In February 2023, the Central Electricity Authority (CEA) notified regulations mandating coal-based thermal power plants to achieve a minimum technical load (MTL) of 40%, down from the existing 55% requirement. The goal was straightforward: enable coal plants to ramp down during peak solar generation hours, creating space for renewable energy on the grid. Yet, as of mid-2026, widespread non-compliance persists. The primary reason?
This technical concern is compounded by financial pressures: operating at lower loads increases station heat rates by 7-9%, raises auxiliary power consumption by 2-4%, and accelerates equipment wear, all of which drive up per-unit generation costs.
The CEA's enforcement toolkit, however, remains limited. While the Electricity Act, 2003 provides the foundation for regulatory authority, the CEA lacks direct punitive powers. Enforcement relies heavily on coordination with state electricity regulatory commissions and load dispatch centers, creating a fragmented implementation landscape. Penalties for non-compliance with regulatory directions can theoretically reach up to ₹1 crore per contravention, but applying these to technical operational mandates presents practical challenges. The result is a regulatory framework that sets ambitious targets but struggles to ensure compliance, particularly when those targets impose significant costs on regulated entities.
The financial implications of flexible operation are stark. Operating at 40% load versus 55% significantly increases operational expenses. Variable costs rise due to degraded efficiency—burning more coal to produce the same amount of electricity—while fixed costs remain unchanged and must be recovered over fewer generated units. This dynamic has already contributed to a decline in coal plant load factors from 85% in 2009-10 to 55% in 2023-24, with projections suggesting further drops to 40%.
The Central Electricity Regulatory Commission (CERC) has approved a compensation mechanism under the Tariff Regulations, 2024, allowing coal plants to recover costs linked to higher station heat rates, increased auxiliary consumption, and secondary fuel oil use when operating at part-loads. The framework includes a 50:50 gain-sharing mechanism if costs turn out lower than expected and provides annual compensation for start-ups beyond seven per unit per year. However, industry feedback indicates that this framework may not fully address the 25-30% ROE reduction, particularly the impact on fixed cost recovery as plants operate at lower capacity factors.
The resistance to flexible operation has tangible consequences for renewable energy integration. In the first quarter of 2026, India curtailed approximately 470 GWh of renewable energy across its inter-state transmission system. Of this, 300 GWh—nearly two-thirds—was directly attributable to transmission constraints, while the remaining 170 GWh resulted from system inflexibility, primarily coal plants unable to ramp down below 55% MTL. Regionally, the Northern Region accounted for 178 GWh and the Western Region for 122 GWh of transmission-related curtailment, translating to 1.5-2% of potential generation lost for renewable plants in these areas.
The transmission bottleneck stems from a fundamental mismatch: renewable projects can be built in 12-18 months, while transmission lines typically require 36-60 months. India has achieved only about 80% of its annual transmission buildout targets over the past five years, creating a growing backlog of delayed projects. One in four major transmission schemes is delayed by at least a year, with nearly 20 GW of renewable energy capacity facing connectivity delays exceeding four months in FY2026-27. This infrastructure gap, combined with coal plant inflexibility, forces system operators to curtail solar power during peak generation hours to maintain grid frequency within the safe band of 49.9-50.05 Hz. In May 2025, system frequency exceeded permissible limits for nearly 20% of the time during high solar generation periods, despite thermal generation being reduced to 58% capacity and 10 GW of solar being curtailed.
The curtailment has significant financial implications across the value chain. For solar power generators, transmission constraint-related curtailment typically does not receive compensation, posing substantial commercial risk. A 6-12 month delay in achieving full grid connectivity can reduce a project's internal rate of return by 100-200 basis points. Even when curtailment occurs under emergency Tertiary Reserve Ancillary Services (TRAS) mechanisms and receives compensation, the uncertainty creates investment risk. Current solar tariffs of ₹2.50-2.87/kWh already leave developers with thin margins—equity IRRs have compressed from >14% to approximately 12% in recent years.
Distribution companies (DISCOMs) face a different burden. For system inflexibility curtailment, they must compensate renewable generators at PPA rates—approximately ₹43-49 crore for the 170 GWh curtailed in Q1 2026. More broadly, the incremental cost of renewable energy integration is effectively transferred to DISCOMs and ultimately socialized among consumers through higher end-user tariffs. As coal PLFs decline, fixed costs are spread over fewer units of generation, driving nearly 85% of the effective increase in overall costs. Average tariffs are expected to rise by roughly 25% over current levels as a result. For new coal plants, tariffs have already risen sharply, exceeding INR 6/kWh in Bihar and INR 5.85/kWh in Madhya Pradesh, driven largely by high fixed costs often exceeding INR 4/kWh.
Breaking this impasse requires leadership from major thermal generators, particularly NTPC. As India's largest power utility, NTPC has already achieved 55% load operation and is working toward 40%. The company has conducted extensive flexibilization studies at multiple plants in collaboration with international agencies and has adopted a three-pronged strategy focusing on technology upgrades, process improvements, and workforce training.
This positions NTPC to lead by example, demonstrating that flexible operation is technically feasible and commercially viable.
However, NTPC alone cannot solve the problem. The lack of clarity on compensation mechanisms for flexible coal operations creates investment uncertainty across the sector. Thermal generators hesitate to invest in retrofits costing INR 100-400 million per unit without guaranteed recovery, while renewable energy developers face curtailment risk that increases their cost of capital. Addressing this requires coordinated action: finalizing and implementing clear compensation frameworks, creating flexibility markets that properly value ancillary services, and establishing predictable policy environments that provide long-term investment certainty.
The timeline for India's 500 GW non-fossil capacity target by 2030 is tightening.
The extension of the June 2026 deadline for 40% MTL compliance by another year provides temporary breathing room but does not resolve the underlying structural issues. Success will require transforming coal plants from baseload workhorses to flexible enablers of India's renewable-led future, supported by storage deployment, grid modernization, and market reforms that align financial incentives with system needs.
