Green Hydrogen Electrolyser Construction Underwriting in India: 2026 Capacity View

India approved the National Green Hydrogen Mission in January 2023 with an outlay of INR 19,744 crore through FY2030 and a stated production target of 5 million tonnes per annum of green hydrogen by 2030. The Strategic Interventions for Green Hydrogen Transition (SIGHT) programme allocated INR 17,490 crore of the mission outlay across two tranches: SIGHT Mode 1 for electrolyser manufacturing incentive and SIGHT Mode 2 for green hydrogen production incentive. By the start of 2026, the Solar Energy Corporation of India (SECI) had run multiple SIGHT tranches awarding production-linked support for 8.62 lakh tonnes per annum of green hydrogen capacity and electrolyser manufacturing support for 3,000 MW per annum of electrolyser stack capacity.

The project pipeline has translated into a concrete build wave. Reliance New Energy's Jamnagar green hydrogen complex, Adani New Industries' Mundra and Kutch hydrogen and ammonia complexes, NTPC's pilots at Andhra Pradesh and Madhya Pradesh, Indian Oil's Mathura and Panipat electrolyser installations, JSW Energy's allocation under SIGHT Mode 2, ACME Group's Bikaner project, and Avaada's Rajasthan complex together represent a project capex pipeline of INR 1.8 to 2.5 lakh crore through 2030. The first wave of electrolyser construction is in execution through 2026 and 2027, with commissioning targets clustered in 2027 to 2029.

For underwriters, the question is what the construction-phase exposure looks like and how the standard Erection All Risks (EAR) wording responds. Green hydrogen plants are not refineries, not power stations, and not chemical plants in the traditional Indian process plant sense. They are large-array electrolyser stack installations connected to dedicated renewable generation, with downstream compression, storage, and either ammonia synthesis or end-use distribution. The hazard profile differs from each of the established process industries in ways that the standard EAR wording, written largely around hydrocarbon process plant experience, does not always capture cleanly.

The 2026 placement experience shows three patterns. First, domestic insurer appetite for green hydrogen EAR placements grew through 2024 to 2026 as the major insurers built dedicated renewable and new-energy risk engineering teams. Second, the international reinsurance market is selective on green hydrogen exposure, with several major reinsurers either restricting line size or imposing wording conditions. Third, the SIGHT incentive linkage in the project economics requires explicit treatment in DSU sums insured, parallel to the ISM Mission interplay observed in semiconductor fab placements.

Three electrolyser technologies are being deployed in India in 2026, with materially different risk profiles that underwriters need to understand at submission stage.

Alkaline electrolysers are the technology majority for the first wave. They use a liquid potassium hydroxide electrolyte, operate at 60 to 90 degrees Celsius, run at ambient or modest pressure, and accept variable input power within a moderate turndown range. Capex per MW runs INR 5 to 7 crore for installed capacity at scale. Indian manufacturers (Reliance, Adani, Larsen and Toubro, John Cockerill India, Ohmium International) and Chinese suppliers (Longi Hydrogen, Sungrow Hydrogen, PERIC) dominate the Indian alkaline market. Risk profile is dominated by electrolyte leakage, hydrogen ingress into oxygen side, and stack degradation. Alkaline systems are mature with several decades of industrial deployment in chlor-alkali and ammonia industries, so the underwriting data set is reasonable.

Proton Exchange Membrane (PEM) electrolysers use a solid polymer membrane electrolyte, operate at 50 to 80 degrees Celsius, run at higher pressure (30 to 80 bar), and accept rapid load following from variable renewable input. Capex per MW runs INR 8 to 12 crore, materially higher than alkaline. ITM Power (UK), Siemens Energy, Cummins (Hydrogenics), Nel Hydrogen, and Plug Power are the leading PEM suppliers globally with Indian deployment partnerships. Risk profile is dominated by membrane failure (catastrophic and progressive), platinum group metal catalyst loss, and pressure boundary failure with high-pressure hydrogen release. PEM systems have less operational history at the multi-hundred MW scale being deployed in India, increasing technology risk underwriting uncertainty.

Solid Oxide Electrolysers (SOEC) operate at 700 to 850 degrees Celsius with a ceramic electrolyte and offer higher electrical efficiency particularly when integrated with industrial waste heat sources. Capex runs INR 14 to 22 crore per MW. Bloom Energy and Sunfire are the leading vendors, with limited Indian deployment in 2026 at pilot scale only. Risk profile is dominated by thermal cycling damage, ceramic stack cracking, and seal failure at high temperature. The technology is least proven at commercial scale in India and is currently being placed only with very limited insurer appetite.

