India’s green hydrogen initiatives are being driven by the National Green Hydrogen Mission, launched in January 2023. This mission seeks to establish India as a global leader in the production, consumption, and export of green hydrogen and its derivatives. Key policy measures have been introduced to support RE integration into green hydrogen production. These include the waiver of interstate transmission charges for RE used in hydrogen production, provisions for renewable energy banking,[21] and streamlined processes for granting open access and grid connectivity to green hydrogen projects. Complementing this is the National Green Hydrogen and Ammonia Policy (2022), which offers a 25-year waiver on interstate transmission charges for green hydrogen and ammonia producers, further incentivizing the development of these clean energy technologies.

The mission has an initial budget allocation of ₹19,744 crore ($2.41 billion), which includes ₹17,490 crore ($2.13 billion) for the Strategic Interventions for Green Hydrogen Transition (SIGHT) program, ₹1,466 crore ($178.78 million) for pilot projects, ₹400 crore ($48.78 million) for research and development, and ₹388 crore ($47.32 million) for other mission activities.

Amid national-level visions and objectives, the mission emphasizes the need for states to be front-runners in the green hydrogen sector by developing ecosystems to promote projects and attract investments. Dedicated state-level policies and governance mechanisms that complement national policies and plans have significantly contributed to India’s growth in green energy across various sectors. Examples include electric vehicles in the transportation sector, solar energy in the power sector, and energy efficiency in the buildings sector. Similarly, in the coming decades, green hydrogen has the potential to be India’s success story in its green energy transition.

The effort to build a green hydrogen economy at the subnational level has started gaining momentum. Fifteen states (see Exhibit 5) have recognized green hydrogen as a critical growth sector by formulating dedicated policies or by including it in their industrial, renewable, or land policies.

Optimal green hydrogen policies attract investments by promoting ease of doing business, create demand by encouraging and supporting end-consumers, support infrastructure deployment, and improve the competitiveness of green hydrogen. Other critical elements include driving research and innovation and establishing robust governance mechanisms for implementation.

States including Andhra Pradesh, Maharashtra, Rajasthan, Uttar Pradesh, and West Bengal have released dedicated green hydrogen policies. These states’ policies offer waivers for electricity transmission fees, wheeling charges, electricity duty, surcharges, etc., ranging from 25% to 100% for 5 to 20 years. These waivers on electricity charges would help reduce the variable operational expenses due to electricity consumption. Currently, renewable electricity makes up 65%–70% of the green hydrogen production cost. As the cost of electrolyzer technology declines, the proportion of RE could go up to 90% of the total cost. Engineering, procurement, and construction costs, which also make up a considerable share of the final levelized cost of hydrogen (LCOH), could decline with the standardization of engineering solutions. The waivers provided by the states have the potential to reduce the landed cost of electricity to the production unit, bringing RE down to less than 60% of the green hydrogen cost. These state policies also provide capital subsidies, allow exemption in land-related charges, offer land at concessional rates, and provide support around clearances and R&D.

Other states without dedicated green hydrogen policies are offering incentives as part of their industrial, renewable, or land policies. Punjab and Uttar Pradesh have each set up a Green Hydrogen Ecosystem Fund to support policy implementation, and Maharashtra has approved ₹8,562 crore ($1.04 billion) for policy implementation.

Odisha has recognized green hydrogen and green ammonia as “thrust sectors.” The state offers a 100% exemption or reimbursement of cross-subsidy surcharge, additional surcharge, and state transmission charges for 20 years on renewable energy procured either from in-state RE plants or from the Grid Corporation of Odisha (GRIDCO). It also provides a 100% exemption from payment of electricity duty for 20 years and reimbursement of the power tariff of ₹3 ($0.036) per unit consumed and purchased from the local DISCOM/GRIDCO for 20 years for green hydrogen and green ammonia projects.[22]

Under a policy issued by Gujarat, the state leases government waste land for green hydrogen production using renewable energy sources. This policy stipulates that land will be leased to the applicant entity for a 40-year period for setting up a solar/wind/wind-solar hybrid energy plant (including any storage system) to produce green hydrogen.[23]

In almost all the state green hydrogen policies analyzed, there are several similar waivers on taxes and duties related to land, including exemption of land taxes, stamp duties, and land-use conversion charges. Uttar Pradesh, Andhra Pradesh, and Punjab also offer the use of government land for renewable energy combined with green hydrogen production. Uttar Pradesh and Andhra Pradesh also provide 100% reimbursement of the State Goods and Services Tax for green hydrogen/green ammonia production.[24] In Annexure 2A, state policies are described and compared across more than 35 variables, including electricity, land, capital cost, common infrastructure, etc.

The primary goal of such policy incentives is to make green hydrogen economically viable. To achieve this, focusing on two critical forms of incentives — capital incentives and electricity charge waivers — becomes imperative (see Appendix B). Capital incentives are designed to address the substantial up-front costs associated with establishing green hydrogen production facilities. By lowering the initial investment costs, capital incentives encourage more companies to invest in green hydrogen production. This accelerates the deployment of green hydrogen technology, fosters innovation, and supports the scaling up of production facilities. Lower capital costs also make it easier to attract private-sector investment and foster a competitive market for green hydrogen.

Offering subsidies on electricity consumed for green hydrogen production can directly lower the operational expenses. This helps reduce the cost per kilogram of green hydrogen produced. Lower energy costs improve the economic feasibility of green hydrogen projects, encourage increased production, and enhance the overall market attractiveness of green hydrogen.

At the most fundamental level, the techno-economic feasibility of the project depends upon two critical factors: cost of renewable power and capital cost of equipment, particularly electrolyzers. Currently the production cost of green hydrogen is significantly higher than that of grey hydrogen. Grey hydrogen costs $1.5–$1.6/kg in a stable market but could soar to a range of $3–$7.5/kg due to liquefied natural gas market disruptions.

The landed cost of renewable power plays a critical role in determining the final levelized cost of green hydrogen production. As highlighted, it accounts for up to 70% of the LCOH, making it the most important variable to optimize for competitive green hydrogen production.

Landed cost of renewable power and impact of state policy

This study analyzes the landed cost of power across 17 states, as outlined in the Assessment Locations section, focusing on both on-site and off-site power generation projects. For on-site solar generation projects, where the cost of generating power is the same as the landed cost (since no transmission of electricity is involved), the current price of power can be as low as ₹2.1/kWh ($0.026/kWh). This is particularly true in renewable energy-rich regions like Gujarat, Maharashtra, and Rajasthan, which have favorable conditions for solar power generation. By 2030, due to advancements in technology, increased efficiencies, and economies of scale, this cost is expected to decrease by 30% to ₹1.5/kWh (US0.018/kWh).

