or aviation only break even at higher costs of carbon (> USD 70/tCo2e) but require hydrogen-based
fuels as the only zero-carbon fuel possibility that can realize decarbonization ambitions.
While end applications in buildings and power require an even higher carbon (~200 USD/t CO2e)
price to become cost competitive, we believe they will see strong momentum, nevertheless. For
example, in the United Kingdom multiple landmark projects are blending hydrogen into naturalgas grids for residential heating. They are also working with hydrogen for backup power solutions,especially for high power applications like data centers. The reason for this is that while hydrogenmay not be able to outcompete conventional solutions, it can be the most cost-effective low-carbon
option for many stationary use cases (see Exhibits 18, 19).

Exhibit 18: Required hydrogen production cost for breakeven with conventional
solutions, without carbon costs
USD/kg in 2030
‘In the money’4.4–4.6

3.8

2.2–3.0

Renewablehydrogen,
average region

2.2

2.3

1.6

1.4

Low-carbonhydrogen,
average region

1.4
0.8

0.6

0.6
0.3

0

Buses

TrainsTrucksDieselSUV<0–0.6

0.6

Mid- Ammonia Refinery Steel PowerHigh Building Ships Airplanes
sized(DRI) generation1 grade heating2(synfuel)vehicleheat
Natural gas(SMR)

1. Average of combined cycle and single cycle turbine applications
2. Boiler with existing network

27

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Coal

Natural gas

Ship Kerosene
fuel

Referencetechnology

Exhibit 19: Required hydrogen production cost for breakeven with conventional
solutions, with 100 USD/t CO2e
USD/kg in 2030
‘In the money’
5.4-5.7
5.1
4.6

4.4
2.8-4.1

2.3
2.3

2.2

1.0-2.4

2.2

1.6
1.4

1.0-1.6

1.5
1.2

0

Buses

TrainsTrucksDieselSUV

Renewablehydrogen,
average region
Low-carbonhydrogen,
average region

High Building Ships Airplanes
Mid- Ammonia Refinery Steel Power
sized(DRI) generation1 grade heating2(synfuel)vehicleheat
Natural gas
(SMR)

Coal

Natural gas

Ship Kerosene
fuel

Referencetechnology

1. Average of combined cycle and single cycle turbine applications
2. Boiler with existing network

A. Road transport and mining equipment
Global transportation generates 24% of global direct CO2 emissions from gasoline and diesel
combustion processes, with road vehicles like cars, trucks, buses, and motorcycles contributing
roughly three-quarters of global transportation emissions. BEVs and FCEVs are both viable alternatives
to decarbonize global transport. Use case-specific requirements such as range, payload and power
requirements can determine the applicability and competitiveness of battery- or hydrogen-powered
solutions.
On-road. In on-road trucking, BEVs remain the most competitive decarbonization option for lowerand mid-range use cases. FCEVs are best positioned to cover long-haul use cases, especially theupper spectrum cases with higher daily ranges. While most freight transport segments are notweight-constrained, FCEVs are the only alternative for weight-sensitive use cases of any driving
range, including pulp and paper or iron and steel transport. That is because heavy batteries would
reduce the potential payload of trucks to a larger extent than would fuel cells and hydrogen tanks.
For passenger cars, intended use and customer preferences will determine the choice of a fuel cell
versus battery-electric powertrain. BEVs clearly outcompete FCEVs in lower-range use cases suchas urban cars or mid-size vehicles (fewer than 500km). However, fuel cell vehicles are an option to
power larger passenger cars, SUVs and vans with longer-range requirements and heavier use cycles,
especially those used in commercial operations such as taxis or ridesharing.
Off-road. While zero-carbon powertrains for off-road segments such as mining trucks are lessadvanced than those for on-road use cases, fuel cell powertrains or even hydrogen combustion
engines might represent the only alternative for decarbonizing very heavy equipment like dump
trucks for mining operations. The high peak power requirements and harsh vibration and heat

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conditions experienced in the off-road environment make hydrogen combustion attractive as analternative to fuel cells in off-road applications.
TCO use-case perspective: On-demand heavy-duty trucking for demanding long-haultransport
We modeled a long-haul heavy-duty class 8 truck for flexible and demanding long-haul transport witha vehicle lifetime of 10 years and a yearly distance of 150,000km. Our on-demand trucking use caserequires a high fuel range of 800km. We assumed a hydrogen price at the dispenser of about USD 4/
kg in 2030 and an underlying cost of roughly USD 50/t of CO2e. In the model, we compared a heavyduty truck (HDT) fuel cell electric vehicle (FCEV) with a battery-electric truck and a diesel truck.
We expect the on-demand HDT FCEV to become the cheapest option in terms of TCO by 2030. It
should achieve break-even with battery-electric vehicles (BEVs) by around 2025, and with internal
combustion engine (ICE) HDTs by 2028. Overall, the decrease in fuel cost (we expect H2 cost to
decline about 60% between 2020 and 2030) will drive an estimated 80% of the TCO change. The
remaining 20% comes from falling equipment costs (powertrain costs are expected to decreaseabout 70% between 2020 and 2030). In the short-term, fuel costs make up about half of the TCO in
this use case, while fuel cell powertrain costs account for approximately 12%, which breaks down as
45% fuel cell system costs, 40% tank cost and 15% other components. In the mid-term, fuel costs
will account for 30% and the powertrain for 7% of total cost (see Exhibit 20).
In specific settings – e.g., where subsidies or other support mechanisms exist – the breakeven point
can be shifted forward. Switzerland’s toll exemptions or California’s low carbon fuel standard (LCFS)
credits are but examples for such policies.

