Coal power to get costlier

India’s average coal PLF is expected to fall to about 55% by FY 2031–32, but utilisation will vary sharply across plants — low-cost units running more, and costlier ones facing reduced operation or shutdowns. This would not only make contracting thermal power expensive for electricity distribution companies (DISCOMs) but also question the viability of future long-term thermal contracts. 

In India, when a DISCOM procures power from a thermal plant, it pays a fixed charge to cover capital expenditure recovery and provide the generator an assured return. It also pays variable (energy) charges to cover fuel and operational costs when the plant dispatches. Consequently, even if the plant remains idle, the DISCOM must bear significant fixed costs to retain the capacity in its portfolio. Over time, both fixed and variable charge components would be impacted by the declining utilisation of thermal plants.

The fixed charge of coal-power assets will be impacted in the following ways:

• Underutilisation of thermal assets: DISCOMs remain liable for holding assets that are being used less frequently. The fixed costs — which must be paid irrespective of actual generation — are, therefore, spread over fewer operating hours. This makes the effective cost of maintaining such capacity significantly higher and represents the largest factor affecting the effective cost for the procuring DISCOM. An in-depth analysis of the state of such stranded power costs and how it adds to the DISCOMs financial burden can be seen here.
• Capital expenditure on retrofits: Many plants will require one-time retrofits for sustained operation at their MTL or even lower. Based on various technical assessments, these retrofits are estimated to cost between INR 100–400 million (USD 1.15-4.60 million) for a generating unit, depending on factors such as plant design (subcritical or supercritical) and age.
• Rising operation and maintenance expenses: Consistent operation at lower loads and steep ramping accelerates equipment wear and tear, leading to higher failure rates and more frequent component replacements. This, in turn, increases the fixed charges allocated for operation and maintenance (O&M) expenses.

The variable charges of coal-power assets will be impacted in the following ways:

• Decline in operating efficiency: Operating at lower PLFs increases the station heat rate (SHR) — meaning the plant must burn more coal to produce the same amount of electricity. As PLFs fall from normative levels of around 85% to 55%, the SHR typically rises by 7–9%, directly inflating the energy charge component of tariffs.
• Higher auxiliary consumption per kWh: Internal equipment such as pumps, fans and conveyors tends to continue to operate at or near rated capacity regardless of the generation level. The auxiliary power consumption (energy used to operate this equipment), therefore, increases by 2–4% per kWh when plants run below optimal loading, since the same consumption is spread across fewer kWh.
• Increased restart expenses: Frequent shutdowns lead to higher use of secondary fuels, such as furnace oil or light diesel oil, which are needed during plant restarts. The extent of oil consumption depends on the type of start — hot, warm, or cold — with associated costs varying accordingly. Restart-related wear and tear can add INR 10–25 million (USD 0.11-0.29 million) in expenses per generating unit each time a shutdown and revival occurs.

There are two key insights that emerge from the analysis of thermal power costs under declining PLFs.

1. Cost escalation is primarily a result of underutilisation rather than technical flexing. As PLFs decline, fixed costs are spread over fewer units of generation—driving nearly 85% of the effective increase in overall costs. This underutilisation will weigh most heavily on coal power buyers (DISCOMs), with average tariffs expected to rise by roughly 25% over current levels.
2. Coal-plant flexibility is technically feasible and economically manageable. Despite earlier concerns, pilot studies and CEA assessments show that the incremental cost of operating coal plants flexibly is modest—about 10–15% of the base tariff for newer supercritical units (mostly commissioned after the late 2000s). In this light, the CEA’s proposal to mandate a statutory 40% MTL appears justified, provided plant-level technical feasibility is established.

The weighted average cost of the existing coal fleet, including fixed and energy charges, stands at around INR 4.78/kWh (USD 54/MWh). This figure is relatively low because many older coal plants were built at cheaper capex and are now largely depreciated under regulated tariffs, keeping fixed charges minimal. However, as the average coal fleet operates at 69% (present, FY 2024-25) and 55% (as modelled for FY 2031-32), the effective cost rises to INR 5.43/kWh (USD 62/MWh) and INR 6.05/kWh (USD 70/MWh), respectively. 

To account for the additional expenses associated with flexible operation, tariff regulations have introduced mechanisms to compensate plants for operating at lower loads — commonly referred to as part-load compensation. These provisions apply not only to government-regulated tariff Section 62 generators but also extend to Section 63 projects procured through competitive bidding, typically under DBFOO (Design, Build, Finance, Own, Operate) contracts.