The stack technology choice cascades through the EAR placement in three ways. The Total Insured Value differs by a factor of nearly three between alkaline and SOEC for the same MW installed. The peril mix differs materially, with alkaline emphasising chemical handling and electrolyte spill exposure while PEM and SOEC emphasise high-pressure hydrogen and high-temperature failure. The vendor warranty and recourse path differs, with established vendors carrying global insurance backing that supports subrogation while newer market entrants may have limited insurance behind their warranty obligations. Underwriters reviewing a green hydrogen EAR submission should require the stack technology, vendor identity, and stack module size at the first submission iteration.

The standard Indian EAR wording extends back to chemical and power plant construction practice. Green hydrogen plants present three coverage areas where the wording falls short and where 2026 placement practice has begun to evolve specific extensions.

The first is hydrogen ignition and deflagration cover during commissioning. Hydrogen has the widest flammability range of any common industrial gas (4 to 75 percent in air), the lowest ignition energy (0.02 millijoules, an order of magnitude below most hydrocarbons), and a tendency to deflagrate into detonation in unconfined releases at sufficient cloud size. Commissioning a 100 MW electrolyser array involves first-time pressurisation of hydrogen handling systems, purge sequence validation, and initial gas-on operation. The probability of small hydrogen releases during this phase is non-trivial, and the consequence of ignition is severe. Standard EAR wordings cover fire and explosion, but the deflagration-to-detonation transition characteristic of hydrogen releases produces a damage signature that loss adjusters can struggle to characterise within standard fire-and-explosion policy language. The 2026 market practice on larger placements is a specific hydrogen handling extension with an additional premium of 0.18 to 0.42 percent of hydrogen-system TIV that explicitly addresses deflagration and detonation events during commissioning.

The second is stack-level loss versus system-level loss treatment. A green hydrogen plant is built around modular electrolyser stack arrays, with each module containing 200 to 500 individual cells. A single cell failure can cascade through the module if not isolated quickly, and a module failure can affect the larger array depending on the balance-of-plant design. EAR wordings typically respond to physical loss or damage on a per-event basis with a single deductible. The question of whether a cascading stack failure constitutes one event with one deductible or multiple events with multiple deductibles is wording-dependent. The Indian market in 2026 is moving toward explicit aggregation language treating cascading stack failures within a 72-hour window as a single occurrence, with a single deductible application.

The third is water treatment and electrolyte system cover. Alkaline electrolysers require deionised water of stringent quality, supplied through a dedicated water treatment train with reverse osmosis, mixed-bed polishing, and degassing. Contamination of the feed water can damage the stack within hours. The water treatment plant is a critical balance-of-plant system whose failure can constitute either a covered EAR event (if caused by an insured peril) or a maintenance failure (which is typically excluded). The wording boundary between sudden water treatment failure and progressive contamination is contested, and 2026 placements increasingly include specific clarifying language on this point.

The DSU sum insured calibration for a green hydrogen project is structurally similar to the semiconductor fab problem but with different economic drivers. The project economics depend on three revenue and cost components: the green hydrogen sale price under offtake contracts, the SIGHT production incentive, and the differential renewable power cost relative to grid-supplied hydrogen production. Each component is affected differently by a construction delay.

The green hydrogen sale price under early Indian offtake contracts ranges from USD 3.5 to 5.5 per kilogram (delivered) depending on the offtaker, the contract structure, and the embedded incentive sharing. Industrial offtakers under the Green Hydrogen Purchase Obligation framework (envisaged for fertiliser and refining sectors) are signing contracts at the lower end of the range, while specialty industrial buyers and export offtakers pay at the upper end. For a 100 MW alkaline electrolyser array producing approximately 15,000 tonnes per annum of green hydrogen at design capacity, design-year revenue runs INR 440 to 690 crore. Annual gross margin after renewable power cost and operating expenses runs INR 130 to 280 crore depending on power cost and contract pricing.

The SIGHT Mode 2 production incentive provides INR 50 per kilogram in year one, INR 40 in year two, and INR 30 in year three for the first 4.5 lakh tonnes per annum awarded under Tranche I. For a 15,000 tonne per annum facility, this represents INR 75 crore in year one falling to INR 45 crore in year three. The incentive is disbursement-linked to actual production, with the production window starting from commercial operations date. A construction delay that pushes COD into a later year of the incentive schedule loses the earlier-year higher incentive rate, with the loss accumulating across the three-year incentive period.

The DSU sum insured should reflect both the gross margin loss and the SIGHT incentive timing loss. The standard market wording on DSU may or may not explicitly include incentive disbursement loss, and operators should verify the wording at placement. A specific endorsement may be required to capture the SIGHT timing impact, particularly because the SIGHT incentive is structured as a fiscal subsidy through SECI rather than as a regulated tariff that more conventional DSU wordings address.