Exhibit 20: Total cost of ownership of on-demand heavy-duty truck

USD/kmUse case:
Flexible and demanding
long-haul transport
under ideal efficiency
conditions

1.7

1.5

1.3
Diesel ICE

1.1

BEV
Fuel cell(FCEV)1

0.9

0.7

0.5
2020

25

1. Assuming renewable hydrogen, Europe

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30

35

2040

TCO use-case perspective: Open-pit dump truck for mining operations
The TCO analysis modeled a 300t open-pit dump truck used in mining operations in Chile with 6,200
operational hours per year and a lifetime of 12 years. High power requirements (about 2,000 kW)
made the mining truck an interesting application for hydrogen internal combustion engines, as fuelcell trucks with such high power requirements remain untested.
We assumed a hydrogen price at the dispenser of USD 1.4/kg in 2030 (with hydrogen production
on-site) and an underlying cost of USD 50/t of CO2e. We did not model a battery-electric mining
truck, since its feasibility is challenging, especially in terms of charging. Because uptime is critical inmining operations, high-speed charging would be required to meet the required battery capacities.
Moreover, many mines are off grid and battery swapping becomes difficult and expensive, given theextremely large batteries involved.
Both H2 ICE vehicles and FCEVs should breakeven with conventional diesel trucks before 2030. We
expect H2 ICE trucks to breakeven before FCEVs do, because they need only minor adjustments
compared with conventional diesel engines (with expected capex running at most 15-20% above
diesel engine capex). Furthermore, local hydrogen production should enable relatively low hydrogencosts that offset the efficiency gap between fuel cells and internal combustion engines, which is 5055% for FCs versus 40-45% for ICEs on a tank-to-wheels basis.10
For the FCEV truck, around 20% of the TCO change result from declining fuel cell powertrain costs,
and another 60% because of lower hydrogen production costs. The H2 ICE truck benefits from adecrease in hydrogen cost. More than 90% of this vehicle’s TCO change results from the decline infuel costs (76% by 2030), since powertrain technology is already mature (e.g., it contributes only 4%
to the expected TCO decline though 2030) (see Exhibit 21).

10

Exhibit
21: Total cost of ownership of a 300 ton open-pit dump truck
With increasing loads, the efficiency gap between FC and ICE shrinks, leading to an almost comparable efficiency for very high loads
USD/h
800

