India Wind Energy Market Size & Share Analysis - Growth Trends and Forecast (2026 - 2031)

India Wind Energy Market Trends and Insights

Hybrid Renewable Auctions Accelerate Capacity Utilization

Hybrid tenders awarded 1,200 MW in Tamil Nadu and Gujarat in fiscal 2025, lifting combined plant-load factors above 35% and permitting developers to secure debt at 9.5% interest, 150 basis points below standalone wind benchmarks.^{[1]Solar Energy Corporation of India, “ISTS Hybrid Tranche-VIII Results,” seci.co.in} The Solar Energy Corporation of India’s eighth ISTS hybrid tranche cleared at tariffs between Rs 2.99 and Rs 3.04 per kWh (USD 0.036–0.037 per kWh), confirming that colocating wind and solar slashes balancing-of-system costs. Tamil Nadu’s 34.75 MW repowering-to-hybrid pilot doubled annual generation by replacing fifteen 1.5 MW turbines with five 3 MW machines paired with 10 MW of solar on the same site. Gujarat’s Kutch region benefits further because nocturnal wind peaks dovetail with strong daytime solar irradiation, which averages 5.5 kWh/m²/day, reducing curtailment risk. Moreover, hybrid structures sidestep state-level energy-banking caps that typically force generators to curtail during monsoon months, protecting revenue streams.

Viability-Gap Funding Unlocks Offshore Supply Chains

The Ministry of New and Renewable Energy earmarked Rs 6,853 crore (USD 820 million) to de-risk the first 1 GW of offshore capacity, split evenly between Gujarat’s Gulf of Khambhat and Tamil Nadu’s Gulf of Mannar, by fixing tariffs at Rs 4.5 per kWh (USD 0.054 per kWh). This subsidy persuaded Siemens Gamesa and Vestas to announce new blade and nacelle factories in Gujarat aimed at a 4 GW tender pipeline through 2028. Seabed surveys by the National Institute of Wind Energy indicate 70 GW of technical potential in 30 m–60 m depths, but evacuation remains critical.^{[2]National Institute of Wind Energy, “Offshore Wind Potential,” niwe.res.in} Power Grid Corporation of India is designing a 2,000 MW HVDC link from the Gulf of Khambhat to Saurashtra, yet land acquisition for converter stations delays commissioning until late 2027.^{[3]Power Grid Corporation of India, “HVDC Corridor DPR,” powergrid.in} Without that corridor, the 500 MW Gujarat pilot cannot reach financial close even though developers already hold seabed leases, underscoring the grid’s gatekeeper role.

Repowering Scheme Targets 5 GW–15 GW of Ageing Assets

India commissioned 25.4 GW of wind before 2010 using sub-2 MW turbines, creating an opportunity to add 5 GW–15 GW by replacing them with 3 MW–5 MW platforms. Tamil Nadu alone hosts 7.3 GW of repowering potential in districts such as Coimbatore and Tirunelveli, where land and grid access are intact. The December 2023 repowering policy mandates at least a 1.5× generation uplift, nudging developers toward 120 m hubs with 140 m rotors. Suzlon’s modular 3.15 MW S144 turbine, designed for narrow rural roads, emerged as the preferred repowering choice and already holds a 1,084 MW backlog. Still, forcing developers to decommission legacy turbines within six months of new-plant commissioning causes a revenue hiatus that smaller independent power producers struggle to finance without bridge facilities.

Green Hydrogen Policy Drives Industrial Wind Demand

The National Green Hydrogen Mission targets 5 million tons per year by 2030, spurring industrial buyers to secure high-load-factor wind power. NTPC reserved 1,320 MW of hybrid wind-solar capacity for its Pudimadaka ammonia plant in Andhra Pradesh, aiming for 70% annual availability. JSW Energy is committed to 3.8 GW of renewables, focusing on Gujarat and Rajasthan sites where wind capacity factors exceed 38%. Constant-load electrolyzers push developers to pair wind with four-hour batteries, as seen in SJVN’s 4,000 MW Rajasthan park that integrates 2,400 MW of wind, 1,600 MW of solar, and 800 MWh of storage. Twelve coastal hydrogen hubs are planned, with Mundra and Dahej alone expected to absorb 6 GW of dedicated wind by 2030. The willingness of industry buyers to sign 20-year contracts above Rs 3.5 per kWh (USD 0.042 per kWh) diminishes exposure to reverse-auction price compression.

