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Turning the European Green
Hydrogen Dream into Reality:
A Call to Action
Without additional regulatory support, European green hydrogenmay remain the fuel of the future

October 2023
By Jens Burchardt, Esben Hegnsholt, Mogens Holm, Frank Klose, Daniel Ritter, and Stefan Schönberger

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The Dream of Green Hydrogen
to Become Reality?
Green hydrogen is a critical element to achieving net-zero emissionsA

s we stated in our 2019 publication The Real Promise of Hydrogen, low-carbonhydrogen and associated synthetic fuels like methanol and ammonia are
indispensable to decarbonizing large sectors of the global economy.

While a broader range of low-carbon hydrogen colors will be needed during thedecarbonization journey, a fossil-free target state will require green hydrogen. To beable to enable the continent’s ambitious climate targets, Europe’s green hydrogenmarket finally needs to scale within this decade.

Europe’s hydrogen market is beginning to take shape …
After a decade of much debate, a meaningful hydrogen market and a multibillion-euro
market for green hydrogen now seems to be emerging on the horizon. A good deal ofthis is driven by a flurry of regulatory activity across the hydrogen value chain:• Subsidy schemes are emerging to support investments in hydrogen production,such as the Dutch SDE++ for domestic projects or the European Hydrogen Bank and
H2Global for imports.
• Infrastructure access is starting to become clearer, as the development of firstelements of the European hydrogen backbone is being expedited in several countries—
with the support of the EU IPCEI scheme.
• Hydrogen demand is being stimulated by investment subsidies (such as for thethyssenkrupp DRI steel plant) and by ongoing discussions on consumption subsidies(such as the German carbon contracts for difference for potential industrial offtakers).
Germany is also planning auctions for its first hydrogen-only backup power plants.
• The recently agreed RED III imposes the mandatory use of RFNBO (including greenhydrogen) for EU industry consumption by way of quotas.1 Further, a combined subtargetof 5.5% for advanced biofuels and RFNBOs was agreed upon, with a minimum requirement of 1% RFNBOs supplied to the transport sector in 2030.
Meaningful demand is expected to emerge if planned regulations come into effect. Several
industrial sectors, primarily current gray hydrogen consumers, may be willing to pay aroundor above €6/kg for green hydrogen by the end of the decade.
Refineries will contribute significant volumes to this demand. Despite some uncertainty
regarding RED III implementation details,2 oil players are already taking action. For instance,
BP and Total are willing to pay a €12.6B premium for 7 GW offshore wind power generationthat secures them green hydrogen at a cost above €6/kg.
Additional sectors such as ammonia and methanol production are also relevant, along withthe portion of Europe’s steel industry capable of selling premium green steel. In Germany
and the Netherlands alone, this “high-price plateau” could drive approximately 1 Mt ofgreen hydrogen demand annually by 2030, equivalent to over 10 GW of electrolyzer capacity.
And as demand is taking shape, so is hydrogen supply. A number of project developers are
currently driving industrial-scale green hydrogen projects to final investment readiness. Again
in Germany and the Netherlands alone, a total pipeline of 23 GW in electrolyzer capacity by
2030 is currently in planning, with 4 GW already at least in the FEED phase.

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Germany 2030: ~ 0.4 Mt green hydrogen demand potential above €6/kg
Exhibit 1: Hydrogen demand merit order for Germany in 2030

German green hydrogen offtakers’ willingness to pay in 2030€/kg H2 (base case)Ammonia
MethanolSteel
Refineries
Industrial heat
Power generation
Aviation
Shipping

10
430 ktpa H2 (~ 4 GW electrolyzersa)
demand potential above €6/kg H2,
thereof ~ 60% from refineries