In contrast, states like Andhra Pradesh, Kerala, and Odisha face higher costs for solar generation, with prices approaching ₹3.0/kWh ($0.036/kWh) due to less favorable climatic conditions, land availability issues, and less developed solar infrastructure. Across the 17 states examined, the average cost of solar power is currently around ₹2.7/kWh ($0.033/kWh), with a projected decrease to ₹1.9/kWh ($0.023/kWh) by 2030 (see Exhibit 6). This expected reduction in costs is driven by the declining price of solar panels, improved installation methods, and better grid integration for renewable energy.

For off-site projects, the situation becomes more complex due to state-imposed transmission charges. These charges, levied when power is generated in one state and transmitted to another or even within the same state, significantly increase the landed cost of power. Depending on the state and the specific project configurations, these charges can raise the landed cost by 4% to 104% — meaning considerable variability of project economics. The size of the increase largely depends on the state’s transmission infrastructure, the regulatory environment, and the nature of the power purchase agreement.

State-level transmission charges are a major contributor to the increased landed cost of green power. Across states, the share of these charges in the total landed cost ranges from 10% to 56%. States such as Gujarat, Karnataka, Tamil Nadu, and Uttar Pradesh tend to have lower transmission and wheeling charges, with the share of transmission costs being below the average of around 33% across the 17 states. On the other hand, Kerala, Maharashtra, Odisha, and Rajasthan states have higher charges, significantly increasing the overall landed cost of power in these regions.

For intra-state solar projects — where both the generation site and the green hydrogen production facility are in the same state — the price increase in the landed cost of power is relatively low, around 40% compared with stand-alone solar projects. These projects benefit from captive assets (where companies generate and use their own power) and incur only limited transmission and wheeling charges. However, when projects rely on third-party contracted power supply, the price increase can be much higher, averaging around 155% — primarily due to the higher transmission charges and fees associated with contracting power from external sources.

Additionally, projects that import power from other states — for example, solar power from Rajasthan or wind power from Tamil Nadu — face higher landed costs due to elevated transmission charges for moving power across state borders. These higher charges are often imposed because of the additional complexity and infrastructure needed to transport electricity over longer distances and significantly affect the overall cost structure for green hydrogen projects.

Third-party contracted power is significantly more expensive than captive or group captive setups due to the imposition of additional charges, such as cross-subsidy surcharges and wheeling surcharges. These charges are typically levied when power is purchased from third-party sources and transmitted across states or regions. In contrast, these surcharges are often waived for captive and group captive use cases, where companies generate and consume their own power or form a consortium to do so. This waiver makes captive setups much more economical for green hydrogen projects.

In scenarios involving third-party contracted power, the landed cost of power can increase substantially — by 80%–225%, depending on the state and the specific regulatory framework governing cross-subsidy and transmission charges. This dramatic rise in costs is especially evident in states with high regulatory fees and charges for power purchased from external sources.

However, some states present exceptions to this trend. For instance, Tamil Nadu and Uttar Pradesh impose relatively lower surcharges for third-party contracted power, making it more affordable than in other states. Additionally, states like Maharashtra have taken a progressive stance by waiving surcharges entirely for green hydrogen projects, further reducing the landed cost of power in these cases.

In states where these additional surcharges are lower or waived, the landed cost of power for green hydrogen projects can fall below the national average of ₹6.9/kWh ($0.084/kWh). This provides a competitive advantage for green hydrogen projects in these regions.

State policies offering various waivers on electricity charges reduce the landed cost of power for green hydrogen projects, from 2% to 94%, depending on the project structure and the state’s policy landscape. For off-site projects, which purchase electricity from the grid, these waivers play a crucial role in reducing both capital expenditure (capex) and operational expenditure (opex) by lowering electricity tariffs, which are one of the most significant components of hydrogen production costs.

However, for on-site projects — where power is generated directly at the project site through renewable energy sources like solar or wind — electricity waivers are not applicable since the power is not sourced from the grid. In these cases, capital subsidies become critical. These subsidies incentivize investment in renewable energy assets, enabling cost reductions through reduced up-front capital requirements. On average, capital subsidies for on-site projects can reduce power costs by about 30% (see Exhibit 7), lowering overall hydrogen production costs.

That said, not all states offer comprehensive support for on-site projects. For example, although states such as Andhra Pradesh, Punjab, and West Bengal have introduced dedicated green hydrogen policies, they do not offer capital investment subsidies for renewable energy assets. As a result, there is little to no cost reduction in power for on-site projects under these states’ policies.

In contrast, off-site projects can take advantage of both capital subsidies and electricity charge waivers. These combined subsidies can reduce the cost of power by 2%–40%, with the smallest reduction observed in Himachal Pradesh, where baseline electricity charges are already minimal. In Rajasthan, where baseline charges are higher, more substantial subsidies lead to the largest reductions. In industrialized states like Maharashtra and Uttar Pradesh, the post-subsidy cost of power is notably lower, reaching ₹2.8/kWh and ₹2.1/kWh ($0.034/kWh and $0.026/kWh), respectively.

Among all states, Odisha stands out as a leader in driving down power costs for green hydrogen production. In addition to the capital subsidies and electricity charge waivers offered under its Industrial Promotion Policy, Odisha provides an additional waiver of ₹3/kWh ($0.036/kWh) on electricity prices, a unique incentive not currently matched by any other subnational policy. This combination of subsidies leads to a remarkable reduction of power costs in Odisha, slashing them by around 50%, and when combined with the additional waiver, this reduction can reach as much as 94%.

These reductions in power costs are crucial to making green hydrogen economically competitive. Detailed discussions on the cost implications across different project configurations are provided in the following sections.

Stand-alone on-site projects

Stand-alone green hydrogen projects are typically designed to operate independently from the electrical grid, relying exclusively on on-site renewable energy sources like solar or wind, and complemented by battery storage systems, to power the electrolysis process. However, some projects may have limited grid connectivity to supplement renewable energy during periods of low generation, while still adhering to strict carbon intensity thresholds.

For example, a project could be connected to the grid as long as the associated carbon emissions do not exceed 2 kg of CO₂ per kg of hydrogen produced, criteria set by the MNRE.[25] This setup allows for operational flexibility while maintaining the environmental integrity of green hydrogen production.

This project configuration stands out for its exceptional cost competitiveness compared with alternative arrangements, primarily due to the absence of transmission charges that typically affect grid-connected projects. Without transmission charges, the ongoing operational costs for the project are reduced, directly lowering the overall cost of producing green hydrogen.

