Chapter 1: Executive Summary – Fundamental Findings of Phased Transition Strategy
The detailed analysis in this report has clarified the essential characteristics of both ammonia and hydrogen value chains. The most important finding is the phased transition structure where ammonia functions as both a transitional energy source and the optimal transport medium for hydrogen. In contrast, hydrogen emerges as the ultimate long-term energy form. While conventional energy transition discourse has predominantly viewed hydrogen and ammonia as competing alternatives, this analysis demonstrates that both are in a complementary and phased relationship.
Based on this structural understanding, we have integrated assessments of technological maturity, economic viability, market potential, and risk factors to develop optimal strategic choice guidelines by application, region, and timeline, along with phased implementation roadmaps for 2030/2040/2050. Investment profitability analysis confirms a gap between the hydrogen business IRR of 8-12% and the ammonia business IRR of 12-18%, with ammonia’s short-term superiority enabling investment risk diversification, technology development efficiency, and accelerated market creation, thereby outlining a realistic implementation strategy for global energy transformation.
Regional competitive structure analysis shows that the Middle East’s combination of abundant natural gas resources and low-cost solar power (1-2 cents/kWh) establishes overwhelming superiority, with predicted structural transformation of international competitiveness through phased reduction of ammonia production costs (2025: $600-800/t → 2030: $400-600/t → 2040: $300-500/t).
Table 1-1: Regional Ammonia Production Competitiveness Structure (Revised)
| Region | Power Cost | Existing Production Base | Transition Strategy | 2030 Target | Key Competitive Factors |
| Middle East | 1-2¢/kWh | Natural gas reforming | Blue→Green two-stage | Blue 70%・Green 30% | Low-cost natural gas・Solar resources |
| China | 4-6¢/kWh | Coal gasification | CCUS combined gradual transition | Green 20% | Largest production capacity・Policy support |
| India | 3-5¢/kWh | Natural gas・Coal | Existing facility modification focus | Green 15% | Chemical industry base・Abundant labour |
| Australia | 1-3¢/kWh | Natural gas reforming | New green facility addition | Blue 60%・Green 40% | World’s highest renewable energy standard |
| Europe | 10-15¢/kWh | Natural gas reforming | Mixed production phased transition | Green 40% | Environmental regulations・Technology |
Table 1-2: Techno-economic Comparison for Long-distance Transport (15,000km)
| Transport Form | Energy Density | BOG Loss Rate | Transport Ship Construction Cost | Operating Cost | Storage Temperature |
| Liquid hydrogen | 71kg/m³ | 8-12% | 3.5x ammonia ship | 4.2x ammonia ship | -253℃ |
| Liquid ammonia | 602kg/m³ | <1% | Baseline | Baseline | -33℃ |
| Compressed hydrogen | 42kg/m³ | 2-3% | 5.8x ammonia ship | 6.1x ammonia ship | Ambient |
Chapter 2: Essential Issues in Manufacturing and Structural Analysis of International Competitiveness
Geopolitical Structure of Ammonia Production and Phased Green Transition
The basic process of ammonia production presupposes hydrogen production, which is achieved through the Haber-Bosch process, which combines three hydrogen molecules with one nitrogen molecule via a catalytic reaction. Due to this chemical structure, competitiveness in ammonia production is inseparably linked to hydrogen production technology, with current industrial hydrogen production comprising 75% natural gas reforming, 20% coal gasification, and 5% electrolysis.
With 80% of global ammonia production capacity derived from fossil fuels, a phased green transition strategy utilising existing production bases in major producing countries (China, India, Russia, USA) becomes the realistic solution. The transition scenario establishes phased conversion from the 2025-2030 period (70-80% fossil fuels, 20-30% electrolysis) to complete green transition by 2040, with green ammonia production costs predicted to decrease from $900-1,800/t in 2024 to $550-1,250/t in 2030, $330-810/t in 2040, and $250-570/t in 2050.
