CERC Proposes Second Amendment to Indian Electricity Grid Code Regulations

The Central Electricity Regulatory Commission (“CERC”), vide Draft Central Electricity Regulatory Commission (Indian Electricity Grid Code) (Second Amendment) Regulations, 2026 dated September 21, 2026, has proposed amendments to the CERC (Indian Electricity Grid Code) Regulations, 2023. The amendments seek to revise provisions relating to trial runs, commercial operation date (COD), pumped storage plants (PSPs), energy storage systems (ESS), scheduling, reserves, congestion charges and access regulation for defaulting entities. The amendments are proposed to take effect from publication in the Official Gazette, except the amendments under Para 16(B), which are proposed to take effect from April 1, 2027.

The Draft Regulations propose changes to the trial-run framework and the period for interchange of power:

1. The notice period for a trial run or repeat trial run is proposed to be reduced from 7 days to 3 days.
2. Renewable Energy Generating Stations (REGS) and ESS, other than Hydro PSP ESS, seeking extension of the period for interchange of power would be required to provide reasons for delay and the likely COD, with the extension request being made at least 10 days before the proposed start date. RLDC may grant multiple extensions, subject to a cumulative limit of 3 months, with monthly status updates.
3. For standalone ESS, a minimum aggregate capacity of 50 MW is proposed for trial runs, with specified provisions for projects below and above 50 MW. Projects of 250 MW and above may conduct trial runs in instalments of at least 50 MW without a limit on the number of instalments.

The Draft Regulations prescribe specific trial-run requirements for PSPs. Short interruptions or load reductions may be permitted with a corresponding extension of the trial, while cumulative interruption exceeding 4 hours would require a repeat trial. Where rated water-drawing capability cannot be demonstrated due to insufficient reservoir levels, COD may be declared subject to demonstration once sufficient reservoir level is available; if the PSP is then unable to demonstrate its design capabilities, it may opt for a repeat trial run or de-rate its capacity, with de-rating effective from COD. Further, where rated capacity cannot be demonstrated within one year of COD due to transmission constraints, the demonstration period may extend to one year from the effectiveness of GNA or one year from COD, whichever is later.

A separate COD mechanism is proposed for PSPs, under which COD of each unit would be declared after a successful trial run at MCR or de-rated capacity and submission of the prescribed declaration, with COD of the last unit being treated as COD of the plant. For renewable generating stations and ESS, the Draft Regulations also propose to delink declaration of COD under the Grid Code from contractual conditions under the PPA, while requiring such contractual conditions to be fulfilled before supply under the contract.

PSPs of 25 MW and above and ESS, other than PSPs, of 10 MW and above connected at 33 kV and above would be brought within the specified primary response framework, in accordance with the applicable CEA connectivity standards. The reserve-estimation methodology may use percentiles other than the existing 99th percentile, with corresponding changes to regional and State control-area requirements.

Regulation of access for defaulting entities is proposed to be incorporated into the Grid Code.  Upon the default trigger date for non-payment of DSM, congestion or reactive energy charges, or non-maintenance of payment security:

1. T-GNA, including approved T-GNA for short-term contracts and power exchange transactions, may be regulated entirely, subject to limited relaxation by NLDC in exceptional grid-security circumstances.
2. If dues remain unpaid for two months thereafter, short-term contracts under GNA may also be regulated entirely.
3. Access for contracts other than short-term contracts would be progressively reduced by 5% for each month of default.
4. Upon payment of outstanding dues or maintenance of adequate payment security, access is to be restored at the earliest and in any event within one day, excluding the date of payment.

The Draft Regulations further provide that a State Government having a free-power share in a Central Hydro Generating Station (CHGS) may sell its entitled free-power share directly from the generating station bus bar, with scheduling, accounting and deviation settlement to be undertaken in accordance with the proposed procedure in Annexure 8. The Draft Regulations also provide for revision of declared high-inflow periods based on utility inputs before commencement of the already declared period and prescribe that thermal generating stations cannot declare peak-hour capacity below off-peak capacity, except in cases of forced or partial outage.

Changes are also proposed for scheduling and market timelines. The Draft Regulations introduce revised timelines for unit de-commitment under Unit Shut Down (USD), including advanced intimation by generating stations and an opportunity for beneficiaries to retain units on bar by ensuring at least 50% MCR. NLDC would also be permitted to undertake Security Constrained Unit Commitment (SCUC) at any time for grid security. Further, the timelines for revision of schedules and Real-Time Market (RTM) processes are proposed to be advanced in two phases, with the second phase taking effect from April 1, 2027.

The Draft Regulations also propose to incorporate congestion-charge provisions into the Grid Code and repeal the existing CERC (Measures to relieve congestion in real time operation) Regulations, 2009 and related procedures, while continuing the existing congestion-charge rate until a new rate is notified under the amended Grid Code.