Consequently, with fewer recurring charges, the project can achieve better profit margins, especially in competitive markets where small cost reductions can make a significant difference. Transmission charges can fluctuate based on grid congestion, energy demand, or regulatory changes. By avoiding the grid altogether, stand-alone projects eliminate the uncertainty and volatility associated with these charges, offering more predictable operating costs.

Stand-alone green hydrogen projects represent one of the most economical project setups, with production costs ranging from $4.4/kg of hydrogen to $4.8/kg. Projects that completely avoid using grid electricity and rely solely on battery storage tend to produce hydrogen at a lower cost than those that use grid electricity to maintain a stable base load. Although using grid electricity offers flexibility, especially in managing fluctuations in renewable energy supply, it introduces two key risks:

1. Higher production costs: Incorporating grid electricity increases overall production costs, as grid electricity tariffs are relatively high across many states.
2. Emissions considerations: Although these projects can still be classified as “green” due to achieving carbon intensities below 2 kg CO₂/kg H₂, they are not completely emissions-free. This partial reliance on fossil-fueled grid power poses challenges, particularly for export-oriented projects, where international markets may demand stricter zero-emissions credentials.

The cost of hydrogen production varies significantly across states. Andhra Pradesh, Karnataka, and Odisha face some of the highest renewable energy generation costs, which can push the hydrogen production price above $4.5/kg. In contrast, states like Gujarat, Maharashtra, and Uttarakhand offer some of the most attractive production prices, driven by more favorable renewable energy conditions.

An interesting exception is Himachal Pradesh, where hydrogen production costs are unusually low — less than $4/kg. This is primarily due to the state’s availability of more than 125 days of solar energy and a capacity utilization factor (CUF) of over 20%,[26] which contributes to its lower costs. However, despite this advantage, Himachal Pradesh is not considered a prime candidate for large-scale green hydrogen production. The challenging terrain makes it difficult to install large solar facilities, and the absence of a significant industrial consumer base in the region limits the feasibility of scaling up hydrogen production.

Although the project structure may be similar across regions, the local renewable energy potential is a significant factor in sizing green hydrogen projects. For example, in an on-site solar and battery-connected project, the optimal size of the solar component for producing 50 ktpa of green hydrogen can vary widely — from 1.9 to 2.8 GW. This range reflects regional differences in solar irradiance and resource availability, with the highest capacity required in Andhra Pradesh and one of the lowest in Gujarat.

Key industrialised states like Maharashtra, Gujarat, Tamil Nadu, Odisha, and Uttar Pradesh, all of which are positioning themselves as leading green hydrogen producers, require an average solar capacity of approximately 2.3 GW for similar projects. The sizing of electrolyzers also shows a similar variation. The required electrolyzer capacity can range from 515 to 670 MW. Battery capacity, which is essential for storing energy to manage fluctuations in renewable supply, also varies significantly. Gujarat has the lowest battery size requirement at around 280 MW, whereas Himachal Pradesh requires a battery capacity of approximately 555 MW. Additionally, the variation in green hydrogen storage requirements is considerable. For example, Karnataka has the highest storage requirement at around 916 tonnes, which is three times that needed in Kerala.

Since these projects do not incur transmission charges, owing to their on-site nature, capital subsidies from state governments become the key financial incentive to reduce overall production costs. However, not all states, even those with dedicated green hydrogen policies, offer capital subsidies. The availability of such subsidies has a significant impact on the viability and competitiveness of these projects. In states where subsidies are available, they can substantially lower capital costs, directly reducing the cost of green hydrogen production.

Several states, including Maharashtra, Uttar Pradesh, Odisha, Rajasthan, and Tamil Nadu, offer capital subsidies as part of their subnational policies to support green hydrogen projects. These subsidies typically range from 25% to 35%, with Uttar Pradesh providing the highest incentives due to an economic booster package layered on top of the capital subsidy.

On average, these capital subsidies result in a 20%–22% reduction in power costs for green hydrogen production. Although this represents a significant cost decrease, there remains a considerable gap between the cost of green hydrogen and its fossil fuel-based counterpart, grey hydrogen. This gap underscores the need for further financial and technological support to bring green hydrogen closer to cost parity with grey hydrogen.

The anticipated decline in production costs from 2024 to 2030 is even more substantial, with a projected average reduction of 46%. This decrease highlights the importance of technological advancements and economies of scale as the hydrogen sector matures. By 2030, the cost of producing green hydrogen is expected to drop from approximately $4.4/kg to $2.4/kg, driven by falling costs in renewable energy, electrolysis technology, and increased infrastructure development.

Although on-site stand-alone green hydrogen projects offer attractive cost economics by avoiding transmission costs and fully utilizing renewable energy, several critical constraints can limit their scalability and effectiveness. These constraints primarily concern the availability of land and proximity to demand centers.

Land availability

Solar and wind energy generation is land intensive. Solar power typically requires 3–5 acres per megawatt, and even more land is needed for wind energy installations due to the spacing needed between turbines. A large-scale green hydrogen facility, particularly one producing 50 ktpa, could require several thousand acres.

Not all regions have large contiguous tracts of land available for renewable projects. Additionally, land that is flat, is not prone to flooding, and has optimal solar or wind potential may be scarce. In densely populated states or regions with competing land uses (agriculture, industry, urban development), acquiring suitable land becomes even more challenging. Land acquisition can also be complicated by legal regulations, ownership disputes, and environmental considerations.

In regions where land is available, it might be prohibitively expensive, especially in proximity to industrial hubs or areas with high renewable potential. The cost of land acquisition — which is not considered in the current LCOH — can substantially increase capital expenditure, undermining the cost advantages of stand-alone projects.

Proximity to demand centers

Green hydrogen is often targeted at industrial sectors like fertilizers and refineries, which require a continuous and high-volume supply of hydrogen. Proximity to these demand centers is a critical factor for the success of on-site stand-alone projects.

If the hydrogen production site is far from industrial demand centers, the costs associated with transporting hydrogen (in either gas or liquid form) can significantly erode the economic benefits of on-site production.

Storing hydrogen for extended periods requires expensive infrastructure (such as high-pressure tanks or cryogenic storage), and the farther from demand centers, the larger the storage requirements. Additionally, distribution networks for hydrogen may need to be built to transport it from production sites to consumers, adding to capital and operational costs.

