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					</table>The Grid Controller of India (<a href="https://grid-india.in/" target="_blank" rel="noopener">Grid-India</a>) has proposed changes to the Central Electricity Regulatory Commission‘s (<a href="https://cercind.gov.in/index.html" target="_blank" rel="noopener">CERC</a>) draft procedure for the grant of temporary general network access (T-GNA) to the interstate transmission system.
Stakeholders can share their feedback/comments by October 30, 2025.
Grid India has proposed to mandate an adequate margin in the transmission system to enable the scheduling of power projects up to their full T-GNA capacity.
The amendment also proposes that entities registered with the national open access registry (NOAR) for short-term open access approval are no longer exempted from registering with the regional load dispatch centers (RLDC) of their respective state for T-GNA approval.
It also proposes to mandate an adequate margin in the transmission system to enable the scheduling of power projects up to their full capacity for which GNA has been granted.
Bi-Monthly Standing Clearance
In cases where GNA has not yet become effective, RLDC will identify generating stations that have sought approval of deemed T-GNA and provide standing clearance on a bi-monthly basis.
The RLDC will grant the clearance for T-GNA based on the availability of margin in the transmission system.
When allocating transmission margins under T-GNA, renewable energy projects connected to a pooling station via deemed T-GNA will be treated on par with those with GNA and where the GNA is yet to become effective at the same pooling station.
Under the bi-monthly clearance system, applicants seeking standing clearance for a deemed T-GNA between the 1st and 15th of the month must apply within 24 hours of the 25th day of the previous month.
Such applications will be received on a pro-rata basis, and permission will be granted based on available transmission capacity. If applications are received after the 25th of the previous month, they will be treated on a first-come, first-served basis.
Under the same system for seeking standing clearance for the 16th to the end of the month, applications must be filed within the 10th day of the current month. In such cases, the applications are processed on a pro-rata basis based on the availability of transmission margin. Applications received after the 10th day of next month will be processed on a first-come, first-served basis.
In the case of hybrid power generators with or without energy storage systems, standing clearance can be granted for the individual power generator up to their respective installed capacity. The generators must ensure the project’s scheduling remains within the connectivity quantum.
Any entity that has been granted T-GNA for renewable energy projects (T-GNARE) can convert it into a T-GNA by submitting an application to the nodal RLDC. It can also initiate power delivery only after four months from the application date.
Calculation of Margin
 For the calculation of the margin of transactions under the advance bilateral category, the amendment proposes the following formula for calculating export T-GNA margin:
Export T-GNA margin = Export Available Transfer Capacity &#8211;(A% export PPA quantum + approved advance T-GNA
Where ‘A’ factor is determined by the NLDC from time to time, based on renewable energy variability and other system exigencies.
Here, the quantum under PPA will be obtained from the contract information furnished by the entities to RLDCs while scheduling under GNA and T-GNA applications.
Operation Charges
The applicant for bilateral and collective T-GNA must pay operating charges to the host RLDC, along with payment of ISTS charges. These operating charges must be submitted in compliance with the timeline for ISTS charges. Any applicant who fails to pay the operating charges within the timelines will be blocked through the NOAR.
If the applicant for T-GNA or T-GNARE projects fails to pay operating charges within the stipulated time, the approved transmission margin will be rejected. The margin of transmission released will be scheduled for other GNA and T-GNA/T-GNARE applications.
For advance T-GNA or exigency T-GNA under bilateral transaction, the applicant must pay operating charges to the host RLDC at the rate of ₹1,000 (~$11.3)/day.
A regional entity that already pays RLDC charges for the installed capacity under the RLDC Fees and Charges Regulations is exempt from paying operating charges for T-GNA for the same installed capacity.
For collective transactions, each successful buyer and seller must pay NLDC operating charges to the respective power exchange, based on the energy scheduled by NLDC, at the rate of ₹1 (~$0.01)/MWh, and subject to a maximum of ₹200 (~$2.26) per day.
Each successful buyer must pay operating charges for T-GNA under collective transactions for drawal schedules exceeding the GNA quantum, the T-GNA quantum, or both.
