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India’s Power Sector Transition: What the 2025 Coal Decline Tells Us About RE Integration, Grid Stability and What Comes Next

In 2025, India’s coal-fired power generation fell 3% — from 1,322 billion units to 1,283 billion units. It was only the second full-year decline in more than 50 years; the first, in 2020, was driven by the COVID-19 pandemic’s collapse of electricity demand. The 2025 decline was different: it was driven by structural growth in renewable energy, which for the first time began displacing coal not just at the margin but at the peak. Power sector CO₂ emissions fell 3.8%. India’s total CO₂ growth slowed to 0.7% — the lowest rate in two decades. Non-fossil electricity capacity crossed 52.57% of installed capacity in February 2026. These numbers mark a genuine inflection point. They also contain a paradox: India simultaneously intends to build 100 GW of new coal-based capacity by 2032, has 36 GW under construction, and is planning for coal to remain dominant in electricity generation well past 2040. This article maps the transition honestly — what has changed, what hasn’t, and what the grid flexibility and storage imperatives mean for industry.

By Reclimatize.in 30 March 2026 Power and Carbon Markets  ·  Policy Analysis

The 2025 numbers — India’s electricity mix in context

The full picture of India’s 2025 electricity generation shows a system at an inflection point — not a completed transition. Coal still dominates, accounting for approximately 70% of total generation. But the direction of movement is now clearly established, and the 2025 data confirms that the shift is structural rather than cyclical.

The divergence between total generation growth (+1%) and coal generation change (–3%) is the defining feature of 2025. It means that every unit of demand growth in 2025 was met by renewable energy or hydro — and that renewable growth additionally displaced existing coal output. This is the structural dynamic that researchers and policymakers have been waiting for: the point at which RE stops merely supplementing coal and begins actively displacing it.

CREA’s disaggregation of the coal decline is analytically important. Of the roughly 39 BU decline in coal generation: clean power growth directly replaced 44% (approximately 17 BU); milder temperatures — meaning lower air-conditioning demand — account for 36% (approximately 14 BU); and a structural slowdown in underlying electricity demand growth accounts for the remaining 20% (approximately 8 BU). The temperature effect is inherently reversible — a hot summer in 2026 could temporarily reverse part of the 2025 decline. But the clean power growth component is structural and accelerating: India added approximately 90 TWh of annual generation capacity from new clean energy additions in 2025 alone — double the record set in 2024.

India’s installed capacity in March 2026

India crossed 52.57% non-fossil installed capacity in February 2026 — a milestone confirmed in the Rajya Sabha by Shri Shripad Naik Ji, Minister of State for Power, on March 23, 2026. The 50% target under the Paris Agreement was met in June 2025, five years ahead of schedule. This is a significant achievement for India’s energy transition and a vindication of the sustained policy commitment to renewable capacity expansion under the leadership of the Prime Minister Shri Narendra Modi Ji.

Yet installed capacity tells only part of the story. Because solar and wind generate at lower capacity utilisation than thermal plants — solar operates for 4 to 5 hours at peak production per day; coal operates for 16 to 20 hours — 52.57% of installed capacity translates to a much lower share of actual electricity generation. Coal at roughly 47% of installed capacity still produced approximately 70% of electricity in 2025. This gap between installed share and generation share will narrow over the next decade as storage allows renewable output to extend beyond daytime hours, but it is the reason why India’s grid cannot simply switch off coal even as non-fossil installed capacity dominates the mix on paper.

Why coal still matters — and the flexibility imperative

Coal’s continued role in India’s electricity system is not a policy choice made in ignorance of climate commitments. It reflects three structural realities that cannot be wished away by capacity announcements.

Thermal baseload and the minimum technical load problem

Most coal-fired power plants in India operate with a minimum technical load (MTL) of approximately 55% of rated capacity. Below this threshold, coal plants face operational instability, turbine damage risk from temperature cycling, and significant heat rate penalties. This means that even during the middle of the day when solar output peaks, coal plants cannot simply be turned off — they must continue running at roughly half their rated output at minimum. The consequence is avoidable curtailment of solar and wind generation: when solar output is high and demand is relatively low (midday, mild temperatures), the inflexibility of coal forces grid operators to curtail cheaper renewable generation rather than reduce coal output below MTL.

CREA’s 2025 analysis documents this dynamic clearly: India’s coal generation in 2025 fell despite rising installed coal capacity because a combination of milder weather, slowing demand, and growing RE reduced the need to dispatch coal during hours when it previously would have run at high utilisation. But coal could not be fully displaced because of the MTL floor. Coal flexibilisation — engineering modifications to lower the MTL from 55% to 40% — costs approximately 5 to 10% of total baseload plant costs and is technically mature. Extending this retrofit across India’s ~200 GW coal fleet would require tens of billions of rupees but would unlock significantly higher RE penetration by reducing the must-run floor.

Peak demand and the evening ramp

India’s electricity demand follows a double-peak daily pattern: a morning peak as industrial and commercial activity begins, and a larger evening peak (typically 6 to 10 pm) as solar output falls to zero while household and commercial lighting, cooling and appliance use remains high. The evening peak is the defining challenge for a solar-dominated RE system. Without significant storage, the evening ramp — the sharp increase in demand that must be met in the hours after sunset — requires dispatchable thermal or hydro capacity. In 2025, solar contributed up to 60 GW during daytime peak hours on high-demand days, substantially reducing coal’s role during the day. But the evening ramp remains coal’s stronghold.