CTU-connected projects

Projects connected to the CTU or the ISTS are gaining attention from developers due to their ability to offer highly competitive production costs. This advantage primarily stems from the financial incentives and exemptions provided under the National Green Hydrogen and Ammonia Policy of 2022. Specifically, the policy waives CTU charges, enabling developers to minimize operational expenses. These cost savings translate into more favorable project economics, making CTU-connected projects particularly attractive for large-scale green hydrogen and ammonia production.

The ISTS is a network of high-voltage transmission lines that link generation centers to load centers across states. ISTS helps balance the national grid by transmitting electricity from surplus regions to deficit regions. It plays a key role in the integration of renewable energy projects, particularly large-scale solar and wind, by ensuring connectivity from remote generation sites to demand centers. ISTS facilitates the movement of electricity across states, which is crucial for interstate power trading under the open access regime. This enhances market competition and optimizes the utilization of generation assets.

Green hydrogen developers are keen to secure ISTS connectivity as they can source electricity from renewable energy plants in different states, ensuring a consistent and reliable power supply. This is especially important in regions with less favorable conditions for renewables. Additionally, green hydrogen projects can benefit from hybrid renewable energy setups, such as a combination of solar and wind, enabled by ISTS connectivity. This ensures round-the-clock energy availability, allowing hydrogen plants to operate efficiently even when one energy source (like solar) is unavailable.

Exhibit 9 highlights the LCOH production in a CTU-connected project. In this analysis, we assume that the green hydrogen production project is connected to the CTU network and is sourcing solar power from Rajasthan and wind power from Tamil Nadu. This project is connected to the grid to source renewable power. For the baseload needed to manage ramping up and down of the electrolyzer, the project can rely on the battery or purchase electricity from the grid at industrial tariffs, with the emissions constraint of 2 kg CO₂/kg H₂.

The production cost for green hydrogen projects connected to the ISTS can vary between $4 and $5 per kg of hydrogen, depending on the specific project components and configuration. This range reflects factors such as the inclusion of renewable energy sources (solar, wind), grid availability, and storage solutions. Projects connected to ISTS generally have more favorable economics, with costs being 20%–30% lower than those of STU-connected projects, which are often subject to multiple state-level transmission charges. These state charges can significantly inflate the cost of electricity, which is the largest operational expense in green hydrogen production.

In projects designed with a mix of grid connectivity, solar, and wind energy, battery requirements are typically limited. This is because wind and solar energy complement each other in terms of generation timing, and the grid acts as a balancing mechanism, allowing excess energy to be exported and any deficits to be met through grid power. However, in projects without access to both the grid and wind energy, batteries become essential to ensuring a steady supply of electricity, particularly when solar energy is unavailable (e.g., at night or during low-sunlight conditions). In such configurations, the share of battery-related costs (capital and operational expenditures) make up about 5% of the overall LCOH.

Similarly, in projects that have access to grid power and wind energy, hydrogen storage infrastructure is found to make up around 6% of LCOH. This is because the combination of solar, wind, and grid access ensures more continuous power generation, limiting the need for hydrogen storage to cover periods of low energy generation. In contrast, for projects relying solely on solar power, the storage component becomes critical to maintaining a consistent supply of hydrogen to consumers. In such cases, the share of storage costs rises substantially, contributing up to 20% of LCOH, as larger hydrogen storage systems are needed to bridge the gaps in solar generation.

These projects can also take advantage of capital subsidy incentives available for green hydrogen initiatives; however, these subsidies typically apply only to electrolyzers, batteries, and certain other plants and machinery. In the case of ISTS projects, where developers source renewable energy from different states, the capital subsidies provided by the state of production may not apply to the renewable energy asset. This limitation reduces the cost-saving potential that such subsidies can offer.

To better understand the implications, consider the example of Uttar Pradesh. With a capital subsidy of approximately 35% (including a booster), the LCOH could decrease by around 10% for a battery-supported solar project (see Exhibit 9). In this subsidized scenario, the final production cost is nearly 25% lower than that of a project using grid power in combination with batteries, solar, and wind energy.

This demonstrates that, although capital subsidies can significantly reduce production costs where they apply, their impact is less pronounced in ISTS projects due to the cross-state nature of renewable energy procurement.

ISTS connections also enable green hydrogen production units to be set up in diverse locations, including regions where renewable energy generation might not be feasible but where industries demanding hydrogen are located. The ability to transmit renewable electricity over long distances facilitates decentralized hydrogen production closer to demand centers, minimizing transport costs for hydrogen and improving its overall feasibility.

As India gears up to establish hydrogen hubs and clusters, ISTS connectivity will be essential in ensuring that these hubs are powered by renewable energy from across the country. This interconnected network helps balance supply and demand, making sure the hydrogen clusters have uninterrupted, clean electricity to meet their energy needs.

Though the ISTS connectivity can offer multiple benefits, it also comes with some key challenges that require attention from the regulatory authorities. One of them is the need for adequate transmission infrastructure. As renewable energy projects expand rapidly, particularly in remote locations with high solar and wind potential, the existing ISTS infrastructure may become insufficient. Transmission bottlenecks can delay the evacuation of renewable energy, limiting the ability of green hydrogen projects to access consistent electricity supplies.

Building new transmission lines and upgrading the ISTS infrastructure require significant investment. The capital costs associated with extending the ISTS network to remote renewable energy zones, particularly for large-scale projects like green hydrogen, can be substantial. These costs can pose financial risks, especially for developers of green hydrogen projects, as they rely on affordable electricity to remain economically viable.

Although ISTS is governed by a central regulatory framework, there are still complexities in navigating state-level regulations for renewable energy projects. Discrepancies in state policies, particularly with respect to energy banking, scheduling, and grid access, can create barriers for smooth ISTS connectivity. Additionally, policy uncertainty regarding the long-term availability of waivers or reduced transmission charges for renewable energy could affect project planning for green hydrogen developers.

Off-site (STU/DISCOM-connected) projects

As the green hydrogen ecosystem continues to mature, off-site projects that are STU- or DISCOM-connected are expected to become the most common type of green hydrogen projects. This shift will occur for several reasons, particularly due to the growing difficulty in setting up stand-alone or ISTS-connected projects in all potential demand locations.

STU/DISCOM-connected projects tap into the state’s existing transmission and distribution infrastructure, which can be more accessible and easier to integrate with the national grid or stand-alone solutions. This allows projects to be located closer to industrial or urban demand centers without the need for building new, isolated infrastructure.

Although STU-connected projects offer several advantages, they are not without challenges. The primary difficulty in prioritizing these projects lies in the higher cost of production, which is largely driven by the multiple state transmission charges, duties, and additional fees imposed when the developer is using grid infrastructure within state boundaries.