Use case:
Open pit dump truck
used in mining
operations

700

600

Technical feasibility
not yet demonstrated

500

Diesel ICE
H2 ICE400

Fuel cell(FCEV)1

300

200
2020

25

30

35

2040

1. Assuming production costs of renewable hydrogen in Chile

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TCO use-case perspective: SUV for family usage
We also modeled an SUV for family usage with a required fuel range of 600km, a lifetime of 15 years
and a yearly distance covered of 20,000 km. We compared a fuel-cell SUV, a battery-electric SUV
and a diesel-powered one.
We expect the FCEV to break-even with the BEV in terms of TCO by 2028, while competitivenessversus diesel-powered SUVs takes one to two years longer. We assumed a hydrogen price at thedispenser of about USD 4/kg in 2030 and an underlying cost of USD 50/t of CO2e.
The main drivers of FCEV TCO reductions are equipment costs (fuel cell system and hydrogen tankoutlays) and decreasing cost of hydrogen at the pump. Hydrogen fuel costs account for 40% of the
TCO through 2030, while almost 60% result from declining powertrain costs.
B. Ammonia
To date, industry produces 180 million tons of ammonia globally, with 80% used as feedstock forfertilizer and the remaining 20% for industrial chemicals production. Ammonia represents about
45% of global hydrogen offtake, making it the largest consumer of hydrogen today. Gray ammonia
production contributes roughly 2% of global emissions, with approximately 0.5 gigatons (Gt) of CO2
emitted because of its production.
With an increasing push toward decarbonization across sectors, new application fields will emerge
for ammonia. Recognized as an effective sustainable shipping fuel in the freight shipping industry (asdiscussed in more detail in the chapter on sustainable shipping fuels), ammonia can also serve as atransport vector for hydrogen (especially for export projects in new geographies) and decarbonize
power production when used for co-firing in existing thermal power plants.
Decarbonization alternatives
Ammonia is produced via the Haber-Bosch process, which combines hydrogen and nitrogen. As ahighly feedstock-intensive process, a significant share of ammonia’s carbon emissions result from thecarbon intensity of the feedstock (30-40% of cradle-to-plant-gate greenhouse gas (GHG) emissions
per ton of ammonia). Consequently, apart from using green electricity as an input for the conversion
process, the only option for decarbonizing ammonia production involves the substitution of grayhydrogen from natural gas with renewable or low-carbon hydrogen.
TCO Perspective
Given the feedstock intensity in the overall TCO (65-80%), ammonia production is highly sensitive tothe production costs of clean hydrogen. As the cost of hydrogen production is region-specific andlargely driven by renewable energy sources (RES) and carbon capture and storage (CCS) costs, thecompetitiveness of clean ammonia versus gray ammonia from natural gas varies by location.
Today, the production of clean ammonia in Northern Europe would cost at least USD 650-800/t andrequire a carbon price of USD 140-220/t of CO2e to reach breakeven. As illustrated in Exhibit 22, thecompetitiveness of clean ammonia will change drastically by 2030. In Europe, the hydrogen priceneeded for clean ammonia to reach breakeven with its conventional counterpart by 2030 would be
about USD 1.4/kg. With an optimal delivered cost of hydrogen of about USD 1.7/kg in Europe (from,for example, PV based electrolysis in Spain), green ammonia would require a carbon price of lessthan USD 50/t of CO2e to break even. With average renewables in Northern Europe, breakeven would
require a carbon price of approximately USD 100/t of CO2e (see Exhibit 22).
In regions with lower-cost feedstock, such as North America and the Middle East, the breakeven cost
would be even lower. In locations with constrained renewables and CCS, imported clean ammonia
from optimal production locations could be an alternative to domestically produced ammonia.

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Exhibit 22: Total cost of ownership of gray H2 versus green and low-carbon forammonia in Europe
Ammonia production costs
USD/ton NH3 in Europe1, 2030
Low-carbon hydrogen basedvs.

Conventionalx

Breakeven cost of hydrogen required vs. conventional
USD/kg

1.4

1.8

3
~730

~580
~480

~480

~470

~400

Opex
Opex

Capex

Capex
Optimalrenewables

Averagerenewables

Green ammonia

Average
SMR + CCSBlue
ammoniaSMR +0 USD/tCO2

SMR +50 USD/tCO2

SMR +200 USD/tCO2

Gray ammonia

1. Natural gas cost 6.9 USD/MMBtu, hydrogen 2030 cost 1.7/2.1/1.8 for optimal renewables (Spain solar)/average renewables (German offshore wind)/SMR with CCS

C. Steel
The steel industry is one of the three biggest producers of CO2. Every ton of steel produced in 2018
emitted on average 1.85 tons of CO2, amounting to about 8% of global emissions according to theWorld Steel Association. Increasing demand for low carbon steel products, changing customer
requirements as well as tightening carbon emission regulations are only a few of the reasonsdecarbonization is a top priority for the steel industry. Consequently, the industry needs a drastic
decrease in emissions to remain economically competitive (and in operation).
Decarbonization alternatives
Two main routes for steel production decarbonization exist: an integrated blast furnace (BF) andbasic oxygen furnace (BOF) combination, or an electric arc furnace (EAF). The BF-BOF route
produces steel from iron ore using coal as a reductant, while the main inputs for the EAF route are
direct reduced iron (DRI) or steel scrap. While both production routes cause carbon emissions, theconventional BF-BOF route is 14 times more carbon intensive due to its dependency on coal.
While there are strategies to decrease emissions on the BF/BOF route, including the reduction of
production losses, efficiency increases, and CCU, these do not eliminate emissions fully, and have notbeen able to demonstrate cost-effectiveness. The DRI-EAF route in contrast can be fully decarbonized.11
This requires steel makers to use renewable electricity to power the EAF, and then add clean
11

Small amounts of natural gas are required that cause emissions of about 4kg CO2 per ton crude steel – for full decarbonizationthese emissions would require abatement.

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hydrogen or biomass as a reductant to produce the DRI. Since biomass will likely see constrained
availability, we focus here on decarbonization using hydrogen.
The use of scrap in the EAF is an important driver of the total cost of production. The availability andquality of scrap largely depends on the region. Higher shares of scrap typically translate into lower
costs, as DRI is usually more expensive. Higher amounts of scrap also typically reduce the quality ofthe steel, which implies a tradeoff between the quality of the steel produced and cost optimizationfrom a higher share of scrap metal employed (see Exhibit 23).

