Before the
MAHARASHTRA ELECTRICITY REGULATORY COMMISSION
World Trade Centre, Centre No.1, 13th Floor, Cuffe Parade, Mumbai – 400 005
Tel. 022 - 22163964/ 65/ 69
Email: mercindia@merc.gov.in
Website: www.merc.gov.in
Date: 19 August 2024
The Commission Notified the MERC (Multi Year Tariff) Regulations, 2019 on August 01, 2019, which superseded the MERC (Multi Year Tariff) Regulation, 2015. The Commission notified the First Amendment to the MERC MYT Regulation 2019 on February 10, 2023 related to the Threshold Limit for Intra-State Transmission Systems to be developed through tariff-based competitive bidding. The Commission also notified the Second Amendment to the MERC MYT Regulation 2019 on June 08, 2023.
As the current MYT Control Period is coming to an end on March 31, 2025, the MERC formulated the draft Maharashtra Electricity Regulatory Commission (Multi Year Tariff) Regulations, 2024 (hereinafter referred as “draft MERC MYT Regulation, 2024) covering the Generation Business, Transmission Business, Distribution wire Business, Retail Supply Business, SLDC, STU, and Energy Storage System for the next MYT Control Period.
While formulating the draft MERC MYT Regulations, 2024, the Commission has been guided by the CERC MYT Regulations, 2024. The Commission has also been guided by the National Electricity Policy, Tariff Policy, relevant Regulations of this Commission and other SERC’s, FOR Recommendations on MYT Framework, APTEL Judgments, etc., for the formulation of draft MERC MYT Regulations, 2024.
The Commission proposed modifications to certain clauses vis-à-vis the clauses specified in the MERC MYT Regulations, 2019 (as amended from time to time) based on the experiences in implementation of the MYT Regulations in the previous Control Period, and to simplify/clarify/amend certain provisions as considered reasonable. The rationale for the changes proposed in the MERC MYT Regulations were elaborated in the Explanatory Memorandum. Generally, only the clauses where any addition/modification is proposed in the MERC MYT Regulations, 2024 were discussed in the Explanatory Memorandum.
Accordingly, draft MERC (Multi Year Tariff) Regulations, 2024 along with Explanatory Memorandum was published on the Commission’s websites www.mercindia.org.in/ www.merc.gov.in in downloadable format on March 07, 2024. A Public Notice was also
published in daily newspapers Marathi (Maharashtra Times and LokSatta) and English (Indian Express and Times of India), inviting comments, objections and suggestions from all stakeholders by March 28, 2024, which was subsequently extended till April 15, 2024 as per request of some of the stakeholders. A total of 50 stakeholders responded to the Notice on Draft MERC MYT Regulations, 2024. The list of stakeholders who offered their comments/suggestions on the draft Regulations and Explanatory Memorandum, which have been considered by the Commission while finalising the Regulations, is placed at Annexure-I.
The main comments and views expressed by the stakeholders through their written submissions and the Commission's views thereon have been summarized in the following paragraphs. It may be noted that all the suggestions given by the stakeholders have been considered, and the Commission has attempted to elaborate all the suggestions as well as the Commission's decisions on each suggestion in the Statement of Reasons, however, in case any suggestion is not specifically elaborated, it does not mean that the same has not been considered. Further, some stakeholders have suggested changes on Syntax/phrase/addition of word(s)/rewording related changes, cross-references, etc., which have been suitably incorporated, wherever necessary.
Wherever possible, the comments and suggestions have been summarised clause-wise, along with the Commission's analysis and ruling on the same. However, in some cases, due to overlapping of the issues/comments, two clauses have been combined in order to minimise repetition.
The SOR is organised in the following Chapters, along the same lines as the MERC MYT Regulations, 2024, summarising the main issues raised during the public consultation process, and the Commission's analysis and decisions on them which underlie the Regulations as finally notified:
| 1 | Regulation 2: Revision / addition of Definitions ..... | 12 |
| 1.1 | Comments Received:..... | 12 |
| 1.2 | Analysis and Commission's Decision ..... | 13 |
| 1.3 | Provision in the final Regulations ..... | 13 |
| 2 | General Principles and Multi Year Tariff Framework..... | 14 |
| 2.1 | Regulation 4.2(iii), 4.2(iv) and Regulations 5: Discontinuation of Mid Term Review (MTR) ..... | 14 |
| 2.2 | Regulation 5.2: Delay in filing a Petition and Penalty Provision for the non-compliance or delay in compliance of the directives of the Commission ..... | 20 |
| 2.3 | Regulation 6: Merit Order Despatch principles on RE sources ..... | 22 |
| 2.4 | Regulation 7: Specific Trajectory of Certain Variables ..... | 23 |
| 2.5 | Regulation 8: Controllable and Uncontrollable Factors ..... | 24 |
| 2.6 | Regulation 9: Mechanism for Pass-through of gains or losses on account of uncontrollable factors..... | 25 |
| 2.7 | Regulation 10.1: Mechanism for gains or losses on account of Controllable factors ..... | 27 |
| 2.8 | Regulation 13: Tariff Determination Process ..... | 28 |
| 3 | Power Procurement ..... | 29 |
| 3.1 | Regulation 17: Applicability ..... | 29 |
| 3.2 | Regulation 20: Approval of long-term/medium-term power purchase agreement/ arrangement ..... | 30 |
| 3.3 | Regulation 21: Additional Power Procurement ..... | 32 |
| 4 | Financial Principles ..... | 33 |
| 4.1 | Regulation 22: Financial Prudence ..... | 33 |
| 4.2 | Regulation 23.2: Capital Cost and Capital Structure (Assets Put to use) ..... | 33 |
| 4.3 | Regulation 23.3: Capital Cost and Capital Structure ..... | 34 |
| 4.4 | Regulations 23.7 to Regulation 24.3: Capital Cost and Capital Structure and Additional Capitalisation 35 |
|
| 4.5 | Regulation 26.1: Debt-Equity Ratio ..... | 38 |
| 4.6 | Regulation 27.1: Depreciation ..... | 39 |
| 4.7 | Regulation 27.5: Depreciation on capital Investment undertaken by Generating Companies ..... | 41 |
| 4.8 | Regulation 28: Return on Equity ..... | 42 |
| 4.9 | Regulation 28.8: Supply Margin ..... | 48 |
| 4.10 | Regulation 29.10: Refinancing of Loan ..... | 50 |
| 4.11 | Regulation 30.5: Foreign Exchange Rate Variation ..... | 51 |
| 4.12 | Regulation 31.1 (a): Interest on Working Capital for Generation ..... | 52 |
| 4.13 | Regulation 31.7: Interest On Working Capital ..... | 54 |
| 4.14 | Regulation 33: Income Tax ..... | 55 |
| 4.15 | Regulation 32: Carrying Cost or Holding Cost ..... | 57 |
| 4.16 | Regulation 34: Contingency reserve ..... | 58 |
| 5.1 | Regulation 23: Supply of Coal or Lignite Prior to the Date of Commercial Operation of Integrated Mine 61 |
|
| 5.2 | Regulation 38: Petition for determination of Generation Tariff..... | 62 |
| 5.3 | Regulation 39: Fuel Utilization plan ..... | 63 |
| 5.4 | Regulation 42: Renovation and Modernization..... | 64 |
| 5.5 | Regulation 43: Special allowance ..... | 65 |
| 5.6 | Regulation 45: Non-Tariff Income ..... | 67 |
| 5.7 | Regulation 46: Target availability for Recovery of Fixed Cost..... | 68 |
| 5.8 | Regulation 46: Gross Station Heat Rate ..... | 70 |
| 5.9 | Regulation 46.14, 46.15 and 46.18: Auxiliary Energy Consumption for Thermal Generating Stations | 72 |
| 5.10 | Regulation 46.20: Transit and handling Losses..... | 75 |
| 5.11 | Regulation 47: Operation and Maintenance expenses for Thermal Generating Station..... | 76 |
| 5.12 | Regulation 47.3: O&M Expenses on account of Emission Control System..... | 79 |
| 5.13 | Regulation 50.2: Computation and Payment of capacity charges for Thermal Generating Stations ..... | 80 |
| 5.14 | Regulation 50.5 and 50.6: Computation of Energy Charges ..... | 81 |
| 5.15 | Regulation 50.11: Incentive ..... | 84 |
| 5.16 | Regulation 51.8: Energy Charge for Hydro Generating Stations ..... | 86 |
| 5.17 | Regulation 54.1: Deviation charges ..... | 87 |
| 5.18 | Regulation 55.1: Input Price of Coal and Lignite..... | 88 |
| 5.19 | Regulation 56.2: Run of Mine Cost..... | 89 |
| 5.20 | Regulation 58 Capital Cost: Determination of Input Price of coal and Lignite from Integrated mines | 90 |
| 5.21 | Regulation 60: Annual Extraction Cost of Integrated Mine (s) ..... | 91 |
| 5.22 | Regulation 67.1 and 67.2: Recovery of Input Charges..... | 92 |
| 6.1 | Regulation 74: Applicability and Tariff based Competitive Bidding for Transmission (Annexure-IV of draft Regulations, 2024) ..... |
93 |
| 6.2 | Regulation 76: Petition for Determination of Provisional Tariff..... | 96 |
| 6.3 | Regulation 78.1: Target Availability for the Transmission Licensee ..... | 96 |
| 6.4 | Regulation 79: O&M Norms for Transmission Licensee..... | 97 |
| 6.15 | Regulation 79.11: Minimum 20% of O&M Expenses on R&M Activities. .... | 101 |
| 6.16 | Regulation 79.13: Revisions in the O&M Norms ..... | 103 |
| 6.17 | Regulation 80.2: Non-Tariff Income..... | 103 |
| 6.18 | Regulation 82: Determination of Intra-State Transmission Tariff..... | 105 |
| 6.19 | Regulation 82: Determination of Intra-State Transmission Tariff..... | 106 |
| 6.20 | Regulation 83: Sharing of TTSC by long-term TSUs ..... | 107 |
| 6.21 | Regulation 85: Billing and Payment of InSTS Charges ..... | 110 |
| 6.22 | Regulation 86: Transmission Losses ..... | 112 |
| 6.23 | Regulation 87: Reactive Energy Charges ..... | 113 |
| 7 | Norms and Principles for determination of Revenue Requirement and Wheeling Charges for Distribution Wire Business and Retail Supply Business..... | 114 |
| 7.1 | Regulation 88: Separation of Account of Distribution Licensee ..... | 114 |
| 7.2 | Regulation 90.2: Determination of Wheeling Charges..... | 115 |
| 7.3 | Regulation 91 and 101: Capital Investment Plan for Wires and Retail supply business ..... | 115 |
| 7.4 | Regulation 92 and 102: O&M Norms for Wire and Retail supply Business ..... | 116 |
| 7.5 | Regulation 96: Determination of Wheeling Charges..... | 122 |
| 7.6 | Regulation 97: Wheeling Losses ..... | 124 |
| 7.7 | Regulation 100: Sales Forecast ..... | 125 |
| 7.8 | Regulation 103: Implementation of Demand Side Management Measures ..... | 125 |
| 7.9 | Regulation 107: Receipt on account of Cross-subsidy Surcharge ..... | 126 |
| 7.10 | Regulation 109: Distribution losses..... | 127 |
| 7.11 | Regulation 110: Determination of Retail Supply Tariff..... | 127 |
| 7.12 | Regulation 111: Determination of the Demand or Fixed Charges ..... | 129 |
| 7.13 | Regulation 112: Determination of Ceiling Tariff ..... | 130 |
| 7.14 | Regulation 113: Time of Day Tariff..... | 136 |
| 8 | Norms and Principles for determination of Fees and Charges for the Maharashtra State Load Despatch Centre (MSLDC)..... | 138 |
| 8.1 | Regulation 116: LDC Development Fund..... | 138 |
| 8.2 | Regulation 119: RLDC Fees and WRPC Charges ..... | 138 |
| 8.3 | Regulation 122: Fees to be Charged by MSLDC ..... | 139 |
| 8.4 | Regulation 123: Performance Link Incentive..... | 140 |
| 9 | Fees and Charges for State Transmission Utility (STU) ..... | 142 |
| 9.2 | Regulation 127: Annual Fixed Charges for STU ..... | 143 |
| 9.3 | Regulation 127: Treatment of Fees and Penalties paid to STU and Creation of STU Development Fund: 144 |
|
| 9.4 | Regulation 128: O&M Expenses for STU..... | 145 |
| 9.5 | Regulation 129: Non-Tariff Income of STU ..... | 146 |
| 9.6 | Regulation 130: Sharing of STU Charges ..... | 146 |
| 9.7 | Regulation 132: Performance linked Incentives..... | 147 |
| 9.8 | Reimbursement of expenses incurred by MSETCL with carrying cost ..... | 148 |
| 10 | Energy Storage Systems (ESS) ..... | 150 |
| 10.1 | Regulation 134: Applicability of BESS..... | 150 |
| 10.2 | Regulation 137: Determination of Tariff for standalone BESS..... | 152 |
| 10.3 | Regulation 138: Determination of Tariff for PSPs..... | 154 |
| 10.4 | Regulation: Annexure – I & II Depreciation Schedule ..... | 155 |
| AAD | Advance against Depreciation |
| ACOS | Average Cost of Supply |
| ABT | Availability Based Tariff |
| AEML | Adani Electricity Mumbai Limited |
| AEML-G | Adani Electricity Mumbai Limited- Generation Business |
| AEML-T | Adani Electricity Mumbai Limited- Transmission Business |
| AEML-D | Adani Electricity Mumbai Limited– Distribution Business |
| ATE | Appellate Tribunal for Electricity |
| ATIL | Adani Transmission (India) Limited |
| APR | Annual Performance Review |
| APTCL | Amravati Power Transmission Company Limited |
| ARR | Aggregate Revenue Requirement |
| BESS | Battery Energy Storage Systems |
| BEST | Brihanmumbai Electric Supply and Transport Undertaking |
| CAGR | Compound Annual Growth Rate |
| CBG | Competitive Bidding Guidelines |
| CEA | Central Electricity Authority |
| CERC | Central Electricity Regulatory Commission |
| CFBC | Circulating Fluidised Bed Combustion |
| Ckt-km | Circuit Kilometres |
| COD | Commercial Operation Date |
| CPI | Consumer Price Index |
| CPRI | Central Power Research Institute |
| CTU | Central Transmission Utility |
| CUF | Capacity Utilisation Factor |
| DE | Design Energy |
| DISCOM | Distribution Companies |
| DoD | Depth of Discharge |
| DRE | Distributed Renewable Energy |
| DSM | Deviation and Settlement Mechanism |
| EA 2003 | Electricity Act 2003 |
| ECR | Energy Charge Rate |
| EE | Energy Efficiency |
| ESO | Energy Storage Obligations |
| ESS | Energy Storage Service |
| ESSD | Energy Storage Service Developer |
| FAC | Fuel Adjustment Charges |
| FERV | Foreign Exchange Rate Variation |
| FGD | Flue Gas Desulphurisation |
| FOR | Forum of Regulators |
| FRL | Full Reservoir Level |
| GCV | Gross Calorific Value |
| GFA | Gross Fixed Asset |
| GoM | Government of Maharashtra |
| HP-DAM | High Price Day Ahead Market |
| HPO | Hydropower Purchase Obligations |
| HRD | Human Resource Development |
| HT | High Tension |
| HVDC | High Voltage Direct Current |
| INR | Indian Rupees |
| InSTS | Intra-State Transmission System |
| IWC | Interest on Working Capital |
| JPTL | Jaigad Power Transco Ltd. |
| KPIs | Key Performance Indicators |
| kWh | kilo Watt hour |
| LT | Low Tension |
| LT-DRAP | Long Term Distribution Licensee Resource Adequacy Plan |
| MBPPL | Mindspace Business Parks Private Limited |
| MDDL | Minimum Draw Down Level |
| MEGPTCL | Maharashtra Eastern Grid Power Transmission Company Ltd |
| MERC | Maharashtra Electricity Regulatory Commission |
| MNRE | Ministry of New and Renewable Energy |
| MOD | Merit Order Despatch |
| MoP | Ministry of Power |
| MoU | Memorandum of Understanding |
| MSEDCL | Maharashtra State Electricity Distribution Company Limited |
| MSETCL | Maharashtra State Electricity Transmission Company Limited |
| MSLDC | Maharashtra State Load Despatch Centre |
| MSPGCL | Maharashtra State Power Generating Company Limited |
| MYT | Multi Year Tariff |
| MTR | Mid-Term Review |
| NAEAF | Normative Annual ESS Availability Factor |
| NAPAF | Normative Annual Plant Availability Factor |
| NEP | National Electricity Policy |
| NEEPCO | North Eastern Electric Power Corporation Limited |
| NTP | National Tariff Policy |
| NTPC | National Thermal Power Corporation |
| OA | Open Access |
| O&M | Operation and Maintenance |
| PAF | Plant Availability Factor |
| PBR | Performance Based Regulation |
| PFC | Power Finance Corporation |
| PGCIL | Power Grid Corporation of India Limited |
| PLF | Plant Load Factor |
| POA | Partial Open Access |
| PoC | Point of Connection |
| PSH | Pumped Storage Hydro |
| PSPs | Pumped Storage Projects |
| RA | Resource Adequacy |
| RAR | Resource Adequacy Requirement |
| RE | Renewable Energy |
| REC | Rural Electricity Corporation |
| RLDC | Regional Load Despatch Centre |
| ROE | Return on Equity |
| RPO | Renewable Purchase Obligation |
| R&D | Research and Development |
| R&M | Repair and Maintenance |
| R&M | Renovation and Modernization |
| RTC | Round the Clock |
| SAIDI | System Average Interruption Duration Index |
| SAIFI | System Average Interruption Frequency Index |
| SBBR | SBI Base Rate |
| SECI | Solar Energy Corporation of India Limited |
| SERC | State Electricity Regulatory Commission |
| SEZ | Special Economic Zone |
| SFOC | Secondary Fuel Oil Consumption |
| SHR | Station Heat Rate |
| SLDC | State Load Despatch Centre |
| SPTCL | Sinnar Power Transmission Company Limited |
| SRAS | Secondary Reserve Ancillary Services |
| STU | State Transmission Utility |
| TBCB | Tariff Based Competitive Bidding |
| TCR | Transmission Capacity Rights |
| ToD | Time of Day |
| TPC | Tata Power Company Limited |
| TPC-G | Tata Power Company Limited- Generation Business |
| TPC-T | Tata Power Company Limited- Transmission Business |
| TPC-D | Tata Power Company Limited – Distribution Business |
| TRAS | Tertiary Reserve Ancillary Services |
| TSC | Transmission Service Charges |
| TSERC | Telangana State Electricity Regulatory Commission |
| TSU | Transmission System User |
| TTSC | Total Transmission System Cost |
| UERC | Uttarakhand Electricity Regulatory Commission |
| UI | Unscheduled Interchange |
| VIPL-T | Vidarbha Industries Power Limited |
| WPI | Wholesale Price Index |
Shree Mahavir Jain, Sachin Choradiya and Bharat Agrawal Power Loom Charitable Association have suggested to add some provisos and modify the existing provisos in the definition of “Accounting Statement” in order to ensure improved quality of financial statements for such entities who are having regulated business under MERC and unregulated business including corporate adjustments.
MSPGCL has suggested to add proviso in the definition of “Auxiliary Energy Consumption” for considering the additional auxiliary consumption regarding installation of system for compliance with revised emission standards, sewage treatment plant and external coal handling plant.
MSPGCL has submitted that the definition of “Base Rate of Delayed Payment Surcharge” is already in alignment with LPS rules 2022 where, the base rate of surcharge at the SBI MCLR applicable + 5% basis point is justified. MSPGCL requested not to reduce the base rate of delayed payment surcharge. Further, MSEDCL submitted that, if dispute is pending before any court and the court rules in favour of generator/transmission licensee, then delayed payment surcharge on these amounts shall be applicable from the date of issuance of the order by the respective court equal to the one-year SBI MCLR. For other undisputed amounts, Base rate of delayed payment charges may be equal to lower of one-year SBI MCLR, or rate mentioned in the PPA for such delayed payment.
Further, the MSPGCL requested to modify the definition of “Plant Availability Factor” and to provide clarity on PAF computation in case of uncontrollable events.
