Out of more than 1,400 green hydrogen projects announced globally, exactly 2 percent have reached a final investment decision, according to Wood Mackenzie. The remaining 98 percent exist entirely as press releases, feasibility studies, and non-binding memoranda of understanding. This single metric exposes a widening gulf between policy aspirations and engineering reality, which means green hydrogen is fundamentally a 2035 story. Institutional investors must model this later timeline rather than the politically popular 2030 targets because capital is fleeing, timelines are slipping, and the few projects that do secure funding are scaling at a pace that makes near-term decarbonization mandates mathematically impossible to achieve. The consensus narrative pushed heavily by policymakers, equipment vendors, and energy incumbents insists that the industry is on the cusp of commercial viability. Yet this optimism is built on artificial demand signals rather than physical supply chain readiness. The result is an industry quietly resetting its expectations to the middle of the next decade, leaving early movers who allocated capital based on flawed cost curves to face massive financial implications. For chief financial officers and infrastructure funds, this delay transforms a theoretical climate solution into a near-term balance sheet liability.
The Consensus Overestimates Speed and Underestimates Cost
The dominant market narrative treats green hydrogen as a near-term, plug-and-play solution to heavy industrial decarbonization. The European Union’s REPowerEU plan calls for 10 million tonnes of domestic green hydrogen production by 2030, while in the United States, the Inflation Reduction Act offers up to $3 per kilogram in tax credits to effectively subsidize the entire cost of early-stage production. Financial models have historically mirrored this aggressive policy push, with estimates clustering around a highly optimistic consensus: BloombergNEF projects green hydrogen costs falling to $2 per kilogram by 2030 to match fossil-based gray hydrogen, while McKinsey pushes the ceiling even higher by arguing the fuel could meet 24 percent of global energy demand by 2050 if rapid scaling begins immediately.
This optimism ignores three hard physical and logistical realities. First, electrolyzer manufacturing capacity is growing, but it is nowhere near the required trajectory. The International Energy Agency reports that global electrolyzer manufacturing capacity reached 11 GW in 2023, which represents just 1 percent of the 1,000 GW needed to meet standard 2030 net-zero scenarios. Scaling heavy industrial equipment manufacturing by a factor of one hundred in less than seven years is historically unprecedented. Unlike software or consumer electronics, chemical engineering hardware requires bespoke fabrication, specialized labor, and massive capital outlays before a single unit rolls off the line.
Second, renewable electricity inputs remain severely constrained because the physics of electrolysis are unforgiving. Green hydrogen requires 50 to 55 kWh of renewable electricity to produce a single kilogram of gas, meaning wind and solar projects capable of delivering this dedicated power are already facing massive permitting bottlenecks and grid connection queues. In the U.S., interconnection wait times for new renewable projects average 3 to 5 years. That leaves developers in a bind, as a hydrogen facility proposed today cannot realistically secure the necessary clean power before the end of the decade. Without that dedicated clean power, an electrolyzer is just an expensive stranded asset sitting idle on a concrete pad.
Third, the supply chain for critical components is fragile. Proton-exchange membrane electrolyzers rely heavily on iridium and platinum. Iridium prices doubled in 2022 and remain highly volatile, and because there is no commercially viable substitute currently in sight for these systems, scaling the technology directly scales commodity risk for the buyer. Consider Siemens Energy’s recent operational struggles. The company is widely viewed as a leader in electrolyzer manufacturing, yet it warned in November 2023 that its hydrogen division would not break even before 2028. Its flagship project, the 1.2 GW H2Giga electrolyzer factory in Berlin, was supposed to pioneer automated mass production but has faced repeated delays due to supply chain issues and technical hurdles. If an industrial giant like Siemens cannot scale its manufacturing on time, the broader market's timeline is fundamentally flawed, and project developers must price in severe procurement delays.
Four Numbers That Break the Narrative
The gap between ambition and execution is best understood through four specific data points that highlight the systemic friction in the market.
First, the 2 percent final investment decision rate for announced projects tracked by Wood Mackenzie indicates a market paralyzed by execution risk. Even the flagship projects that do secure funding are struggling to maintain their schedules. NEOM’s $5 billion green hydrogen project in Saudi Arabia was once hailed as the world’s largest and most bankable facility, yet the consortium has pushed its first production date from 2026 to 2027. Industry observers expect further delays into 2028, citing supply chain bottlenecks and complex permitting challenges. When the most heavily capitalized project on earth cannot hit its targets, smaller developers face an even steeper uphill battle.
