India has become one of the world’s fastest-growing clean-energy markets. Solar parks now stretch across Rajasthan and Gujarat. Rooftop panels are going up on lakhs of homes every week. Non-fossil capacity has crossed 300 GW. Onshore wind turbines have come up in several states. Yet, more than ten years after New Delhi notified a dedicated National Offshore Wind Energy Policy, not a single commercial offshore turbine stands in Indian waters.
That contrast is the story. The same government that made solar cheap and scalable has not yet been able to convert offshore wind from a strategy paper into steel in the sea. Last year the Solar Energy Corporation of India cancelled its first big auctions after developers stayed away. A second attempt is now being prepared. Whether it works will depend less on another slogan and more on costs, risk-sharing, ports, cables and tender design.
When the present government took office in 2014, India’s energy story was still dominated by coal. Installed solar capacity was only 2.82 GW and total renewable capacity was about 76 GW. The political bet that followed was unusually clear for Indian energy policy: build a large, auction-driven renewable market, cut tariffs through competition, and later pull manufacturing onshore.
The results on solar are hard to dispute. As of 30 June 2026, installed solar capacity stood at 162.15 GW — a 57-fold rise in twelve years. By 31 July 2026 it had climbed further to about 164.59 GW. India is now among the world’s three largest solar markets. Utility-scale plants account for most of that capacity; rooftop and off-grid systems make up the rest.
The policy toolkit was practical. Competitive reverse auctions through SECI and state agencies drove tariffs down to levels few countries imagined in 2014. The solar park model offered land, roads and evacuation in one place; fifty-six parks totalling about 39.5 GW have been sanctioned, and nearly 19 GW inside those parks has already been commissioned. Inter-state transmission charge waivers made it easier to move desert solar power to demand centres. The Production Linked Incentive scheme for high-efficiency modules has begun to reverse import dependence, with module manufacturing expanding sharply and cell and wafer capacity catching up. Household schemes, especially PM Surya Ghar: Muft Bijli Yojana, turned rooftop solar into a mass programme. Officials have said about one lakh homes a week are now installing systems under the scheme.
The wider renewable ledger looks similar. Renewable capacity rose from 76.38 GW in 2014 to 288.58 GW by 30 June 2026. Non-fossil capacity, including nuclear, crossed 300.50 GW on 31 July 2026 — more than 54 per cent of India’s total installed power capacity of about 552 GW, and over 60 per cent of the 500 GW non-fossil target for 2030 announced by Prime Minister Narendra Modi at COP26 in Glasgow. In FY 2025-26 alone India added a record 55.29 GW of non-fossil capacity, of which solar contributed 44.6 GW. Onshore wind also revived, reaching about 58 GW. Foreign direct investment into renewables since FY 2014 has been around USD 45.7 billion.
Solar worked because three things lined up at once: falling global module prices, a simple onshore construction model, and a government willing to keep auctioning gigawatts year after year. Offshore wind needs a fourth and fifth ingredient that solar never required — a marine industrial ecosystem and a risk-sharing design that banks will finance.
India took initiatives to offshore wind soon after the Modi government came to power. The National Offshore Wind Energy Policy was notified in October 2015. The National Institute of Wind Energy later identified about 70 GW of technical potential, almost all of it off Gujarat and Tamil Nadu. The government has spoken of 30 GW of offshore capacity by 2030 and of auctioning tens of gigawatts of seabed lease areas through the decade. India has more than 7,500 km of coastline and an exclusive economic zone large enough, on paper, to host a major marine energy industry.
Those numbers created an expectation that the first turbines would be in the water soon. That has not happened. Onshore wind is a mature Indian business. Offshore wind remains a file, a map and a cancelled tender.
The resource itself is not imaginary. Wind speeds off Tamil Nadu are among the better ones in Asia. Floating LiDAR measurements have suggested capacity utilisation factors in parts of that coast in the 45–60 per cent range, far healthier than the conservative assumptions used in the first Gujarat auction. Gujarat’s Gulf of Khambhat was studied earlier and more thoroughly, which is why the first funded pilot was parked there even though its expected plant load factor was weaker.
