PLOT NO: AH/5 (2ⁿᵈ & 4ᵗʰ Floor) Premises No: MAR 16-1111
Action Area – 1A, New Town, Rajarhat, Kolkata – 700 163
Email: cp-wberc@gov.in
Website: wberc.gov.in
No: 82/WBERC
Dated, the 13ᵗʰ July, 2026
West Bengal Electricity Regulatory Commission (hereinafter referred to as the ‘WBERC’ or ‘the Commission’) was constituted vide Notification No. 06-Power/111 dated 06.01.1999 by the Government of West Bengal, under sub-section (1) of section 17 of the erstwhile Electricity Regulatory Commissions (ERC) Act, 1998 (14 of 1998) to discharge the duties and perform the functions specified under section 22 of the ERC Act, 1998. Upon enactment of the Electricity Act, 2003 (36 of 2003) along with the amendments (hereinafter referred to as ‘the Act’), WBERC became the State Commission in terms of first proviso to sub-section (1) of section 82 of the Act.
Section 61 of the Act empowers the Commission to specify, by regulations, the terms and conditions for determination of tariffs. Section 61 (i) of the Act provides that the Commission shall be guided by the National Electricity Policy and Tariff Policy while making the regulations on terms and conditions of tariff.
Section 181(1) read with Section 181(2) (zd) empowers the Commission to make regulations, consistent with the Act and the rules made thereunder, generally to carry out the purposes of the Act, including the terms and conditions for determination of tariff under Section 61 of the Act.
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Section 181(3) of the Act, read with the Electricity (Procedure for Previous Publication) Rules, 2005, requires the Commission to publish draft regulations and invite objections and suggestions from the public before notifying them.
The West Bengal Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2011, as amended from time to time, have governed the tariff determination in the State for over a decade. However, the Commission recognizes that there has been significant transformation in the power sector since 2011; which includes increase in renewable energy penetration along with its impact on thermal generators, change/variation in fuel sourcing and mix for thermal generating plants, evolving scenario in electricity distribution, Resource Adequacy Planning requirements, Late Payment Surcharge, Rights of Consumers and impetus for tariff rationalization/simplification including ToD Tariffs, etc.
Considering the impact on the State Power Sector due to the above-mentioned aspects and after having an experience of earlier tariff control periods, the Commission considered it necessary to notify a fresh Multi-Year Tariff (MYT) framework in supersession of the 2011 Regulations and the amendments made thereto.
The Commission issued the Draft West Bengal Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2025 (“Draft Regulations”) on 13.11.2025 vide Public Notice No. WBERC/Regulation-81/25-26/668, along with an Explanatory Memorandum setting out the rationale for the principal provisions. Stakeholders were invited to submit suggestions, objections and comments within a month from the date of publication of the Draft Regulations, i.e., by 14.12.2025. Thereafter, applications were submitted by several stakeholders requesting multiple time extensions for submission of comments/suggestions/objections, considering extensive nature of the draft Regulations. The Commission, considering these requests, granted extension of time on four occasions for
submission of comments/suggestions/objections, with the final extended date being 22.06.2026.
The Commission received comments/suggestions/objections from the following eighteen (18) stakeholders:
The Commission in accordance with the Act and the Electricity (Procedure for Previous Publication) Rules, 2005, after consideration of all views/suggestions/objections received upto the final extended date, i.e., 22.06.2026, proceeded to finalize the West Bengal Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2026 ("the Tariff Regulations 2026").
All views/suggestions/objections received have been duly considered and reviewed. This SOR sets out the key issues raised, the Commission's analysis, and its decisions thereon in the succeeding paragraphs.
Several stakeholders have suggested that these Regulations be brought into force from a prospective date and not from 01.04.2026. Some of the generating companies stated that these Regulations necessitate extensive new compliances, reporting and petition-filing requirements. Due to this, it was stated that they need time for system readiness and MYT petition preparation. Accordingly, they proposed that one-year (FY 2026-27) transitional control period be considered and the new Regulations be made prospectively applicable from 01.04.2027. Another suggestion was received seeking transitional arrangements to ensure that existing PPAs and already-finalized tariffs remain valid and are not re-opened or re-interpreted retrospectively. All urged, in substance, that the Regulations be made prospectively applicable to ensure regulatory certainty and orderly implementation.
