BACKGROUND

On 31.07.2026, the Central Electricity Regulatory Commission (“CERC”) has issued a draft notification proposing the fifth amendment to the CERC (Sharing of Inter-State Transmission Charges and Losses) Regulations, 2020 (“Principal Regulations”), framed under Section 178 of the Electricity Act, 2003 (“Act”). CERC has invited comments/ suggestions and objections from stakeholders and interested persons until 31.08.2026.

The Principal Regulations were notified in 2020 and have already been amended four times. The fourth amendment, notified in 2025 (“Fourth Amendment”), introduced the graded waiver trajectory presently set out at Table 1 to Regulation 13(2)(a) of the Principal Regulations, a full 100% waiver of ISTS charges for 25 years for a wind/solar based REGS or RHGS commissioned on or before 30.06.2025, tapering to 75%, 50% and 25% for projects commissioned in the three succeeding years up to 30.06.2028, and to nil thereafter. The Fourth Amendment also added offshore wind as a fourth identified renewable source.

The Fourth Amendment also inserted the existing sub-clause (h) to Regulation 13(2) of the Principal Regulations, which permitted a project whose Scheduled Commercial Operation Date (“SCOD”) fell on or before 30.06.2025, i.e., a project otherwise falling within the 100% waiver band, to be granted an extension of upto one year (in tranches of upto six months each, and upto twice) to its commissioning timeline, where the delay was on account of force majeure, including non-availability of the transmission system, or reasons not attributable to the developer. A project availing of such an extension, and achieving COD within the extended period, continued to be treated as if it had been  commissioned on 30.06.2025, thereby retaining the 100% waiver. However, this dispensation was confined to the 100% waiver band; no comparable relief was available to projects that would otherwise fall within the subsequent graded windows of 75%/50%/25%.

This fifth amendment responds to the representations from the Ministry of New and Renewable Energy (“MNRE”) and other entities, and to a specific directive from the Ministry of Power (“MoP”) vide Office Memorandum dated 16.04.2026 (“OM”), with reference to CERC, seeking to extend this dispensation for delay so that it also covers projects falling within the 75%/50%/25% graded waiver windows.

The OM articulated a critical regulatory gap with significant sectoral implications. As noted above, while a project otherwise falling within the 100% waiver band could seek relief from a transmission-attributable delay under the existing sub-clause (h), no comparable relief existed for projects falling within the 75%/50%/25% graded windows. Under existing Regulation 13 of the Principal Regulations, such projects lose  transmission charges waiver, in whole or in part, if the Commercial Operation Date (“COD”) is delayed, regardless of the reason. Where delays originate from transmission system unavailability, matters entirely outside the developer’s control, this regulatory treatment and structural mismatch between the generating station and the transmission infrastructure has disrupted the project financing for multiple developers and raised sectoral concerns regarding India’s renewable capacity expansion targets.

The MoPs directive reflects a policy imperative to align regulatory treatment with project economics and accelerate renewable energy deployment by de-risking transmission-delay scenarios.

Beyond the three headline changes below, the draft also clarifies that Green Day-Ahead Market purchases count toward the 51% renewable-charging requirement for storage; permits contract-wise (rather than project-wise) assessment of that 51% test for pumped-storage plants with multiple beneficiaries, and makes technical clarifications to definitions and procedure.

CO-LOCATED STORAGE: FIXING THE 12 YEAR CLIFF

Under existing Regulation 13(2)(a), a wind/solar Renewable Energy Generating Station (“REGS”) or Renewable Hydro Generating Station (“RHGS”) gets a 25-year ISTS waiver, i.e., graded by COD (100% declining to nil across four slabs ending by 30.06.2028). However, Battery Energy Storage Systems (“BESS”), sits under a separate Table 2, that fixes 100% waiver at maximum of 12 years. MNRE’s OM dated 31.03.2026 identified this critical “financial cliff ”. Since, Power Purchase Agreements (“PPAs”) are typically executed for a period of 25 years and require storage facilities for generation for the 25 year period, the 12-year waiver period destabilised the tariffs already bid on that assumption.

