The recent Central Electricity Authority’s (CERC) proposal to tighten deviation limits for the scheduling and dispatch of power has raised concerns about higher project costs for renewable developers and potential increases in consumer tariffs.

As part of its broader effort to reduce grid instability, CERC has proposed narrowing the tolerance band for the deviation settlement mechanism (DSM) for wind and solar projects starting in 2026. The tighter DSM limits could result in higher deviation charges for renewable projects or force developers to invest more in advanced forecasting and weather-monitoring systems to minimize penalties.

The CERC has also proposed changing the calculation of deviation settlement to use the project’s scheduled generation instead of available capacity. The move also reduces the DSM tolerance band for wind from ±15 % to ±10 % and for solar from ±10 % to ±5 %.

The Commission also suggested a phased reduction in the ‘x’ value used in the formula to calculate the deviation in a time block for wind and solar projects. A decrease in the x value will likely increase the deviation settlement charges paid by wind and solar projects injecting into the grid over time.

Impact on Project Costs

Developers argue that, given the intermittent nature of renewables, reducing the DSM band could result in moderate revenue losses for solar projects and greater exposure for wind projects. The cost of hybrid power projects could also rise slightly.

Kishor Nair, Chief Executive Officer at Avaada Energy, said that with the tightening of the deviation band from ±10 % to ±5 % particularly for solar projects, and introducing X-factor in the deviation formula, revenue loss sustained by developers will increase from 3.5% at a deviation band of ±10% to 5.5% revenue loss when the deviation band is ±5% and X=100.

He added that developers will also incur a revenue loss of up to 65% when X=0 and the deviation band is ±5%.

Pavan Maddhesia, Head (Asset Management) at Sunsure Energy, said that to avoid DSM charges, project developers would have to deploy advanced forecasting systems, install automatic weather stations (AWS), and possibly integrate battery energy storage systems (BESS) with renewable projects.

Developers could also aggregate multiple renewable projects through qualified coordinating agencies to reduce the impact.

Maddhesia added that these mandates could increase both capital and operational expenditure of projects.

Sonam Chandwani, Managing Partner at KS Legal & Associates, said that the proposed tightening of DSM bands will increase the compliance burden under the CERC framework and will require developers to review their power purchase agreements (PPA). “Developers may need to seek amendments in PPAs or renegotiations to incorporate these regulatory changes and protect themselves contractually from unforeseen penalties.”

Chandwani added that a 3–5% increase in capital expenditure is foreseeable, which could further impact the project’s financial closure and debt servicing ratios unless lenders and regulators provide transitional relief.

Developers say that the increased project costs could severely undermine confidence in renewable projects and slow down investments in the renewable sector.

Increasing Tariffs

Developers mentioned that rising project costs are likely to be passed on to end consumers through higher tariffs.

Nair noted that due to the tightening of the DSM band, developers are likely to incur revenue losses ranging from ₹0.0855 (~$0.0009)/kWh to ₹1.7 (~$0.019)/kWh, which will impact the viability of the current tariffs.

Maddhesia observed that tariffs for new projects would have to account for increased DSM risk, additional capital expenditures for AWS and BESS, and higher operating and maintenance costs.

He felt that reducing DSM tolerance bands could also affect existing projects with fixed tariffs, potentially lowering their internal rate of return. “Developers may factor in tariff increases in future bids to offset DSM-related risks.”

Chandwani, however, said that since tariffs are subject to competitive bidding and CERC’s tariff guidelines, the actual hike may be constrained. “Developers may also need to incorporate these regulatory adjustments in future tariff petitions or bid documents to avoid post-award disputes. Overall, tariffs could increase by 2%-3%, though CERC and state regulators will likely review such justifications carefully.”

She added that internal governance and contractual risk allocation through operations and maintenance (O&M) agreements must be strengthened to clearly define responsibility for deviations.

Nair noted that when the regulators tightened the DSM band from ±15% to ±10% with effect in September last year, developers started aggregating at the pooling substation level to minimize revenue losses. A further reduction in the deviation band from ±10% to ±5% for solar projects will prompt developers to reconsider their aggregation strategy at the pooling substation. “A larger pool of solar or wind at the state or regional level could provide some sort of relaxation over the revenue loss due to the tightening of the DSM band”.

Will AWS Help?

