Is Japan’s 2040 'Near-Zero Emissions' Target for Thermal Power Realistic? A Cost and Feasibility Check of Hydrogen, Ammonia, and CCS

in Japanese

(This is the English translation of the summary of the Japanese article, originally published on 22 May 2025. Please refer to the Japanese version for the charts and figures.)
 

1. Introduction — Japan‘s NDC Assume Near-Zero Emissions from Thermal Power

In February 2025 the Japanese government revised its Global Warming Countermeasures Plan, setting new targets for greenhouse gas reductions: a 60% cut from 2013 levels by 2035, and 73% by 2040. The concurrently released 7th Strategic Energy Plan projects that by 2040, the power mix will consist of 40–50% renewables, 20% nuclear, and 30–40% thermal power.

A key premise of these plans is that CO₂ emissions from thermal power need to be near zero by 2040 through the use of hydrogen or ammonia as fuels, and carbon capture and storage (CCS). These technologies are expected to reduce CO₂ emissions 0.08 ～ 0.20 kg/kWh, down sharply from the roughly 0.8 kg/kWh emitted by today's coal plants. However, these reductions depend on technologies that are not yet established.

Cost is another major concern. In preparing the Energy Plan, the Ministry of Economy, Trade and Industry (METI) calculated the levelized cost of electricity (LCOE) using model plants through its "Cost Verification Working Group" (see Figure 1 on the Japanese site). Since LCOE results are susceptible to assumptions, the validity of those assumptions is crucial.

A separate report by the Renewable Energy Institute noted that the Working Group may have underestimated the cost and risks of nuclear power while overestimating the future costs of renewables¹. Even based on government estimates, power generated from hydrogen (29.9 yen/kWh) and CCS-equipped coal (27.7 yen/kWh) is 2 to 3 times more expensive than solar or wind. Moreover, even these cost figures may be underestimated.

This column reviews the feasibility and cost assumptions behind hydrogen, ammonia, and CCS technologies.
(For full details, please refer to the original Japanese text. This is a summary.)

2. Cost Assessment of Hydrogen and Ammonia-Based Thermal Power

The government's cost estimates for hydrogen and ammonia power generation do not sufficiently reflect the realistic increases in capital and operating costs involved in their deployment. METI assumes that the capital and O&M costs for hydrogen-only generation can be modelled using LNG power plant data, and those for co-firing with ammonia using coal plant data². However, actual deployment requires dedicated combustion systems, storage facilities, and supply infrastructure, and the additional costs of installing and maintaining these have not been accounted for.

2.1. Cost of Ammonia Power Generation
Key concerns include:

Underestimated Equipment and Operating Costs

• A demonstration project (JERA’s Hekinan power plant) required the replacement of 48 burners to achieve 20% ammonia co-firing in one power plant. Construction of four storage tanks and 4 km of pipeline is ongoing for the future co-firing project.
• Due to ammonia's toxicity, corrosiveness, and flammability, leak monitoring and safety measures are essential.
• BloombergNEF estimates that even 20% co-firing results in 11% higher capital costs and 10% higher O&M costs³.

Lower Efficiency and Higher Fuel Costs

• Ammonia has lower calorific value than coal. BloombergNEF estimates a 12% efficiency drop at 20% co-firing.
• Nevertheless, the government assumes unchanged efficiencies (43.3% for coal, 57% for LNG)⁴.
• Lower efficiency leads to increased fuel consumption and higher operating costs.

Unaccounted GHG Emissions (N₂O) and Mitigation Costs

• Ammonia combustion emits N₂O at 800–1500 ppm, a gas with 273 times the global warming potential of CO₂.
• In CO₂-equivalent terms, this is 1.5 to 3 times more than coal-fired emissions.
• Costs for mitigation measures (e.g., suppression technologies, recovery equipment) are not included in the government estimates.

2.2.  Cost of Hydrogen Power Generation
The government’s estimates assume hydrogen plants can share the same specifications as LNG facilities, overlooking critical technical and economic differences.

Key concerns include:

Underestimated Equipment Costs

• Hydrogen’s energy density is roughly one-third that of LNG, requiring larger infrastructure for an equivalent energy supply.
• Liquid hydrogen must be stored at −253°C, much lower than LNG's −162°C, requiring specialized equipment like loading arms and cryogenic tanks.
• These are not covered in the existing estimates and are acknowledged by METI as areas still needing technical development.