0
5

10

15

Structural H2 demandpotential
Mtpa

a. Assuming 65% electrolyzer efficiency (LHV) and 5,000 full load hours
Source: BCG analysis… but it is not yet taking off
And yet, investment decisions are still pending. Europe’s hydrogen market still needs toovercome several major barriers to reach its actual potential.
Optimistic cost projections are not materializing. Just a few years ago, the consensus
view expected green hydrogen production costs below €3/kg; see exhibit 2. Meanwhile, adeteriorated macroeconomic context, higher energy market prices, and structural challenges
in the wind power and electrolyzer supply chains prove these costs unrealistic, at least forthe coming decade. As a result, real hydrogen asset projects currently in development suggest green hydrogen production costs in the range of €5–8/kg in 2030 for central Europe.
Even at the lower end of these costs, green hydrogen is not competitive with alternative
decarbonization technologies for most potential consumers. At the higher end, greenhydrogen producers would struggle to find offtake at all.

1. The RED III quota requires the mandatory use of at least 42% RFNBO—effectively green hydrogen—of EU industry’s total hydrogen consumption by 2030 and 60% by 2035.
2. It is not yet clear to what extent refineries’ hydrogen consumption will be considered within RED III industry
versus transport sector quotas and how relevant multipliers for the transport sector quota will be set in
the future.

TURN THE GREEN HYDROGEN DREAM INTO REALITY: A CALL TO ACTION

Real asset projects reveal much higher green hydrogen costs than pastconsensus views
Exhibit 2: Green hydrogen wholesale price projections in Europe in 2023
Driving factors for cost increase versus pastconsensus view2030 green H2 costs in central Europe€/kg H2

Cyclical€5–8/kg H2

Higher capital costs resulting inhigher return requirements from green
power and electrolyzer investments
Fewer electrolyzer full-load hours,
as wholesale power market offers better prices to wind farms more often>2×Supply chain constraints of wind
power and electrolyzer manufacturers< €3/kg H2

Complex “real-life” electrolyzer
systems incl. BOP,a many components
with limited cost reduction potentialb

2021
Consensus view

2023
Asset projects

Structural

Lacking infrastructure will limit
availability of lower-cost green H2pipeline imports in next ~ 10 years

a. BOP = balance of plantb. Such as power electronics or gas conditioning, which are already standard components in utility-scale applications
Source: BCG analysis

Cost sensitivity to green hydrogen production
The cost of delivered green electricity still
remains the largest factor determining overall green hydrogen economics. As a result ofa higher cost of capital and structural supply
chain challenges of wind power systemmanufacturers, the levelized cost of powerhas significantly risen in recent years and islikely to remain above pre-crisis levels during
this decade. Also, given that green hydrogenin most European countries has to be produced from additional non-subsidized renewables, electrolyzers are competing for green
power with skyrocketing wholesale prices on
the captured-power market.
High electrolyzer utilization can be amajor lever for decreasing hydrogen production costs—but will come at a trade-off withgreen power costs in most locations. However, by following an integrated approach tolocation choice, renewable electricity production, electrolyzer configuration, and power
market situation, hydrogen project developers can achieve significant production costadvantages over their competitors.
BOSTON CONSULTING GROUP

Electrolyzer system costs have not dropped
yet and are not likely to fall as fast as expected a few years ago.
Structural supply chain constraints on thepart of electrolyzer manufacturers as well as
more-complex-than-expected system designs
result in persistently high electrolyzer systemcosts. Updated assessments also suggest
limited cost reduction potential for many
components already being used today on anindustrial scale, such as power electronics orgas conditioning. Decreasing electrolyzer
system costs can be achieved by streamlined
project development processes and capabilities, closer collaboration across the value
chain, and scale in the project portfolio.
Optimizing electrolyzer efficiency can help
push down the cost of hydrogen production.
However, large improvements in thesefactors will entail a trade-off withelectrolyzer CAPEX.

