Green for Cash or Splash: Green Hydrogen M&A and Project Finance Going Through a Profound Change.
Mainstream media sources have consistently referred to Hydrogen as some kind of miracle alternative to fossil fuels and an answer to future energy crises. But what exactly is hydrogen? Hydrogen is not a traditional energy source, but more of an energy carrier - a unit that has to be manufactured before anyone can use it. Hydrogen itself has about nine main colors (green, blue, grey, black/brown, pink, yellow, turquoise, white and orange), from which the energy sector is dominated prominently by green and grey. The color itself tells us nothing about the molecule itself, but more about the manufacturing route. Furthermore, from the manufacturing we can deduce its emissions and the costs.
In 2024, less than one percent of the hydrogen, from the roughly 100 million tonnes produced, came from low-emissions routes. The rest was unabated fossil hydrogen, more particularly steam methane reforming - which releases nine to ten kilograms of CO2 for every kilogram of hydrogen. Geographically speaking, the majority of the coal gasification was conducted in China. Blue Hydrogen is the same reforming but with carbon capture attached. The Green Hydrogen is created through a process known as electrolysis - passing renewable electricity through water to split it into hydrogen and oxygen, with oxygen as the only by-product. In essence, almost all of the demand is in refining, ammonia, methanol and direct reduced iron. So, the applications which dominate media news headlines account for about one percent of the entire sector.
From a physics standpoint, a kilogram of hydrogen holds about 33.3 kWh of usable energy. The said commercial electrolyser system, used to extract the 33.3 KwH consumes 50-55 kWh to make it. These numbers mean that a third of the energy input is lost just in the conversion alone, while we have not even yet accounted for compression, transport and other variables. In this high consumption cost, the most expensive culprit is power, accounting for 55-70% of the production costs. Therefore, only three variables move the cost number: electrolyser capital costs, power price and utilisation.
With every cost factored in this leaves us with a cost between $2.50-7.00/kilogram globally (said numbers depend on geographical location). In Europe the price comparison is even worse with green hydrogen priced at €5-9 and grey at €1-4 - while keeping in mind that green is supposed to replace grey hydrogen. Some nearly three times the incumbent at the midpoint price ( Green (€7) and Grey (€2.5) ). We can make the logical deduction that nobody is buying green hydrogen because of the cost advantage. Producers buy it because regulators compel them to do so through subsidies or because the incumbent in that particular setting is expensive diesel rather than cheap gas. Within Europe there is also another consideration to be made, the categorization “green” is a legal one, not a chemical. That same molecule qualifies as an RFNBO (Renewable Fuels of Non-Biological Origin) only if the electricity behind it passes a specific set of predetermined tests.
So let’s dive into the process of assembling the lines to create hydrogen. Electrolysers are the factory for hydrogen. Alkaline systems are stable and cheapest but prefer a steady load. With PEM (Proton Exchange Membrane) system costs are higher. These systems have the capability to decrease and ramp up production quickly, but are dependent on iridium, whose supply is a genuine scale constraint. Solid Oxide does reach the highest efficiency, runs hot and remains unproven over the long run, but it also allows us to directly use green ammonia as a fuel source (more on that later). All are sold as capital equipment, so revenue is lumpy and hostage to customer investment decisions.
On the other hand, fuel cells run the reaction backwards, and win where batteries fall short - long duty cycles, large payloads and short refuelling windows.
Another important confusion to mention are two different mobile products. Movable production units (MPU) and hydrogen power units (HPU). MPUs are constrained electrolysers and make hydrogen on site, while HPUs are containerised gensets built around fuel cell stacks that consume it. In practical terms, sized as a drop-in replacement for diesel generators on a construction site, a film set or other sites as such. An example of such is GeoPura’s HOU-2, which delivers 500kw per unit and is marked on a 99.9999 percent reliability. HPU’s are definitely more interesting from a commercial perspective as they can be considered a rental asset, more than a generative plant.
