TRADING PARTNER

EHB Implementation Roadmap:
Public support as catalyst forhydrogen infrastructure
European Hydrogen Backbone
APRIL 2024

TRADING PARTNER

Hydrogen and the EHB are crucial enablersof the European energy transition.

Connective hydrogen
infrastructure is central
to the energy transition—

A successful early rollout of hydrogen
infrastructure will be key to achieving
Europe's decarbonisation targets by
2030 and beyond.

—

Pan-European hydrogen infrastructure
supports the scale-up of renewableenergy and bolsters security of supply,with connectivity between supply anddemand regions directly contributing
hundreds of billions of euros in savings.1

Hydrogen cluster
approach

Pan-European
networkhydrogen supply
close to demandhydrogen supply
from cheaper regions

Early market dynamics during the scale-up of hydrogen result in misaligned incentives
for EHB buildout, hindering proactive early-stage investments.
Investors are willing to invest in bankable projects but require guarantees.

—

Investors seek projects with firm end-user commitments, which are difficult to obtain in the earlystages of market ramp-up.

Pipelines sensibly built to accommodate future demand come with early-stage financial risks.

European Hydrogen Backbone

Executive summary (1/2)—

The EHB is most cost-effective when sized to serve mature-market volumes, preventing expensive
expansion projects and infrastructure-related bottlenecks as the hydrogen market develops.

—

Consequently, generating sufficient revenue in the first five-to-ten years of operation poseschallenges for forward-looking pipeline developers, with low initial revenues discouraging
private investment despite the decades-long durability of decarbonisation benefits.

TSOs are pushing forward with build-out but should not be required to bear all financial risk.

www.ehb.eu—

Public risk sharing is needed to enable investment in the construction and operation of pipeline
projects, rather than disincentivising proactive TSOs by requiring them to bear the risk alone.

—

Example: A €5 billion cross-border pipeline project requires an initial investment of €125-250M
for developmental studiesa to help mature the project and make it bankable for investors.

1) Gas for Climate, ‘Assessing the benefits of a pan-European hydrogen transmission network’a) DEVEX assumed to be a percentage of CAPEX, with variability on a project-to-project basis

2

TRADING PARTNER

The EHB recommends two forms of public support: developmental support andconstruction/operating support.

Early-market public
support for hydrogen
infrastructure is the mostcost-effective way to spurthe build-out of hydrogenvalue chainsBenefits of developmental support:

Benefits of construction & operating support:

Broad allocation of early-stage developmental
support provides policymakers with key insights on
network build-out and enables developing hydrogenpipeline projects to unlock greater access to market
capital by creating bankable projects. It can also
provide cost efficiencies by spurring collaborative
development of technology.

Construction and operating support helps to alignincentives and overcome the temporary early-market
imbalance that occurs during the first five-to-ten yearsof network operation. Policymakers must avoid
penalising early hydrogen network adopters with highearly tariffs and pioneering network developers withthe full burden of market development risk.

Total external support required€B— An estimated €27.5B of public support
enables 14MT (490 TWh) of hydrogen to
be delivered by ~31.000 km of hydrogenpipelines by 2030, reducing annual
emissions by up to 312 MT CO2e per yearby 2050.b— Beyond what is currently-available in EU funding,
additional public support is needed.

European Hydrogen Backbone

Executive summary (2/2)

27.5

20

25.0

10
0

2.5
Developmental
supportConstruction &Operating support

Total required
public support

Realising 2030 decarbonisation goals requires near-term public action.
The use of public funding canbe reduced using emerging
support mechanisms.
Emerging mechanisms and regulatory
proposals such as an intertemporal costallocation framework can significantly
reduce the amount of direct publicfunding required.

www.ehb.eu

30➜ Estimates of required developmental
and construction & operating support

Support should beallocated now.
Given the typical seven-year project
development timeline and theurgency of 2030 EU climate goals,
support should be committed assoon as possible.

Further efficiency canbe gained throughbetter coordination.
Significant cost savings can berealised through network
planning and development inconjunction with other energy
vectors.

b) Metric tonnes of CO2 equivalent emissions reductions. Guidehouse, Inc analysis based on projected hydrogen demand in 2050, by sector,
using green hydrogen as a substitute for fossil energy

3

TRADING PARTNER

The scale and urgency of the challenge: .
The EU has set ambitious emissions reduction
targets for 2030 and 2050, outlining a key rolefor hydrogen in its REPowerEU strategy.

As a result, many governments and multinational
corporations are scaling down near-termemissions targets, citing supply concerns andhigh energy costs.4

According to the IPCC’s 2023 report, effective
and currently feasible options for reducing
GHG emissions are available but are not being
deployed quickly enough.2 Similarly, as of early
2024, the IEA projected that only 7% ofannounced 2030 renewable hydrogenproduction capacity is currently on track,
specifically citing a lack of transport
infrastructure as a limiting factor.3

The European energy
transition necessitatescommitted, near-term
actionHydrogen offers a multi-sectoral solution thatcomplements other decarbonisation pathways
like electrification and carbon management. It isof crucial importance to provide near-term
public financial support to hydrogen
infrastructure projects to enable it to build on
existing momentum and bolster further
decarbonisation efforts.

The EHB is a key component ofcross-sector decarbonisation,
keeping Europe on a trajectory
towards 2030 and 2050 climate
targets

Emissions (Gigatons CO2e)➜ European decarbonisation progress towards goals5,c
5.0
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
1990

2020
target2030

MS Projections

2040

2030
target

2000

2010

2020

2030

2050

“In the next decade wemust redraw the map ofinfrastructure across thecontinent. We will needelectricity super-grids. The
gas network must be
repurposed to transporthydrogen or CO2”

2050 target(net zero)

2040

2050

Historical emissions
Linear Trajectory to legislated EU targets–Šefčovič, Simpson,and Hoekstra,
6 February 2024.

2023 Member State projections with additional measures
Sources: A complete reference list is provided at the end of the report on slide 22.
Footnotes: c) Includes offset LULUCF emissions

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TRADING PARTNER

Connective hydrogen infrastructure provides the most cost-effective solution for supplying the hydrogen
economy, with a pan-European network projected to save €330B as compared to a clustered approach.
1,3,6,7

Hydrogen infrastructure
supports renewableenergy build-out,
connecting cost-effective
supply and demandacross the continent

A well-connected hydrogen networkbuilds upon the strengths of European
energy system to facilitate
decarbonisation, renewable energy
integration, and network resilience

Connectivity allows forhydrogen to be produced
in regions with greater
renewable resources andlower costs, and thendelivered to demand
centres around thecontinent.

