[Column Series] Reassessing Japan’s Long-Term Decarbonized Capacity Auctions (No.3) Can Hydrogen and Ammonia-Fueled Power Realistically Serve as Decarbonized Energy Sources?

in Japanese

(Japanese original published on 23 July 2025)

Will hydrogen and ammonia power, which the government is promoting alongside CCS-equipped thermal plants, become viable decarbonized power sources?

Hydrogen inevitably entails energy conversion losses and higher costs due to production processes and facilities, whether it is green hydrogen derived from renewable electricity, or grey/blue hydrogen produced from natural gas. Because of this, hydrogen should be reserved for applications where electrification is impractical: certain industrial processes, chemical synthesis where hydrogen is an unavoidable feedstock, and long-distance transport fuels for ships and aircraft¹.

Ammonia, synthesized from hydrogen and nitrogen in the air, is even more expensive than its hydrogen feedstock, and its CO₂ emissions per unit of heat are relatively high². On the other hand, ammonia has advantages: it is easier to transport in bulk by ship, and easier to burn than hydrogen³. These traits make it promising as a combustion fuel. The government sees large-scale power generation as a key demand source to support a cost-reducing supply chain for bulk ammonia imports and considers the long-term decarbonized capacity auction as part of this strategy.

However, using large volumes of hydrogen and its derivative ammonia for thermal power generation would not only drive-up electricity costs, but also cause significant energy conversion losses. In fact, auctions held in 2023 and 2024 have already demonstrated these concerns in practice. For the third round, scheduled for fiscal 2025, the government is preparing to modify the auction rules, for instance by raising the price cap to secure sufficient bidding volume. This article examines the current situation and its challenges.

1. Current status of the Long-Term Decarbonized Capacity Auction

The auction has been held twice so far, in 2023 and in 2024, and preparations are now underway for the third round. In the first round, while total bids for all decarbonized power sources exceeded the procurement target, LNG-fired power fell short of its target, and all bids were accepted. Similarly, for retrofits of existing thermal plants to co-fire hydrogen and ammonia, bids also fell short of the target, and all were accepted. For this category, the awarded capacity reached only 826 MW against a target of 1,000 MW.

In the second round, the target for hydrogen/ammonia co-firing retrofits was again set at 1,000 MW, but there was only a single bid, amounting to 95 MW, less than one-tenth of the target⁴. LNG-fired power also underperformed: bids totaled 1,315 MW against a target of 2,240 MW, with all bids accepted.

In response to these results, the system is being revised ahead of the third auction. In particular, to encourage more bidding, price-related rules are expected to change. Planned revisions include raising the price cap, allowing the inclusion of variable costs such as fuel expenses, and introducing adjustments to account for inflation and interest rate fluctuations⁵(Table 1).

Table 1. Changes in procurement conditions for retrofitting existing thermal plants to co-fire hydrogen and ammonia

2. Challenges of Hydrogen and Ammonia Power Generation

In the auction, bidders are required to submit a decarbonization roadmap to 2050, showing the pathway toward full decarbonization. However, these roadmaps only specify the hydrogen and ammonia co-firing portion, making it difficult to see how much fossil fuel use will remain as a baseline. Moreover, although full decarbonization by 2050 is required, the draft guidelines for the Long-Term Decarbonized Capacity Auction allow “projects capable of generating 90% or more of rated output using hydrogen or ammonia fuel” to qualify as dedicated-firing projects⁶. This means up to 10% of LNG use is still permitted.

Based on the roadmaps submitted by winning bidders in the first auction, Figures 1 and 2 show the timeline for reductions in both the co-fired hydrogen/ammonia portion and the remaining fossil fuels, sorted by planned start of operation. This makes it possible to see when coal and LNG currently in use will decline and highlight the following issues.