Land Allotment Constraints in Karnataka and Maharashtra

Karnataka and Maharashtra contributed 2.1 GW of 2024 installations, yet now face forest-clearance backlogs that extend project schedules by 18–24 months. Karnataka’s Forest Department demands compensatory afforestation at double the diverted acreage, inflating per-megawatt land cost by up to Rs 10 lakh (USD 12,000). Maharashtra halted approvals in five talukas of Satara after title disputes with tribal communities froze roughly 800 MW of capacity. Developers pivot to Rajasthan and Gujarat, but lower wind speeds of 6.5 m/s at a 100 m hub height shave capacity-utilization factors by 8-10% compared with Karnataka’s 7.2 m/s profile. Repowering projects also stall because contiguous plots large enough for 140 m rotors are fragmented across multiple smallholders, elevating transaction complexity.

Grid Evacuation Delays for Offshore Wind

The 2,000 MW HVDC corridor from the Gulf of Khambhat to Saurashtra has yet to clear land-acquisition hurdles, pushing commissioning to 2027 and suspending financial close on the 500 MW Gujarat offshore pilot. Despite fixed tariffs and seabed leases, developers cannot finalize debt packages without grid visibility. Tamil Nadu’s Gulf of Mannar faces a similar bottleneck: the state transmission utility has not committed to a 765 kV onshore line, leaving bidders for the 4 GW offshore tender unable to model connection costs. Offshore’s capital intensity, Rs 12-14 crore/MW (USD 1.44-1.68 million/MW), magnifies delay risk because equipment and lease payments begin well ahead of revenue realization. Unless central planners fast-track grid links, offshore wind will remain a late-decade, rather than mid-decade, growth lever.

Segment Analysis

By Location: Onshore Dominance Persists, Offshore Emerges

Onshore capacity accounted for the entire India wind energy market in 2025, expanding by 3.4 GW that year and heading toward a 14.9% CAGR through 2031, underpinned by robust state PPA demand. Gujarat led 2024 installations with 1,250 MW, followed by Karnataka at 1,135 MW and Tamil Nadu at 980 MW, as these states maintained clear land and grid processes. Offshore contributes none of the installed base today, yet a 1 GW funded pilot, 500 MW each in Gujarat and Tamil Nadu, targets commissioning by 2028 once the Power Grid evacuation link activates. National seabed surveys suggest 70 GW of technical potential at moderate depths, highlighting a long-run expansion vector for the India wind energy market.

Domestic OEMs dominate the onshore supply chain from blade fabrication in Gujarat to nacelle assembly in Himachal Pradesh, enabling six-month delivery cycles.^{[4]Suzlon Energy, “Q2 FY25 Investor Deck,” suzlon.com} Projects in Rajasthan and Andhra Pradesh now serve dedicated green-hydrogen complexes, pairing 2,400 MW of wind with solar and storage to guarantee 70% annual availability. Offshore’s higher capacity factors, 45-50% compared with 25-30% onshore, could unlock premium tariffs once grid bottlenecks clear, but developers remain wary of the 40% capex premium and limited installation vessel availability. Consequently, most capital will continue to favor onshore repowering and hybrid assets until 2027.

Note: Segment shares of all individual segments available upon report purchase

By Turbine Capacity: Migration Toward 3 MW–6 MW Platforms

Machines up to 3 MW held 59.5% of the India wind energy market in 2025 because earlier-generation models populate the legacy fleet. Yet turbines rated 3 MW–6 MW are accelerating at a 21.4% CAGR through 2031, driven by independent power producers seeking superior economics in Gujarat’s Kutch and Tamil Nadu’s Tirunelveli districts. Inox Wind’s 3.3 MW model with a 137 m rotor offers 15% higher annual energy production than its 3 MW predecessor while fitting the same foundation footprint, easing permitting.