Furthermore, the MSPGCL and Tata power have suggested to add proviso regarding the circumstances or event of “pandemic” in the definition of “Force Majeure” as these events would impact the capital cost or running cost of the plants.
MSPGCL has also suggested including the new definitions such as “Ancillary Services”, “Default Trigger Date”, “Daily Capacity Index” and “Capital Spares”.
MSETCL has suggested to incorporate suitable provisions in the definition of “Date of Commercial Operations” or “COD” to define the liability of utilities due to mismatch in date of commercial operation and to provide necessary relief in terms of declaring COD despite of assets not being put to use by granting full relief to Transmission Licensee. MSEDCL suggested reconsidering the definition of “Date of Commercial Operations” w.r.t to integrated mine as it should be ideally in relation with the plant’s requirement and the mine’s peak rated capacity and not on a pre-defined percentage.
MSEDCL has also suggested revising the definition of “Cycle efficiency of Energy Storage System” as it is necessary to consider self-discharge loss, to reflect the correct availability.
Furthermore, MSedCL suggested to add suitable proviso in the definition of “Non-DPR Schemes” regarding the CAPEX schemes which is completely funded through consumer contribution, Grants, Subsidy and contribution to contingency reserve should be excluded from the limits specified in the Regulations.
MSedCL also requested to retain the earlier definition of “Transmission system User”.
Tata Power has suggested to modify the clause (ix) in the definition of “Useful life” as the useful life of Communication system should be 7 years instead of 15 years, in line with CERC Tariff regulations 2024.
Definition of “Date of Commercial Operation” or “COD” has been linked with MEGC 2020. Further, definition of “Distribution Licensee” has been modified to include Deemed Distribution Licensee and Exempt Licensees. Definition of “Useful Life” has been modified in line with CERC Tariff Regulations 2024.
Definition of “Energy Storage System Developer” or “ESSD” has been added in the definition section.
“Date of Commercial Operation” or “COD”, “Distribution Licensee”, “Useful Life” has been revised and Definition of “Energy Storage System Developer” or “ESSD” has been added in the definition section.
40 “Due date” means the date by which the bill for the charges for power supplied by the Generating Company or for the transmission service provided by a Transmission Licensee are to be paid, in accordance with the Agreement, as the case may be, and if not specified in the Agreement, forty-five days from the date of presentation of the bill by such Generating Company or Transmission Licensee or STU;”
MSedCL submitted that as per definition of due date, in the absence of any agreement the monthly bill for transmission Tariff shall be payable within forty-five days of date of bill by the STU. MSedCL requested to modify the clause and revised due days for payment to forty-five days. MSedCL also submitted that if in BPTA, provision of billing days is less than 45 days, then LPS rules clause shall be retained and the same will be applicable to MSedCL.
The Commission noted the submission of MSedCL. The Commission also notes that, payment due date will be applicable for payment of generator or transmission licensee or STU or
MSLDC as the case may be. The payment due date related provisions should be uniform across all utilities.
Accordingly, the Commission has revised the definition 2.1(40) of due date in the final MERC MYT Regulations 2024. The Commission has removed the reference to the provision of due date in the Bilateral Agreement. The Bilateral Agreement between TSU and STU or in case of Generator and beneficiary may have provisions different than the normative provisions. Further the linkage of due date is with consideration of receivables while calculating the interest on working capital for generator or licensee or STU or MSLDC. The tariff determination process under MERC MYT Regulations 2024 is on annual basis whereas bilateral agreements may be for any period as mutually agreed. The provisions of the Tariff Regulations should be normative and at par across all the utilities.
Accordingly, the Commission has revised the definition of, “Due date” to remove the reference of bilateral agreement and also deleted the Regulation 86.2 to delete the reference of payment to transmission licensees within 30 days. With this revisions, all the payments i.e. payment due for generator, transmission licensee or STU or MSLDC shall be payable with due date i.e within 45 days from the submission of bills.
(40) “Due date” means the date by which the bill for the charges for power supplied by the Generating Company or ESSD or for the transmission service provided by a Transmission Licensee are to be paid which is forty-five days from the date of presentation of the bill by such Generating Company or ESSD or Transmission Licensee or STU or MSLDC;”
“85.2 The monthly bill for transmission Tariff shall be payable within thirty days of date of bill by the STU.”
127.2 The monthly bill for MSLDC Charges shall be payable within thirty days of receipt of bill by the Long term Beneficiaries and the Medium Term Open Access consumers.
137.2 The monthly bill for STU Charges shall be payable within thirty days of receipt of bill by the Long term Beneficiaries and the Medium Term Open Access consumers.
“4.2 .....
(iii)Petition for True-up for the first four years of the Control Period based on audited accounts and provisional true-up for the fifth year of the Control Period of operational
and financial performance vis-à-vis the approved shall be submitted by the Generating Company or ESSD, or Licensee or MSLDC or STU.
(iv) True-up for the first four years of the Control Period, provisional true-up for the fifth year of the Control Period of operational and financial performance vis-à-vis the approved forecast for the respective years, and categorization of variation in performance as those caused by factors within the control of the Petitioner (controllable factors) and by factors beyond its control (uncontrollable factors) by the Commission.”
MSEDCL requested to retain the provision for MTR for sustainable working of MSEDCL, as removal of MTR leads to increase in Carrying cost results in tariff shock to consumers. The actual revenue realization is low as compared to proposed revenue collection due to various factors such as change in consumer mix, change in consumption pattern, etc. Because of the lower revenue realization, MSEDCL experienced strain on its working capital requirement. MTR provides this very specific correction in tariff, which ease the working capital burden on distribution licensee.
It is submitted that rise in power purchase cost will be duly taken care of with Fuel cost adjustment. However, rise in cost other than power purchase cost is not covered under FAC. Therefore, once the expenses were incurred, the same will be recovered from the consumers after the true-up. This will aggravate financial crunch of MSEDCL.
Further, in trueing up exercise, the revenue also gets trued up. The tariff is determined based on projected expenditure and revenue. Revenue is projected for five years taking into account past sales CAGR, category wise demand, consumer mix, rise in economy, inflation etc. Due to huge volume and market volatility, the actual revenue is bound to change, and the gap/surplus therefrom needs to be recovered from consumers through tariff. The variation in actual revenue and change in ABR is not factored in FAC and as such the variation in actual revenue is not passed on year-to-year basis but will be considered only after expiry of control period.
Therefore, it is suggested that for the benefit of Utilities and consumers, the provision for filing Mid-Term Review Petition may be retained in this Regulation. Alternatively, to avoid issues of working capital as mentioned above, MSEDCL request the Commission may allow other legitimate expenses (such as O&M, IWC, IOL etc.) under Zouc so that these expenses are regularly pass through similar to that of power purchase.
AEML submitted that, MYT Petition does not consider all Capex. Utility plans the capex during control period. It cannot be considered without MTR. If additional capex is considered at the time of True up it would result in additional burden on consumers. MTR is required for course correction opportunity and reduces the carrying cost impact. Utility would not be able to implement the technological changes, process changes during control period.
Further, the Reg 9.9 specifies the ceiling limit of 20% for FAC Charing. If MTR process is indeed done away with, ways should be provided for the regulated entities to recover their
uncontrollable costs during the Control Period, by way of FAC and other additional charges, so that revenue gap does not pile up at the end of the Control Period. In case MTR is removed, FAC ceiling should also be removed to allow retail supply businesses to pass on the additional power purchase cost on the consumers during the Control Period itself, instead of carrying it till the end of CP.
MSETCL submitted that projections / forecasting under MYT regime for 5 years is a difficult activity under regulated scenario which is dynamic in nature. There are frequent changes in power sector and central/ state level affecting the business or envisaging need to adjust to the business dynamics. This all may affect the projections/ approvals of the Commission and hence there is need for mid-term review which will provide mechanism to correct for balance years of MYT.
AEML SEEPZ and AEML requested to retain the MTR process as per MERC MYT Regulations 2019. In case, if the MTR process is not retained, the Regulations ought to provide opportunity to the regulated entities to approach the Commission with petition for revision in ARR and tariff or for seeking an additional charge on account of additional capital expenditure schemes approved subsequent to the issue of MYT Order or on account of impact of any uncontrollable or force majeure event.
Tata Power submitted that, if Mid-term course correction does not take place, it will give a significant tariff shock to the consumers as the Gap would be doubled at the end of Control Period, which may get spread in the entire future Control Period of 5 years. Burdening the consumers with such Gap and Carrying Cost on the same is not correct. It may create a problem of working capital for distribution licensee. The CERC's approach of true-up the ARR of Generating Companies and Transmission Licensees at the end of the Control Period is not entirely appropriate, it is also submitted that CERC is not regulating Distribution Licensees, and nowhere has such an approach been adopted at State level for Distribution Licensees. Accordingly, Tata Power Requested to continue with the existing process of Mid-Term review and also provide for the filling of the Petition at any time during the Control Period.
MSPGCL, APTCL, EON KHARADI requested to retain the existing approach of MTR and provisions of subsequent MTR filling for the revision of tariff for control period. It is submitted that MTR is necessary for managing the power purchase cost of the distribution licensee and avoid financial burden of the distribution licensee.
Prayas Energy Group requested to conduct MTR process during the control period to revise the tariff design and true-up for first two years and proposed that GENCOs, TRANSCOs, DISCOMs, LDCs and STUs shall file an annual petition covering Compliance to directives, performance, costs regarding key trajectories and the status of major capital projects. For example- GENCOs should also submit compliance with fuel utilisation plan.
ATIL and MEGPTCL requested to retain the provisions as per MYT regulations 2019. It is submitted that removal of MTR process leads to delay the true-up process which will results in delaying in revenue gap/surplus recovery leads to creation of regulatory assets and associated carrying costs.
STU submitted that, it should be allowed to file MYT Petition for Fees and Charges with Mid-term review provision to reduce the carrying cost burden, as there may be variation of more than 20% against approved ARR/Annual Fixed Charges which may result in sudden, steep, and sustained increase in tariff. The consequential impact of Order on such Petition passed by the Commission shall be passed through under the 'Other Uncontrollable Cost' component of the Z-factor Charge (ZOUc) as an adjustment in the Tariff on a quarterly basis for the second, third, fourth and fifth Years of the Control Period, as may be determined in the Order of the Commission passed under these Regulations.
The Commission has considered the submission of the Stakeholders. With regards to Mid-term Review of MYT projections and revised MYT projections after three years of the Control Period, the Commission in the Explanatory Memorandum had noted that, the MERC (Terms and Conditions of Tariff) Regulations, 2005 notified on August 23, 2005, had provision of yearly Truing-up. Subsequently, the Commission in MYT Regulations, 2011, moved from Yearly Truing-up to Mid-Term Review at the end of third year of the Control Period. The Commission continued with the provision of Mid-Term Review in the third and fourth control period. The Commission is of the view that the Generation Companies, Licensees and Utilities in Maharashtra have gained the sufficient experience over a period to project the Aggregate Revenue Requirement over a control period.
Further, the comparative analysis of the data of existing control period (from FY 2020-21 to FY 2024-25) shows that, the projections approved by the Commission at the time of MYT Orders and actual parameters of ARR till MTR are fairly comparable for Generation, Transmission and SLDC and consolidated gap of MTR for Generation, Transmission and SLDC with carrying cost at the end of the control period is only Rs. 295.67 Crore, which is approx. 1.39% of consolidated ARR for Generation companies, Transmission utilities and SLDC.
Further, it is also noted that the CERC MYT Regulations for past three control period have the provision of True-up at the end of the Control Period only and the CERC has continued with the similar approach for the next Control Period starting from April 01, 2024.
Besides, the Commission recognises that the mechanism of $Z_{FAC}$ and $Z_{OUc}$ would address the requirements of timely recovery of variation in fuel cost and power purchase costs as also for variation in transmission costs (inter-state and intra-state) and cost variations (increments/decrements) arising due to uncontrollable factors such as ATE judgments or Orders/decrees of other Authorities. Further, as regards variation in the capital expenditure and capitalisation, the Commission has enabled the clause to factor in projections of capital expenditure and capitalisation over the control period in addition to considering implementation status of capex schemes for which in-principle approval is already granted.
Hence, the Commission has decided to continue with its approach of "no Mid-term review" for Generation, ESS, Transmission, SLDC and STU business.
However, variations in the distribution business operations and retail tariffs thereof are not only subjected to variations in operation costs and performance parameters but also dependent on several exogenous factors of change in sales mix, demand variations influenced by economic growth that may lead to significant over-recovery/ under-recovery of revenue, of longer period of 5 years if not trued up, upon regulatory scrutiny. Hence, it would be appropriate to continue with existing practice of mid-term performance review for distribution business. The same has also been suggested by distribution licensees and also consumer organisations.
The analysis of data also shows that, consolidated gap of MTR with carrying cost till the end of the control period for Discoms works out to be around Rs. 4,204 crores, which is 3.30% of cumulative Discoms ARR.
Thus, considering submission of Distribution licensees, consumer organisations and the analysis of the data, the Commission has decided to continue with the provisions of Midterm review only for distribution licensees during the fifth control period.
The added Regulations w.r.t MTR is as under:
“4.2
...
a. Petition for Mid-Term Review of operational and financial performance vis-à-vis approved forecast for the first three years of the Control Period; and revised forecast of Aggregate Revenue Requirement, expected revenue from existing Tariff, expected revenue gap or surplus, as the case may be, and proposed category-wise Tariffs for the fourth and fifth year of the Control Period, shall be submitted by the Distribution Licensees for Wires Business and Retail Supply Business. .
b. True-up for the first and second years of the Control Period based on audited accounts and provisional true-up for the third year of the Control Period shall be submitted by the Distribution Licensees for Wires Business and Retail Supply Business along with its Petition for Mid-term Review.
c. Determination of the revised Aggregate Revenue Requirement and Tariff for Distribution Wires Business, Retail Supply Business by the Commission for the fourth and fifth year of the Control Period based on the Mid-term Review.
d. Mid-Term Review shall cover True-up for the first and second years of the Control Period based on audited accounts and provisional true-up for the third year of the Control Period of operational and financial performance vis-à-vis the approved forecast for the respective years and the categorisation of variation in performance as those caused by factors within the control of the Petitioner (controllable factors) and
by factors beyond its control (uncontrollable factors) shall be undertaken by the Commission for Wires Business and Retail Supply Business as part of Mid-term Review.
e. Petition for True-up for the third and fourth years of the Control Period based on audited accounts and provisional true-up for the fifth year of the Control Period of operational and financial performance vis-à-vis the approved forecast for the respective years shall be submitted by the Distribution Licensees for Wires Business and Retail Supply Business along with its Petition for Tariff determination for next Control Period..
a. Petition for True-up for the first four years of the Control Period based on audited accounts and provisional true-up for the fifth year of the Control Period of operational and financial performance vis-à-vis the approved forecast for the respective years, shall be submitted by the Generating Company or ESSD, or Transmission Licensee or MSLDC or STU along with its Petition for Tariff determination for next Control Period.
v. The mechanism for pass-through of approved gains or losses on account of uncontrollable factors as specified by the Commission in these Regulations.
The revised clauses are as under:
“5.1
...
b) Mid-term Review Petition, which is complete in all aspects as per these Regulations, shall be filed by November 30, 2027 by Distribution Licensees comprising:
Revised forecast of Aggregate Revenue Requirement, expected revenue from existing Tariff and charges, expected revenue gap, and proposed category-wise Tariff for the fourth and fifth year of the Control Period;
c) True-up Petition, which is complete in all aspects as per these Regulations, for the first four year of the Control Period shall be filed by November 1, 2029 by Generating Companies, Energy Storage system Developer, Transmission Licensees, MSLDC, STU;
“5.2 -----
Provided that, in case of non-adherence of the prevailing Regulations and/ or directives of the Commission, with unsatisfactory justification, the Commission may consider the disallowance of ARR upto INR One Crore per default for non-adherence to the directions of the Commission at the time of approval of the ARR of the Petitioner.”
BEST requested that penalty should be linked with ARR to avoid disparity among the Discoms. MSPGCL requested to remove the provisions for penalty for non-adherence of directive issued by the Commission. They submitted that the proposed charge in the draft regulations is that Rs. One crore per default will be levied due to non-compliance to the directions of the Commission at ARR approval. Also, there may be a possibility of double penalty for single violation which must be avoided and there is no clarity on default and when penalty will be imposed.
AEMIL, AEML SEEPZ and AEML submitted that existing provisions to disallow the carrying cost for the corresponding period of delay may be continued. Further, it is submitted that in case the draft provisions are retained, the period to seek clarification of queries, if any sought by the utility, may not be considered as delay in responding. Also, in order to ensure that queries are properly understood and responded to, as desired, proper data formats, wherever applicable, may be provided along with the query. Further, the penalty provisions in the regulations ought to be in conformity with the Section 142 and 146 of the Electricity Act, 2003. The regulations
ought to provide the utilities a notice period to correct the non-compliance before levying any penalty.
ATIL, Tata Power and MEGPTCL requested to align the penalty clause with Section 142 and 146 of the Electricity Act 2003. ATIL submitted that the proposed clause in draft MERC MYT Regulations 2024 completely violates the Section 142 and 146 of the Electricity Act 2003 which provides a penalty not more than INR One Lakh.
With regards to non-compliance, the Section 146 deals with non-compliance of any Orders or directions under this Act. Hence provisions of Electricity Act already take care of the punishment in case of non-compliance of any Order or directions issued under this Act. No need to have separate provisions for non-compliance.
Union of Chemist and Shri Krushna Bhoyar submitted that the Commission may penalise the Petitioner by disallowing the ARR of INR 1 Crore per default is case of non-adherence to prevailing Regulations. However, there is no clarity on default and when the penalty will be imposed. Also submitted that, no such penalty laid down by other SERC. Shri Krushna Bhoyar Requested to remove the mentioned penalty clause.
STU and MSETCL requested to consider the penalty as per Section 142 of the Electricity Act, 2003 or may decide nominal amount depending on non-adherence on case-to-case basis after giving due opportunity of being heard.
GEPL, KRCIPPL, MBPPL, and NUPLLP requested to reduce the disallowance of ARR to any smaller amount as deem fit by the Commission based on the nature of non-compliance for deemed distribution license under the SEZ Act and penalties for non-compliance should be levied passionately.
Ensuring the timely compliance of the directives of the Commission is necessary in the interest of the consumers. In some cases, the non-adherence or delay in compliance of the directives of the Commission may have financial impact on the consumer retail tariff.
The utilities are expected to be serious about the compliance of the directives in timely manner, in the interest of consumers. It is clarified that the proposed dis-incentive through dis-allowance of ARR is the regulatory measure over and above the penal provisions as stipulated under Section 142 and Section 146 of EA 2003 for non-compliance of directives of the Commission.
Further, opportunity to provide justification will be provided before invoking such regulatory measures. Compliance of directives will be considered as performance parameter and non-compliance will be subjected to dis-incentive in monitory terms through ARR. It is clarified that such disincentive shall not be applicable for delayed filing of data gaps, but if Petition is delayed on account of it then other provisions of the Regulations will becomes applicable.
“5.2 Along with the Petition for determination of Tariff or Fees and Charges and Truing-up under these Regulations, the Petitioner shall submit consolidated statement of the status of the adherence of prevailing Regulations and / or the directives of the Commission in the earlier Orders (including Tariff as well as Non-Tariff Orders) along with the justification of non-compliance, if any:
Provided that, in case of non-adherence of the prevailing Regulations and/ or directives of the Commission, with unsatisfactory justification, the Commission may consider to apply disincentive of INR One Crore per default at the time of approval of the ARR.”
“6.4 -----
Provided further that Merit Order Despatch principles shall not apply to purchase of power from Renewable Energy sources up to the RPO specified by the Commission.”
MSPGCL requested to exclude the RE power having generic tariff from the applicability of the proposed provision. In case the Merit Order Despatch becoming applicable for RE power after RPO compliance, the power with generic tariff may be remained unscheduled. So, the above regulations are contrary to the Section 61 with 86 (1)(e) of the EA, 2003 for promotion of RE power generation.
NUPLLP submitted that, Solar, Wind and Hydro Renewable Generating sources are having “Must Run” status and by nature of generation are not schedulable. Therefore, the proviso should be modified.