A final point to raise regarding the hydrogen kit would be the constrained storage. With hydrogen having the best energy density by mass it compresses to 700 bar or liquifies. Accordingly, hydrogen has the worst energy density by volume at roughly 5.6 MJ per litre at 700 bar against 32 for petrol. Factoring costs such as trucking, compression for storage, and liquefication raises the price per kilogram by an industry estimate of $2.70-3.20, which can rival the cost of making the molecule at all. Therefore, from a logistical and infrastructural point, hydrogen is still not a preferred energy source.
A PPA is a long-term bilateral contract for the supply of electricity at a previously agreed price. The volume (market trading activity) and tenor (contract maturity length) are settled either physically or financially against the entirety of the asset market. In most industries the Purchase Power Agreement is simply a procurement detail, but for Hydrogen it’s the product itself. If from our prior calculations, we consider power to be 55-70% of the cost per kilogram, then the PPA price effectively sets the hydrogen price.
Two routes for set agreement exist - direct connection and grid connection. A practice through which the electrolyser is put behind the meter of a renewable power plant is known as direct connection. It is contractually simple, but fully exposed to that asset’s capacity factor. Subsequently, we have the grid connection which uses a PPA plus guarantees which account for the origin of the produce. Furthermore, this route requires a generating commissioned no later than 36 months before the electrolyser and not itself being a recipient of operating and investment aid. The caveat here is that the recipient rule has exceptions through installations running before 1st of January 2028, allowing them to run until 2038 - a criterion yet to be applied on the newest fleet of power plants.
The implicit cost of green hydrogen is measurable. Research by the Institute of Energy Economics at the University of Cologne estimates the hourly requirement to be just under €30 per MWh of hydrogen on a business project’s case, from which €22 is the tightening from the monthly to hourly - equating to €0.7 per kilogram.
That could be considered a competitive price instead of a splash…
Further the Hydrogen Purchase Agreement (HPA) operates at a span of 10-15 years, is set as take-or-pay and for any hydrogen demand is indexed to power or gas. Modelling suggests that serving a rigid delivery schedule, compared to a flexible one will allow for a third more electrolyser capacity and 20% more storage. Also without an HPA there is no banking liability, and with that there is no project finance.
To summarise, a green hydrogen project is a spread trade. The PPA limits on the input side and the HPA on the output side, accompanied by an electrolyser as the conversion asset.
It is a well-known fact that for new power sources it is difficult to create a market niche and to expand as there are purely more financially viable alternatives. It furthermore requires a great deal of R&D, patience, and a well-capitalized cash pile within the firm in order for it to survive the period of dreadful and consistent losses, which put investors on their toes.
Such is the case of Ballard Power Systems, a Canadian global leader in Proton Exchange Membrane (PEM) hydrogen fuel cell technology. Historically, Ballard focused on manufacturing fuel cell engines primarily for heavy-duty motive applications, such as buses, trucks, trains, and marine vessels. The issue with this model, though, is the difficulty for the customer to find hydrogen fuel and maintain the vehicle, which is the core reason why sales growth has lagged behind expectations. Nevertheless, an exciting announcement appears to have turned the tide:
“Ballad Power Systems acquires GeoPura in the biggest ever green hydrogen merger for apprx. $400 million in June 2026”
Well, this is quite the news, because it creates one of the most interesting vertical integrations in the sector of green hydrogen yet. GeoPura Limited is a British green hydrogen producer and distributor that specializes in manufacturing and deploying zero-emission stationary power solutions called Hydrogen Production Units (HPUs), i.e. stationary green hydrogen generators, which could be rapidly deployed on construction sites and do not suffer the same geographic and demand risks as fixed turnkey infrastructure projects.
Ballard continues to make a loss and has pushed its break-even target from late 2027 to early 2028, but this new scale up model is likely going to return the older target date and allow for full synergic integration. GeoPura is expected to generate approximately $50 million in 2026 revenue. By comparison, Ballard’s standalone 2026 revenue is estimated at $168 million, reporting $20.6 million in Q2 2026, up 15% year-over-year. The integration unlocks $25 million in annual run-rate EBITDA synergies through consolidated manufacturing, corporate overhead optimization, and internalizing Ballard's fuel cell supply chain into GeoPura's systems as they were significant business partners prior to the merger.
