From pv magazine 04/2021
Large-scale solar projects are key focus areas for India as it strives to accomplish its “100 GW by 2022” solar target. The nation has floated a number of ambitious solar tenders larger than 500 MW in size, but not all of them have been successful. While some tenders were oversubscribed and broke previous tariff records, the 7.5 GW tender in Ladakh never even reached the auction stage. And Gujarat’s 700 MW in Dholera Solar Park was canceled, even after projects were awarded.
Sourya Choudhary, senior director and head of the utility business for AMP Energy India, attributes the feasibility or success of any auction to the pre-auction planning and the tender structure itself. Choudhary says there are many considerations, with Indian project developers weighing up the availability of large tracts of contiguous land, grid infrastructure readiness, consistency and clarity on policies, and the availability of low-cost funds, as well as solar module prices. These are key factors to consider for any independent power producer trying to make an investment decision.
The 7.5 GW Ladakh tender is a classic example of how some, or all of these factors can dictate a developer’s response. The tender had some good things going for it. For example, Solar Energy Corporation of India (SECI) was the offtaker, large tracts of land are available in Ladakh, and the region also enjoys high solar irradiation. However, the bid structure, inappropriate risk allocation, and prohibitive entry barriers for the sizing of bids hampered its success.
Choudhary said that a solar power producer considering investment in the Ladakh tender would be dissuaded by tender conditions that left it responsible for the grid build-out required to connect the project and export power. Moreover, the terrain in the region is some of the most challenging in India, and in addition to that, Ladakh developers were only supposed to participate with projects starting at a prohibitive 2.5 GW in size.
If that wasn’t enough, though large tracts of land are available, the land in Ladakh was seldomly of the flat and easily accessible type that has been used for solar parks elsewhere in India – whether in Rajasthan, Karnataka, or Andhra Pradesh, making working conditions difficult.
On the project finance side there were more difficulties. Lenders would likely be uncomfortable in financing such complex projects. And given the challenges, the relevant distribution company was thought to be uncomfortable with the relatively high tariffs achieved as a result.
Given all of these factors, it should come as little surprise that the tender went unsubscribed, and the government withdrew it.
“The core competency of a solar project developer is to construct a solar power plant and run it profitably,” said Choudhary. “When you ask such an entity to develop a complex transmission project, then immediately the risk allocation is improper, and the resultant outcome will not be the best possible scenario.”
As demonstrated by the Ladakh example, pre-auction planning must ensure the bankability of the power purchase agreement (PPA) and, very importantly, allocate risks appropriately. The pertinent risk parameter ought to be allocated to the entity which is best positioned or best placed to mitigate it.
The offtaker’s track record in terms of timely payment and its history toward honoring contracts enables the bidders to calculate the risk involved while planning their bids – bids that pay off when well managed. Subrahmanyam Pulipaka, the chief executive officer of the industry body the National Solar Energy Federation of India, cites the example of Gujarat’s 500 MW solar auction that yielded a record-low tariff of INR 1.99/kWh ($0.027/kWh) at the end of 2020.
Gujarat was able to attract such low bids because of offtaker Gujarat Urja Vikas Nigam’s history of timely payments – facilitating access to cheaper project finance.
Curtailment risk also factors in. Even though solar power plants are accorded must-run status in India, some states have issued “backing down” or curtailment instructions to generators – for both technical and commercial reasons – discouraging investment.
Utility-scale solar is cost-effective for big solar developers as large, consolidated facilities provide economies of scale. However, this requires a great deal of land, preferably flat, in sunny open areas.
Raghav Gupta, Jakson Group’s vice president-solar EPC, describes land availability as the gray area of the golden [solar] mine – forcing many developers, specifically those with a multinational presence, to withdraw from EPC or independent power producer (IPP) activities in India. Land acquisition is a painstaking process, especially when it conflicts with agricultural usages.
“Land acquisition in India is a messy process,” said Gupta. “To maneuver around it, you can’t always stay in the white zone. You have to jump into the gray zone, which not everybody will be willing to do. Land acquisition is unclear, and the situation is different for different regions. It is unpredictable in terms of prices and timeline too.