With more projects coming on line over time, it becomes increasingly difficult to find large contiguous land parcels for renewable energy generation at every demand location. State-level grid connections via STU/DISCOMs allow for the renewable energy plant to be sited in areas in the state where land and renewable resources are more abundant, while the hydrogen production facilities can remain closer to demand centers. This flexibility makes it easier to scale projects.

On average, these transmission-related charges can increase the landed cost of power to 1.5–2.5 times the base generation cost of renewable energy. The exact magnitude of these charges varies from state to state, depending on the specific regulatory framework. States with higher transmission and wheeling charges, or less favorable policies for renewable energy transmission, can make it more expensive to develop STU-connected projects. This variability creates uncertainty for developers and can complicate project planning and cost estimation.

To explore the complexities and cost implications of STU-connected projects, three different scenarios have been considered regarding the siting of renewable energy plants relative to the hydrogen production facility. The first scenario involves siting the solar plant in the same state as the green hydrogen production facility, but off site. The second scenario places off-site solar and wind plants in the same state as the hydrogen production (see Exhibit 10). The third scenario considers solar and wind plants located in different states, with solar energy sourced from Rajasthan and wind energy from Tamil Nadu in this analysis.

Whereas Kerala has the highest cost for green hydrogen production among all states — more than twice the cost of grey hydrogen — states like Gujarat, Karnataka, Punjab, Rajasthan, and Uttar Pradesh come closest to achieving costs comparable to grey hydrogen. The elevated production cost in Kerala can be attributed mainly to the higher base cost of power generation, but a significant portion is also due to substantially higher transmission charges.

When state incentives to promote green hydrogen production are evaluated, two critical factors emerge: the magnitude of the waivers (i.e., the size of the subsidies) and the tenure (how long the incentives last). These factors heavily influence the final cost of green hydrogen production. Depending on the state, the reduction in production costs due to subsidies can vary significantly, from as little as 1% in West Bengal to 61% in Odisha.

In states like Andhra Pradesh and West Bengal, the waivers for electricity charges are granted for five years, and no additional support is provided for capital investment. Green hydrogen projects typically have a life span of around 30 years, meaning that these incentives cover only one-sixth of the project’s duration. Thus, for most of the project’s life span, developers would have to bear the higher transmission charges, significantly affecting their long-term financial planning.

Odisha emerges as a leader in green hydrogen production cost competitiveness. As outlined in Stand-Alone On-Site Projects, the state’s comprehensive incentive package could bring down green hydrogen costs to as low as $3/kg, which is roughly 42% lower than the average production cost across other states. This positions Odisha as one of the most attractive locations for green hydrogen development, offering significant cost advantages both in the short and long term. Moreover, the scale of these incentives makes Odisha the only state capable of achieving green hydrogen prices that could currently compete with the cost of grey hydrogen, further enhancing its appeal for investment in the sector.

Long-term economies of scale are expected to play a crucial role in enhancing the overall competitiveness of green hydrogen production across states. As projects scale up, production costs will decrease due to more efficient use of resources, better technology, and lower unit costs. Currently, the average cost of green hydrogen production across 17 states is around $4/kg, without factoring in state-specific incentives.

By 2030, 9 of these 17 states will already be producing green hydrogen at a cost below $4/kg, with some of the most competitive prices expected in Gujarat, Uttar Pradesh, Karnataka, and Rajasthan. These states benefit from lower transmission and energy costs, making them attractive for large-scale green hydrogen production.

However, important industrial states such as Maharashtra, Odisha, and Andhra Pradesh continue to face higher production costs due to elevated transmission charges levied by the state governments. These transmission fees significantly drive up the cost of power, which is the key input for producing green hydrogen, making it harder for these states to compete on cost.

On the other hand, industrial powerhouses like Gujarat and Karnataka offer some of the most favorable cost structures. Their lower transmission fees, combined with the ability to scale production, give them a significant competitive advantage. By capitalizing on economies of scale, these states can offer some of the best cost dynamics for green hydrogen production, which will strengthen their position as leaders in the emerging green hydrogen economy.

Contracted power–based projects

In the green hydrogen sector, many players are aiming for vertical integration in the whole supply chain, from renewable energy generation to green hydrogen production. Some are also expanding into the production of hydrogen derivatives and exploring end-use applications. However, a segment of the industry is focusing exclusively on green hydrogen production, opting not to invest directly in renewable energy generation. In these cases, companies rely on sourcing renewable energy through PPAs rather than owning renewable assets.

One of the key advantages of sourcing power through a PPA is the ability to maximize the utilization of the hydrogen production plant, potentially up to 100%. This high utilization rate allows for the optimal use of electrolyzers, reducing both the capital and operational expenditures associated with them. By running at full capacity, companies can minimize the size and cost of the electrolyzer needed for hydrogen production, leading to improved efficiency in equipment use and overall project cost management.

PPAs enable companies to secure a reliable supply of renewable electricity for hydrogen production without the need to diversify into the renewable energy business. These agreements offer the advantage of stable energy access, which is critical for hydrogen production processes that require continuous power supply. However, this arrangement tends to come with a higher landed cost of electricity compared with vertically integrated models.

Based on the analysis, the landed cost of contracted power is expected to range between ₹5.3/kWh and ₹8/kWh ($0.065/kWh and $0.098/kWh), with an average of ₹6.9/kWh ($0.084/kWh) across 17 states. Since the base contract cost remains constant, the variation in landed cost arises from the differing charges applicable in each state. Compared with other scenarios across the states, this landed cost is 6%–140% higher.

The baseline cost of power in a third-party PPA is typically higher than the base generation cost that would be achieved through direct ownership or captive power generation. This is due to the added expenses from transmission and distribution charges, including cross-subsidy surcharges and additional surcharges. These fees, often applied in third-party agreements, are typically waived in captive or group captive projects, where companies generate and use their own power or share resources among a consortium. As a result, the reliance on third-party power procurement adds to the operational expenses of hydrogen production.

Consequently, the cost of hydrogen production shows significant variation, ranging from $5.9/kg to $8.5/kg, which is considerably larger than in other scenarios. Although state policies help reduce costs, most waivers are applicable for only a limited time and do not span the entire project life cycle, limiting their impact. According to the analysis, the anticipated cost reduction could be around 10%. However, it is important to note that these contracts are typically not for project life, and subsequent negotiation may help secure lower prices as market dynamics evolve.

