India’s power sector is facing an extraordinary convergence of challenges that forced the government’s hand.
This demand surge isn’t following the usual pattern. September typically sees easing demand as summer heat recedes, but this year has been different. Power consumption grew by 14% in the first nine days of September compared to the same period last year, driven by a potent combination of factors.
The primary culprit is a deficit monsoon.
This has created a dual demand shock. Persistent heat has kept air conditioners humming for longer than usual, while deficient rains have forced farmers to rely heavily on electric pumps for irrigation. The result is sustained high demand during both day and night hours, with the gap between demand and supply narrowing to just 0.1 GW at times.
The supply side is equally stressed. Hydropower generation has fallen 12% year-on-year in the first three weeks of September, marking the fifth consecutive monthly decline.
The situation is so severe that coal stocks at thermal plants fell to just 9 days of consumption at 85% plant load factor in August, the lowest level in 34 months.
Against this backdrop, the Ministry of Power invoked Section 11 of the Electricity Act, 2003 on September 25, 2026. This provision allows the government to direct generating companies to operate and maintain their stations according to government instructions during extraordinary circumstances. What makes this intervention unprecedented is its target: 112 captive coal-fired plants with installed capacity of at least 50 MW.
Captive power plants have historically enjoyed significant operational autonomy. Under the Electricity Act, they’re defined as plants set up primarily for their own use, with users required to hold at least 26% ownership and consume at least 51% of the electricity generated annually. This model has allowed industries like aluminium, steel, and cement to secure reliable, cost-effective power while avoiding cross-subsidy surcharges and additional surcharges.
The Section 11 directive fundamentally alters this arrangement. These plants must now operate at maximum availability from October 1 through December 31, 2026. More significantly, they must offer surplus electricity through power exchanges. The government has specified that plants can use 51% of generation for captive consumption and must sell the remaining 49% on exchanges. This transforms captive plants from primarily self-serving entities into strategic grid-supporting resources during the critical October-December period.
The intervention is having immediate effects on India’s power markets. Day-ahead market prices on the Indian Energy Exchange have repeatedly hit the maximum ceiling of Rs 20 per unit during September, particularly during non-solar hours when demand peaks but solar generation is unavailable.
This price surge reflects a classic supply-demand imbalance. During evening peak hours, when solar output drops to zero, the grid relies heavily on thermal and hydropower. But with hydropower down 12% and coal stocks critically low, supply has struggled to keep pace. The supply deficit from captive coal plants—which were previously operating based on commercial considerations rather than grid needs—exacerbated this shortage.
The mandatory exchange sales requirement creates several causal feedback loops. First, it injects additional supply into the market, particularly during evening hours when prices are highest. This should help moderate prices by increasing sell-side liquidity. Second, it brings diverse generation costs into the market, improving price discovery. Third, it provides DISCOMs with access to additional peak capacity, reducing their dependence on expensive peaking plants. The net effect should be enhanced market efficiency and reduced price volatility during critical periods.
For industries that rely heavily on captive power, this directive creates significant operational and financial challenges.
Steel and cement are similarly energy-intensive, with power and fuel accounting for 15-20% and 30-32% of total costs respectively.
The 51%/49% split fundamentally alters their economics. During normal operations, these industries generate power primarily for their own consumption at an estimated cost of Rs 6 per kWh. Under the new directive, they must sell 49% of generation through exchanges. At current exchange prices of Rs 15-20 per unit during peak periods, this could generate significant revenue. However, it also creates cost allocation complexities and potential margin compression if exchange prices normalize below captive generation costs.
The operational implications are equally significant. These industries must now coordinate production schedules with exchange price forecasts. Continuous processes like aluminium potlines require uninterrupted power—diverting generation to exchanges during peak demand periods could force production curtailment. Cement grinding operations, which run continuously, could face bottlenecks if power is diverted. The directive essentially forces these industries to balance their own production needs with grid support requirements.
The mandate to maintain adequate coal stock for maximum generation adds another layer of complexity. Captive plants must now hold approximately 19 days of coal inventory versus the crisis-level 9 days seen in September. This doubles inventory holding requirements, creating significant working capital pressures.
For a 500 MW captive plant, this means increasing inventory from 108,000-144,000 tonnes to 228,000 tonnes—an additional 84,000-120,000 tonnes. At Rs 2,500 per tonne, this represents an additional working capital requirement of approximately Rs 17.1 crore per plant. Across 112 affected plants, the total additional working capital requirement could reach Rs 380 crore.
Coal procurement logistics become critical. Captive plants must compete with utility thermal plants for railway rake allocation during periods of high demand. Many rely on e-auction coal at premium prices, which may have lower supply priority than Fuel Supply Agreement coal. Plants without dedicated Merry-Go-Round systems face additional logistics complexity and costs. The government’s response to the coal crisis—increasing railway rakes from 370 to 444 per day in early September—demonstrates the logistical challenges involved.
The regulatory approach isn’t uniform. The ministry has also extended special provisions for Tata Power’s 4,000 MW Mundra imported coal plant through December 31, 2026. This extension follows a similar pattern but serves different objectives. The Mundra plant faces severe financial constraints due to imported coal price volatility, having accumulated losses of Rs 6,457 crore and outstanding debt of Rs 10,159 crore by 2017.
The Mundra extension is plant-specific, focusing on cost recovery through Supplementary Power Purchase Agreements with five states. It provides full fuel cost pass-through without caps, protecting the plant from imported coal price spikes. In contrast, the captive plant directive is sector-wide, using market mechanisms rather than regulatory guarantees. This differentiated approach reveals the government’s nuanced regulatory philosophy: targeted interventions for systemic risks like imported coal plant viability, and market-based solutions for broader grid challenges.
The fundamental objective is grid reliability. Thermal plants, including captive coal facilities, are indispensable during non-solar hours. India’s coal power fleet provided 45 GW of ramping flexibility on May 21, 2026, reducing output at midday to accommodate solar and increasing it in the evening as solar faded. The coal fleet achieved nearly 92% of available capacity, proving critical for meeting nighttime demand.
The 28 GW increase in peak demand from 243 GW in 2025 to 271 GW in 2026 translates to approximately 19-21 GW of additional thermal generation requirement. Captive plants are expected to contribute 2-4 GW of this additional generation during peak hours. Their geographic distribution across industrial states provides regional coverage for peak demand management, while their operational flexibility enhances grid stability through inertia provision and voltage support.
Weekly reporting requirements to the Central Electricity Authority enhance transparency and coordination. DISCOMs gain visibility into captive plant operations, enabling better demand forecasting and procurement optimization. The reporting covers generation, captive consumption, exchange sales, available capacity, and coal stocks—providing comprehensive data for grid management.
This regulatory intervention represents a paradigm shift in India’s power sector. It transforms captive plants from primarily self-serving entities into strategic grid resources during critical periods. The success of this approach will depend on effective implementation, adequate fuel availability, and the development of complementary measures including energy storage expansion and demand-side management programs.
The directive is temporary—running only through December 2026—but it establishes a significant regulatory precedent. As India’s power demand continues to grow, driven by cooling needs, electrification, and economic expansion, the balance between industrial autonomy and grid security will remain a central challenge. The current intervention provides a model for managing this balance, but long-term solutions will require accelerated renewable deployment, storage investments, and grid modernization to reduce dependence on emergency measures.