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Low-cost green electricity at high electrolyzer utilization as major drivers
for attractive hydrogen economics
Exhibit 3: Green hydrogen production cost sensitivities

2030 green H2 production costbaseline in central Europe
6.0 €/kga

Baseline
value

Sensitivity
analysis

Delivered (green) electricity (€/MWh)65-25/+15

Electrolyzer utilization (%)

55%+25/-10 pp

Electrolyzer system costs (€/kW)

1,700-500/+400

Electrolyzer WACC (%)

8%

±2 pp

-0 .3

+0.3

Electrolyzer efficiency (%)

62%

±3 pp

-0 .3

+0.3

-1 .3

+0.8

-0 .8

+0.6

-0 .7

a. Real in 2023, representative of current asset project cost projections in central Europe
Note: Electrolyzer life span of 15 years and electrolyzer OPEX of €0.3/kg H2
Source: BCG analysis

Major offtakers are themselves at risk.
Cheaper green end-product imports posea significant threat to offtakers in sectors likeammonia, methanol, and steel. The European
ammonia industry already lost significant
market share during last year’s energy crisis.
At domestic green hydrogen prices beyond€4–5/kg, European producers would hardly
be able to compete with green ammonia
imported from regions with better

+0.5

Lower
H2 costs

Higher
H2 costs

renewable power conditions. And this threat
may only intensify over time. As the globalhydrogen market matures and regions with
better renewable conditions achieve steeper
production cost declines, increasing European
production volumes of products such as
ammonia, methanol, or iron sponge will be
at risk—potentially diminishing Europe’s
future hydrogen market potential.

TURN THE GREEN HYDROGEN DREAM INTO REALITY: A CALL TO ACTION

Ammonia: Willingness to pay for green hydrogen determined by RED III
and blue hydrogen costs
Exhibit 4: Dutch ammonia players’ willingness to pay for green hydrogen in 2030
Domestic production
under RED III quota€6.9/kg

Domestic production
outside RED III quota

Import of green andblue ammonia

Level of RED III penalty(here €450/t CO2) sets
upper WTP boundary

Potential
RED III
penalty€2.8/kg(Part of ) EU production
under RED III quota faces
risk of displacement bycheap imports

Cost of blue H2 setslower WTP boundary€4.5/kg€2.8/kg

LCOH

Full
costa

Full
costa

Full
costa

Steam methane
reforming

Steam methane
reforming“Domestic blue
H2”(ATR + CCS)

€3.1/kg
ATR + CCS
full costa

Logistics

Logistics

Green H2 from
Saudi Arabia

Blue H2 from theUnited Statesa. CAPEX, OPEX, natural gas, and CO2 costs for steam methane reforming, ATR, and CCS, respectively
Source: BCG analysis

Offtakers are unable to commit to long-term contracts. With the common market
expectation of decreasing production costs from new projects over time, offtakers of greenhydrogen are very reluctant to commit to long-term contracts of more than a few years.
Yet without secure long-term offtake, early hydrogen project developers face the risk of
stranded assets, undermining investment prospects. This deadlock perpetuates a chickenand-egg problem, preventing the hydrogen market from gaining faster momentum.

BOSTON CONSULTING GROUP

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Very few green hydrogen customers are able to commit to long-term
offtake contracts
Exhibit 5: Industry customers’ willingness to commit to hydrogen contracts(survey with 166 participants)
Survey question: “What commitment period for green hydrogen supply contracts would you
be most willing to enter into?”
49%

Only 3% of survey participants
are willing to commit togreen hydrogen contracts
exceeding five years

Refineries
Process industries
Chemical, steel, non-iron
metals, building materials,
minerals, and mining

31%

Industrial goods
Mechanical industry,
automotive, paper, glass,and packaging

17%

2%
0 years
Spot market only

< 2.5 years< 5 years< 10 years

1%< 15 years

Source: Based on responses to a customer survey with n = 166 respondents in Germany and the Netherlands
across relevant sectors; BCG analysis

