How Section 11 Became Tata Power Mundra’s Operating Model

A 4,000 MW power plant that lost money badly enough to sit idle for nine months is now legally required to run at full capacity. The government issuing that order is the same one that regulates the tariffs behind the losses.

That tension sharpened again this week. On 26 September 2026, India’s Ministry of Power extended its Section 11 directive for Tata Power’s Mundra Ultra Mega Power Project through 31 December 2026. It is the second extension in a single operating season, and the plant has run under statutory compulsion continuously since 1 April 2026.

For anyone tracking private investment in Indian thermal power, Mundra is a live case study in the friction between grid reliability and commercial viability. The read you should take from it is about the mechanism, not the headline: a statutory tool is now substituting for a commercial arrangement, and understanding how that works reframes the risk entirely.

What Section 11 actually does, and why Mundra keeps triggering it

Section 11 of the Electricity Act, 2003 gives the government a specific power. In defined conditions, it can direct a generating company to operate and maintain a station according to its instructions, overriding the operator’s own commercial judgment. The statutory trigger is a single phrase.

Section 11 of the Electricity Act, 2003 grants this authority specifically for conditions deemed extraordinary, and includes a provision requiring the Appropriate Commission to offset any financial impact on the generating company, a safeguard whose adequacy sits at the centre of the Mundra commercial dispute.

“extraordinary circumstances”

That phrase does all the legal work. It is what converts a plant the operator would rather keep offline into one that must run, and it has been invoked at Mundra not once but three times in a single year.

The Mundra plant is 4,000 MW of capacity across five 800 MW units in Kutch district, Gujarat, operated by Coastal Gujarat Power Ltd (CGPL), a wholly owned subsidiary of Tata Power. It runs entirely on imported coal and supplies five states: Gujarat, Maharashtra, Punjab, Haryana, and Rajasthan.

Here is the part that matters. Before the first directive, the plant was offline for roughly nine months, from 2 July 2025 to 1 April 2026, shut down because of sustained financial losses. This was not routine dispatch management. It was a commercial exit reversed by statute.

The 2026 sequence then unfolded in three stages:

1. 1 April 2026: Initial Section 11 directive orders the plant back into operation for summer demand management, valid to 30 June.
2. 30 June 2026: First extension to 30 September, issued to avoid electricity shortage against an estimated 270 GW summer peak.
3. 26 September 2026: Second extension to 31 December, citing persistently elevated power demand.

The rolling three-month structure tells you something. The government is not managing a fixed-term emergency with a planned endpoint. It is handling the problem in seasonal blocks, and that pattern itself signals the absence of a structural fix. For an investor, the key point is that this is not a negotiated commercial deal. It is statutory compulsion, which changes the risk calculus entirely.

The financial logic behind nine months of silence

Why would an operator idle a 4,000 MW asset for nine months? The answer sits in the gap between what the plant earns and what its fuel costs.

Mundra sells power under long-term Power Purchase Agreements (PPAs) with fixed or low-escalation tariffs. It buys imported coal at international prices that move sharply. When coal costs rise, the tariff structure does not allow full pass-through, so margins compress until continued operation stops making commercial sense.

The Asian Development Bank’s extended annual review for the project (ADB project 41946-014, updated 14 July 2025) puts numbers on the structural nature of this problem:

• Per-unit operating profit averaged approximately ₹0.20 per unit between FY2013 and FY2019.
• The base-case financial model assumed ₹0.73 per unit.
• ADB attributes the gap directly to higher fuel costs and under-recovery of the fuel price at CGPL.
• The review characterises this as a persistent structural issue, not a temporary fluctuation.

Sit with that comparison. Actual per-unit operating profit ran at less than 28% of the modelled figure, sustained across seven years. That is not a performance wobble. It tells you the project’s original financial assumptions were wrong in a way that has never been corrected.