Despite the benefits of high utilization, the significantly higher landed cost of electricity in third-party PPA arrangements outweighs the gains. The elevated electricity costs result in a higher overall cost of hydrogen production compared with other project configurations, such as vertically integrated models or captive power setups. This raises important considerations for investors about the trade-off between maximizing production efficiency (by fully utilizing electrolyzer capacity) and minimizing overall costs through more strategic project structuring.

This scenario also prompts broader questions about the most effective investment strategy for green hydrogen projects. Should the industry prioritize maximum utilization of production assets, or should it focus on optimizing the project structure to balance power costs and operational efficiency? These questions are crucial for determining the long-term sustainability and profitability of green hydrogen ventures and are explored in further detail in the next section.

As highlighted in the previous section, costs for green hydrogen production remain high; however, state-level subsidies have made a significant impact by driving substantial reductions. To achieve competitive price points of $1.5–$2/kg, green hydrogen production must scale significantly by the end of this decade, ensuring the anticipated decline in input costs.

Although cost remains a critical factor, developers’ decision-making is also shaped by a range of other considerations. Although optimized production costs can provide national and subnational benchmarks, developers must navigate a complex array of choices that influence actual investments. One of the most discussed topics in industry forums is maximizing system utilization. This focus often leads to minimizing electrolyzer size, which in turn reduces capital investment. However, the widespread practice of upstream renewable oversizing, coupled with smaller electrolyzers, presents a consistent challenge: how to use excess power effectively or avoid losses from curtailment.

In addition to these challenges, uncertainty persists around the commercial scalability and price trajectory of green hydrogen storage and battery storage, despite recent cost declines. Developers must also account for various system risks, which add further complexity to project investment decisions.

This section delves into these critical considerations, offering insights into the key choices developers face when investing in green hydrogen projects.

Role of enhanced system utilization in better project economics

Among green hydrogen project developers, as in other sectors, there is a persistent effort to maximize system utilization. Given the high cost of electrolyzers, it is reasonable to minimize their size and, consequently, the capital outlay of the project.

Utilization of any project can be defined in multiple ways. One approach is to evaluate the overall system utilization, where the total number of hours that a system has access to electricity determines the maximum operational threshold and, consequently, the appropriate electrolyzer size. For instance, to deliver a consistent demand of 100 ktpa (~11.4 tonnes/hour), a project with 25% utilization requires an electrolyzer size of 2,450 MW, while a project with 85% utilization requires 721 MW.

However, the interpretation of 25% or 85% utilization can vary. One interpretation involves achieving the annual utilization target by front-loading production at the beginning of the year and using storage to deliver green hydrogen for the rest of the year. Lower utilization in this context would necessitate higher hydrogen storage capacity, whereas higher utilization would reduce the storage requirement. This method is inefficient, as it requires oversizing the upstream renewable project to meet the higher electricity demand, significantly increasing the overall capital expenditure.

Alternatively, a more optimized approach involves running the project nearly year-round, adjusting capacity usage on an hourly basis according to the availability of renewable resources. This method focuses on optimizing the annual hourly delivery of green hydrogen, thereby reducing the project’s overall capital outlay. This optimized system utilization approach is also widely discussed among developers and focused on in this section.

Another method of defining utilization involves a fixed electrolyzer capacity with varying utilization levels based on power availability. For example, a 1,000 MW project operating at 100% utilization runs continuously throughout the year, whereas, if tied to a solar project with fluctuating power production, its utilization might drop to 18%–25%. In this case, the effective project capacity would change from 1,000 MW to 250 MW with only 25% utilization. However, the choice of an electrolyzer is not arbitrary and must be carefully defined to align with the specific project requirements and power availability.

There are various methods to achieve near 100% project utilization, one of which is energy banking, a solution actively sought by industry. Banking has played an important role in supporting the open-access acquisition of renewable energy. DISCOMs offer this service in return for “banking charges,” which may be paid either in kind (a portion of the banked energy) or in cash (₹/kWh).

Energy banking has the potential to increase project utilization by up to 100%. However, promoting it could lead to various challenges with increasing project sizes and corresponding renewable energy capacity. First, managing the timing and volume of energy injections and withdrawals can strain grid stability, especially with fluctuating renewable energy inputs. Second, balancing supply and demand becomes more complex, leading to potential inefficiencies and higher operational costs. Third, DISCOMs may face financial challenges due to the variable cost differences between energy banking and real-time energy prices. Lastly, the infrastructure may require upgrades to handle the higher energy flows, necessitating significant investment.

Other mechanisms to provide 24/7 electricity include diversifying the energy mix along with storage options to offer round-the-clock power, using demand response to encourage consumers to shift their electricity usage to off-peak times to help balance demand and supply, and promoting energy storage systems such as batteries, pumped hydro, or thermal storage.

In this context, the primary question that arises is whether 100% utilization is necessary given its impact on the final levelized cost of hydrogen production. In other words, is it possible to find an optimal utilization rate that allows developers, energy providers, and distribution companies to manage their operations and expenses effectively?

To explore this question, this study examines different utilization rates — 25%, 50%, 75%, and 85% — and their corresponding costs of production (see Exhibit 11A), hydrogen storage requirements (Exhibit 11B), and the oversizing of renewable energy assets (Exhibit 11C).

Lower utilization rates, such as 25%, would require approximately 2.5 GW of electrolyzer capacity to deliver a project with a uniform demand pattern and a production capacity of 100 ktpa. In contrast, increasing the utilization rate to 85% would reduce the required electrolyzer size by 70% to 720 MW.

Currently, electrolyzer costs range from $500/kW to $1,400/kW. Considering the average cost of electrolyzers (~ $741.5/kW), the capital requirement for electrolyzers would decrease from nearly ₹15,000 crores to ₹4,400 crores ($1.83 billion to $537 million) when utilization increases from 25% to 85% for a 100 ktpa project. Therefore, prioritizing increased system utilization can significantly reduce the LCOH. For instance, increasing system utilization from 25% to 50% would reduce the LCOH by 22%, and a further increase to 75% would reduce it by an additional 9%. However, beyond 75%–85%, the reduction in LCOH is marginal, about 2% (see Exhibit 11A). Thus, increasing system utilization beyond a certain threshold yields marginal gains.

The need to achieve 100% utilization becomes less critical as electrolyzer costs decline. Lower electrolyzer costs mitigate the challenge associated with larger electrolyzer sizes, allowing developers to oversize the system while maintaining a reasonable capital outlay. As the cost of electrolyzers decreases, their proportion in the LCOH also declines. Thus, in the projected 2030 scenario, gains from increased project utilization are less significant compared with optimization strategies for project development (see Exhibit 11A).