Policymakers aren’t done yet
Despite all progress: Under Europe’s current regulatory environment, domestic green hydrogen will remain the fuel of the future. Ambitious national implementation of EU regulation isneeded now to create incentives throughout the hydrogen value chain.
Regulations should help bring green hydrogen costs to offtakers at least below€5/kg, given that higher costs than that would severely threaten the international competitiveness of key offtake industries, particularly chemicals and steel—even compared to green
imports. To achieve this, double-sided auctioning initiatives like the European Hydrogen
Bank and H2Global could be expanded in their financial volume and extended in their scope
to also support large-scale domestic projects.3 To increase the competitiveness of domestic
projects in these auctions, policymakers should continue granting CAPEX funding (e.g., IPCEI)
for the coming years and consider allowing green hydrogen producers to source powerfrom new renewable generation with state-backed price guarantees like carbon contracts fordifference schemes.4 Beyond 2030, other green hydrogen cost decreases toward €3/kg will
require electrolyzers operating at maximum capacity at the lowest possible green power
costs. Turning this European hydrogen dream into reality will require regulators to immediately accelerate the deployment of low-carbon power, grid, and storage infrastructure, and to
stimulate demand-side flexibility.
Upcoming demand-side regulation needs to create sufficient willingness to pay.
For existing gray hydrogen producers such as refineries and chemical companies, RED III isplanning firm quotas for green hydrogen shares. To generate a willingness to pay beyond €5/kg,
this would need to carry hefty noncompliance penalties of around €450/t CO2. In parallel,
Europe should establish frameworks that enable producers of green commodities to sell at
a premium. For example, green steel or fertilizer quotas would allow key green hydrogenofftakers to pass additional costs on down the value chain.5 Finally, any demand-side subsidy
schemes should be tailored to specific industries. For example, if Germany’s carbon
TURN THE GREEN HYDROGEN DREAM INTO REALITY: A CALL TO ACTION

contracts for difference tenders were industry-agnostic, a company aiming to shift fromnatural gas to hydrogen-based steel production would have to compete against a company
electrifying its heat generation at a much lower cost. In practice, this would decelerate
decarbonization efforts in all industries where decarbonization is comparatively expensive
and drastically limit short-term hydrogen demand.
The development of hydrogen infrastructure must not be delayed. To create infrastructure clarity for producers and offtakers alike, policymakers need to impose ambitious planning
through grid agencies, create favorable investment conditions through incentive regulationand public funds, and prioritize the rapid deployment of transport and storage infrastructure.
Connecting EU industrial centers with the lowest-cost hydrogen production sites should bea priority for the decade ahead.

Exact design of only a few regulations will strongly impact the European
green hydrogen market
Exhibit 6: Key regulations needed to enable the takeoff of the European
green hydrogen market
H2 supply
Bring H2 costs
to offtakers
below ~ €5/kg

Goals

Expand funds for
H2Global/the
Europ. Hydrogen
Bank (EU) andSDE++ (NL)

Regulatory
instruments

Extend H2Global/
the European
Hydrogen Bank
to large-scaledomestic projects
Decrease LCOH:Electrolyzer CAPEX
funding, RES CfD
for green H2 production, accelerated
deployment of
RES, power grids,
and demand-side
flexibility

Refineries

Chemicals

Power

Infrastructure

Raise willingness to pay above €5/kg H2 for relevant volumes
to match expected supply

Create clarity
within this year

RED III noncompliance penalty~ €450/t CO2
Adjust e-mobility
multipliera to set
conditions for
HBE/GHG quota
of > €3/kg

Steel

Green steel quota

Sector-specific demandside subsidiesb
RED III applicability also on imported
end products, e.g., fertilizer
Evaluation of (subsidized) local“safety reserve” volume production

Incentives for new
H2 capacity, e.g.,targeted H2
backup tenders
Financing of thegap between H2and natural gas,e.g., CCfDs
Use of existingmechanisms
to speed
implementionc

Sufficient DRICAPEX subsidies

NL: already clear
perspective given
DE: finish H2concept within ’23
as planned
Implement H2 ingrid developm.
plan and incentive
regulation
Ensure initialpublic funding
and planning anddecisions similar toGerman LNG act

a. To prevent the market from being flooded with certificates when e-mobility scales up
b. E.g., through targeted climate protection agreements in Germany and continued rollout of tailor-made agreements in the Netherlandsc. Climate protection agreements and power plant tenders in DE, SDE++, and tailor-made agreements in NL
Source: BCG analysis