The pattern is not new. An Economic Times report from 12 November 2013 noted that Tata Power booked a consolidated loss of ₹114.7 crore in the three months to 30 June of FY2013-14, attributed mainly to higher imported coal prices for the Mundra plant. The stress was visible more than a decade ago.

One caveat on the current picture: FY2024 to FY2026 net loss and debt figures for CGPL are not available in accessible filings, and neither are precise compensation figures under recent Section 11 or regulatory orders. The ADB data still establishes the underlying point clearly. What it tells you is that Section 11 is not a short-term grid tool bolted onto a healthy asset. It is a statutory compulsion layered on top of an unresolved commercial problem.

Why imported coal exposure made Mundra structurally vulnerable

The vulnerability traces back to procurement design. Ultra Mega Power Project tariffs in India were bid around domestic coal price assumptions, which built stable fuel costs into the winning tariffs. A plant fuelled by imported coal carries a cost line the tariff was never structured to absorb.

That exposure is not unique to Mundra among UMPP-model plants. But Mundra is the clearest documented case, precisely because the ADB review quantifies the under-recovery over seven years rather than leaving it to inference.

India’s imported coal generation policy has been evolving in parallel with the Mundra directives, with proposals to mandate imported coal-based plants into dispatch during peak periods, a structural shift that would formalise what Section 11 currently achieves through emergency compulsion.

India’s 270 GW peak and why the grid cannot spare 4,000 MW

If the plant loses money, why is the government so determined to keep it running? Because the grid is operating at the edge of its capacity, and the numbers moved fast in 2026.

India’s all-time peak power demand hit 270.82 GW on 21 May 2026 at 15:45 hours, surpassing the previous record of 265.44 GW set the day before. The escalation over four days was steep, according to Down To Earth’s Power Demand Tracker citing the Union Ministry of Power.

The government treats this as a stakes marker. The Power Minister stated on 23 July 2026 that the all-time high of 270.8 GW was “successfully met” in May, and noted that July peaks again exceeded 270 GW twice, also met.

Power Minister, 23 July 2026: the all-time high all-India peak demand of 270.8 GW was “successfully met in May 2026.”

Now weigh the renewable side. At the 270.8 GW peak, renewables supplied roughly 34% of demand. That is a meaningful share, and it shows a grid genuinely changed from a decade ago. But it also tells you why thermal backup remains load-bearing: even with a third of peak demand met by renewables, the system still leaned on units like Mundra to cover the top of the curve.

The drivers behind these peaks are structural, not one-off. Business Standard’s June 2026 analysis links record demand to urbanisation, rising cooling loads, and more intense heatwaves. Those forces are not going away next season. A system where renewables cover 34% of a record peak while the government compels a loss-making imported coal plant to hold 4,000 MW in reserve tells you exactly where India’s transition sits at the operational edge: advanced in installed renewable capacity, but short on the storage and dispatchability needed to release thermal backup on the hottest days.

Heatwave-driven demand spikes in 2026 have tested grid stability across multiple states simultaneously, creating conditions where the Ministry of Power’s decision to invoke Section 11 was less a policy choice than an arithmetic response to the gap between available dispatchable capacity and peak demand.

What repeated compulsion signals about commercial risk in Indian thermal power

The three-directive sequence is more than a run of emergency responses. Read together, April to December 2026 looks like a revealed preference: when grid reliability demands it, the government will use statutory compulsion as a substitute for a commercially viable tariff.

The Mundra directive sits within a broader pattern of coal plant mandates: on the same day as the second Mundra extension, India also ordered 112 coal plants to operate at maximum output, citing fuel buffers running at a seven-day margin across parts of the national grid.

That distinction matters for how you underwrite the asset. A plant whose continued operation depends on Section 11 directions rather than commercial tariffs is, for the duration of those directions, operating outside the parameters project finance and equity investors typically require. Bankability assumes a tariff that covers costs. Compulsion does not carry that assumption.

