Green Hydrogen Production Insurance in India: Electrolyser Risk, Storage Hazards, and Transportation Liability

The National Green Hydrogen Mission, approved by the Union Cabinet in January 2023 with an outlay of INR 19,744 crore, sets a 2030 target of 5 million metric tonnes of annual green hydrogen production and 125 GW of associated renewable capacity. The Strategic Interventions for Green Hydrogen Transition (SIGHT) programme funds both electrolyser manufacturing and green hydrogen production through reverse auctions run by SECI. Reliance, Adani New Industries, L&T, NTPC, Indian Oil, GAIL and ACME have all announced hydrogen projects, with declared capex commitments crossing INR 4 lakh crore over the decade. Dedicated hydrogen hubs are being developed at Kakinada in Andhra Pradesh, Paradip in Odisha, Thoothukudi in Tamil Nadu, Gopalpur, Mangalore and Jamnagar, with project sizes typically in the INR 500 to 5,000 crore range per phase.

From an insurance standpoint, green hydrogen in India is an unfamiliar risk. The SFSP and Industrial All Risks (IAR) wordings that Indian insurers rely on were built around conventional process industries. No domestic insurer has a deep loss book for large electrolyser plants, 700 bar gaseous storage, cryogenic liquid hydrogen tanks or LOHC (liquid organic hydrogen carrier) conversion units. Loss data sits with Munich Re, Swiss Re, Hannover Re and a handful of Lloyd's syndicates that have underwritten European and North American hydrogen projects over the past decade. Indian insurers have capacity but limited internal expertise, so the early hydrogen hubs are being placed on a fronted basis with dominant reinsurance support and strict warranty regimes.

The gap matters because green hydrogen combines the familiar risks of a chemical plant (pressure vessels, rotating machinery, flammable inventory) with unfamiliar physics. Hydrogen flames are near-invisible in daylight, the molecule diffuses through materials that would contain natural gas, and stored energy densities are extreme. Getting the policy structure right at construction stage, rather than retrofitting coverage after a loss, is the difference between a financeable project and an uninsurable one.

Three electrolyser technologies dominate Indian project pipelines: alkaline (AEL), proton exchange membrane (PEM) and solid oxide (SOEC). Each presents a distinct loss profile that underwriters must map against manufacturer data and warranty terms.

Alkaline electrolysers, supplied by players such as Thyssenkrupp Nucera, John Cockerill, Ohmium (India manufacturing) and Reliance's in-house stack, run a 25 to 30% potassium hydroxide electrolyte at 70 to 90 degrees Celsius and 1 to 30 bar. The dominant perils are KOH leakage causing severe corrosion, diaphragm rupture leading to cross-contamination of hydrogen and oxygen, and gas crossover events that can produce a flammable mix inside the cell. AEL stacks have a typical cell lifetime of 60,000 to 90,000 hours, and thermal cycling during intermittent renewable operation accelerates gasket and bipolar plate degradation.

PEM electrolysers, from suppliers like Nel Hydrogen, Cummins Accelera, Siemens Energy and ITM Power, operate at higher current densities and pressures up to 30 bar, with Nafion-class membranes sensitive to iron, chromium and calcium contamination from feed water. The catastrophic loss mode is thermal runaway in the stack: a localised hotspot pierces the membrane, mixes hydrogen and oxygen across the MEA and ignites, typically destroying the stack and adjacent balance of plant. Stack cost for a 20 MW PEM module runs INR 60 to 100 crore, and Indian insurers must understand that a single thermal runaway can write off the stack even if the building is untouched.

Solid oxide units from Bloom Energy, Topsoe and Ceres operate at 700 to 850 degrees Celsius and face ceramic fracture from thermal shock, interconnect oxidation and chromium poisoning. SOEC is still early in commercial deployment in India, and insurers should expect higher maintenance warranties, longer prototype exclusions and conservative sub-limits on stack damage until more run-time data accumulates.