Fundamental Constraints of Hydrogen Electrolysis Technology and Solutions
The primary constraint of hydrogen electrolysis technology lies in the capacity factor. Due to the intermittency of renewable energy, current capacity factors remain at 40-70%, creating fundamental challenges with compatibility with the Haber-Bosch process’s requirement for >90% continuous operation. Solving this requires innovation in hydrogen storage technology, with cost reduction from the current $300-500/MWh to $100-200/MWh, enabling capacity factor stabilisation through 24-72 hours of intermediate hydrogen storage.
Alkaline electrolysis is the most mature with 70% efficiency and CAPEX of $800-1,500/kW, while PEM electrolysis has 65% efficiency but higher CAPEX of $1,500-2,500/kW, and SOEC electrolysis boasts high performance of 85% efficiency but faces cost challenges at CAPEX of $2,000-3,500/kW. While scale effects from larger systems are expected, current technical limits are around 100MW scale, with technological breakthroughs to the 500MW class by 2030 and the 1GW class by 2040 holding the key to industrialisation.
Table 2-1: Phased Green Transition Scenario (Utilising Existing Plants)
| Transition Stage | Natural Gas Reformed Hydrogen | Electrolytic Hydrogen | Additional Investment | CO2 Reduction Rate | Manufacturing Cost Impact |
| Stage 1 (2025-2030) | 70-80% | 20-30% | 30% of existing investment | 20-30% | +15-25% |
| Stage 2 (2030-2035) | 40-50% | 50-60% | 60% of existing investment | 50-60% | +25-40% |
| Stage 3 (2035-2040) | 20-30% | 70-80% | 90% of existing investment | 70-80% | +35-55% |
| Complete transition (2040+) | 0% | 100% | 120% of existing investment | 100% | +40-70% |
Table 2-2: Roadmap for Resolving Major Technical Bottlenecks
| Technical Field | Current Constraint | 2030 Target | 2040 Target | Solution Approach |
| Electrolyzer scaling | 100MW class limit | 500MW-class establishment | 1GW class commercialisation | Phased scale-up |
| Hydrogen storage cost | $300-500/MWh | $200-300 | $100-200 | Technology diversification・Optimal selection |
| Process flexibility | Continuous operation required | 50-100% variation in response | 20-100% variation in response | Control technology・Catalyst improvement |
| Total manufacturing cost | $600-800/ton | $400-600 | $300-500 | System integration optimisation |
Chapter 3: Hidden Bottlenecks in Transport and Logistics and Sources of Competitive Advantage
Physical Limitations and Economic Burden of Liquid Hydrogen Transport
The primary constraint of liquid hydrogen transport lies in its physical characteristics. The low density of 71kg/m³ (1/8 that of ammonia) and BOG (boil-off gas) losses of 8-12% due to maintaining extremely low temperatures of -253℃ create fatal constraints for long-distance international transport. Liquid hydrogen ship construction costs reach 3.5 times that of ammonia ships, with operating expenses also 4.2 times higher.
Total cost comparison for 15,000km long-distance transport shows liquid hydrogen at $680/t-H₂ versus ammonia at $190/t-H₂ equivalent, creating a 3.6-fold disparity. Receiving terminal construction costs also show liquid hydrogen at $1.5-2.5 billion versus ammonia receiving terminals (converted from existing LPG infrastructure) at $0.2-0.5 billion, establishing economic superiority with 1/10 the investment for new construction.
Overwhelming Superiority of Ammonia Transport and Cracking Technology Innovation
Ammonia liquefies at 8.6 atmospheres at ambient temperature, enabling high-density transport at 602kg/m³. Conversion of existing VLGCs (Very Large Gas Carriers) can be achieved with $30-50 million investments, realising BOG losses below 1%. This physical superiority creates a 5-fold cost disparity in last-mile delivery efficiency, with ammonia at $3/kg versus hydrogen at $15/kg.
The cracking technology innovation roadmap predicts phased improvements from the current 92% efficiency・$0.8/kg-H₂ to 95% efficiency・$0.4/kg-H₂ by 2028, 95% efficiency・$0.4/kg-H₂ by 2035, and 99% efficiency・$0.1/kg-H₂ by 2040. This technological progress simultaneously realises the economic viability of ammonia-route hydrogen supply and avoids stranded asset risks from existing investments.