Policy paper after policy paper followed the 2015 notification: strategy documents in 2023, Offshore Wind Energy Lease Rules in 2023, viability gap funding in the Union Budget, and transmission studies by the Central Electricity Authority for an initial 5 GW each off Gujarat and Tamil Nadu. In June 2024, the Union Cabinet approved the Viability Gap Funding (VGF) scheme for offshore wind energy projects at a total outlay of ₹7,453 crore. This included ₹6,853 crore for installation and commissioning of 1 GW projects, and ₹600 crore for upgradation of two ports to meet logistics requirements for offshore wind energy projects.
However, what did not follow was a bankable project.
The market’s verdict arrived in August 2025. SECI had floated two landmark projects, a 500 MW ISTS-connected project off Gujarat’s Gulf of Khambhat, backed by viability gap funding, and seabed-lease rights for up to 4,000 MW off Tamil Nadu. Together they represented about 4.5 GW. The tenders were released in 2024, and were hailed as India’s entry into the sector.
The Gujarat tender notice was issued in September 2024. The successful bidder would have built the wind farm in an area of 202 square kilometres in the Gulf of Khambhat and entered into a power purchase agreement (PPA) with SECI for a period of 25 years. For the Tamil Nadu bid invited in February 2024, seabed areas for 4 GW of offshore wind capacity were proposed to be leased out, including identified sub-blocks 2, 3, 4, and 7 off the coast of Tamil Nadu in the Gulf of Mannar. The winning bidder would have been responsible for conducting seabed surveys and related development work to validate existing data sets for financial closure.
Bid deadlines were extended more than once, and the final closing date for bids were extended to 31 July 2025 for both the tenders. Interest still did not materialise. Both tenders were cancelled in August 2025. MNRE Secretary Santosh Sarangi later said publicly that there were “no participants” because the projects were financially and technically unviable under the terms on offer.
That cancellation is the single most important fact in India’s offshore wind story so far. It showed that a national policy, a potential map and a subsidy envelope are not the same thing as a project that Ørsted, RWE, Adani Green or a public-sector joint venture will actually bid for.
The failure is not one-dimensional. Cost is the headline. Design, infrastructure, regulation and global timing complete the picture.
Wind turbines can be installed on land, which are onshore wind turbines, while turbines installed in the sea are called offshore turbines. Almost all of India’s existing wind capacity is of onshore type. India has mapped a large offshore resource off Gujarat and Tamil Nadu but has not yet commissioned a commercial farm.
Both harvest the same resource, moving air turning a rotor, but the setting changes the machine. Onshore projects use roads, ordinary cranes and existing grid lines. A typical Indian onshore turbine is in the 2–6 MW range and can be built relatively quickly once land and connectivity are ready. Size is capped by what will fit under flyovers and across rural roads, and by noise, height and village setback rules.
Offshore work is marine engineering. Every foundation sits on the seabed, every blade is shipped from a heavy-lift port, and every cable is buried under the seafloor. That makes each project far costlier than onshore wind or solar. Because foundations, installation vessels and export cables attach to each turbine rather than each megawatt, developers install fewer, much larger machines — commonly 12–15 MW, with rotors more than 220 metres across.
Physics favours that scale. Power captured rises with the area swept by the blades; double the rotor diameter and potential harvest grows about fourfold. Sea wind is stronger and less turbulent than land wind, so taller hubs and longer blades pay off. One large offshore unit can therefore replace several onshore turbines and spread the marine bill over more megawatts. That is also why India’s onshore factories, built around 2–3 MW machines, cannot simply switch to offshore work.
Due to the reasons mentioned above, offshore wind is several times more expensive to build than the technologies India has already mastered. Typical industry estimates put Indian offshore capex at about ₹20–25 crore per MW. Onshore wind is closer to ₹6–8 crore per MW. Utility-scale solar is often under ₹5 crore per MW. The levelised cost of early Indian offshore power had been estimated around ₹9–10 per unit. Recent solar and onshore wind tariffs have been in the ₹2.5–3.5 range. Even in Europe, where the industry is mature, offshore power has often needed support near the equivalent of ₹8–10 a unit.