“Also, even after sales, people could create problems, which would hamper the project’s progress. Sometimes issues arise even after the project has been commissioned,” added Gupta.
In most Indian states, the ideal sites for ground-mounted solar, closest to the existing grid connections, will often be the most valuable for agriculture. Developing projects in the state of Rajasthan, which has huge tracts of unused, barren, and affordable land, requires developing a transmission network that can support the export of solar energy to the state and national grids.
Gopal Somani, a former director of Jaipur-based Rajasthan Renewable Energy Corporation Ltd. (RRECL), sets out the key challenges.
“The grid connection and safe evacuation of solar power generated from [remote areas] will need additional costs and much more time to create new transmission infrastructure. This apart, there has always been a gap for power evacuation systems to be in place when solar plants are ready for grid connection. The utilities do not compensate deemed generation for such delays in the power purchase agreement (PPA). Thus the project economics sink,” Somani said. “
Mega solar farms – built at locations that are often remote, such as Western Rajasthan or the Rann of Kutch, supply 100% of their output to the existing grid at distant points of load centers. This makes managing the existing grid more difficult when solar penetration increases, forcing a partial evacuation and curtailment during peak solar generation.” Somani said an average 6-9% curtailment has been experienced for such projects over the last three years.
While hardly a new feature of the Indian solar marketplace, the imposition of import duties on solar components, to support local manufacturers, has raised its head again as a formidable threat to large-scale project development in the country. Clearly defined policies and timelines around import duties help developers calibrate the resultant impact or risk to the projects and take appropriate measures.
India’s government has been working at reducing import dependence by way of imposing import duties. The safeguard duty on solar cell and module imports is supposed to be abolished by the end of July this year, but there is a lack of clarity around its extension and applicable rate.
A basic customs duty (BCD) of 40% on modules, and 25% on cells, will go into force from April 1, 2022. India’s finance ministry has already approved the proposal. Developers see the customs duty rates as too high and fear these would raise costs for project installation, raising energy costs.
Care Ratings analysts estimate that prices applied to solar cell and module imports for solar electricity could increase 20% as a result of the new custom duty regime. The tariff could rise by INR 0.25-0.30/kWh if only cells are imported, and INR 0.40-0.45 paisa/kWh in case modules are directly imported, according to the Care analysis.
“The impact can be looked at in two angles, as the already bid-out projects and the future projects which shall be bid-out,” commented AMP Energy India’s Choudhary. “As far as the already bid-out projects are concerned, there are clearly defined formulas and tender clauses that allow for a pass-through. As far as the developers of the previous bid projects are concerned, the developer’s risk is mitigated because the pass-through would be there.
“However, in the same context, what needs to be evaluated is whether the resultant increase in the tariff is acceptable to the end procurer (distribution company), and if not, what are the ways to mitigate it,” Choudhary added.
There could be a possible compromise position more amenable to project developers, local manufacturers and distribution companies alike. Some incentivization to local manufacturing would help reduce the dependence on cell and module imports and make locally produced panels sufficiently competitive. Some sort of government payment to the distribution companies could compensate for the additional costs, and higher solar tariffs. Funding for such measures could be sourced from India’s Green Fund, Choudhary suggested.
Being capital-intensive, solar projects are financed mainly through debt finance. According to a report by India’s Council on Energy, Environment and Water (CEEW), about 75% of a solar project’s capital cost is financed using debt. Equity, the other principal financing instrument, accounts for around a quarter of the ticket price.
In India, debt finance for renewable energy projects generally incurs a 10-11% interest rate over a 16 to 18-year loan tenure. The CEEW report states that interest rates on debt finance vary depending on the credit worthiness of the offtaker, namely the PPA counterparty.
Interest rates are lower for solar projects involving more creditworthy offtakers such as central government offtakers, like the Solar Energy Corporation of India, state-owned NTPC, and Gujarat distribution companies.
Projects built in areas planned for solar park development, rather than those on developer-acquired or leased land, attracts lower interest rates primarily due to lower land costs and reduced grid infrastructure risks. This again indicates the need to address the fundamental problem of payment delays by Indian distribution companies to generators, to reduce the perception of risk among lenders.
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