Table 3-1: BOG Loss Rate Comparison by Transport Method (Transition Period Technology Standards)
| Transport Method | Daily Evaporation Rate | 20-day Transport | 30-day Transport | 40-day Transport | Transition Period Applicability |
| Liquid hydrogen | 0.3-0.5% | 6-10% | 9-15% | 12-20% | Limited (awaiting innovation) |
| LNG | 0.1-0.15% | 2-3% | 3-4.5% | 4-6% | Continued use |
| Ammonia | 0-0.05% | <1% | <1.5% | <2% | Optimal transition solution |
| MCH | 0.02-0.05% | <1% | <1.5% | <2% | Small-scale oriented |
Table 3-3: Cost Structure Comparison for 15,000km Transport ($/ton-H₂ equivalent)
| Cost Element | Liquid Hydrogen | MCH | Ammonia | Transition Period Competitiveness |
| Ship construction depreciation | 180 | 80 | 70 | Ammonia advantage |
| Fuel costs | 120 | 60 | 50 | Ammonia advantage |
| BOG losses | 200 | 20 | 15 | Ammonia overwhelming advantage |
| Port facility costs | 100 | 40 | 30 | Ammonia advantage |
| Insurance・Others | 80 | 35 | 25 | Ammonia advantage |
| Total transport cost | 680 | 235 | 190 | Ammonia 3.6x efficiency |
Chapter 4: Storage Technology Limitations and Technical Bottlenecks to Overcome
Technical Limitations of Liquid Hydrogen Storage and Capital Investment Burden
Liquid hydrogen storage has reached physical limits in insulation and vacuum technology for maintaining -253℃ extremely low temperatures. Daily evaporation rates of 0.1-0.3% (10-30 times that of ammonia refrigerated storage) result in unavoidable cumulative losses during long-term storage. Scale-up is also constrained by technical limitations with practical upper limits around 10,000m³, making it difficult to secure scale merit in large-capacity storage.
Due to special materials and insulation investments, storage tank construction costs are 2-3 times that of conventional tanks. Maintenance costs also require periodic renewal due to insulation performance degradation. These technical and economic constraints limit liquid hydrogen storage to short-term buffer applications, making it unsuitable for strategic reserves.
Practicality of Ammonia Storage and Large Capacity Response
Ammonia storage allows a choice between refrigerated (-33℃) and ambient pressure methods, with large-capacity refrigerated storage showing economic superiority. Material selection of carbon steel + PWHT (post-weld heat treatment) and stainless steel enables optimal design according to application and scale.
Underground storage has been demonstrated to have large-capacity, long-term storage, as shown by the US Gibbstown facility. While hydrogen is limited to salt cavern compressed hydrogen storage (UK Teesside, US Clemens, etc.), ammonia has various underground storage options available. This technological maturity gap establishes ammonia’s superiority in strategic reserves and supply-demand adjustment functions.
Table 4-1: Material Selection Guidelines by Capacity
| Capacity Range | Recommended Material | Corrosion Protection | PWHT Requirement | Expected Life | Material Cost Ratio | Overall Economics |
| 100-1,000m³ | SA516+Lining | Epoxy 5mm thick | Required for >38mm | 25 years | 1.0 | Excellent |
| 1,000-10,000m³ | SA516 Gr.70 | Cathodic protection | Required for >38mm | 20 years | 1.0 | Good |
| 10,000-40,000m³ | SA516 Gr.70+PWHT | Material corrosion resistance | Required | 25 years | 1.2 | Good |
| 40,000m³+ | SA516 Gr.70+PWHT | Material corrosion resistance | Required | 30 years | 1.3 | Standard choice |
| 40,000m³+ (Alternative) | SUS316L | Material corrosion resistance | Not required | 40 years | 3.5-5.0 | High cost |
Chapter 5: Strategic Applicability Comparison in Utilisation Technologies and Application Fields
Phased Transition Strategy in Power Generation
In the power generation sector, a phased transition from ammonia co-firing to hydrogen-dedicated firing becomes the optimal solution regarding both technological maturity and economics. While there is a performance gap between ammonia co-firing efficiency of 40-45% and hydrogen dedicated firing of 60-63%, ammonia co-firing’s technological readiness level of TRL7-8 and applicability to existing coal-fired power plants make short-term implementation realistic.