The Commission has considered the suggestions of the Stakeholders. The Commission also noted that the provisions of the Electricity (Promotion of Generation of Electricity from Must-Run Power Plant) Rules, 2021 issued by the MoP. These rules mandate that RE projects, including but not limited to wind, solar, wind-solar hybrid, and hydropower sources, must be considered as must-run projects and these projects shall not be subjected to curtailment or regulation of generation or supply of electricity on account of merit order dispatch or on account of any other commercial consideration. In view of the above the Commission has revised the proviso as below:
Hence, the revised the proviso under Regulation 6.4 is revised as follows:
“6.4 .....
Provided further that Merit Order Despatch principles shall not apply to purchase of power from Renewable Energy sources."
"7.1 The Commission, while approving the Multi-Year Tariff Petition, may stipulate a trajectory for certain variables, including but not limited to transmission losses, distribution losses, Reliability Indices, System Average Interruption Frequency Index (SAIFI), System Average Interruption Duration Index (SAIDI) to monitor and report the supply availability and wires availability, Aggregate Technical and Commercial Losses (AT&C Loss), collection efficiency, and payment efficiency."
GEPL, KRCIPPL, MBPPL, and NUPLLP submitted that as per Rule 20 of Electricity (Amendment) Rules, 2023, the trajectory for AT&C loss reduction trajectory to be approved by the Commissions for tariff determination shall be in accordance with the trajectory agreed by the respective State Governments and approved by the Central Government under any national scheme or programme, or otherwise. It is also submitted that till such time, trajectory for the same is not approved by State Government, the Commission may either not specify the trajectory or even if it is specified, then there should not be any disallowance towards the same.
The Commission in the Explanatory Memorandum has provided the justification for providing Trajectory of AT&C losses for monitoring purpose only. As per Rule 10 of the Ministry of Power (MoP) Rights of Consumer Rules 2022, the State Commissions are required to specify trajectory of System Average Interruption Frequency Index (SAIFI), and System Average Interruption Duration Index (SAIDI).
Further, as per Rule 20 of the MoP Electricity (Second Amendment) Rules, 2023, the Aggregate Technical and Commercial (AT&C) loss reduction trajectory to be approved by the State Commissions for tariff determination in accordance with the trajectory agreed by the respective State Governments and approved by the Central Government under any national scheme or programme, or otherwise:
The Commission has noted the provisions of the MoP Rules to specify the trajectory for AT&C losses. For Truing-up process the Commission considers the sales and revenue on accrual basis from the audited accounts for actual energy balance at the time of Truing-up. The collection efficiency is also monitored separately during the Truing-Up process.
However, considering the provisions of the MoP Rules, it is proposed to specify the Trajectory of AT&C losses for monitoring purpose for the Control Period (From FY 2025-26 to FY 2029-30). Accordingly, the Specific trajectory for certain variables is proposed.
No change in the Provision of Draft MERC MYT Regulations 2024.
“8.1 The “uncontrollable factors” shall comprise the following factors, which were beyond the control of, and could not be mitigated by the Petitioner, as determined by the Commission:
MSEDCL requested to include Wage Revision under Uncontrollable Factors. In the states like Gujarat, Karnataka, Punjab, Rajasthan, variations in employee expenses due to wage revision, terminal benefits etc. are passed through over & above actual O&M expenses. STU and MSETCL submitted that wage revision is undertaken after every five years apart from the yearly increase/ increment in the wages / salaries of the employees. In Case No. 232 of 2022, the Commission has agreed to consider wage revision arising as an uncontrollable factor and worked out the sharing of gains/(losses) for O&M expenses.
AEMIL requested to remove the "Variation in interest on working capital" from Regulations 8.2 and 31.7 of the draft MYT Regulations 2024. The regulatory framework should be simplified and brought in line with CERC framework, which allows working capital to the utility on normative basis only, without getting into determination of efficiency gains/losses. AEML SEEPZ and AEML suggested that the "Change in Law" line item in the list of uncontrollable factors should be expanded to include change in direct or indirect taxes, duties or statutory levies by concerned Govts. Or Local Bodies."
Tata Power submitted that, the Commission needs to clearly specify the intent as regards applicability and treatment of Controllable Factors in case of Distribution Licensees operating in parallel licence area. It is also submitted that, the Commission needs to ensure that the Distribution Licensees operating in parallel licence area are able to claim the variation in controllable parameters as a pass-through in their ARR, in the same manner as other Distribution Licensees.
Wage revision is considered a part of employee expenses under O&M Expenses. The Commission has considered the entire O&M expenses as controllable factor under MYT Regulations of last 3 control periods and considering O&M expenses under sharing of gains and losses to encourage the efficiency in O&M expenses. In view of the above, it would not be appropriate to treat wage revisions of employees as uncontrollable factor. However, it is clarified that impact of arrears of wage revision during the control period shall be normalised over the annual period while ascertaining the sharing of gains and losses of actual performance of O&M cost vis-à-vis normative O&M costs for the respective years during the control period.
Further, the Commission is of the view that working capital is a controllable parameter and like any other controllable parameters, the treatment shall be the same, i.e., sharing of gains/losses as applicable between the normative and actual parameters has to be done. As regards consideration of taxes under uncontrollable factors, the Commission in its various order has already allowed variation in statutory levies under change in law. Hence, no Changes in the Regulations 8 of Draft MERC MYT Regulations 2024 are considered.
No change in the Provision of Draft MERC MYT Regulations 2024.
"...
9.8 The total ZFAC recoverable as per the formula specified above shall be recovered from the actual sales in terms of "Rupees per kilowatt-hour or Rupees per kVA":
Provided that, in case of unmetered consumers, the ZFAC shall be recoverable based on estimated sales to such consumers, computed in accordance with such methodology as may be stipulated by the Commission:
----- Provided further that any under-recovery in the ZFAC on account of such ceiling shall be carried forward and shall be recovered by the Distribution Licensee over such future period as may be directed by the Commission.
9.10 The consequential impact of decisions of higher Courts or Tribunals or Review Orders passed by the Commission on the Generating Companies, Transmission Licensees, Distribution Licensees, MSLDC, STU and ESSD shall be passed through under the 'Other Uncontrollable Cost' component of the Z-factor Charge (ZOU) as an adjustment in the Tariff on a yearly basis for the second, third, fourth and fifth Years of the Control Period, as may be determined in the Order of the Commission passed under these Regulations.
MSEDCL requested to adopt the methodology for computation of ZFAC in line with MoP rules and amendments thereof. STU submitted that the recovery based on yearly basis may lead to increase in carrying cost and hence it is suggested to keep on quarterly basis to ensure minimum burden on beneficiaries/ consumers.
GEPL, KRCIPPL, MBPPL, and NUPLLP submitted that, the Commission can consider balanced approach by disallowance in carrying cost rather than disallowing the whole cost for failure of filing FAC. It is also requested during truing up Distribution licensee should be permitted to recover such cost excluding the carrying cost.
ATIL and MEGPTCL requested to clarify that the variation in InSTS transmission charges based on Hon'ble Supreme Court/Hon'ble APTEL/MERC orders can be passed through ZFAC formula without any amendment in InSTS order and the recovery from various TSUs shall be in the same ratio as indicated in the latest InSTS order.
NUPLLP requested to clarify and modify the said proviso under the Regulation 9.9, whereby, if ABR is considered in kVAh, then it is necessary to consider power factor category wise / utility wise as the average cost of supply is computed in kwh. Tata Power submitted that in Regulation 9.8 the ZFAC should be denoted in 'Rupees per kVAh', which reflects sales rather than 'Rupees per kVA', which reflects the demand. Regarding Second Proviso of Regulation 9.9 Tata Power submitted that, the Commission should do away with the ceiling rate and delete the said proviso.
Variation in InSTS transmission charges shall be recovered through ZFAC formula and recovery from TSUs shall be in same ratio as indicated in the prevailing InSTS order. Further, the intent of Rule 14 of MOP Electricity (Amendment) Rules is to have timely recovery of power purchase costs by the Distribution Licensee arising on account of the variation in the price of fuel and power purchase cost on a monthly basis as part of the methodology and formula specified by the appropriate Commission through the consumer tariff. The Regulation 9 of draft MERC MYT Regulation 2024 specifies the formula along with detailed methodology for recovery of cost variation for $n^{\text{th}}$ month through the consumer tariff in $(n+2)^{\text{th}}$ month.
The Commission vide earlier tariff Orders has specified the provision of FAC fund, which is utilised to manage increase or decrease of power purchase as compared to approved which led to levy or refund of FAC. This enables Distribution Licensees to recover its increased expenses either through FAC fund or from consumers. Hence, $Z_{\text{FAC}}$ mechanism in the MERC MYT Regulation 2024 is in line with the intend of Rule 14 of Electricity (Amendment) Rules. The Commission has informed to MoP vide letter dated November 22, 2023 that, the provisions of the MERC MYT Regulations are in compliance with the MoP Rules for automatic compensation through ZFAC. Further, ZFAC shall be denoted in 'Rupees per kVAh', instead of 'Rupees per kVA'. Regarding Second Proviso of Regulation 9.9 (revised to 10.9), the
Commission finds no merit in removing the ceiling rate as it may lead to tariff shock to consumers.
With regards to Regulation 9.10 (revised to 10.10) Zouc is for consequential impact of decisions of higher Courts or Tribunals or Review Orders passed by the Commission on the Generating Companies, Transmission Licensees, Distribution Licensees, MSLDC, STU and ESSD. These types of decisions/orders are not so frequent that quarterly adjustment is required. ZOUC is determined based on a Petition filed by the concerned Generating Companies, Transmission Licensees, Distribution Licensees, MSLDC, STU and ESSD on yearly basis.
The changes in Regulation 10.8 are as follows:
“10.8 The total $Z_{FAC}$ recoverable as per the formula specified above shall be recovered from the actual sales in terms of “Rupees per kWh or Rupees per kVAh as the case may be”:
“10.1 The approved aggregate gain to the Generating Company or Transmission Licensee or Distribution Licensee or MSLDC or STU or ESS Developer on account of controllable factors shall be dealt with in the following manner:
(a) Two-third of the amount of such gain shall be passed on as a rebate in Tariff over such period as may be stipulated in the Order of the Commission;
(b) The balance amount of such gain shall be retained by the Generating Company or Transmission Licensee or Distribution Licensee or MSLDC or STU or ESS Developer.”
10.2 The approved aggregate loss to the Generating Company or ESS Developer or Transmission Licensee or Distribution Licensee or MSLDC or STU on account of controllable factors shall be dealt with in the following manner:
(a) One-third of the amount of such loss may be passed on as an additional charge in Tariff over such period as may be stipulated in the Order of the Commission;
(b) The balance amount of such loss shall be absorbed by the Generating Company or Licensee or MSLDC or STU or ESS Developer.”
BEST requested to allow the mechanism for sharing of Gains/Losses on account of Controllable factors be in the 50:50 ratio.
AEMIL suggested to keep the sharing of efficiency gains and losses at 50/50 between the licensee (or GENCOs) and the beneficiaries.
GEPL, KRCIPPL, MBPPL, and NUPLLP submitted that one-third of the amount of such gain shall be allowed to be passed on as a rebate in tariff and the two-third amount of such gain shall be retained by GENCOs, Transmission licensees, DISCOMs, MSLDC, STU and ESS developer to incentivise the utilities. Also, for incremental improvement in performance parameters over the target specified by Commission, higher efforts are required by utility. Further, they stated that two-third of the amount of such loss may be passed on as an additional charge in tariff and the balance one-third amount of such loss shall be absorbed by the GENCOs, Transmission licensees, DISCOMs, MSLDC, STU and ESS developer. Tata Power requested to provide sharing of gains/(losses) in the ratio of 1:1 as CERC specify in its Tariff Regulation 2024.
The Commission notes that, the proposed mechanism of Sharing of Gains & Losses for controllable factor are inline with FOR model Regulations and other states like Gujarat &Telangana etc. The Commission is following the proposed mechanism since past two control periods. Hence, the Commission is not proposing any changes in proposed provisions of mechanism of Sharing of Gains & Losses for controllable factor in the draft MERC MYT Regulation 2024.
No change in the Provision of Draft MERC MYT Regulations 2024.
“13.3...
Provided also that the Commission may conduct a Technical Validation Session prior to admission of the Petition.”
"13.6 The Petitioner shall, within three days of an intimation given to it in accordance with Regulation 13.4, publish a Public Notice in at least two English and two Marathi language daily newspapers widely circulated in the area to which the Petition pertains, outlining the proposed Tariff, and such other matters as may be stipulated by the Commission, and inviting suggestions and objections from the public: ..."
Prayas Energy Group suggested that Technical Validation Sessions are treated as indispensable to the tariff determination process as important information and insights can be derived from clarifications and additional data provided by the companies and licensees. Thus, the draft regulation should mandate the Commission to conduct TVS prior to the admission of tariff petitions in the presence of consumer representatives.
MSEDCL requested to retain the existing clause. It is submitted that, it is not necessary to put the filing/stakeholder consultation and public hearing in the newspaper separately or through SMS or e-mail, it would unnecessarily add the cost to the consumers.
AEMIL requested to allow seven days for publication of Marathi language notice as the process involves English to Marathi translation for which a separate agency is engaged. Further, the translation involves a lot of back and forth for error correction, so that the literal meaning of the content is conveyed.
GEPL, KRCIPPL, JNPT and MBPPL requested to waive the requirement of publishing a public notice with proposed tariff and other such matters in at least two English and two Marathi language newspapers for deemed distribution licensees like us.
Tata Power requested to allow to publish the Public Notice on website of the licensee and e-filing portal of the Commission. The objective of reducing the burden imposed on businesses/citizens and to promote ease of doing business, Tata Power requested to apply CERC's Suo Motu Order in Petition No. 1/SM/2022 dated January 22, 2022, where the requirement of publication in newspapers has been substituted by the provision for publication on the websites.
The purpose of the Technical Validation Session (TVS) is to scrutinise the tariff petition and make the error free, tariff petition available for public consultation. The Commission undertakes, TVS before admitting the tariff petition. Making the petition available in the public domain before TVS may not be appropriate as it may have certain gaps, inconsistencies, errors etc, which may mislead the consumers and general public.
The Commission is of the view that when the Distribution Licensee follows the publication process, it helps to inform the general public including existing and potential consumers. Therefore the Commission is not inclined to exempt any Licensee from the publication process. Hence, no revision has been proposed in these Regulations.
With regards to timelines of 3 days to publish notice, such timeline has been proposed considering that 120 days have been allowed by the EA, 2003 for issuance of Order from the date of admission of the Petition. Delay in public notice would delay the overall timelines for processing the Petition including public hearings and issuance of the Tariff Order.
No change in the Provision of Draft MERC MYT Regulations 2024.
“17.1 The Regulations contained in this Part shall apply to power procurement by a Distribution Licensee from a Generating Company or Trading Licensee or Distribution Licensee or from any other source through agreement or arrangement for purchase of power for distribution and supply within the State.”
New Age Markets of Energy Pvt. Ltd. (NAME), OTC Platform submitted that, since the definition of “OTC Platform” needs to be introduced in Chapter 2 Definition, the Regulation 17 of MERC Regulation needs to recognize the role of OTC Platform.
The Commission is of the view that, the provisions of the OTC Platform are covered in the relevant provisions of the Central Commission. Further, ‘any other source’ mentioned in above quoted Regulations can cover OTC platform and other market based instruments for power procurement. Accordingly, the Commission is not proposing the any revision in Regulation 17.1 (18.1 in revised Regulations).
No change in the Provision of Draft MERC MYT Regulations 2024.
"20.1 Every long-term/medium-term agreement or arrangement for power procurement, including on a Standby basis, by a Distribution Licensee from a Generating Company or Licensee or from another source of supply, and any change to an existing agreement or arrangement shall come into effect only with the prior approval of the Commission:
Provided that the prior approval of the Commission shall not be required for purchase of power from Renewable Energy sources at the generic/preferential tariff determined by the Commission for meeting its Renewable Purchase Obligation (RPO).
20.2 .....
Provided that public consultation shall not be required for adoption of tariff discovered through competitive bidding under Section 63 of the Act:
Provided further that in case of power procurement under Section 62 of the Act, public consultation as stipulated under Regulation 20.3 to 20.5 shall be followed.
...
20.6 The Commission shall consider a Petition for approval of power procurement agreement or arrangement having regard to the approved power procurement plan of the Distribution Licensee and the following factors:
d) Availability (or expected availability) of capacity in the intra-State transmission system for evacuation and supply of power procured under the agreement or arrangement; ...”
Prayas Energy group requested to ensure that approval of power procurement plan is subject to regulatory and public scrutiny and mandated the additional power procurement plan under draft Reg 21 shall be subject to public process. Further, it is requested to carry out the public consultation for tariff adoption of Section 63 projects and any deviation from standard bidding guidelines for power procurement through Sec 63.
New Age Markets of Energy Pvt. Ltd. (NAME) OTC Platform submitted that, considering Regulation 7 of the Central Electricity Regulatory Commission (Power Market) Regulation 2021, the Regulation 20 of MERC Regulation needs to recognize the role of OTC Platform.
Tata Power requested that, DISCOM should have fair idea about the transmission constraints before finalizing quantum/duration/terms of the bidding. STU may be directed to publish the required such data on its website. Further requested for references to Regulation 112.3 (e) in Regulation 20.1 and Regulation 21 to avoid any ambiguity.
The Commission is approving the power procurement proposed by Distribution Licensee under Section 63 of the EA 2003 by following the regulatory process in line with the conduct of the business regulations. Further, the Commission is also conducting the hearing for prior approval of the Bidding documents for competitive bidding with deviations proposed by the Distribution Licensees. Besides, the Commission has also formulated Regulations for framework for Resource Adequacy and the distribution licensees are expected to prepare their power procurement plans (long term/ medium term / short term) in compliance with Resource Adequacy framework regulations as operational within the State. Thus, approval of the RA plans shall form basis for preparation and approval of power procurement plans of distribution licensees. The relevant provisions have been incorporated under MYT Regulations for conformance to RA Regulations.
With regards to “OTC Platform” the Commission is of the view that as per the provisions of the CERC Regulations, it is one of the option available for distribution licensees for procurement of power. It may not be required to specifically mention any option for power procurement in the Regulations. Discoms are free to plan the options for power procurement following the principles as specified in the MERC Resource Adequacy Regulations 2024 and optimisation principles.
With Regards to TPC submission, the Commission is of the view that, STU is publishing its 5 years transmission plan on its website. Distribution licensees may draw the inferences from the available data about the transmission constraints while planning the power procurement. Accordingly, the Commission is not proposing any changes in the Regulations 21.
No change in the Provision of Draft MERC MYT Regulations 2024.
"... 21.3 Any variation, during the first or second block of six months of a Year, in the quantum or cost of power procured, including from a source other than a previously approved source, that is expected to be in excess of five per cent of that approved by the Commission, shall require its prior approval:
... 21.4 Where the Distribution Licensee has identified a new short-term source of supply from which power can be procured at a Tariff that reduces its approved total power procurement cost, it may enter into a short-term power procurement agreement or arrangement with such supplier without the prior approval of the Commission.
... 21.6 Within fifteen days from the date of entering into an agreement or arrangement for short-term power procurement for which prior approval is not required, the Distribution Licensee shall submit to the Commission its details, including the quantum, Tariff computations, duration, supplier particulars, method of supplier selection and such other details as the Commission may require so to assess that the conditions specified in this Regulation have been complied with. ..."
GEPL, KRCIPPL, MBPPL, and NUPLLP requested to allow the variation for quantum up to 20% subject to 10% variation in cost for small distribution licensees on actual basis. Regulatory Assistance Project suggested to conduct a study to identify an optimal capital structure that consider risk and cost and the minimizes cost to customers in the long run.
In case of variation in the quantum above 5%, the distribution licensees are expected to approach to the Commission for prior approval with an intention that, the distribution licensees need to project their demand more accurately and seriously considering the future variations. Further, the Commission is not restraining the distribution licensees from procuring the additional power but only suggesting for taking approval of the Commission in the interest of regulating the Tariff of the consumers.
No change in the Provision of Draft MERC MYT Regulations 2024.
Tata Power submitted that the Commission has specified no true-up shall be done in case of ceiling tariff mechanism. Tata Power needs clarity on the applicability of this Regulation for Distribution Licensee operating in parallel licence area and subjected to ceiling tariff mechanism. Regulatory Assistance Project recommended to consider the deployment of a ‘Non-Wires Alternative’ (NWA) concept for the DISCOMs as an additional measure to lower consumer costs, cleaner environment, and better customer satisfaction.
