India's solar boom faces a new test as rising costs squeeze returns

Solar developers face higher costs from domestic cells, commodities and rupee depreciation, while competitive tariffs leave little room to absorb the increase, putting project economics under pressure

India’s utility-scale solar sector is entering a tougher phase. The cost of building projects is rising, while tariffs remain low after years of aggressive bidding.

 

An August estimate by ratings agency Icra states that utility-scale solar project costs could rise 20–25 per cent in the near term. In a separate report, Wood Mackenzie forecast a 20 per cent increase in utility-scale solar system prices by the fourth quarter of 2026. It cited constraints in domestic cell supply after the implementation of List II of the Approved List of Models and Manufacturers (ALMM).

 

Industry experts said developers that won projects when modules and other inputs were cheaper are now finding it harder to absorb the increase in costs because their tariffs have already been fixed.

  

The pressure is also affecting new investments. Developers are changing the assumptions they use while bidding, while lenders and investors are becoming more cautious about projects where final costs and returns remain uncertain.

 

The question that arises here is whether India’s solar boom, which was built on falling equipment costs and low tariffs, can continue to deliver the returns expected by developers and investors as project costs rise.

Why are solar projects becoming more expensive?

Prices of aluminium, copper and steel have risen over the past 12–18 months, increasing the cost of modules, cables, mounting structures and other project components.

 

The rupee has also depreciated by around 10 per cent against the dollar over the same period, said Uday Doshi, founder of renewable energy consulting and advisory firm Excelsior Engineering Solutions (EES). 

 

He said ALMM List-II, which requires domestically manufactured cells for utility-scale projects from June 1, 2026, has added another layer of cost.

 

An exemption until December 31, 2026 applies to net-metering and open-access projects, but utility-scale projects do not have the same exemption, he said.

 

"The ALMM List-II mandate requiring domestically manufactured cells for utility-scale projects from 1 June 2026 tightened cell supply and lifted prices," Doshi told Business Standard.

 

The concern now is whether domestic cell production can grow quickly enough to meet demand.

 

"With List-II cell supply still trailing module capacity, current price firmness is likely to persist and is expected to intensify once the transition window for the exempt segments closes at the end of 2026 and adds further demand to a constrained domestic cell market," Doshi said.

How is ALMM-II widening the cost gap?

The shift to domestic sourcing can sharply increase costs for projects that were originally bid on the assumption that imported cells would be used.

 

Sudharman Ezhil, director and CEO of Natrinai Ventures (NGE Green Energy), said the cost difference between a domestic-cell plant and a non-DCR plant is currently at least ₹70 lakh to ₹1.2 crore per MW.

 

"On a 50 MW project, that is ₹35–60 crore that was not in anyone's bid model," Ezhil said.

 

According to him, projects bid before mid-2025 assumed imported cells at ₹14–15 per watt. The same module using a domestic cell now costs ₹24–25 per watt, he said.

 

"That alone moves the total project cost by 15–20%," Ezhil said.

 

He said the issue is not limited to cost. "Cell manufacturing is far more complex than module assembly, process control, wafer quality, yield, and India's listed cell capacity is a fraction of its module capacity," he said.

 

Developers are therefore dealing with both higher procurement costs and uncertainty over the long-term performance of newly listed domestic cell lines.

Why are earlier low-tariff projects under pressure?

Projects awarded at tariffs of around ₹2.50–2.60 per unit were bid when costs were lower. Once a power purchase agreement is signed, developers have limited ability to pass on higher project costs through the agreed tariff.

 

"These projects were bid on a different cost base. When the cost of modules and other project inputs rises after the tariff has already been locked in, the developer has limited ability to pass that increase through to the contracted tariff," Doshi said.

 

"The immediate impact is therefore a compression of the project's financial cushion and equity returns," he said.

 

If the gap between the original cost assumptions and current costs becomes too large, the problem can go beyond lower returns.