Hydrogen cluster approach

Pan-European networkhydrogen supply close to demandhydrogen supply from cheaper regions

The EHB can play a major role in overall European decarbonisation efforts, reducing annual emissions
by up to 312 MT CO2e per year by 2050.b Hydrogen delivered by the EHB will:— Directly mitigate emissions from hard-to-decarbonise sectors of the economy— Enable increased build-out and integration of variable renewable energies across the continent— Improve energy system stability by stockpiling excess supply from different regions and across varying timeframes,
particularly when the network is coupled with storage facilities— Provide access to hydrogen storage for countries that do not possess suitable geological characteristics themselves,increasing system flexibility and reducing risks associated with geopolitical disruptions— Bolster network resilience and security of supply via the integration of multiple energy sources, locations, and pathways
Sources: A complete reference list is provided at the end of the report on slide 22.
Footnotes: b) Metric tonnes of CO2 equivalent emissions reductions. Guidehouse, Inc analysis based on projected hydrogen demand in 2050, by sector,
using green hydrogen as a substitute for fossil energy

5TRADING PARTNER

TSOs are driving development of the EHB, leading
both large-scale coordination efforts and thedelivery of real projects on the ground
EHB members have continued to push forward with PCI and HNOnominations, market studies, and concrete project implementation
EHB members are developing concrete projects: 6— 41 EHB projects have received PCI status.d— EHB infrastructure projects have been included in ENTSOG’s 2024 Ten-Year
Network Development Plan (TYNDP).6,e— Development studies in Spain, Denmark, France, Germany, Lithuania, andNorway have identified ample supply and demand resources that support astrong business case.6-11

EHB members are actively leading national and international hydrogendevelopment activities:— The first Hydrogen Network Operator (HNO) nominations have taken place,with three EHB member TSOs awarded HNO status, two close to securing therole in their countries, and more expected to follow, as a further five are in thenomination process.6— EHB members will also be active stakeholders in the developing European
Network of Network Operators for Hydrogen (ENNOH).

EHB member TSOs
EHB members appointed as HNO or
working through provisional HNO process
EHB PCI list project, corridor A
EHB PCI list project, corridor B
EHB PCI list project, corridor C
EHB PCI list project, corridor D
EHB PCI list project, corridor E
H2 infrastructure part of PCI list in Germany
H2 infrastructure part of EHB 2040 vision

Sources: A complete reference list is provided at the end of the report on slide 22.
Footnotes: d) The definitive selection of PCIs was published in April 2024.
e) the projects in this map only highlight H2 infrastructure part of the assumed 6 th PCI list; for an overview of all projects please see Figure 6 in this report

6

TRADING PARTNER

TodayDevelopment Phase

Implementation timelines:
Access to phased financial
support is key tohydrogen infrastructuredevelopment

Hydrogen pipeline projects typicallyrequire initial developmental
expenditures (DEVEX) to enable Final
Investment Decisions (FID), as well as
funding for construction andoperations~2027
Individual Project FIDs
and start of construction

~2030

~2070

Construction & Operations Phase

Developmental Activities:

Construction Activities:

Operational Activities:— Developmental and feasibility studies— Construction— Operational costs— Permitting and regulatory approvals— Workforce contracting— Maintenance costs— Gauging and securing end-usercommitments— Procurement ofmaterials
and equipment— Technical analyses

DEVEX support (pre-FID) enables:

Construction & operating support (post-FID) enables:— Developmental support enables
TSOs to conduct feasibility and otherstudies to increase a project’s maturity
and bankability, prior to FID.

— The construction and operations phases occur after
successful FID, requiring capital expenditures (CAPEX) tobuild the network and operational expenditures (OPEX) to
operate and maintain the pipeline.

— Example: a typical DEVEX investmentof 125-250M€f is required for a 5B€
hydrogen project, which is aburdensome cost for TSOs to bearalone in light of the broader societal
decarbonisation benefits.

— A commitment of construction & operating support isnecessary before FID to allow TSOs to de-risk investment andattract additional private capital.

Footnotes: f) DEVEX assumed to be a percentage of CAPEX, with variability on a project-to-project basis

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TRADING PARTNER

Mitigating risk is an essential step to build out a new market, especially for interconnectedmarkets like hydrogen.

De-risking enables a strategic viewof network development andincreases the EHB’s ability to attract
market capitalDe-risking activities increase the ability to attract external funding.
Commercial investors’ willingness to finance hydrogen projects is limited by perceived development risks
and low early-stage returns. Public support mechanisms can provide two alternatives for assistance, either
by: enhancing potential returns or reducing risks.13 De-risking is the more effective option to improve
the risk-return curve and stimulate external investments, given the constraints of operating in a regulated
market that limits potential returns.14➜ Risk-return curve for hydrogen projects

Risk-returncurve

1Return-enhancing
policies andinstruments

Return

For new markets,coordinated public
support is mosteffectively used tomitigate investment risk,
acting as a catalyst forbroader network buildout

In the still-developing hydrogen market, ‘due diligence’ activities can provide a roadmap to coordinate
efficient whole-network build-out. Given the societal benefits of a productive hydrogen value chain, TSOs
cannot be solely responsible to bear the risks involved with infrastructure development.

Hydrogenpipeline
projects

2
Risk-reducing
policies andinstruments

Risk
Sources: A complete reference list is provided at the end of the report on slide 22.

Graphic adapted from Global Green Growth Institute 13

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TRADING PARTNER

Both developmental and implementation support are needed to enablesuccessful network development
Investment in DEVEX helps clarify network coordination and build-out, while construction and operating support can help to overcome
inherent early-market dynamics
2022

1

Development Phase (pre-FID)
Public support for developmental activities can enable efficient deployment of capital across the full network, increasing the likelihood of success.

2023

For those projects in the earlier
stages of development, pre-FID
support can help to resolve technicaland financial challenges, increasing
the confidence of external investors.

2024
2025

A whole-network view of
deployment allows for strategicplanning that enables optimal
phasing of build-out, with increased
reliability and energy security.

2026
2027
2028
2029

2030

2

A coordinated approach to technology
advancement—with simultaneous
collaboration among multiple market
players—can reduce CAPEX
requirements, resulting in greater speed tomarket, better access to technology, and areduction in overall costs.

Construction & Operations Phase (post-FID)
Public support also works to de-risk construction and operational activities during the initial years of market ramp-up.

The first five-to-ten years of network
operation—a period with increasing
but less than full market adoption—
present a challenge for pipelines togenerate the total revenues allowedby regulators.

The gap between required CAPEX andearly projected revenues is considered aninvestment risk by investors, who lack theappetite to be first movers in this space.
Therefore, clarity around publicconstruction and operating support iscritical to sufficiently de-risk theseinvestments, prior to FID.