Despite the recurring annual loss, Ballard Power Systems is continuously shrinking it as they reported in Q2 2026 a shrinking net loss, dropping to $20.3 million ($0.07 per share) from $24.3 million a year prior. Adjusted EBITDA losses improved significantly to $9.8 million from $30.6 million, aided by lower operating costs and a boost in overall revenues. This comes amidst a realignment plan under President and CEO Marty Neese to reduce annualized operating expenses by at least 30%, stated one year ago. Now it comes to light that it has managed to slash 40%, ensuring R&D efficiency is maintained as the teams of GeoPura and Ballard integrate.
At the end of the day, Ballard remains exceptionally well-capitalized, ending Q2 2026 with $502.1 million in cash and cash equivalents. This comes after a hybrid approach to the upfront $370 million, which is financed with approx. $111 million as a cash on hand with the rest being financed by almost 51 million Ballard shares ($5.02 per share), giving GeoPura Limited shareholders a 14.4% pro-forma stake in Ballard Power Systems. To ensure market stability, these shareholders are bound by customary lock-up agreements that restrict the transfer or sale of their new Ballard common shares for a specified post-closing period. In addition to the upfront purchase price, the deal incorporates a performance-based earn-out of more than $36 million if GeoPura reaches £28 million in revenues for 2026.
This seems like a buzz; demonstrates an impressive feat.
Now about governance: Upon closing, GeoPura's Founder and CEO, Andrew Cunningham, will transition to the role of President of Ballard, reporting directly to Ballard’s Chief Executive Officer, Marty Neese. The merger has been unanimously approved by the Board of Directors of both companies. Now a filing clearance under the UK National Security and Investment Act has to be issued and an approval of the Toronto Stock Exchange for the listing and issuance of the new 50.8 million new Ballard common shares. The deal is expected to close by the end of the year.
Ok. Let us accept now that the deal goes through. What then? How will this impact the firm’s business model? In this case, it will do so a lot. For years, the clean hydrogen sector struggled under a "pure-play" hardware manufacturing model and the "valley of tears" then swept the shiny valuations of hydrogen and renewable energy providers as reality hit where it hurt the most - profitability. But now the tides are turning and Ballard can earn a lot from it.
The firm sold state-of-the-art fuel cell engines, but customers faced a massive bottleneck: they could not easily access, transport, or store the hydrogen fuel needed to run them. By acquiring GeoPura, Ballard is executing a paradigm shift to an Energy-as-a-Service (EaaS) model, removing customer adoption friction by bundling hardware, fuel, and logistics into a single contract. This is where the gamechanger kicked in.
And the cherry on top for the match from heaven:
Furthermore, establishing permanent, turnkey fixed hydrogen infrastructure requires millions in capital expenditure, lengthy permitting processes, and long-term site commitments. GeoPura bypassed this deployment hurdle by focusing on mobile Hydrogen Power Units (HPUs) and can still enable Ballard to become a PPA champion with an EaaS business model. Now this is the sweet spot!
the Foundation?
For green-tech companies transitioning from high-burn development cycles to commercial maturity, M&A structuring is a delicate exercise in balance-sheet preservation. In Ballard Power Systems’ approx. $370 million upfront acquisition of GeoPura, the transaction’s hybrid equity-cash design illustrates how public players can manage share dilution while securing immediate financial accretion.
Funding 70% of the upfront purchase price through the issuance of approx. 50.8 million Ballard common shares (valued at US$5.02 per share) diluted Ballard’s existing share base, giving GeoPura’s shareholders a 14.4% pro-forma stake in the combined entity. However, this equity-heavy structure successfully shielded Ballard’s cash reserves, allowing the firm to conclude Q2 2026 with a robust $500+ million in cash and cash equivalents.
From an earnings perspective, the transaction is highly accretive. Standalone, Ballard's estimated 2026 revenue is $168 million. Incorporating GeoPura’s projected 2026 revenue of £38 million (approx. $50 million and with £10 million more than the milestone target) represents an immediate 30% top-line expansion. More critically, the deal is projected to unlock $25 million in annual run-rate EBITDA synergies by consolidating manufacturing, corporate overhead, and supply-chain logistics. All of this pushes closer the postponed break-even to the older and more optimistic period of late 2027 instead of early 2028.
