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					</table>The Andhra Pradesh Electricity Regulatory Commission (<a href="https://aperc.gov.in/" target="_blank" rel="noopener">APERC</a>) has quashed a Tata Power Renewable Energy (<a href="https://www.tatapowerrenewables.com/" target="_blank" rel="noopener">TPREL</a>) petition seeking compensation from Andhra Pradesh state electricity authorities for deemed generation losses, claiming that the curtailment was due to insufficient transmission capacity.
However, the Commission found no breach of the Power Purchase Agreement (PPA) by the respondents and concluded that the curtailment was justified under grid security considerations.
Background
Tata Power Renewable Energy (TPREL), a subsidiary of Tata Power Company, operates a 100 MW wind power plant in Anantapur District, Andhra Pradesh.
The New and Renewable Energy Department Corporation of Andhra Pradesh approved the project, which was commissioned in two phases between December 2016 and March 2017.
A PPA was executed with the Southern Power Distribution Company of Andhra Pradesh (<a href="https://www.apspdcl.in/index.jsp" target="_blank" rel="noopener">APSPDCL</a>), ensuring a tariff of ₹4.84 (~$0.05) per unit for 25 years.
TPREL claimed it faced significant challenges in evacuating power due to the limited capacity of the Uravakonda GSS.
The Andhra Pradesh State Load Despatch Centre (<a href="https://cms.mercomindia.com/gensol-enters-us-market-with-solar-trackers-subsidiary-scorpius/" target="_blank" rel="noopener">APSLDC</a>) and the Transmission Corporation of Andhra Pradesh (<a href="https://aptransco.co.in/" target="_blank" rel="noopener">APTRANSCO</a>) issued curtailment instructions, restricting the evacuation of power to as low as 67% of the installed capacity at times.
This curtailment was attributed to the inadequate transformation capacity at the grid substation and other technical constraints.
Commission&#8217;s Analysis
The Commission analyzed whether the respondents, APSLDC and APTRANSCO, failed in their statutory duties to provide adequate transmission capacity for the evacuation of power from TPREL&#8217;s wind power project.
TPREL argued that the curtailment violated the terms of the PPA and the statutory obligations under the Electricity Act, 2003. The company sought compensation for the deemed generation losses amounting to ₹683.9 million (~$8.1 million).
However, APSLDC and APTRANSCO contended that the PPA did not contemplate compensation for such curtailments, and the curtailment was necessary for grid security.
The respondents maintained that the curtailment complied with the Indian Electricity Grid Code and the Andhra Pradesh Code of Technical Interface . They argued that the curtailments were necessary to maintain grid stability and were not solely due to infrastructural inadequacies.
The Commission concluded that while there were genuine transmission constraints, the respondents had taken steps to address these issues, including upgrading the infrastructure and exploring alternative transmission routes.
Recently, APERC <a href="https://www.mercomindia.com/andhra-regulator-approves-7-gw-solar-power" target="_blank" rel="noopener">approved</a> a tripartite Power Supply Agreement allowing the Andhra Pradesh Green Energy Corporation, now known as AP Rural Agriculture Power Supply Company, to draw 7 GW of solar power from the Solar Energy Corporation of India.
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Andhra Regulator Rejects Wind Project’s Claim for Deemed Generation Losses

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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/index.html" target="_blank" rel="noopener">CERC</a>) has amended the CERC (Sharing of Inter-State Transmission Charges and Losses) Regulations, 2020, to provide a structured framework to address delays, promote accountability, and streamline the billing process.
Effective from November 1, 2023, these amendments will be known as CERC (Sharing of Inter-State Transmission Charges and Losses) (Second Amendment) Regulations, 2023.
Definition of &#8220;Deemed COD&#8221;
The amendment brings an important change by defining the Deemed Commercial Operation Date (COD). Deemed COD represents the commercial operation date for a transmission system or its parts. There are two scenarios for determining Deemed COD:
<ol>
<li>Under regulated tariff mechanisms, the COD is approved by the Commission following specific rules in the CERC (Indian Electricity Grid Code) Regulations of 2023, the Tariff Regulations of 2014, or the Tariff Regulations of 2019.</li>
<li>The transmission licensee will declare the Deemed COD for transmission systems or parts managed through tariff-based competitive bidding.</li>
</ol>
Redefining &#8220;Is Delayed&#8221; and Introducing New Clauses
The amendment makes several fundamental changes. First, it replaces &#8220;is delayed&#8221; with &#8220;has not been achieved.&#8221; A new set of rules has been introduced outlining how yearly transmission charges (YTC) are treated for inter-state transmission systems (ISTS) or parts considered Deemed COD.
The new rules stipulate the following:
<ul>
<li>Inter-State transmission licensees will receive 50% of their YTC for the first six months or until actual power flow starts, whichever comes first, from the Deemed COD.</li>
<li>They will receive 100% of YTC from the seventh month onward if the power flow hasn&#8217;t begun within six months of the Deemed COD.</li>
<li>If there is a shortfall, additional funds will be sourced from T-GNA and T-GNARE or, if necessary, from the Deviation and Ancillary Service Pool Account under DSM Regulations.</li>
</ul>
These rules do not apply to transmission elements covered under the transformer component. Instead, such elements will be billed to the respective drawee designated ISTS consumer of the state from the Deemed COD date. In cases where separate YTCs are unavailable, the calculation will be based on the estimated capital cost of similar configurations in the ISTS.
Delays and Liquidated Damages
The amendment deals with situations where one inter-state transmission licensee causes a delay in another licensee&#8217;s system that has achieved Deemed COD.
In such cases, the responsible licensee must pay 50% of its system&#8217;s YTC or 50% of the YTC of the system that achieved Deemed COD, whichever is lower, until the delayed system achieves COD. This rule applies no matter what agreements are in place between the parties. If liquidated damages are imposed for the delay, that amount will be used to offset the liability, and any remaining balance will be credited to the Regional Transmission Deviation account.
Similar rules apply to intra-state transmission licensees, causing delays. They need to pay 50% of the YTC for the delayed intra-state transmission system or 50% of the YTC for the ISTS that achieved Deemed COD (excluding elements under the Transformer component). When YTC for the delayed intra-state system is unavailable, the Central Transmission Utility will calculate it based on the estimated capital cost of similar setups in the ISTS.
Impact on Tariff-Based Competitive Bidding
For ISTS operating under tariff-based competitive bidding, the first contract year begins when the transmission licensee receives 100% YTC.
The Commission recently <a href="https://www.mercomindia.com/cerc-allows-power-generators-two-capacity-revisions/" target="_blank" rel="noopener">addressed</a> issues related to implementing the Grid Code Regulations about the scheduling of generating units, revision of estimated restoration time, revision of declared capacity, and obligation to supply in case of unit shutdown, among others.
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CERC Amends Power Transmission Rules for Greater Accountability

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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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