Crucially, these mechanisms tend to ‘pass through’ the additional costs, insulating generators from many operational and financial risks associated with lower PLFs — on top of the fixed cost recovery already embedded in tariffs. As a result, the incremental cost of flexibility is effectively transferred to the DISCOMs and, in most cases, ultimately socialised among consumers through higher end-user tariffs.

However, with growing renewable penetration and steadily declining PLFs, the effective cost of maintaining coal capacity within a DISCOM’s portfolio has been increasing — and is expected to rise sharply as utilisation falls further. Lower generation spreads the fixed cost over fewer units of output, inflating the per-unit cost of coal power even without any change in tariff structure. This trend is likely to intensify in the coming years, becoming a growing burden on DISCOMs’ power portfolios and ultimately on consumers.

Ember’s modelling, aligned with the CEA’s capacity outlook, reaffirms that India can comfortably achieve its 2032 power sector goals with the ~35 GW of coal capacity, which is already under construction (including maintaining reserves). This indicates that no additional coal capacity is required before FY 2031–32, as the existing pipeline sufficiently meets adequacy needs, along with sufficient reserves. Planning or approving new coal plants beyond the 35 GW would risk severe overcapacity. 

Adding capacity beyond this would be unnecessary and counterproductive, even if justified under the pretext of ensuring “reliable” peak supply. On the contrary, such expansion would impose severe financial and operational stress on DISCOMs by locking them into underutilised, high-cost coal assets, while also worsening grid stability challenges.

It is evident that the effective cost of owning coal generation assets will continue to rise as PLFs decline. However, recent years have seen a steady increase in coal-based tariffs compared to previous periods. Several factors, such as a shift toward improved plant technologies, the implementation of stricter emission control norms, and the burden of enhanced regulatory compliance requirements, are contributing to this upward movement of coal tariffs.

The newer thermal fleet is likely to be technologically more advanced and designed to operate flexibly — including the ability to reach MTL levels below 40% and perform two-part operations to respond to system needs. While these features improve the response to a changing power mix, they also raise capital and maintenance costs — meaning that the effective cost of holding new thermal capacity will be considerably higher than that of existing, already-depreciated assets.

The total tariff — combining both fixed and energy charges (INR/kWh) — for newly approved or recently built coal plants across India, developed by both public and private entities, has risen sharply. In several cases, coal power has become prohibitively expensive, with tariffs above INR 6/kWh (USD 68/MWh) in Bihar and around INR 5.85/kWh (USD 66/MWh) in Madhya Pradesh, despite both states being located close to coal-producing regions. Much of this escalation is driven by very high fixed costs, often exceeding INR 4/kWh (USD 45/MWh). 

For example, a cost of INR 6/kWh (USD 69/MWh) can effectively rise to INR 7.25/kWh (USD 83/MWh) for a DISCOM when adjusted for the utilisation levels reflected in the model. The higher fixed costs further exacerbate the challenge, leading to stranded power assets that are seldom dispatched yet continue to incur servicing obligations.

These coal tariffs are now comparable to, or even higher than, recently discovered Firm and Dispatchable Renewable Energy (FDRE) tariffs, which range between INR 4.3–5.8/kWh (USD 49–67/MWh). FDRE projects are structured to deliver round-the-clock or assured peak power while maintaining annual utilisation levels of 70–80%. Through the stringent design of these tenders, developers are being pushed to make FDRE projects increasingly dispatchable.

Similarly, recent solar and storage tenders in India have also been competitively priced, with price discovery in the range of INR 2.9–3.6/kWh (USD 33–41/MWh). The trend is clear: while the cost of dispatchable renewable energy systems continues to decline through innovation, the cost of fossil-based generation is expected to increase — a divergence that is likely to become even more pronounced in the coming years.

While it is often argued that FDRE, even with dispatchability mandates, cannot fully match the reliability of coal due to its dependence on weather, two important counterpoints challenge this assumption. First, India has repeatedly faced coal shortages during peak demand seasons, mainly driven by mining disruptions, logistical bottlenecks, and poor stock management at the plant level — proving that greater coal capacity does not automatically ensure reliable dispatch. Second, with the rapid decline in battery storage costs, FDRE systems are becoming increasingly cost-competitive. The reliability advantage, with falling costs, stems from the ability to oversize generation and storage, and continuously integrate technological improvements (for example, breakthroughs which ensure minimal BESS degradation). 

India should not rush into building new coal plants without careful consideration of the underlying realities. The country has already learned hard lessons from past episodes of excess and untimely coal build-out that overlooked critical factors such as realistic demand growth, fuel linkages, etc. It must avoid repeating that mistake. This time, however, the underlying realities present a fundamentally different kind of challenge — with cost-competitive, dispatchable renewable energy emerging as an economically superior alternative to meet future power needs.