3. Such public tender schemes would also help alleviate the “contract duration dilemma.”
4. In many European power markets, wholesale prices will exceed the levelized cost of renewable power
production during many hours in any given year throughout this decade. With unsubsidized renewables,
this will result in low electrolyzer utilization and hence higher green hydrogen prices. Green hydrogenproduced from renewable sites under a (nominally, but not factually subsidized) carbon contracts fordifference scheme would decrease the cost of invested capital and result in cheaper green hydrogenproduction while still providing project developers with reasonable returns.
5. Such RFNBO quotas would need to be accompanied by strict product certification rules for both domestic
and imported goods.

BOSTON CONSULTING GROUP

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Hydrogen players should also embrace action
The absence of decisive regulation should not prevent hydrogen players from taking action.
The emerging hydrogen market is a rare market opportunity. The question is not whether
it will flourish, but rather exactly when in the coming years, where, and how. Proactivity will
empower hydrogen players to seize immense potential and establish a leading position inthis transformative market.
Market players should embrace risk-taking and get a robust pipeline of hydrogenprojects FID-ready. This will require risking significant development expenditure—but for
the likely reward of faster capability buildup, privileged access to the most promisingofftakers, strategic partnerships with equipment manufacturers, and higher credibility withkey regulatory bodies. In earlier emerging industries like offshore wind and electromobility,
early movers have reaped lasting dividends. Hydrogen seems to be the same.
The cost of green hydrogen needs to fall faster. Players should push to streamline project development and scale up collaborations with electrolyzer OEMs and EPCs. They should
also reemphasize technical and economic integration between electrolyzers and renewablegeneration assets, often requiring close collaboration across business units.
Producers should reassess their target customer base. The emerging regulatoryenvironment is (re)shaping Europe’s demand market. Future producers should revisit their
go-to-market approach and make sure they understand how upcoming regulations will
impact potential offtakers’ hydrogen appetite, their willingness to pay, and their (partial)
default or relocation risk.
The industry should conduct factual and well-informed advocacy. Scaling hydrogen inotherwise hard-to-abate applications is in society’s interest. In recent years, much of advocacy
has centered on formulating ambitious goals to create the needed transformative momentum.
Now that regulation and public funding need to be focused on finally kick-starting the greenhydrogen market, regulators are increasingly receptive to facts about the key obstacles ahead
and to pragmatic solutions to remove them. Unrealistic claims about the cost of green hydrogen, its competitiveness, and time to scale will do the hydrogen industry, its customers, andsociety at large a disservice.

TURN THE GREEN HYDROGEN DREAM INTO REALITY: A CALL TO ACTION

Europe’s (green) hydrogen market has
made major progress in recent years,
but without additional funding and a
regulatory framework, hydrogen stillrisks remaining the fuel of the future.
Ambitious national implementationof EU regulation is needed now.
Policymakers and market players alikeneed to increase momentum to makesure this transformative industry
reaches its full potential.

TURN THE GREEN HYDROGEN DREAM INTO REALITY: A CALL TO ACTION

About the Authors
Dr. Jens Burchardt
burchardt.jens@bcg.com
Managing Director and Partner, Berlin
Esben Hegnsholt
hegnsholt.esben@bcg.com
Managing Director and Partner, Copenhagen
Mogens Holmholm.mogens@bcg.com
Partner and Associate Director, CopenhagenFrank Klose
klose.frank@bcg.com
Managing Director and Senior Partner, Düsseldorf
Dr. Daniel Ritter
ritter.daniel@bcg.com
Project Leader, Munich
Stefan Schönberger
schoenberger.stefan@bcg.com
Partner, Berlin

For further information
If you would like to discuss this report, please contact the authors.

BOSTON CONSULTING GROUP

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