Uncertain Cost Reductions in Hydrogen Supply Infrastructure

• Currently, about 90% of hydrogen costs come from transport-related activities (liquefaction, shipping, etc.).
• The government aims to cut costs to 30 yen/Nm³ by 2030, assuming the deployment of 160,000 m³ hydrogen carriers.
• However, following the 2024 cancellation of an Australian brown-coal-based hydrogen project⁵, plans shifted to smaller 40,000 m³ vessels⁶, reducing the government's expected economies of scale. This undermines the earlier assumptions of major cost savings through large-scale transport.

The government’s hydrogen cost estimates underestimate ① the uniqueness and cost of generation equipment, ② the infrastructure needed for ultra-cold transport and storage, ③ the uncertainties in achieving transport efficiency, and ④ the vulnerability of international supply chains.

3. Cost of CCS-Equipped Thermal Power Generation

Government estimates for 2040 assume CCS can be deployed on a large scale, but this overlooks significant technological, geographic, and regulatory uncertainties that could drive up costs.

Key issues include:

Unrealistic CO₂ Capture Rate Assumptions

• A 90% capture rate is assumed, but CCS for power plants has only achieved 60–70% so far⁷. Although for cost estimate, it would be appropriate to consider 90% or more capture costs, achieving and sustaining such high rates in practice is challenging due to sharply rising costs, increased energy demand, and operational complexity..
• Under the currently discussed CCS inclusion in the Decarbonized Power Auction, even a 20% CO₂ capture is acceptable⁸. This shows the reality of the difficulty in capturing and storing economically.

Unconsidered Geological Constraints

• Japan lacks identified geologic formations for safe CO₂ injection. In FY2024, over half of the government selected the "Advanced CCS Projects" ⁹ for offshore or international storage, suggesting domestic options are limited.
• According to Wood Mackenzie¹⁰, CCS costs in Japan are 1.5–2 times higher than in other countries, the highest in the Asia-Pacific region.

Unrealistic CO₂ Transport Assumptions

• The model assumes 200 km of pipeline transport, based on Tomakomai's pilot.
• Many actual projects plan for over 5,000 km of overseas shipping, reflecting the lack of domestic storage.
• Overseas transport increases costs by at least 25% compared to domestic solutions, according to the same analysis above by Wood Mackenzie.

Absence of Contingency Cost

• CCS for power plants remains an immature technology with unresolved issues in capture, transport, storage, and monitoring. Such infrastructure typically requires contingency budgeting to account for risks¹¹. However, government estimates do not include such contingency cost estimation.

4. Energy Policy and Assumptions — Seeking Common Ground for the Future

As shown in Figure 1, even the government’s estimates indicate that hydrogen, ammonia, and CCS-based power are far less cost-competitive than solar and wind. Furthermore, the underlying assumptions are questionable, and actual costs are likely higher.

Investments based on underestimated costs and overestimated feasibility may lock Japan into high-cost, import-dependent energy, burdening businesses and households.

The new RE100 criteria ban electricity derived from coal co-firing after 2026¹². For Japan’s 93 RE100 members, this would also rule out ammonia co-fired power.

Renewable Energy Institute’s 2040 scenario shows renewables could supply over 90% of power, cutting CO₂ emissions by about 80% from 2019 levels and raising energy self-sufficiency to 75%, while also supporting domestic investment, job creation, and energy security¹³.

It also concludes that if hydrogen and CCS costs do not fall, the government's GHG reduction goals are likely unattainable, and even if the technologies do improve, electricity costs would rise.

If underestimated power generation costs for hydrogen, ammonia, and CCS-equipped thermal power, combined with overestimated feasibility, lead to misguided investment decisions, the result could be a costly, high-emission, import-dependent energy supply. This would place a burden on business activity and, ultimately, on the public.

When presenting key national energy policies, it is essential to establish a shared understanding of the underlying assumptions through discussions among diverse experts beyond organizational interests. Only through such an inclusive and transparent process can we envision a more realistic, sustainable, and broadly accepted energy future.