The renewable power supply contract is the further wrinkle. Most Indian green hydrogen projects integrate dedicated renewable generation through either captive plants, group captive arrangements, or long-term power purchase agreements with the renewable generator. Delay in electrolyser commissioning may force the operator to either take or pay on the renewable PPA without producing hydrogen, or to absorb the cost of the renewable plant standing idle. This cost is a real consequence of construction delay that DSU wordings typically do not address explicitly. The 2026 placement practice on the larger projects is to include the renewable PPA take-or-pay exposure as a quantified DSU component, with the calculation methodology agreed with the underwriter at placement.

The DSU indemnity period is typically 12 to 24 months for these projects, with longer periods elected where the operator faces material vendor lead-time risk on stack replacement. Alkaline stack replacement lead time from order to commissioning runs 8 to 16 months for tier-one vendors, with PEM stack replacement potentially longer due to platinum group metal sourcing and specialised cell manufacturing. The deductible (waiting period) is typically 60 to 120 days, reflecting that minor EAR events should not trigger DSU. Premium rates for DSU on green hydrogen builds run 1.4 to 2.6 percent of sum insured per annum, with placement structures typically including a layered tower with primary domestic capacity and excess capacity from facultative reinsurance.

The electrolyser stack supply for the Indian market in 2026 comes from three vendor pools with materially different risk profiles. Underwriters need to understand the vendor mix at placement because vendor warranty, vendor insurance backing, and subrogation prospects differ.

Indian-manufactured alkaline stacks from Reliance, Adani New Industries, John Cockerill India, L&T, and Ohmium International are the SIGHT Mode 1 production beneficiaries. The SIGHT Mode 1 manufacturing incentive provides up to INR 4,400 per kilowatt over five years for stacks meeting localisation criteria. By 2026 the Indian manufacturing base has scaled to 3,000 to 4,500 MW per annum of nominal stack capacity, with utilisation building through the year. Indian-manufactured stacks carry vendor warranties typically running 24 to 36 months on stack performance, with limited insurance backing behind the warranty in most cases. Subrogation against an Indian stack vendor for a major stack failure is operationally feasible but commercially limited if the vendor's product liability insurance is thin.

Chinese alkaline stacks from Longi Hydrogen, Sungrow, PERIC, Cockerill Jingli, and others entered the Indian market through 2023 to 2025 with pricing 25 to 40 percent below the leading European alternatives. The Chinese alkaline industry has scaled rapidly to over 30 GW per annum of installed capacity globally, with the largest operational deployments in Inner Mongolia, Xinjiang, and Ningxia exceeding 1 GW per single project. Reliability data from these large deployments is still maturing, with public reporting limited. From an underwriting perspective, Chinese stack vendors typically carry the Chinese statutory product liability insurance with limited transnational reach. Subrogation paths through Indian courts against the Chinese parent for stack failure are theoretically available but practically slow.

European and US PEM stacks from ITM Power, Siemens, Cummins, Nel, Plug Power, and others carry substantial vendor insurance backing through global product liability programmes. ITM Power's 2024 commissioning failures on their REFHYNE II project produced large insurance claims that were absorbed by the global vendor programme, demonstrating the recourse pathway. Indian projects using these vendors have stronger subrogation prospects, though policy wording precision on the subrogation waiver and contractual liability assumption is important to preserve recovery.

Solid oxide vendors Bloom Energy and Sunfire have limited Indian deployment and corresponding limited Indian vendor liability infrastructure. Projects using SOEC in 2026 are pilot or demonstration scale, with insurance treatment generally requiring custom wording rather than market standard approaches.

The practical underwriting question is whether the project's stack vendor mix concentrates risk in vendors with limited insurance backing or distributes risk across vendors with stronger backing. A project sourcing 60 percent of stack capacity from a single Chinese vendor presents a different vendor concentration profile than a project sourcing across three Indian and two European vendors. Underwriters in 2026 are beginning to ask vendor mix questions explicitly at submission and to price differentially based on the vendor portfolio. Brokers should anticipate this question and present the vendor mix proactively, with available evidence on vendor insurance backing where it can be obtained.

Global reinsurance capacity for green hydrogen construction risk is evolving rapidly through 2024 to 2026, with most major reinsurers having either established a defined appetite or having decided to decline the segment for the present cycle.

Capacity providers active in 2026 include Munich Re (selective, with engineering review), Swiss Re (selective, with appetite tied to specific stack technologies), Hannover Re (broader appetite, particularly on alkaline), Allianz Commercial (specialty energy capacity), AIG (with renewable energy team integration), Tokio Marine HCC (engineered risk capacity), and several Lloyd's syndicates with specialty energy appetite. Capacity providers with restricted or declined appetite include several major European reinsurers that experienced loss on early European projects.