Exhibit 23: Total cost of ownership of green steel versus alternative low-carbon
and conventional pathways
H2 Direct Reduction(DRI)

Cost of steelmaking1
USD/tonBlast Furnace
(BF)

H2

Coke
CO2 cost of breakeven with BF,
USD/t CO2DRI

Iron ore(DRI pellets)

~80

~45

0

~570

Sinterediron ore

~515
Capex

~450

~445

H2

Directreduction plant

Blast furnace (BF)

Scrap
Electricity

HDRI

Pig Iron
Other opex
O2

Electric arc
furnace

Scrap

Oxygenconverter
BF EU

Raw steelRaw steel
Caster

1. End product is crude steel
2. 60% DRI, 40% scrap

H2 DRIEU

H2 DRI + H2 DRI
scrap EU2 + scrap
MiddleEast2

H2 DRI + scrap steel2 can be costcompetitive in 2030 where hydrogen isaffordable or in average locations with acost of carbon of <50 USD/tCO2

TCO Perspective
In an optimized setup with 40% scrap and 60% DRI and accounting for a realistic expected costof carbon, clean steel could become cost competitive with steel produced via the BF-BOF routeby 2030. For example, clean steel production in Europe could cost as little as roughly USD 515
per ton of crude steel. This exceeds the estimated USD 450/ton of crude steel from the BF-BOF
route without carbon costs, as – while capex costs are about 30% lower - H2 feedstock costs andincreased electricity requirements drive its operational costs significantly higher. This cost difference
could be offset by a carbon cost of about USD 45/ton CO2e, bringing BF-BOF produced steel to thesame level as H2-DRI and scrap steel. Using a “pure DRI” setup would increase costs significantly for
the DRI-EAF route due to higher capex, higher electricity requirements, and, of course, higher DRI
costs. In regions with more affordable renewables and H2 costs, clean steel production costs could
be even lower than the aforementioned USD 515/ton of crude steel from H2-DRI + scrap in Europe.

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For example, for an optimized plant in the Middle East that accesses renewable electricity at about
USD 25/MWh and hydrogen at an estimated USD 1.4/kg, the cost of clean steel could be as low as
approximately USD 445/ton. Interest from customers such as automotive OEMs to source green steel
at a small premium creates additional momentum for clean steel alongside the favorable cost outlook
in the future.
D. Sustainable shipping fuels
To date, international commercial shipping accounts for 0.9 Gt of CO2e, equivalent to 2.6% of global
GHG emissions. Assuming a business-as-usual scenario, commercial shipping emissions could
increase up to 1.7 Gt of CO2e by 2050.
To combat climate change, the International Maritime Organization (IMO) aims not only to reduce
GHG emissions from shipping by at least 50% by 2050 (to 0.5 Gt of CO2e) compared with a 2008
baseline, but to decarbonize the sector fully as soon as possible in the century.
Decreased energy demand resulting from technological advancements and targeted energy
efficiency measures could save up to 0.5 to 0.9 Gt of CO2e. However, alternative low-carbon shipping
fuels are required to bridge the remaining gap of 0.3 to 0.7Gt of CO2e for the industry to meet the
IMO 2050 target of 0.5 Gt of CO2e.
Decarbonization alternatives
To shift toward low- or zero carbon shipping, two innovations must happen in parallel: the productionof decarbonized fuels and the development of new propulsion systems that enable the efficient useof these low-carbon fuels.
Phases of propulsion systems roll-out
The development of the propulsion systems will likely happen in overlapping phases: In a transitional
period, dual-fuel engines running on a combination of conventional heavy fuel oil (HFO) andalternative fuels will allow a gradual shift towards decarbonized fuels with minimized retrofitting
implications for established propulsion systems.
ICE propulsion systems running on low or zero carbon fuels represent the next step toward
decarbonization as they – depending on the type of fuel – achieve vast emission reductions or evenzero emissions at relatively low costs compared with those of alternative propulsion systems in theupcoming years.
The final phase will see the broader application of alternative propulsion systems such as electric or
fuel cell systems that guarantee high fuel efficiency for hydrogen-based fuels.
Assessing different fuel choices
Industry players are discussing various fuel alternatives12 to conventional liquid fossil fuels that differ interms of feedstock availability and technology maturity. Moreover, depending on regulation-induced
constraints, routes, and driving modes, the applicability of the alternative fuels for different ship types
will also vary.
Liquified natural gas produces 30% lower CO2 emissions compared with HFO. However, methane
slippage in production processes and engines represents a real danger, as methane is 25x more potent
than CO2 as a GHG measured over a 100-year period and thus detrimental to the climate. For thisreason, the applicability of LNG as a low-carbon fuel is increasingly questioned. However, bio-methaneand synthetic methane could be practical future options for the longer term.

12

Liquefied natural gas, biofuels (e.g., hydrated vegetable oil), synthetic methane (not in the scope of this report), liquid cleanhydrogen, green ammonia, and green methanol.