The first Gujarat auction tried to bridge that gap with viability gap funding and a pre-set tariff of about ₹4.50 per kWh. Think-tank Ember later calculated that even after the capped VGF, generation cost remained about ₹5 per kWh higher than the tariff on offer. Developers were being asked to eat a structural loss on a first-of-its-kind marine project. No serious bidder did.
There is a second cost problem: time. An offshore farm can take six to eight years from lease to first power. Solar farms in India are often built in 12–18 months. Capital sits idle longer, interest accumulates, and every delay in vessels, weather windows or grid connection compounds the damage.
Subsidies were not the only issue. The shape of the auction mattered. Ember and several developers pointed to the same design flaws. The government fixed both the buying price and the subsidy cap, which left no room when steel, turbines or interest rates moved. Developers were responsible for turbines, foundations and cabling to the offshore pooling substation, while state-owned Power Grid Corporation of India was to handle transmission inland. Ember concluded that the fixed tariff and a capped subsidy left little room for developers to balance revenue with initial cost assumptions.
The assumed capacity utilisation factor for the Gujarat site was about 36 per cent, below international offshore benchmarks of 40–50 per cent and below the readings for Tamil Nadu. Grid-delay risk was also only partly covered: developers could get more time if the Central Transmission Utility was late, but they would not be paid for lost generation. Bid-preparation windows of 100–120 days were tight for global firms that need six or seven months for internal investment-committee approvals.
Mature markets do not usually load all of that risk onto the first demonstration projects. The United Kingdom separates seabed leasing from the power-price auction. Several European transmission operators, such as the Netherlands’ TenneT, take grid-connection risk themselves. India’s first round looked more like a mature-market reverse auction than a market-creation exercise.
The project timeline stipulated in tenders required completion of the projects in four years. It was a highly ambitious deadline for the first offshore projects in the country, as the global norm is six to eight years, even in mature markets with an established ecosystem.
Compared to onshore wind turbines, installing turbines on the seabed takes a much longer time. Even the pre-construction phase can take place over 3-5 years. This includes feasibility studies, environmental planning, wind assessment, grid access and site layout. The phase requires seabed surveys, obtaining permits, and establishing the necessary infrastructure at the marshalling port and installation site.
The next phase of site conditioning, detailed design and procurement of materials can take a further 2-4 years. During this phase, various turbine components like blades, towers, nacelles and foundations are manufactured at various facilities and transported to the marshalling port near the project site for assembly. After that, construction can take a further 2 years, which starts with installation of the foundation. The foundation can be installed on the ground below water, or it can be a floating base anchored to the seabed, depending on the site depth and conditions.
After the foundation is ready, the turbine tower is erected, and turbines are mounted with cranes and specialised equipment. Electrical and mechanical components, such as cabling, transformers, and control systems, are connected after the turbines are installed. Therefore, it can take a total of 6-8 years for an offshore wind project to start generating power.
India can build 2–3 MW onshore turbines at scale. Suzlon, Siemens Gamesa’s Indian operations, Envision and others already serve that market. However, offshore machines are a different product: much bigger 10 MW-plus turbines, corrosion-resistant foundations on the seabed, specialised cables, and installation vessels that cost hundreds of millions of dollars.
India does not yet have a fleet of heavy-lift installation vessels, purpose-built assembly and marshalling ports with the right quay strength and draft, a local jacket or monopile fabrication cluster of North Sea or Chinese scale, or a deep bench of marine contractors who have installed arrays in monsoon-affected waters. That creates a chicken-and-egg problem. Manufacturers will not invest in Indian offshore factories until they see a multi-gigawatt pipeline. Developers will not bid aggressively until factories, ports and vessels exist. The first tenders asked the private sector to solve that loop alone.
An offshore farm is useless if the cable to shore and the ISTS pooling station are late. CEA has completed transmission planning for an initial 10 GW — 5 GW each off Gujarat and Tamil Nadu. That is only the necessary initial work. India’s onshore renewable boom is already straining evacuation in Rajasthan and other hubs; offshore projects would add a new class of high-voltage subsea and coastal infrastructure. Global bottlenecks in HVDC equipment make the calendar even less certain.
There is no clarity on ownership of the offshore grid system. The Offshore Wind Policy only requires the transmission utilities to undertake onshore evacuation and grid connectivity. The EOI requires the developer to set up the electricity transmission infrastructure from the pooling station in the sea till the point of connection to the onshore substation.
