Regional spotlight: Hydrogen & e-fuels in India — what's different and why it matters

India announced a $2.3 billion National Green Hydrogen Mission in 2023, targeting 5 million tonnes of annual green hydrogen production capacity by 2030, yet as of early 2026 the country produces fewer than 50,000 tonnes of green hydrogen per year across all operational projects combined (Ministry of New and Renewable Energy, 2025). That gap between ambition and deployment defines the opportunity landscape. India is simultaneously the world's fourth-largest hydrogen consumer (approximately 6.7 million tonnes per year, almost entirely grey hydrogen from natural gas reforming), the world's fourth-largest refining capacity holder, and home to one of the lowest-cost renewable energy markets on the planet with solar tariffs consistently below $0.03 per kWh. For teams evaluating hydrogen and e-fuel strategies globally, India presents a structurally distinct market where the interplay of abundant cheap renewables, massive existing hydrogen demand, limited natural gas reserves, and an evolving policy framework creates dynamics that do not map neatly onto European or North American playbooks.

Why It Matters

India's hydrogen economy diverges from Western markets in ways that fundamentally alter technology selection, business model design, and competitive positioning.

First, India is a hydrogen demand market before it is a hydrogen export market. Unlike Australia, Chile, or the Middle East, which frame hydrogen primarily as an export commodity, India's 6.7 million tonnes of annual consumption in fertilizer production (approximately 4.2 million tonnes), petroleum refining (approximately 1.8 million tonnes), and chemicals/methanol synthesis (approximately 0.7 million tonnes) provides a domestic off-take base that does not require new demand creation (IEA, 2025). Decarbonizing this existing grey hydrogen consumption through green hydrogen substitution represents the first addressable market segment, one with established logistics, pricing benchmarks, and buyer relationships.

Second, India's renewable energy cost advantage reshapes electrolyzer economics. Solar tariffs of $0.025 to $0.030 per kWh and wind tariffs of $0.035 to $0.040 per kWh, combined with high solar irradiance (1,600 to 2,200 kWh/m2/year across most of the country), position India to achieve green hydrogen production costs of $2.00 to $2.50 per kg by 2028, approaching cost parity with grey hydrogen at Indian natural gas prices (TERI, 2025). By comparison, European green hydrogen costs currently range from $4.50 to $7.00 per kg, and US costs range from $3.00 to $5.00 per kg before subsidies.

Third, India lacks the generous production subsidies available in competitor markets. The US Inflation Reduction Act provides up to $3.00 per kg in production tax credits under Section 45V. The EU's hydrogen bank auctions have awarded contracts at EUR 0.37 to 4.50 per kg in subsidy support. India's Strategic Interventions for Green Hydrogen Transition (SIGHT) program offers incentives of INR 40 to 50 ($0.48 to $0.60) per kg for electrolyzer manufacturing and INR 10 to 20 ($0.12 to $0.24) per kg for green hydrogen production, significantly lower than Western equivalents. Indian projects must therefore compete on cost fundamentals rather than subsidy capture.

Key Concepts

India's Electrolyzer Manufacturing Ambitions

India's National Green Hydrogen Mission includes a target of 15 GW of domestic electrolyzer manufacturing capacity by 2030. The SIGHT program has allocated INR 4,440 crore ($533 million) in incentives for electrolyzer manufacturing under a production-linked incentive (PLI) scheme. As of early 2026, the Ministry of New and Renewable Energy has awarded incentive tranches to manufacturers including Larsen & Toubro, Greenko, Reliance Industries, and Adani New Industries, covering approximately 8 GW of planned manufacturing capacity (MNRE, 2025).

Indian electrolyzer manufacturers are primarily targeting alkaline water electrolysis (AWE) technology, which uses less expensive materials than proton exchange membrane (PEM) systems and aligns with India's existing manufacturing strengths in heavy electrical equipment. L&T's electrolyzer facility in Hazira, Gujarat, began commercial production in 2025 with an initial capacity of 1 GW per year, producing alkaline stacks at reported costs 25 to 35% below European and Chinese equivalents. However, PEM and anion exchange membrane (AEM) technologies remain largely dependent on imports, and India's electrolyzer industry currently lacks the scale to produce advanced catalyst materials (iridium and platinum for PEM) domestically.