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Liquid biofuel could serve as a transitionary fuel given its usability with conventional ICE propulsion
systems without requiring significant retrofitting investments. However, feedstock availability constraints
and growing demand from other decarbonizing sectors could result in rising prices and supply
limitations. Moreover, depending on the feedstock, biofuels differ in CO2 emission reduction potential,
varying between 70% and 90% compared with HFO on a lifecycle basis.
Liquid clean hydrogen is producible in a carbon neutral way and – as a fuel – preferred over gaseousclean hydrogen due to its higher energy density. LH2 reduces the climate impact substantially because
it eliminates CO2 and all non-CO2 emissions (e.g., nitrogen oxide (NOx) and sulfur oxide (SOx)). Hence,
LH2 is a likely option for ship types that undergo stringent emission regulations such as small passenger
ships sailing through natural reserves. However, the large volumes required for storage compared withother high density shipping fuels make LH2 a less preferable option for long-haul shipping.
Ammonia is a compound of nitrogen and hydrogen featuring a high energy density (50% higher than
LH2). Companies can produce it carbon-neutrally via renewable hydrogen from electrolysis. NH3 is easy
to store and can use existing ammonia supply chains and infrastructure. Due to its toxicity, ammonia
may prove challenging for some ship types (e.g., ships with passengers) due to safety concernsand potential future regulation around its storage onboard and in bunkering locations close to highly
populated regions. To maximize the impact of ammonia as a sustainable shipping fuel, measures forstrict control of NOx and other non-CO2 emissions must be in place.
Methanol results from combining CO2 and hydrogen. Suppliers can produce it carbon-neutrally fromrenewable hydrogen and CO2 from DAC, biogenic CO2 or with reduced carbon emissions if CO2 fromindustrial emissions serves as a feedstock. Regardless of the production route, fueling propulsion
systems with methanol causes CO2 emissions, partially offsetting the CO2 savings from production.
Like ammonia, methanol benefits from an existing global infrastructure and limited conversion costs forexisting vessels.
TCO perspective
The most cost-effective decarbonization path differs per sub-segment of commercial shipping as eachhas distinct operating characteristics and economics. To account for such differences and investigate
the role hydrogen-based fuels might play, we chose container ships and cruise ships for modeling.
Both chosen sub-segments play a key role in the global shipping industry: container ships accountfor the largest share of global fleet emissions with 23%, and cruise ships represented the fastest
growing segment before the COVID-19 pandemic. In addition, both segments are among the likely
early-adopters of decarbonization strategies, given their proximity to end consumers that exhibit higher
willingness to pay and face external regulatory pressures.
Container ships
In the long-term, green ammonia will be the cheapest zero carbon fuel for container ships, requiring
USD 85/t of CO2 to breakeven with HFO as illustrated in Exhibit 24. Dual-fuel ICE engines will accelerate
decarbonization in the transitional period of the next 10 to 15 years before alternative fuels andpropulsion systems reach scale. In the long-run, ammonia fuel cells should become the preferred
propulsion system given their higher fuel efficiency compared with combustion engines and expectedsignificant decrease in CAPEX over time.
Container ship operators should be able to allocate the additional costs associated with alternative fuels
entirely to end customers as the cost increase only accounts for a fraction of the shipped product’s
final price. For example, a pair of jeans that retails at USD 60 and is transported from Southeast Asia to
the US would become less than 1% (USD 0.13) more expensive if transported on a ship powered by anammonia ICE engine compared with a ship running on heavy fuel oil (see Exhibit 24).

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Exhibit 24: Competitiveness of alternative fuels in container shipping in 2030
Mn USD/year for container ship1 andbunkering location in Middle East
2030

xx CO2 cost required to breakeven with Heavy Fuel Oil,
USD/tonIncumbent fuelZero-carbon shipping fuelLow-carbon shipping fuelxx Additional price per jeans,
USD

~10

~90

~310

~85

~195

~335

~385

<0.01

0.07

0.17

0.13

0.29

0.49

0.56

Breakeven carbon tax higher for biodiesel than ammonia, given
inherent carbon emissions in biodiesel (0.6 x emissions of HFO)

56
52

42
36
33
30
26

26

Heavy fuel oil
ICE

LNG
ICE

O&M
Fuel

Capex2

1.
2.
3.
4.

Dual fuelAmmonia ICE 3

Biodiesel
ICE4

Ammonia
ICE

Methanol
ICE

LH2
ICE

AmmoniaFC

67 MW ship, TEU = 13,000–15,000, sailing distance of 84,200 sm/year
Including opportunity costs from increased space requirements compared to HFO ICE engine
Dual fuel engine powered by 50% HFO and 50% ammonia
2nd generation biodiesel based on used cooking oil

Cruise ships
Compared with container ships, cruise ships exhibit a different route profile with shorter trip lengths,
frequent stops, and more stringent safety regulations and risk considerations, all of which will likely
rule out the use of ammonia due to its toxicity. Given this probability, carbon-neutral methanol andliquid hydrogen become the most viable fuel options, requiring about USD 300/t of CO2 to breakeven with HFO, as illustrated in Exhibit 25.
As with container ships, dual-fuel ICE engines offer cruise ships a transitional technology until the fullroll-out of methanol ICE and LH2 fuel cells takes place. In the short run, this hybrid solution offers up
to 25% lower costs compared with the fully decarbonized drive types.
Biodiesel and LNG – both discussed as transitional fuels – reduce but do not eliminate GHG
emissions. LNG has the additional disadvantage of methane slippage, which has a stronger negative
climate impact than CO2. Thus, potential zero emission regulation will likely rule out the use of either
fuel in some ships.
Comparable to container ships, cruise ship operators could also potentially pass the resulting
cost increases of switching to green methanol or LH2 to end consumers, as certain cruise shippassengers may have both the means and the willingness to pay for decarbonization. For example, atypical 10-day Baltic sea cruise of USD 1,400 would add about USD 660 to the average ticket pricefor methanol if all incremental costs were allocated entirely to customers (see Exhibit 25).