Such support also allows successful
pioneering projects to provide early
lessons learned and serve as aroadmap for broader networkbuildout.

9

TRADING PARTNER

Recommendation: Policymakers can provide clarity and bolster progress
toward 2030 climate goals by allocating phased public support
Near-term allocation of both developmental support (2.5B€) and construction & operating support (25B€) provides the clarity
required to catalyse cost-efficient network build-out
2022

2023
2024
2025
2026
2027
2028
2029

2030

2.5B€ in development support is needed now to advance ~31.000 km(~44 projects) towards FID and put the network on the optimal buildout path.
— DEVEX support is required as soon as possible to enable EHB projects toreach FID, with a quarter of the projected 2030 EHB network planned to be
operational before 2029, and a further three-quarters of EHB projects planned
to be running by 2030.

25B€ in construction and operating support is needed before 2027 toovercome inherent early-market dynamics, increase the confidence ofoutside investors, and enable successful early-stage projects to serveas blueprints for future progress.
— The EHB provides a durable foundation for long-term European
decarbonisation efforts, but early-market dynamics necessitate coordinatedsupport during its initial phase.
— It is not necessary that the entirety of the 25B€ be funded via direct financial
allocations from public bodies—a variety of support schemes and external
actions can help to reduce the ask, including:— Emerging support mechanisms that enable efficient accounting of thelong-term project economics➜ Estimate of required developmental andconstruction & operating support
€B
30
20
25.0

27.5

Construction &Operating support

Total required
public support

10
2.5
0

Developmental
support➜ Projected EHB Build-out
7.500 kminitial projects
2025-2029

23.500 km of further
network build-out prior
to 2030
31.000 km total by 2030

— Regulatory actions that accommodate the varied timelines and wideranging societal benefit derived from the EHB
10TRADING PARTNER

Recommendation: European policymakers can efficiently deploy publicfinancial support by funding DEVEX studies for early-stage projects
Investing in DEVEX is the most cost-effective way to leverage limited near-term funding, providing information to de-risk projects
and unlock larger pools of market capital
2022

2023
2024
2025
2026
2027
2028
2029

2030

1

Development Phase (pre-FID)
Private market capital is available, but it must be
unlocked by early-stage DEVEX investments that de-riskand clarify the EHB’s business case.
Public capital is limited; it is crucial to leverage such support
for the greatest possible impact. For the EHB, development
studies help to put build-out on the optimal path by clarifying
the long-term business case and boosting the network’s
attractiveness to external investors.

➜ Stages and levers of project development and investment

InitialDEVEX
support+Publicimplementation
support=Global investments in infrastructure are expected to double in
2024 (relative to 2023), with continued growth expected in
the next 2-3 years.15 Large institutional investors are making
significant infrastructure acquisitions and reaching
infrastructure fundraising targets faster than expected,16
indicating that more market capital could become available
soon.

Perceived risks
decrease

MarketcapitalMarketinvestment
thresholdWith a relatively small amount of initial public support,
DEVEX activities could be leveraged to stimulate greater
decarbonisation benefits by providing better access toproviders of market-rate capital.

Publicinvestment
threshold

Early-stage project

Bankable project

Mature project
Graphic adapted from Global Green Growth Institute 13

Sources: A complete reference list is provided at the end of the report on slide 22.

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TRADING PARTNER

Support of DEVEX also illuminates the path to efficient
network-wide development
Early developmental insights can improve the phasing of network build-out, enable efficient coordination between market actors,
and promote cost reductions
2022

1

Development Phase (pre-FID)

2023
2024
2025
2026
2027
2028
2029

2030

The insights gained from developmental
studies pave the way for efficient networkwide development.
Developmental studies provide insights into theinitial key connectors of the grid, highlighting
the most effective investments to target.
Although the final form of a pan-European gridprovides continent-scale connectivity, progress
will not occur all at once, and policy-makers canmost quickly and cost-effectively spur build-out
by providing insights into optimal project
phasing.

The information provided by developmental
studies will lead to system-wide cost
reductions through incentivised collaboration.
Developmental support across Europe will allow
projects to simultaneously mature, with sharedprogress enabling project developers to sharelearnings, accelerate development, and reduce
costs.
Collaborative efforts can help to reducebottlenecks by addressing common needs likehydrogen supply chain development or theadvancing the development of latest-generation
compressor technologies. This collaborative
approach can foster greater efficiency andproductivity within the entire network.

Developmental support is a compellinginvestment for policymakers.
Allocating funds to DEVEX studies has limited
downsides; apart from any individual project’s
FID outcome, DEVEX funding will create insightsthat help to identify the most attractive EHB
investments. Highlighting projects with a strong
business case and high likelihood of successincreases the overall probability of Europe
reaching its decarbonisation targets.

12

TRADING PARTNER€2.5 billion in developmental support will prepare ~31,000 km of projects for
FID, bolstering progress towards Europe's decarbonisation goals
Reducing the financial burden of the DEVEX phase creates alignment of incentives for pioneering first-movers,
making efficient use of limited EC resources
2022

2023
2024
2025
2026
2027
2028
2029

2030

1

Development Phase (pre-FID)
EHB Recommendation: Fund development studies foras many hydrogen infrastructure projects as possible,
across the entirety of Europe
Grant support to a large set of projects to funddevelopment studies. Each study will be used toquantify risks and assess the opportunities to mosteffectively accelerate implementation.
This funding helps mitigate initial development andinvestment risks, aligning incentives towards
expedient full-network build-out and spurring further
development of Europe’s renewable energy andhydrogen industries.
TSOs cannot start developmental studies without
sufficient public support, leading directly to delayed
pipeline completion dates and putting climate goals
at risk.

➜ Developmental funding: needed vs available
B€
2.5
2.0
1.5

2.5
Including existing programs, anadditional ~€2B in near-term
developmental support is required
to fund development studies

2.0

1.0
0.5
0.0

0.5

CEF-E funding1?

Other funds2

Additional needed
developmental
supportNeeded DEVEX
investments to built out
2030 EHB vision3

1: An estimated €3.5 billion remains from the Connecting Europe Facility – Energy (CEF-E) €5.9 billion total program budget. 15% of the CEF-E spending is dedicated to cross-border projects, with a potential increase up to 20% subject to market uptake. This means that
€2.8 billion (€3.5 billion x 0.8) is left for PCI projects. Through 2027, the CEF-E program will support 5 categories of PCI: electricity, smart gas grids, hydrogen, electrolyser facilities, and CO 2 networks. Therefore, it is estimated here that only approximately €0.5 billion(€2.85 billion / 5) of the remaining budget (available for the next 4 years) will be allocated to support hydrogen transport infrastructure.
2: It is unclear how much support network operators can expect from other funds, such as the European Regional Development Fund, Modernisation Fund, Cohesion Fund, InvestEU, and Horizon Europe.
3: We assume the total DEVEX needs of the 2030 EHB network are a percentage of CAPEX, based on an internal EHB member survey.