Financial prudence is necessary while undertaking Truing up of tariff for all utilities including distribution utilities. The Commission clarifies that under these MYT Regulations, it has not introduced Ceiling Tariff as mandatory provision in case of parallel distribution licensee cases. In fact, the Commission hereby clarifies that it has only incorporated enabling clause for introduction of Ceiling Tariff, subject to fulfilment of certain conditions and if Commission deems it appropriate to introduce Ceiling Tariff mechanism at future date. Thus, the retail tariff determination for distribution licensees shall continue even in case of parallel distribution licensee. Thus, the Distribution licensee must submit its actual ARR duly reconciled with its audited accounts, for the purpose of true-up exercise or otherwise. Hence, financial prudence under Regulation 22 of MYT Regulations, 2024 is independent of applicability of ceiling tariff and it’s truing up.
No changes in provision of draft MERC MYT Regulations, 2024
“23.2...
Provided further that the capital cost of the assets forming part of the Project but not put to use or not in use, shall be excluded from the capital cost of Generation Project and transmission system:
....
Provided also that any capital expenditure incurred based on the specific requirement of a Generating Company or Licensee shall be substantiated with necessary documentary evidence of such request and undertaking received.”
MSETCL submitted that the 5th proviso should be modified in such a way that if the asset is not put to use on account of delay due to beneficiary events, then the Licensee should be suitably compensated for the delay and shall be entitled for full recovery. As such the development of downstream system falls under the purview of other Licensees in terms of load management, which is beyond the control of the Transmission Licensees, therefore, it is submitted that the impact of non-readiness of other Utilities should not be passed on to Transmission Licensees. Further, MSETCL should be allowed capital cost recovery and O&M expenses to maintain the assets in proper condition and ready for operationalisation on immediate basis when needed.
Tata Power requested that, the Commission may clearly specify that the ‘Interest During Construction’ shall be allowed as part of the Capital Cost, for the land acquired for the Transmission Scheme after inclusion of the said Scheme in the Five-Year STU Plan.
The Commission is not considering the assets which are not put to use for capitalisation recovery and O& M recovery as it may lead to increase in the tariff without consumer benefits. With regards to Tata power’s suggestion, the consideration of IDC is part of capex approval process which is governed by the MERC Capex Regulations 2022.
No changes in provision of draft MERC MYT Regulations, 2024
“23.3 The capital cost admitted by the Commission after prudence check shall form the basis for determination of Tariff:
Provided that prudence check may include scrutiny of the reasonableness of the capital expenditure, financing plan including the choice and manner of funding, interest during construction, use of efficient technology, cost over-run and time over-run, and such other matters as may be considered appropriate by the Commission for determination of Tariff:
Provided further that the entire gain to the Generating Company or Licensee or MSLDC or STU on account of variations in capitalisation, in terms of variation in Interest and Finance Charges, Return on Equity, and Depreciation, shall be passed on as a rebate in Tariff over such period as may be stipulated in the Order of the Commission after prudence check:
Provided also that the loss to the Generating Company, ESSD or Licensee or MSLDC or STU on account of variations in capitalisation, in terms of variation in Interest and Finance Charges, Return on Equity, and Depreciation, shall be shared between the Generating Company, ESSD or Licensee or MSLDC or STU and the respective Beneficiary or consumer in the manner stipulated by the Commission in its Order after prudence check.
MSPGCL submitted that, its ongoing projects have been significantly impacted due to Covid-19. Therefore, MSPGCL requested that the entire capital cost of these ongoing projects be permitted without any deductions in IDC on grounds of time or cost overruns.
Tata power requested to delete the second and third proviso as the capital cost is approved based on the prudence check by the Commission and approved based on actuals as per MERC (Approval of Capital Investment Schemes) Regulations 2022. Such costs are not normative costs and actual costs are required to be considered for the tariff determination.
The Commission has initiated the current proceedings for framing the MYT Regulations 2024 for fifth control period. The case specific issues raised by the MSPGCL are out of the purview of the current proceedings initiated by the Commission. With regards to Tata power's submission the Commission does not find any merit in the submission. The provision of the prudence check during MYT proceedings would be necessary as there may be some of the capex proposal which may be submitted by utilities during MYT proceedings also.
No changes in provision of draft MERC MYT Regulations, 2024.
“23.7 The Commission may approve, for each year of the Control Period, an additional amount equivalent to 20% of the total capital expenditure approved for that year, towards planned or unplanned capital expenditure that is yet to be approved by the Commission.”
“23.8 The cumulative amount of capitalisation against non-DPR schemes for any Year shall not exceed 20% or such other limit as may be stipulated by the Commission through an Order, of the cumulative amount of capitalisation approved against DPR schemes for that Year:
Provided that, in case MSLDC the cumulative amount of capitalisation against non-DPR schemes for any Year shall not exceed Average capital expenditure of past three years actually incurred or 20% of approved capital expenditure of previous years, whichever is lower, in case there is no approved capital expenditure for particular year.
Provided further that the Commission may allow capitalisation against non-DPR schemes for any Year in excess of 20% or such other limit as may have been stipulated by the Commission through Order, on a request made by the Generating Company, ESSD or Licensee or MSLDC.”
“23.12 The capital cost may include initial spares capitalized as a percentage of the Plant and Machinery cost up to the cut-off date, subject to the following ceiling norms:-----
APTCL requested to allow the non-planned capital expenditure for a particular year on a case-to-case basis in case there is no approved capital expenditure for that year. Tata Power requested to allow 50% of proposed capitalisation towards schemes that are yet to receive approval from the Commission at the time for issuance of MYT order. If Commission finally decides to discontinue the MTR process, then Commission may allow the utilities to include additional charges to incorporate the effect of CAPEX schemes approved subsequent at the time of issuance of MYT order. This will minimise the under recovery of legitimate costs during the Control period and reduces the impact on consumers.
MSPGCL requested to consider the spill over the scheme and carry out DPR to Non-DPR ratio assessment over the control period instead of carrying out annual basis. Due to practical difficulties, the implementation timelines are sometimes difficult to follow and project execution is deferred to the next financial year. However, non-DPR schemes are smaller in nature/ scope, so implementation can be faster. This creates mismatch between DPR & Non-DPR schemes and leads to capex disallowance for the year.
AEMIL requested to remove the provision of 20% limit for non-DPR schemes. The Non-DPR schemes are approved by the Commission in accordance with MERC Capex Regulations, 2022. Accordingly, there is no requirement of any non-DPR limit, since all DPR and Non-DPR capitalization will now go through regular scrutiny before being allowed in Tariff Order.
STU has requested for more clarity in terms of the approval of the non-DPR schemes in case of STU and relax the criteria to higher level. It has submitted that it might happen that capital expenditure scheme may be lower than DPR limit of INR One Crore considering its nature of business and transition period as like SLDC.
Tata Power requested to revise the allowable ratio for non-DPR schemes to 30% of the capitalization approved against DPR schemes for that year. It is submitted that by considering the anticipated reduction in the number of schemes qualifying as DPR schemes due to cost revisions. Further it is also requested to revise regulation 24.3 as the capital investment schemes arising from changes in law or directives from statutory authorities may not always entail additional capitalization for existing systems or equipment. Instead, they may necessitate entirely new capital expenditures. Such expenditures in Non-DPR schemes should be permitted as capital expenditure (CAPEX) without any cost limitation based on the Non-DPR/DPR ratio. This approach will ensure that regulatory constraints do not hinder necessary investments mandated by legal or regulatory requirements. It allows for compliance with statutory obligations while maintaining the integrity and flexibility of the capital expenditure framework.
MSDCL submitted that the Commission should define a benchmark capital cost for Emission Control System (ECS) with technical specifications in its Regulations so that Generators can
adhere to this benchmark cost while installation of ECS. Capital cost incurred above the benchmark cost may be disallowed by the Commission.
The Commission has considered the comments of the stakeholders. The Commission has decided to discontinue the mid-term review process for all unities except distribution licensees. In light of this decision, the Commission finds it appropriate consider the historical trend of capitalisation of approved capital schemes (DPR and Non-DPR), projected growth in the distribution network, consumer base & demand, expected growth in generation capacity addition and transmission network augmentation requirement, ongoing/pending capital schemes, status update of in-principal approved schemes, status of tie-up of funds for various capex schemes proposed by generation company, transmission licensee, distribution licensee, STU, SLDC, as the case may be at the time of MYT proceedings. Accordingly, the Commission has added the specific provision in the final MERC MYT Regulations 2024. As the new Regulation is added as below, the Regulation 23.7 of the draft MERC MYT Regulations 2024 may be irrelevant for allowing separately additional capex expenditure limited to 20%. Accordingly, the Commission has deleted Regulation 23.7 of the draft MERC MYT Regulations 2024.
With regards to Non-DPR schemes, the Commission has increased the limit of Non-DPR schemes from existing 20% to 30%, considering the number of Non-DPR schemes are expected to be increased with increasing the limit of DPR schemes from 10 Cr to 25 Cr under Capex Regulations, 2022. Further, the Commission also considers the submission of stakeholders that, Non-DPR schemes should be monitored cumulatively over a control period.
The Commission notes the submission of the STU and clarifies that, STU being a new entity and having minimal CAPEX requirement can be treated similar in lines with MSLDC for the relaxation in the approval of CAPEX schemes below INR 1 Cr.
With regards to submission of Tata Power, the Commission is of the view that, the revised provisions of the Regulation 24.5 and 24.6 shall address the concerns raised by the Tata power. Tata Power may submit the capital investment schemes arising from changes in law or directives from statutory authorities during MYT proceedings further the increased quantum of Non-DPR schemes from 20% to 30% would also help the utility to take up more schemes under Non-DPR during the MYT period and same may be considered by the Commission at the time of Truing up proceedings subject to prudence check.
The new Regulations 24.6 is added as below in the final MERC MYT Regulations 2024 and Regulation 23.7 of the draft MERC MYT Regulations 2024 is stands deleted.
24.6 For the purpose of approval of projected capital expenditure plan and capitalisation plan for Control Period, the Commission shall take into consideration historical trend of capitalisation of approved capital schemes (DPR and Non-DPR), projected growth in the
distribution network, consumer base & demand, expected growth in generation capacity addition and transmission network augmentation requirement, ongoing/pending capital schemes, status update of in-principal approved schemes, status of tie-up of funds for various capex schemes proposed by generation company, transmission licensee, distribution licensee, STU, SLDC, as the case may be.
Further changes proposed in the Regulation 24.9 are as follows:
“24.9 The cumulative amount of capitalisation against non-DPR schemes for any Year shall not exceed 30% or such other limit as may be stipulated by the Commission through an Order, of the cumulative amount of capitalisation approved against DPR schemes for that Year:
Provided that, in case MSLDC and STU the cumulative amount of capitalisation against non-DPR schemes for any Year shall not exceed 30% of the Average capital expenditure of past three years actually incurred or 20% of approved capital expenditure of previous years, whichever is higher, in case there is no approved capital expenditure for particular year.
Provided further that the Commission may allow capitalisation against non-DPR schemes for any Year in excess of 30% or such other limit as may have been stipulated by the Commission through Order, on a request made by the Generating Company, ESSD or Licensee or MSLDC or STU.”
“26.1 For a capital investment Scheme declared under commercial operation on or after April 1, 2025, debt-equity ratio as on the date of commercial operation shall be 70:30 of the amount of capital cost approved by the Commission under Regulation 23, after prudence check for determination of Tariff:
Provided that the equity investment to be considered in any year shall not exceed the difference between the sum of cumulative return on equity allowed by the Commission in previous years, efficiency gains and losses, incentives and disincentives, and income earned from investment of return on equity, and the cumulative equity investment approved by the Commission in previous years, unless the Generating Company or ESSD, or Licensee or MSLDC or STU submits documentary evidence for the actual deployment of equity and explain the source of funds for the equity:”
APTCL requested to delete the proviso given in the reference regulation because, once the entire equity is recovered through RoE, any further deployment of internal accrual shall not be considered as equity whereas, this equity shall be considered as normative debt which is eligible only for interest on Long-term loan. Further, this would limit the profitability of power
utilities and act as a deterrent to utilize the cash generated from internal accrual for the purpose of CAPEX. Hence, the company can earn better returns by investing the available cashflow.
The Commission notes the submission of APTCL. The proviso of Regulation 26.1 is necessary monitor the cumulative equity in the business and the RoE allowed against it by the Commission in the previous years. The Commission is required to ensure that the overall normative equity in the business shall not exceed 30% during the control period.
No changes in provision of draft MERC MYT Regulations, 2024.
"27.1 .....
(b) Depreciation for the Existing Capital Schemes or Existing Assets of the Generating Company or Licensee or ESSD or MSLDC or STU shall be computed annually based on the straight-line method at the rates specified in the Annexure I to these Regulations:
...
(c) Depreciation for the New Capital Schemes or New Assets of the Generating Company or Licensee or MSLDC or STU or Energy Storage system Developer shall be computed annually based on the straight-line method at the rates specified in the Annexure II to these Regulations:
.....
(d) The salvage value of the asset shall be considered at 10 per cent of the allowable capital cost and depreciation shall be allowed upto a maximum of ninety per cent of the allowable capital cost of the asset:
Provided that the Generating Company, ESSD or Licensee or MSLDC or STU shall submit certification from the Statutory Auditor for the capping of depreciation at ninety per cent of the allowable capital cost of the asset:
Provided further that the salvage value of Information Technology equipment and computer software shall be considered at zero per cent of the allowable capital cost.
....."
AEMIL requested to specify the Salvage value of Batteries and Meters in addition to IT equipment and computer software and also suggested to consider the salvage value for Batteries and Meters as zero as such equipment is almost scrapped, with absolutely no realisation against the scrap. ATIL and MEGPTCL requested to keep depreciation rate for new assets same as of
existing assets as provided in MYT Regulations, 2019 as it is difficult to get higher tenure loans and it will also increase interest burden on the consumers due to slower repayment of loans. The depreciation rate for new assets is reduced from 5.28% to 4.22% considering repayment period of 15-18 years. GEPL, KRCIPPL, MBPPL, and NUPLLP requested to clarify the methodology for asset getting depreciated more than 70% before completion of 12 years.
MSETCL submitted that its existing Loan tenures are of 3-year moratorium with 10-year repayment term except PFC which is of 3-year moratorium + 15-years repayment term. It is also submitted that in future loans are secured at 10-12 years repayment terms from banks/ financial institutions apart from the PFC/ REC, its debt service obligations would be affected. MSETCL also submitted that, the period of 12 years for depreciating 70% of asset value shall be kept same for both existing and new assets in case of MSETCL which may be affect cash flow. Proposed mechanism is an approach to defer tariff.
MSEDCL requested to exclude MSEDCL from the said provision & accordingly the period of 12 years for depreciating 70% of asset value shall be kept same for both existing and new assets in case of Distribution Licensee. It is also submitted that, any investment that is proposed to be taken up by Generating Companies shall always be linked to useful life of the Plant rather than the tenure of the PPA with Distribution Licensee.
Tata Power submitted that salvage value for building and civil works should be considered as zero, as after demolition, the civil waste needs to be disposed off and does not have any scrap value. Also requested for clarity, as depreciation rates for different assets are different. Hence, some assets will depreciate up to 70% by the end of 15 years, if their depreciation rate is around 4.6%, while some of the assets will take more time to depreciate up to 70%, and some assets with higher depreciation rates will depreciate up to 70% in lesser number of years. It is also requested to revise the Regulations 27.1 (e) and (f). The depreciation of emission control systems should be aligned with the remaining useful life of the plant. It is submitted that the modifications will ensure that the depreciation of emission control systems is more closely tied to the operational lifespan of the plant, reflecting the ongoing investment in environmental compliance measures, and facilitating fair and equitable tariff determination.
The Commission notes the submission of the stakeholders. The Commission in its explanatory memorandum to MYT Regulations 2024 has clarified that, the Tariff Policy stipulates that the depreciation rates specified by the CERC should be adopted for generation and transmission business, and may be adopted for the distribution business also, after suitable modification to be undertaken by the Forum of Regulators. Accordingly, the Commission has considered the provisions of the CERC MYT Regulations 2024 while proposing the loan repayment tenure for the New Projects as 15 years. The Commission in its explanatory memorandum to MYT Regulations 2024 has also noted that, the tenure of long-term loans being offered by the PFC and REC is in the range of 15 to 20 years.
Further, with regards to depreciation rates, the Commission has adopted the depreciation rates proposed by the CERC for old and new assets. It is expected that, the utilities shall maintain the separate record of existing assets and new assets under 5th Control period. Accordingly, the Commission has added clarification about the existing assets and new assets.
No change in provisions of Regulation 23.1 (b) and 23.1 (c) of draft MERC MYT Regulations, 2024.
Clarification has been added as below:
“The term “Existing Capital Schemes” or “Existing Assets” here means the Capital Schemes or the Assets, including Non-DPR schemes which are commissioned on or before the March 31, 2025 or Assets in-principally approved by the Commission before the notification of these Regulations for the Generating Company or Licensee or MSLDC or STU or ESSD.”
The term “New Capital Schemes” or “New Assets” here means the Capital Schemes or the Assets, which not covered under Existing Assets.
"27.5 The depreciation on capital investment schemes undertaken by Generating Companies or Generating Businesses shall be allowed proportionately corelated to the remaining tenure of the Power Purchase Agreement with the Distribution Licensee."
Tata Power requested to provide the clarification to ensure transparency and alignment between tariff considerations and the contractual agreements governing Hydro power generation. Further, it is submitted that as the Power Purchase Agreement (PPA) for Tata Power have been signed for a period of 5 years, the tariff is subject to an increase due to depreciation considerations over this period. Moreover, the Explanatory Memorandum lacks clarity regarding the correlation of depreciation to the remaining tenure of the PPA. It is crucial to clarify this aspect, particularly as hydro plants are typically associated with perpetual PPAs.
With regards to Tata power's request for clarification for depreciation of hydro projects the Commission while approving the power procurement plan of Tata Power Distribution, in Case No. 39 of 2023 dated 28 November 2023, the Commission has directed to extend the PPA of hydro power for longer tenure of 15 to 20 years. The Commission's directive is as below:
24.10 Also, PPA for cheaper Hydro units can be extended for longer period say 15/20 years based on life assessment study. Such arrangement would also enable TPC-G to undertake long term capital investment on their generating units. Hence, the Commission directs TPC-D to sign unit wise PPA with TPC-G for extended period of 5 years. While signing such PPA, existing unit wise allocation between BEST Undertaking and TPC-D shall be maintain. Based on same principles, BEST Undertaking shall also sign unit wise PPA with TPC-G.
The above direction of the Commission addresses the concerns of the Tata Power for recovery of the capex investment when it is linked with PPA tenure.
No changes in provision of draft MERC MYT Regulations, 2024.
“28.2 Base Return on Equity for the Generating Company, Transmission Licensee, Distribution Wires Business shall be allowed on the equity capital determined in accordance with Regulation 26 for the assets put to use, at the rate of 11 per cent per annum in INR terms:
Provided that in case the Generation Company or Licensee or MSLDC or STU or ESSD claims Return on Equity at a rate lower than the normative rate specified above for any particular year, then such claim for lower Return on Equity shall be unconditional:
Provided further that such claim for lower Return on Equity shall be allowed subject to the condition that the reduction in Return on Equity shall be foregone permanently for that year and shall not be allowed to be recouped at the time true-up as applicable.”
MSPGCL, ATIL and MEGPTCL requested to align the base RoE with CERC MYT Regulations 2024 and suggested to retain the ROE to 15.5%
AEMIL, AEML SEEPZ and AEML suggested that Base ROE for Transmission Licensees may specified as 15.5%, so as to align with CERC Regulations. Further, Performance dependent portion of ROE could be specified as both Incentive and penalty should be done in the same way as CERC. AEML submitted that, the Beta considered for analysis is un-levered beta has been considered for the analysis. Un-levered Beta strips off the risk of leverage (debt) and isolates solely the risk of assets / equity. This is clearly not in sync with investor / shareholder expectation. Any person investing in the business is assuming the risk of leverage as well and accordingly their expectation of return from investment rises to be commensurate with such risk. Un-levered companies or those with zero debt clearly have a low risk profile and hence expectation from returns on equity investment in such businesses is also lower. On the other
hand, shareholders of highly levered businesses expect a significantly higher return from their investment in order to cover the risk posed by higher leverage. If the Un-levered Beta used in the analysis is replaced by Beta itself, the Cost of Equity across the board will significantly increase, which is the expected result considering the risk expectation from leverage.
