The finance questions a fixed rupee tariff leaves open

Every rupee we earn passes through a buyer that is either a state distribution company or an agency that resells to one, so counterparty credit is the first risk I examine and the last I stop watching. My team maintains a scorecard for each of the eleven utilities and intermediaries we sell to. It draws on their payment record with us since 2019, their published accounts and tariff filings, the subsidy their state government has actually released against what it promised, and whether the letters of credit their contracts require are open and adequate. Published utility ratings inform it but do not decide it. The scorecard sets an exposure limit for each buyer, which our bid committee must respect. Every month I report receivable days by buyer, with legacy dues being paid in instalments shown apart from current billing, and we recognise late payment surcharge only when it is received or a settlement makes collection near certain.

Each of our plants sits in its own project company with its own lenders, usually financed with about 75 per cent debt during construction from banks and public-sector infrastructure lenders. Construction debt is expensive, and short against a twenty-five-year contract, so once a plant has a year of operating data I want to refinance it on terms that match the contract. My team runs one debt model across our thirty-four project companies, tracking covenants, debt-service reserves and repayment profiles, so that the board can see where a poor wind season or a slow-paying buyer would breach a coverage ratio before it happens. I also decide which plants are ready for refinancing and which need another year of evidence, because lenders price a plant's recorded output, not our forecast of it. Since 2021 we have refinanced ₹8,900 crore of project debt, lengthened average residual tenor from eleven to sixteen years and reduced our weighted average borrowing cost from 9.6 to 8.4 per cent.

Renewable assets suit green debt, but a green label does not change what a borrowing costs or when it must be repaid. In 2018 we issued a five-year dollar green bond through a restricted group of eight project companies, and it taught me how far the hedging premium and the refinancing date can outweigh the headline coupon. We repaid it in 2023 from rupee loans. In August 2025 we issued ₹1,500 crore of ten-year listed green debentures, amortising in line with the underlying power contracts, under SEBI's framework for green debt securities. That framework expects issuers to say how the proceeds will be used and to report on their use afterwards, and we appointed an independent reviewer to check our allocation to eligible projects. I report the allocation, and the generation of the plants it financed, to the Audit Committee every year. A green bond whose proceeds cannot be traced is a reputational liability, not a cheaper loan.

Our tariffs are fixed in rupees for twenty-five years, while for most of the last decade the solar modules in our plants were bought in dollars from overseas manufacturers. The exposure sits in a narrow window: between the day we bid a tariff and the day we pay for modules, usually twelve to eighteen months. Since 2023 our board-approved policy has required that every bid include the cost of forward cover for that window, or rest on a rupee-priced supply contract. Basic customs duty on imported cells and modules from April 2022, and the government's approved list of models and manufacturers that now governs many projects, have since moved most of our purchasing to Indian manufacturers. That has reduced our dollar exposure without removing risk, because a domestic supplier brings delivery delays, quality questions and its own dependence on imported cells and wafers. I now examine module suppliers' balance sheets as carefully as I examine our buyers'.

Most of our tariffs were discovered through competitive bidding and then adopted by the relevant commission: the Central Electricity Regulatory Commission for inter-state projects sold through central intermediaries, and the state commissions for contracts with their own utilities. The tariff itself rarely changes. Compensation for changes in law, for curtailment and for late payment can, and each is an accounting judgement before it becomes cash. When the GST rate on solar generating equipment rose from 5 to 12 per cent in October 2021, our claims for the extra cost were contingent assets under Ind AS 37: disclosed, with amounts and status, but not recognised until the commission had ruled and the buyers had accepted the computation. I apply the same discipline to curtailment compensation and to surcharge on overdue bills. I also prepare the annual impairment review of our oldest wind farms under Ind AS 36, a judgement that grows closer each year as turbines age and their original tariffs approach expiry.