Ammonia and Methanol as Hydrogen Derivatives

India's e-fuels strategy is inseparable from its fertilizer security concerns. The country imports approximately 9 million tonnes of urea annually at a cost of $3 to $4 billion, and green ammonia produced from domestic green hydrogen could simultaneously decarbonize fertilizer production and reduce import dependence. The economics are compelling at projected 2028 green hydrogen costs: green ammonia at $450 to $550 per tonne approaches cost parity with imported grey ammonia at $350 to $450 per tonne when factoring in supply chain risk premiums and shipping costs (ICRA, 2025).

Green methanol represents a second derivative pathway with strong Indian demand signals. India's methanol blending program targets 15% methanol blending in gasoline by 2030, requiring approximately 12 million tonnes of methanol annually. While most near-term supply will come from coal-to-methanol (leveraging domestic coal reserves), green methanol from captured CO2 and green hydrogen is positioned as the medium-term pathway as carbon constraints tighten.

Renewable Energy Integration Challenges

India's green hydrogen production faces grid integration complexities distinct from markets with more mature renewable energy curtailment. Indian states with the best renewable resources (Rajasthan, Gujarat, Tamil Nadu, Karnataka) also experience grid congestion that limits power evacuation. Dedicated renewable energy capacity for hydrogen production (the "additionality" principle) avoids grid competition but requires overbuilding to compensate for solar capacity factors of 20 to 25% and wind capacity factors of 28 to 35%.

Round-the-clock renewable energy supply for continuous electrolyzer operation requires hybrid solar-wind configurations with battery storage, increasing the effective cost of electricity delivered to the electrolyzer by 30 to 50% compared to daytime-only solar operation. This creates a design trade-off: lower electrolyzer utilization with cheap solar-only power versus higher utilization with more expensive hybrid supply. Indian project developers are increasingly favoring oversized solar with limited storage, accepting 40 to 55% electrolyzer capacity factors to minimize delivered energy costs.

What's Working

India's largest integrated green hydrogen project, developed by Acme Group in Bikaner, Rajasthan, began commissioning its first phase in late 2025. The project pairs 1.5 GW of dedicated solar capacity with 0.5 GW of alkaline electrolyzers to produce 66,000 tonnes of green ammonia per year for export via the Mundra port in Gujarat. Acme has secured off-take agreements with European buyers at prices indexed to the Rotterdam ammonia benchmark, demonstrating that Indian production can access premium export markets. The project's total installed cost of approximately $1.8 billion ($3,600 per tonne of annual ammonia capacity) is 20 to 30% below comparable projects announced in Australia and the Middle East (Acme Group, 2025).

Indian Oil Corporation (IOC) has integrated a 15 MW PEM electrolyzer at its Mathura refinery in Uttar Pradesh, producing approximately 7 tonnes of green hydrogen per day for direct use in hydrocracking and desulfurization units. The project, operational since mid-2025, replaces grey hydrogen from a steam methane reformer (SMR) unit without requiring modifications to downstream refinery processes. IOC reports delivered green hydrogen costs of $3.80 per kg against a grey hydrogen internal transfer price of $2.50 per kg, leaving a green premium of approximately $1.30 per kg that IOC absorbs as part of its sustainability commitments. The project validates the technical integration pathway but underscores the cost gap that remains without stronger policy support.

NTPC, India's largest power generation company, is developing a 4.75 GW renewable energy hub in Rajasthan specifically designed for green hydrogen and green ammonia production. The first 50 MW electrolyzer phase became operational in 2025, with plans to scale to 500 MW by 2028. NTPC's existing relationship with state electricity boards and its balance sheet strength give it advantages in securing renewable energy capacity and financing large-scale projects that newer entrants struggle to replicate.

Greenko Group's integrated renewable energy storage project in Andhra Pradesh combines 5.23 GW of solar and wind capacity with 1.68 GW of pumped hydro storage to deliver round-the-clock renewable power. While primarily designed for grid supply, Greenko has allocated 500 MW for green hydrogen production, leveraging the pumped hydro to achieve 85%+ electrolyzer capacity factors, a significantly higher utilization rate than solar-only configurations and a potential model for cost-competitive continuous hydrogen production.

What's Not Working

India's green hydrogen pipeline faces execution challenges that temper the optimism of policy announcements and memoranda of understanding.