 

"The tariff under the PPA does not automatically move up with the cost of the project, so the developer has to absorb the difference," Doshi said, adding, "Where that gap becomes too large, the issue moves beyond IRR compression to financial closure, procurement, and execution delays."

 

Industry experts said this puts older projects in a different position from new ones. New projects can be bid using current costs, while projects already awarded must work with tariffs fixed under earlier assumptions.

Why are investors and lenders becoming more cautious?

The change in project economics is also affecting financing decisions.

 

Ezhil said banks and investors have become more cautious, partly because they remain uncertain about the quality and bankability of output from newly listed Indian cell lines.

 

"Lenders underwrite 25-year cash flows, and they do not yet have degradation data or warranty comfort on these cells," he said.

 

According to Ezhil, this is leading to more conservative assumptions about power generation, tighter debt service coverage requirements and, in some cases, demands for developers to bring in more equity.

 

He cited the example of a 50 MW procurement project where the customer has land, connectivity and the intention to buy power, but the project remains stuck.

 

"Neither side can fix the capex, so neither side can fix the PPA tariff," Ezhil said.

 

He said the proposed storage mandate has created another uncertainty because investors cannot determine the final cost of the plant or the price at which its power can be sold.

 

"When both the numerator and the denominator are moving, capital waits," Ezhil said.

How are developers changing their bidding strategy?

Higher costs are affecting both projects that have already been awarded and those that are yet to be auctioned.

 

Developers have limited options for projects already awarded. Ezhil said some are absorbing the higher costs, renegotiating supply arrangements or slowing execution while waiting for possible regulatory transition measures.

 

"For projects awarded at ₹2.50–2.70 per unit on imported-cell assumptions, the cost has moved and the tariff has not," he said.

 

For new projects, developers are changing the cost assumptions used to calculate their bids.

 

"Nobody is pricing a plant at last year's cost base," Ezhil said.

 

He said commercial and industrial (C&I) open-access power purchase agreement (PPA) offers are already increasing by ₹0.30–0.50 per unit. The domestic content requirement (DCR) premium alone could increase utility-scale tariffs by ₹0.25–0.40 per unit, even before the cost of storage is included.

 

The change is also pushing some developers towards solar-plus-storage projects, where higher tariffs reflect the ability to supply power beyond peak solar-generation hours.

Could solar tariffs rise from here?

Doshi expects higher costs to show up in utility-scale solar auction tariffs. "ALMM List-II could lift tariffs by roughly 18-20 percent, enough to materially alter project economics and erase two years of tariff declines in a single procurement cycle," he said.

 

He estimated that tariffs may need to rise by around 10 per cent for projects to generate viable returns under the current cost structure.

 

But buyers may find higher tariffs difficult to accept. "DISCOMs are already managing debt and revenue pressures, and accepting higher procurement tariffs may not be straightforward," Doshi said.

 

The sector is therefore facing a gap between what projects now cost to build and what buyers have historically been willing to pay.

Does slower investment mean developers are losing interest in solar?

The change in economics has not led to a simple exit from the sector. Doshi said he is seeing more acquisitions and takeovers rather than companies completely stopping operations.

 

A project that appeared viable when it was bid can become less attractive if costs rise during construction, he said. In such cases, the original developer may exit, while another company acquires the project or platform.

 

Doshi cited the reported acquisition of Welspun New Energy by Purvah Green Power, valued at around ₹2,500 crore, as an example. Welspun had around 45 MW of operational capacity, 245 MW under construction and a 700 MW pipeline, he said.

 

He also cited Inox Clean Energy's August acquisition of Vena Energy India's renewable platform for ₹6,000 crore.

 

For the broader solar sector, the immediate question is whether projects can continue to attract capital at the returns that developers and investors expected when equipment costs were falling and tariffs were declining.

 

Project costs have moved higher, but tariffs on existing projects cannot automatically rise with them. New bids will have to reflect this change.

 

According to experts, this puts India’s solar market in a new phase, where future growth will depend not only on how much capacity can be built, but also on whether projects can generate returns high enough to attract the capital needed to build them.