13

TRADING PARTNER

Construction and operating support is also crucial for strengthening theearly-market business caseTo overcome the uncertainties inherent in any new market, policymakers should allocate funding to ensure that both pioneering andlonger-term hydrogen infrastructure projects are successful
2022

2023
2024
2025
2026
2027
2028
2029

2030

2

Construction & Operations Phase (post-FID)
Revisiting the Investment Recovery Challenge➜ Investment recovery challenge: concept— The EHB is most cost-effective when sized to accommodate
mature-market volumes, preventing expensive expansion projects
and infrastructure-related bottlenecks as the hydrogen market
develops.
— During the early years of network operation and while the userbase is still increasing, the imbalance between upfront CAPEX
costs and early market revenues makes it difficult for a typicalpipeline project operating in this new environment to generate
the full revenues allowed by a regulator.g— The EHB is projected to deliver large-scale societal benefits for
decades, but this initial imbalance–occurring during the first
five-to-ten years of network operation—is considered aninvestment risk by outside investors.
— Public support is critical to overcome this risk, helping a large
group of developmental projects proceed from the development
phase into the construction phase. Public support should bedesigned to align incentives such that early adopterhydrogen network users are not disincentivised by highearly tariffs, and such that proactive pipeline developers
are not disincentivised for pioneering network
development.

Footnotes: g) For a detailed explanation of this concept, see the EHB’s November 23 publication.

Shaded area represents the investment recovery
challenge—the initial imbalance between early-market
revenues and the costs required to build out a network
sized to accommodate mature-market volumes.
Tariff in€/kg
Operation starts
in 2030
2030

2038

2040

2050

2060

2070

Bookedcapacity on
the network
Tariff required by network
operators to recoup total
investments

Maximum earlymarket network user
willingness-to-pay

Investment
recoverychallenge

14

TRADING PARTNER

By providing ~25B€ in construction and operating support, policymakers canensure up to 20 Mton of hydrogen in the early 2030s
Construction and operating support helps to stabilise the early-market business model, de-risk investments in network build-out,
and further encourage proactive early adopters
2022

2023
2024
2025
2026
2027

2

Construction & Operations Phase (post-FID)
Estimated at 25B€, the amount of required construction andoperating support is informed by a few key assumptions:
Extent of networkbuild-out
31.000 km of pipelines
operational prior to 2031

CAPEX costs for
network build-out
Based on an internal survey of
EHB TSO projects6

Projected long-term
demandThe Investment Recovery Challenge is estimatedat 25B€, and is typically required between 20252027 to de--risk FIDs

14.7 Mton (490 TWh) H2 throughput in
2030, and 40.5 (1349 TWh) Mton in 2040h

Additional
assumptions

Tariff in€/kg

As detailed in the Appendix, slide 23

2028

Compared to the amount of public support available today,
significant additional allocations are necessary:2029— CEF-E, the EU's only fund dedicated to transmission infrastructure,
has only €0.5B available.

2030➜ Investment recovery challenge: quantified— Other funds are also relevant, but it is unclear how much support
network operators can expect from the Recovery and Resilience
Facility,i European Regional Development Fund, Modernisation
Fund, Cohesion Fund, InvestEU, Horizon Europe, and others.

Operation starts
in 2030
2030

2038

2040

2050

2060

2070

Bookedcapacity on
the network
Tariff required by network
operators to recoup total
investments

Maximum earlymarket network user
willingness-to-pay

Footnotes: h) With a budget of over 700B€, the Recovery and Resilience Facility presents a significant funding opportunity. However, as the fund must be spent before mid-2026, it is not applicable to most EHB projects.
i) Calculations for hydrogen demand are based on a bottom-up analysis, by sector (2022 EHB analysis largely conducted prior to REPowerEU)

Investment
recoverychallenge

16

TRADING PARTNER

Emerging mechanisms like amortisation funds and contract for differences
can reduce investment risk during the Construction & Operations phase
Beyond direct financial support, funding instruments like those under development in Germany and the Netherlands can ease theburden of up-front investment
2022

2023
2024
2025
2026
2027
2028
2029

2030

2

Construction & Operations Phase (post-FID)
Direct1

STEP

DirectDirect2

Amortisation account — Germany

3

Subsidy — Netherlands— The Strategic Technologies for Europe
Platform (STEP) aims to reinforce, leverage,
and direct existing EU funds to selectsectors,23 potentially including hydrogen
infrastructure projects. 26—

The German hydrogen network’s €19.8 billion
cost will be financed by a combination ofequity capital, market investors, and grid fees
paid by network users20,21 without using
dedicated state subsidies.

—

The Dutch government will subsidise 50% of the € 1.5B
total costs to bring its hydrogen network to operation.18—

Funds will be used to (partially) cover CAPEX, OPEX,
depreciation, and capital costs.

— Projects that contribute to STEP objectives
can apply for a Sovereignty Seal, improving
their access to EU funding,j facilitating
combined support from multiple programs,
and helping to attract external
investments.24——

A clawback is integrated into the subsidy: the actualsubsidy spent through the end of the lead-up phase will
be calculated after completion in 2030 and any paidout surplus will be directed back to the government.19— However, Member States recently voted
against providing additional funding for
STEP, meaning it can now only draw fromexisting EU programs.25—

Grid fees will likely be capped to ensure thecompetitiveness of the network for early
adopters. The government will establish an
amortisation account to secure the initial losses
resulting from capped fees until payback has
been completed (and anticipating a significant
payback horizon).k
In case of market ramp-up failure, thegovernment can opt to cancel the account, withphased mechanisms to either transfer risk to
network operators or take full governmental
ownership of the network.

Indirect4

Contract for differences – H2 Global/HINTCO—

H2 Global/HINTCO uses a Contract for Differences
approach, coupling long-term purchase contracts fromproducers and short-term sales contracts fromhydrogen users. This scheme helps to stimulate themarket for hydrogen and therefore indirectly de-risks
investments in hydrogen infrastructure.17

Sources: A complete reference list is provided at the end of the report on slide 22.
Footnotes: j) Co-financing (100%) and pre-financing (30%) rates apply to the 2021–2027 STEP programming period.22-23k) The German government expects the account to ultimately be balanced by 2055, or the government will pay for a percentage of the shortfall (up to 74%), with grid operators having to fund the remaining fraction (up to 26%). 20-21 The exact division of costs incase of shortfall is currently under discussion.