Increasing utilization leads to smaller electrolyzers operating for more hours but producing a lower volume per hour than larger electrolyzers. To meet the consistent demand of large industries, hydrogen storage will become essential. For instance, increasing utilization from 25% to 85% will require storage capacity to grow from 5 days to over 20 days. Additionally, it will necessitate higher renewable energy capacity beyond the threshold of optimal utilization. Therefore, project developers could aim for optimal utilization factors, ideally between 60% and 75%, to achieve optimized production costs while managing storage requirements, RE capacity, and grid stability.

Exclusive choice between battery storage and hydrogen storage

When planning a project, developers can optimize for battery storage, hydrogen storage, or a combination. However, deciding between storing electrons (battery energy) and storing molecules (hydrogen) is crucial, especially given the anticipated decline in battery and hydrogen storage prices. This analysis explores scenarios involving an exclusive choice between battery energy and hydrogen storage, examining their implications for optimal project sizes and, consequently, for the cost of green hydrogen production. The highlights of the exclusive project configurations are described in Exhibit 12.

Green hydrogen production profiles differ depending on the choice of either battery storage or hydrogen storage (see Exhibit 13A). Both project configurations ensure a constant supply of green hydrogen to the consumer, but a project with hydrogen storage can operate flexibly, using stored hydrogen to meet demand, whereas using battery storage only (with no hydrogen buffer) means production must remain consistent throughout the year.

The optimized project size differs significantly depending on the availability of energy and hydrogen storage. With battery storage, the project can achieve 100% utilization, minimizing the electrolyzer size to just 610 MW for a 100 ktpa project. However, this requires the renewable energy capacity to be more than 7 GW. Conversely, with hydrogen storage, the project utilization is around 33%, necessitating a larger electrolyzer size — approximately 1.9 GW — and requiring more than 3 GW of renewable energy capacity. Oversizing renewable energy capacity relative to the electrolyzer size typically results in excess power generation. This excess is limited to about 20% with hydrogen storage and a smaller renewable energy capacity, compared with 70% with battery storage and a significantly larger renewable energy capacity (see Exhibit 12). Only a fraction of the excess energy is consumed by the electrolyzers (see Exhibits 13B and 13C).

The different configurations of projects with battery storage or hydrogen storage do not indicate a right or wrong approach. The choice depends on the developer’s business model and consumer needs. Excess power is only a challenge until a parallel consumer market is established for purchasing it. As the demand for renewable energy in India continues to grow across various sectors, the surplus power could provide an additional revenue stream. This revenue can help offset the high investment costs, thereby reducing the LCOH.

Despite the different project configurations, the final LCOH with battery storage or hydrogen storage is roughly the same (see Exhibit 14).

Currently, the difference in LCOH is less than a dollar, which is expected to further reduce to just 30 cents by 2030 due to declining costs of batteries and hydrogen storage. However, from a project optimization perspective, projects using hydrogen storage are more flexible in their production patterns (see Exhibit 13B) and can yield a marginally more competitive LCOH. As illustrated in Exhibit 14, by 2030, the cost of hydrogen production could be less than $3.6/kg by 2030, with potential for fee waivers to reduce it to less than $2.5/kg.

An ideal and optimized green hydrogen project would strategically combine energy storage (such as battery storage) and hydrogen storage. This hybrid approach offers multiple advantages, balancing operational flexibility, cost-effectiveness, and resilience. Energy storage allows for the immediate use of excess renewable energy during periods of low demand, enabling more stable grid operations and minimizing curtailment losses. Meanwhile, hydrogen storage provides the ability to store and use surplus energy over a longer time frame, which is especially valuable for periods of intermittent renewable energy generation, such as on cloudy or windless days.

The production costs outlined in Section 4 highlight the range of challenges that developers will face in India, where regional variations in resource availability, infrastructure, and market conditions can have significant impacts on project economics.

In practice, developers must navigate these varying conditions, tailoring their project configurations to local factors. The combination of energy and hydrogen storage can help mitigate some of these challenges, enabling a more consistent and optimized production process across different scenarios.

Moreover, as the hydrogen economy evolves, real-world projects that successfully integrate energy and hydrogen storage will be better positioned to capitalize on emerging revenue streams, such as selling excess renewable power or hydrogen to industrial consumers, the transport sector, or grid operators. By optimizing both production and storage, developers can enhance profitability while contributing to India’s long-term goals for decarbonization and energy transition.

Leveraging excess power generation from renewable energy oversizing

Green hydrogen projects are being established using oversized renewable energy assets, leading to excess power generation that would otherwise be curtailed if not effectively utilized. To prevent this, the surplus electricity can be either sold into the market or stored in energy storage systems, thereby ensuring higher utilization rates of the projects. If not managed properly, this excess power represents a significant missed opportunity. By strategically harnessing this surplus electricity, which would otherwise go unused, green hydrogen initiatives can enhance their overall efficiency and cost-effectiveness.

If a solar power project is planned in the same state as the hydrogen production, the excess solar energy can range from 11% to 41% of the total generated by the asset. By comparison, the excess generation from wind — considered a complementary power source to the primary solar asset and therefore planned at a much smaller scale — ranges from 0% to 12%. If the projects are structured to harness power from resource-rich states, such as Rajasthan for solar and Tamil Nadu for wind, the excess power generation can be more precisely predicted, at 14% for solar and 2% for wind.

Excess power generation varies significantly based on project configurations, but the location selected for power generation and green hydrogen production in the state has a greater influence. In most states, on-site projects exhibit lower excess generation than off-site solar-based green hydrogen projects in the state. However, there are exceptions in states like Andhra Pradesh, Gujarat, and Rajasthan,  where resource availability can lead to higher excess generation even in on-site projects.

This observation highlights the critical importance of site selection, as the availability and intensity of renewable resources greatly affect the amount of excess power generated. Consequently, the dynamics of excess generation can change considerably based on the specific sites chosen for the projects. For instance, both Gujarat and Rajasthan are renewable-rich states, but the excess generation for on-site solar-based projects is higher in Rajasthan (31%) than in Gujarat (26%). Conversely, for off-site solar-wind combined projects, excess solar generation is significantly higher in Gujarat (41%) than Rajasthan (11%). This is because Gujarat has more wind to meet power demand, freeing up additional available solar power, which is not the case for Rajasthan.

The excess power produced from oversizing green hydrogen projects can generate additional revenue, helping to offset the high LCOH. In 2022–23, the weighted average price of electricity transacted through the Green Day Ahead Market (GDAM) was ₹5.6/kWh ($0.068/kWh).[27] This market provides an opportunity to sell the excess power generated by renewable energy assets.