Project financing remains the primary bottleneck. Indian banks and non-banking financial companies have limited experience underwriting hydrogen project risks, and the absence of standardized off-take contract structures (bankable long-term purchase agreements) makes debt financing difficult. Most operational projects rely on corporate balance sheet funding or development finance institution support rather than commercial project finance. The gap between announced project capacity (over 5 million tonnes per year by 2030) and projects that have reached financial close (fewer than 200,000 tonnes per year) illustrates the financing challenge (BloombergNEF, 2025).

Water availability is a constraint that receives insufficient attention in India's hydrogen planning. Alkaline electrolysis requires approximately 9 litres of purified water per kg of hydrogen produced. At India's 2030 production target of 5 million tonnes per year, this translates to approximately 45 billion litres of water annually. Many of India's best solar resource regions (Rajasthan, Gujarat's Kutch district) are water-stressed, and competition with agricultural and municipal water needs creates permitting and social license risks that are more acute than in less water-constrained markets. Seawater desalination adds $0.10 to $0.15 per kg to hydrogen costs and introduces additional project complexity.

Transmission infrastructure connecting renewable energy zones to industrial hydrogen demand centers remains inadequate. Rajasthan's solar resources are 800 to 1,200 km from fertilizer and refining clusters in eastern and southern India. Dedicated hydrogen pipelines do not exist, and trucking compressed or liquefied hydrogen over these distances costs $1.50 to $3.00 per kg, eroding India's production cost advantage. The proposed National Hydrogen Pipeline Network, announced in the 2025 Union Budget, has a target completion date of 2032 but no detailed engineering or routing studies have been published.

Electrolyzer performance in Indian operating conditions requires further validation. Ambient temperatures exceeding 45 degrees Celsius in peak summer months, combined with dust loading and humidity variations, affect stack efficiency and degradation rates in ways not fully captured by manufacturer warranties based on European operating data. Early projects report stack degradation rates 10 to 20% higher than nameplate specifications, potentially increasing levelized hydrogen costs by $0.15 to $0.30 per kg over the project lifetime.

Key Players

Established companies: Reliance Industries (multi-GW green hydrogen and electrolyzer manufacturing at Jamnagar), Adani New Industries (green hydrogen and ammonia production integrated with renewable energy), Indian Oil Corporation (refinery-integrated electrolyzers at multiple sites), NTPC (large-scale renewable-to-hydrogen projects in Rajasthan), Larsen & Toubro (electrolyzer manufacturing and EPC for hydrogen projects), GAIL India (hydrogen blending in natural gas pipelines and distribution infrastructure)

Startups and technology providers: Acme Group (integrated green ammonia production and export), Greenko Group (round-the-clock renewable energy for hydrogen production), Ohmium International (PEM electrolyzer manufacturing in Bengaluru for domestic and export markets), HygenCo (distributed green hydrogen supply for industrial clusters), Svante Technologies India (CO2 capture technology for e-fuel production)

Investors and development finance: Asian Development Bank (concessional financing for green hydrogen projects), World Bank (technical assistance for hydrogen policy and regulation), Japan Bank for International Cooperation (bilateral financing under Asia Energy Transition Initiative), IREDA (Indian Renewable Energy Development Agency, domestic project lending), Breakthrough Energy Ventures (early-stage hydrogen technology investments)

Action Checklist

• Map India's existing grey hydrogen consumption sites (fertilizer plants, refineries) as priority conversion targets with established off-take demand and logistics
• Evaluate electrolyzer technology selection for Indian conditions, prioritizing alkaline systems with demonstrated performance in high-temperature environments
• Assess water sourcing strategies early in project development, particularly for sites in Rajasthan and Gujarat where water-stress risks require desalination or wastewater recycling
• Structure off-take agreements with credit-worthy counterparties (IOC, BPCL, HPCL, fertilizer cooperatives) to enable project financing
• Monitor SIGHT program incentive disbursement timelines and eligibility criteria updates from the Ministry of New and Renewable Energy
• Explore green ammonia export opportunities to Europe and Japan where buyer willingness to pay green premiums of $100 to $200 per tonne above grey ammonia exists
• Engage with state governments in Gujarat, Rajasthan, and Andhra Pradesh that have announced state-level hydrogen policies with additional land and infrastructure incentives
• Track the National Hydrogen Pipeline Network development for long-term infrastructure planning and co-location strategy

