Hydrogen and ammonia are costly for Japan's power sector

Summary

Japan is aiming to make hydrogen and ammonia key pillars of its energy transition. In the 7th Strategic Energy Plan and Basic Hydrogen Strategy, production volumes of hydrogen and ammonia are targeted to accelerate from 3 million tonnes in 2030 to a combined 20 million tonnes by 2050. The sectoral distribution of the hydrogen and ammonia has not yet been established, with use-case options in power, industry, and transport. Additionally, 15 trillion yen (US$94bn) has been budgeted for policy support for hydrogen supply chains, including 3 trillion yen set aside to support contracts for difference (CfDs) over the next 15 years. Against this backdrop of policy and public financial support, our analysis raises significant questions over the delivered cost of hydrogen and ammonia into Japan and its role in reducing emissions in the power sector.

Our results show from a cost and emissions reduction perspective, hydrogen and ammonia are expensive options in the power sector and (at least initially) when fuel blending shares are low, the emissions savings are minimal (particularly once the emissions across the blue hydrogen and ammonia supply chains are taken into account). If we compare the range of delivered hydrogen costs to Japan against METI's target price, our analysis suggests a large range of uncertainty, with our minimum price for domestically produced hydrogen significantly above METI's target price. This raises a key policy question: in some sectors, would direct electrification be a more cost-efficient way to scale clean energy and encourage deeper emissions reductions sooner?

The accompanying report and levelised cost Excel tool helps users to explore different pathways for delivered cost and emission intensity of hydrogen and ammonia production. TransitionZero has also published scenario analysis of transitions to net-zero emissions in the power sector using an energy system model.

Current Japanese policy aims to create a hydrogen economy

Japan was the first country to form a national hydrogen strategy. The strategy identified several sectors where hydrogen could facilitate decarbonisation including road transport and shipping, refining, high process heat in industry (chemicals, iron and steel) and the power sector.

However, a key question - not just in Japan, but globally - is how to decarbonise all sectors and how to support first movers across the economy. For example, the direct electrification of energy service demands (mobility, space heating, industrial processes) could avoid significant efficiency losses and costly processes across the hydrogen supply chain. Whilst electrification undoubtedly raises questions around grid stability, flexibility, and storage, investments in the grid (including using electric vehicles as mobile batteries) could improve energy security and facilitate decarbonisation in the long run. Crucially, hydrogen produced from fossil gas (i.e. via a steam methane reformer (SMR)) is currently (and at least in the near-future, likely to be) the dominant production pathway, meaning Japan will continue to be open to international volatility if hydrogen continues to be produced from fossil feedstocks.

Levelised cost of hydrogen and ammonia accounting tool

We developed a levelised cost of hydrogen (LCOH) and ammonia accounting tool to assess costs and emissions intensities of delivering hydrogen and ammonia in Japan across different production pathways and from different geographies. Some of the key features of this tool are shown in the table below.

* Note: these stages only apply to imported pathways for delivered hydrogen and ammonia into Japan

The analysis in this blog and the wider report use levelised cost and emissions intensity metrics to assess the range of cost and emission implications of producing and importing hydrogen and ammonia into Japan. This analysis does not assess physical volumes of hydrogen and ammonia, nor the corresponding absolute emissions associated with those volumes.

However, by using the cost and emission intensity ranges developed in this study, we can use absolute production targets and emissions intensity targets from the Japanese government to provide additional context to our analysis. For full details on the input data, please download the report here and the Excel tool here.

Current levels of policy support for hydrogen contracts for difference (CfDs) would leave a significant price gap

Our analysis suggests that the current 3 trillion yen allocated to support contracts for difference (i.e. to bridge the difference between fossil fuels and their corresponding hydrogen and ammonia substitutes) would leave a substantial price gap, and it is likely a significant proportion would have to be passed on to consumers.