If this is not a decisive argument about the merger accretion, then what is?
Moreover, the Ballard-GeoPura merger serves as a landmark case study in vertical integration, merging upstream technology manufacturing with downstream energy logistics:
Previously, Ballard has been supplying GeoPura with PEM fuel cells for their HPUs, whereas the combined entity now could bypass this and internalize the corporate processes and remove third-party markup costs. Instead of booking a single, non-recurring hardware sale, the combined firm captures multiple revenue connectors across the entire asset lifecycle, focusing on equipment leasing, fuel distribution, and O&M.
Relying solely on organic growth has proven challenging for the hydrogen sector. As financial analysts have noted, the wider adoption of hydrogen in traditional mobility sectors (such as heavy-duty trucking and rail) has progressed at a slower pace than original industry projections anticipated. Logistical challenges, fuel sourcing, fractured demand markets, and customer risk aversion are among the most challenging parts of green hydrogen adoption.
Consequently, clean energy developers are turning to inorganic, "Buy-and-Build" consolidation to capture market share, become more competitive, and establish industrial scale. The industry is entering a phase of realistic, intelligence-led consolidation. Smaller pure-play technology providers (such as Nel, Utis, Stargate, or Hydrogenera) hold exceptional R&D and engineering capabilities, but often lack the deep balance sheets, manufacturing scale, and extensive customer networks required to compete. Inorganic transactions bridge this "valley of tears" by matching technical expertise with commercial deployment platforms and feasible revenue targets.
And here comes the operational alpha, about which the world gets so excited for: By acquiring GeoPura, Ballard did not just buy technology; it bought an immediately deployable stationary power portfolio and direct access to an active, blue-chip customer base (including Microsoft, Netflix, Disney, and the UK Ministry of Defence). This allows Ballard to instantly redirect its world-class R&D into the high-growth stationary and backup generator markets and bypass years of organic business development. True intelligence-led consolidation.
While corporate balance sheets can fund early M&A and pilot deployments, scaling the green hydrogen economy to meet industrial demand requires transitioning to highly structured, non-recourse project finance. However, developers face a significant bankability bottleneck when trying to finance large-scale installations. Commercial lenders require absolute certainty of cash flows to fund projects through Special Purpose Vehicles (SPVs). This capital structure is built upon three critical pillars:
First, a long-term secure Power Purchase Agreement for the hydrogen producers themselves is required as roughly two-thirds of green hydrogen production costs would come from it, due to the electricity needs for electrolysis. Then there is the Counter Party Credit Rating Requirement, where renewable energy developers themselves require their own PPA buyers to hold investment-grade (AAA) credit ratings. Lastly, Public-Private Bridging Instruments play as the dealbreaker. Until green hydrogen achieves autonomous cost-parity with fossil alternatives, public capital must bridge the "green premium". Contract structures such as GeoPura's 15-year Hydrogen Allocation Round 1 (HAR1) contract with the UK government provide guaranteed, long-term state subsidies that satisfy commercial underwriting criteria.
This is why it is a nightmare to go for big infrastructure green hydrogen projects with such fractured markets.
Considering the third and currently most critical pillar of the project finance aspects of green hydrogen, we have to discuss the green hydrogen policies, government initiatives, and market makers. Now let us focus on the Old Continent. To bridge the cost gap between expensive low-carbon molecules and cheap fossil fuels, Europe has established a toolkit of market-shaping mechanisms designed to drive bankability and coordinate supply and demand.
We are starting with EHB Auctions. The European Hydrogen Bank (EHB) is not a physical bank but a highly successful public financing instrument managed internally by the European Commission. Its primary mechanism is a domestic competitive bidding auction that awards support in the form of a fixed premium payment (€/kg) for up to 10 years of verified and certified production.