The Draft Regulations were published on 13.11.2025 and the date of applicability of these Regulations was proposed as 01.04.2026. However, on consideration of the suggestions for prospective applicability by multiple stakeholders, the Commission decides to extend the date of applicability. Further, the Commission vide a Suo Motu Order dated 01.09.2025 in Case No. SM-41/25-26, had already fixed a five-year control period (Ninth Control period) spanning FY 2026-27 to FY 2030-31 for determination of tariff for all generating companies and licensees. Therefore, considering the settled position on the control period as stated above, the Commission is not inclined to accept the suggestion to consider FY 2026-27 as a transitional year.
Accordingly, while the five-year Ninth Control Period is maintained, the Commission has considered it appropriate to make these Regulations applicable from 01.08.2026, instead.
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of 01.04.2026 proposed in the Draft Regulation. Until a fresh tariff is determined under these Regulations, the tariff subsisting as on 31.03.2026 shall continue to apply.
Accordingly, the draft regulation 1.3 stands modified to the extent.
Several stakeholders objected to the proposed reduction of Return on Equity by 0.25% per month for delay in filing MYT/Mid-Term Review/Truing-up petitions. They submitted that this provision leads to double penalty, as delayed filing already entails deferred recovery and denial of carrying cost. They further submitted that the same is inconsistent with the view of the Hon'ble APTEL, that consequences for delay must be proportionate and non-punitive. Suggestions were also received to increase the penalty for delay in filing petitions.
The Commission is of the view that denial of carrying cost on the resulting revenue gap, by itself, leads to a proportionate and self-operating consequence of any delay in filing. The Commission also noted that clause 8.1(7) of the Tariff Policy, 2016 enables to initiate tariff determination on a suo motu basis where a licensee does not file a petition in time. The above-referred clause envisages that any gap arising from such delay shall be to the account of the licensee, an approach already given effect through the denial of carrying cost.
Accordingly, the proposed proviso in the draft regulation stands deleted.
Suggestions were received on the generic definition of "Bank Rate" (one-year SBI MCLR plus 100 basis points) to be aligned with the "Reference Rate of Interest" of one-year SBI.
The Commission has noted the submissions and is of the view that the "Bank Rate" is a generic reference rate used for varied purposes across this Regulation which includes computation of carrying/holding cost on the revenue gap or surplus, Interest During Construction on normative loan pending infusion of actual loan; each being distinct in nature from the financing of working capital, for which a separate and specific provision has been made under Regulation 37. It is pertinent to note that the CERC Tariff Regulations, 2024-29 defines "Bank Rate" as one-year SBI MCLR plus 100 basis points which is used for computation of such heads, while the higher "Reference Rate of Interest" is used for computation of interest on working capital. Therefore, the definition of “Bank Rate” adopted in the Draft Regulations is consistent with the CERC Tariff Regulations, 2024-29, and accordingly the definition of "Bank Rate" is retained, as proposed.
Several stakeholders submitted that the thresholds for approval of Capital Expenditure under Schedule-3, Regulation 3.2 for classifying a "major investment", i.e., Rs. 10 crore or 0.5% of the approved closing GFA of the previous trued-up year, whichever is lower, for a Generating Company and a Distribution Licensee, and Rs. 20 crore for a Transmission Licensee; are unduly low and do not reflect the present-day scale and cost of capital works. Further, it was stated that the resultant volume of DPR preparation and in-principle approval could delay time-sensitive works and affect system reliability. Enhancement of the thresholds were proposed, with proposals for enhancing the
The Commission has noted the submissions and is of the view that in the Explanatory Memorandum accompanying the Draft Regulations, the capital-investment approval framework has been introduced, in furtherance of clause (c) of Section 61 of the Act, to promote economic use of resources and optimum investment, and to instil greater clarity, scrutiny and monitoring in capital addition. This will reduce regulatory uncertainty for the utilities and limit the scope for litigations on this account. Therefore, the classification of works above the specified thresholds, as DPR Schemes, requiring in-principle approval is integral to that objective. Accordingly, the Commission does not consider it appropriate to dilute this framework as such.