Demonstration projects by J-POWER and Mitsubishi Heavy Industries have confirmed favourable economics with 2-3% efficiency reduction at 20% co-firing and investment recovery periods of 5-8 years. Power generation ammonia demand is predicted to expand from 10 Mt in 2030 to 50 Mt in 2050, functioning as a reliable decarbonization measure during the transition period until hydrogen-dedicated firing technology matures.
Application-specific Optimisation in Transportation and Industrial Sectors
Application-specific optimisation becomes important in the transportation sector. Fuel cell vehicles (FCVs) have advantages due to hydrogen’s high energy density, but delays in hydrogen station infrastructure development constrain widespread adoption. Meanwhile, in marine fuel, ammonia is positioned as a realistic option for achieving IMO 2050 targets, and in aviation fuel, it is expected to complement the technical constraints of liquid hydrogen.
In the industrial sector, the strategic value of ammonia has been confirmed through compatibility with existing industrial bases, such as 90% CO₂ reduction through HyREX in the steel industry (cost increase of 20-30 thousand yen/ton) and stable fertiliser demand in the chemical sector (200 million tons annually). Quantitative guidelines for optimal technology selection have been established through application-specific supply-demand and cost structure analysis.
Chapter 6: International Comparison of Safety and Regulatory Environment and Social Acceptance Analysis
Risk Characteristics Comparative Evaluation and Manageability
Hydrogen safety challenges are concentrated in high diffusion characteristics, explosion risks (lower explosion limit 4%, ignition energy 0.02 mJ), and cryogenic risks of liquid hydrogen. Accident assumption ranges extend to a 1-2km radius, with liquid hydrogen facilities requiring safety measures that increase construction costs by 20-30%. In contrast, ammonia’s toxicity (TWA 25 ppm regulation) and lower explosion limit of 15% are at manageable risk levels, and safety measure costs can be suppressed by converting existing LPG facilities at ambient temperature and pressure.
While accident range assumptions for ammonia extend to 3-5km, broader than hydrogen, social acceptance can be secured through established detection, protection, and evacuation measures. Insurance premium rates show a gap between the 2-4% hydrogen and ammonia businesses at 0.5-1.5%, serving as an objective risk assessment indicator.
International Regulation and Standardisation Trends and Response Strategies
International regulatory development is progressing through IMO IGC Code and ADR/DOT regulations, with schedules set for 2025 ammonia fuel ship standards and 2030 hydrogen fuel standards. ISO/IEC standardisation is scheduled for completion in the 2025-2026 period, with formalisation of quality certification systems for green hydrogen (CertifHy) and green ammonia (GA Certification) advancing.
Parallel development of domestic laws in various countries through the High Pressure Gas Safety Act (Japan), REACH regulation (EU), and DOT49CFR (USA) is also progressing, with consistency between international standards and domestic regulations becoming a prerequisite for business development. The compatibility of safety assurance and business continuity in social implementation is achieved by developing BCP (business continuity planning), emergency response manuals, and insurance systems.
Chapter 7: Global Market Analysis, Demand Forecasting and Competitive Environment Assessment (Complete Revision)
Integrated Analysis of International Agency Forecast Data and Phased Transition Scenarios
IEA World Energy Outlook 2024 predicts hydrogen demand will expand to 130 million tons in 2030, 280 million tons in 2040, and 500 million tons in 2050. This forecast encompasses important structural changes, where the majority of hydrogen demand will be supplied through ammonia cracking at consumption sites, resulting in limited direct hydrogen trade and a fundamental change where indirect hydrogen supply via ammonia becomes the mainstream of international energy trade.
