Can 15 Years of Support Create a Real Hydrogen Market? Japan’s Price-Gap Experiment Begins

Hydrogen has spent years trapped inside a contradiction. Large production can reduce cost, but nobody wants to buy large volumes until cost falls. Industrial users say hydrogen is too expensive to justify replacing existing equipment. Producers say they cannot finance large plants without customers. Between them sit electrolyzers, ships, storage tanks and pipelines that remain too often in the demonstration stage.

Japan’s Hydrogen Society Promotion Act, enacted in 2024, is an attempt to build a public bridge across that chicken-and-egg problem. At its center is the price-gap support mechanism: while low-carbon hydrogen or low-carbon ammonia remains more expensive than natural gas, coal, conventional ammonia or another incumbent fuel or feedstock, government support can cover the certified gap.

The policy envelope is roughly ¥3 trillion over 15 years. By the March 31, 2025 application deadline, 27 plans had been submitted. METI said that simply adding their requested support amounts produced a total far beyond the available envelope. Japan did not have a shortage of hydrogen projects seeking subsidy.

The real scarcity was harder: which projects could use 15 years of public help to build industries that no longer need the help when year 16 arrives?

In one sentence: pay part of the gap while hydrogen gets cheaper

The basic logic is simple. A certified “base price” represents the price required to sustain the low-carbon hydrogen or derivative supply project. A “reference price” represents the economic benchmark associated with the conventional fuel or feedstock being displaced. Where the base price is above the reference price, that difference becomes the focus of support.

Imagine a low-carbon fuel requiring a price of 100 while the conventional alternative costs 40. A gap of 60 prevents the industrial customer from switching. The state temporarily bridges that gap so that the market can start before low-carbon production reaches mature scale.

The base price is not simply whatever number a company chooses to write in an application. The plan is assessed for production and transport cost, reasonable return, cost-reduction pathway, contracted demand, low-carbon performance, project credibility and long-term continuation.

The reference price is also tied to the incumbent fuel or feedstock economics rather than remaining a timeless fixed number. If fossil-fuel prices rise, the gap can narrow. If they fall, low-carbon hydrogen faces a tougher competitive benchmark.

Why 15 years? A hydrogen plant cannot recover its investment in three

Hydrogen infrastructure is capital-intensive and long-lived. Electrolyzers, compressors, tanks, pipelines, ammonia terminals, boilers and industrial furnaces require investment decisions measured in decades.

A supplier considering hundreds of millions—or billions—of dollars of infrastructure needs visibility on future demand. An industrial customer replacing a gas furnace with hydrogen equipment needs confidence that fuel will still be available years later.

Japan therefore chose a 15-year support horizon. More importantly, the policy design expects supply to continue for another 10 years after assistance ends. The state is not trying to finance a 15-year demonstration; it is trying to trigger businesses with a life of roughly a quarter-century.

A technology grant can succeed when a machine works. Price-gap support succeeds only if the fuel keeps selling after the grant disappears.

From the world’s first national hydrogen strategy in 2017 to a market law in 2024

Japan published the world’s first national Basic Hydrogen Strategy in December 2017. Early policy emphasized technology development and initial deployment: fuel-cell vehicles, hydrogen stations, residential fuel cells and international supply-chain demonstrations.

Cost reduction was already central. Japan set a direction of reducing hydrogen cost from roughly ¥100/Nm³ toward ¥30/Nm³ in 2030 and eventually ¥20/Nm³.

During the early 2020s the competitive landscape changed. National hydrogen strategies proliferated, and the United States, Europe, the United Kingdom and Germany introduced increasingly large programs designed to create production and demand. Japan’s technical lead no longer guaranteed a commercial market.

In June 2023 Japan revised its Basic Hydrogen Strategy and moved decisively from technology policy toward industrial policy. It added a 2040 supply target of roughly 12 million tonnes of hydrogen and derivatives on a hydrogen-equivalent basis and pointed toward more than ¥15 trillion of public-private supply-chain investment over 15 years.

The Hydrogen Society Promotion Act was enacted in May 2024 and entered into force on October 23. Price-gap support, hub-infrastructure support, project certification and regulatory special measures became the legal architecture for the post-demonstration phase.

Inspired by Europe, but built around a Japanese supply-and-demand plan

Japan’s Agency for Natural Resources and Energy says the mechanism draws lessons from long-term price-gap support used in countries including the United Kingdom and Germany. The shared logic is straightforward: where low-carbon fuels remain materially more expensive than incumbent fuels, markets may not produce a first wave of large investment without policy support.