Estimated annual fuel expenditure and current allocated public financial support for CfDs

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Note: The range of annual expenditure on hydrogen and ammonia are derived by taking the price difference between the lowest and highest cost of hydrogen and ammonia net an assumed price for an equivalent unit of gas and coal. We then multiply those by the production targets from the Basic Hydrogen Strategy and 7th Strategic Energy Plan. This gives us a minimum and maximum derived total cost of supplying the targeted volumes of hydrogen and ammonia, net the displaced equivalent volume of fossil fuels.

In the power sector, power plants running on 100% hydrogen or ammonia would have a very high marginal cost of generation and would likely only be run as peaking plants or as balancing plants with very low capacity factors(see next chart).

From both a cost and emissions reduction perspective, renewables are the most effective options for investment in a decarbonised power system​

In comparison to other harder-to-abate sectors, the power sector has technologies proven at scale to help reduce exposure to fossil fuel markets and reduce emissions. Whilst Japan is constrained in terms of spatial potential for renewables, there is nevertheless an opportunity to make solar and wind, combined with battery storage, a cornerstone of the power system. Our analysis suggests that on a levelised cost and emissions reduction comparison, renewables outcompete innovative thermals. Whilst thermal plants have a key advantage in terms of being dispatchable, batteries are starting to facilitate renewables working in a similar manner. For example, recent analysis by Ember in the USA has shown solar PV plus battery systems can take advantage of high supply-lower demand during the day and shift this to peak evening hours, displacing a significant proportion of demand for dispatchable fossil generation.

Using METI's targets of blending shares in innovative thermal plants (i.e. blending conventional fossil fuels with hydrogen or ammonia), we assessed the levelised cost of electricity of blending plants against three renewable technologies combined with battery storage: solar PV, onshore wind, and offshore wind. Renewables are consistently cheaper than innovative thermal technologies, even when the share of higher cost hydrogen/ammonia in the blending mix is low as it is in 2030.

Levelised cost of electricity for different renewable and blending technologies

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Note: The min price and max price in the chart above for each blending option takes the minimum and maximum delivered price of hydrogen and ammonia from our levelised cost analysis. We then generate a levelised cost of electricity (LCOE) taking into account the price of blended fossil fuels and the efficiency of each technology. We assume the share of hydrogen and ammonia blending increases in line with METI's SEP6 for 2030 and OCCTO's latest Generation Adequacy study for 2040/50 assumptions. This increased blending share is the reason why the levelised cost of the blending/CCS technologies increases from 2030 to 2050.

In 2030, hydrogen and ammonia will be blended with gas and coal at shares of 10% and 20%, respectively. Thus the emissions reduction benefits of these blending shares, particularly once the emissions associated with producing blue ammonia and hydrogen are taken into account, are limited. From an emissions perspective, our analysis suggests a combination of keeping methane leakage across the gas supply chain to less than 1% (of total volume) and carbon capture and sequestration rates exceeding 80% would be required to keep current outlined regulatory benchmarks for blue ammonia delivered to Japan. In 2030, none of the production pathways for blue ammonia we analysed were within the current regulatory emissions intensity ceiling of 168 kgCO₂/MWh (or 0.87 tCO₂/tNH₃). The chart below shows the emissions intensity of delivered blue ammonia into Japan from a range of supply locations and across our modelled years (2030, 2040 and 2050).

Emissions intensity of delivered blue ammonia to Japan

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As the share of hydrogen and ammonia increases, the emissions reduction benefits also improve, however the costs (given hydrogen and ammonia are significantly more expensive than fossil gas and coal) of generation also significantly increase.

Assuming the share of hydrogen and ammonia fuels in innovative blended thermal plants increases to 100% by 2050, our analysis suggests the levelised cost of electricity from these thermal plants will be between $193-696/MWh, compared to $66-124/MWh for renewables combined with battery storage.

