The "duck curve" is the standard shorthand for what happens to a power grid as solar capacity grows: net demand (total demand minus what renewables supply) sags in the middle of the day as solar output peaks, then ramps up sharply in the evening as the sun sets and demand hasn't. A 2023 CSEP working paper analysing high-resolution 2019 Indian grid data confirms the pattern is already visible here, and warns it will sharpen: "renewable energy's contribution to net demand is lower at periods of high net demand, especially the evening peak," and "storage, or an alternative peaker, would be required to meet the evening peak." The same paper notes that roughly 90% of India's power is still not priced through mechanisms that reflect these real-time grid conditions — a gap the country's Time-of-Day tariff rules, discussed below, are only now starting to close.

The demand side of that evening ramp is increasingly a residential story, not a commercial one. A 2018 Centre for Science and Environment analysis of Delhi's summer electricity demand — cited here for the structural pattern it documents, not as current data — found that late-night demand exceeded afternoon demand on 21 of 31 days in May of that year, driven almost entirely by air conditioner use after commercial establishments had closed; the average day peak (5,280 MW) and average night peak (5,256 MW) were within 0.5% of each other. Whatever the exact numbers look like in 2026, the underlying mechanism — cheap subsidised power plus rising AC ownership plus heat-trapping building design equalling a genuine night-time demand peak — has no obvious reason to have reversed.

India's Ministry of Power notified the Electricity (Rights of Consumers) Amendment Rules, 2023 on 14 June 2023 (G.S.R. 437(E)), mandating Time-of-Day (ToD) tariffs nationwide. Under the rule: peak-period tariffs for commercial and industrial consumers with demand over 10 kW must be at least 1.20 times the normal tariff, and at least 1.10 times for other consumers; "solar hours" — an 8-hour daily window specified by each State Commission — must be priced at least 20% below the normal tariff; and peak-hour duration cannot exceed the solar-hours duration. The rule took effect for larger commercial and industrial consumers from 1 April 2024, for other consumers (except agricultural) from 1 April 2025, and immediately upon smart-meter installation for metered consumers.

That last clause matters more than it looks. For the mass of smaller consumers, ToD only bites once a smart meter is actually installed, and India's rollout is still mid-flight: the country has set a goal of installing 250 million smart meters by 2026, and as of a July 2025 industry summary, ToD "adoption is still under consideration by various state regulatory bodies and has not been uniformly implemented across states." A national-level academic literature review on dynamic tariffs for Indian residential consumers, published by researchers at the Council on Energy, Environment and Water in 2024, frames the same rollout as tied directly to the country's renewable-integration math: with India targeting 500 GW of non-fossil capacity by 2030 and variable renewables expected to exceed a 50% share of the generation mix by 2029-30, the "potential supply-demand mismatch" this piece describes as the duck curve is exactly the problem dynamic and time-of-day pricing is meant to solve — but the CEEW review's own emphasis is that DISCOMs "must have a deep understanding of consumer attributes before implementing dynamic tariffs," which is a slower, more deliberate process than a single gazette notification can complete on its own. In practice, the price signal analysed in Section 2 is still reaching only part of the consumer base it was designed for.

Read plainly, this is a tariff structure that pays a real premium — 10 to 20% above normal, and by construction more than 20% above the discounted solar-hour rate — for electricity supplied outside the solar window. Biomass power, unlike solar, can be dispatched into exactly that window. It is, on paper, one of the more direct beneficiaries the ToD rule could have created for a renewable generator.

It didn't show up. The Ministry of New & Renewable Energy's state-wise installed renewable capacity table, dated 31 July 2026, puts India's total bio-power capacity (biomass power/bagasse cogeneration, biomass cogeneration non-bagasse, and waste-to-energy, on-grid and off-grid combined) at 11,747.57 MW — against 164,594.75 MW of solar and 58,136.89 MW of wind. Comparing that to the CSEP paper's December 2019 breakdown (sourced to the Central Electricity Authority), bio-power capacity has grown only 19% in roughly six and a half years, while solar capacity nearly quintupled (+384%) and wind grew 55% over the same window. Excluding large hydro from both years for a fair comparison, India's total non-hydro renewable capacity grew 178% between the two dates — bio-power's growth rate was roughly a ninth of that.