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Exhibit 25: Competitiveness of alternative fuels in cruise ships in 2030
Mn USD/year cruise ship1 andbunkering location in Europe
2030

xx CO2 cost required to breakeven with Heavy Fuel Oil,
USD/tonIncumbent fuelZero-carbon shipping fuelLow-carbon shipping fuelxx Additional price per ticket,
USD

~415

~400

~315

~310

~480

~540

~630

~150

~325

~365

~660

~1,020~1,145~1.340

54
47

49

39
32

32

Biodiesel
ICE3

Dual fuelMethanol ICE4

28
O&M

25

Fuel

Capex2

Heavy fuel oil
ICE

1.
2.
3.
4.

LNG
ICE

Methanol
ICE7

LH2
ICE

Methanol
FC

LH2
FC

18 MW ship, GT > 10,000, sailing distance of 138,200 sm/year
Including opportunity costs from increased space requirements compared to HFO ICE engine
2nd generation biodiesel based on used cooking oil
Dual fuel engine powered by 50% HFO and 50% methanol

E. Aviation
The aviation sector emits more than 0.9 Gt of CO2 per year, the equivalent of approximately 2% of
the world’s carbon emissions. In the past decade, the industry has shown an increased focus on
decarbonization, leading to the International Air Transport Association’s (IATA) target of halving CO2
emissions by 2050 compared with a 2005 baseline.
The industry has a strong record on fuel efficiency improvement, cutting fuel burn per passengerkilometer in half since 1990. However, operational efficiency improvements will not be enough torealize the decarbonization targets communicated by IATA.
Decarbonization options
As one of the hardest-to-abate sectors with high daily range requirements and weight constraints,
aviation decarbonization options remain limited. Since batteries and electrification are currently
impractical in aviation, the focus shifts to alternative fuels as substitutes for highly refined, fossil
fuel-intensive jet fuel. A range of alternative fuels that vary in technological maturity and feedstock
availability could substitute for traditional jet fuel.
Biofuel is the most mature and proven technology of those available. As for exact costs, theCO2 reduction potential depends on the feedstock source chosen for biofuel production. Acrossfeedstocks, a 70-90% reduction of CO2 emissions compared with kerosene (jet fuel) is possible
on a lifecycle basis with biofuels. Yet, contrary to other alternative fuels, biofuels emit particulatematter and other pollutants, which drive aviation’s negative climate impact. Another challenge arises

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from potential feedstock shortages due to high demand from other segments (as discussed in the
shipping fuels chapter).
Synthetic jet fuels (also called synfuels) represent another jet fuel alternative that suppliers can
produce in a low-carbon way through the reaction of renewable hydrogen and CO2. Unlike purehydrogen solutions, synfuels can use existing jet fuel infrastructure and propulsion systems. The CO2
decarbonization potential depends on the CO2 feedstock source – direct air capture, in contrast to
industry CO2 emissions, creates a zero-carbon fuel. Even though synfuels do not eliminate emissions
beyond CO2 and thus reduce the overall climate impact to a lesser extent than pure hydrogen,they are one of the only viable options for the decarbonization of long-range flights from a cost
perspective.
Liquid clean hydrogen is the most nascent technology in this group given its need for new propulsion
systems (such as hydrogen combustion turbines or fuel cells) as well as storage and storage
management systems. Hydrogen is the only alternative fuel that cuts all CO2 emissions from flying.
Furthermore, LH2 can reduce a significant share of all non-CO2 emissions like like NOx and SOx,
leading to an overall reduction of 50-90% in climate impact which exceeds the reduction potentialof all other alternative fuels. Contrary to other sustainable aviation fuels, LH2 requires an overhaul ofexisting fuel infrastructure.
TCO perspective
In aviation, the choice of the optimal low-carbon fuel depends on the size of the aircraft and the
distance to be covered. To provide a perspective on the entire aviation industry, we modeled fivedifferent use cases: a commuter jet (19 PAX, 500km), a regional jet (80 PAX, 1,000km), a short-range
aircraft (165 PAX, 2,000km), a medium range aircraft (250 PAX, 7,000km) and a long-range aircraft(325 PAX, over 10,000km). The costs modeled represent all direct and indirect costs, including
CAPEX increases of the aircraft as well as infrastructure requirements.
Overall, the results show that hydrogen at scale can cost-effectively decarbonize flights up to theshort and medium range categories, which account for 70% of global aviation CO2e emissions. As
highlighted in Exhibit 26, for the four use cases in this range, liquid hydrogen is the most competitive
abatement option at a cost of USD 90-150/t of CO2e by 2040. It also outperforms synfuel by 15-85%
in terms cost per available seat-kilometer (CASK).
Beyond the 10,000km range, the storage space requirements make hydrogen unfeasible in termsof cost. Thus, for long-range flights, which account for 30% of global CO2e emissions, synfuel is themost cost-competitive decarbonization option, at a cost of USD 200/t of CO2e.
Note that, unlike in the rest of the report, we take a 2040 perspective here because an earlier entryinto-service and commercialization assumption for hydrogen-based aircraft remains unlikely (seeExhibit 26).