The CERC has also highlighted the need for regulatory certainty in case of existing projects / assets and has stated that in order to ensure regulatory certainty for investors of existing projects, it is necessary to retain the RoE for existing assets at rates provided in 2019 Regulations.
AEML suggests that the Base RoE for existing Generating Companies, Transmission Licensees and Distribution Wires business may kindly be specified as 15.5%, so as to align the same with the CERC. Performance dependent portion of RoE could be specified as both incentive and penalty same way as the CERC has done. If the Commission accepts the changes in Base ROE, there shall be corresponding changes in percentage rate of performance linked ROE as well.
Tata Power requested to consider the approach adopted by CERC of allowing the RoE at 15.5% for Thermal generating stations and 16.5% for Hydro generating stations and providing entire ROE at the beginning of the Control Period with reduction, if any, in case the Utility fails to achieve the specified performance levels. Further, the reduction of RoE linked to performance parameters should be kept at a maximum of 1 to 1.5%, and not 4.5%. It is also requested to the base ROE be retained as 15.5% or at worst 14%.
Tata Power suggested that ramp rate performance based linked ROE should be aligned with the CERC Tariff regulation 2024. Regulation should modify to incorporate that performance Linked RoE of 0.1% shall be allowed for every incremental ramp rate (ramp-up or ramp-down) of 0.1% per minute achieved over and above the ramp rate of 1% per minute, subject to ceiling of additional rate of Return on Equity of 0.5% like existing provision of the MYT Regulations 2019. Tata Power also requested to retain provision as per MYT Regulation, 2019. Tata Power submitted that, to recover the full ROE for the Distribution Wires Business, it is required to achieve Wire Availability of 100%, i.e., SAIDI of Zero. It is submitted that this is not possible to achieve 100% Availability in Practice.
Prayas Energy group requested to direct the MSLDC to ensure frequent randomized demonstration of ramping capability of generating stations claiming ramp rates over 1.25% and allow RoE incentives based on the performance during testing and ensures details of declaration and testing should be published on SLDC website every month as per the formats specified in MERC Grid Code 2020. Further, if generating station is unable to achieve required ramp rate during demonstration of declared capacity, it leads to disallow incentives for RoE. Furthermore, Prayas requested to ensure the submission of MSLDC procedure for certification and achievement of ramp rate is time bound and its approval is subject to public process.
Prayas Energy Group requested to remove the proposed incentivization for availability >75% but < 85% during peak hours. Prayas suggested the targeted incentives for additional RoE for availability >85% during peak hours across high demand and low demand seasons as follows-
| Availability > 90% | Availability >85% | |
|---|---|---|
| High-Demand Season | 0.6% | 0.4% |
| Low-Demand Season | 0.4% | 0.2% |
Note: High/Low demand season and Peak/off-pick hours should be defined based on National Net Load
Prayas Energy Group requested to give clarification for the difference in incentives provided for availability during peak hours for thermal and hydro generators. It is submitted that, the range of incentivisation for thermal is 0.25% to 0.75%, while for hydro the range is 1% to 2.25%. The additional performance-based RoE for hydro is being considered as making it equitable with other generation in fifth control period, as stated by the Commission in para 4.6.15 of EM. Hence, the reason for the significant difference is not clear.
GEPL, KRCIPPL, MBPPL, and NUPLLP requested to reconsider the return on equity to ensure consistency and proposed to retain the ROE at 15.50%, as specified in CERC MYT Regulations 2024. The reduction of Base RoE to 11% and with increase in performance-based RoE may results in accumulation of revenue gap due to filling of 5-years petition. They also submitted that, 100% Wires Availability required for full RoE of 4.5%, that is SAIDI of zero. So, it is not possible to achieve in practice. They stated that, the maximum wires availability pegged at 99.50% for earning full additional RoE.
MSEDCL requested to keep the base rate of ROE for wire business at 14%. It is submitted that MSEDCL facing significant challenges despite being allowed at 14%. Rising of power purchase costs, operational costs and market fluctuations resulted in significant financial losses. As a result, MSEDCL is unable to get benefits from the expected return on investments.
MSEDCL submitted that the target availability for distribution network shall be lower for MSEDCL as compared to other licensees in Maharashtra. It is proposed that the existing clause may be retained for maintaining target availability of 95% to MSEDCL & for every 0.5% over achievement in wires availability RoE shall increase by 0.50% subject to ceiling of 4.50%. Further, MSEDCL is yet to install smart meters at multiple locations for measurement of System Average Interruption Duration Index (SAIDI). Hence, sufficient time to be given to MSEDCL for installation of Smart meters to calculate SAIDI automatically. The implementation of smart meters, MSEDCL will control the assessed billing. However, till that time, % assessed billing shall be set based on the past period's performance.
MSEDCL submitted allowable incentives in following manner:
MSEDCL also submitted that, linking the benefit of operating in FGMO mode to ROE of the generator will load the cost only on the Distribution Licensees which is not justified. The performance linked ROE should be allowed only above the normative availability. MSEDCL also submitted that, linking the benefit of operating in FGMO mode to RoE of the generator
will load the cost only on the Distribution Licensees which is not justified. MSEDCL submitted that the availability of hydro generation during peak hours is one of the prime criteria to avoid costly power purchase from alternate sources by the Discoms. Hence the performance linked RoE shall be allowed only above the normative availability.
MSEDCL submits that Transmission licensee incurred huge capex to develop transmission lines and other transmission network. The Commission has approved approx. 27% of RoE expenses to Net ARR of MSETCL in the true-up of FY 2020=21 & FY 2021-22. Hence, there is no need to increase RoE additionally by 0.75% if the transmission system is operational with data telemetry, communication system up to load dispatch centre or protection system. As seen in past, the existing provisions provide for enough possibilities of earning RoE by transmission companies. Hence, the clause related to additional incentives of 0.75% may be deleted.
MSEDCL submitted that the proposed provision of 5 Paise Supply Margin led to reduction in supply margin by 40% which is unjustifiable.
MSPGCL requests the commission that prior to making provision for any incentive for achieving additional Ramp rates it will be prudent to assess the actual ramp rates as on date through a third-party assessment and then based on such findings the achievable higher ramp rates can be set for providing the incentive RoE.
AEML submitted on Ramp Rate that, NLDC methodology for Ramp Rate certification cannot be considered for State generating companies.
Mean Time Between Failure linked with RoE: MSPGCL requested for clarity regarding the approach or methodology for calculating MTBF-linked Return on Equity (RoE). Furthermore, it is crucial to offer RoE linked to unit-wise MTBF to incentivize individual units to operate continuously. MSPGCL submitted that, the Impact of linking ROE with MTBF is Rs. 120-130 Cr per year. AEML also submitted that, MTBF not possible to achieve for older generators like DTPS.
Peak Hours availability: AEML submitted that, Target peak availability of more than 90% for getting addnl. RoE of 1% is too onerous for old generation stations.
Performance linked RoE for Distribution Wires business: AEML submitted that, for the full RoE of 4.5%, 100% Wires Availability is required i.e. a SAIDI of Zero. This is not possible to achieve in practice. As per the existing MYT Regulations also, the maximum Wires Availability for earning full additional RoE is pegged at 99.50%.
Operational under FGMO: MSPGCL submitted that receipt of assured quality of coal is critical for operating unit under FGMO. Hence, absence of assured quality of coal would not enable MSPGCL to achieve this performance parameter to secure additional 1.25% RoE. The impact of linked ROE with FGMO is ~ Rs. 160 Cr per year. MSPGCL requested to align provisions related to base RoE and additional ROE with provisions specified by CERC in its
Regulations 2024 or at least retain the existing provisions of MERC MYT Regulations 2019, i.e. 14% of base ROE and 1.5% performance linked RoE. The mechanism to make the performance of the unit more efficient, DSM penalties are already in place as per DSM Regulations. These mechanisms have led to penalties for MSPGCL. Therefore, enforcing excessively stringent technical requirements to meet the RoE at this juncture would be inappropriate. Further as compared to other projects Hydro projects have long gestation period and lowering assured ROE from 14% to 11% would be detrimental for existing Hydro projects and it would disincentivize future Hydro projects. All three criteria for additional ROE for hydro generating stations are attainable. Hence, the base ROE for hydro generating stations should be set at 15.5%, with additional ROE such as capacity index ROE granted above this threshold to provide further incentives for the development of new hydro generating capacity.
AEML SEEPZ and AEML submitted that maximum wires availability needs to be pegged at 99.50% at present and the performance linked graded ROE can then be specified accordingly.
Further, AEML submitted that Regulation 78 uses the term “For incentive consideration”. The same needs to be modified to “For Additional RoE”, as there is no separate incentive for Availability anymore.
ATIL and MEGPTCL requested to align the Base RoE with RoE specified by CERC in Tariff Regulation 2024. ATIL and MEGPTCL submitted the reference of Electricity Rules, where it is clearly mentioned that RoE specified by any SERCs would be aligned with RoE specified by CERC. Accordingly, the RoE should be 15.5% as per CERC MYT Regulations, 2024 otherwise it will impact the Generators/licensees future Debt-funding and consequently hamper investments in the sector. Further, ATIL and MEGPTCL requested to treat the incentives (performance-linked) separately. The RoE should not be linked to efficiency incentives as incentives is mainly to reward the performance and efficiency of the utility which will encourage the utilities to maintain good performance and efficiency. Graduate Engineer’s Association requested to cancel the Proposed reduction in base ROE, it will affect the prospective investment in sector.
Krushna Bhojar requested to keep the Base ROE Rate at existing 14% and refrain from reducing it to 11% as it is de-motivating for the investors in case the return on their investments reduces. Maharashtra Rajya Magasvargiya Vidyut Karmachari Union requested that the proposed reduction in base ROE should be cancelled otherwise it will arise serious situation in power sector. It is also submitted that this flip flop policy of MERC will affect the prospective investment in sector. Union of Chemist submitted that, reducing the Base RoE rate from 14% to 11% will result in Power Sector Companies going into Bankruptcy. The Commission is requested to remove the clause of reducing the Base RoE to 11%
The Commission notes that the CERC in its final MYT Regulations 2024 has proposed RoE of 15.50% in case of Generation and Transmission utilities and 15% for new transmission
assets/utilities. Further, the performance linked RoE will be reduced from the allowed RoE at the time of Truing-up.
MoP vide its Amendment to Electricity Rules, 2005 dated July 26, 2023 has prescribed Rule under Rule 20(8), which mandates the SERC to align its rate of regulated returns on equity (RoE) with the CERC for Generation and Transmission business.
In view of the above provisions of the MoP rules and final notified CERC MYT Regulations, 2024, the revision in ROE rate is proposed to be aligned with the CERC MYT Regulations 2024 subject to few adjustments in the performance linked parameters.
Further, the Commission has also taken into consideration various objections and suggestions received from generating companies, distribution licensees and other stakeholders on the issue of regulating return on equity while determining the dispensation under the MYT Regulations for fifth control period.
Accordingly, the Commission has considered Total RoE of 15.5% for Generation, Transmission, Distribution (Wires), 17.50% for Distribution (Retail Supply), 14% for STU and SLDC with performance incentive linked with KRA and 18% for ESS for the purpose of projections during Control Period. Further, the RoE shall be linked with performance parameters which will be assessed at the time of truing up as per the conditions provided in the Regulations for the respective Licensees.
Further, RoE shall be grossed up with the Income Tax and the same shall be allowed at the time of MYT Projections. In addition, Performance Linked RoE shall be adjusted at the time of Truing-up for all the respective licensees for shortfall to achieve the performance criteria provided for the respective business and incremental RoE for exceeding the performance norms in case of few specific parameters. Further, in the case of Distribution Wires, the linkage of incentive/dis-incentive to performance parameter SAIDI, has been modified considering several objections received on this point.
Thus, the criteria for performance-linked RoE for Wire Availability is revised to 99.50% in line with MYT 2019 Regulations.
Performance parameter of Mean Time Between Failure (MTBF) has been retained from MERC MYT Tariff Regulations 2019 with modification in % performance linked RoE.
With regards to supply Margin for Retail Supply Business, AEML and TPC have submitted that Equity portion of the upcoming Capitalisation of toward BESS and Smart Meters are not being considered as part of the Retail Supply Equity, which was in principally approved by the Commission before the notification of CAPEX Regulations, 2022. The Commission has considered the submissions of the stakeholders on supply margin and deleted the provision for introduction of supply margin for now and instead restored the provision for allowing ROE at 17.5% for retail supply business similar to MERC MYT Regulations 2019.
Return on Equity shall be allowed in two parts viz. Base Return on Equity, and Performance Linked Return on Equity linked with actual performance:
Provided that, the Return on Equity allowed at the time of MYT Proceedings shall be inclusive of both Base Return on Equity and Performance Linked Return on Equity:
Provided further that Performance Linked Return on Equity considered at the time of MYT Proceedings is on provisional basis and may undergo change at the time of True-up based on level of performance on various parameters stipulated in these Regulations:
Provided that return on equity in respect of additional capitalization beyond the original scope, including additional capitalization on account of the emission control system, Change in Law, and Force Majeure shall be computed at the base rate of one-year marginal cost of lending rate (MCLR) of the State Bank of India plus 350 basis points as on 1st April of the year, subject to a ceiling of 14%:
Provided also that in case the Generation Company or Licensee or MSLDC or STU or ESSD claims Return on Equity at a rate lower than the normative rate specified above for any particular year, then such claim for lower Return on Equity shall be unconditional:
Provided also that such claim for lower Return on Equity shall be allowed subject to the condition that the reduction in Return on Equity shall be foregone permanently for that year and shall not be allowed to be recouped at the time of Mid-Term Review or true-up as may be applicable.
Accordingly, Regulation 29.2 to 29.11 have been revised in the final regulations.
"28.8 In case of the Retail Supply Business, the Supply Margin upto 5.00 Paisa/kWh inclusive of Income Tax component shall be allowed for all the Retail Supply Licensees for each financial year over the Control Period subject to reduction upto 2.00 Paisa/kWh at the time of true-up if Supply Licensee fails to achieve following performance parameter: ....."
AEML requested to allow RoE to Retail Supply business of Distribution Licensee, as at present or allow the Distribution Licensee to shift its fixed assets such as meters and associated infrastructure out from supply business to wires business. AEML SEEPZ and AEML requested that supply margin ought to specify as pre-grossed up rate and grossing up with effective income tax rate should be done basis the actual effective tax rate as per accounts. Further, AEML SEEPZ and AEML requested to allow pro-rata reduction in supply margin on both collection efficiency and billing assessed parameters, instead of bullet reduction as suggested in the present draft, this will be symmetrical with pro-rata allowance of additional RoE as proposed in the draft.
GEPL, KRCIPPL, MBPPL, and NUPLLP requested to clarify, if any distribution licensee claims lower/NIL RoE, then how the disallowance will be carried out by Commission. Further, on part of RoE for Retail Supply Business, the Commission may allow the RoE same as in MYT Regulations, 2019 or as proposed in the draft MYT Regulations, 2024. They also submitted that in case Supply Margin regime is adopted for retail supply businesses, the reduction in Supply Margin proposed for non-achievement of performance parameters of
Collection Efficiency and Assessed Bills, should be on pro-rata basis, as opposed to the proposed reduction.
MSEDCL submitted that, the proposed clauses lead to reduction is supply margin by 40% which is unjustifiable. MSEDCL submitted that, historically collection efficiency of AG consumers is ranging between 40% to 60% including subsidy. So, it is requested to collection efficiency in performance linked RoE shall only be linked to non-AG consumers. Tata Power submitted that the Commission may consider continuing with the RoE approach for Supply Business also along with the Supply Margin in such a way that the overall ROE of 17.5% will be protected for the assets base along with the supply margin separately for the sales by a Licensee. Alternatively, the approach for Supply Margin may be modulated further. Tata Power stated that, the supply cost recovery through Supply Margine only, it is not sufficient. Tata Power submitted that; the methodology should be such that it will give the entire recovery of supply cost. The Commission may consider allowing Base RoE of around 9% computed as per present practice, with the balance RoE of 8.5% (considering that Supply Business is inherently riskier and has rightly been allowed RoE of 17.5% in the past) being allowed through the Supply Margin allowed at the appropriate rate in paise/kWh linked to the actual Sales.
The Commission notes that introduction of Supply Margin has its own advantage as the returns of retail supply business are directly linked to growth in the sales/supply by such business and inherently supportive of competitive arrangements in the retail supply business. However, the considering objections/suggestions of the stakeholders, it may be appropriate to introduce such Supply Margin linked returns at later date. Accordingly, the Commission has proposed to retain the provisions of the allowable Returns for retail supply business linked to RoE (Base RoE and performance linked RoE) instead of Supply Margin approach for the Distribution Retail Supply Business. The RoE at 17.50% shall be grossed up with effective tax approved at the time MYT projections and adjustments with linkage to shortfall in performance by way of reducing RoE upto 2.00% at the time of truing up.
The changes in Regulation 28.8 are as follows:
“29.8 In case of the Retail Supply Business, the Performance Linked Return on Equity considered in MYT Order shall be retained at the time of true-up, as per the following schedule, subject to the maximum reduction linked to performance parameters of 2.00%:
| Performance Parameter | Reduction in Performance Linked RoE | |
|---|---|---|
| Collection Efficiency | ≥ 99% | 0.00% |
| < 99% and ≥ 95% | Reduction of 0.50% of RoE | |
| < 95% | Reduction of 1.00% of RoE | |
| Assessed Billing | ≤ 1.5% | 0.00% |
| > 1.50% and ≤ 5.00% | Reduction of 0.50% of RoE |
| Performance Parameter | Reduction in Performance Linked RoE |
|---|---|
| > 5.00% | Reduction of 1.00% of RoE |
“29.10 The Generating Company or Licensee or MSLDC or STU or Energy Storage system Developer, as the case may be, shall make every effort to re-finance the loan as long as it results in net savings on interest and in that event, the costs associated with such re-financing shall be borne by the Beneficiaries and the net savings shall be shared between the Beneficiaries and them in the ratio of 2:1, subject to prudence check by the Commission:
APTCL submits that if the rate of interest of refinances loan is less than the prevailing base rate then rate of interest shall be considered equal to the Base Rate as on the date on which the Petition for determination of Tariff is filed. However, if the rate of interest of refinances loan is more than the prevailing base rate then the rate of interest shall be considered equal to the Base Rate as on the date on which the Petition for determination of Tariff is filed or the weighted average rate of interest of actual loan portfolio before refinancing whichever is higher.
Prayas Energy Group requested to allow separate reporting of re-financing options availed by generators. Licensees, MSLDC and STU as part of tariff/true-up process. Further, it is also requested to add regulatory provisions to scrutinise and approve interest rates of long-term borrowings (as part of generator’s true-up/tariff petitions) by comparing them with prevalent rates and rate movements to ensure prudence.
AEML submitted that the rate of interest of new loan because of refinancing can only compared with existing loan, which is refinanced, not compared with weighted average rate of the entire loan portfolio, which could comprise several other Indian currency loans as well as foreign currency loans. AEML requested to allow the cost of refinancing in ARR, in case, if there is a net saving in cost to beneficiaries after considering the reduction of interest due to refinancing. The benefit of refinancing is computed after netting off the cost and then the same is shared with the beneficiaries. Disallowing cost of refinancing will discourage the utilities to refinance their expensive loans by lower cost loans. In case refinancing results in net increase in cost, the disallowance of interest rate could at worst be to the extent of incremental interest, as compared to what had been allowed previously. Therefore, there is no reason why the interest rate should be considered as Base Rate in such a case. The rate of interest of new loan as a result of refinancing can only compared with existing loan, which is refinanced, not compared with weighted average rate of the entire loan portfolio, which could comprise several other Indian currency loans as well as foreign currency loans.
AEMIL requested to allow the cost of refinancing in ARR, in case, if there is a net saving in cost to beneficiaries after considering the reduction of interest due to refinancing. The benefit of refinancing is computed after netting off the cost and then the same is shared with the beneficiaries. Disallowing cost of refinancing will discourage the utilities to refinance their expensive loans by lower cost loans. In case refinancing results in net increase in cost, the disallowance of interest rate could at worst be to the extent of incremental interest, as compared to what had been allowed previously. Therefore, there is no reason why the interest rate should be considered as Base Rate in such a case.