The results of the third domestic EHB auction (held between December 2025 and February 2026) illustrate the intense market demand and cost trajectory of European hydrogen. The €1.3 billion EU budget was over six times oversubscribed, attracting 58 bids from 11 countries. Ultimately, 9 projects were selected to receive €1.09 billion in funding sourced from the EU Emissions Trading System (EU ETS) revenues. These projects will install almost 1.1 GW of electrolyser capacity, producing over 1.3 million tonnes of renewable and low-carbon hydrogen over their first 10 years of operation, avoiding 9 million tonnes of CO2 equivalent emissions. Winning bid prices for the last EHB Auction ranged from an incredibly competitive €0.44/kg to €0.98/kg.
Now this is what we call industrial pricing.
To prevent high-quality national projects from stalling due to EU budget caps, the EHB includes an Auctions-as-a-Service (AaaS) feature. This allows Member States to use their own national budgets to fund projects that performed well in the EU-wide auction but missed out on EU-level funding streamlining national funding with less bureaucracy and long waiting times. Furthermore, a flat production premium does not fully cover demand-side risks, which has forced a strong push to introduce double-sided auctions to better connect producers and users. Unfortunately, both of those mechanisms are not implemented yet with the latter not even mapped out by the European Union.
While the EHB focuses on domestic production, the H2Global Foundation is designed to foster a global hydrogen import market by acting as a "Green Market Maker". The first of its kind for hydrogen, actually. Operated through its wholly-owned subsidiary Hintco, H2Global resolves the early market failure where producers need long-term bankable revenue security while buyers are unwilling or unable to pay the premium price for clean molecules.
The mechanism runs two independent competitive processes. On the supply side Hintco signs long-term, bankable purchase contracts with global green hydrogen producers, providing the investment security required to reach a Final Investment Decision (FID). An FID is the critical moment when a company’s board of directors or project sponsors formally approve a project, commit large amounts of money, and sign major construction or supply contracts, marking the official green light to move from planning into building. On the other side, when it comes to the demand, Hintco sells the imported clean molecules to domestic European buyers via short-term competitive auctions, testing their real willingness to pay. The bridge between the bid and ask price, i.e. the residual "green premium", is covered by limited public funding from Hintco.
In November 2024, Hintco awarded its first renewable-ammonia pilot auction to Fertiglobe, a partnership between ADNOC and OCI Global, under a contract worth up to €397 million. Fertiglobe is expected to begin delivering renewable ammonia to European ports in 2027, with volumes potentially reaching 397,000 tonnes cumulatively by 2033. The auction established a landmark price signal of around €1,000 per tonne delivered to Europe, or €811 per tonne net, and, critically, the long-term offtake agreement helped the Egypt Green Hydrogen project in the Suez Canal Economic Zone reach Final Investment Decision (FID), supporting the development of 273 MW of new renewable generation capacity for hydrogen production.
This ammonia business is a whole rabbit hole by itself; see more under “Going Big a bit to the East”
While public capital kick-starts the market, meeting the estimated €263 billion investment needed to satisfy 2030 EU regulatory demand requires crowding in private capital and leveraging international financial institutions. Now mentioning this, a funding gap arises with the European Investment Bank. Traditional EIB guidelines are historically risk-averse, which can constrain early-stage developers in emerging markets.
The EIB currently deploys the €3 billion Pan-European Securitisation Lending Envelope (under InvestEU) to help SMEs and midcaps finance climate and innovation projects. However, this is spread across multiple sectors and is not yet specifically tailored to hydrogen credit risks, which put the sector in a disadvantage, when competing with more established renewable energy industries.
Under the proposed €234.3 billion European Competitiveness Fund (ECF) in the next Multiannual Financial Framework (MFF), the InvestEU toolbox will be fully integrated into a single rulebook. This offers a prime opportunity to tailor risk-sharing instruments directly to the hydrogen value chain, such as establishing state-backed credit-risk guarantees for PPAs and service-interruption insurance to de-risk projects for commercial banks.
Industry advocates are pushing for a streamlined progression where projects go from research and validation under FP10 (Horizon's €175 billion successor) to industrial scale-up under the ECF, and finally to infrastructure deployment under the Connecting Europe Facility (CEF). This is designed to systematically mature projects so they can comfortably crowd in private ESG-focused limited partners.
