In the first part of this series, we mapped how India's power sector works, from generation to transmission and finally distribution. We also saw an interesting mismatch: coal and lignite were about 42% of India's installed capacity in June 2026, but supplied nearly 69.5% of electricity during April-June 2026.

That tells us installed capacity alone does not explain the generation business. The more important questions are: What does 1 MW cost to build? How often can it generate? How does the owner get paid? And what can stop that MW from earning?

Here is where thermal and renewable power start looking like two very different businesses.

*The thermal revenue model above refers to CERC-regulated cost-plus plants. NITI Aayog's current modelling assumes ₹11.5 crore/MW for new supercritical coal, ₹4.2 crore/MW for solar and ₹7.6 crore/MW for onshore wind. Recent NTPC projects have come in at roughly ₹12.5 crore/MW, while the government estimates utility-scale solar at around ₹3.5-4 crore/MW.

Thermal Power Economics in India: How Coal Plants Make Money

To understand how thermal power companies earn money, it helps to first look at how these plants differ by location, technology and operating efficiency.

Types of thermal plants: location and technology matter

Coal plants can first be divided by where they are built. Pit-head plants are located close to coal mines, reducing the cost and complexity of transporting millions of tonnes of coal. Non-pithead plants are farther away, sometimes closer to demand centres or ports, making fuel logistics more important.

Technology creates another divide. Older subcritical plants are less efficient, while supercritical and ultra-supercritical plants operate at higher steam pressure and temperature. This allows newer plants to use less coal for producing the same electricity and lowers emissions per unit generated.

How does a thermal plant make money?

Thermal power is commonly sold through long-term Power Purchase Agreements, or PPAs, and 25-year contracts have been widely used in India. For plants where CERC determines the tariff based on allowed costs and returns, revenue has two main components.

Here is where thermal and renewable power start looking like two very different businesses. The capacity charge pays the company for building the plant and keeping it ready, while the energy charge pays for running it when electricity is required.

Fuel therefore works differently from a normal manufacturing business. Under this regulated model, landed fuel cost forms part of the energy charge, so changes in coal and transport costs are largely reflected in the tariff, subject to regulatory norms.

PAF vs PLF: what actually drives thermal earnings?

Plant Availability Factor, or PAF, measures whether the plant is technically ready to generate. The general annual availability benchmark is 85% for most thermal plants, whereas major credit rating agencies and utility operators benchmark strong solar plant availability at > 97%  although older and specialised plants can have different norms.

For most plants, reaching the required availability is important for full fixed-cost recovery. So if a 1,000 MW plant is ready but the DISCOM does not need all 1,000 MW at that moment, its fixed-cost economics are better protected than in a business that earns only when output is sold.

Plant Load Factor (PLF) measures how much electricity a power plant actually generates compared with the maximum it could generate if it operated at full capacity throughout the period.

For thermal power plants, CERC specifies a Normative Annual Plant Load Factor (NAPLF) of 85% for incentive purposes (for most plants). If a plant’s scheduled generation exceeds this 85% benchmark, the additional generation qualifies for a PLF incentive, subject to CERC regulations:

• 75 paise/kWh for excess scheduled generation during peak hours
• 55 paise/kWh for excess scheduled generation during off-peak hours

This 85% PLF norm applies only for calculating generation incentives; it should not be confused with Normative Annual Plant Availability Factor (NAPAF), which is used for recovery of fixed capacity charges.

How do capital and returns work?

For new plants under CERC's regulated framework, the normative capital structure is 70% debt and 30% equity. The base allowed RoE for thermal generation is 15.5% on the equity portion, with the regulations providing separately for tax gross-up.

Suppose a thermal project costs ₹12,000 crore. Normative equity would be ₹3,600 crore, and a 15.5% base RoE works out to roughly ₹558 crore a year. Interest on debt, depreciation and O&M are recovered separately through the capacity charge.

But this does not mean every coal company is guaranteed a 15.5% shareholder return. These CERC rules apply to regulated tariff projects under Section 62, while projects whose tariffs were discovered through competitive bidding under Section 63 fall outside this framework.

Where are thermal plants built, and what can go wrong?

A coal plant needs more than cheap land. It needs reliable coal, water, railway or port connectivity and access to the transmission grid, which is why coal-rich regions such as Odisha, Chhattisgarh, Jharkhand and Madhya Pradesh are natural locations for pit-head projects.

Land use varies by project design, but CEA studies show large thermal plants can broadly fall around 0.5 to 1 acre/MW, depending on coal quality, ash systems, cooling systems and railway infrastructure. Solar, as we will see, requires several times more land per MW.