For example, Maharashtra’s off-site, within-state solar-wind project has excess power generation of 22% for solar and 2% for wind. Selling this excess power at the fixed GDAM price could offset the production cost of green hydrogen by 15%, reducing it from $4.6/kg to $3.8/kg (including state electricity transmission charge waivers) (see Exhibit 15). This offsetting mechanism could further reduce production costs in states with greater excess generation than Maharashtra, such as Gujarat, with more than 40% excess solar and 9% excess wind. In Gujarat, with a similar project configuration, the cost of green hydrogen production could drop nearly 33%, from $4.7/kg to $3.2/kg, even without electricity charge waivers, which could further lower the cost.

System risks influencing project development choices

Beyond cost considerations, the path from conceptualization to operationalization of green hydrogen projects faces numerous risks that can undercut their viability and success. This study delves into the complex risk landscape surrounding green hydrogen project development.

Key risk factors include fluctuating renewable energy costs, regulatory uncertainties, technological challenges, and financial limitations. Market volatility and the evolving nature of hydrogen infrastructure magnify these challenges. This section thoroughly analyzes these risks to provide stakeholders with valuable insights to navigate and mitigate them. Understanding these risks is essential to ensuring the sustainable growth and long-term success of green hydrogen initiatives, ultimately contributing to the broader goals of reducing carbon emissions and combatting climate change.

Drawing from a literature review and discussions with project developers and experts, the study identifies 10 critical risks to project development, as summarized in Exhibit 16.

1. High cost: Capital and operational expenditures. The development of green hydrogen projects demands substantial capital expenditures and operational expenditures. Initial investments cover the installation of electrolyzers, renewable energy infrastructure, and ancillary systems. Operating costs include maintenance, labor, and energy consumption. This high-cost structure necessitates massive financial investments, posing a significant barrier for project developers. Additionally, securing funding often requires convincing investors of the project’s long-term viability and return on investment, which can be challenging given the emerging nature of the technology and market.

2. Emerging technology: Electrolyzer efficiency and durability. Green hydrogen production relies heavily on electrolyzers, which are still in the nascent stages of development. Current electrolyzers require significant advancements to improve their efficiency and system durability. Enhancements in catalyst materials, membrane technologies, and system integration are crucial to achieving higher efficiency rates and longer operational life spans. The current technological limitations result in higher costs and lower production rates, deterring large-scale adoption and commercialization.

3. Energy source: Renewable power availability and reliability. The availability, affordability, and reliability of renewable power sources, such as solar and wind, are critical for green hydrogen production. Variability in renewable energy generation due to weather conditions can lead to inconsistent hydrogen production rates. Additionally, the cost of renewable energy can fluctuate, affecting the overall economics of green hydrogen projects. Ensuring a stable and affordable supply of renewable energy is essential for the feasibility and scalability of green hydrogen initiatives.

4. Infrastructure development: Grid, storage, and transportation. Integrating green hydrogen into India’s power grid offers potential but faces challenges like the variability of renewable energy sources, causing unstable hydrogen production. Balancing supply and demand is complex, compounded by limited hydrogen storage. Infrastructure upgrades are needed, despite high costs for mainstreaming green hydrogen projects. The infrastructure for storing and transporting green hydrogen is underdeveloped. Hydrogen storage requires specialised tanks and facilities to maintain high pressure or low temperatures, adding to the overall project cost. Transporting hydrogen, especially over long distances, poses significant challenges and risks due to its high flammability and low energy density. Developing a robust and extensive hydrogen infrastructure network is essential in order to support the widespread adoption and distribution of green hydrogen.

5. Regulatory ecosystem: Complex and varied landscape. The regulatory environment for green hydrogen is complex and involves multiple agencies. There is significant variation in regulations, allowances, and subsidies across different regions and countries. Navigating this intricate regulatory landscape can be challenging for project developers, leading to delays and increased costs. Consistent and supportive regulatory frameworks are crucial to facilitating the development and deployment of green hydrogen technologies.

6. Market offtake: Securing end-user adoption. End-users, including industrial and transportation sectors, are still exploring ways to integrate green hydrogen into their operations. Without secured offtake agreements, green hydrogen projects face the risk of not achieving commercial viability. Ensuring a steady demand for green hydrogen and its derivatives is critical for project success. This requires extensive market development efforts, including educating potential end-users about the benefits and applications of green hydrogen.

7. Scale-up: Financing for comprehensive ecosystem transition. Financing green hydrogen projects faces significant hurdles, especially in emerging markets like India, where the ecosystem is still developing. High financing rates are a key challenge, as green hydrogen projects require substantial capital for infrastructure. Investors demand higher returns due to risks like technological uncertainties, fluctuating energy prices, and regulatory changes. This, coupled with a lack of historical performance data, makes securing affordable financing difficult. Additionally, there is limited availability of specialised financial instruments tailored to green hydrogen’s long payback periods and high up-front costs. The sector suffers from insufficient investment, as few investors have the risk appetite, and public funding and subsidies are limited. Perceived risks, including technological and regulatory uncertainties, deter potential financiers. Furthermore, the industry lacks adequate risk management capabilities to address these concerns, limiting funding options and delaying project implementation, which hinders the growth of India’s green hydrogen sector.

10. Supply chain disruptions: Global dependencies and geopolitical risks. Green hydrogen production depends on a complex global supply chain for raw materials and components, such as platinum for catalysts and rare earth elements for electrolyzers. Geopolitical risks, trade restrictions, and supply-chain disruptions can have a significant impact on the availability and cost of these critical materials. Ensuring a stable and diversified supply chain is vital for the uninterrupted development and operation of green hydrogen projects.
11. Safety concerns: Handling and storage of hydrogen. Hydrogen is highly flammable and requires careful handling throughout its life cycle, from production to end use. Ensuring the safety of hydrogen production facilities, storage systems, and transportation networks is paramount. This includes implementing stringent safety protocols, advanced detection systems, and emergency response strategies. Addressing safety concerns is critical to gaining public and stakeholder trust in green hydrogen technologies.
12. Investment uncertainty: Economic and market volatility. Economic uncertainties, market fluctuations, and changes in financing conditions can affect the viability of green hydrogen projects. Investors may be wary of committing funds to projects with uncertain returns, particularly in a volatile economic environment. Securing long-term investment and financing requires demonstrating the project’s economic feasibility, stable regulatory support, and potential for market adoption. Addressing investment uncertainty is crucial to attracting the necessary capital for green hydrogen development.