Whilst a levelised cost is a simplified metric and power system dynamics are significantly more complicated, scenario modelling - to be released subsequently - by TransitionZero estimates that a cost-optimal net-zero pathway for Japan would have renewables and nuclear providing over 80% generation by 2050 with the role of thermals targeted at peak demand. The combined widespread deployment of renewables, storage systems, interconnection capacity and supply- and demand-side flexibility can all help with system stability. Research by TransitionZero has shown that supply-side flexibility from thermal operators and increased storage in a power system with high renewable shares (50% in 2040) can minimise curtailment of renewables. Additionally, research by REI, Agora, and LUT has shown the key role of demand-side flexibility across multiple sectors including iron and steel and power and heat in facilitating the required transition.

The role of hydrogen and ammonia in the power sector in this context is negligible as fossil-CCS is considered a more cost effective decarbonisation route (assuming capture rates increase to 90% by 2050). This diminished role for thermals could push the LCOE of the blending technologies up even further because in Figure 2 we assume that future capacity factors of hydrogen-gas and ammonia-coal plants are equal to 2024 capacity factors for conventional gas (42%) and coal (57%) plants. In reality, significant installed capacity could be required (in MW) but to operate only in a select number of hours in a year (e.g. when the system is stressed from peak demand, lower renewable output etc.).

The range of delivered hydrogen costs in our analysis is significantly wider than METI’s strike price target

In 2030, METI's target price for hydrogen is approximately $2.2/kg, falling to $1.5/kg by 2050. Our analysis suggests the 2030 price may be achievable for hydrogen produced in Japan but only if sequestration capacity (for captured CO2) is available domestically and gas prices are significantly below their current levels (we use IEEJ projections of approximately $9/MMBtu in 2030). Whilst gaseous hydrogen can be produced at a much lower cost in other geographies, the additional cost of liquefying hydrogen - an energy intensive process - and high losses in transportation means that delivered liquid hydrogen into Japan is consistently higher cost than hydrogen produced in Japan. Our analysis suggests that significant policy support or accelerated cost reductions along the hydrogen supply chain would be required to meet METI's strike price target of $1.5/kg in 2050.

Our analysis looked at two main production pathways - blue and green - for delivering hydrogen and ammonia in Japan. Given the energy-intensive process for liquefying hydrogen so it can be shipped longer distances and the significant boil-off losses in transportation, domestically produced hydrogen is consistently cheaper than importing LH2. Whilst in 2030 domestically produced blue hydrogen is cheaper than green using our baseline assumptions, continued cost reductions in renewable energy and electrolysers means that by 2040, domestically produced green hydrogen is cheaper than blue. This finding is caveated with the assumption that any captured CO2 would need to be transported and sequestered outside of Japanese territorial waters. However given that Japan has limited sequestration potential and that other much larger emitting sectors will be competing for this limited capacity, it seems likely that CO2 emitters in Japan will have to rely on agreements to ship and store carbon elsewhere, reflected in large Japanese industrial conglomerates signing Memoranda of Understanding (MoUs) with public and private entities in Southeast Asia and Australia.

This sharpens the policy question raised at the outset. Given the scale of renewables and electrolysers required to produce green hydrogen, and the efficiency losses at every stage of the supply chain, directing Japan's constrained renewable potential towards hydrogen production carries a real opportunity cost. Direct electrification combined with storage systems could scale clean energy at lower cost and encourage deeper emissions reductions sooner. This has implications on both the supply and demand side, as policies to encourage the electrification of energy service demands (e.g. mobility, heating) could stimulate power demand and have their own impact on the stability of grid supply (e.g. electric vehicles being utilised for mobility and as effective batteries).

Explore the report and levelised cost of hydrogen and ammonia tool

You can explore the wider report and levelised cost of hydrogen and ammonia Excel tool on our website here.

The Excel tool can be expanded and used as a template to:

1. Expand geographically - include more countries to compare the cost and emissions intensities of domestically produced vs. imported supply options
2. Expand the supply chain to include other processes - for example, to include ammonia-to-hydrogen cracking as an alternative option for delivering hydrogen as a final product

This blog is part of a series based on research by Dan Welsby, Joel Yap and Alex Luta for ClientEarth.

*For example, a 1 MW electrolyser would require 3-8 MW of renewables (depending on the technology in question) to ensure a comparable output from a 1 MW investment in an SMR with CCS

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