17

TRADING PARTNER

A framework for intertemporal cost allocation provides critical flexibility
to support early-market operations
Mechanisms proposed in the recent Gas/Hydrogen Packagel would allow mature-market revenues to stabilise hydrogen market
ramp-up and could significantly reduce required public support
2022

2023
2024
2025
2026
2027
2028
2029

2030

2

Construction & Operations Phase (post-FID)➜ Intertemporal cost allocation mechanism

A framework for intertemporal cost allocation (ICA) could
significantly reduce the amount of public support required.
The graph at right shows that implementing a long-term ICA framework
could potentially reduce the overall required implementation support
by up to three quarters. It should be noted that—even with ICA—someamount of public support will still be required, and ICA may not be
feasible in all countries.
There are still aspects of the mechanism to be clarified, such as thetiming of the implementation, specific rules governing its applicability,
and the expected level of participation from future users.

Without requiring users to exceed their maximum
willingness-to-pay, future network users could contributean additional 19B€j to early operations, reducing the totalrequired up-front implementation support by up to 75%.
Tariffin€/kg

Network-user willingness-to-pay, the speed of hydrogen network
adoption, and specific rules for cost allocation will play a major role indetermining the effectiveness of the framework. To navigate these
uncertainties, the EHB recommends that national regulators work
closely with network operators to provide guidance to project
developers.

Even pending clarification, the ICA framework remains oneof the most effective tools available to accelerate early
development of the hydrogen market.

Footnotes: l) While the final regulation is not published yet, the EHB assumes minor changes to the text based on reached political agreementm) IRC and ICA values represent time-discounted amounts

This area represents the 25B€ requiredfor construction and operating supportm
2030

2038

2040

2050

2060

Maximum network user
willingness-to-pay

Tariff required by network operators torecoup total investments

Investment recovery
challenge

Additional revenue through intertemporal
cost allocation mechanism

2070

18

TRADING PARTNER

Efforts to set up the network for early success and accelerate market
adoption will reduce the total amount of investment required over time
Activities that act to de-risk and mature the hydrogen market are likely to stimulate additional, simultaneous drivers of network
growth
2022

2023
2024

2

Construction & Operations Phase (post-FID)
Financial, political, and regulatory efforts that work to accelerate the maturity of the hydrogenmarket also work to reduce the size and duration of public support required for the
EHB, benefiting both policymakers and citizens that contribute to public financial pools.

➜ Benefits of Accelerated Market Development➜ The impact of network user willingness-to-pay:

2025

74

Accelerating network adoption significantly
reduces the total amount and duration offinancial support required (shaded area)

2026
2027

25

Tariff in€/kg

0.16 €/kg

0.32 €/kg

11
0.48 €/kg

4

1

0.64 €/kg

0.80 €/kg

Assumed maximum willingness-to-pay for hydrogen transport tariffs

2028

Size of the investment recovery challenge (B€), based on
network-user maximum willingness-to-pay

2029
2030

2030

Estimating the amount of required public support involves key assumptions
about the emerging market. The gap between TSO break-even costs andnetwork user willingness-to-pay is perhaps the most important factor for
determining the amount of support required (chart below).

2033

2035

2038

2040

2045

Bookedcapacityon thenetwork

Tariff required by
network operators torecoup total investments

Maximum network
user willingness-to-pay

Investment recovery
challenge

Baseline value used for EHB analysis and estimates

Willingness-to-pay is likely to vary by location and end-use sector, while
TSO break-even costs are driven by geographic, population, and politicalfactors. Given the significance of this gap in driving overall economics,
support mechanisms that specifically target either of those factors arelikely to be most effective.
19

TRADING PARTNER

Successful planning for hydrogen infrastructure necessarily includes
coordination with other energy vectors
Integrated planning for hydrogen and electricity transmission infrastructure allows for a more cost-effective, reliable, and timely
energy transition
Consistent standards and regulations governing the technology, processes,
sustainability, and safety can drive down costs along the value chain—both forhydrogen and for electricity. The EU’s draft Gas/Hydrogen package underlines theneed for cross-sector network development plans that accommodate multiple energy
carriers.26 The draft Gas/Hydrogen package further mandates EU-level integrated
network planning between the future ENNOH, ENTSO-E and ENTSO-G.27 The EU
Action Plan for Grids calls for the inclusion of hydrogen stakeholders in the preparationof Offshore Network Development Plans (ONDP).
An integrated infrastructure planning approach necessitates a shift towards a
longer-term view to identify strategic investments and drive down costs for consumers
in the future. Such a system enables supply to be optimally located and sized to serveboth electric and hydrogen demand.
Integrated infrastructure planning provides benefits for both energy vectors: 28— Integrated, whole-system transmission planning delivers infrastructure optionality andcan lower risk for new projects, increasing the likelihood and quality of investment.
— Intermittent renewable energy requires an increase in demand-side flexibility anddispatchable peak generation—an ideal match for hydrogen storage infrastructure—
increasing the security of energy supply and reducing curtailment.
Key recommendation: Support schemes should be designed to de-risk investment
decisions and unlock the system-wide benefits of integrated infrastructure development
across electricity and hydrogen vectors, rather than focusing solely on one or the other.

Sources: A complete reference list is provided at the end of the report on slide 22.

Power infrastructure
enabling hydrogenproduction

Drivers for theH2 economy
Consistent standards andregulations across vectors

Pipeline infrastructure
enabling transport andstorage of hydrogen

System integration
benefits
Optionality of infrastructure

Permitting and safety

High levels of system flexibility
enabled by hydrogen production

Early, targeted financing decisions
to unlock private capital

Whole system decarbonisation
including hard-to-abate sectors

Challenges
Several technologies are not yet competitive in many applications or regions,with a need for improved performance, design, and operational standards.
Lack of stability in regulatory and market conditions results in high uncertainty
and deters investment.

20

TRADING PARTNER

The European Hydrogen
Backbone Roadmap:
the most cost-effective
path forward to spurhydrogen market
development

Early-stage public support isrequired to unlock the full-scaleconnectivity and decarbonisation
potential of a pan-European
hydrogen networkwww.ehb.eu

01

Hydrogen is critical to Europe’s decarbonisation goals: The EHB will
provide connectivity, security, and cost-effective decarbonisation, whileserving as cross- sector catalyst for further climate efforts.

02

With limited public funding available, it is crucial to use it
efficiently. DEVEX support is an enabler of strategic planning andaccess to further market capital: Early-term development support usedas ‘seed funding’ can put the network on its most efficient path tosuccessful deployment.