The rates on line for green hydrogen EAR placements through 2025 and into 2026 sit in the range of 0.55 to 1.45 percent of TIV for the construction phase, with DSU adding 1.4 to 2.6 percent of DSU sum insured. The wide range reflects the variation across stack technology, vendor mix, site exposure (cyclone risk, seismic zone, contractor experience), and the specific placement structure. Loss experience on early European projects, notably the ITM Power REFHYNE II issues and several Asian project commissioning failures, has hardened terms relative to 2022 to 2023 levels.

Domestic capacity through GIC Re facultative cession and the Indian non-life insurer panel can support primary layers up to approximately INR 800 to 1,400 crore signed capacity per location. The balance of larger placements is supported through international reinsurance, with GIFT City IFSC Gift Cities offering placement structure in USD, EUR, and selected other currencies that match the equipment sourcing currency. The 2026 placement practice on larger Indian green hydrogen projects routinely sees 35 to 55 percent of capacity placed through Gift City structures, with the balance through domestic and direct international channels.

Pricing structure for the renewal cycle entering 2026 shows three patterns. First, domestic insurers are competing aggressively on the smaller alkaline placements where engineering uncertainty is lower. Second, international reinsurers are pricing PEM and SOEC placements with significant premium loading versus alkaline, reflecting the technology risk uncertainty. Third, the SIGHT incentive interplay and the DSU calibration discussion are moving from placement-time negotiation to standard wording inclusion, with the leading brokers having developed semi-standard endorsement language adopted by multiple insurers.

Submission timelines for major Indian green hydrogen placements run 20 to 32 weeks from initial submission to bound cover. Operators planning placements should engage their broker no later than 9 months before construction start to allow adequate submission preparation, market engagement, and wording negotiation. Brokers should expect underwriters to request the project HAZOP, the EPC contractor track record on hydrogen projects, the stack vendor reference list, and the project lender requirements (which often drive specific coverage features). The placement cycle is materially longer than for comparable conventional power plant placements due to the engineering due diligence requirement.

Underwriter expectations on submission quality for green hydrogen placements have escalated through 2024 to 2026. The minimum submission package now expected by lead Indian insurers and international reinsurers includes the items listed below.

For the construction phase EAR placement, the submission should include the project capex breakdown by tranche, the construction schedule with critical path identified, the EPC contract structure and contractor identity, the stack vendor identity with stack technology and module size, the balance-of-plant equipment list with major equipment vendor identity, the site location with soil report and hazard assessment, the project HAZOP outputs, the EPC contractor's safety case for hydrogen handling, the lender financing structure with insurance covenants extracted, and the project's incentive structure (SIGHT, state government, customs duty exemption) with disbursement schedule.

For the DSU extension, the submission should include the offtake contract structure with pricing and offtaker identity, the SIGHT incentive schedule with year-by-year amounts, the renewable power supply arrangement with PPA structure, the production ramp-up profile from COD through design capacity, the customer qualification requirements where applicable, and the management commentary on commissioning risk assessment.

For the operational programme transition, the submission should include the planned transition timeline from EAR to operational cover, the operational programme broker identity (where different from the construction broker), and the operational policy structure proposed by the operational broker.

Engineering surveys at green hydrogen construction sites are run by specialist surveyors with hydrogen process experience. The cost per site survey runs INR 18 to 65 lakh depending on the project scale and the construction phase. Survey content covers the cleanroom or equipment installation environment, the gas detection and emergency shutdown systems, the contractor safety management on site, the materials handling and high-value equipment storage, the security and access control on the construction site, and the commissioning readiness assessment as the project approaches first gas. Insurer engineering teams in 2026 increasingly include either dedicated hydrogen specialists (in some cases recruited from the European hydrogen demonstration projects) or external consultants engaged for specific surveys.

The 2026 trend toward more rigorous engineering survey requirements is partly driven by reinsurance treaty terms. Several international reinsurers participating in Indian green hydrogen placements explicitly require independent engineering survey as a treaty condition, with the survey report forming part of the underwriting file. Project operators that resist or delay engineering survey access typically secure inferior placement terms and longer placement cycles. Operators that proactively schedule and facilitate survey access typically place faster and at better terms.

The broker's role in submission preparation has expanded significantly. Specialist construction and renewable energy brokers at Marsh India, Aon India, WTW India, Howden India, and several boutique broker houses have built dedicated green hydrogen capability through 2024 to 2026. The broker's value in the placement is concentrated in submission packaging, engineering survey coordination, wording negotiation, and reinsurance market engagement rather than the simple market sounding that earlier renewable placements relied on. Operators selecting brokers for green hydrogen placements should evaluate the broker's specific hydrogen capability and track record, not just their renewable energy or construction credentials.