As per the terms in the cancelled tenders, if the grid connection was late, the developer would have to wait without any compensation for the delay. In a better-designed market, the system, the grid operator either delivers the connection on a fixed date or compensates the generator. The Netherlands and Germany delivered “ready-to-build” tender packages, full permits, geotechnical reports and grid connections in hand, reducing early-stage risk for developers.
Until such a principle is accepted, developers will be reluctant to commit, and lenders will treat Indian offshore power purchase agreements as incomplete.
As India’s existing grid network is insufficient to evacuate the potential power generated by offshore turbines, the govt had introduced The Green Energy Corridors Project, a dedicated power transmission network in India designed to evacuate and integrate electricity from renewable sources like solar and wind into the national grid. However, there have been delays in implementation of the project in many States, and the infrastructure has failed to keep pace with development of existing renewal projects like solar and onshore wind.
Offshore projects sit at the junction of energy, defence, shipping, fisheries, environment and petroleum. The 2023 lease rules created a legal path. However, they did not create a single-window culture. Developers still expect sequential rather than parallel clearances, disputes over fishing grounds, shipping lanes and marine ecology, and political sensitivity around coastal communities.
Before a seabed lease is granted for surveys or projects, developers must secure approvals from as many as six authorities: Ministry of Defence, Ministry of Home, Ministry of External Affairs, Ministry of Environment, Forest and Climate Change, Ministry of Ports, Shipping and Waterways, and Department of Space. While the National Institute of Wind Energy is required to take in-principle clearance from relevant authorities before offering an offshore wind block for bidding, the successful bidders are required to obtain the further clearances/NOCs from all relevant authorities. Moreover, additional clearances may be required from the State Government for creating evacuation infrastructure, logistics, etc.
Construction deadlines written into lease rules, broadly three years, extendable to five, will be hard to meet if one ministry sits on a file.
The government has accorded ‘Must-run’ status to solar and wind power as per clause 5.2(u) of Central Electricity Regulatory Commission (Indian Electricity Grid Code) Regulations, 2010. This means, solar and wind power plants can’t shut down for commercial reasons, they can be shut down only for reasons of grid safety and security, that too after communicating such reasons. However, in the last few years, there has been an irregular curtailment of wind power. The onshore developers in the State Tamil Nadu and Andhra Pradesh have suffered substantial financial loses due to this.
Therefore, the government should have established the grid network to evacuate power from offshore turbines before announcing such decisions.
This is the political-economy point that official presentations underplay. Once solar tariffs collapsed, every additional rupee of public support and every extra ISTS line produced more megawatts on land than at sea. Discoms, understandably, prefer cheap power. Finance ministries prefer schemes that show commissioned capacity before the next election. Developers prefer projects that close in two years, not eight.
Offshore wind was never going to beat solar on price in the 2020s. It can still justify itself as firmer coastal generation, a hedge against land constraints, and a strategic industrial bet. That case was not made strongly enough in the first auction design. The result was a policy that existed on paper while the real machine of Indian renewable policy — SECI auctions, ISTS waivers, production-linked incentives and rooftop subsidies — kept feeding solar.
India tried to open a new offshore market just as the global industry hit a wall. After 2022, higher interest rates, dearer steel, scarce installation vessels and snarled supply chains forced cancellations and renegotiations across the United States, the United Kingdom and parts of northern Europe. Several governments discovered that auction prices set in cheaper years no longer covered the cost of building a offshore wind farm.
The United Kingdom’s 2023 allocation round, once a model for the world, attracted no bids until the strike price was raised. Non-Chinese turbine makers booked large losses. Ørsted, the sector’s best-known developer, suffered a well-publicised squeeze and narrowed its map. An untested Indian auction with a tight tariff and an uncovered cost gap was not where such firms wanted to take more risk.
The United States then turned from a promised second home market into a political hazard under Donald Trump. From January 2025 the Trump administration withdrew federal waters from new wind leasing, tightened tax credits, tried to halt East Coast projects already under construction and is paying around $4 billion to developers to surrender leases. The Trump administration has vowed to shut down wind turbines in the country, not allow any new ones to be built, in favour of fossil fuels. However, courts have kept a few farms that were already being built alive.
