With offshore wind tender rules rewritten, the first hydrogen subsidies awarded and full trading under the GX emissions trading scheme set for 2027, lawyers say Japan’s energy transition now depends less on policy ambition and more on whether projects can make money.
Since pledging in 2020 to reach net zero by 2050, Japan has been busy writing its decarbonisation rulebook. It has set up offshore wind auctions, passed a dedicated hydrogen law, created a carbon capture and storage (CCS) regime and launched a national carbon market.
Climate is only part of the motivation. Japan has few natural resources and imports most of its energy. When the 2011 Fukushima disaster took its nuclear reactors offline, the country leaned harder on imported gas and coal. That left it exposed to swings in global prices and to supply disruptions beyond its control.
Now comes the hard part. Rising costs, wary lenders and the arrival of real carbon prices are testing whether those rules can produce projects that banks will finance. As a result, clients are bringing their lawyers very different questions.
“The biggest change is that the market has become much more focused on commercial viability rather than policy ambition,” says Peter Armstrong, partner and regional head of energy and natural resources, Asia, at DLA Piper.
Offshore wind: feasibility over price
Offshore wind is one of the clearest examples. The Japanese government is targeting 10 GW by 2030, but over the past year one of the market’s flagship deals fell apart.
“In the offshore wind sector, a consortium that had won bids in the first round of the public tender pulled out of the projects, citing rising costs that had made the projects unprofitable,” says Kunihiro Yokoi, partner at Anderson Mori & Tomotsune.
The fallout has changed how projects are awarded. The withdrawal “has led to new tender rules,” Yokoi says, “clearly shifting the focus toward the feasibility of projects, such as capability, construction and operational plans and supply-chain resilience, rather than pricing or development speed alone.”
Armstrong sees the same caution among developers. “In offshore wind, developers are looking closely at auction design, supply chain inflation, and project economics following challenges faced by earlier award winners,” he says.
The news isn’t all bad. In other marine areas, Yokoi notes, projects that were under development are now moving into implementation. In January, Japan’s first floating offshore wind farm, off Goto City in Nagasaki, began commercial operation.
On the road to 2030, permitting remains a major hurdle. Yokoi says the starting point is securing the right to use the seabed, which he calls “a critical issue” for developers. Environmental impact assessments and coordination with holders of statutorily protected rights also arise regularly.
Armstrong argues that the real difficulty is managing everything at once. “The biggest challenge is coordinating multiple regulatory and stakeholder processes rather than obtaining any single permit,” he says.
“Developers continue to face challenges relating to seabed occupation rights, environmental assessments, fisheries engagement, grid connection, port infrastructure, and local stakeholder support.”
The design of the auctions is also under scrutiny. “We are also seeing increased focus on whether the auction framework provides enough flexibility to address supply chain cost increases and changing market conditions,” Armstrong says.
He adds that cabotage, vessel availability, labour requirements and localisation expectations remain important considerations for international sponsors.
“In the offshore wind sector, a consortium that had won bids in the first round of the public tender pulled out of the projects, citing rising costs that had made the projects unprofitable… [this] has led to new tender rules clearly shifting the focus toward the feasibility of projects…rather than pricing or development speed alone.”
Kunihiro Yokoi, Anderson Mori & Tomotsune
Hydrogen and ammonia: subsidies first, finance later
Hydrogen and ammonia are central to Japan’s plans for cleaning up power generation and heavy industry, and they too are moving from paper to practice.
The first subsidies under the Hydrogen Society Promotion Act have been awarded. Yokoi says seven projects — four in Japan and three overseas — have received price-difference subsidies under the Act’s first programme. They range from industrial electrolytic hydrogen projects to imported ammonia for co-firing at power plants. Two more projects have secured support under a second programme that funds transport and storage facilities.
Hydrogen- and ammonia-fired thermal power projects have another option too. Yokoi adds that they can also bid into a separate subsidy scheme, the Long-Term Decarbonisation Power Supply Auction (LTDA).