At the same time, on a review of the prevailing scale and cost of capital works, and having regard also to the thresholds adopted by other State Commissions, the Commission considers the threshold for classification of a "major investment" under Schedule-3, Regulation 3.2 of the draft Regulation be revised. The Commission now revises this threshold to Rs. 25 crore or 0.5% of the approved closing GFA of the previous trued-up year, whichever is lower, in the case of a Generating Company and a Distribution Licensee, and to Rs. 50 crore in the case of a Transmission Licensee.
As regards the ceiling on Non-DPR capitalisation under Regulation 3.7, while the Commission is of the view that the limit of 20% of the capitalisation proposed under DPR Schemes or 0.5% of GFA, whichever is lower, is by and large adequate. However, the Commission recognises that a licensee or generating company may, in a given year, have
a genuine and demonstrable requirement in excess thereof. Therefore, while the said limit has been retained, subject to the qualification that the Commission may, by order, stipulate a different limit. Further, the Commission included a clarification that the said ceiling shall not apply where the annual capitalisation falls below the threshold specified in Regulation 3.2.
[Regulation 60.5 read with Regulation 2.1(lxa)]
The Draft Regulations provided that energy charges shall be computed on the basis of "GCV as received" at the generating station, measured through third-party sampling, but restricted the maximum admissible variation between the "As billed" GCV and the "As received" GCV to 300 kCal/kg for domestic coal and permitted an adjustment of 15 kCal/kg per 100 km beyond 200 km for coal from integrated mines subject to the same aggregate ceiling. The draft also proposes to disallow any such variation for imported, e-auction and washed coal.
Stakeholders commented that the cap is inconsistent with the "As received" principle based on the judgments of the Hon'ble Supreme Court in Nabha Power Limited v. Punjab State Power Corporation Ltd., (2018) 11 SCC 508 and Maharashtra State Electricity Distribution Co. Ltd. v. Adani Power Maharashtra Ltd., (2023) 7 SCC 401, wherein it has been held that the calorific value of coal changes during transportation and handling and must accordingly be measured at the receiving end of the generating station. It was submitted that degradation between the loading and unloading points is physically unavoidable, arising from moisture absorption in open wagons during transit and monsoon exposure, weathering during the stock period, etc. Stakeholders have submitted that the CERC Tariff Regulations, 2024 imposes no such cap, while MERC permits variation up to 750 kCal/kg.
Stakeholders accordingly suggested to remove the cap and allow full pass-through of cost on the basis of “GCV as received” certified through third-party sampling. Alternatively, it was also proposed to increase the cap to 750 kCal/kg and extended the same to all categories of coal. Further, for integrated mines, it was proposed that 100 kCal/kg be permitted for initial 100 km distance from mine to the generating plant, with an additional 15 kCal/kg for every 100 km thereafter.
The Commission has reviewed the submissions of the stakeholders and observes that while degradation in the calorific value of coal occurs between the loading point and unloading point for domestic coal, the same cannot remain un-checked or un-capped. From the petitions filed by the generating companies, the Commission has noted that the variation between "GCV as billed" and "GCV as received" claimed to be passed on through tariff has been in the range from 128.59 kCal/kg to 2735 kCal/kg, i.e., more than 7 grade slippages. The Commission noted with concern such large divergence in coal quality slippage claimed by the entities.
The judgments of the Hon’ble Supreme Court referred, establish the principle that the GCV of coal is to be reckoned at the point of delivery of the project and not at the mine end or on an equilibrated basis. This principle has already been adopted in these regulations. The said judgments, however, do not lay down the prudent quantum of variation that ought to be recognized for the purpose of tariff, which is a matter falling within the domain of the Appropriate Commission in the exercise of its regulatory function under Section 61 of the Act. The question before the Commission is not whether degradation occurs, but how much of it should be borne by consumers through the energy charge.
The Commission has also noted the Statements of Reasons (SOR) of the Central Commission and of MERC. It is recorded in these SORs that, stakeholders had placed reliance on the fact that the average loss in calorific value across the grades of coal, from G1 to G17, at approximately 226 kCal/kg. A coal-based generating company in the
country likewise proposed a slab-based allowance subject to a maximum variation of 300 kCal/kg. Further, variation of the same order, i.e., 300 kCal/Kg is reflected in the study of an independent research organization [Study on “Getting Good Grades: Addressing the challenge of coal quality slippage in the Indian power sector” dated December 2025 conducted by Prayas (Energy Group)]. As regards MERC, in its Statement of Reasons discloses that the allowance of 750 kCal/kg was arrived at upon consideration of circumstances specific to that State, and in particular upon the efforts demonstrated by its State generating company in the matter of sampling methodology.