Battery energy storage systems with four to eight hours of discharge duration are the primary solution to the evening ramp problem. India currently has approximately 500 MWh of operational battery storage — trivial relative to the scale of the evening ramp challenge. With 9,650 MW of BESS under construction as of March 2026, the picture will change materially over the next two to three years. But the gap between current storage and the storage needed to fully replace coal’s evening supply role remains large. Until that gap is closed, coal’s role in providing firm, dispatchable evening power is both real and irreplaceable in the near term.

Long-term PPAs and stranded asset risk

India’s coal generation is bound by a web of long-term power purchase agreements (PPAs) between coal-based generators and distribution utilities. Many of these PPAs were signed for 25-year terms in the 2000s and 2010s, when coal was the dominant cheap electricity source and renewable PPAs barely existed. Under the terms of these agreements, utilities must pay capacity charges to coal plants whether or not they dispatch the electricity — meaning the financial obligation to coal continues even if grid operators would prefer to dispatch cheaper renewable power. Breaking or renegotiating these PPAs requires regulatory orders, legal challenges, and compensation negotiations that can take years. The long-term PPA structure is thus a significant lock-in mechanism that delays the practical displacement of coal beyond what the installed capacity picture might suggest.

The government’s position — phase-down, not phase-out, with new coal planned

India’s official position on coal in international climate negotiations is “phase-down” rather than “phase-out” — a deliberate distinction that reflects India’s development stage, energy security priorities, and the realities of a grid that must reliably serve 1.4 billion people through a transition. India has explicitly stated that coal use will not peak until 2040 or later, and the government’s planning horizon includes 100 GW of new coal-based capacity by 2032, with the Ministry of Power considering further expansion toward 420 GW by 2047.

This position sits in some tension with the 2025 data. CREA’s finding that India’s existing and under-construction coal fleet already exceeds what multiple resource adequacy assessments project is needed for 2030 electricity demand — assuming the 500 GW non-fossil target is met — raises genuine questions about the necessity of further coal additions. On India’s highest-demand day of 2025, only 216 GW of thermal capacity was needed; the full 210+ GW coal fleet was not even fully online (26 GW was in maintenance). If coal plant load factors (PLFs) fall further as RE penetration rises and demand growth moderates, new coal additions risk stranding significant capital.

The government’s counter-argument is energy security: given the intermittency of renewable energy and the current inadequacy of storage, maintaining a large thermal base provides insurance against demand surges, RE shortfalls, and grid emergencies. Shri Shripad Naik Ji stated explicitly in the Rajya Sabha on March 23, 2026 that coal-based plants continue to play a critical role in providing base load power and grid stability, ensuring India’s energy security. This is a defensible position in the current grid context — but one that should be revisited as storage deployment accelerates and grid flexibility reforms take hold through 2028 to 2030.

What the transition means for industrial electricity consumers and the CCTS

For CCTS-obligated industrial plants and industrial electricity buyers more broadly, India’s power sector transition has direct financial and compliance implications across three dimensions.

Grid emission factor trajectory

As established in the preceding article on India’s grid emission factor, the CEA-published weighted average emission factor is declining as RE grows as a share of generation. The 2025 data — power sector emissions falling 3.8% while RE generation grew 22% — is consistent with the emission factor declining from 0.727 tCO₂/MWh (FY 2023-24) to 0.710 tCO₂/MWh (FY 2024-25, provisional). The long-term trajectory is firmly downward. For CCTS Scope 2 calculations, a declining grid emission factor means the compliance benefit per unit of renewable energy procurement also declines over time. Plants that act now to procure renewable electricity capture more Scope 2 reduction per rupee of investment than plants that wait five years.

Electricity price volatility and security

India’s electricity price dynamics are shifting as the RE share grows and coal’s role evolves. During peak solar hours in states like Rajasthan, Gujarat and Tamil Nadu, day-ahead market (DAM) prices on IEX now regularly fall to very low levels — sometimes approaching zero — as solar supply exceeds immediate demand. During evening hours when solar drops off, DAM prices spike as coal and hydro cover the ramp. This intra-day price volatility creates both opportunity and risk for industrial consumers. Plants with battery storage or flexible load scheduling can take advantage of cheap midday solar through exchange markets. Plants that are inflexible and draw heavily from the grid in evening hours face premium prices.

For industrial open access consumers, these dynamics strengthen the case for behind-the-meter solar plus storage: capturing midday solar cheap and discharging through the evening peak reduces both electricity cost and grid emission intensity simultaneously. The BESS multiplier of 3.0x under the March 2026 CERC REC amendment directly incentivises this approach for generators — and the economics are beginning to work for consumers too as BESS costs decline at 7 to 20% annually.

Coal PLF decline and industrial captive power

Many energy-intensive industries in India operate coal-based captive power plants (CPPs) for electricity and process heat. As grid-supplied electricity from RE becomes progressively cheaper, the economic case for coal-based CPPs weakens. The CCTS reinforces this pressure: coal CPPs contribute to both Scope 1 (combustion emissions) and Scope 2 (if serving as a utility to the plant) GHG emission intensity, while on-site or procured renewable electricity contributes zero. Industries that invested in coal CPPs in the 2000s and 2010s are now managing assets that face both rising carbon compliance costs and strengthening competition from cheaper renewable alternatives.

The transition question for industrial CPP owners is not whether to switch but how fast and in what sequence. Partial hybridisation — adding solar or wind capacity alongside the existing coal CPP, reducing coal dispatch during generation hours — is the most common initial approach. Full transition to renewable CPP requires either solving the evening ramp problem locally (through storage) or accepting a grid backup relationship that uses DISCOM supply (and associated RCO obligations) during non-RE hours. Both pathways are financially viable in most states; the choice depends on the plant’s load factor, location, and capital position.

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