MSETCL submitted that, the Commission should encourage to lower interest rate of the respective/ individual loan rather than linking it with the weighted average rate of interest of actual loan portfolio. Further, by refinancing with lower rate as compared to the respective/ individual loan, the weighted average rate of interest of actual loan portfolio should ideally come down in subsequent year assuming no other new loans at the higher rate are to be considered.
Tata power submitted that rate of interest of new loan because of refinancing can only be compared to the rate of interest of the existing loan, which is refinanced, rather than the “weighted average rate of interest of actual loan portfolio”. It will be appreciated that any refinancing of loan, which is having interest rate lower than existing rate of interest for a particular loan, is beneficial for the consumer.
The Commission notes the submissions of the stakeholders. The Commission is of the view that, Rate of interest of the refinanced loan shall be lower than the rate of interest of the individual loan, which is being refinanced. The modification in terms of comparing with older interest rate of the individual refinance instead of Weighted Average interest rate of actual loan portfolio shall be considered. Accordingly, the Commission has revised the proviso for the clarification as below.
Provided further that rate of interest of the refinanced loan shall be lower than the rate of interest of the individual loan, which is being refinanced;
30.5 Any extra rupee liability towards Foreign Exchange Rate Variation on import of material may be disallowed.
Explanation: The incidence of Foreign Exchange Rate Variation is invariably expected to be negligible unless such equipment is not available in India.
AEMIL and AEML requested that the said regulations may be applied only to projects which shall achieve financial closure after April 01, 2025. It is also submitted that, FERV liability on imported material should be assessed on a case-to-case basis, as per the Project and contract specific and other facts and circumstances. So, it requested to deleted or modified the Provision. Tata Power submitted that there may be such equipment, which needs to be imported due to compatibility issues with existing equipment, non-availability of required equipment specifications in India, lower price than indigenous equipment, less competitiveness due to monopoly of single manufacturer in India, or any other similar reason. In such cases extra liability towards FERV on import of material may be allowed by the Commission.
The Commission is of the view that, utilities should take the efforts like hedging of the FERV to manage the risk. The FERV risk should not be passed on to the consumer. The Commission is not inclined to revise the clause as suggested by the stakeholders.
No changes in provision of draft MERC MYT Regulations, 2024.
(a) In case of coal based/lignite-fired Generating Stations, working capital shall cover:
(b) In case of oil-fired Generating Stations, working capital shall cover:
.....”
MSPGCL suggested that proposed changes may be done post carrying out proper study. The IoWC is allowed after reducing DPC and interest of delay payment as per books of account. In MSPGCL case, due to higher DPC and interest on delay payment, actual IoWC for true-up considered as NIL. Further, MSPGCL has been maintaining the optimum level of coal stock for its operation. However, reduction in cost of coal towards stock from 30 days to 20 days may become critical while meeting the high demand requirement of MSEDCL.
MSPGCL submitted that there is a mismatch between receivable considered for computation of Normative Working Capital requirement and actual expected receivables considering the bill due date considered as per PPA dated April 01, 2009. MSPGCL proposed provision which may be added (Regulation 2 (2.1) (40) to resolve disputes and align with IoWC provisions of draft regulations 2024. The "due date" means the date by which the bill for the charges for power supplied by the Generating Company or for the transmission service provided by a Transmission Licensee are to be paid, in Thirty days from date of presentation of bill by Generation company, Transmission company."
AEML submitted that the Coal stick days should be considered at the normative level, even at the time of true-up.
Tata Power proposed to allow the working capital allowance of 30 days towards coal stock be permitted for imported coal-based plants like Trombay. This modification will ensure operational reliability and continuity of power generation, safeguarding against disruptions due to potential delays in coal deliveries. Further, it is mentioned in the draft Regulations that at
the time of truing up working capital shall be computed based on scheduled generation or target availability of the generating Station, whichever is lower. In this regard, it is pertinent to note that while maintaining fuel availability, a generating station has to necessarily maintain fuel according to target availability. It cannot maintain fuel according to scheduled generation as it is available only one day prior and that is also subject to revisions in real time up to a minimum of target availability. Hence in the actual scenario, the generating station has to engage working capital corresponding to fuel as per target availability only.
The Commission has noted the submission of the Gencos. The Commission notes that, the CERC in its MYT Regulations 2024 has retained the working capital requirement for thermal power plants. Accordingly, the Commission has retained the provisions of working capital requirement as per draft MERC MYT Regulations 2024, in the interest of reduction of generation tariff.
No changes in provision of draft MERC MYT Regulations, 2024.
"31.7 For the purpose of Truing-up for each year, the variation between the normative interest on working capital computed at the time of Truing-up and the actual interest on working capital incurred by the Generating Company or Licensee, MSLDC or STU, substantiated by documentary evidence, shall be considered as an efficiency gain or efficiency loss, as the case may be, on account of controllable factors, and shared between it and the respective Beneficiary/ies or consumer as the case may be, in accordance with Regulation 10:
Provided that the Delayed Payment Surcharge and Interest on Delayed Payment as per books of accounts of the Generating Company or Licensee or MSLDC or STU shall be deducted from the actual interest on working capital, before sharing of the efficiency gain or efficiency loss, as the case may be:
Provided also that if actual interest on working capital exceed the normative interest on working capital, then the interest expenses incurred for funding of Regulatory Assets approved by the Commission shall be deducted from the actual interest on working capital, before sharing of the efficiency gain or efficiency loss, as the case may be."
MSPGCL requested to introduce provisions for Payment Security Mechanism (PSM) implementation monitoring (payment of LPS bills, providing LC etc.) and subsequent disciplinary action through regulating the power scheduled by defaulting distribution licensees,
as provided under Electricity (LPS), Rules, 2022. Further, MSPGCL requested for maintaining the provision regarding adjustment of LPS against actual IoWC, it should also carry out monitoring of timely payment of dues and timely resolution of billing disputes.
AEML, ATIL, MEGPTCL and AEMIL requested to simplify the Regulations and allow interest on working capital on normative basis only without getting into determination of efficiency gains/losses, similar to the Central sector Regulations. That will also completely avoid the complication of finding out the actual interest on working capital or adjustment of DPC/IoA etc. Hence, "Variation in interest on working capital" may be removed from Regulation 8.2 and suggested that Regulation 31.7 may be deleted.
The Commission notes the submission of the stakeholders. With regards to payment security mechanism, the Commission in past vide case specific orders has clarified that the provisions of the MOP Rules are directly applicable to utilities and utilities are expected to implement the same.
The Commission has considered the Interest on Working Capital as “Controllable” parameters and treating is under sharing of gains and losses, as the Commission is of the view that, Generator or Utility should take efforts to minimise the Interest on Working Capital and reduce the burden on the tariff. Further projecting the short term loan rate for working capital for entire control period without any correction at the time of truing up may impact in either way on tariff. The sharing of gains and losses against IOWC at the time of Truing up would be necessary to correct the estimated rate of IOWC at the time of MYT proceedings.
No changes in provision of draft MERC MYT Regulations, 2024.
“33.1 The Income Tax for the Generating Company or Licensee (except Distribution Retail Supply Business) or MSLDC or STU for the regulated business shall be allowed on Return on Equity, including Performance Linked Return on Equity at the rate of Minimum Alternate Tax (MAT) applicable for the respective financial year or actual tax paid, whichever is lower, through the Tariff charged to the Beneficiary/ies, subject to the conditions stipulated in Regulations 33.2 to 33.5:”
.....
33.2 The rate of Return on Equity, including the rate of Performance Linked Return on Equity as allowed by the Commission under Regulation 28 of these Regulations shall be grossed up with the MAT rate or actual tax paid, which ever lower, for the previous year.
Provided that in case the Generating Company or Licensee or MSLDC or STU for the regulated business has not paid any Income Tax for respective year, the Tax Rate shall be considered as zero at the time of Truing-up, subject to prudence check.”
MSPGCL requested to retain the provision of allowing income tax at actual and not to be restricted as lower of actual income tax paid or MAT. It is also submitted that for future years, income tax to be allowed as per actual income tax paid as per latest audited accounts.
AEML requested to revert to the earlier approach of Regulatory Profit Before Tax for allowing Income Tax, at the time of true-up. This approach ensures that Income Tax is permitted to the regulated business segments in a ring-fenced manner, in isolation of the impact of other regulated or unregulated businesses the present practice of grossing up RoE with the Effective Tax rate, as determined from the books of accounts, should be continued, regardless of whether it is zero or Corporate Tax rate
AEMIL, AEML SEEPZ and AEML requested that the present practice of grossing up RoE with the Effective Tax rate, as determined from the books of accounts, should be continued, regardless of whether it is zero or Corporate Tax rate. Further, it is submitted that Regulation 33.1 uses the term “Actual Tax paid”, while Regulation 33.3 uses the term “Actual Tax rate”. The formula in Reg. 33.3 makes it clear that actual tax rate is to be considered. The term “actual tax paid” conveys the meaning of actual tax paid in Rs and hence this needs to change to “actual tax rate”.
ATIL and MEGPTCL submitted that, existing MERC MYT Regulations 2019 stipulate the same methodology for grossing up of RoE with Income Tax as mentioned in CERC Tariff Regulations 2019 and the same has been retained under CERC Tariff Regulations 2024. So, retain same provisions as mentioned in MERC MYT Regulations 2019 pertaining to income tax.
STU submitted that, it would put its best effort in coordination with MSETCL to comply with the regulations; however, till the time complete segregation of MSLDC and STU is pending, while allowing the Income Tax for the STU, the rate of tax allowed for MSETCL for the respective financial year shall be considered.
MSETCL submitted that, it shall be allowed the actual tax paid by the Utility under all cases and not the lowest of MAT and actual tax paid. The Explanatory Memorandum has specifically mentioned about MAT or actual tax paid whichever is lower for utility having multiple business. MSETCL is 100% regulated entity, and all income / expenses are duly accounted for as per relevant provisions of the applicable Act. Hence the suggestion given in para 4.9.3 of EM is applicable for other utilities and not for utility like MSETCL. It is requested to relook into said provision and retain the existing provision for income tax on actual basis.
NUPLLP proposed that, Income tax to be allowed on actual / MAT or Corporate Tax whichever is actually paid.
MSEDCL submitted that, Income Tax is an uncontrollable expense to licensee, so the licensee shall allow the actual tax paid by the Utility under all cases and not the lowest of MAT and actual tax paid. Due to such provision, the Utility unable to recover the tax expense paid to Income Tax department in case the tax liability is over and above MAT.
Tata Power submitted that, instead of consideration of generic approach, the Commission should compute the Tax rate separately based on the individual Regulated business. Further, Tata Power requested for framework, in case the Income Tax is not payable separately for the regulated business. It is also submitted that, it cannot be that the Tax rate will be considered as zero in such case, because Tata Power has not paid any Income Tax for the regulated business, as Tata Power pays the Income Tax for the Company as a whole.
The Commission has noted the submission of the stakeholders. The Commission notes that, if utility select the option of filing tax returns under the new tax regime, the MAT would not be applicable to the utility. Accordingly, the Commission has revised the provisions of the income tax to allow the income tax based on the actual Income Tax rate paid by utility at the time of MYT projections.
The revised provision of the Regulation 34.1 is as below:
34.1 The Income Tax for the Generating Company or ESSD or Licensee (except Distribution Retail Supply Business) or MSLDC or STU for the regulated business shall be allowed on Return on Equity, including Performance Linked Return on Equity at the income tax rate applicable for the respective financial year, through the Tariff charged to the Beneficiary/ies, subject to the conditions stipulated in Regulations 34.2 to 34.5.
Following provisos are added
Provided further that, at the time Multi Year Tariff Projections, the Income tax rate shall be allowed as the latest available Income Tax Rate approved by the Commission, whereas, at the time of true-up the Income Tax rate shall be approved based on the actual Income Tax paid by the Generating Company or ESSD or Licensee or MSLDC or STU or ESSD, subject to prudence check;
Provided that, in case of the Generating Company or Licensee or MSLDC has engaged in any other regulated or unregulated Business or Other Business, the actual tax paid on income from any other regulated or unregulated Business or Other Business shall be excluded while arriving at actual income tax rate.
“32.1 The Commission shall allow Carrying Cost or Holding Cost, as the case may be, on the admissible amounts, with simple interest, at the weighted average Base Rate prevailing during the concerned Year, plus 150 basis points:
Provided that Carrying Cost or Holding Cost shall be allowed on the net entitlement after sharing of efficiency gains and losses as approved after true-up:
Provided further that in case of Distribution Licensees, the Incentive on account of Distribution Losses, as applicable, shall be deducted from the net entitlement, for the purpose of computing Carrying Cost or Holding Cost.”
APTCL requested to allow the carrying cost or holding Cost on monthly compounding basis. APTCL gave reference of the judgement passed by the Hon'ble Supreme Court Civil Appeal No 11095 of 2018 & 4080 of 2022, where Hon'ble Supreme Court mentioned once the carrying cost is granted, the interest on carrying cost would be calculated on compound interest basis not on simple interest basis. It has been held that compound interest on carrying cost helps the licensee to restore their original economic position. Further, APTCL submitted "Change in Law" principle can be equated to the "Revenue Gap/ (Surplus)" determined as a part of true-up exercise as both the principles delays the recovery of the rightful claim of the Licensee and hence the treatment of corresponding carrying cost also has to be in similar manner.
The Commission notes the submissions of the stakeholders. The Judgement of the Hon'ble Supreme Court referred by the utility is case specific. In regulated regime, carrying cost or holding cost is allowed on the gap or surpluses post true-up process which is for the concerned financial year. Hence issue of allowing monthly compounding interest does not arises.
No changes in provision of draft MERC MYT Regulations, 2024.
34.1 Where the Licensee has made a contribution to the Contingency Reserve, a sum not less than 0.25 per cent of the original cost of fixed assets shall be allowed annually towards such contribution in the calculation of Aggregate Revenue Requirement:
.....
34.2 The Contingency Reserve shall not be drawn upon during the term of the Licence except to meet such charges on account of:
(a) Expenses or loss of profits arising out of accidents, strikes, acts of God included, but not limited to lightning, storm, action of the elements, earthquakes, flood, torrential rains, drought and natural disaster or circumstances which the management could not have prevented.
(b) Expenses on replacement or removal of plant or works other than expenses requisite for normal maintenance or renewal:
(c) Compensation payable under any law for the time being in force and for which no other provision is made:
Provided that such drawal from the Contingency Reserve shall be computed after making do adjustments for any other compensation that may have been received by the Licensee as part of an insurance cover and Government Grant, if any.
Provided that, the drawl of such expenses shall be treated as consumer contribution in accordance with Regulations 25.1 of these Regulations
Provided further that the Licensee shall obtain the Commission's prior approval for drawal of Contingency Reserve by submitting the necessary justification for the drawal of Contingency Reserve along with documentary evidence.
..."
AEML SEEPZ and AEML requested that the Regulations may also include a proviso whereby licensees may be allowed to present proposal for bridging a portion of their revenue gap by drawing upon contingency reserves, in their ARR and true-up petitions, with adequate justification and in circumstances where a majority of such revenue gap has been created as a result of force majeure events. This is necessary to allow flexibility to the licensees as well as Commission to absorb whole part of tariff shock to consumers on account of arising past revenue gaps from force majeure events.
MSETCL submitted that, Explanatory Memorandum did not provide any particular rationale for departing from existing established practice of post facto approval for distribution licensee. MSETCL requested that, MSETCL may be allowed to first utilize reserve for restoration of services, or any other purpose as defined/ allowed in regulations under intimation to the Commission.
GEPL, KRCIPPL, MBPPL, and NUPLLP requested to drawl of contribution to contingency reserves to be allowed on post-facto approval basis considering the emergency of the situation.
MSEDCL submitted that contribution to contingency reserves equal to 0.5% of GFA shall be continued as it will generate enough funds with the utility to use during contingency situation. MSEDCL also submitted that, Contingency reserve is to be utilised on account of loss created due to force majeure conditions and any other conditions which were beyond the control of Licensee. The Utility may be allowed to first utilise the reserve for restoration of services and then approach the Commission for approval. So, it is requested the provision for post facto approval of utilisation of Contingency Reserve may be retained in the Regulations.
The condition for the prior approval was added to understand in advance the quantum of the amount to be funded through Contingency Reserves and undertake Financial Prudence before actual expenditure.
However, considering the submissions of the utilities and since the Commission is discontinuing with MTR process (except distribution business), it would be appropriate to allow the licensee to use the contingency reserves to raise the funds in case of contingency requirements and approach the Commission for post-facto approval. Accordingly, it is proposed to revise the draft regulations in line with the MYT Regulations, 2019.
Further, with regards to utilisation of contingency reserves for meeting the revenue gap on account of force majeure events, the Commission clarifies that, the purpose of contingency reserve is very clear. The purpose of contingency reserves is not to bridge the revenue gap but to meet the contingency requirement. In case of utilisation of funds from contingency reserves, the Commission shall ensure that, the contingency fund will be replenished in future to meet the future contingency requirement.
The changes in Regulation 35.2 are as follows:
“35.2.....
Provided further that the Licensee shall obtain the Commission's post facto approval for drawal of Contingency Reserve by submitting the necessary justification for the drawal of Contingency Reserve along with documentary evidence.”
“23.10 The revenue earned from sale of infirm power prior to the COD in excess of fuel cost as specified under Regulation 44, shall be adjusted against the Capital Cost.”
MSPGCL requested to provide clarity regarding adjustment in capitalization on account of revenue or profit/loss during prior to COD. MSPGCL also requested to retain the provision regarding “Input price for supply of coal from integrated mine prior to date of COD”.
The Commission notes the submission of MSPGCL. The provision of the Regulation 23.10 is clear. The revenue earned from sale of infirm power prior to the COD in excess of fuel cost, shall be adjusted against the Capital Cost while determining the capital cost at the time of COD. Further the proposed provision is in line with the CERC MYT Regulation 2024. With regards to MSPGCL’s submission to retain the provision regarding “Input price for supply of coal from integrated mine prior to date of COD, the Commission has noted the submission of MSPGCL and retained the provision regarding Input Price for Coal prior to the COD as provided in Regulation 24.12 below.
The revised provision of the Regulation 24.12 of MERC MYT Regulations, 2024 is as below:
The input price for supply of coal or lignite from the integrated mine(s) prior to their date of commercial operation shall be:
Provided that any revenue earned from supply of coal or lignite prior to the date of commercial operation of the integrated mine(s) shall be applied in adjusting the capital cost of the said integrated mine(s).
“38.5 The Generating Company shall file the Petition for determination of provisional Tariff for new Generating Station, at least six months prior to the anticipated date of commercial operation of Generating Unit or Stage or Generating Station as a whole, as the case may be.”
“38.6 The Generating Company shall file a Petition for determination of provisional Tariff for new Generating Station based on capital expenditure incurred and projected to be incurred up to the date of commercial operation and additional capital expenditure incurred, duly certified by the statutory auditors:
Provided that the Petition shall contain details of underlying assumptions for the projected capital cost and additional capital cost, wherever applicable.”
MSPGCL appreciated this Regulation of filling of petition for provisional tariff. MSPGCL submitted that, the timeline for submission of petition for provisional tariff changed from 2 months (as per MYT Regulations 2019) to 6 months prior to COD.
MSEDCL requested to maintain the existing timeline, it is submitted that six-month period is extensive, and various issues may arise that can delay the anticipated Commissioning date. MSEDCL also submitted that, the difference between the provisional / interim tariff and final tariff shall not exceed more than 10% and such additional cost may not be allowed as a pass through.
The Commission has reviewed the comments/suggestions received from stakeholders. The Commission notes the submission of MSEDCL that six-month period is extensive, and various issues may arise that can delay the anticipated Commissioning date. Further, it is also noted that the CERC in its final MYT Regulations has removed such provision related to filing of the provisional tariff before the anticipated COD. Hence, the Commission retain the two months period similar to MERC MYT Regulations 2019.
The revised proviso is as under:
“39.5 The Generating Company shall file the Petition for determination of provisional Tariff for new Generating Station, at least two months prior to the anticipated date of commercial operation of Generating Unit or Stage or Generating Station as a whole, as the case may be.”