The Commission is statutorily required to undertake prudence check and to ensure that fuel cost passed through tariff is reasonable and does not impose unjustified burden on consumers. It is noted that the difference between “GCV as billed” and “GCV as received” had been so substantial that accepting the same without any restriction would have permitted the generating companies to pass on the cost impact of excessive, unexplained and unreasonable deterioration in coal quality to consumers.
Further, Fuel Supply Agreements (FSAs) themselves contain a mechanism for quality assessment at the loading end. As per the relevant Clauses of the FSA entered into between the generating companies and Coal India Limited / its subsidiaries, the assessment of coal quality at the loading end is undertaken through a third-party agency by way of joint sampling in the presence of both the seller and the purchaser. Any deviation in coal quality or grade slippage identified through such quality assessment results in credit note / adjustment to the extent of difference between the base price of the declared grade and the analysed grade of coal. Therefore, the quality of coal at the loading end is not an unchecked assumption, but is subject to contractual sampling and adjustment.
Further, as per the relevant Clauses of the FSA, title and risk in the coal stand transferred to the generating company /purchaser, once the coal is delivered at the delivery point / loading end. Therefore, from the loading end till unloading at the generating station, the
responsibility for quality and quantity of coal lies with the generating companies/purchaser.
It is aptly recognized that the degradation in the calorific value of coal between the loading point and unloading point for domestic coal is within the control of the generating company/purchaser and there are sufficient contractual remedies to contain this degradation to a prudent degradation level. Therefore, the Commission has proceeded in line with the requirement of Section 61 (d) of the Act to safeguard the consumers' interest and at the same time allow recovery of the cost of electricity in a reasonable manner while specifying terms and conditions for the determination of tariff. In view of the above, the Commission decides to retain the 300 kCal/kg cap on the admissible variation between “GCV as billed” and “GCV as received” for domestic coal.
With regard to coal from integrated mines, the Regulations provide a distance-based adjustment of 15 kCal/kg per 100 km beyond 200 km, or actual, whichever is lower, subject to the same aggregate ceiling, in line with Regulation 60(3) of the CERC Tariff Regulations, 2024. The Commission does not find sufficient basis, on the material presently placed before it, to allow 100 kCal/kg GCV degradation for initial 100 km from mine to the generating station.
The Draft Regulations specified normative Operation and Maintenance expenses for the Control Period, escalated annually at 2.74%, being the hybrid inflation index (60% WPI and 40% CPI for Industrial Workers) for the year 2024-25.
Stakeholders commented that the escalation rate, being derived from the hybrid inflation index of a single year, does not reflect the sustained inflation trend experienced by the utilities, and that a five-year average of the said index — variously computed at approximately 5.02% and 4.05% — would be more representative. On the level of the norms, it was submitted that the norms for thermal generating stations are materially
lower than the corresponding norms under the CERC Tariff Regulations, 2024. Suggestions were also received on the provision where O&M expenses will be allowed 90% of the admissible cost to the stations having more than two units and sharing common facilities. Generating station-wise analysis were furnished seeking upward revision of the norms for some of the generating stations.
Revision was also sought in the norms for the transmission system and of the allocation of ratio between the Line and Sub-station and request for consideration of the normative manpower strength given in the 2011 Regulations while revision of the O&M norms. Regarding the distribution system, suggestion was received to consider CEA's "Guidelines for Benchmarking of Operation and Maintenance Norms for Distribution Utilities" dated 30.01.2025 where benchmark norms of 15% of GFA is specified.