Forecasts for American offshore capacity by the mid-2030s collapsed. European developers that had booked US assets took impairments and became more cautious everywhere else, including in countries still trying to hold their first auctions.
However, Europe did not need Washington to lose momentum. Grid delays, harbour bottlenecks and the day-rate of the few ships that can lift a 15 MW nacelle kept lifting costs even where policy stayed supportive. Several North Sea governments had to rewrite contracts or add inflation indexation. The International Energy Agency cut its global offshore outlook to 2030 by more than a quarter, citing American policy, weak European economics and supply-chain strain together.
China kept installing and still accounts for most new capacity. That only underlined the problem for everyone else: the industry’s centre of gravity stayed in a market that uses its own factories and developers, while Western firms had less capital and less appetite for first-of-a-kind projects abroad. Emerging markets felt that chill directly.
None of these excuses a badly designed Indian tender. The global industry was already expensive, politically jumpy and short of vessels. New Delhi asked it to enter a new country on thin margins at the worst moment of the decade.
Despite the setback, New Delhi has not abandoned the file. After the 2025 cancellations, the Centre has tried to reset the first phase rather than announce another grandiose target. Officials have themselves said the envelope may still need to be sweetened if tariffs are to meet discom expectations.
MNRE and SECI have been working on a redesigned auction for the second half of 2026, either as two 500 MW bids or one 1 GW award. The Union Ministry of New and Renewable Energy plans to issue a tender for the Tamil Nadu coast. More reliable data for the site has been obtained after the completion of a wind data assessment using floating LiDAR by the National Institute of Wind Energy. The tender was scheduled to be finalised by May-June, but the ministry is still evaluating the matter.
As the private sector has been reluctant to enter the sector, the govt has asked public sector giants ONGC and NTPC to develop offshore wind projects on nomination basis. NTPC and Oil and Natural Gas Corporation have already signed a Memorandum of Understanding (MoU) to set up a Joint Venture Company for Renewable Energy business. ONGC’s experience in offshore oil rigs can be valuable in setting up offshore wind turbines.
Transmission issues are also being sorted out. CEA’s 5-plus-5 GW transmission studies are on the table. Inter-State Transmission System (ISTS) charge waivers for offshore projects have been extended for a longer window than for some other technologies, which recognises the longer gestation for offshore wind. The 2023 Offshore Wind Energy Lease Rules gave the legal basis for seabed rights. The Bureau of Indian Standards has begun aligning turbine design standards with IEC norms. Two ports in Gujarat and Tamil Nadu are slated for logistics upgrades under the VGF package.
International partnerships have also been revived. India and Denmark have had a technical collaboration since 2019. In February 2026 India and the United Kingdom launched an India–UK Offshore Wind Task Force covering market design, infrastructure, supply chains and finance. Cooperation with the European Union on offshore wind and green taxonomy has also been announced. They can transfer auction design and port-planning lessons. Tamil Nadu has discussed buying offshore power at a premium to ordinary renewable tariffs.
None of this is yet a project. It is a second attempt to create one.
If the 2026 tenders are only a reprint of 2024 with a slightly larger cheque, they will fail again. The international record is fairly consistent about what first-generation offshore markets need.
The revenue gap has to be closed honestly. That means either raising viability gap funding, allowing a higher discovered tariff, or moving to a contract-for-difference model of the British type, where the generator is guaranteed a strike price and the government or offtaker settles the difference against the market. A predetermined ₹4.50 tariff plus a capped grant is not a market-creation instrument.
The first sites should be made ready to build. Government should finish or heavily de-risk surveys, environmental baselines, defence clearances and grid connection before asking for bids. Developers would then compete on execution and price, not on who can guess the clearance calendar. Transmission risk should also shift. If the Central Transmission Utility or Power Grid is late, the project should receive deemed-generation payments. That single clause would change how banks model the first gigawatt.