To determine whether the drawal schedule exceeded the GNA quantum, T-GNA quantum, or both in the case of a collective transaction, the SLDC will furnish to NLDC each intrastate entity-wise detail of schedules under GNA or T-GNA, as applicable, by 1400 hours of the next day of delivery. The intrastate entity-wise detail of schedules must be transferred through the NOAR.
Upon receiving this information, NLDC will issue a power exchange-wise and entity-wise segregation of payable operating charges by 1700 hours on the next day of delivery.
The payable operating charges will be allocated to the power exchanges in the ratio of requisition by the entity in the respective exchange for the day.
If the NLDC does not receive the information from SLDC by 1400 hours of the next day of delivery, it must issue operating charges by 1700 hours of the next day of delivery.
NOAR will notify the operating charges for T-GNA under collective transactions at 1700 hours on the next day, and payments of operating charges will be made by the exchanges to NLDC by 2400 hours on the next day.
Operating charges will also apply to the scheduling of power from an alternate source by a generating station in accordance with the Indian Electricity Grid Code.
In cases where Advance T-GNA or T-GNARE for more than one month in advance is scheduled to start within the next three working days, the transmission charges for the first month must be deposited by 04:00 hours of the day prior to the scheduling of the transaction under T-GNA/T-GNARE approval.
The transmission charges for subsequent months will be paid by 24:00 hours, two days before the last day of the current month, for transactions in the next month on a rolling basis.
Failure to comply with this schedule will also result in the defaulting applicant being auto-blocked through NOAR.
In the event of power curtailment, transmission constraints, or revisions to transactions from the previous month, the nodal agency will refund operating and ISTS charges to concerned applicants, including power exchanges, by the 15th day of the following month. In case no discrepancy is reported within 15 days from the date of issue of the reconciliation statement, the statement will be deemed reconciled.
Recently, CERC <a href="https://mercomindia.com/cerc-notifies-amendment-to-connectivity-and-gna-regulations-2025" target="_blank" rel="noopener">notified</a> the Connectivity and GNA to the Interstate Transmission System (Third Amendment) Regulations, 2025. The new rules modify several aspects of the Principal Regulations of 2022, introducing expanded definitions, revised procedures for application withdrawals, restructuring of bank guarantee requirements, rules for connectivity to ISTS substations, and detailed compliance obligations for renewable generating stations and energy storage systems.
Subscribe to Mercom’s real-time <a href="https://www.mercomindia.com/product/mercoms-renewable-energy-regulatory-updates" target="_blank" rel="noopener">Regulatory Updates</a> to ensure you don’t miss any critical updates from the renewable industry.

Grid India Proposes Transmission Margin for Full T-GNA Capacity Utilization

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					</table>The Ministry of Power (<a href="https://powermin.gov.in/" target="_blank" rel="noopener">MOP</a>) has proposed regulating short-term and general network access (GNA) for distribution licensees (DISCOMs) who fail to clear their dues even after two and a half months.
The Ministry has proposed amendments to the Electricity (Late Payment Surcharge and Related Matters) Rules 2023, and encouraged Interested stakeholders to submit their comments by January 12, 2024.
The regulations will be referred to as the Electricity (Late Payment Surcharge and Related Matters) (Amendment) Rules, 2023. They are scheduled to become effective upon their publication in the official gazette.
The first amendment to the rules outlines the measures to be taken in cases of non-payment of dues by the distribution licensee or other users of the transmission system, even after two and a half months from the presentation of the bill by the generating company, transmission licensee, or trading licensee, or in the case of default in the payment of installments.
The short-term access or temporary general network access (T-GNA) or GNA for the sale and purchase of electricity through short-term contracts or power exchanges will be entirely regulated for the defaulting DISCOM.
The same restriction will apply to any existing short-term access, T-GNA or GNA.
The National Load Despatch Centre may, under exceptional circumstances for grid security, temporarily review the regulation of short-term access or T-GNA and GNA after recording the reasons in writing.
If, one month after this regulation of access, or if the dues remain unpaid for three and a half months, the medium-term open access or long-term access or T-GNA or GNA for the sale and purchase of electricity through contracts other than short-term contracts would be regulated by 10%.
The reduction or drawal of long-term access, medium-term open access, or T-GNA of GNA for the sale and purchase of electricity through contracts other than short-term contracts will occur progressively by 10% each month.