“39.6 The Generating Company shall file a Petition for determination of provisional Tariff for new Generating Station based on capital expenditure incurred and projected to be incurred up to the date of commercial operation and additional capital expenditure incurred, duly certified by the statutory auditors:
Provided that the Petition shall contain details of underlying assumptions for the projected capital cost and additional capital cost, wherever applicable
“39.1 The Generating Company shall prepare and submit Fuel Utilisation Plan for the Control Period commencing on April 1, 2025, along with the Petition for determination of Tariff for the Control Period from April 1, 2025 to March 31, 2030, in accordance with Part A of these Regulations, to the Commission for approval.”
“39.6 A Generating Company shall maintain data of actual performance of Unit/Station wise Fuel Utilisation vis-à-vis Fuel Utilisation plan approved by the Commission, along with justification for variation between approved and actual fuel utilisation plan and, shall put up such data within fifteen days from the end of each month, on the internet website of the Generating Company.”
MSPGCL requested to allow any deviation from Fuel Utilisation Plan (FUP) during its execution and no penalty should be charged.
Prayash Energy Group requested to disallow 1% of the variable charge as a penalty in the absence of regular monthly publication of actual performance vis-à-vis the FUP on the generator's website as required by draft Regulation 39.6. Also submitted that review of actual fuel utilisation performance and provide directives to generators towards improved power procurement and utilisation.
AEML submitted that this regulation may exempt Generating companies which have a single generating station using a particular fuel for power generation.
MSEDCL submitted that the responsibility for fuel management and ensuring fuel availability lies with the generating company. However, there may be instances where fuel availability is limited due to shortages on certain days of the month. In such cases, fixed charges should not be calculated based on the actual availability. So, MSEDCL requested to provide clear guideline for addressing such situations to prevent disputes from arising in the Future.
The Commission has introduced this Regulation in MERC MYT Regulations, 2019 considering that a long-term Station-wise generation plan, and a plan for sourcing the required quantum of different fuels, with the intent that uncertainties of fuel can be deal in a planned manner, which will optimise/minimise the variable cost of generation and benefit the consumers. The Commission expects that generation companies should prepare FUP at the time of MYT Petition and adhere with the plan during implementation to minimise the deviation.
Regarding penalty in the absence of regular monthly publication of actual performance vis-à-vis the FUP on the generator's website, the Commission has already added the disincentive provision to Regulation 5.2 of the MERC MYT Regulations 2024 against the non-adherence of the directives of the Commission. The Commission may appropriately consider implementing the provision of Regulation 5.2 upon following the due Regulatory process.
No changes in provision of draft MERC MYT Regulations, 2024.
"42.1 For undertaking Renovation and Modernisation for the purpose of extension of life beyond the useful life of the Generating Station or a Unit thereof, the Generating Company shall file a Petition for approval with a Detailed Project Report giving complete scope, justification, cost-benefit analysis, estimated life extension from a reference date, financial package, phasing of expenditure, schedule of completion, reference price level, estimated completion cost, record of consultation with Beneficiaries and any other relevant information. ...."
MSEDCL submitted that any capital investment initiated by the generating company for renovation and modernization (R&M), or any other purposes is being passed through to the distribution licensee and, consequently, to the consumers. Therefore, the generating company needs to undertake any capital expenditure at an optimal cost level. The Generating company is required to take approval of the beneficiary for R&M work.
The Generating Company intending to undertake Renovation & Modernisation, tied up its capacity with the Distribution Licensee. The proposed Renovation & Modernisation will affect the quantum of supply as well as cost of procurement of power for the Distribution Licensee. Further there may be long duration shutdown during the R&M activities. The Commission
finds merit in the submission of distribution licensee that the consent from the Distribution Licensee should be obtained for undertaking Renovation & Modernisation activities. The Commission also notes that, the CERC also has the similar proviso in its MYT Regulation 2024. Accordingly, the Commission is revising the Regulation as below:
The revised Regulation 43.1 is as below:
43.1 For undertaking Renovation and Modernisation for the purpose of extension of life beyond the useful life of the Generating Station or a Unit thereof, the Generating Company shall file a Petition for approval with a Detailed Project Report giving complete scope, justification, cost-benefit analysis, estimated life extension from a reference date, financial package, phasing of expenditure, schedule of completion, reference price level, estimated completion cost, and any other relevant information.
Provided further that, the generating company intending to undertake renovation and modernization (R&M) shall be required to obtain the consent of the beneficiary Licensees, for such R&M and submit the same along with the Petition.
Provided that the generating company opting for Renovation and Modernization (R&M) shall not be eligible for Special Allowance under Regulation 44 of these Regulations;
... ”
“43.1 In the case of coal-based/lignite fired thermal, and Hydro generating stations who have completed the useful life may opt to avail of a 'special allowance' in accordance with the norms specified in this Regulation, as compensation for meeting the requirement of expenses towards additional capital expenditure as per MERC (Approval of Capital Investment Schemes) Regulations, 2022, including capital expenditure arising out of change in law, award of arbitration or for compliance of the directions or order of any statutory authority, or order or decree of any court of law, and force majeure.
...
43.3 The Generating Company shall submit the details of all work to be undertaken through special allowance, with the MYT petition, for the approval of the Commission, which shall be granted after prudence check of reasonableness of the cost estimates, cost-benefit analysis, and such other factors as may be considered relevant by the Commission.
Provided that, the Special Allowance admissible to a generating station shall be maximum upto INR 10.75 lakh per MW per year for the control period. -----
MSPGCL submitted that, in the CERC Tariff Regulation 2024, has excluded capitalisation arising out of change in law, award of arbitration or for compliance of the directions or order of any statutory authority, or order or decree of any court of law, and force majeure, while allowing special allowance. MSPGCL requested to keep additional expenditure of similar nature outside the special allowance.
MSPGCL submitted that the proposed provision of special allowance, i.e., Rs. 10.75 Lakhs per MW per year, in the draft Regulations is justified in line with CERC Tariff Regulations 2024. MSPGCL suggested that the special allowance should have a yearly escalation to address inflation. Thus, Rs. 10.75 Lakhs per MW per year could be determined for the 1st year of the control period, with subsequent yearly escalations.
AEML submitted that first proviso of Regulation 43.5 should be removed. At the end of the Control Period, actual utilisation of funds can be assessed and any remaining un-utilised balance at the end of the Control Period could accordingly lapse. This will allow flexibility to the generating company to utilise the funds throughout the control period and will also take care of higher or lower utilisation in individual years due to a variety of uncontrollable reasons.
MSEDCL suggested that the Special Allowance norm shall be retained at Rs. 9.5 lakh per MW per year.
Tata Power requested to incorporate similar Regulations 43.1 in case of Gas Turbine Generating Stations in the MERC MYT Regulations, 2024.
Special Allowance of INR 10.75 lakh per MW per year is proposed in the draft Regulation 2024, which is in line with the Draft CERC MYT Regulations 2024 and by escalating the specifically proposed in the draft MYT Regulations 2011. The Special allowance is expected to cover all the activities which are considered under R&M by generating companies completed useful life of 25 years. Therefore, the capital expenditure arising out of change in law, award of arbitration or for compliance of the directions or order of any statutory authority, or order or decree of any court of law, and force majeure, are expected to be included in Special Allowance of INR 10.75 lakh per MW per year.
The Commission also notes that the CERC has not considered any yearly escalation to the Special Allowance to address inflation. The special allowance is optional and generating company is free to plan for R& M in lieu of special allowance.
The Commission finds merit in the submission that the Gas Turbine Generating Stations may also be allowed Special Allowances. Hence the Special Allowance regulation is modified to include the Gas Turbine Generating Stations.
As regards to treatment to unutilised fund at the end of the year, (proviso of Regulation 43.5), the Commission has considered the stakeholders suggestions to allow carry forward of unutilised funds till the end of the control period. This would provide the Generating Companies flexibility to utilise the funds throughout the control period for larger activities of R&M in a planned manner.
The revised Regulation 44.1 is as under:
“44.1 In the case of coal-based/lignite fired thermal, Gas based power plants, and Hydro generating stations who have completed the useful life as specified in these Regulations may opt to avail of a 'special allowance' in accordance with the norms specified in this Regulation, as compensation for meeting the requirement of expenses towards additional capital expenditure as per MERC (Approval of Capital Investment Schemes) Regulations, 2022, including capital expenditure arising out of change in law, award of arbitration or for compliance of the directions or order of any statutory authority, or order or decree of any court of law, and force majeure.
...
44.3 The Generating Company shall submit the details of all work to be undertaken through special allowance, with the MYT petition, for the approval of the Commission, which shall be granted after prudence check of reasonableness of the cost estimates, cost-benefit analysis, and such other factors as may be considered relevant by the Commission.
Provided that, the Special Allowance admissible to a generating station shall be maximum upto INR 10.75 lakh per MW per year for the control period.
Provided also that, the Generating Company opting for special allowance shall not be allowed to capitalise the assets created through special allowance and shall not be eligible for Depreciation, Return of Equity, Interest on Loan on such assets created through special allowance:
Provided also that no additional capitalization shall be admissible under MERC Capex Regulations, 2022 once the special allowance is claimed and utilised by the Generating Company subject to prudence check by the Commission.
44.4 In the event of a generating station availing of Special Allowance, the expenditure incurred upon or utilized from special allowance shall be maintained separately in the separate fund by the generating station and the expenditure incurred or utilized from the special allowance shall be made available to the Commission as and when directed.
Provided that special allowance allowed in the MYT Order shall be trued up at the end of Control Period and unutilized special allowance shall be adjusted in the ARR with the holding cost, if any. ”
45.2 The Non-Tariff Income shall include:
.....
Provided that the interest earned from investments made out of Return on Equity corresponding to the regulated Business of the Generating Company shall not be included in Non-Tariff Income: -----
MSPGCL requested to revise the provision for Non-Tariff Income as per CERC Tariff Regulation 2024 wherein the non-tariff net income in case of generating station and transmission system from rent of land or buildings, sale of scrap and advertisements shall be shared between the beneficiaries or the long-term customers and the generating company or the transmission licensee, as the case may be, in the ratio 50:50.”
The Commission is of the view that Non-Tariff Income generated by the Regulatory utility is by using the assets which are created from the regulatory tariff framework. The consumers are funding these assets through tariff framework, so any income generated from these assets are expected to be utilised for reduction in the tariff to be paid by the consumers. It would not be appropriate to share only 50% of income with consumers and retain 50% by the Utility.
No changes in provision of draft MERC MYT Regulations, 2024.
“46.1 Target Availability for full recovery of Annual Fixed Charges shall be 85 per cent for all thermal Generating Stations, except those covered under Regulation 46.2”
“46.2 Target Availability for full recovery of Annual Fixed Charges for the following Generating Stations of Maharashtra State Power Generation Company Ltd. (MSPGCL) shall be:
| Particulars | Target Availability (%) |
|---|---|
| Koradi TPS excluding Unit No. 8, 9 and 10 | 75.00 |
| Chandrapur TPS excluding Unit No. 8 and 9 | 80.00 |
Provided that the Commission may revise the Availability norms for these Generating Stations in case any Renovation & Modernisation is undertaken or these plants/Unit avails for the Special Allowance”.
MSPGCL submitted that target availability of Nashik and Bhusawal unit to be retained at 80% and not to be increased as proposed in draft Regulations.
Further, requested to revise the target availability of Chandrapur Unit 3 to 7 and Khaparkheda Unit 1 to 4 to 75%.
AEML requested to align the provisions for PAF and PLF as per the CERC MYT Regulations, 2024.
Graduate Engineer's Association, Union of Chemist, Shri Krushna Bhoyar and Maharashtra Rajya Magasvargiya Vidyut Karmachari Union have requested that the target availability of the old generating stations/units (Nashik Unit No. 3 to 5, Bhusawal Unit 3, 4, & 5, Chandrapur Unit 3 to 7, and Khaparkheda Unit 1 to 4), which have completed useful life of 25 years, should not be increased and kept as per MYT Regulations of 2019.
Tata Power suggested to include additional proviso as per CERC Tariff Regulation, 2024 to address the treatment of NAPAf for generating stations that have completed 30 years of Operation as on March 31, 2024 to ensure consistency and fairness in the treatment of NAPAf for aging generating units.
The Commission had proposed the norms for Availability for existing Generating Stations based on actual performance for past period and the same was detailed in the Explanatory Memorandum.
MSPGCL has submitted the CPRI reports for some of the TPS and requested for relaxation in the performance norms. However, based on the data received from MSPGCL, it is noted that, actual availability of Bhusawal TPS for FY 2019-20 and FY 2020-21 is more than 90% and for Nashik TPS the actual availability for FY 2020-21 is more than 95% and in FY 2021-22 it is 84.44%.
For Khaparkheda Unit 1 to 4, CPRI Report, recommends Availability as 73.75% for Unit 1 and 2, while 79.75% for Unit 3 and 4. But Khaparkheda Unit 1 to 4, actual availability for FY 2022-23 and FY 2023-24(H1) is more than 92%. It is observed that actual performance has improved in past years. CPRI report provides unit wise performance parameters whereas it is observed that, Khaparkheda Unit 1 to 4 combinedly meeting the operational norms requirement. Further, variation in actual and normative performance shall be treated under sharing of gains and losses mechanism. Hence, the Commission is not inclined to provide any relaxation for these stations and norms proposed in the draft MERC MYT Regulations 2024 are retained in the final Regulations.
As regards inclusion of additional proviso as per CERC Tariff Regulation, 2024 to address the treatment of NAPAf for generating stations that have completed 30 years of Operation as on March 31, 2024, the Commission is of the view that already relaxed norms are considered based on actual performance for generating stations having life more than 25 years. Hence, the Commission has not considered the submission Tata power for inclusion of proposed proviso.
No changes in provision of draft MERC MYT Regulations, 2024.
“46.4 Gross Station Heat Rate for existing coal-based thermal Generating Stations, other than those covered under Regulation 46.5 and 46.6 shall be:”
| 200/210/250 MW set | 300 MW sets | 500 MW set (Sub-critical boilers) | 600 MW and above sets (Super-critical boilers) |
|---|---|---|---|
| 2400 kcal/kWh | 2385 kcal/kWh | 2375 kcal/kWh | 2230 kcal/kWh |
46.7 Gross Station Heat Rate for existing Gas Turbine/Combined Cycle Generating Station/Unit shall be:
| Mode of Operation | Uran GTPS of MSPGCL (kcal/kWh) | Unit-7 of TPC-G (kcal/kWh) |
|---|---|---|
| Combined Cycle | 2035 | 2035 |
| Open Cycle | 2900 | 2900 |
MSPGCL submitted that its most of the generating station sets of 250 MW are designed by around 2000-2001 with equipment orders placed in 2004 and the units were commissioned between 2007 to 2010. Thus, it will not be prudent to expect improvement in SHR for such old units. Therefore, proposing an enhancement in the SHR of these old units is unwarranted. Further, MSPGCL also submitted that Section 61 (d) of Electricity Act 2003 provides for safeguarding of consumer’s interest while at the same time, recovery of cost of electricity in the reasonable manner. Therefore, to get appropriate recovery, MSPGCL has requested to retain the existing norm of SHR of 2430 kcal/kWh for sets of 200/210/250 MW.
AEML requested to align the norm as per CERC Tariff regulation, 2024 at 2415 kcal/kwh for 200/210/250 MW set.
Tata Power requested to consider the GSHR for FY 2019-20 to FY 2023-24 to get more accurate picture. It is submitted that the five-year average SHR for its Unit-5 comes to 2569 kcal/kWh, which is higher than present normative GHR of 2549 kcal/kWh due to reduction in PLF and higher losses at low load operation.
MSEDCL requested to set the Norms for SHR to lower level rather than continuing with the same norms as notified in past. The operational norms should be progressive in nature and should be revised from time to time.
As Regards to GSHR for new Coal and Lignite based thermal power Generating Stations /Units achieving COD after April 01, 2025, MSPGCL requested to retain existing GSHR calculation factor of 1.05. This is crucial as these provisions are formulated based on the guideline provided by CERC. The factor is provided to cover the fluctuations in load ability on account of reasons like seasonal variations, demand variations, local operating conditions etc. There is no specific reason for the proposed reduction in factor from 1.05 to 1.04 in case of units having capacity 500 MW or more. On the contrary, in coming period with increase in RE penetration, there will be more variations in load ability resulting in further variations in actual SHR. Further, Tata Power requested to consider 5-Year average GHR for Unit-7 for the period FY 2019-20 to FY 2023-24 comes to 2079 kcal/kWh which is much higher than present normative GHR of 2,035 kcal/kWh due to reduction in PLF and higher losses at low load operation.
The Commission had proposed the norms for SHR for existing Generating Stations based on actual performance for past period and the same has been detailed in the Explanatory Memorandum. Average SHR over 5 year (FY 2018-19 to FY 2022-23) for 200/210/250 MW Set is around ~2419 kCal/kg, which is very close to SHR of 2415 kCal/kg for 200/210/250 MW Set allowed by the CERC Tariff Regulation, 2024.
Further, in MERC MYT Regulation 2019, for 200/210/250 MW Set, norms were aligned with CERC Tariff Regulations 2019. Hence, SHR of 200/210/250 MW Set is revised to 2415 kcal/kg in line with the CERC Tariff Regulations 2024. As regards Unit 5 and Unit 7 of TPC, the SHR norms are already relaxed, and the actuals are near to the norms. Hence, no change is proposed in the draft MERC MYT Regulations 2024 for these units..
Also, the Commission approves the additional capital expenditure for each project after taking into account the factors such as vintage, size, past generating history, past maintenance practices, condition of plant, etc. Also, the present MYT framework allows sharing of loss on account of norms of operation, unlike the CERC. Hence, it would not be appropriate to further relax the operational norms as requested by the Gencos. GSHR for new Coal and Lignite based thermal power Generating Stations /Units were always aligned with the CERC Tariff Regulations, 2024. Hence, based on CERC Tariff Regulation 2024, norms for 500 MW set revised from 1.04 of design heat rate to 1.045 of design heat rate.
The revised provisions of the SHR for existing coal-based thermal Generating Stations are as follows:
“47.4 Gross Station Heat Rate for existing coal-based thermal Generating Stations, other than those covered under Regulation 47.5 and 47.6 shall be:”
| 200/210/250 MW set | 300 MW sets | 500 MW set (Sub-critical boilers) | 600 MW and above sets (Super-critical boilers) |
|---|---|---|---|
| 2415 kcal/kWh | 2385 kcal/kWh | 2375 kcal/kWh | 2230 kcal/kWh |
...
47.8 Gross Station Heat Rate for New Coal and Lignite based thermal power Generating Stations /Units achieving COD after April 1, 2025 shall be equal to:
For 200/210/250 MW Sets: 1.05 X Design Heat Rate (kcal/kWh)
For 500 MW Sets and above: 1.045 X Design Heat Rate (kcal/kWh)
Where the Design Heat Rate of a Unit means the Unit Heat Rate guaranteed by the supplier at conditions of 100% MCR, zero percent make up, design coal and design cooling water temperature/back pressure:
.....”
MSPGCL submitted that for Chandrapur Unit 3 to 7, the norm during MYT 3rd Control period was 2.00 ml/kWh, however, in the current 4th MYT Control Period it was reduced to 1.00 ml/kWh. MSPGCL submitted that the average of last 10 Years SFOC for Chandrapur Unit 3 to 7 was 1.76 ml/kWh, hence requested to provide SFOC norm of 1.7 ml/kWh for Chandrapur Unit 3 to 7.
MSEDCL submitted recommendations of CPRI 2012 report for improving the performance of old generating Stations. It means, after nearly 12 years of the receipt of report, MSPGCL is unable to improve its operational performance. So, cost towards higher consumption of secondary oil due to lack of operational efficiency shall be disallowed.
The Commission had proposed the SFOC norms for existing Generating Stations based on actual performance for past period and the same has been detailed in the Explanatory Memorandum. For the new Stations, the SFOC norms have been retained at 0.5 ml/kWh, as specified in the MYT Regulations, 2019. The norms specified for MSPGCL’s Generating Stations are already relaxed norms and any further relaxation is not justifiable. In view of this, the Commission has retained the norms proposed in the draft MYT Regulations.
No changes in provision of draft MERC MYT Regulations, 2024.