2019 figures per CSEP Working Paper 58 (Tongia, Dave & Dalal, 2023), citing CEA's Executive Summary on Power Sector (2019/2020). 2026 figures per Ministry of New & Renewable Energy's state-wise installed capacity table, dated 31 July 2026. Both years exclude large hydro for comparability, since large hydro is tracked and reported separately from the "new RE" category in Indian government statistics.

The result: bio-power's share of India's non-hydro renewable capacity has fallen by more than half, from 11.4% in 2019 to 4.9% in 2026, even as the category it should complement — intermittent solar — came to dominate the mix even more completely, rising from 39.5% to 68.7% of the same total. A grid getting steadily more solar-heavy is, by the CSEP paper's own logic, a grid with a steeper evening ramp and a growing need for exactly the kind of dispatchable renewable supply that isn't scaling.

The state-wise breakdown shows where what little bio-power capacity exists is concentrated: Maharashtra, Uttar Pradesh and Karnataka between them account for roughly 62% of India's total, almost entirely through sugarcane-bagasse cogeneration attached to existing sugar mills rather than purpose-built biomass power plants.

Per-state Bio-Power Total figures per MNRE's state-wise installed-capacity table as on 31.07.2026, which reports a pre-computed Bio-Power Total column per state (summing bagasse cogeneration, non-bagasse biomass cogeneration, and waste-to-energy on- and off-grid); used here in preference to an earlier attempt at reconstructing state totals from a March 2026 table that dropped zero-value columns inconsistently in extraction.

The Central Electricity Regulatory Commission's proposed RE Tariff Order for the third year of the current Control Period (FY2026-27) sets the normative capital cost for a Rankine-cycle biomass power project at ₹638–744 lakh per MW depending on cooling technology and feedstock (rice straw/juliflora-based projects cost more), assumes an 80% plant load factor, and prices in a biomass fuel cost that escalates 3.45% a year from state-specific baseline prices (₹4,262.57 per tonne in Andhra Pradesh and ₹4,852.24 per tonne in Haryana, for example). Run through CERC's levellised-tariff methodology, the resulting applicable tariff for a standard water-cooled, travelling-grate-boiler biomass plant comes out to roughly ₹9.6–11.1 per kWh across the major biomass states — split into a levellised fixed-cost component of about ₹3.4–3.5/kWh and a variable fuel-cost component of ₹6.3–7.6/kWh that dominates the bill.

That figure is the real explanation the ToD story alone doesn't supply. A 10–20% peak-hour premium is a percentage of the "normal tariff" a state commission sets — for competitively bid solar and wind power in India, that normal tariff typically sits in the ₹2.5–3.5/kWh range, several times lower than biomass's own levellised cost before any ToD premium is even applied. A 2018 study on biomass pellet-based power generation in India, published by CEEW-affiliated researchers, reached an independent version of the same conclusion from a different angle: the levelised cost of biomass-pellet electricity was estimated at €0.12 per kWh, "even higher than the cost of imported coal-based electricity," with viability hinging on feedstock surplus, transport distance from farm to plant, and cooling technology — the same variables CERC's cost norms are built around. Two structurally different pricing exercises, run seven years apart, arrive at the same basic verdict: biomass power in India is expensive to generate on its own economics, well before anyone gets to ask whether a night-time tariff premium can close the gap.

Biomass power's slow growth almost certainly has causes this piece's sourcing doesn't cover in depth — feedstock logistics and year-round agricultural-residue supply chains beyond the state-level fuel-price table above, existing power purchase agreement structures that may not yet reflect ToD pricing at the generator level, and the practical lag between a 2023-24 tariff rule taking effect and a biomass plant being financed, built and commissioned. One structural cause is now clearer, though: the ToD price signal itself is still incompletely deployed, gated behind a 250-million-smart-meter rollout target for 2026 and uneven state-by-state regulatory implementation, so a meaningful share of the consumer base a biomass generator might sell peak-hour power to isn't actually paying ToD rates yet. What this piece does establish is that the cost gap is large enough that the ToD premium looks unlikely to be the deciding factor on its own: a plant charging ₹9.6–11.1/kWh needs a buyer willing to pay that rate, ToD premium or not, and this piece's sourcing doesn't cover who is actually signing power purchase agreements at CERC's normative biomass tariff versus how much biomass capacity is being built by sugar mills for captive/bagasse-cogeneration use, which follows different economics entirely.