IRENA Global Energy Transformation 2024 assumes a structure where, in its forecast of 600 million tons of hydrogen demand in 2050, 200 million tons of international trade will be transported in ammonia form, with the remaining 400 million tons supplied through ammonia cracking or regional production in each region. BloombergNEF points to economic improvement through cracking technology innovation as an important factor in demand expansion, suggesting that technological progress will determine market expansion.
Table 7-1: Integrated Analysis of Hydrogen and Ammonia Demand Forecasts by International Agencies (Million Tons)
| Forecasting Agency | Hydrogen Demand 2030 | Hydrogen Demand 2050 | Ammonia Demand 2050 | International Trade Ratio |
| IEA | 130 | 500 | 600 (Hydrogen carrier 350) | 40% |
| IRENA | 140 | 600 | 680 (Hydrogen carrier 400) | 35% |
| BloombergNEF | 120 | 450 | 550 (Hydrogen carrier 300) | 45% |
| Integrated forecast | 130 | 520 | 610 (Hydrogen carrier 350) | 38% |
Three-Stage Structural Transformation of Ammonia Demand and Economic Analysis of Power Generation Sector
The ammonia demand structure will likely experience a clear three-stage structural transformation according to technological maturity and economic changes. The first stage (2025-2035) is positioned as the direct utilization expansion period, where in addition to conventional chemical raw material demand of 180 million tons, new demand of 70 million tons for power generation co-firing, 30 million tons for marine fuel, and 20 million tons for initial hydrogen carrier forms a total demand market of 300 million tons.
The second stage (2035-2045) is the transition acceleration period, where in the power generation sector, phased transition from co-firing to dedicated firing and further to hydrogen power generation causes ammonia direct utilisation demand to peak at 100 million tons. Simultaneously, hydrogen carrier demand rapidly expands, potentially forming a large-scale market of 150 million tons annually. The third stage (2045-2050) is the hydrogen society completion period, where ammonia direct utilisation demand converges to 180 million tons in chemical raw materials and 50 million tons in limited power generation and marine applications, with hydrogen carrier demand established as the main market at 350 million tons.
Table 7-2: Three-Stage Structural Transformation Scenario of Ammonia Demand (Million Tons)
| Period | Chemical Raw Materials | Power Generation | Marine Fuel | Hydrogen Carrier | Total Demand | Characteristics |
| 2030 | 180 | 70 | 30 | 20 | 300 | Direct utilisation expansion period |
| 2040 | 180 | 100 | 80 | 150 | 510 | Transition acceleration period |
| 2050 | 180 | 30 | 20 | 350 | 580 | Hydrogen society: Completion of the hydrogen society period |
Detailed Economic Analysis of Phased Transition in Power Generation Sector
The most important factor in energy transformation is the fundamental difference in cost structure between fossil fuels (natural resources) and manufactured fuels (factory products). While oil and natural gas, as finite resources, have extraction costs that rise long-term, ammonia and hydrogen, as factory products, may see manufacturing costs continuously decrease through technological innovation, scale expansion, and learning curve effects.
Technical research indicates that ammonia manufacturing costs could decrease from the current $600-1,000/ton to $400-500/ton in 2030, $250-350/ton in 2040, and $150-250/ton in 2050 through technological progress. Similarly, hydrogen manufacturing costs could be reduced from the current $6-10/kg to $1.5-2.5/kg by 2050 through technology maturation and production scale expansion.