03

Construction and operating support is also imperative to overcome
temporary early-market dynamics and to guide further build-out: Early
pioneer projects will serve as successful case studies that create momentum
as the network grows.

04

Regulatory and market mechanisms can help to ease the burden on
public funding pools: Recent regulatory proposals from theGas/Hydrogen Package and market mechanisms developing in Member
States and could significantly reduce the direct funding required from theEuropean Commission.

05

Economy-wide decarbonisation is an ambitious challenge requiring theresources, mechanisms, and political will to act, and the EHB is part ofthe solution: The EHB will play a crucial and multi-dimensional role incombating climate change, provided that early-stage support is allocated tospur its development.

21

TRADING PARTNER

The European Hydrogen Backbone – driving the vision for a connected,
secure, and carbon-free energy system
The EHB’s 33 member TSOs span the European continent, collaborating to lead the development of renewable and low-carbonhydrogen infrastructure

July 2020

April 2021

June 2021

Visionarypan-EU maps

Updated andextended vision

Detailed analysis of Projecting a substantial
future hydrogenacceleration ofdemand, by sector hydrogen infrastructurebuild-out through 2030

The
EuropeanHydrogen
Backbone:

April 2022

May 2022

November 2023

Analysis of supply
and demand of five
supply corridors
connecting Europe

Analysis of the most recent
hydrogen infrastructuredevelopments and costestimates

Is critical for the EU to achieve net zero
greenhouse gas emissions by 2050
Contributes to a sustainable and affordable
energy supply for Europe
Facilitates transport of both domestically-produced
and imported hydrogen through pipelines as well
as shipped liquids, enhancing security of supply
Enables the fastest integration ofvariable renewable energies
Allows for domestic hydrogen production that
contributes to European energy independence➜ The EHB has been providing leading-edge insights to drive
the development of the hydrogen market since 2020.
22

TRADING PARTNER

References1)

Gas for Climate, ‘Assessing the benefits of a pan-European
hydrogen transmission network’2) 2023 IPCC report, Climate Change 2023 Synthesis Report
3) IEA, Renewables 2023
4) Shell weakens 2030 carbon emissions reduction target | Reuters5) European Environment Agency, Greenhouse gas emission trend
projections and target
6) EHB report, Implementation Roadmap — Cross Border Projects
and Costs Update7) Energinet, Market dialogue on hydrogen infrastructure8) DNV, Specification of a European Offshore Hydrogen Backbone
9) GRTgaz & Teréga, National consultation of low-carbon andrenewable hydrogen market stakeholders10) Government of Ireland, National Hydrogen Strategy11) EPSO-G, Lithuania Energy System Transformation To 2050
12) Gassco & dena, German-Norwegian Energy Cooperation Joint
Feasibility Study
13) Adapted from: Global Green Growth Institute, Mind the Gap:
Bridging the Climate Financing Gap with Innovative Financial
Mechanisms

19) Baker McKenzie, Germany: Development of a hydrogen core gridand update of the National Hydrogen Strategy20) Clean Energy Wire, Germany backs investments to build 9,700kilometre, €20 billion hydrogen grid21) European Cluster Collaboration Platform, STEP: Strategic
Technologies for Europe Platform Summary22) Council of the European Union, Strategic Technologies for Europe
Platform: provisional agreement to boost investments in criticaltechnologies
23) Science Business, The EU’s plan for critical technologies ends up
as a shadow of the promised sovereignty fund24) European Parliament, Strategic technologies for Europe platform(STEP)
25) Draft Gas/Hydrogen package directive26) Draft Gas/Hydrogen package regulation

27) ENTSOG, ENTSOG 2050 Roadmap For Gas Grids
28) European Commission, Commission proposes new EU framework
to decarbonise gas markets, promote hydrogen and reduce
methane emissions

14) European Parliament, The use of development funds for de-risking
private investment: how effective is it in delivering development
results?

Report Authors

15) Financial Times, Infrastructure funds draw billions of dollars as
energy and supply chains shift

Robert Slowinski, Rik van Rossum,
Yasin Sagdur, Dio Trijnes,
Stephanie Kandathiparambil,
Martijn Overgaag16) The New York Times, BlackRock to Buy Global InfrastructurePartners for $12.5 Billion16) H2Global Stiftung, The H2Global Instrument17) Nationaal Waterstof Programma, Gasunie legt Waterstofnetwerk
Nederland aan18) Tweede Kamer der Staten-Generaal, Kamerstuk 32813 nr. 958

www.ehb.eu

23

TRADING PARTNER

Appendix

TRADING PARTNER

The goal of these appendix slides are to explain the data/methodology the
EHB used to calculate the total needed implementation support

1

2

3

Quantitative input data
The slides in the first chapter
are dedicated to explaining
all the input data.

Conceptual modelling assumptions
The slides in the second chapter
explain some conceptual assumptions
informing the final modelling choices.

Model calculations
The final set of slides
explain the calculationsin the model in detail.

25

TRADING PARTNER

The goal of these appendix slides are to explain the data/methodology the
EHB used to calculate the total needed implementation support

1

2

3

Quantitative input data
The slides in the first chapter
are dedicated to explaining
all the input data.

Conceptual modelling assumptions
The slides in the second chapter
explain some conceptual assumptions
informing the final modelling choices.

Model calculations
The final set of slides
explain the calculationsin the model in detail.

26

TRADING PARTNERCAPEX and compression needs for all size pipelines
Input data (1/3)

Value(M€/km)Parameter2

Value(M€/km)20”onshore pipes

1.80

20”onshore pipes

0.02636” onshore pipes

3.2048”onshore pipes

4.40

36” onshore pipes

0.09336” offshore pipes

5.4448”onshore pipes

0.18336” offshore pipes

0.158

48”offshore pipe

0.311

Parameter1

Pipeline CAPEX,
new

Pipeline CAPEX,
repurposed

Pipeline
compressor
need, new48”offshore pipe

7.48

20”onshore pipes

0.54

20”onshore pipes

0.02636” onshore pipes

0.6448”onshore pipes

0.8836” onshore pipes

0.04036” offshore pipes

1.09

48”onshore pipes

0.18336” offshore pipes

0.068

48”offshore pipe

0.311

48”offshore pipe

1: Survey EHB members 2023, 2: Hydraulic simulations conducted by network operators

1.50

Pipeline
compressor
need, new77

27

TRADING PARTNER

Kilometers of expected operational pipeline in 2030 and assumed hydrogen throughput
Input data (2/3)