Thermal's risks are plant outages, fuel shortages, inefficient older units, pollution-control spending, water constraints and delayed DISCOM payments. As discussed in Blog 1, even a well-designed tariff cannot completely remove the cash-flow problem if the buyer itself pays late.

Renewable Energy Economics in India: How Solar and Wind Make Money

What sits inside the renewable generation business?

Renewable generation is no longer just standalone solar farms. Developers now build utility-scale solar, onshore wind, wind-solar hybrids and renewable projects combined with storage to provide power for longer and more predictable periods.

Solar and wind have no recurring fuel bill. Most spending happens before the first unit is generated, which means project cost, financing, generation and timely grid connectivity become crucial to returns.

How does a renewable project make money?

Large solar and wind projects are usually awarded through competitive bidding. Developers quote the tariff at which they are willing to sell power, and SECI commonly signs 25-year PPAs with winning developers, backed by corresponding 25-year agreements with the buying utilities.

The basic revenue equation is much simpler than regulated thermal:

Revenue = Units sold × contracted tariff

There is no separate coal-like fuel reimbursement and no regulator-guaranteed 15.5% equity return. But there is a normative ROE i.e, 14%. The developer's return depends on whether the project can generate enough electricity at the tariff it originally bid.

Solar and wind also receive must-run protection, which means they generally cannot be curtailed simply because another power source is commercially preferred. Curtailment is still possible for technical constraints or grid-security reasons.

CUF: the number that drives solar and wind economics

For renewables, an important number is Capacity Utilisation Factor, or CUF. It measures how much electricity the asset actually produces compared with what it would produce if it ran at full capacity throughout the year.

CERC's 2024 regulations use a minimum 21% CUF for project-specific solar PV tariffs. For wind, the normative CUF ranges from 22% to 35%, depending on how strong the wind resource is at the location.

This explains why comparing only project costs can be misleading. Solar costs roughly ₹3.5-4.2 crore/MW to build, while onshore wind is closer to ₹7-8 crore/MW, but the real return depends on how many units every MW produces and what tariff those units earn.

Capital, land and location

Renewable financing is more market-driven than regulated thermal. CERC's review of actual RE projects found 70:30 to be the most common debt-equity structure, although some solar and wind projects were financed at 75:25.

Solar's bigger physical constraint is land. Government estimates put solar at roughly 4 acres/MW, which means a 1,000 MW solar project could require around 4,000 acres.

But land alone is not enough. Solar works best where strong sunlight, affordable contiguous land and transmission access come together, helping explain why Rajasthan and Gujarat have become major solar centres.

Wind is even more location-dependent. MNRE estimates India's gross wind potential at 1,163.9 GW at 150 metres, but 1,136.7 GW of it is concentrated in just eight states, including Rajasthan, Gujarat, Maharashtra, Karnataka and Tamil Nadu. A cheap piece of land is of little value if the wind resource is poor.

What can hurt renewable economics?

This brings us back to a problem we introduced in Blog 1: electricity is not always generated where it is consumed. A renewable project in Rajasthan may need transmission infrastructure to move its electricity hundreds of kilometres to demand centres elsewhere.

Grid infrastructure can also take longer to build than the generating asset. CEA's 2026 standard timelines range from 24 months for several 400 kV and lower-voltage transmission works to 30-36 months for larger 765 kV lines and substations.

Land aggregation, weaker-than-expected sunlight or wind, delayed grid connectivity and equipment bottlenecks can therefore delay revenue. The government has also acknowledged transformer and reactor supply-chain constraints, while customs duties and ALMM sourcing rules can influence solar equipment procurement.

Thermal vs Renewable Energy in India: Cost and Business Model Comparison

The difference is now easier to see. Thermal generation is largely built around availability, fixed-cost recovery and fuel-cost recovery, while renewable generation is built around upfront investment, a contracted per-unit tariff and maximising generation from every MW installed.

Thermal gives the grid controllable power, but brings fuel, environmental and operating complexity. Renewables remove the fuel bill, but shift the challenge towards land, resource quality, transmission and increasingly storage.

And once these unit economics are clear, the next question becomes much more interesting: which companies are actually best placed to win? Thermal rewards efficient fleets, fuel access and scale, while renewable energy rewards low-cost capital, land access, grid connectivity and execution.

Coming in the Next Blog: Supply-Side Dynamics, Dominant Players & Consolidation

In the next blog, we will shift from how power plants make money to who controls India’s generation capacity, why scale matters, and whether the sector is increasingly consolidating around a smaller group of large players.