Only after the payment of outstanding dues will the regulation of short-term, medium-term open access, long-term access, or T-GNA or GNA under this rule end and be restored at the earliest, but not later than two days.
The National Load Despatch Centre is expected to issue a detailed procedure to implement these rules.
In case of the reduction of the drawl schedule, the liability for payment of capacity charges for its original share in the generating station and the inter-state transmission (ISTS) charges will remain with the regulated entity.
&#8220;Short-term access&#8221; in the above context is defined as access to the transmission system for up to one year. &#8220;Medium-term open access&#8221; pertains to access for periods ranging from one to three years, while &#8220;long-term open access&#8221; refers to access for periods exceeding three years.
Additionally, the term &#8220;short-term contract&#8221; means a contract for the sale or purchase of electricity for up to one year.
Power not requisitioned by a distribution licensee
The second proposed amendment will mandate the DISCOM to communicate its power requisition schedule for each day, pertaining to each generating company with which it has a purchase agreement, at least two hours before the closure of the timeframe for submitting proposals or bids in the day-ahead market for that day.
In the event of a failure to provide such intimation, the generating company can offer the un-requisitioned surplus power, inclusive of power available against the declared capacity of the unit under shutdown, in the power exchanges while adhering to the specified limitations on ramping and start-up capabilities as outlined in the grid code.
Provided that in cases where the power offered by the generating company remains uncleared in the Day-Ahead Market (DAM), it will subsequently be offered in other market segments, including the Real-Time Market (RTM), within the power exchanges.
Additionally, such power offerings in the market will be subjected to a price ceiling not exceeding 120% of its energy charge, as determined or adopted by the appropriate commission.
Suppose the generating company fails to present such un-requisitioned surplus power in the power exchanges. In that case, the un-requisitioned surplus power, up to the declared capacity and not offered in the power exchanges, will not be considered available for computing the payment of fixed charges.
In June last year, MoP <a href="https://www.mercomindia.com/discoms-allowed-clear-dues-generators-48-installments" target="_blank" rel="noopener">notified</a> the ‘Late Payment Surcharge and Related Matters Rules, 2022.’ According to the rules, a late payment surcharge will be payable on the outstanding amount after the due date at the base rate of the late payment surcharge applicable for the first month of default.
DISCOMs owed power generators ₹799.77 billion (~$9.6 billion) in total dues for the monthly billing cycle in October 2023. The current outstanding dues, excluding the latest monthly dues, are ₹232.62 billion (~$2.8 billion). The overdue before the trigger date is ₹232.46 billion (~$3.3 billion), after which the amount will increase by ₹160.1 million (~$1.9 million) as the late payment surcharge would become applicable.
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Ministry to Regulate Transmission Access for DISCOMs Failing to Clear Dues

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					</table>The Central Electricity Regulatory Commission (<a href="https://cercind.gov.in/" target="_blank" rel="noopener">CERC</a>) 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 <a href="https://www.nhpcindia.com/" target="_blank" rel="noopener">NHPC</a>, <a href="https://sjvn.nic.in/" target="_blank" rel="noopener">SJVN</a>, <a href="https://www.ntpc.co.in/" target="_blank" rel="noopener">NTPC</a>, <a href="https://www.thdc.co.in/" target="_blank" rel="noopener">THDC India</a>, <a href="https://posoco.in/" target="_blank" rel="noopener">Grid-India</a>, and Northeast Regional Power Committees (<a href="https://www.india.gov.in/website-north-eastern-regional-power-committee-ministry-power" target="_blank" rel="noopener">NERPC</a>), 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 &#8216;D&#8217; 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, &#8216;D&#8217; 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&#8217;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&#8217;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&#8217;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 &#8220;design capabilities up to the rated water.&#8221;
The central regulator emphasized that trial runs should demonstrate the unit&#8217;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 &#8216;D-1&#8217; 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 &#8220;Power to Remove Difficulty&#8221; 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 &#8220;First Time Charging/Energization (FTC) and Integration of New or Modified Power System Element,&#8221; 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 <a href="https://www.mercomindia.com/cerc-requisition-power-needs/" target="_blank" rel="noopener">response</a> 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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CERC Allows Power Generators Two Capacity Revisions for Six Months from October

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