The Central Electricity Regulatory Commission (CERC) has addressed certain issues related to the implementation of the CERC (Indian Electricity Grid Code) Regulations, 2023.

The Grid Code was published on July 11, 2023, and its provisions were to become effective from October 1, 2023.

Several entities, including NHPC, SJVN, NTPC, THDC India, Grid-India, and Northeast Regional Power Committees (NERPC), raised concerns about specific aspects of the Grid Code and sought clarification on these issues.

Scheduling of Generating Units

NHPC expressed concerns about scheduling power generation from solar, wind, and hydro projects. It proposed that these must-run power projects should be allowed to schedule power from 00:00 hrs of D+1, where D refers to the first day of the supply schedule.

THDC also emphasized the need for more flexibility in scheduling to avoid revenue loss and underutilization of resources.

The CERC examined the existing provisions in Clause 2 of Regulation 27 of the Grid Code, which stated that scheduling of a generating station or unit should start from 00:00 hours of D+2. The Grid Code initially suggested scheduling from D+3 to allow for margin assessment and timely unit commitment decisions.

The CERC clarified that ‘D’ referred to in Clause 2 of Regulation 27 should be the date when a generating station notifies its COD. Scheduling should commence from 00:00 hours of D+2. For instance, if a generating station wishes to declare its COD at 00:00 hrs on 5.11.2023, it must inform the COD date no later than November 3, 2023. In this scenario, ‘D’ would be November 3, 2023, and scheduling would start at 00:00 hrs on November 5, 2023.

Revision of Estimated Restoration Time

NHPC highlighted the challenges of revising estimated restoration times in case of forced outages. It suggested that the restriction on revision should be lifted to accommodate variations in restoration times due to the nature of faults and unforeseen circumstances. THDC supported this proposal.

The CERC, which examined Clause 7 of Regulation 49 of the Grid Code, also allowed for the revision of estimated restoration times once a day.

It also clarified that revising the declared capacity from the seventh/eighth block due to a forced outage and declaring an estimated restoration time would not count as two separate revisions. Instead, they would be considered a single revision. This clarification allows generating stations more flexibility in revising schedules based on evolving circumstances.

Revision of Declared Capacity

NHPC raised concerns about hydropower stations and their day-ahead scheduling based on the previous day’s inflow patterns. It pointed out that actual inflow can vary significantly due to rainfall or snow melting upstream of reservoirs, leading to forecast inaccuracies. It suggested allowing revisions in the schedule to accommodate these forecasting errors, especially for Pondage and Run-of-River hydropower stations.

The CERC acknowledged that while frequent revisions of declared capacity could create uncertainty for beneficiaries, it also recognized the practical difficulties faced by different types of generating stations. To strike a balance, the CERC allowed generating stations or energy storage systems covered under Regulation 49(7) to make up to two revisions of declared capacity and schedule in a day. `The revised schedule would become effective from the seventh or eighth time block, as Clause (4) of Regulation 49 specified.

This dispensation would be allowed for six months from October 1, 2023.

Obligation to Supply in Case of Unit Shutdown

NTPC raised concerns about the Grid Code’s obligation to supply in case a generating unit is taken under shutdown. They noted that if a unit opts for shutdown, it would still be required to fulfill its obligation to supply electricity to its beneficiaries, which could lead to extra costs.

Grid-India also requested clarification on how the treatment of declared capacity and revision of schedules would work when a project chooses to go under shutdown.

The CERC referred to Clauses (1) and (2) of Regulation 47 of the Grid Code, which address Unit Shutdown (USD) and the obligations of supplying electricity when a generating station opts for shutdown.

The CERC clarified that if a generating station chooses to go under shutdown while retaining its declared capacity, it must supply electricity to beneficiaries who made requisitions before the shutdown. To meet this obligation, the generating station must arrange supply from alternative sources or enter into contracts under the Power Market Regulation.

However, beneficiaries cannot request a schedule if the generating station revises its declared capacity (if allowed as per the Grid Code). Hence, no obligation to supply is cast on the generating station.

Revision of Schedule of RE Generators under T-GNA

Grid-India raised concerns about the provisions for revising schedules for wind/solar and run-of-river (ROR) generators under the Transmission and General Network Access (T-GNA) regulations. It pointed out that while wind/solar and ROR generators can revise schedules for bilateral transactions due to forecasting errors, there is no clarity regarding revisions for GNA and T-GNA schedules. It also highlighted that there could be complexities in scheduling for ROR projects in tandem, where water inflows depend on pondage and upstream generation.