Type of pipeline

Kilometers operational in 20301

New

15,752

Repurposed

16,864

Total

32,616

Assumed throughput through EHB 2030 network245

H2 throughput (Mton/y)

40
35
30
25

20
15
10
5
0
2030 2035 2040 2045 2050 2055 2060 2065 2070
1: EHB maps, 2: Bottom-up EHB analysis

28

TRADING PARTNER

Additional financial and technical data
Input data (3/3)

Parameter1

Capex spend profile

1: EHB maps, 2: Bottom-up EHB analysis

Value

1 year before operation

7%

2 years before operation21%

3 years before operation

56%

4 years before operation

16%

DEVEX spread (y)3Maximum willingness-to-pay during initial market phase (€/kg)

0.33

Compressor annual fixed OPEX as % of CAPEX (%)

1.7%

Compressor operating hours per year (h)5000Electricity price for compressor operation (€/MWh)107

Pre-tax WACC (%)

5.35%

Depreciation pipeline (y)40 years

Deprecation compressor (y)25 years

Return on capital pre commercial operating date

40 yearsCompressor station CAPEX (M€/MWe)

4.0

Pipeline annual fixed OPEX as (%) of CAPEX

0.9%

DEVEX as (%) of CAPEX

2.5%
29

TRADING PARTNER

The goal of these appendix slides are to explain the data/methodology the
EHB used to calculate the total needed implementation support

1

2

3

Quantitative input data
The slides in the first chapter
are dedicated to explaining
all the input data.

Conceptual modelling assumptions
The slides in the second chapter
explain some conceptual assumptions
informing the final modelling choices.

Model calculations
The final set of slides
explain the calculationsin the model in detail.

30

TRADING PARTNER— From a network throughput perspective, the EHB is modelled as a single pipeline. From financial perspective, it ismodelled as a combination of its component pipeline projects, including varying sizes, lengths, and implementation
timelines.

Modelling
assumptions(1/2)— Conceptually, all European hydrogen supply enters the (single pipe) EHB infrastructure at one entry point, and all
demand exits at a single point. In this formulation, specific location-based, distance-based, and cross-border tariffs are
not considered. The choice to use a single tariff is a consequence of the choice to model the EHB as a single pipelinefrom a flow perspective and should not be interpreted as a preferred policy ask to introduce a single EU tariff.
— We only model the 2030 EHB network.
— The network is built to accommodate a mature hydrogen market, meaning that there will be an initial low utilisation ratethat increases until 2040. EHB members believe that early clarity about the phasing of hydrogen network build-out
enables the market to decarbonise the energy system at the lowest societal cost.
— A straight-line depreciation profile is used to calculate the value of the network assets.
— The hydrogen and decarbonised gas market package proposal states that cross-subsidisation of hydrogen networks bynatural gas network revenues is allowed only under certain conditions4. As the regulation is still uncertain at this point,
our methodology assumes no cross-subsidisation5. Again, this simplification is used for calculation purposes only andshould not be seen as a policy preference by network operators toward policy makers.
— No carry forward mechanisms are assumed in the base-case implementation support calculations, if yearly revenue of apipeline is below the regulated returns, it is added to the investment recovery challenge. Some countries may havetime-limited carry forward mechanisms (e.g. max 5 years) – but on the timeline and scale of EHB this does not impact
the system significantly.
— The revenue calculation of the modeled pipeline is based on a tariff charged per unit of hydrogen throughput. In real
life, pipeline revenue is based on long-term/capacity booking, and revenues are often split into entry/exit charges.
Please interpret mention of hydrogen throughput in the text as a proxy for capacity booked.
— All values are modeled are pre-tax. Tax systems and rates are different for each country; as the numbers in this report
are applicable across Europe we report on pre-tax values only.
— The financial calculations in this report only consider the transportation of hydrogen, while in reality network operators
could also operate storage facilities.
— The RAB model only accounts for hydrogen pipelines. For repurposed pipelines we assume the costs made torepurpose these pipelines are part of new hydrogen RAB model.
31

TRADING PARTNER

The goal of these appendix slides are to explain the data/methodology the
EHB used to calculate the total needed implementation support

1

2

3

Quantitative input data
The slides in the first chapter
are dedicated to explaining
all the input data.

Conceptual modelling assumptions
The slides in the second chapter
explain some conceptual assumptions
informing the final modelling choices.

Model calculations
The final set of slides
explain the calculationsin the model in detail.

32

TRADING PARTNER

Model calculations
To arrive at the total implementation support calculations, these slides will first explain how the EHB
calculated the tariff required by network operators to recoup total investments
Tariff required by network operators to recoup total investments

Implementation support need (investment recovery challenge)— Definition: The maximum yearly revenue that the regulator allows to be recuperated
divided per kg of hydrogen throughput.
— Calculation: (Yearly OPEX (€/y) + yearly asset depreciation (€/y) + return on capital(asset value at the beginning of a year (€/y) x WACC (%)) / hydrogen throughput— Definition: The financial disparity between tariff required by network operators to recoup
total investments and the revenue that can be realistically obtained from end users.
— Calculation: (Tariff required by network operators to recoup total investments (€/kg/y) –maximum early market network user willingness-to-pay €/kg/y) x hydrogen throughput(kg/y)

Tariff required by network operators
to recoup total investments

Maximum early market network
user willingness-to-pay

Investment recovery challenge

Tariff in €/kg

Y1

Y8

Y10

Y20

Y30

Y40

Capacity
booking of
the network

33

TRADING PARTNER

The yearly allowed revenue by a regulator is a function of three categories which are
explained in the next slides
Yearly asset depreciation + return on capital + yearly OPEX

Yearly asset depreciation [€]Yearly allowed total revenue
by regulator [€]Tariff required by network
operators to recoup total
investments [€/kg]+

Yearly return on capital [€]Yearly OPEX [€]÷

Hydrogen throughput [kg]34

TRADING PARTNER

Yearly asset depreciation — the role in the overall tariff calculations (1/3)
Yearly asset depreciation + return on capital + yearly OPEX

Yearly asset depreciation [€]Yearly allowed total revenue
by regulator [€]Tariff required by network
operators to recoup total
investments [€/kg]+

Yearly return on capital [€]Yearly OPEX [€]÷

Hydrogen throughput [kg]35

TRADING PARTNER

Yearly asset depreciation — conceptually explained for straight-line depreciation (2/3)
Yearly asset depreciation + return on capital + yearly OPEX
Total DEVEX investments [€]Yearly DEVEX
depreciation— Calculated as a % of CAPEX— Investment are spread out over three years