The balance of plant (BoP) exposure is often larger than the stack itself. Rectifiers and power electronics (typically 20 to 25% of capex) are vulnerable to renewable-grid harmonics. Deionisation and reverse osmosis trains, hydrogen dryers, deoxo units and compressors from Atlas Copco, Burckhardt, Howden and Ariel each have their own MBD profile. A realistic project wording should schedule stack, BoP and storage as separate sub-items with distinct sub-limits and deductibles.

Storage is where hydrogen's energy density turns into catastrophic potential. Indian projects are deploying four storage modes, each with a different insurance problem.

Compressed gaseous hydrogen at 350 bar in Type I steel cylinders and tube trailers is the workhorse for on-site buffering and captive road transport. The principal perils are hydrogen embrittlement of ferritic steels, stress corrosion cracking at weld heat-affected zones, and fatigue from pressure cycling. PESO-approved cylinder retesting under SMPV(U) 2016 is mandatory every five years, and insurers should condition coverage on evidence of the latest hydrostatic test and ultrasonic inspection reports.

700 bar Type III and Type IV composite cylinders, used primarily for mobility refuelling at HRS (hydrogen refuelling stations), carry lower embrittlement risk because the inner liner is aluminium or polymer, but they concentrate enormous stored energy in a small volume. A rupture of a single 700 bar automotive cylinder releases energy comparable to 5 to 10 kg of TNT equivalent. Insurers underwriting HRS must verify thermally activated pressure relief devices (TPRDs), bollard protection and blast radius analysis under IS 16061 and SAE J2601.

Liquid hydrogen storage at minus 253 degrees Celsius is being deployed for export-oriented projects at Kakinada and Thoothukudi. The perils include loss of vacuum in double-walled tanks leading to rapid boil-off and potential over-pressure, BLEVE (boiling liquid expanding vapour explosion) if a tank is engulfed in fire, and cold embrittlement of carbon steel piping from LH2 spills. Conversion units that liquefy gaseous hydrogen consume 10 to 13 kWh per kg of hydrogen and contain large helium refrigeration trains whose breakdown can idle the entire storage complex.

LOHC systems using dibenzyltoluene or methylcyclohexane convert hydrogen into a stable liquid at ambient pressure for shipping. The risk profile here looks more like a chemical plant: hydrogenation and dehydrogenation reactors run at 150 to 350 degrees Celsius with precious-metal catalysts, and the organic carrier itself is classified as a combustible liquid under Indian regulations. Project policies should treat LOHC plants with process industry wordings, including a dedicated reactor sub-limit and scheduled catalyst loss cover.

Across all modes, hydrogen's near-invisible pale-blue flame, its flammability range of 4 to 75% in air, and its very low ignition energy of 0.02 mJ (an order of magnitude below natural gas) mean that standard optical flame detectors and gas detection layouts designed for hydrocarbon plants are insufficient. Insurers should require hydrogen-specific UV and multi-wavelength IR flame detectors, ultrasonic leak detectors and ventilation rates calibrated for hydrogen diffusion, with surveyor sign-off before first fill.

Green hydrogen in India sits across several regulators, and an insurable project must document compliance with each. The Petroleum and Explosives Safety Organisation (PESO), under the Department for Promotion of Industry and Internal Trade, licenses hydrogen storage and handling under the Gas Cylinders Rules 2016 and the Static and Mobile Pressure Vessels (Unfired) Rules 2016. PESO Form A licenses are required for on-site storage above defined thresholds, and Form G licenses cover mobile pressure vessels used for transport. Any policy schedule must list the relevant PESO license numbers and validity dates as a condition precedent, with automatic suspension on license lapse.