Second, the Hydrogen Council estimates that $1.5 trillion in cumulative investment is needed to scale green hydrogen to 100 million tonnes per year by 2030, but actual global investment in 2023 totaled just $12 billion. This represents a 30 percent decline from 2022, which means the funding gap is widening rather than closing. Institutional investors have been burned by early-stage failures and are aggressively pulling back. BlackRock launched a highly publicized $1 billion hydrogen fund in 2021 but has deployed just $200 million and made no new commitments since 2023, citing a severe lack of bankable projects. For a chief financial officer trying to syndicate debt for a new facility, this institutional retreat means higher hurdle rates and punishingly expensive capital.
Third, the first wave of operational green hydrogen projects is revealing brutal underlying economics through massive cost overruns. Air Liquide’s 20 MW electrolyzer in Bécancour, Canada, came online in 2021 at a total cost of $250 million, representing three times the initial engineering estimates. The project currently produces hydrogen at $5 per kilogram, far above the $2 per kilogram industry target. Similarly, ITM Power’s 10 MW electrolyzer in Germany faced cost overruns of 40 percent upon its 2022 completion due to supply chain disruptions and technical integration issues. These are not isolated outliers, but rather the standard first-of-a-kind penalty for scaling nascent hardware.
Fourth, a 2024 analysis by Rystad Energy found that half of all announced green hydrogen capacity is located in regions with insufficient renewable electricity supply or inadequate grid infrastructure. Australia’s ambitious plans to export green hydrogen to Asia rely on the assumption of 50 GW of new wind and solar capacity, but the country’s grid can currently handle just 10 GW of intermittent renewables. Without massive, decade-long infrastructure upgrades, these export projects are functionally dead on arrival, leaving Asian offtakers without a viable decarbonization pathway.
Why Policy Mandates Cannot Force Supply Chain Readiness
The strongest rebuttal from industry optimists is that aggressive policy will force the market to scale regardless of near-term friction. The EU’s Carbon Border Adjustment Mechanism and the U.S. Inflation Reduction Act hydrogen tax credits are designed to create artificial demand, theoretically forcing heavy emitters to adopt green hydrogen regardless of the base cost. Europe’s specific mandates for green steel and aviation fuel require 5.6 million tonnes of green hydrogen by 2030, creating what appears to be a guaranteed offtake market. On top of that,, the U.S. Treasury’s 45V guidance finalized in December 2023 sets strict additionality rules for what qualifies as green hydrogen, effectively banning fossil-based gray hydrogen from receiving transition subsidies.
This policy-driven argument holds weight in financial models but overlooks critical engineering flaws. Mandates can create legal demand, but they cannot solve physical supply chain bottlenecks. Europe’s steel industry cannot switch to green hydrogen without massive facility retrofits, and the equipment required to make those retrofits does not exist at scale. Thyssenkrupp, Europe’s largest steelmaker, has already delayed its highly anticipated hydrogen-based steel pilot from 2025 to 2027, explicitly citing a lack of reliable electrolyzer supply. When a steelmaker cannot procure the necessary hardware, they are forced to continue burning coking coal, missing their Scope 1 emissions targets and triggering severe regulatory penalties under the Carbon Border Adjustment Mechanism.
Subsidies distort market pricing but do not eliminate execution risk. The U.S. 45V credit is generous at $3 per kilogram, but it expires in 2032. Because grid interconnection takes up to five years, a project starting today might only receive three years of subsidized production before facing a massive fiscal cliff. Without long-term policy certainty extending into the 2040s, capital will not flow at the scale required. Developers are already pausing projects, waiting to see if future U.S. administrations will extend or alter the credits.
The data required to disprove this pessimistic thesis is clear. If 50 percent of announced green hydrogen projects reach a final investment decision by 2026, and global electrolyzer manufacturing capacity hits 100 GW by 2027, the 2030 targets might still be achievable. Currently, neither metric is tracking anywhere close to those milestones, meaning the industry must prepare for a prolonged period of capital starvation and consolidated growth.