Investors remain interested, Armstrong says, but are becoming more selective. “Investment decisions are increasingly tied to subsidy support, long-term offtake arrangements, and proven demand rather than simply technology deployment,” he says. “Japan’s hydrogen framework and Contracts for Difference (CfD)-style support mechanisms have helped move discussions from concept stage toward bankable projects.”
Still, getting from a subsidy award to financial close is a big step, and both lawyers believe hydrogen and ammonia deals are not yet as financeable as renewables.
Yokoi says financing in this space is still at an early stage in Japan, so lenders may be unwilling to assume completion risk and may require some form of sponsor support. “This is very different from wind or solar financings, which are considered as projects using proven technologies,” he says.
Armstrong says the gap comes down to track record and revenue certainty. “The key difference is that hydrogen and ammonia projects are generally not yet supported by the same operating history and revenue certainty that underpin traditional wind and solar financings,” he says.
“As a result, lenders place much greater emphasis on revenue support mechanisms, government subsidies, technology risk allocation, EPC structures, feedstock arrangements, and long-term offtake agreements.”
That means building up several layers of support before lenders will commit. “In many cases, projects require a combination of strategic sponsors, government support, and contracted demand before debt providers become comfortable,” Armstrong says.
“By contrast, wind and solar financings are now relatively mature and typically rely on well-understood construction and operating risk profiles.”
CCS and carbon pricing: who pays?
Carbon capture and storage (CCS) is following a similar path from rulemaking to project development.
Yokoi says that, with the CCS Business Act now fully in force, detailed monitoring rules for CO₂ storage projects are in place. By April 2026, exploratory drilling had been approved at two offshore sites, Tomakomai and Kujukuri. Work is now under way on an initial pipeline of projects, with commercial-scale storage targeted for the early 2030s.
Of all these frameworks, though, the Green Transformation (GX) emissions trading scheme is likely to have the widest commercial reach. Full trading begins in 2027, and companies are moving from tracking the policy to preparing for it.
“On the GX side, clients are spending significantly more time on carbon compliance, emissions data management, and understanding how future carbon costs will impact investment and procurement decisions,” Armstrong says.
For many companies, there is a lot to learn. “Clients are not familiar with the new rules,” says Yokoi. Companies joining the scheme for the first time want to know what will be asked of them. Others want help drafting standard terms for the relevant contracts or working out how the scheme affects deals they have already signed.
For Armstrong, much of the work comes down to one question: who’s footing the bill? “Many are reviewing power purchase agreements, fuel supply agreements, industrial offtake contracts, and M&A documentation to determine who bears future carbon costs and how those costs can be passed through,” Armstrong says.
“Companies are also assessing how J-Credits and other eligible credits can fit within their broader compliance strategy.”
What to watch
For Yokoi, the big unknown is the scope and design of the LTDA. He says offshore wind, hydrogen, ammonia and other GX-related projects “will still require some strong driver to improve profitability of the projects and boost developments at this stage.”
He is also watching relations with local communities, which have become a hot topic for renewable projects in Japan in recent years. He expects developers to pay close attention to any regulatory moves in this area.
Armstrong is watching three developments. The first is further offshore wind reform, which could sway investor confidence and project economics. The second is the rollout of hydrogen and ammonia support, which will determine whether large-scale supply chains become financeable. The third is carbon pricing and credit rules under the GX scheme, which will increasingly shape investment decisions and deal structures.
Behind all this is a broader balancing act: keeping energy secure and affordable while continuing to cut emissions. Armstrong believes the task is becoming harder as data centres, AI infrastructure and industrial electrification drive up power demand.
That pressure could shift the priorities of regulators and investors, making energy security and grid development increasingly important drivers of legal and commercial strategy.
“The biggest challenge is coordinating multiple regulatory and stakeholder processes rather than obtaining any single permit… Developers continue to face challenges relating to seabed occupation rights, environmental assessments, fisheries engagement, grid connection, port infrastructure, and local stakeholder support.”
Peter Armstrong, DLA Piper
“These developments are likely to shape how energy transition projects are financed, contracted and developed over the coming years,” says Armstrong.