Lastly, the EU’s forthcoming Electrification Action Plan (EAP) aims to raise electricity’s share of final energy consumption from roughly 23% today to about 46% by 2040, and hydrogen is positioned as both a beneficiary and an enabler of this transition. Because electricity accounts for around 60–70% of green hydrogen production costs, measures that reduce electricity prices, network charges, and taxes for energy-intensive users could materially lower the levelised cost of electrolytic hydrogen. At the same time, grid-connected electrolysers can provide flexibility by rapidly increasing consumption when renewable generation is abundant, absorbing surplus wind and solar power that might otherwise be curtailed, while converting it into hydrogen for use in hard-to-electrify sectors such as heavy industry and transport.
All of this could allow a seamless connection between main power grids, green hydrogen electrolysers, BESS, and renewable energy producers, which could create a “full-circle moment”
The fundamental issue with Hydrogen isn’t the technology, but the customer itself. Any hydrogen project asks the buyer for a large capital investment to buy equipment, producing and burning fuel that is more expensive than the one that it generates. With all that the resale and service market is practically negligent. So, Hydrogen-as-a-service removes the decision by allowing the supplier to keep the asset, maintenance obligation and fuel supply, selling to the customer what is only in demand - reliable on-site power. The practice of converting electricity to hydrogen and back returns just a third of the input energy, and it simply cannot compete with grid connection.
Here, the customer pays the monthly fee and the supplier retains ownership. Instead of a fifteen-year commitment and a board decision, with expensive infrastructure, the customer sees a line item benchmarked against the diesel generator it already rents.
For the supplier, the lease is secure, contractually obligatory and visible, while the revenue shows an infrastructure multiple. The price to pay is a heavy balance sheet, full of capital intensive investments, reliant on cheap funding with risk transferred to the supplier. An idle unit is almost certainly a failure for such a firm.
Even if you lease a unit it is useless without hydrogen at the right time and correct amount. Of course, the customer just wants a functioning unit without learning how to buy it. Said supplier bundles the molecule with delivery, refuelling and logically charges a markup on the amount supplied. And this itself is the annuity: linked to volume, scaling with usage rather than with equipment sales. And for this very reason there is economic viability to price the lease so thinly.
The supplier keeps operational responsibility under a service contract: telemetry, predictive maintenance, guaranteed availability, priced against uptime because uptime is what the customer buys. High gross margin, low capital intensity, and load-bearing, since the telemetry that schedules a service visit also schedules the next refill and so protects the fuel margin.
After seeing what Hintco and the H2Global Foundation could do to green hydrogen and hydrogen-adjacent RFNBO such as green ammonia (NH3) in Egypt, which is again a zero-emission high-density energy storer made by combining pure nitrogen and green hydrogen via a renewably electrified chemical process, we might also want to unravel what lies a bit further to the East from Europe. This is the place where we love seeing mega projects and the extravagance of Europe’s neighbours as the sector’s early stages are challenged by hyperscalling outside of what was yet possible.
The clean energy transition is shifting from isolated demonstration sites to massive, utility-scale infrastructure. At the vanguard of this movement is the NEOM Green Hydrogen Project in Saudi Arabia. Representing a massive joint venture between ACWA Power, Air Products, and NEOM, the project is designed as the world's first utility-scale green hydrogen plant.
Spanning approximately 300 square kilometres the facility is located to exploit Saudi Arabia’s optimal natural conditions, featuring "three times the sun" alongside strong wind and water resources. The project boasts over 2,000 MW (2 GW) of electrolysis capacity, with the supply and installation of the water electrolyser technology overseen by Thyssenkrupp Nucera.
The facility is currently 65–70% complete, with green hydrogen production actively targeted to commence by the end of 2026. Furthermore, it will convert its green hydrogen into 1.2 million tonnes of green ammonia annually to serve as a high-density, transportable energy carrier for global export.