Japan’s model, however, is structured around certified supply-and-utilization plans. It does not merely ask who can produce a kilogram of hydrogen. It asks who supplies it, who buys it, what industrial process changes, how the fuel is delivered and whether the business remains credible after support.

That matters because producing hydrogen is not the same as creating a hydrogen market. A steelworks, chemical plant, boiler, furnace, power station or filling station has to consume the molecule at the other end.

The first two certifications: steel and recycled-carbon chemistry

The first certifications came on September 30, 2025—and neither centered on passenger cars.

In Aichi, Toyota Tsusho, Eurus Energy Holdings and Iwatani plan a manufacturing special-purpose company that will procure power from onshore wind generation and electrolyze water at Aichi Steel’s Chita plant. The certified plan supplies 1,600 tonnes of low-carbon hydrogen per year from August 2030 through July 2055, with the hydrogen used in specialty-steel production.

In Kawasaki, Resonac plans to gasify used plastics and waste clothing and use the resulting hydrogen as feedstock for lower-carbon ammonia. Nippon Shokubai participates as a user. The certified annual supply is 20,815 tonnes of ammonia—3,234 tonnes on a hydrogen-equivalent basis—from April 2030 through March 2055.

The first selections reveal the policy’s industrial bias. Japan did not begin with a highly visible consumer use. It began with steel and chemistry—hard-to-abate sectors where hydrogen or hydrogen-derived molecules can replace existing feedstocks and high-temperature energy.

December 2025: the program jumps to hundreds of thousands of tonnes of ammonia

On December 19, two much larger low-carbon ammonia projects were certified.

JERA plans to supply ammonia produced at the Blue Point project in Louisiana, using most of it for ammonia conversion at Hekinan Thermal Power Station and part of it for industrial furnaces operated by companies including Toyota Industries, AGC, NGK Insulators and Aisin Fukui. The certified volume is 492,244 tonnes of ammonia per year—76,452 tonnes on a hydrogen-equivalent basis—from February 2030 through January 2055.

A second project led by Mitsui, together with Hokkaido Electric Power, UBE Mitsubishi Cement and Tosoh, plans to bring low-carbon ammonia from Louisiana to Japan. It will be used in power generation at Tomato-Atsuma, cement-furnace fuel and chemical feedstock. The certified volume is 280,000 tonnes per year, equivalent to 43,807 tonnes of hydrogen, from January 2031 through December 2055.

These projects make clear that the law is not limited to molecular hydrogen. “Low-carbon hydrogen and derivatives” includes carriers and compounds such as ammonia. Ammonia already has global shipping and storage infrastructure and can function as both a hydrogen carrier and a direct fuel or feedstock.

March 2026: the policy returns to locally produced hydrogen

On March 27, 2026, the next two price-gap certifications looked very different from the giant import-ammonia chains. Both are domestic electrolysis projects.

In the Yamanashi hub, Yamanashi Hydrogen Company and Suntory plan a production SPC beside Suntory’s Minami Alps Hakushu Water Plant. Most hydrogen will provide heat for sterilization at the water plant, while Tomoe Shokai will distribute part of the supply to additional users. The plan covers 1,607 tonnes per year from April 2028 through March 2055.

In Fukushima, YHC and Himeji Rika plan hydrogen-production sites at Himeji Rika’s Tamura plant and the Fukushima Hydrogen Energy Research Field. Hydrogen will supply burners used in quartz-glass processing, while Tomoe Shokai will connect additional users including Sumitomo Rubber’s hydrogen boilers, the Umi-no-Mori hydrogen station and planned TEPCO-group fossil-fuel substitution. The certified supply is 1,177 tonnes per year from April 2028 through March 2055.

Why put 492,000 tonnes and 1,177 tonnes under the same policy?

The scales look almost absurdly different. But the functions are different too.

The large ammonia projects are designed to create volume. Ships, terminals, power stations and industrial furnaces can establish regular flows large enough to begin pushing logistics and capital cost downward.

The regional hydrogen projects are designed to create density. Hakushu bundles beverage-process heat with nearby users. Fukushima combines quartz processing, tire manufacturing, mobility and other regional demand. Local electrolysis can avoid the liquefaction and long-distance logistics of imported hydrogen where demand is concentrated near production.

Japan does not yet know which architecture will dominate which applications. Supporting both gives the country operating data on two competing market structures: giant imported molecular supply chains and smaller domestic production hubs.

“Low carbon” is supposed to be measured in carbon intensity, not color

The hydrogen industry often uses color shorthand: renewable electrolysis as “green,” fossil-based hydrogen with carbon capture as “blue.” Japan’s legal framework is more useful when it focuses instead on measurable carbon intensity.