The Factories Act 1948 and the Manufacture, Storage and Import of Hazardous Chemical Rules (MSIHC) 1989 apply to hydrogen production sites, requiring major accident hazard (MAH) classification, on-site and off-site emergency plans, and consent to operate from the State Pollution Control Board. The Public Liability Insurance Act 1991 triggers at much lower inventory thresholds than most operators realise, and statutory PLI cover is the minimum, not the ceiling, for third party exposure around hydrogen plants.

The Petroleum and Natural Gas Regulatory Board (PNGRB) is drafting regulations for hydrogen blending in city gas networks and for dedicated hydrogen pipelines. The Bureau of Energy Efficiency is developing efficiency standards for electrolysers under the National Green Hydrogen Mission, and BIS standards IS 16061, IS 16635 and IS/ISO 19880 govern HRS design, hydrogen quality and dispensing safety. Insurance policy schedules should require compliance with the latest BIS edition and treat material deviation as a warranty breach.

The Central Electricity Authority (CEA) regulations on electrical safety and grid connection apply to the large rectifier and transformer installations at electrolyser plants, and CEA-notified electrical inspectors sign off on commissioning. Project insurers should align erection all risks (EAR) policy conditions with CEA commissioning protocols, so that testing and trial runs fall inside the EAR period rather than in the gap between EAR expiry and operational policy inception.

A typical green hydrogen project in the INR 500 to 5,000 crore band needs a layered programme that tracks the project through construction, commissioning and operation.

During construction, erection all risks (EAR) or contractors all risks (CAR) policies cover the physical fabrication and installation of electrolysers, compressors, storage and balance of plant. Indian EAR wordings follow the market agreed text but need specific amendments for hydrogen: extension of testing and commissioning cover to the full trial run period (typically 12 to 16 weeks rather than the standard 4), explicit inclusion of hot testing with hydrogen, and prototype cover for first-of-a-kind electrolyser stacks where the Indian manufacturing facility has fewer than three reference installations.

Delay in start-up (DSU) or advanced loss of profits (ALOP) cover protects the project's financial model against construction-phase losses that push commissioning past the scheduled commercial operation date. For hydrogen projects financed against PPAs or offtake agreements, DSU sums insured should reflect gross profit over a 24 month indemnity period, not the more common 12 month assumption, because replacement lead times for custom electrolyser stacks and hydrogen-grade compressors can run 12 to 18 months from order.

Once operational, Industrial All Risks or fire plus LOP provides the material damage and business interruption backbone, paired with Machinery Breakdown (MBD) and Machinery Loss of Profits (MLOP) for rotating equipment and electrolyser stacks. The MBD policy must explicitly name stack internal damage as an insured peril, because standard MBD wordings designed for rotating machinery can be read to exclude electrochemical cell damage. MLOP indemnity periods of 18 to 24 months are appropriate given stack replacement timelines.

Public liability under the PLI Act 1991 is statutory, but meaningful third party protection around a hydrogen hub requires commercial PLI or broad form general liability with limits of INR 100 to 500 crore depending on plant proximity to populated areas. Product liability is often overlooked: hydrogen sold to steel, refinery, fertiliser or mobility buyers carries explicit product specifications (purity above 99.97% for fuel cell use under ISO 14687 Grade D), and a shipment that causes damage to a buyer's fuel cell stack or refinery catalyst can generate claims running into tens of crore. Product liability wordings must include financial loss and product recall components, not only bodily injury and property damage.

Marine cargo and inland transit cover hydrogen tube trailers, cryogenic tankers and LOHC shipments, with specific clauses addressing venting losses, boil-off during demurrage and contamination from prior cargo. Environmental impairment liability (EIL) is increasingly demanded by lenders for hydrogen sites that handle KOH, catalysts and LOHC carrier oils, and standard CGL pollution exclusions leave this exposure uncovered without a dedicated EIL policy.

Moving hydrogen from production site to end user is often the riskiest segment of the value chain, and the insurance structure must follow the physical mode.