CERC’s solution does not simply extend the ISTS waiver for BESS to 25 years on a standalone basis, i.e., as an independent asset. Instead, only where connectivity for a REGS/RHGS is obtained specifying storage as part of the project (including storage added later as a source change), and the two assets are scheduled as one single unit, the combined energy output, i.e., the generation plus storage, receives the REGS/RHGS’s own 25-year waiver schedule, with the waiver period starting from REGS’s COD and not the battery’s. Hence, CERC continues to recognise the battery as a 12-year asset; the amendment simply unifies the waiver period and assumes battery replacement/upgradation to be included in the PPA to keep pace.

A related change concerns cycle-wise charging. A solar-charged BESS can generally draw power from its co-located REGS only during the day and may need to charge from other sources, such as wind power through the ISTS, during the evening. The amendment introduces a new proviso to Regulation 13(2)(b)(ii), allowing each charging cycle to be assessed separately. Therefore, a cycle charged from the co-located REGS would qualify for the favourable treatment under Schedule 1 of Table 2, while a cycle charged from another source would be subject to the graded charges under Schedule 2. Accordingly, the National Load Dispatch Centre (“NLDC”) is to frame the detailed accounting procedure for implementing this mechanism.

DUAL CONNECTIVITY: ACCOUNTING FOR STU-ROUTED POWER

Large round-the-clock consumers, such as data centres, green hydrogen/ammonia plants and smelters, are increasingly seeking connectivity to both the ISTS and intra-State transmission networks. The draft GNA (Fourth Amendment) Regulations, 2026 propose to permit such dual connectivity. However, these entities would be eligible to apply only for ordinary GNA and not GNA for renewable energy (“GNARE”). This restriction follows concerns raised by Distribution Licensees and the Central Electricity Authority that dual connectivity may result in parallel or duplicated transmission infrastructure being created for the same consumer, with the associated costs potentially being passed through to other consumers by way of transmission charges.

Because a dual-connected drawee entity may draw part of its power directly through STU feeders, the Fifth Amendment adds a proviso to Regulation 12(1)(b). The lower of the actual or scheduled STU-drawn quantum in a time block is added to the State’s net drawl, if the State is a net-drawl State, or subtracted from its net injection, if it is in net-injection mode. If the STU-entity interface meter shows the opposite flow, the quantum is treated as zero. A companion proviso to sub-clause (c) provides that such an entity’s transmission deviation is calculated against the sum of its ISTS GNA and its “Access with STU”, so that its full permitted access through both networks is taken into account. The STU is required to share this access data with NLDC and CTU. These provisions, however, are conditional on the GNA Fourth Amendment itself being finalised.

A related fix addresses intra-State entities that separately hold GNARE/Temporary GNARE. Since such access permits drawl only from identified renewable sources, any drawl beyond that, even within the sanctioned quantum, is now treated as a deviation, extending the mechanism that already applied to regional entities. (Example: a State with 5,000 MW GNA, an intra-State entity holding 500 MW GNARE scheduling 300 MW from identified sources, and total State drawal of 5,450 MW, yields a 150 MW deviation.)

THE EXTENDED WAIVER WINDOW: RELIEF FOR TRANSMISSION-DELAYED PROJECTS

This represents the amendment’s most significant change for developers. As enumerated above, until now, only a project otherwise falling within the 100% waiver band could seek relief from a transmission-attributable delay, through the existing sub-clause (h) extension. Under the existing waiver schedule (Table 1), however, a project falling within the subsequent 75%/50%/25% graded windows had no such recourse: its waiver depended strictly on actual COD, and a delay solely because its transmission infrastructure was not commissioned could reduce its waiver, or eliminate it entirely, even though the ISTS waiver benefits the procurer, not the developer, generating PPA disputes over who absorbs the cost.