While the capital-intensive construction is funded by the joint venture consortium, its long-term viability is deeply linked to the creditworthiness of international off-takers. ACWA Power’s leadership argues that if European nations are to achieve their climate and industrial decarbonisation targets, they must establish import corridors with Saudi Arabia to access stable, low-cost clean molecules that are insulated from the geopolitical volatility of natural gas, which will both directly and indirectly influence the risk factors regarding the creditworthiness of the consortium.
After such a splash, the least an investor could ask for is that…
To operationalise this global flow of energy, Saudi Arabia is actively linking its production capacity directly to European industrial demand centres. A prime example of this strategy is the landmark bilateral agreement between ACWA Power and SEFE (Securing Energy for Europe). Signed in the presence of the Saudi Energy Minister and German Finance Minister, the agreement establishes a targeted hydrogen bridge between the two nations. The initial objective of the partnership is to deliver 200,000 tonnes of green hydrogen annually by 2030.
Under the terms of the MoU, ACWA Power will act as the lead developer, investor, and operator of the upstream green hydrogen and green ammonia production assets. SEFE will serve as a co-investor and, crucially, as the primary off-taker. SEFE will leverage its extensive customer portfolio of 200 TWh annually to market the imported clean molecules to German and European industrial customers.
Rather than relying on soft commitments, the partnership is backed by physical infrastructure plans. SEFE, through its subsidiary GASCADE, is actively converting part of its 4,100 km gas pipeline network under the FLOW project for hydrogen transmission. Furthermore, SEFE is developing the offshore AquaDuctus pipeline in the North Sea and a massive 500 GWh underground storage facility in Jemgum to balance seasonal demand. This network is designed to link into cross-border corridors, such as the 133 km Danish-German pipeline scheduled for 2030, which will transport imported and domestic molecules directly to heavy industrial hubs such as Thyssenkrupp's direct reduction steel mills in Germany.
This all begs the question: How feasible is all of that?
We have already discussed the financing mismatch of project finance within the green hydrogen industry due to requirements for a creditworthy PPA supplier, a creditworthy PPA customer, and an instrument bridge financing the “green premium”, which could further reduce the risk that plays the key role for the SPV and non-recourse project financing. On the other hand, Energy-as-a-Service (EaaS) offers a different financing route, particularly for smaller, distributed or temporary hydrogen applications. Instead of requiring the customer to purchase expensive hydrogen equipment upfront, the service provider owns and operates the infrastructure and charges the customer through recurring operating payments, which converts CapEx into OpEx.
The two models are therefore complementary rather than competing. Project finance is more suitable for large, long-lived hydrogen production and industrial infrastructure where predictable contracted cash flows can support substantial debt, while EaaS is more suitable for modular and distributed applications where flexibility and lower upfront investment are more important. As hydrogen markets deepen, stronger offtake structures, improved credit support and more established pricing should make conventional project finance increasingly feasible, while EaaS can continue to support smaller-scale deployment and early commercial adoption.
The green hydrogen sector is undergoing a profound change and we could expect a lot more from it. Three years ago the sector seemed as if it was just an experimental project for green politicians, who so desperately wanted to return the Green Transition to the table in the wake of major geopolitical conflicts in Europe and the Middle East. Now, by leveling the playing field and focusing policy incentives to create one of the most fascinating energy sector subdomains, the game has changed and major projects have arisen. Capabilities have expanded. Missions have become feasible with advancements in technology.
The world is adapting and now energy policy has become a central talking point, especially in Europe after 2022. The AI revolution is pushing up energy consumption, extreme infrastructure requirements arise after supply shortages, due to geopolitical conflicts. This makes the sector one of the most volatile and at the same time most interesting due to the sheer vastness of opportunity.
Outside of the roaring chaos in the EMEA region’s energy sector, climate change, and the mind-boggling data centre projects sprawling everywhere, especially in North America, this is where flexibility, strong combustion, and clean energy could outshine traditional energy and renewable energy sources. With the rise of green hydrogen and green ammonia as well as through the flexibility from HPUs and SOFCs, a new energy model could become less of a fringed concept and more like a progressive reality. People then only have to adapt.