Table 7-5: Phased Retail Electricity Price Transition Considering Technological Innovation (Cents/kWh, Grid-end Prices)
| Technology Stage | Period | Fuel Manufacturing Cost | Retail Price | Fuel Cost | Environmental Cost | Infrastructure Cost | Change from the Previous Stage | Price Variation Factors |
| Coal-fired power | ~2030 | Coal $45/t | 7.4 | 2.5 | 3.9 | 1.0 | Baseline | Rising extraction costs・Environmental regulations |
| Natural gas power | 2025-2035 | Gas $12/MMBtu | 7.1 | 4.5 | 1.8 | 0.8 | -4% | Transition period mainstay・Price stability |
| 20% ammonia co-firing | 2030-2040 | NH₃ $400/t | 7.8 | 5.0 | 1.6 | 1.2 | +10% | Early technology・Small-scale production |
| 50% ammonia co-firing | 2035-2045 | NH₃ $300/t | 8.2 | 5.8 | 1.0 | 1.4 | +16% | Technology maturation・Production expansion |
| Ammonia-dedicated firing | 2040-2050 | NH₃ $200/t | 7.9 | 5.5 | 0.6 | 1.8 | +11% | Mass production・Cost reduction |
| Hydrogen-dedicated firing | 2045-2050 | H₂ $2/kg | 6.2 | 4.2 | 0.0 | 2.0 | -13% | Technological revolution・Scale effects |
An important finding is that hydrogen power generation may technically achieve parity with or fall below fossil fuel era electricity prices after 2045. Compared to current natural gas power at 7.1 cents/kWh, hydrogen-dedicated firing power in 2050 shows the possibility of achieving 6.2 cents/kWh, potentially securing approximately 13% price superiority. This competitiveness transformation holds the possibility of achieving “Green Premium Zero” that simultaneously satisfies environmental performance and economics.
The cost burden of 8.2 cents/kWh (+16% %) during the transition period (2035-2045), ammonia co-firing period is positioned as an “investment period” for technology transition, with subsequent hydrogen society securing electricity costs equivalent to the fossil fuel era, indicating structural transformation. Environmental costs decrease progressively from 3.9 cents/kWh for coal-fired power to 0.6 cents/kWh for ammonia and 0.0 cents/kWh for hydrogen dedicated firing.
Regional Cracking Hub Strategy and Quantitative Analysis of Investment Scale
Regionally, competition for cracking hub construction may develop in major consumption areas. Construction of cracking hubs that serve as conversion points from imported ammonia to hydrogen in major energy consumption regions is being considered, with these hubs potentially serving as core functions for regional hydrogen supply.
Candidate site selection for major cracking hubs is evaluated by four factors: geographical advantage, existing energy infrastructure, industrial agglomeration, and policy support. Regions with major ports have advantages in utilising existing LNG terminals and petrochemical complexes, enabling direct supply to chemical, steel, and power generation industries. Regions that are maritime transportation hubs have geographical conditions to serve as regional supply cores and can potentially utilise existing infrastructure and related industrial agglomeration as oil refining hubs.
Table 7-4: Regional Cracking Hub Market Size Forecasts
| Regional Type | Processing Capacity (10,000 tons/year) | Investment Scale (Billion USD) | Hydrogen Cost ($/kg) | Example Features |
| Large industrial regions | 600-1,000 | 90-150 | 2.5-3.5 | Existing petrochemical complex locations |
| Asia-Pacific region | 400-800 | 60-120 | 3.0-4.0 | Major ports・Industrial cities |
| North America region | 400-700 | 60-105 | 2.0-3.0 | Petrochemical・Energy hubs |
7.5 Global Supply Chain Optimisation and Long-term Investment Strategy
Investment opportunities during the rapid expansion period of hydrogen and ammonia markets involve large-scale investments with cumulative infrastructure investment of $220 billion, fuel cell-related $280 billion, and cracking equipment $120-180 billion. Resource regions are expected to establish 4-6 million tons of annual production capacity through manufacturing and export specialisation, with investments of a $40-60 billion scale.
In the international division of labour system, structural optimisation progresses with resource countries specialising in ammonia synthesis and export, while consumption areas specialise in import, cracking, and diverse application development. This structure enables 20-40% cost reduction compared to direct hydrogen transport through ammonia-route hydrogen transport, contributing to securing the economics of global energy transformation.
Through optimising technological development and investment timing, 2035-2045 becomes the main investment concentration period. Temporary price increases due to J-curve effects are expected to be followed by a competitive advantage that will last for 20+ years. This phased transition strategy enables the compatibility of energy security and economics.