CERC noted that wind/solar sellers could revise schedules in bilateral transactions to accommodate the intermittent nature of renewable sources. However, there were specific cases involving GNA and T-GNA where wind/solar sellers or ROR generating stations needed clarity on the revision of schedules due to forecasting errors.

CERC clarified that wind/solar sellers and ROR generating stations should be able to revise their schedules, regardless of whether they are under GNA or deemed T-GNA. This revision is permitted in case of bilateral transactions as per Regulation 49(8) and 49(9) of the Grid Code, even for Cases 2, 3, and 4.

Trial Run of a Pumped Storage Project

THDC raised concerns about the trial run of a pumped storage project, specifically the Tehri Pumped Storage Project. It noted that the project’s unit capacity depends on the water level (varying from 740 m to 830 m) from the upstream Tehri reservoir. During periods of lower reservoir levels, it might not be possible to demonstrate the “design capabilities up to the rated water.”

The central regulator emphasized that trial runs should demonstrate the unit’s capacity corresponding to the maximum continuous rating under Regulation 22(2)(a). If this is impossible due to insufficient reservoir levels, the project can declare a COD after demonstrating capabilities at available water levels. However, it must immediately demonstrate design capabilities up to the rated water drawing levels once sufficient reservoir levels are available after COD. If the project fails to do so, it can de-rate capacity or conduct a repeat trial run.

Consent to a Generator for Scheduling in the Day Ahead Market

Grid-India highlighted a provision in the Grid Code, Regulation 49(1)(l), which allows the consent of beneficiaries or buyers to be withheld when a generating station whose tariff is determined under Section 62 of the Electricity Act 2003 seeks to sell un-requisitioned surplus power in the day ahead market. It contended that this provision contradicts Rule 9 of the Electricity (Late Payment Surcharge and Related Matters) Rules 2022.

The CERC clarified that the provision in Regulation 49(1)(l) of the Grid Code takes precedence, and generating stations subject to tariff determination under Section 62 can sell their un-requisitioned surplus power in the day ahead market without the need for consent. This clarification aligns with the provisions of the Grid Code and maintains consistency in power market operations.

Transition from STOA to T-GNA Regime

Grid-India raised concerns regarding the priority of allotment of transmission corridors for exigency T-GNA transactions created through the conversion of approved Short-Term Open Access (STOA) transactions. It noted that exigency T-GNA transactions have lower priority than advance T-GNA transactions as per the provisions of the GNA regulations.

CERC clarified that STOA transactions, which have already been approved, are treated as exigency applications since their access and schedule are similar to exigency transactions. However, since they are pre-approved transactions, they should be given priority in the corridor after scheduling GNA transactions by 9 AM on ‘D-1’ day.

First-Time Energization and Integration of New Power System Elements

The Commission addressed concerns related to the first-time energization and integration procedure of new or modified power system elements, as per Regulation 8(2) of the Grid Code.

Regulation 8(2) mandates that the NLDC, in coordination with RPCs and RLDCs, outlines a detailed procedure for first-time energization and integration of new or modified power system elements. This procedure must cover various aspects, including integration with the grid (e.g., protection, telemetry, communication systems, metering, statutory clearances), data requirements for system studies, and timelines for data submission. The procedure requires approval from the Commission.

NLDC submitted this procedure for approval by the Commission on September 28, 2023. However, since the Grid Code became effective on October 1, 2023, there might be a gap until the new procedure is examined and approved by the Commission.

CERC issued directions under the “Power to Remove Difficulty” provisions mentioned in Regulation 58 of the Grid Code to address this gap. These provisions empower the Commission to make necessary provisions for removing difficulties in implementing the Grid Code.

In this context, CERC directed that the existing procedure for “First Time Charging/Energization (FTC) and Integration of New or Modified Power System Element,” which was in practice as of September 30, 2023, will continue to be in force until the new procedure framed under the Grid Code receives approval from the Commission.

In response to a significant surge in power demand and subsequent reports of load-shedding incidents, the Commission took a series of strategic measures to mitigate the current power shortage and enhance the grid’s efficiency.

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