A multi-year seabed pipeline needs to be published. A single 500 MW project will not justify a jack-up vessel or a turbine blade factory; a visible 8–10 GW leasing timetable through 2030 might. Marine spatial planning should map fishing, defence and shipping before the next lease, not after. The two identified ports should be built as industrial projects rather than afterthoughts. Marshalling ports, laydown yards and channel depth are as central as the turbine. China and Taiwan treated ports as part of industrial policy. India should too.
Localisation should come in stages. Demanding high domestic content on day one will only inflate cost. Towers, steel and cables can come first; nacelles and installation vessels can stay flexible until volumes exist.
Public-sector initiatives may be needed for the pilot. The ONGC–NTPC joint venture should start work on offshore wind soon. A well-governed public-private structure with sovereign-backed offtake will build confidence in the sector.
Above all, India should not pretend offshore wind will be as cheap as solar. It should be sold as complementary power: higher capacity factors, coastal demand centres, less land conflict, and an industrial capability the country does not yet have. If the only test is paise per unit, solar will win every time and the turbines will stay on the deck.
India does not need to copy anyone’s politics. It does need to copy the sequence that worked.
Denmark created the industry. Consistent state support, early demonstration farms and a home market for companies like Vestas and Ørsted produced the skills that the rest of the world later hired. The lesson is patience plus a domestic launch pad.
The United Kingdom became Europe’s scale leader through Contracts for Difference. Developers bid a strike price and revenue is stabilised for about fifteen years. Costs fell sharply across allocation rounds as the pipeline became visible. The UK also learned the hard way, in 2023, that if auction parameters ignore inflation and supply-chain costs, even a mature market can attract zero bids.
The Netherlands took grid risk away from generators. TenneT builds the offshore connection and developers bid to fill a socket that the state has already committed to deliver. India’s first tender did the opposite.
China used industrial policy at continental scale: provincial targets, state-owned developers, rapid port and vessel build-out, and a huge domestic market that absorbed high early costs. China now dominates global installed offshore capacity. The model is not fully portable — India does not run energy the way Beijing does — but the lesson on supply-chain sequencing is portable.
Taiwan is the closest emerging-market. It used feed-in tariffs and localisation rules to pull European developers in, then built an operations hub around the Port of Taichung. Repeated award rounds mattered more than one perfect auction. Ørsted’s continued commitment there is often contrasted with its caution on India: Taiwan offered a pipeline and a workable offtake; India’s first round offered a gap.
The World Bank’s work on emerging-market offshore wind keeps returning to the same checklist. A country needs a national strategy that says why it wants this industry, realistic multi-year targets, marine spatial planning, and a leasing, permitting, offtake and grid package with clear owners, plus revenue stabilisation for the first projects. India has fragments of that list. It has not yet assembled the package.
GWEC’s recent global reporting still treats India as an early-stage market with no commissioned offshore capacity. Its base case has slipped towards first commissioning in the early 2030s and only a couple of gigawatts by 2035 unless policy changes faster than it has so far. That is a long way from a 30 GW-by-2030 goal set earlier.
The honest forecast is therefore two-tracked. If the redesigned 1 GW round offers a real revenue floor, takes grid risk off the bidder, and comes with a port and a five-year lease calendar, India can still open the market — late, expensive, but open. Coastal states would get a new industrial skill. The 500 GW non-fossil target would gain a generation source that does not need more desert land. India has already proved, in solar, that policy plus scale plus auctions can rewrite an energy sector in a decade. Offshore wind is asking for a harder version of the same discipline: more patient capital, more state risk-bearing at the start, and less faith that a potential map is the same thing as a project.
Lower per-tonne freight costs, sharply lower fuel use, multimodal terminals, Jalvahak incentives and private investment are shaping a system in which heavy cargo can move by river for the longest, most efficient leg of journeys.
Ask who owns a stretch of national highway, or an embankment, or the tunnel wall at Silkyara. The honest answer is often several departments, none of whom will admit it first. A road, a bridge, a drainage channel should each belong to one named office, the kind that gets credit when it holds and blame when it doesn’t.
India’s goal now should not be just to become a ‘Builder’s Navy’, but a ‘Fast Builder’s Navy’. This means freezing designs, placing large orders together and never letting shipyard assembly lines sit empty.
Selected issues, clear explanations and thoughtful perspectives—delivered when we publish.