Chapter 8: Comprehensive Evaluation of Economics and Investment Profitability and Financing Strategy
LCOE and LCOH Time Series Analysis and Investment Profitability
LCOE (Levelized Cost of Electricity) analysis in the power generation sector shows a structure of hydrogen dedicated firing at 10-18 yen/kWh in 2050, ammonia dedicated firing at 20-35 yen/kWh, and ammonia co-firing at 10-15 yen/kWh, confirming the economic superiority of ammonia co-firing during the transition period. For LCOH (Levelized Cost of Hydrogen), resource country advantages of the Middle East, $1-2.5/kg and Australia, $1.5-3.5/kg (2050), are contrasted with Japan’s landed cost structure (via ammonia) of $2.1-4.9/kg.
Large project investment profitability shows gaps with the hydrogen business IRR of 8-12% and the ammonia business IRR of 12-16% for 1GW projects with investment amounts of $2-3.5 billion. Investment recovery periods also show ammonia’s short-term recovery advantage with hydrogen at 18-25 years and ammonia at 12-16 years, contributing to investment risk reduction.
Risk Factors and Financing Schemes
Through comprehensive evaluation of technology risk (equipment life, failure, performance risk), market risk (demand fluctuation, price fluctuation), and policy risk (regulatory changes, subsidy reduction), investment decisions based on risk-adjusted return on capital (RAROC) become important. Investment thresholds require long-term price guarantees of LCOH $8/kg or higher and securing capacity factors of 75% or higher as necessary conditions.
The feasibility of large project finance is enhanced through expansion of the green bond market scale, long-term low-interest financing by government financial institutions (JBIC, EIB, World Bank, etc.), and increased allocation by institutional investors (current few % → 2040 target 10%). Phased transition schemes have been established from government subsidy systems (equipment subsidies, tax incentives, price guarantees) to private investment attraction and industrial independence.
Chapter 9: Technology Innovation Roadmap and Possibilities for Disruptive Innovation
TRL Assessment and Technology Maturation Timeline
Stage-by-stage analysis using Technology Readiness Level (TRL1-9) shows that while hydrogen technology has long-term timelines with SOEC electrolysis commercialisation in 2030 and artificial photosynthesis practical application in the 2040s, ammonia technology has commercialisation of variable response, miniaturisation, and cracking technologies scheduled for 2028-2032. Particularly, cracking technology aims for technical targets of 95% efficiency・$0.3/kg-H₂ by 2028 and the plasma method 98% efficiency・$0.1/kg-H₂ by 2032, realising economic viability of ammonia-route hydrogen.
Revolutionary technology scenarios expect significant energy savings and reaction efficiency improvements through plasma synthesis technology and 300℃ high-efficiency catalysts (practical application by 2028). These technological innovations simultaneously achieve a complete departure from existing fossil fuel processes and competitiveness assurance.
International R&D Allocation and Industry-Academia Collaboration Ecosystem
National R&D investment allocation shows water hydrogen priority investment with Japan ¥120 billion (4:1 hydrogen priority), Germany €2.5 billion (3:1), China ¥20 billion (5:1), and USA $3 billion (6:1). International technology division of labor has established transparent role allocation with Japan (SOEC, cracking), Germany (infrastructure integration), Australia (large-scale demonstration), and Middle East (commercial investment).
International industry-academia collaboration through NEDO, EU Clean Hydrogen Partnership, ARENA, etc., promotes technology development acceleration and practical application risk diversification. Global ecosystem construction progresses through technology compatibility assurance via ISO/IEC standardisation (2025-2030) and international coordination of patents and intellectual property rights.
Table 9-1: Hydrogen Production Technology Maturity Gap and Ammonia Advantage Period
| Technology Classification | Current TRL | Commercialization Period | Ammonia Advantage Period | Technology Transition Conditions |
| Alkaline electrolysis | 9 | Already commercialized | 2025-2030 | Cost competitiveness |
| PEM electrolysis | 8-9 | 2024-2026 | 2025-2035 | Scale-up・Cost reduction |
| SOEC electrolysis | 6-7 | 2030-2035 | 2025-2040 | Practicality・Reliability establishment |
| Artificial photosynthesis | 2-3 | 2040-2045 | 2025-2045 | Basic technology establishment |
Chapter 10: International Trends in Policy and Institutional Environment and Strategic Implications
International Coordination of Phased Transition Policies
International coordination of phased transition policies is advancing through the EU REPowerEU policy, Japan’s Hydrogen Basic Strategy, the US Clean Hydrogen Strategy, etc. A three-stage transition of 2030 co-firing technology establishment, 2040 cracking technology maturation, and 2050 hydrogen society completion has been adopted as a standard policy framework, with policy predictability (10-15 years) promoting private investment attraction.