Dedicated hydrogen pipelines are being planned between Kandla and Gorakhpur, between Jamnagar and Mundra, and inside large refining and fertiliser complexes at Paradip, Mathura and Panipat. Pipeline insurance under Indian market wordings covers sudden and accidental rupture, third party damage and business interruption from loss of throughput. Hydrogen-specific amendments are needed: coverage for hydrogen embrittlement of pipeline steel (which is typically excluded as a gradually operating cause), cover for compressor station breakdown, and explicit treatment of right-of-way intrusion risks in densely cultivated corridors. PNGRB authorisation and compliance with T4S (technical standards and specifications) are policy conditions precedent.

Road tankers moving compressed hydrogen in tube trailers or liquid hydrogen in cryogenic trailers are governed by CMV Rules and PESO mobile pressure vessel licenses. Carriage of hazardous goods under Motor Vehicles Act provisions requires a transport emergency card (TREMCARD), driver training and prescribed route compliance. Motor own damage and motor third party policies on these vehicles need endorsements specifying hazardous cargo, and transit cover should explicitly schedule hydrogen inventory value. A single 250 kg tube trailer running at 350 bar carries hydrogen worth INR 1 to 2 lakh at current green hydrogen prices, but a catastrophic rupture in a populated area generates third party liability exposure of INR 50 to 100 crore or more.

Maritime export of hydrogen as ammonia, methanol or LOHC from Kakinada, Paradip and Gopalpur is developing rapidly, with Japanese and Korean offtakers anchoring early projects. Marine cargo cover for hydrogen derivatives follows the standard ICC A clauses, but insurers underwriting ammonia shipments should be alert to the ISGOTT-equivalent handling protocols emerging under IMO guidance, and the toxicity exposure of large-scale ammonia bunkering. Port insurance at these hubs needs to account for hydrogen liquefaction or ammonia synthesis loops on-site, which change the port's accumulated peril profile significantly from conventional bulk or container terminals.

Indian insurers have the balance sheet but not yet the track record to lead large hydrogen placements on net retention. New India Assurance, Oriental Insurance, United India, National Insurance and the large private carriers ICICI Lombard, Tata AIG, Bajaj Allianz, HDFC ERGO and SBI General are fronting the early hydrogen projects with treaty and facultative reinsurance support from Munich Re, Swiss Re, Hannover Re, SCOR and select Lloyd's syndicates. GIC Re typically takes mandatory cession and additional voluntary shares where the risk matches its appetite.

Typical retention for an Indian lead on a INR 2,000 crore hydrogen project sits in the 2 to 5% band, with the balance shared across domestic co-insurers and international reinsurers on a proportional or facultative excess of loss basis. Premium rates for operational all risks on hydrogen plants are currently running at 0.15 to 0.35% of declared value depending on technology maturity, loss prevention investment and PESO compliance history, which is materially above rates for mature refining or petrochemical units of comparable size.

Underwriter readiness varies sharply. Engineering underwriting teams familiar with thermal power, wind and solar can transition into hydrogen with upskilling, but they need structured exposure to stack failure modes, PESO compliance documentation and loss prevention standards from FM Global, HSB and the Hydrogen Safety Panel. IRDAI has not yet issued hydrogen-specific guidance, and there is a strong case for the regulator to publish a technical note on minimum survey standards, recommended indemnity periods and mandatory policy conditions for hydrogen projects, similar to the approach taken for wind and solar in the past decade.

For sponsors and lenders, the practical implication is that hydrogen insurance cannot be a last-mile procurement exercise. Insurance structuring must begin at FEED (front end engineering design) stage, with an insurance consultant reviewing layout, segregation distances, detection and ESD philosophy before equipment orders are placed. Retrofitting insurability into a completed plant is significantly more expensive than designing for it, and in some cases will not be possible within the risk appetite of the domestic market. The projects that secure bankable insurance programmes in this decade will be those where sponsors treat insurance as a design input, not as a procurement step after commissioning.