Strategic Inflection Points for Stakeholders
Green hydrogen’s delayed scaling is not just a technical setback for engineers. It represents a strategic inflection point for three key stakeholder groups. Each faces a severe reckoning in 2025, and the capital allocation choices they make now will determine who survives the inevitable market shakeout.
Institutional Investors Face Accelerating Capital Flight
Institutional investors have poured roughly $50 billion into the green hydrogen sector since 2020, chasing the narrative of a $1.4 trillion addressable market by 2050. That capital is now highly vulnerable. Brookfield Asset Management raised a massive $15 billion energy transition fund in 2022, but has quietly shifted its deployment focus away from hydrogen and toward battery storage and grid upgrades. BlackRock’s stalled deployment is another clear signal that the risk-return profile no longer makes sense for conservative institutional money.
The trigger for a broader market pullback will likely arrive in the first quarter of 2025, when the first wave of delayed mega-projects is forced to announce revised timelines to shareholders. When NEOM officially pushes its first production to 2028, analysts expect a 20 to 30 percent correction in hydrogen-related equities. Pure-play companies are already suffering, with Plug Power down 80 percent since 2021 and ITM Power down 90 percent. The smart money is rotating out of pure-play producers and into adjacent sectors, specifically electrolyzer component suppliers like Nel Hydrogen and McPhy, or diversified renewable project developers like NextEra Energy and Ørsted. This rotation protects capital from binary project execution risks while maintaining exposure to the broader energy transition theme.
Corporate Offtakers Confront the Supply Trap
Corporate offtakers, including enterprise giants like Amazon, Microsoft, and Maersk, signed early, highly publicized deals to buy green hydrogen. They are now discovering that commercial supply simply does not exist. Amazon’s 2021 agreement with Plug Power for 10,000 tonnes of green hydrogen per year has been delayed indefinitely, with Plug citing severe production constraints. Maersk ordered 12 green methanol-powered ships in 2022 to decarbonize its logistics network, but has been forced to secure fossil-based gray methanol for its first vessels, severely undermining its corporate climate claims. When a logistics giant is forced to burn fossil fuels in custom-built green ships, their environmental, social, and governance premium vanishes, angering corporate clients who paid extra for zero-carbon shipping.
A major reckoning will occur in 2025 when the first major offtake contracts come up for renewal or cancellation. Buyers will face a difficult choice. They can pay an exorbitant premium for green hydrogen assuming it is physically available, switch back to gray hydrogen and accept regulatory penalties, or abandon hydrogen entirely in favor of alternative decarbonization methods. The latter is already happening. In 2024, Dow Chemical canceled a planned $1 billion green hydrogen project in Texas. The company opted instead to install carbon capture technology on its existing gray hydrogen plants, a pragmatic decision driven by cost and reliability. Expect more defections in 2025, particularly from industrial operators operating on thin margins who cannot afford to subsidize failing clean technology experiments.
Engineering Teams Pivot to Adjacent Markets
Engineering teams at both hydrogen startups and legacy incumbents are quietly shifting their focus to survive the delay. Siemens Energy, following the delays in its electrolyzer division, has doubled down on grid stabilization technologies. ITM Power, facing severe cash burn and investor pressure, is now prioritizing stationary fuel cells for data centers, which represents a smaller but much more immediate and bankable market. Even Plug Power, once the undisputed poster child for the green hydrogen revolution, has pivoted heavily toward material handling such as warehouse forklifts and stationary backup power, where enterprise demand is predictable and infrastructure requirements are minimal.
The catalyst for further pivots will be the final implementation of the 2025 U.S. Treasury guidance on 45V credits. If the rules strictly enforce hourly matching and additionality for renewable electricity inputs, many proposed projects will instantly become uneconomic. Hourly matching means an electrolyzer cannot run at night unless the wind is blowing, which destroys the facility's utilization rate and spikes the levelized cost of hydrogen. Product teams that fail to diversify their technology stack before this regulatory reality sets in will face mass layoffs. The winners in this space will be the companies that successfully repurpose their core technology for adjacent markets, such as utilizing electrolyzers for industrial oxygen production, deploying fuel cells for grid backup, or focusing on hydrogen derivatives like ammonia for maritime shipping.
Two Predictions for the Green Hydrogen 2035 Reality
By May 2026, two specific market outcomes will definitively confirm that green hydrogen is a 2035 story, rendering the 2030 targets obsolete.