÷
DEVEX depreciation duration [y]Total pipeline CAPEX investments [€]Yearly pipeline CAPEX
depreciation÷
Pipeline depreciation duration [y]Yearly asset
depreciation [€]Total compressor CAPEX investments [€]Yearly compressor
CAPEX depreciation÷Compressor depreciation duration [y]— Calculated by multiplying the unitary cost of per sizeof pipeline (€/km/per size) times the kilometres of
installed pipeline of a size (km/per size)— Investments are spread out four years before
operation— Calculated by multiplying the compressor need of
all pipelines (MWe/km/size) times the installed kcompressor capex (€/MWe)— Compressor need to be replaced after 25 years— Investments are spread out four years before
operation

Total DEVEX investments [€]Interest during
construction— Calculated by taking the RAB pre-operation andmultiplying with the WACC÷
DEVEX depreciation duration [y]36TRADING PARTNER

Yearly asset depreciation — results (3/3)
Yearly asset depreciation + return on capital + yearly OPEX
Yearly investments, per investment category
Billion €Yearly asset depreciation, per investment category
Billion €

58.6

60

55
50

Dividing the sum of each investment category by their asset
depreciation period results in the yearly asset depreciation

45
40

30

3.2

3.2

3.2

3.2

3.0

20

12.7

3.2

3.2

3.3

0.9

2024 2025 2026 2027 2028 2029

1.0

11.4

10
0.9

3.3

1.5

17.4

15

3.2

4.0

Yearly depreciation increases slightly in 2054 as
replacement CAPEX investments are made (see purplebar), before the old CAPEX compressors are actuallyreplaced. However, in 2055 the original compressors are
fully depreciated (no more green bar) and therefore
depreciation returns to old level.

2.0

25.7

25

0

3.5

2.5

35

5

3.8

4.0

4.3

1.4

2051 2052 2053 2054

DEVEX

CAPEX - Repurposed Pipeline

CAPEX - New Pipeline

CAPEX - Compressor

0.5
0.0

2030 2031 2032 2033

2051 2052 2053 2054 2055

Replacement CAPEX - Compressor

2070

Yearly depreciation

Interest During Construction

37

TRADING PARTNER

Yearly return on capital – the role in the overall tariff calculations (1/3)
Yearly asset depreciation + yearly return on capital + yearly OPEX

Yearly asset depreciation [€]Yearly allowed total revenue
by regulator [€]Tariff required by network
operators to recoup total
investments [€/kg]+

Yearly return on capital [€]Yearly OPEX [€]÷

Hydrogen throughput [kg]38TRADING PARTNER

Yearly return on capital – conceptually explained for straight-line depreciation (2/3)
Yearly asset depreciation + yearly return on capital + yearly OPEXRAB at the end of the previous year

Return on capital[€]X

RAB at the beginning of
the current year [€]+All investments during the current year•

Sum of all investment in a year across all categories,
as shown in the previous slides-

Depreciation•

See slides in the previous category to understand how
the yearly depreciation is calculated

WACC [%]

39

TRADING PARTNER

Yearly return on capital – results (3/3)
Yearly asset depreciation + yearly return on capital + yearly OPEXRAB based on total yearly investments and depreciation

Return on capitalBillion €Billion €120

7Multiplying the RAB at the beginning of the current
year with the WACC gives the return on capital

100
80

60
40

5
RAB increases due toyearly investments (seeslide 37 for overview ofyearly investments)

20

RAB increases ascompressors are
replaced after 25 years(new investments, seeslide 37)

RAB decreases due
to depreciation (seeslide 37 foroverview ofdepreciation)

4.5

4

3

2.6
1.9

2

0
-20

6

6.2

1
2024 2030

2040

Total yearly investment
Depreciation

2050

2060

2070

RAB at the beginning of a current year

0
2030

2040

2050

2060

2070

Return on capital
40

TRADING PARTNER

Yearly OPEX – the role in the overall tariff calculations (1/3)
Yearly asset depreciation + yearly return on capital + yearly OPEX

Yearly asset depreciation [€]Yearly allowed total revenue
by regulator [€]Tariff required by network
operators to recoup total
investments [€/kg]+

Yearly return on capital [€]Yearly OPEX [€]÷

Hydrogen throughput [kg]41TRADING PARTNER

Yearly OPEX – conceptually explained (2/3)
Yearly asset depreciation + yearly return on capital + yearly OPEX

Yearly OPEX [€]+Pipeline fixed OPEX

Calculated as a percentage of CAPEX

Compressor fixed OPEX

Calculated as a percentage of CAPEX

Compressor variable OPEX

Calculated as compression need of all pipelines [MWe] x electricity price[€/MWh] x compressor of operating hours [h]42TRADING PARTNER

Yearly OPEX – results (3/3)
Yearly asset depreciation + yearly return on capital + yearly OPEX

Yearly OPEX, per OPEX category

Billion €New Pipeline fixed OPEX

Repurposed Pipeline fixed OPEX

Compressor fixed OPEX

Compressor variable OPEX

4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0

0.5
0.0

2030

2040

2050

2060

2070
43

TRADING PARTNER

Now, the tariff for network operators can be calculated by dividing the sum of yearly asset
depreciation, return on capital, and OPEX by the hydrogen throughput
Yearly asset depreciation + yearly return on capital + yearly OPEX

Yearly asset depreciation [€]Yearly allowed total revenue
by regulator [€]Tariff required by network
operators to recoup total
investments [€/kg]+

Yearly return on capital [€]Yearly OPEX [€]÷

Hydrogen throughput [kg]44TRADING PARTNER

Yearly allowed total revenue by regulator
Yearly asset depreciation + yearly return on capital + yearly OPEX
Yearly allowed total revenue

Tariff required by network operators to recoup total investments

Billion €

€ /kg

14

1.0
0.9

12
Dividing the yearly allowed
revenue by regulator with the
expected throughput results inthe tariff

10
8

0.8
0.7

0.6
0.5

6

0.4

4

0.3
0.2

2

0

0.1
2030

2040

2050

Return on Capital (slide 40)
RAB Depreciation (slide 37)

2060

2070

0.0
2030

2040

2050

2060

2070

OPEX (slide 43)
Yearly allowed total revenue by regulator
45

TRADING PARTNER

Implementation support calculation
Finally, the implementation support is calculated by subtracting the maximum early market network user willingness-to-pay from thetariff required by network operators and multiplying with the expected throughput

€ /kg
1.0
0.9

Tariff required by network
operators to recoup total
investments

Maximum early market network
user willingness-to-pay

Investment recovery
challenge

The green area is reflective of the
25B€ implementation support
referenced in the main content slides

0.8
0.7
0.6
0.5
0.4
0.3

0.2
0.1
0.0

2030

2040

2050

2060

2070

46