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Exhibit 26: Total cost of ownership of aviation fuels for different use cases in 2040

Jet fuel (fossil)

Commuter
19 PAX, 500 km

Regional
80 PAX, 1,000 km

Short-range
165 PAX, 2,000 km

40

70

100

Abatement costs
USD/ ton CO2eq

Costs per available
seat kilometer
USD cents

Hydrogen1

255

255

Synfuel (with direct air captured CO2)1

Medium-range
250 PAX, 7,000 km

200

170

200

Long-range
325 PAX, 10,000 km

270

200

15.3
13.7
13.1

7.4
6.7
6.0

5.8
4.5

4.6

4.2

<1%

3%

24%

5.2

3.8

3.6

Share of global
aviation CO2, %

5.8

5.8

43%

30%

1. Hydrogen propulsion assumed to be fuel cell-based for Commuter and Regional flights, and H2 turbines for Short/Medium/Long-range aircrafts. Synfuel produced with
Reverse Water Gas Shift reaction and Direct Air Capture (DAC). Production based in Europe

Zoom-in on short-range segment. Hydrogen is a more competitive decarbonization alternative
for short-range flights than synfuel as it outperforms synfuels in both costs and climate impact. Overtime, the cost advantage of hydrogen over synfuels will decrease as costs for the direct air capture
technology required to produce carbon neutral synfuels fall.
Switching from kerosene to hydrogen implies a cost of about USD 100/t of CO2e. If this additional
cost were allocated entirely to the end consumer, it could raise the price of an airplane ticket by 3035% in 2030 or USD 25 for a one-way flight from Frankfurt to London (see Exhibit 27).
Zoom-in on long-range segment. For the long-range flight segment synfuel is the most costcompetitive viable decarbonization option, as the required tank size would rule out hydrogen for
distances of more than 10,000 km. While synfuel in the near future is still expensive, the costs ofsynfuel should drop significantly (by over 50% between 2020 and 2040), driven by the decreasing
feedstock prices of hydrogen and CO2. However, a high carbon cost of between USD 200 and 250/t
of CO2e is still needed to break even with kerosene. In a scenario with a USD 50/t of CO2 cost ofcarbon in 2030 and a strong acceleration to USD 200/tCO2 by 2040, synfuel could break even withconventional jet fuel between 2038 and 2043 for long-range flights, as shown in Exhibit 28.
For the end customer, the ticket price for a long-range flight from London to Singapore (with anaverage ticket price of USD 600) might increase by up to USD 300 by 2040 if airlines allocate costs
entirely to the end customer.

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Exhibit 27: Total cost of ownership of a short-range flight over time
Cost per available seat kilometer
USD cents
9.0

Use case:
Flight of 2,000km
with 165 pax

8.5
8.0
7.5
7.0
6.5
6.0
5.5
5.0

Kerosene (with rising
CO2 costs)1

4.5

Synfuel (with direct air
captured CO2)
H2 direct propulsion

4.0
3.5
2020

Kerosene(no CO2 costs)

25

30

35

40

45

2050

1. CO2 cost growing from approx. 30 USD/t CO2e in 2020 to 50 USD/t CO2e in 2030, 200 USD/t CO2e in 2040 and 300 USD/t CO2e in 2050

Exhibit 28: Total cost of ownership of a long-range flight over time
Cost per available seat kilometer
USD cents
11.0
10.5

Use case:
Flight of 10,000km
with 325 pax

10.0
9.5
9.0
8.5
8.0
7.5
7.0

Kerosene(with rising
CO2 costs) 1

6.5
6.0

H2 direct propulsion

5.5
5.0

Synfuel (with direct air
captured CO2)

4.5

Synfuel(with industrial CO2)

4.0

Kerosene(no CO2 cost)

3.5
2020

25

30

35

40

45

2050

1. CO2 cost growing from approx. 30 USD/t CO2e in 2020 to 50 USD/t CO2e in 2030, 200 USD/t CO2e in 2040 and 300 USD/t CO2e in 2050

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40Hydrogen scale up
will require capital andsector-level strategies

70bn
committed public funds by governments to supporthydrogen transition strategies