The MoP’s OM which this amendment formally recognises and operationalises, accordingly requested CERC to extend the dispensation for delay – until then confined to the 100% waiver band – so that it also covers projects falling within the subsequent 75%/50%/25% graded windows, with a firm PPA as of 31.03.2026, a firm connectivity date between 01.07.2025 and 30.06.2028, and COD achieved within a specified period in coordination with the COD of the transmission infrastructure.

Consequently, CERC has operationalised MoP’s OM through new sub-clauses (h-i) and (h-ii) and an accompanying Table 6, which – unlike the existing sub-clause (h), extends the delay relief dispensation across all four connectivity-date bands (100%/75%/50%/25%), and not merely the 100% band. Sub-clause (h-i) makes a wind/solar REGS or RHGS eligible for a waiver pegged to its firm connectivity date (not actual COD) where it: (i) has a minimum 7-year PPA with a procurer, signed on or before 31.12.2026 (CERC’s own cutoff, since MoP’s 31.03.2026 date had already lapsed); (ii) was delayed beyond its firm connectivity date specifically due to non-availability of the transmission system; and (iii) achieves COD within two months of its GNA becoming effective.

The waiver is subject to three additional conditions: (i) no extension or substitution of the qualifying PPA will be recognised; (ii) the PPA must be submitted to Central Transmission Utility of India Limited (“CTUIL”) and NLDC by 31.01.2027, and where the contract is routed through a trader or REIA, both legs of the PPA must be furnished, with each leg dated on or before 31.12.2026; and (iii) if the Project does not achieve COD within two months of its GNA becoming effective, it will fall back to the ordinary Table 1 trajectory, which may result in no waiver.

CERC has also broadened what counts as a “firm” PPA. Previously only Section 63 competitive-bid PPAs qualified; now any agreement that is enforceable under the Contract Act, 1872 is accepted, provided the complete supply chain, i.e., the supplier to the procurer is documented and the tenure is at least 7 years. The two-month grace period runs from GNA effectiveness rather than the transmission-system COD, since effective of GNA already requires all identified elements achieving COD.

Where a project qualifies under both the ordinary Table 1 pathway and the new Table 6 pathway, sub-clause (h-ii) requires the project to choose one of the two pathways by submitting an undertaking to NLDC and CTUIL within 15 days of COD. Once made, this choice cannot be changed. The choice is important because the two pathways provide different benefits: Table 6 may provide a higher percentage of waiver, but only for the tenure of the qualifying contract (for example, 15 years), whereas Table 1 may provide a lower percentage of waiver but for the entire 25-year period.

For project developers, this mechanism as structured insurance against the risk of the associated or dedicated transmission infrastructure’s readiness risk rather than a blanket relief. It de-links the waiver from the COD of the developer However, this protection is not automatic and requires an early, qualifying long-term PPA, current paperwork with CTUIL/NLDC, and scheduled commissioning once the transmission grid is operational. Developers and financiers evaluating delayed projects should model both the Table 1 and Table 6 outcomes before the 15-day election window opens, since the choice cannot be revisited.

CONCLUSION

The co-located storage and dual-connectivity changes are largely accounting and eligibility clarifications that address  closing gaps that surfaced through implementation emerging from operational experience. The extended waiver window is a new, time-bound relief route that directly operationalises the MoP’s OM, extending the delay-relief dispensation earlier available only to the 100% waiver band under sub-clause (h) so that it now also covers projects within the subsequent 75%/50%/25% graded windows. Its value to any given project depends heavily on whether a qualifying long-term PPA is already in place, whether the delay is attributable specifically to transmission infrastructure not being available, and whether commissioning of the generating station can realistically happen within two months of GNA effectiveness. The draft amendment remains open for stakeholder consultation until 31.08.2026 to seek changes.