FAQ

Q: When will green hydrogen reach cost parity with grey hydrogen in India? A: At current Indian natural gas prices of $10 to $12 per MMBtu (reflecting import dependence on LNG), grey hydrogen costs approximately $2.20 to $2.80 per kg. Green hydrogen from dedicated solar in high-irradiance regions is projected to reach $2.00 to $2.50 per kg by 2028, achieving parity without subsidies. However, this comparison assumes daytime-only electrolyzer operation at 20 to 25% capacity factor. For applications requiring continuous hydrogen supply, the cost of round-the-clock renewable energy with storage raises green hydrogen costs to $2.80 to $3.50 per kg, pushing parity to 2030 or beyond. The crossover point varies significantly by location, technology choice, and the buyer's willingness to accept intermittent supply.

Q: How does India's hydrogen strategy compare to the Middle East and Australia? A: India's structural advantage is domestic demand. Saudi Arabia, the UAE, Oman, and Australia are building hydrogen production primarily for export, requiring complex shipping logistics and international off-take agreements that add $1.00 to $2.00 per kg in delivered cost. India's 6.7 million tonnes of existing annual hydrogen consumption provides a captive domestic market that reduces off-take risk and avoids export infrastructure costs. India's disadvantage is infrastructure maturity: the Middle East has established port and petrochemical logistics, and Australia has proven natural gas pipeline networks adaptable for hydrogen. India's lower labor and EPC costs offset some of this infrastructure gap, but project execution timelines in India tend to run 12 to 18 months longer than in Gulf states due to permitting complexity and land acquisition processes.

Q: What role will e-fuels play in India's energy transition? A: E-fuels, synthetic hydrocarbons produced from green hydrogen and captured CO2, are not expected to play a significant role in India's energy mix before 2032. The current economics of e-methanol ($800 to $1,200 per tonne vs. $300 to $400 for fossil methanol) and e-kerosene ($2,500 to $3,500 per tonne vs. $800 to $1,000 for conventional jet fuel) are prohibitive without mandates or substantial carbon pricing. India's near-term e-fuel opportunity is limited to green methanol for the shipping sector (where IMO regulations create demand) and niche sustainable aviation fuel (SAF) volumes driven by international airline requirements. The government's methanol blending target of 15% by 2030 could accelerate demand, but coal-to-methanol is likely to capture most of this volume initially due to cost advantages.

Q: Which Indian states offer the most favorable conditions for hydrogen projects? A: Gujarat leads with a dedicated State Hydrogen Policy (2023), port infrastructure at Mundra and Kandla for ammonia export, proximity to refining and fertilizer demand, and strong solar resources. Rajasthan offers the lowest solar energy costs in India and vast available land, but faces water scarcity and transmission constraints. Andhra Pradesh combines good solar and wind resources with port access at Krishnapatnam and Machilipatnam. Tamil Nadu has strong wind resources and an established industrial base but higher land costs. Odisha is emerging as a hub for hydrogen use in steel decarbonization, with Tata Steel, JSW Steel, and JSPL all evaluating green hydrogen integration at their eastern India facilities.

Sources

• Ministry of New and Renewable Energy. (2025). National Green Hydrogen Mission: Annual Progress Report 2024-25. New Delhi: Government of India.
• International Energy Agency. (2025). India Energy Outlook 2025: Hydrogen Chapter. Paris: IEA.
• The Energy and Resources Institute (TERI). (2025). Green Hydrogen Cost Trajectory in India: Scenarios to 2030. New Delhi: TERI.
• ICRA Limited. (2025). Green Ammonia in India: Cost Competitiveness and Market Potential. Mumbai: ICRA Research.
• BloombergNEF. (2025). India Hydrogen Market Outlook: Project Pipeline and Financing Analysis. London: BloombergNEF.
• Acme Group. (2025). Bikaner Green Hydrogen-Ammonia Project: Phase 1 Commissioning Report. Gurugram: Acme Group.
• NITI Aayog. (2025). Harnessing Green Hydrogen: Opportunities for Deep Decarbonisation in India. New Delhi: National Institution for Transforming India.