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VI | Implementation: bringing it all
together to capture the promise ofhydrogenThe strong commitment to deep decarbonization by governments worldwide has triggered an
unprecedented wave of momentum in the hydrogen industry. Financial support, regulation and clearhydrogen strategies and targets in combination with the USD 70 billion committed public funds bygovernments to support the hydrogen transition have caused value chains to scale up, costs to comedown and investments to climb to new heights.
The next chapter in the hydrogen story requires stakeholders to translate their ambitious strategies
into concrete measures. Governments, businesses and investors should set sector-level strategies(e.g., for the decarbonization of steel), with long-term targets, short-term milestones, and thenecessary regulatory frameworks. They must develop value chains for equipment, scale up
manufacturing, attract talent, build capabilities, and accelerate product and solution development.
This scale up will require capital, and investors have an outsized role to play in developing andpushing at-scale deployments. All this will require new partnerships and ecosystem building, withboth businesses and governments playing important roles.
To get things started, strategies should aim at the critical unlocks, like reducing the cost of hydrogenproduction and distribution. We estimate that roughly 65 GW of electrolysis are required to bringcosts down to a breakeven with gray hydrogen. This equals a funding gap of about USD 50 billion.
One place to support deployment is the development of clusters with large-scale hydrogen offtakers
at their core. These will drive scale through the equipment value chain and reduce the costs ofhydrogen production. By combining multiple offtakers, players can share investments and risks
and begin to establish positively reinforcing collaborative loops. Other smaller hydrogen offtakers in
the vicinity of such clusters can then piggy-back on the lower-cost hydrogen supply, making theiroperations breakeven faster.
Based on these core characteristics, we see several cluster types gaining traction, including:— Port areas for fuel bunkering, port logistics, and transportation— Industrial centers that support refining, power generation and the production of fertilizer or steel— Export hubs in resource rich countries
To make clusters successful, they should include players along the whole value chain to optimize
costs, tap into multiple revenue streams and maximize the utilization of shared assets. They shouldbe open to additional players and infrastructure should allow easy access where possible.
The next few years will be decisive for the development of the hydrogen ecosystem, for achieving
the energy transition and for attaining the decarbonization objective. As this report shows, progressover the past year has been impressive, with unprecedented momentum. But much lies ahead. The
companies in the Hydrogen Council are committed to deploying hydrogen as a critical part of thesolution to the climate challenge and Hydrogen Insights will provide a regularly updated, objective
and global perspective on the progress achieved and the challenges ahead.

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Hydrogen Council, McKinsey & Company

Glossary

ATR

Autothermal reforming

BEV

Battery electric vehicle

BF

Blast furnace

BOF

Blast oxygen furnace

BT

Benzyltoluene

CAPEX

Capital expenditure

CASK

Cost per available seat kilometer

CO2

Carbon dioxide

CO2eCarbon dioxide equivalent

CCS

Carbon capture and storage

CCU

Carbon capture and utilization

DAC

Direct air capture

DRI

Direct reduced iron

EAF

Electric arc furnace

EPC

Engineering, procurement and construction

ESG

Environmental and social governance

EU

European Union

FC

Fuel cell

FCEV

Fuel cell electric vehicle, including light- and heavy-duty vehicles, andmaterial-handling vehicles

FID

Final investment decision

GHG

Greenhouse gas

GDP

Gross domestic product

Gt

GigatonHDT

Heavy duty truck

HFO

Heavy fuel oil

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HRS

Hydrogen refueling stations

H2

Hydrogen

IATA

International air transport association

ICE

Internal combustion engine

IMO

International maritime organizationkg

Kilogramkm

Kilometer

LCFS

Low carbon fuel standard

LCO2

Liquid carbon dioxide

LCOE

Levelized cost of electricity

LH2

Liquid hydrogen

LNG

Liquefied natural gas

LOHC

Liquid organic hydrogen carrier

MENA

Middle East and North Africa

MeOH

Methanol

MMBTu

Million British thermal units (unit of energy, 1 MMBTU = 1.06 GJ)

Mt

Million tons

M&A

Merger and acquisition

NH3

Ammonia

NOx

Nitrogen oxides (type of tailpipe emission from ICE vehicles)

PAX

Persons approximately (number of passengers carried)

PEM

Polymer electrolyte membrane

PV

Photovoltaics

R&D

Research and development

RE

Renewable energy

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RES

Renewable energy sources

SMR

Steam methane reforming

SOx

Sulfur oxides (type of tailpipe emission from ICE vehicles)

SUVSport utility vehicletTon(s)

TCO

Total cost of ownership

TW/GW/MW/kW

Terawatt, gigawatt, megawatt, kilowatt (unit of power, 1 Watt = 1 J per s)

TWh/MWh/kWh

Terawatt hour, megawatt hour, kilowatt hour (unit of energy, 1 Watt-hour =3600 J)

USD

United States Dollars

WACC

Weighted average cost of capital

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