The evidence points one way. The ADB finding of roughly 28% of modelled per-unit operating profit across FY2013-FY2019 frames the long-run commercial gap. The nine-month shutdown from July 2025 shows that, absent compulsion, the plant’s own commercial logic leads to closure. The three extensions supply the empirical pattern for the rolling-compulsion characterisation.

What the pattern does not do is resolve the future. There is no documented plan for Mundra after 31 December 2026. The rolling-extension approach defers the structural problem rather than solving it, which means the same statutory logic could be deployed again beyond 2026.

For investors and analysts tracking Indian thermal power, that is the core regulatory risk: the same environment that set tariffs too low to sustain the plant can also compel it to run at a loss, with the private investor absorbing the commercial consequences of both decisions.

Three open questions the next directive will not answer

Three uncertainties sit unresolved, and none will be settled by another extension:

• Compensation: Do rolling extensions carry an implicit commitment to tariff compensation that actually covers costs? Specific figures awarded under Section 11 or recent orders are not publicly available, which makes a full read of the plant’s current financial position impossible.
• Demand dependence: What would the plant’s commercial status be if India’s peak demand growth moderates, or if storage capacity grows enough to displace thermal backup at the top of the curve?
• Precedent: Does the Mundra invocation create a template for other structurally loss-making thermal plants facing the same fuel-cost and tariff pressures?

Each question turns on variables outside the operator’s control. That, more than any single loss figure, is what defines the risk here.

What the Mundra pattern reveals about India’s energy policy at the grid edge

Pull the three threads together and Mundra stops looking like an accident. The statutory mechanism, the financial history, and the demand reality connect through specific, traceable decisions about tariff design, fuel source, and capacity procurement.

The plant was bid into a tariff framework built around domestic coal, then run on imported coal. It has under-recovered fuel costs for years, as the ADB review documents. And it sits in a grid where peak demand climbed from 214.9 GW on 1 April to 270.8 GW by 21 May 2026, a pace that leaves little room to spare 4,000 MW.

The renewable context sharpens the picture rather than softening it. At 34% renewable share at peak, India’s grid is genuinely different from a decade ago. But the gap in dispatchable backup is still wide enough that plants like Mundra remain load-bearing, which makes their commercial viability a system-level concern, not just a company-level one.

The structural drivers identified in Business Standard’s June 2026 analysis, urbanisation, rising cooling loads, and heatwaves, all point the same direction. So the closing implication is straightforward: the Mundra case will matter for as long as peak demand growth outpaces the storage and dispatchability buildout, which the 2026 data suggests is the current condition.

The structural demand drivers pushing India toward 300 GW, data centre buildout, EV adoption, and industrial cooling loads, are the same forces that make the grid’s dependence on dispatchable thermal capacity more acute, not less, over the medium term.

If you are assessing future Section 11 invocations, at Mundra or elsewhere, three variables carry the signal:

• Peak demand trajectory: whether extreme peaks keep arriving faster than capacity planning assumes.
• Storage deployment pace: whether battery and other storage growth reaches the depth needed to release thermal backup on peak days.
• Tariff framework evolution: whether tariffs shift to make thermal backup commercially sustainable rather than statutorily compelled.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions.

Making sense of a plant the market would close and the grid cannot afford to lose

The 26 September extension confirms the underlying reality: statutory compulsion is now the operative commercial arrangement for one of India’s largest thermal plants, and there is no documented plan to replace it.

The takeaway for anyone underwriting thermal generation in India is direct. Model the scenarios where tariff under-recovery persists and Section 11 compulsion becomes the de facto operating regime, because Mundra shows the government will use this tool repeatedly and sequentially without a defined exit.

By the time the current directive expires on 31 December 2026, the plant will have run under compulsion through both a summer and the onset of winter. As of 26 September 2026, available reporting offers no guidance on what comes next.

That is the question worth watching: what happens after December, and whether the following extension confirms rolling compulsion as a feature of India’s thermal capacity management rather than a temporary fix.