By setting up AWS, developers aim to enhance forecasting and scheduling, particularly when combined with AI-based forecasting models and real-time data transmission to renewable energy management centers and state load dispatch centers. However, they say that it must be part of the broader strategy involving aggregation and hybridization.

In July 2025, the Central Electricity Authority proposed installing one AWS for each renewable energy project with a capacity of 50 MW.

Nair mentioned that while AWS will play a vital role in long- and medium-term forecasting, its effectiveness for short-term forecasting remains to be analyzed.

He added that, for effective short-term forecasting, micro-location and regional forecasting of AWS must be enhanced.

Nair observed that the industry has been asking the Indian Meteorological Department (IMD) to facilitate accurate weather forecasting using advanced satellites. “The IMD has the expertise in weather forecasting, and independent power producers will provide the energy schedule based on the forecast given by IMD. Independent power producers should not be penalized for factors that are beyond their control.”

Chandwani said that the non-installation or malfunctioning of AWS could be interpreted as negligence, inviting regulatory scrutiny or contractual liability under PPA performance clauses.

She added that while AWS enhances accuracy, it cannot guarantee full compliance due to the unpredictability of weather conditions. However, she noted that AWS data could serve as a mitigating factor in defending deviation penalties, showing that deviations occurred despite best efforts.

She added that it would also require developers to ensure data accuracy and maintain proper audit trails, as regulators may demand evidence of due diligence during disputes or settlements involving DSM.

Can BESS be a Solution?

Developers claim that BESS can help mitigate DSM charges by storing surplus power when generation exceeds the scheduled capacity and supplying it when generation falls short of the schedule.

However, integration of BESS with all wind and solar projects could significantly increase capital costs and O&M expenses. The added costs come from battery upkeep and the need for advanced energy management systems.

According to Nair, while integrating BESS will increase tariffs for solar projects, such integration will be considered only for future projects.

Chandwani stated that incorporating BESS can substantially mitigate DSM exposure by stabilizing output; however, it will significantly increase capital costs by up to 20%–25%. “Legally, if regulators or distribution companies make BESS mandatory, the obligation may be treated as a ‘Change in Law’ under existing PPAs, allowing developers to seek compensation or tariff adjustment. The legal classification of such mandates will be crucial to determine who bears the cost of compliance.

Hybrid Solutions

Maddhesia noted that wind-solar hybrid solutions can help balance generation across time blocks and reduce variability.

He stated that, with proper forecasting and aggregation implemented and leveraging geographical diversity, a hybrid power project could also reduce the need for BESS integration; however, it faces some limitations.

“In high-penalty zones or for grid-critical projects, BESS may still be necessary to meet DSM compliance reliably. For most renewable sites, a combination of hybrid projects (solar and wind), accurate forecasting, aggregation of multiple plants, and AWS-based solutions can reduce or even eliminate the need for large BESS. However, if the goal is to completely avoid DSM charges, especially during evening demand peaks or long periods of low wind and solar generation, some battery storage remains the most reliable option,” said Maddhesia.

Nair said that hybrid solutions alone cannot help developers adjust to DSM band tightening, but integrating BESS with solar-wind hybrid power projects would help them tackle it.

Chandwani said that wind-solar hybrid projects naturally balance generation profiles and may reduce the need for BESS; however, developers should ensure that hybrid capacity and forecasting are distinctly approved and recorded in scheduling to avoid regulatory ambiguity during DSM computation.

Reduction of Curtailment

Project developers argue that tighter DSM tolerance demands could indirectly help reduce curtailment and encourage power generators to improve their scheduling accuracy, resulting in smoother, grid-friendly generation patterns that are easier for the system operator to manage.

Recently, Mercom India had reported about large-scale curtailments in wind and solar projects in Rajasthan and Gujarat.

Chandwani commented that if developers maintain DSM compliance, any curtailment beyond grid safety reasons could be contested as a breach of the “must-run” status of renewable projects. “Improved predictability may empower developers in future regulatory or judicial challenges against unjust curtailments.”

Nair argued that while regulators are trying to reduce intermittency and avoid curtailing renewables, grid regulators need to amend their forecasting and scheduling processes.

He suggested reducing forecasting and scheduling from 15-minute time blocks to 5-minute time blocks. He added that the Intraday revisions must also be revised from the 3rd and 4th time blocks, rather than the 7th and 8th time blocks.