Christopher Hailstone is a titan in the utility sector, bringing decades of experience in navigating the complex intersections of grid reliability and renewable integration. As India’s power market matures, his insights into the Central Electricity Regulatory Commission’s (CERC) latest mandates are crucial for understanding how the country will balance a grid increasingly dominated by intermittent sources. This conversation explores the shift toward stricter deviation rules for future wind and solar projects, the integration of energy storage systems, and the regulatory philosophy driving the 2026 amendments that came into force on August 31.
The CERC has recently signaled a major shift by bringing future wind and solar projects under the same deviation rules as conventional generators. From your perspective, why is this leveling of the playing field happening now, and what does it mean for the traditional exemptions these sectors enjoyed?
For over a decade, wind and solar developers operated under a protective regulatory umbrella, enjoying relaxed treatment and tolerance bands that shielded them from the harsh financial realities of grid imbalances. We have reached a tipping point where the “infant industry” argument no longer holds weight because these technologies have matured significantly in terms of forecasting and scheduling accuracy. By removing the non-linkage of deviation charges with grid frequency, the regulator is demanding that renewable energy acts like a responsible citizen of the grid. This shift forces developers to embrace hybrid projects and sophisticated storage solutions to ensure they can meet their schedules just as reliably as a coal or gas plant would. It is a move toward a more disciplined, market-oriented environment where variability must be managed at the source rather than being offloaded onto the wider system.
With renewable energy reaching a staggering 51.5 percent of the generation mix on July 29, 2025, the grid is clearly in a different state than it was even a few years ago. How does the new scheduling discipline reflect the reality of managing a grid where intermittent power is no longer a minority?
Seeing that 51.5 percent figure from last summer was a wake-up call for everyone in the industry, proving that renewables are no longer a peripheral supplement but the beating heart of the Indian power system. With such high penetration, any deviation from the schedule isn’t just a minor accounting error; it is a potential threat to grid stability that requires immediate, expensive intervention from ancillary services. The CERC’s decision to apply general deviation rules ensures that future projects are built with the foresight to handle this responsibility, moving away from the old tolerance bands that are no longer sustainable for a modern grid. We are seeing a shift where forecasting tools and the aggregation of renewable generation are becoming mandatory operational requirements rather than optional extras. This discipline is essential because as the share of renewables continues to climb, the margin for error in balancing supply and demand shrinks to almost zero.
The implementation timeline is staggered, with bidding-based projects seeing changes from early 2027 and others from 2029. Why is this prospective approach so critical for the financial health of these multi-million dollar energy projects?
In the world of energy infrastructure, sudden regulatory shifts can be catastrophic for project bankability, which is why the decision to start the clock for bidding projects on January 1, 2027, is a pragmatic move. It allows developers to bake these new deviation-related risks and obligations into their financial models and commercial arrangements long before a single shovel hits the ground. For non-bidding projects, providing a runway until January 1, 2029, ensures that projects currently under construction or in late-stage planning aren’t blindsided by costs they never accounted for in their original power purchase agreements. This clarity is a relief for investors who need to see a stable regulatory horizon to commit the massive capital required for India’s energy transition. By making these changes prospective, the Commission is essentially saying that the rules of the game are changing, but they are giving the players enough time to adjust their equipment and strategies.
Standalone energy storage and pumped hydro are receiving specialized treatment in these amendments. How does the use of the Energy Charge Rate (ECR) for pumped hydro deviations change the economic incentive for these large-scale storage assets?
Pumped hydro storage is a unique asset because it doesn’t have a standard contract rate or reference charge rate like a typical thermal plant, so using the Energy Charge Rate specified under the 2024 Tariff Regulations is a logical fix. This approach applies to both generation and pumping modes, recognizing that these plants are essentially massive batteries that help the beneficiaries balance their loads. Since their annual fixed charges are recovered through capacity charges, the deviation mechanism needs to focus on the actual cost of the energy being moved, which the ECR reflects accurately. This provides a clear, predictable framework for operators who are trying to manage the complex hydraulics and electrical requirements of these facilities without being unfairly penalized. It creates a specialized niche in the regulations that acknowledges the flexible, grid-supporting role these assets play while ensuring they are still held accountable for their schedules.
There has been some friction regarding the ₹2 per kWh ceiling for infirm power during the testing of storage systems. Why do you think the Commission held firm on this price point despite stakeholders arguing it doesn’t cover their costs?
The tension over the ₹2 per kWh cap is palpable because developers often feel the sting of high energy consumption and losses during those critical trial runs and first synchronizations. However, the Commission has to play the role of a neutral referee, balancing the financial health of the storage developer against the potential drain on the National Deviation and Ancillary Services Pool Account. From the regulator’s perspective, injecting infirm power is an occasional, transitional phase rather than a sustained commercial operation, so the compensation should not be high enough to incentivize long, inefficient testing periods. While it might feel like a low ceiling for those managing expensive battery assets, it is a safeguard to ensure that the DSM pool remains robust and is not overextended by testing-related volatility. It is a classic example of regulatory balancing where the collective stability of the market takes precedence over the specific cost recovery of a single project phase.
The CERC decided to stick with the time-block-wise weighted average Area Clearing Price rather than moving to a daily average as originally proposed in the draft. Why is this granular approach to pricing so important for the economic signals the Commission wants to send?
Sticking to the time-block-wise weighted average ACP of the Integrated Day Ahead Market is a victory for market transparency and precision. If we had moved to a daily average, we would have smoothed out the very price spikes and dips that tell us when the grid is under stress or when there is an oversupply of energy. By keeping the price signals granular, the regulations reward those who can accurately forecast their generation in the specific 15-minute intervals where it matters most to the grid’s health. It forces a certain level of sophistication in how developers think about their daily operations, pushing them to align their generation with the actual needs of the market. In a grid that is becoming more volatile due to weather patterns, these sharp economic signals are the only way to effectively coordinate thousands of different generators and storage units.
What is your forecast for the evolution of the Indian power market as these stricter deviation rules take hold by 2029?
I foresee a massive wave of technological upgrading where AI-driven forecasting and large-scale battery integration become the standard for every new wind and solar farm across the country. As we approach the 2029 deadline for commercial operations of these new projects, the “standalone” renewable project will likely become a relic of the past, replaced by sophisticated hybrid systems that can promise—and deliver—firm, dispatchable power. We will see a consolidation of smaller players who may struggle with these stricter scheduling demands, while larger entities will thrive by aggregating generation to smooth out local weather variations. Ultimately, this regulatory shift will transform India’s power market into one of the most disciplined and technologically advanced in the world, proving that green energy can be just as reliable and predictable as the fossils we are leaving behind.