Figure 1 Decarbonization roadmap of successful bidders for hydrogen and ammonia co-firing in the first auction

Figure 2 Decarbonization roadmap of successful bidders for LNG power in the first auction

1) Continued operation of high-emission coal plants

Among the six hydrogen/ammonia co-firing projects awarded in the first auction, five involve retrofitting existing coal plants to co-fire ammonia (Figure 1). These projects involve 20% co-firing retrofits, meaning that the entire plant’s capacity is about five times larger than the awarded capacity and most of the fuel burned will still be coal. The roadmaps vision started at 20% co-firing, moving to 50%, and then eventually converting to 100% ammonia in the 2040s. This implies that coal will continue to be used well in the mid-to-late 2040s.

Even if 50% co-firing is achieved partially, GHG emissions would still be 37% higher than those from current LNG-fired power plants⁷. To match the GHG emissions of LNG power, the co-firing ratio would need to reach 82%, which is not expected until after 2035⁸. For the next decade or more, these plants will emit more GHGs than LNG-fired generation, even with co-firing.

It is also important to note that, according to the working group that verified generation costs for the Seventh Strategic Energy Plan, 100% ammonia firing is expected to be achieved not by converting coal boilers, but by converting LNG gas turbines⁹. This means that dedicated ammonia generation requires different technology and different facilities from coal co-firing. As a result, the ammonia co-firing technology being demonstrated today—starting with 20% co-firing, aiming for higher shares and eventual commercial operation—will no longer be needed by the early 2040s at the earliest, and by 2050 at the latest.

Rather than investing substantial R&D resources (budgets, engineers, and time) into a technology that will become unnecessary by 2050, prolonging the life of coal plants, Japan should focus on accelerating the development of technologies that will actually be needed in the future. That would be a faster route to strengthening industrial competitiveness and increasing national tax revenues. Japan cannot afford to divert scarce resources to technologies with no long-term future.

2) LNG use continuing even in 2050

Figure 2 adds the LNG portion to the decarbonization roadmaps of the ten LNG-fired power plants awarded in FY2023. Compared with hydrogen/ammonia co-firing retrofits, LNG plants had both larger procurement targets and larger awarded capacities¹⁰. However, before co-firing begins—anywhere from 5 to 15 years after capacities are awarded—these plants will continue to run on 100% LNG. Even after co-firing starts, many projects plan only 10–20% hydrogen co-firing, meaning the remaining 80–90% will still be LNG. Moreover, even after converting to dedicated hydrogen firing between the mid-2040s and 2050, up to 10% LNG use will remain permitted.

While LNG plants are efficient and emit less CO₂ than coal-fired plants, in a decarbonizing world they risk becoming stranded assets, much like coal plants today. CCS, which the government expects to handle these emissions, is unlikely to be a viable solution. This issue is discussed in the next column (“Auctioning Fossil Power with CCS That Does Not Deliver— Unpacking the Technical and Institutional Gaps”).

LNG-fired plants are valued for their stable output and high flexibility in balancing variable renewables. But as long as their fuel is imported, they remain exposed to the geopolitical risks of maritime transport. Moreover, flexibility only has value if the share of variable renewables (solar, wind, etc.) is sufficiently increased to require balancing.

3) Limited GHG reduction effect from hydrogen and ammonia

Hydrogen and ammonia projects plan to transition from co-firing to dedicated firing, but most roadmaps show an initial reliance on blue hydrogen/ammonia, switching to green in the future¹¹. Blue hydrogen is produced from natural gas with CO₂ capture and storage and is also used as feedstock for blue ammonia. However, both involve significant warming impacts from methane leakage during natural gas extraction and transport. This issue is now being highlighted through global initiatives for detection and mitigation¹².

Globally, including in Japan, low carbon hydrogen standards have been set for carbon intensity (CO₂ equivalent emissions per kg of hydrogen produced), covering the upstream processes of feedstock production and transport¹³. Japan has also set standard for low carbon ammonia, applying them to eligibility for fuel cost gap support (Contract for Difference) under the Hydrogen Society Promotion Act¹⁴. Yet even if ammonia fully replaces coal in a coal plant, GHG emissions per unit of heat are only reduced by 62%, leaving 38% of emissions. In a high-efficiency gas turbine, the remaining emissions would still be 31% of the original coal plant level¹⁵. With the government allowing up to 10% of LNG co-firing, the reduction effect would be even smaller.