First, less than 10 percent of announced green hydrogen capacity will be operational. Of the 1,400-plus projects currently tracked by Wood Mackenzie, fewer than 140 will be producing hydrogen at commercial scale. The vast majority will be officially canceled, indefinitely delayed, or drastically downsized. The critical metric for analysts to watch is the final investment decision rate. If it does not exceed 15 percent by the fourth quarter of 2025, the 2030 volume targets are mathematically dead. The ultimate bellwether project remains NEOM’s green hydrogen plant. If it fails to reach first production by 2028, the entire Middle Eastern hydrogen export strategy will require a fundamental rewrite, forcing sovereign wealth funds to reallocate billions in planned infrastructure spending.
Second, green hydrogen costs will remain above $3 per kilogram in most global regions. The $2 per kilogram target, once viewed by analysts as an inevitable result of scale, will prove entirely elusive outside of highly specific niche geographies endowed with ultra-cheap, stranded renewables such as Chile or Namibia. The metric to watch is the levelized cost of hydrogen for projects reaching a final investment decision in 2025. If the average cost exceeds $3.50 per kilogram, the underlying economics simply do not work without permanent, uncapped government subsidies. The canary in the coal mine is Air Liquide’s Bécancour project. If its operational costs do not fall below $4 per kilogram by 2026, the industry must admit its fundamental cost curve assumptions were wrong, and buyers must prepare for permanently higher green premiums.
The green hydrogen industry is not failing, but rather experiencing the painful friction of industrial reality. The 2030 targets were always aspirational political tools, and the market is now aggressively resetting to a timeline dictated by physics, grid queues, and supply chains. The question is no longer whether green hydrogen will eventually scale. The question is whether the capital, policy, and engineering challenges can be solved in time for 2035. The answer is yes, but only if operators and investors stop pretending the future is already here.
Isn’t the U.S. Inflation Reduction Act enough to make green hydrogen competitive?
The Inflation Reduction Act’s $3 per kilogram tax credit is highly lucrative and covers the theoretical cost of production, but it does not solve physical supply chain shortages, local permitting battles, or grid interconnection constraints. Plug Power’s CEO admitted in 2024 that the credit makes the economics work on paper, but acknowledged that severe execution risks remain in the physical world. On top of that,, the credit expires in 2032, creating a massive fiscal cliff for projects that take five years just to connect to the grid. Without long-term policy certainty extending well into the 2030s, institutional capital will not flow at the scale required. Developers are already pausing projects to see if future administrations will extend the credits, leaving corporate buyers without a reliable timeline for procurement.
What about blue hydrogen as a bridge?
Blue hydrogen, which is fossil-based gray hydrogen paired with carbon capture technology, was heavily promoted as the pragmatic bridge until green hydrogen could scale. However, carbon capture infrastructure adds $1 to $2 per kilogram to baseline costs, and methane leakage rates remain stubbornly high. A thorough 2024 study by Cornell University found that blue hydrogen’s lifecycle emissions are only 9 to 12 percent lower than standard gray hydrogen, severely undermining its value as a climate solution. Recognizing these poor economics and regulatory risks, Shell canceled its flagship blue hydrogen project in Canada in 2023. Without a clear path to cost parity or meaningful emissions reductions, blue hydrogen is increasingly viewed as a stranded asset risk by institutional investors.
Are there any green hydrogen projects actually working?
A few small-scale pilot projects are currently operational, but none are functioning at the commercial scale required for heavy industry. The largest operational facility is Air Liquide’s 20 MW electrolyzer in Bécancour, Canada, which produces hydrogen at roughly $5 per kilogram, far above the $2 per kilogram target. This specific project only works because it is co-located with abundant, pre-existing hydroelectric power, a rare geographic advantage that cannot be easily replicated. Most industrial regions lack the dedicated renewable electricity supply required to duplicate this model. The next major test for the industry is NEOM’s project in Saudi Arabia, which aims to produce 650 tonnes per day by 2027. If it succeeds on that timeline, it will be the exception that proves the rule, rather than a replicable template for the rest of the world.
Related MarketIntel briefing: read Green Hydrogen Won't Scale Before 2035: The Financial and Engineering Realities for a connected view on this market signal.