The Commission has re-examined the escalation methodology, in light of the uniform stakeholder submissions, that a single-year inflation observation is an unrepresentative basis for a five-year normative trajectory. The Commission noted the fact that a single year’s hybrid index is exposed to year-specific volatility in commodity and consumer prices, whereas the O&M norms escalation is intended to hold across the entire Control Period. Therefore, a multi-year average is a reasonable basis for arriving at the escalation rate. Accordingly, the Commission has revised the annual escalation rate embedded in the normative O&M tables under Schedule-6 from 2.74% to 4.80%, computed on the basis of the Hybrid Inflation index, comprising 60% Wholesale Price Index (WPI) and 40% Consumer Price Index (CPI) for industrial workers, averaged over the last five years. The revised annual escalation rate so arrived, is used to recompute the year-wise normative O&M values across Schedule-6.
The total O&M expenses of the generating stations of the State were assessed using the audited figures of O&M expenses and manpower costs for 2023-24 and 2024-25. This assessed O&M expenses have been compared with the norms approved by the Central Commission for the respective years and were found to be in comparable range, except
for a few generating stations. Therefore, the norms specified by the Central Commission for 2023 – 24 have been revised based on the annual escalation rate, as stated above, to arrive at the norms from 2026 – 27 and onwards.
With regard to the norms for transmission system, the Commission observes that the transmission licensee has been operating at about fifty per cent of the manpower contemplated under the norms specified in the 2011 Regulations. Therefore, the norms for transmission licensee have been stipulated considering a buffer of approximately 10%. Appropriate manpower deployment needs to done to ensure the state grid continues to operate at an optimum level. Therefore, the norms have been specified by the Commission considering the framework of the Central Commission while customizing the norms, based on the State-specific cost base.
The norms for the distribution system have likewise been specified considering the audited figures for O&M expense and manpower costs of the distribution system. With respect to legal expenses relating to the distribution business of DVC, whose generation and transmission O&M is determined by the Central Commission, the Commission has decided that the same shall be specified in the Tariff Order with due prudence, as noted in Schedule-6.
Stakeholders suggested that the proposed requirement of the excess of accumulated depreciation (net of cumulative normative loan repayment) be not applied mandatorily towards reduction of equity in equal tranches over five years upon a generating station, transmission system or distribution system completing its useful life. Stakeholders submitted that assets prudently maintained beyond their useful life continue to deliver genuine value to the system, i.e., inertia, voltage support, balancing and ramping capability, which is of growing importance with rising variable renewable energy penetration.
The Commission considers the submission and outcomes identified by stakeholders. The provisos to draft Regulation 30.2 mandating reduction of equity upon completion of useful life (including the associated treatment of advance-against-depreciation and post-useful-life depreciation) have accordingly been deleted.
Stakeholders have urged alignment of the base Return on Equity with the CERC Tariff Regulations, 2024-29, i.e., 15.50% generally, as against the Draft Regulation’s 14.00% for thermal generation, transmission and run-of-river hydro assets capitalized on or after 01.04.2024 (15.50% for distribution and storage/pumped-storage hydro; 16.50%/15.50% for pre-2024 assets). Stakeholders relied on Rules 20(7) and 20(8) of the Electricity Rules, 2005 in support of their proposal and stated that the prevailing interest-rate environment will support investor confidence and project bankability and also on the capital requirements of the energy transition.
The Commission has noted the submissions, including the reliance on Rule 20 of the Electricity Rules, 2005. The Commission noted that the rate of return proposed in the draft is same with the existing returns specified by the Commission in 2011 Regulations with effect from 2024 – 25. The Commission has accordingly retained the base RoE rates at Regulations 31.2 and 31.3 as proposed in the Draft Regulation.
Stakeholders submitted that the proposed spread of 250 basis points over one-year SBI MCLR for Interest on Working Capital falls short of the 325-basis-point “Reference Rate
The Commission has noted the submissions and is of the view that the rate of interest proposed in the draft regulation is same with the existing rates specified by the Commission in 2011 Regulations. The Commission has accordingly retained the interest rates at Regulations 37.3 as proposed in the draft Regulations.
Stakeholders submitted that the slab-based DPSC structure proposed in the Draft Regulations (10%/12%/15% per annum for successive periods of delay) is materially lower than the existing effective rate of 1.25% per month, would weaken consumer payment discipline, and would adversely affect revenue realization and the cost of carrying receivables.