Policy discussions around the Act have used thresholds of 3.4 kg-CO₂e per kilogram of hydrogen and 0.87 kg-CO₂e per kilogram of ammonia through the defined production boundary. Certified projects have to demonstrate low-carbon characteristics under the applicable rules rather than relying solely on branding.

That means a project does not become environmentally credible simply by calling itself green or blue. Electricity source, feedstock, methane emissions, capture rate and production efficiency affect actual carbon intensity.

The quiet customer of price-gap support is the industrial buyer

Legally, certified low-carbon supply businesses sit at the center of the support mechanism. Economically, the program is also changing the investment decision of the customer.

Aichi Steel has to alter steelmaking operations. Suntory uses hydrogen boilers. Himeji Rika uses hydrogen burners. Hokkaido Electric and JERA convert generating assets. Those investments are difficult when future fuel price and availability are unknown.

A 15-year support framework gives buyers something nearly as important as cheap fuel: visibility. It tells the user that the new fuel is not expected to disappear after a two-year demonstration.

The inability to sign long contracts has been one of hydrogen’s less glamorous bottlenecks. Price-gap support is partly a policy mechanism for making long-term contracts bankable.

Japan cannot simply select the cheapest kilogram

If the only objective were the lowest possible hydrogen price, Japan could focus exclusively on imported projects from regions with very cheap renewable energy or gas resources.

But project selection also reflects energy security, industrial competitiveness, Japanese technology deployment, start date, certainty of demand, future cost reduction, regional spillovers and broader GX effects.

That is why a relatively expensive domestic electrolysis project may still have policy value. It can build domestic markets for electrolyzers, compressors, logistics systems, boilers and industrial furnaces that Japanese firms may later sell globally.

The danger is equally obvious. “Industrial policy” can become an excuse to protect projects whose cost never converges toward world markets. A 15-year bridge only makes sense if the bridge leads somewhere.

Risk one: subsidy can weaken the incentive to cut cost

If government fills the price gap, a supplier might appear to have less reason to lower its own cost. That is the classic risk of any long-term support mechanism.

The defense is rigorous base-price assessment, cost scrutiny, cost-reduction plans and monitoring. The 15-year period cannot mean “stay expensive for 15 years.”

It is supposed to create time to depreciate first-of-a-kind equipment, raise utilization, scale production, improve logistics and replace early hardware with cheaper generations.

Whether hydrogen becomes a subsidy industry or an industry that graduates from subsidy will be visible in the slope of that cost curve.

Risk two: government creates only temporary demand

A second danger is that industrial users buy hydrogen only while public money makes it attractive, then return to gas or coal when support ends.

That is why post-support supply continuation matters. If customers disappear immediately after the 15th year, the policy has not created a durable market.

The intervening years therefore have to change more than fuel price. Customers need sunk investment in hydrogen equipment; low-carbon products need market value; carbon pricing and emissions rules need to make fossil alternatives less artificially cheap; buyers need procurement standards that reward lower-carbon inputs.

Price-gap support alone cannot finish the market. Japan’s emissions trading, carbon pricing, product standards and private procurement all have to mature while the 15-year clock is running.

Risk three: cheap hydrogen at the port can become expensive hydrogen at the factory

An overseas producer may manufacture low-carbon ammonia cheaply, yet Japanese delivery can remain expensive if terminals, tanks, vaporizers, pipelines and truck-loading facilities are underused.

The Act therefore separates price-gap support from “hub development support,” which can help build shared infrastructure such as tanks and pipelines.

The connection is already visible. The JERA Hekinan and Hokkaido/Tomakomai ammonia chains received price-gap certification in December 2025 and hub-infrastructure certification on March 27, 2026.

Supporting fuel and shared infrastructure in parallel can be economically rational. It also makes policy accounting more important. If the state supports the molecule, terminal, pipeline and conversion equipment, policymakers should ultimately compare total public expenditure with actual lifecycle CO₂ avoided.

Is co-firing ammonia in coal plants the best use of scarce low-carbon fuel?

The largest early volumes are low-carbon ammonia, which makes power-sector use unavoidable in the policy debate.

Supporters argue that using existing large thermal assets can create enormous early demand, quickly launch international ammonia supply chains and reduce emissions intensity while technology advances. JERA completed a 20% heat-input ammonia demonstration at Hekinan Unit 4 in 2024 and is targeting commercial large-scale use around FY2029.

Critics argue that scarce low-carbon ammonia should be prioritized for fertilizer, chemical feedstock, shipping or industrial processes with fewer alternatives rather than subsidizing extended coal-plant operation.