The government’s definition of “decarbonized thermal power” covers only domestic power plant operations. But international certification systems and regulatory frameworks are based on a “well-to-gate” scope, covering the entire upstream supply chain to the hydrogen production stage, under which the result is never zero. Since much of Japan’s planned hydrogen and ammonia supply will be imported, additional GHG emissions from maritime transport and conversion processes (liquefaction, ammonia synthesis, methylcyclohexane production) must be considered. Internationally, there are moves to include transport in benchmarks, and this is expected to be reflected in ISO standards.

4) Risk of high-cost electricity

As noted earlier, awarded capacity for hydrogen/ammonia co-firing retrofits in the second auction was less than one-tenth of the target. For the third auction, the government plans to more than double the price cap, alongside other favorable terms for bidders (Table 1). If this boosts participation, it will lead to more expensive electricity; if it fails, it may trigger even more generous incentives.

Either way, the cost will ultimately fall on consumers, not only through taxes but also through higher electricity bills. The government appears to be aiming to award the remaining 600 MW needed to reach its Sixth Strategic Energy Plan target of supplying about 1% of electricity from hydrogen and ammonia by FY2030 (equivalent to 1.52 GW)¹⁶. But with current difficulties in attracting bids, it may be time to revisit the assumptions made four years ago and update the plan to reflect present realities.

3. Conclusion

Reviewing the auction results and current situation from the perspective of hydrogen and ammonia-fired power generation reveals a troubling reality: under the banner of “decarbonized thermal power in 2050”, fossil-fuel-based generation, particularly coal, will remain dominant for nearly the next two decades. Even by 2050, the supply of truly decarbonized electricity is unlikely to be sufficient. Moreover, changes to the auction’s price ceiling are expected to drive up winning bid prices, raising the risk that future hydrogen and ammonia generation costs will exceed government projections even further.

In the government’s own cost review, conducted in parallel with the drafting of the 7th Strategic Energy Plan, the projected 2040 generation costs for decarbonized thermal power—such as dedicated hydrogen-fired and coal–ammonia co-firing—were estimated to be higher than those of renewable sources. However, those projections assumed that the capital and O&M costs for ammonia co-firing would match those of coal plants, and that for dedicated ammonia firing and hydrogen (both co-firing and 100% firing) they would match those of LNG plants. Looking at the upward trend in auction price ceilings, these assumptions appear unrealistic, suggesting that the actual costs of decarbonized thermal power are likely to exceed government estimates.

If this course continues, Japan risks being locked into expensive, high-emission electricity: burdening households, eroding companies’ international competitiveness, and even threatening the country’s ability to secure sufficient foreign currency for imports.

Now is the time to pursue genuine decarbonization of the power sector. Rather than pouring public funds into promoting hydrogen and ammonia generation technologies with high import dependence, high costs, and limited emissions reduction benefits, Japan should prioritize expanding solar, wind, and hydropower, alongside investments in pumped storage and batteries to strengthen flexibility. This approach would improve energy self-sufficiency, reduce greenhouse gas emissions, and revitalize domestic industry.

 

Column Series: Reassessing Japan’s Long-Term Decarbonized Capacity Auctions

No. 1  Overview: Questioning the Effectiveness of the Long-Term Decarbonized Capacity Auction (18 August 2025)
No. 2  Supporting Fossil Power Under the Label of “Decarbonization”: Where Does a 90% Reduction Without Phase-Out Lead?  (26 August 2025)
No.3  Can Hydrogen and Ammonia-Fueled Power Realistically Serve as Decarbonized Energy Sources?  (26 August 2025)