The Commission, having weighed the distribution licensees’ submissions on payment discipline and revenue certainty, has decided not to introduce the slab-based structure and instead to retain the existing Delayed Payment Surcharge rate of 1.25% per month on the billed amount, levied on simple interest basis, as has applied under the Commission’s orders to date. For L&MV agriculture consumers, no DPSC applies for delay up to the first 90 days and 1% per month thereafter.
Issue 11 – Capping of input price of coal from integrated mines [Regulation 115.1] Issue 12 – Other Issues raised regarding Definitions [Regulation 2]
Stakeholders have suggested that the capping of input price of coal from integrated mines at upper band price notified by Coal India Limited will adversely affect the financial viability of captive mining operations. It is submitted that CIL prices are "pooled" prices derived from a mix of open-cast mines and legacy underground mines across India and in variance to the captive mines which have certain geological constraints.
The Commission noted that submission of the stakeholders and deletes the proviso of capping the input price of coal from captive mine with reference to CIL notified price. The Commission has suitably modified the said proviso in line with the regulations framed by the Central Commission for determination of input price of coal for captive mine in the State.
Stakeholders have suggested to align the definition of ‘Auditor’ in line with the Licensing Regulations 2013. Suggestions were received to consider ‘Capital Expenditure’ based on Accrual Basis. Some stakeholders suggested to include ‘ABT’ and ‘Bulk Power Transmission Agreement’ to the definition. Suggestions were also received for the definitions of ‘Season’, ‘Unit’, ‘Force Majeure’, ‘Medium Term Power Procurement’ and ‘Useful Life’.
The Commission has noted each of the definition pointed out by the Stakeholders and accordingly addressed them in the regulation, as necessary.
In regard to the term of the ‘Auditor’, the Commission is of the view that the terms as used in these Regulations is principally invoked in the context of certification of financial
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statements, accounting statements and asset registers for the purpose of tariff determination and truing-up, for which an Auditor appointed under the Companies Act is the appropriate certifying authority. This is distinct from the wider category of technical, cost or energy auditors recognized for other regulatory purposes under the Licensing Regulations, 2013, which continue to apply in their own domain.
Regarding allowing ‘Capital Expenditure’ on accrual basis, the Commission is of the view that any consequent recovery of return and depreciation through tariff on such undischarged liability is not permissible. Accordingly, the definitions have been retained.
Suggestion has been received on the architecture of the MYT framework that a five-year control period with upfront ARR determination invites inflated projections and that RoE should be capped at 12% and T&D losses at 12% and that O&M should be allowed on actuals rather than norms. Suggestions were also received that the proposed framework of determination of tariff for 5 years control period along with Mid Term Review and Truing Up is overlapping in nature and proposed to return to principles of annual ARR determination.
The MYT framework is mandated by the Tariff Policy under Section 61 of the Act and is the settled practice, providing the regulatory certainty required for long-term investment while preserving annual accountability through truing-up on audited accounts, the gain/loss-sharing mechanism for controllable factors, and the Commission’s power to disallow imprudent costs. Accordingly, the principles of MYT Framework have been retained.
The suggestions on RoE and O&M norms have been dealt in the previous paragraphs. With regard to T&D losses, the Commission will stipulate a trajectory for distribution losses considering various factors including passed trends, demand growth, proposed
Apart from the above, suggestions were received on segregation of accounts, allocation of power from generating stations and to consider different Judgements of Hon’ble APTEL, etc.
The Generation and Transmission business of DVC is under the purview of the Central Commission. The Commission has also taken note of the said suggestions and considered such issues related to distribution activity of DVC within the State duly keeping in mind the provision of DVC Act, 1948.
The Commission has taken into consideration different concerns of the stakeholders related to Procedure for Tariff Determination in Chapter 3, Uncontrollable Factors in Regulation 9.1, allowance of Ash Utilization Expenses, FPPAS in Schedule – 4, Resource Adequacy and other transmission and distribution related issues brought out by the licensees. Necessary changes to the issues have been accordingly made in the Regulations.
Some form-level comments have been received by the stakeholders which have been addressed accordingly. The Commission decides that Generating Companies, Transmission Licensees and Distribution Licensees may add rows/ columns/ sheets to
the filing formats as may be necessary for their requirement but should not delete rows/
columns or sheets in the formats given.
Sd/- (DR. MALLELA VENKATESWARA RAO) CHAIRPERSON Dated: 13.07.2026