The correct evaluation therefore cannot stop at tonnes of ammonia consumed. It has to include lifecycle emissions, competing alternatives, remaining plant life and whether today’s co-firing asset can credibly transition toward deeper decarbonization.

The opposite problem: local green hydrogen may remain too expensive

The Yamanashi and Fukushima hubs are tiny next to half-million-tonne ammonia chains. They sacrifice some economies of scale.

But local production avoids some of the international chain: no ocean transport, no liquid-hydrogen import terminal and potentially far shorter delivery. Where renewable electricity is competitive and industrial demand sits beside the electrolyzer, domestic hydrogen can have structural advantages.

Regional systems also allow several customers to share one local supply company rather than making the business depend entirely on a single giant buyer.

The unresolved question is scale. Is Japan better served by many thousand-tonne local hubs, or by a handful of giant ports distributing imported molecules inland? The first certified projects are experiments in both answers.

Why steel, quartz, beverages and chemicals?

The first projects share an important characteristic: the demand already exists. Steel needs process energy and reducing environments. Quartz processing needs high-temperature burners. Beverage plants need sterilization steam. Chemical companies already consume ammonia. Power plants already burn enormous volumes of fuel.

Government is not inventing a new consumer behavior from zero. It is trying to change the molecule that satisfies an existing industrial demand.

That helps explain why Japanese hydrogen policy has moved away from a passenger-car-centered narrative toward industry, heavy transport and energy hubs. An existing furnace or boiler can provide an anchor demand whose consumption is measurable before the hydrogen plant is built.

The low-carbon threshold should tighten as the market matures

Meeting the first-generation carbon-intensity standard cannot be the endpoint if the objective is net zero.

For fossil-derived low-carbon ammonia, upstream methane, carbon-capture rate and permanent storage matter. For electrolytic hydrogen, whether electricity comes from average grid supply or genuinely low-carbon additional generation changes the lifecycle result.

A 15-year support program therefore needs ongoing measurement, reporting and verification. “Low carbon” cannot become a certificate granted once at project approval and forgotten for the next decade and a half.

Is ¥3 trillion expensive? Ask what Japan is trying to buy

¥3 trillion is undeniably large. But the state is trying to purchase more than kilograms of hydrogen.

The program is also intended to create domestic electrolyzer markets, import chains, port infrastructure, burner and turbine technology, bankable long-term contracts, energy-source diversification and industrial decarbonization.

That does not exempt the program from comparison. The same public money could support renewable generation, transmission, batteries, efficiency or industrial electrification. Because hydrogen introduces conversion losses, direct electrification can often reduce emissions more cheaply where it is technically practical.

The right question is not “Is hydrogen expensive?” It is “Is support concentrated on uses where lower-cost alternatives are genuinely limited?”

2030 is not the finish line; it is the first delivery date

Most of the first certified projects begin supply between 2028 and 2031. In 2026, therefore, Japan does not yet have a proven price-gap policy. It has a policy that has begun converting project proposals into investment commitments.

Around 2030, hydrogen should begin flowing to Aichi Steel, low-carbon ammonia should move through Kawasaki chemistry, imported ammonia should reach Hekinan and Hokkaido, and regional hydrogen should serve Hakushu and Fukushima industries.

Then the 15-year clock really starts.

During those years electrolyzers have to get cheaper, renewable power has to expand, ships and terminals have to raise utilization, burners and boilers have to move into series production and additional customers have to enter the market.

In the mid-2040s, support for the earliest projects will begin ending.

If hydrogen disappears when the subsidy disappears, Japan will have purchased 15 years of activity rather than a market.

If customers continue buying, producers expand without equivalent support and new contracts can be signed on increasingly commercial terms, the state will have helped create an industry.

The real purpose of subsidy is to make subsidy unnecessary

Critics of hydrogen policy make a legitimate point: if a fuel needs enormous subsidy because it is structurally uneconomic, permanent protection will weaken both economic efficiency and decarbonization.

But energy infrastructures rarely emerge in a policy vacuum. Electricity networks, railways, LNG, nuclear power and renewable energy all developed within regulatory systems, public infrastructure, guaranteed markets or early public support.

The test is not whether hydrogen receives support at the beginning.

The test is what the support buys during the years before it ends: lower production cost, better equipment, common standards, more customers, deeper private investment and technologies that can compete beyond Japan.

Japan declared an ambition to lead the hydrogen society in 2017. It created a market law in 2024. In 2025 and 2026 it began assigning real long-term public support to specific supply chains.

The next question is no longer whether the technology works.

When the state stops paying the difference 15 years from supply start, will the market still be there?

That is the fairest scoreboard for Japan’s roughly ¥3 trillion hydrogen experiment.