Repowering rules mandating a 1.5× uplift effectively push developers to 3 MW–5 MW units with 120 m hubs, and Suzlon’s S144 turbine sells briskly into this niche. Corporate PPA buyers, such as data-center operators, prefer larger turbines that raise capacity factors enough to cut battery storage requirements. Goods-and-services tax adds up to USD 12,000/MW to these larger machines, but higher energy yields still raise internal rates of return by 50–100 basis points in Class II wind regimes. Turbines beyond 6 MW remain the preserve of offshore tenders that will not come online until grid links are ready, limiting near-term volume.

By Application: Utility-Scale Dominates, C&I Gains Momentum

Utility-scale projects made up 88.3% of the India wind energy market size in 2025 and are forecast to grow at a 17.0% CAGR to 2031 on the back of 25-year state PPAs and SECI’s 1,200 MW hybrid auctions. Tamil Nadu’s distribution company inked an 800 MW order at Rs 3.1 per kWh (USD 0.037 per kWh), and Gujarat’s state utility bought 600 MW at Rs 2.99 per kWh (USD 0.036 per kWh), providing tariff visibility. Hybrid rules that stipulate 80% annual availability lifted utility-scale internal rates of return to 12-13% compared with 10-11% for legacy standalone wind.

Commercial and industrial (C&I) off-takers, though smaller, are scaling quickly as firms sign 10-15 year corporate PPAs for round-the-clock green power. CleanMax manages a 1.4 GW PPA book that includes 400 MW of wind for pharmaceutical and automotive clients who prize fixed tariffs. Amazon’s Karnataka contract pairs 150 MW of wind with 100 MW of solar and 50 MWh of storage, achieving 85% availability without DISCOM banking. Community projects stay marginal because DISCOMs stipulate minimum PPA tranches of 25 MW, and the Central Electricity Regulatory Commission caps net-metered wind at 1 MW. That regulatory ceiling limits community economics, channeling most incremental capital to utility and C&I segments.

Note: Segment shares of all individual segments available upon report purchase

Geography Analysis

Tamil Nadu, Gujarat, and Karnataka collectively controlled more than 70% of installed capacity in 2025, with Tamil Nadu alone operating about 10 GW, followed by Gujarat at 9 GW and Karnataka at 7 GW. Gujarat’s Kutch district added 1,250 MW in 2024 thanks to 7.5 m/s wind speeds at 120 m hubs and a single-window process that compresses development to 18 months. Tamil Nadu’s Coimbatore and Tirunelveli districts delivered 980 MW in 2024, largely through repowering projects that swap 1.5 MW turbines for new 3 MW machines on existing pads. Karnataka installed 1,135 MW in 2024, but delays in forest clearances across Davangere and Chitradurga now redirect capital toward Rajasthan and Andhra Pradesh sites with more accessible land.

Rajasthan and Andhra Pradesh have emerged as secondary hubs driven by green-hydrogen demand. SJVN’s 4,000 MW park in Rajasthan integrates 2,400 MW of wind with 1,600 MW of solar to feed NTPC’s electrolyzers at Pudimadaka, while JSW Energy earmarked 1,200 MW in Andhra Pradesh for green steel production. Land in Rajasthan costs Rs 15-20 lakh/MW (USD 18,000-24,000/MW), substantially lower than Gujarat’s Rs 25-30 lakh/MW (USD 30,000-36,000/MW), though wind speeds are about 1 m/s weaker. Andhra Pradesh’s Anantapur and Kurnool districts, averaging 6.8 m/s, attracted 400 MW of 2024 additions despite transmission congestion that developers mitigate by on-site storage.

Offshore prospects center on Gujarat’s Gulf of Khambhat and Tamil Nadu’s Gulf of Mannar. The viability-gap funding program fixes tariffs at USD 0.054 per kWh for the first 1 GW, but without the 2,000 MW HVDC link, lenders will not release funds. Until evacuation hurdles clear, capital will favor onshore hybrids. The ministry’s transmission waiver reduced delivered tariffs in Gujarat and Rajasthan by up to Rs 0.50 per kWh (USD 0.006 per kWh), improving project IRRs by nearly 1 percentage point and reinforcing these states’ lead positions.