The Central Electricity Regulatory Commission’s (CERC) latest grid connectivity amendment addresses a problem that sits at the centre of India’s power transition: projects may receive access to the national transmission system while approvals, construction and scheduled connection dates continue to move. The new rules allow developers to surrender connectivity after prolonged delays, recover eligible bank guarantees and seek access to transmission capacity that would otherwise remain unused.
The provisions were notified on November 11 as part of the CERC (Connectivity and General Network Access to the Inter-State Transmission System) (Fourth Amendment) Regulations, 2026. According to the supplied report, the regulations will take effect after publication in the Official Gazette. Their significance lies less in a single project than in the way they revise the relationship between project developers, the Central Transmission Utility, electricity consumers and the national transmission network.
The central change is an exit mechanism for developers facing extended approval or scheduling delays. A project can surrender its entire grid connectivity allocation when the gap between preliminary and final approvals is two years or more, or when its scheduled connectivity date is delayed by at least two years. Developers that have received final approval must apply within 45 days. Projects still waiting for final approval can also seek withdrawal within 45 days of completing the two-year period.
The process is designed to have a defined administrative timeline. The nodal agency must process an eligible withdrawal request within 15 days. If the request is approved, the developer’s bank guarantees are returned, while the application fee is forfeited. This structure separates the cost of entering the system from the financial security tied to a connection that has remained delayed. It also creates a formal route for releasing transmission capacity that may no longer be linked to a viable or timely project.
That distinction matters because grid connectivity is not simply a permission to plug in. It is part of a wider transmission planning chain involving approvals, network availability, project schedules and the readiness of generation or storage assets. When a project retains an allocation despite prolonged delay, the capacity may remain difficult to reassign. CERC’s amendment therefore treats delayed connectivity as both a developer problem and a network-utilisation problem.
The rules also attempt to make more use of existing transmission infrastructure outside the hours associated with solar generation. Renewable energy and battery storage projects with capacity of at least 50 megawatts can seek grid access during non-solar hours, subject to available capacity. The Central Transmission Utility must publish and update the available capacity at eligible substations every month.
This provision recognises that a transmission asset can have different levels of availability across the day. Solar projects typically inject power during daylight hours, while storage projects can charge or discharge at other times, depending on their operating arrangements and approvals. The amendment does not guarantee access: projects remain subject to available capacity. But monthly publication of that capacity can make the process more visible to developers and consumers and may reduce uncertainty about where additional access is possible.
The 50-megawatt threshold is also significant. It directs the non-solar-hour access provision towards larger renewable energy and battery storage projects rather than creating a blanket entitlement for every installation. The supplied material does not establish how many substations will qualify, how much capacity will be available or how quickly projects will be connected. Those details will determine whether the provision becomes a substantial change in network utilisation or remains limited to selected locations.
CERC has also allowed certain eligible electricity consumers to maintain connections with both the national transmission network and state-level networks, subject to necessary approvals and applicable charges. This introduces greater network choice, but it does not remove the institutional boundaries between interstate transmission and state networks. The practical value of dual connectivity will depend on approval procedures, charges and the technical ability of consumers to manage both arrangements.
The amendment further provides for faster release of certain bank guarantees after projects complete one year of commercial operation. This replaces the earlier five-year phased release mechanism, according to the report. In effect, the revised approach reduces the period during which qualifying projects must keep specified financial security tied up after entering commercial service. The change could alter project cash-flow planning, although the supplied material does not specify the categories of guarantees covered or the exact release schedule.
The consumer dimension is particularly relevant because the changes were not limited to developer requests. The Uttar Pradesh Rajya Vidyut Upbhokta Parishad said three of its recommendations were incorporated into the amended regulations. Its chairman, Avadhesh Kumar Verma, said the organisation had submitted eight suggestions on June 8.
The three provisions identified by the consumer body are a one-time network access charge of Rs 1 lakh per MW to reduce monthly transmission costs, the ability to surrender unused connectivity after delays of two years or more under specified conditions, and monthly publication of available transmission capacity at substations during non-solar hours. These measures connect the regulatory reform to two persistent questions in electricity infrastructure: who pays for network access, and how efficiently is scarce transmission capacity used?
The proposed one-time charge is especially important because transmission pricing affects the economics of power supply before electricity reaches consumers. The supplied report describes the Rs 1 lakh per MW payment as a measure intended to reduce monthly transmission costs, but it does not provide a comparison with the previous cost structure or explain which consumers and projects will qualify. The financial effect therefore cannot be assessed solely from the notification summary.
What is clear is that the amendment combines four different regulatory objectives. It gives delayed developers an exit route; seeks to improve the utilisation of substations during non-solar hours; permits certain consumers to retain central and state connections; and reduces the period for releasing some post-commissioning bank guarantees. These provisions address flexibility, transparency, network use and financial security within the same regulatory framework.
The institutional design places considerable responsibility on the Central Transmission Utility and the nodal agency responsible for processing withdrawal requests. The utility must publish monthly capacity information, while the nodal agency must decide eligible withdrawal applications within 15 days. The effectiveness of the reform will therefore depend not only on the wording of the regulations but also on the quality and regularity of implementation.
The amendment also shows how transmission access has become a governance issue rather than a purely technical one. A delayed project can affect the allocation of network capacity, the deployment of renewable energy and storage, the financial exposure of developers and the charges ultimately associated with electricity supply. By setting a two-year threshold, CERC has created a defined point at which prolonged delay can trigger a change in the project’s relationship with the grid.
The available evidence does not establish whether the new provisions will accelerate project completion, lower consumer tariffs or materially increase renewable energy integration. Nor does it identify the number of delayed projects that could use the surrender mechanism. What the amendment does establish is a clearer administrative response to long delays and a requirement for more regular visibility into available substation capacity.
The next test will be operational. The regulations must be published in the Official Gazette before taking effect, after which developers, consumers, the Central Transmission Utility and the relevant nodal agency will have to apply the new procedures. Monthly capacity disclosures, the 15-day processing requirement and the treatment of bank guarantees will show whether the revised framework converts regulatory flexibility into more usable transmission capacity.