In addition to multilateral cooperation frameworks such as IPHE (International Partnership for Hydrogen and Fuel Cells in the Economy) and IEA, phased technology transfer programs for developing countries are being deployed through ADB and JICA. This promotes the simultaneous realisation of global technology diffusion and market expansion.
Carbon Pricing Systems and Economic Viability Assurance
International convergence of carbon pricing systems through EU-CBAM (Carbon Border Adjustment Mechanism) and similar measures is advancing economic viability assurance for clean technologies. Increases from the current EU-ETS €85/ton to €100-150/ton by 2030, and the introduction of equivalent systems in the US and Asian countries are realising competitiveness assurance for ammonia and hydrogen technologies.
Technology compatibility and quality assurance in international markets are being established through international regulation and standardisation schedules such as the IMO, and the unification of shipping standards through quality certification systems (CertifHy, Green Ammonia Certification). These institutional developments simultaneously achieve long-term investment predictability assurance and business risk reduction.
Chapter 11: Strategic Recommendations – Energy Transition Strategy Under Environmental Constraints
Strategic Justification of Three-Stage Transition Roadmap
The three-stage transition roadmap established through this analysis has been demonstrated as the optimal solution from all aspects of technology, economics, policy, and social acceptance. Stage 1 (2025-2035) ammonia-led period realises reliable foundation formation for energy transformation through low-risk investment utilising existing infrastructure and short-term CO₂ reduction effects. Stage 2 (2035-2045) transition acceleration period achieves technology choice risk diversification and investment efficiency through parallel development of both technologies, enabled by cracking technology maturation.
Stage 3 (2045-2050) of the hydrogen society completion period completes the transition to a completely zero-emission energy system through the realisation of disruptive innovations such as artificial photosynthesis. This phased approach enables the simultaneous realisation of stranded asset risk avoidance, investment recovery assurance, and technology learning promotion.
Cracking Technology Innovation and Investment Partnership Strategy
Cracking technology innovation (2028: 95% efficiency → 2040: 99% efficiency, cost $0.8/kg-H₂ → $0.1/kg-H₂) becomes the determining factor for transition strategy success. This technological progress simultaneously assures economic viability for ammonia-route hydrogen and preserves the long-term value of existing ammonia infrastructure investments.
In international investment partnerships, the construction of optimal division of labour systems through three-tier structures of resource countries (production, export), transit hubs (storage, cracking), and consumption areas (direct utilisation, hydrogen infrastructure) becomes important. As a risk diversification strategy, comprehensive responses to technology risk (demonstration technology adoption, EPC performance guarantees), market risk (long-term contracts, customer diversification), and policy risk (international coordination, institutional stabilisation) establish realistic implementation strategies for global energy transformation.
Conclusion: Practical Value and Feasibility of Phased Transition Strategy
This analysis confirms that a phased transition strategy to a hydrogen society via ammonia is feasible from all aspects of technological maturity, economics, policy environment, and social implementation. By viewing ammonia and hydrogen not as competing but as complementary relationships, effective utilisation of existing infrastructure, investment risk diversification, and technology development efficiency become possible.
Progress in cracking technology (current 90-95% efficiency → future 99% efficiency) becomes an important element supporting the practicality of the transition strategy, with ammonia-route hydrogen supply functioning as a realistic option that secures economics while avoiding stranded asset risks. The three-stage transition roadmap (2025-2035 ammonia-led, 2035-2045 transition acceleration, 2045-2050 hydrogen society completion) provides a feasible strategic framework that balances technical constraints and economic rationality.
Through this phased approach, while responding to uncertainties in technology, economics, and policy during the energy transition period, a steady path toward achieving the 2050 zero-emission target has been outlined.
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