“46.14 Auxiliary Energy Consumption for the following coal-based thermal Generating Stations of MSPGCL shall be as given in the Table below:
| Stations | Auxiliary Energy Consumption |
|---|---|
| Koradi TPS excluding Unit No. 8, 9 and 10 | 10.81% |
| Khaparkheda TPS excluding Unit No. 5 | 9.70% |
| Chandrapur TPS excluding Unit No. 8 and 9 | 7.80% |
| Nashik TPS | 10.75% |
| Bhusawal TPS excluding Unit No. 4 and 5 | 10.96% |
Provided that the Commission may revise the auxiliary energy consumption norms for these Generating Stations in case any Renovation & Modernisation is undertaken or avail for the Special Allowance.
46.15 Auxiliary Energy Consumption for other existing coal-based thermal Generating Stations shall be as given in the Table below:
| Particulars | With Natural Draft cooling tower or without cooling tower |
|---|---|
| (i) 200/250 MW Series | 8.50% |
| (ii) 300/350 MW & above | |
| Steam driven boiler feed pumps | 6.00% |
| Electrically driven boiler feed pump | 8.50% |
Provided that for thermal Generating Stations with induced draft cooling towers and where tube type coal mill is used, the norms shall be further increased by 0.5% and 0.8%, respectively:
46.16 Auxiliary Energy Consumption for Gas Turbine/Combined Cycle Generating Stations/Units shall be:
(a) Combined cycle : 2.75%
(b) Open cycle : 1.00%
Provided that where the gas based generating station is using electric motor driven Gas Booster Compressor, the Auxiliary Energy Consumption in case of Combined Cycle mode shall be 3.30% (including impact of air-cooled condensers for Steam Turbine Generators);
Provided further that an additional Auxiliary Energy Consumption of 0.35% shall be allowed for Combined Cycle Generating Stations having direct cooling air cooled condensers with mechanical draft fans;-----”
MSPGCL requested to increase the auxiliary consumption norm for Chandrapur Units # (3 to 7) to 9.5% for Paras Units # 3&4 and Parli Units # 6&7 to 10.25%. MSPGCL has also submitted CPRI data for Parli Unit (6,7 and 8), Paras Unit (3 and 4), Khaparkheda Unit (1,2,3 and 4) and Chandrapur Unit (3,4,5,6 and 7) and requested the Commission to consider the same while determining the norms for these Units.
MSEDCL has submitted that MSPGCL is unable to improve its operational performance as per the recommendations of CPRI 2012 report even after nearly 12 years of the report. So, cost towards higher auxiliary consumption due to lack of operational efficiency shall be disallowed and it is requested to revise the auxiliary consumption norms for MSPGCL plants. Further, MSEDCL requested to revise the normative auxiliary consumption based on the actual past performance of the gas bases stations.
AEML suggested that auxiliary consumption norms for FGD for power plants like AEML's ADTPS shall be allowed on actual basis, as against a normative percentage. Without prejudice, it is submitted that in any case, the Aux consumption norm for sea water based FGD system with Gas-to-Gas heater should not be less than 1.3% in MYT Regulations, 2024.
Tata Power requested to include new proviso under Regulation 46.16 of the Draft MERC MYT Regulations for Cooling water pump auxiliary consumption or approve the auxiliary consumption of TPC Unit-7 in combined cycle mode as 3.45% including Cooling water pump auxiliary consumption.
The Commission in its Explanatory Memorandum to Draft MYT Regulations 2024 has clarified that, the norms for Auxiliary consumption proposed for old Generating Stations to encourage the efficiency measures to be taken by plants for reduction in the Auxiliary Consumption.
The Commission noted that, MSPGCL has submitted CPRI data for Parli Unit (6,7 and 8), Paras Unit (3 and 4), Khaparkheda Unit (1,2,3 and 4) and Chandrapur Unit (3,4,5,6 and 7). CPRI has recommended higher Auxiliary consumptions norms for generating stations like Parli Unit (6,7 and 8), Paras Unit (3 and 4), which have not completed their useful life.
The Commission is of the view that, during the useful life period where generators are receiving O&M expenses as per the normative parameters and further adjustment through sharing of gains and losses, generators are expected to perform within the technical parameters considered at the time of project planning. The Commission also notes that, CPRI has recommended some technical measures to improve Aux. consumption. MSPGCL is expected to implement the recommendations of CPRI urgently.
Further, Auxiliary consumption norms considered by the Commission are in line with the CERC Tariff Regulation, 2024. Accordingly, the Commission is not inclined to revise the norms for Parli Unit (6,7 and 8) and Paras Unit (3 and 4) as proposed in the draft MERC MYT regulations 2024.
Further the CPRI has recommended norms for Chandrapur Unit (3 to 7) in the range of 8.67% to 10.51%. The Commission notes that, CPRI has recommended auxiliary consumption norm of 8.67% to Chandrapur TPS Unit 6. If all the units of Chandrapur (3 to 7) are having COD in similar period and vintage life of these units is similar, operational performance of all these units is expected in the similar range. If Unit 6 can achieve the auxiliary consumption norm of 8.67%, then other Units are also expected to perform similarly. Accordingly, the Commission has considered Aux. consumption of 8.67% as proposed by CPRI for Chandrapur Unit 6 and
revised the auxiliary consumption norm for Chandrapur Unit (3 to 7) to 8.67% from existing 7.8%.
Further, the CPRI recommended norms for Khaparkhedha Unit (1 to 4) are already near to the norms considered by the Commission in draft MERC MYT Regulations, 2024. Hence, no revision in norms for Khaparkhedha Unit (1 to 4) has been considered.
The Commission also notes that, the CPRI report provides variation in Aux consumption based on the loading of plant, however the Commission has already specified the framework under Electricity Grid Code, 2020 for compensating for variation in SHR and Aux consumption with reduction in plant loading up to technical minimum of 55%. This framework would address the concern of variation in plant loading raised by CPRI. Further actual performance norms shall be treated under the sharing of gains and losses and 1/3 of the loss will be passed on to the consumers through the tariff.
Further, TPC-G in its submission substantiated the impact of sea water cooling system on auxiliary consumption. The Commission notes that, additional 0.3% of auxiliary consumption is allowed for combined cycle inline with the Commission MYT Order for 4th Control Period. Extract of the same is as under:
"...the Commission is not inclined to relax the norms towards Auxiliary consumption of Unit 7 and approves Auxiliary consumption of 2.75% for Unit 7 for 4th Control Period. However, considering the historical actual auxiliary consumption of Unit 7 and considering the dispensation mentioned in the Statement of Reasons for the CERC (Terms and Conditions of Tariff) Regulations, 2019 for coastal plants as pointed out by TPC-G, the Commission may consider to allow the actual auxiliary consumption, if it is higher than normative value of 2.75%, at the time of truing up, subject to ceiling of auxiliary consumption of 3%, if TPC-G proves the impact of sea water cooling system on the Unit 7 Auxiliary consumption with necessary details at the time of truing up."
The Commission is of the view that, the above provisions would take care of the issues raised by Tata Power.
Accordingly the Regulation 47 is revised in the final MERC MYT regulations 2024.
"46.20 Transit and handling Losses
Normative transit and handling losses for coal/lignite based Generating Stations, as a percentage of quantity of coal or lignite dispatched by the coal/lignite supply company during the month shall be:
(a) Pit head Generating Stations: 0.2%
(b) Non-pit head Generating Stations: 0.8%
...."
MSEDCL requested to revise the norms for Transit loss for MSPGCL plants based on the actual past performance of these stations. It is unfair to pass on additional cost even though the performance has improved. AEML suggested that normative transit loss of 0.8% in case imported coal transportation which also involves rail transport from port of arrival upto the power plant.
The Commission in its Explanatory Memorandum has discussed in details of the proposed norms for Transit losses for the Generating Stations. The Commission notes that, the average Transit losses of MSPGCL for the last 5 years (FY 2018-19 to FY 2022-23) is lower than the Transit losses norm of 0.8 % specified by the Commission except for Khaparkheda Unit 1 to 5. With regards to AEML's submission for normative transit loss of 0.8% in case of imported Coal, the Commission has specified 0.2% transit loss similar to Pit head plants which is also in line with the norms specified by the CERC. Accordingly, the Commission has retained the existing norms, which are in line with the CERC Tariff Regulations, 2024.
No changes in provision of draft MERC MYT Regulations, 2024.
“47.1 Generating Stations/Units that achieved COD before August 26, 2005
(a) The Operation and Maintenance expenses for Generating Stations which achieved COD before the date of coming into effect of the MERC (Terms and Conditions of Tariff) Regulations, 2005, shall be computed in accordance with this Regulation
b) The Operation and Maintenance expenses excluding water charges and including insurance shall be derived on the basis of the average of the Trued-up Operation and Maintenance expenses after adding/deducting the share of efficiency gains/losses, for the five Years ending March 31, 2024, excluding abnormal Operation and Maintenance expenses, if any, subject to prudence check by the Commission:
.....
h) If the Generating Station or Unit opts for Special Allowance as per the provisions of the Regulation 43 of these Regulations, the applicable O&M norms for such Generating Station/Unit shall be as per the provisions of the Regulation 47.2 below of these Regulations for the respective category and type of the Generator.”
MSPGCL requested to allow O&M costs in the segregated manner, with employee costs approved at actuals, subject to prudence check, and the (A&G + R&M) component allowed at the normative level. It has submitted that, there is needs of review of the ratio and considering the factual contribution of (employee + labour) costs in total O&M costs, the weightage for CPI to be increased to 70% with balance weightage for WPI, while computing the escalation factor for O & M costs. Further it is requested to allow the Security Expenses separately from O & M expenses at actual, subject to prudence check, in line with the CERC MYT Regulations, 2024. It is submitted that, the CERC Tariff Regulations, 2024 allows procurement of capital spares to generating companies on actual basis during truing up process on year-on-year basis over and above normative O & M. It is requested to include the similar provisions in MERC MYT Regulations, 2024.
MSPGCL and Tata Power requested to revise the methodology of computation of normative O&M expenses for the base year to reflect the realistic expenses without considering adding/deducting sharing of gain/losses and while determining norms average of past years. It is submitted that special allowance is for the major R&M work of the plant due to ageing of the plant or unit. Hence, it is not justified that norms of new generating stations to be made applicable for units opt for special allowance. Further, it is requested to take into consideration the costs for STP water from neighbouring Municipal Corporations along with incidental costs for such arrangements while approving the water charges for the station. Unless these O & M costs are considered separately under Water charges, it will be difficult for MSPGCL to carry out O&M of STPs within the normative O&M expenses. MSPGCL also submitted that while comparing YoY norms for FY 2024-25 as per existing Regulations and proposed norm for FY 2025-26 in draft MERC Regulation, the norm is reduced by 14.89%, 8.42% and 5.68% for three type of gas based generating station. It may be noted that the CERC has increased norm for FY 2024-25 by (-) 9.96%, 15.13% and 6.08% in final MYT Regulations. However, in draft Regulation the Commission has reduced the norm for Gas turbine/combined cycle and small gas turbine generating station.
Graduate Engineer's Association, MSPGCL and AEML requested to allow the claim of the impact of wage and pay revision at actuals during truing up. AEML suggested that a proviso may be added to clarify that in case no norms for specific water consumption has been specified for a generating station with a particular cooling technology, the water charges shall be allowed at actuals, subject to prudence check.
Tata Power submitted that the Commission has to remove efficiency factor of 1% considered for the reduction in O&M escalation. For New Generating Stations and Generating Stations that achieved COD on or after August 26, 2005, MSPGCL requested to consider the CERC norms for FY 2025-26 and subsequent year norms be fixed considering the escalation rate of 5.25% as per the CERC Regulations 2024.
Shri Krushna Bhojar and Union of Chemist submitted that, O&M Expenses allowed for Coal based thermal power plants of units of capacity 250MW and 500MW is more however for those of units of 600MW capacity are less. It is requested to allow O&M Expenses for new units of 600MW capacity on the similar grounds to that of 250MW units and 500MW units.
The Operation and Maintenance expenses are considered as controllable expenses and subjected to sharing of gains and losses against it. As employee expenses are part of the O& M it cannot be treated as uncontrollable and allowed on actual basis. Employee cost forms significant portion of the O&M expenses and hence, there is no rationale for allowing employee expenses on the basis of actual and the balance R&M expenses and A&G expenses on normative basis. Accordingly, the Commission has retained the weightage of WPI/CPI in 50:50 ratio for computation of escalation factor similar to MERC MYT Regulations, 2019.
Further it is clarified that while computing the O& M norms the Commission has considered the Wage and pay revision impact of the past period allowed by the Commission and escalated while computing the normative O&M expenses for FY 2025-26 to FY 2029-30. Hence, wage revision, if any, during the Control Period, shall be treated as part of employee expense and controllable parameter and accordingly shall be treated under sharing of gains and losses.
Regarding allowing of the Security Expenses separately from O& M expenses, the Commission is of the view that while determining the norms for the Control Period it has considered the trued-up O&M expenses for five year which also includes the Security expenses. Hence, the Commission finds no merit in the submission of the stakeholder.
As regards the capital spares, the Commission is of the view that it is allowing the special allowance and higher norms for the generating expenses in this MYT Regulation which can take care of any requirement of capital spares. Hence, the Commission is not inclined to add separate Regulations related to capital spares.
As regards consideration of sharing of gains and losses while computing base year average O&M expenses, the Commission is of the view that it is necessary to consider the sharing of gains and losses of O&M expenses so that efficiency improvements of the Control Period get reflected in the next Control Period norms.
The Commission also notes that MSPGCL has submitted Report of the Committee constituted by MSPGCL with experts of the CEA for evaluating the O&M Expenses of Koradi Thermal Power Station (KTPS) (3 X 660MW). The report mainly comments on the lower normative O &M approved by the MERC as compared to the CERC during 4th control period (2019-2024). The report also provides some recommendations to MSPGCL for controlling O&M Charges such as employee expenses need to be controlled as compared to other supercritical plants. Repair & Maintenance expenses need to be controlled by segregation the expenses under Capex and Opex. Though A&G expenses are less as compared to other plants, still there is scope for further reduction in A&G expenses. Adoption of best practices and deployment of recommendations by third party technical consultants would help to reduce the O&M expenses of these plants. The Commission expects that MSPGCL should implement these recommendations on priority to manage the O&M expenses.
Further, the Commission has allowed Special Allowance, which is optional for old generators which have completed useful life of 25 years. It is expected that, generating stations should select the requirement of special allowance appropriately to maintain or improve the
performance parameters of the generator. It is expected that once the generator avails the special allowance it will not be entitled for relaxation in the performance norms.
Further, water charges are allowed at actuals over and above normative O&M expenses. The Stakeholders have to substantiate their claim during the Truing up.
For New Generating Stations and Generating Stations that achieved COD on or after August 26, 2005, the Commission has revised the escalation rate to 5.33% for the control period based on CPI:WPI (50:50) for FY 2023-24 with adjustment for efficiency factor of 1% in line with provisions of the MYT Regulations 2019. Further, Wage Revision impact has already been considered while determining the O&M norms.
Regulation 48 has been revised appropriately to address the comments of the stakeholders.
"47.3 The operation and maintenance expenses on account of Emission Control System in coal or lignite based thermal generating station shall be 2% of the admitted capital expenditure (excluding interest during construction) as on its date of commercial operation, which shall be escalated annually @3.71% during the Control Period ending on 31st March 2030
Provided that income generated from sale of gypsum or other by-products shall be reduced from the operation and maintenance expenses."
MSEDCL submitted that O&M on account of Emission Control System (ECS) shall be equal to 2% of the admitted capital cost (excluding IDC & IEDC) and further escalated by 3.71% p.a. till end of control period. MSEDCL submitted that, the rate and escalation can further be brought down. The escalation in O&M expenses can be lower for initial years and can be increased subject to a ceiling rate once 70% of the emission control system is depreciated.
Prayas Energy Group requested to allow ECS cost recovery based on compliance to environmental norms, which can be linked to Maharashtra State Pollution Control Board (MPCB) certification for adherence. Further, it is requested to ensure timely compliers are protected by excluding ECS expenses from consideration of MoD till the final deadline. Furthermore, it is requested to penalise non-compliance post the final deadline to avoid unfair advantage to non-compliers. Further, It is also requested to compute O&M expenses based on CAPEX (excluding IDC) of the ECS alone, Further the norms proposed in draft regulations should be the ceiling of O&M expenses towards ECS. Hence, O&M expenses based on the lower of actuals or norms proposed.
The escalation rates are considered in line with escalation rates considered for O&M expenses for thermal generating stations which are in line with the CERC Tariff Regulations, 2024. Accordingly, the Regulation 48.3 is revised to address the comments received from stakeholders.
Regarding penalty on the non-compliance related to ECS, the Commission has already added the disincentive provision to Regulation 5.2 of the MERC MYT Regulations 2024. Hence no change in provision of draft MERC MYT Regulations, 2024.
"48.3 The operation and maintenance expenses on account of Emission Control System in coal or lignite based thermal generating station shall be 2% of the admitted capital expenditure (excluding interest during construction) as on its date of commercial operation, which shall be escalated annually @4.33% during the Control Period ending on 31st March 2030.
Provided that income generated from sale of gypsum or other by-products shall be reduced from the operation and maintenance expenses."
"50.1 The fixed cost of a thermal generating station shall be computed on annual basis based on the norms specified under these Regulations and recovered on monthly basis under Capacity Charge. The total Capacity Charge payable for a generating station shall be shared by its beneficiaries as per their respective percentage share or allocation in the capacity of the generating station. The Capacity Charge shall be recovered under two segments of the year, i.e., High Demand Season (period of three months) and Low Demand Season (period of remaining nine months), and within each season in two parts, viz., Capacity Charge for Peak Hours of the month and Capacity Charge for Off-Peak Hours of the month as follows:
Capacity Charge for the Year (CCy) = Sum of Capacity Charge for three months of High Demand Season + Sum of Capacity Charge for nine months of Low Demand Season.
....."
MSPGCL requested to remove high/low demand categorization and recovery of capacity charges should be only based on peak and off-peak availability. Further, in case the Commission adopts the existing approach, to address the issue of balancing the overhaul requirement of stations, MSPGCL suggested to carry out segregation of available generating capacities in station-wise priority for High demand and low-demand season. MSPGCL Submitted that this approach would ensure that every station is not subjected to same high/low season simultaneously and enable stations to schedule overhauls without affecting the recovery of capacity charges.
Prayas Energy Group requested to reconsider availability-linked AFC recovery with the approach suggested in the table below and noted that the HIGH/LOW Demand season and peak/off-peak hours should be based on net load (i.e., after accounting for the must-run capacity such as solar and wind) rather than overall load. Further, Prayas Energy Group is also requested to consider varying PLF incentives across high/low demand season in addition to peak /off-peak hours based on net-load, as suggested in the table below.
| Peak Hours | Off-peak Hours | |
|---|---|---|
| High demand season | ~2.5X weightage per hour for AFC recovery* → Rs. 0.5/kWh PLF incentive |
~1.2X weightage per hour for AFC recovery* → Rs. 0.25/kWh PLF incentive |
| Low demand Season | ~1.2X weightage per hour for AFC recovery* → Rs. 0.25/kWh PLF incentive |
~0.8X weightage per hour for AFC recovery* → No PLF incentive |
*For example, if the high-demand season is defined as 3 months and each day is assumed to have 4 peak hours, then the four combinations of high-demand/peak, high-demand/off-peak, low-demand/peak and low-demand/off-peak would correspond to about 4%, 21%, 13% and 63% of the year, respectively. However, the AFC recovery for these periods as per the suggested approach would be about 10%, 25%, 15% and 50% respectively.
The Commission has continued with the provision of the MERC MYT Regulations, 2019, with the objective of ensuring availability of the Generators when they are needed by the Distribution Licensees. The Commission has separately proposed incentive for the higher PLF during peak demand under Regulation 51.11 of MERC MYT Regulations, 2024 for actual energy generated in excess of ex-bus energy corresponding to target Plant Load Factor during peak hours. Regarding suggestion to link the AFC with seasonal demand, the Commission is of the view that, before implementing such suggestion, analysis would be required to ensure that generators should not be penalised by part recovery of the AFC during variation in the seasonal demand. In the absence of this analysis the Commission has not inclined to link the AFC recovery with seasonal availability.
No changes in provision of draft MERC MYT Regulations, 2024.
50.5 .....
Energy Charges (INR) = (Energy Charge Rate in INR/kWh) x [Scheduled Energy (ex-bus) for the month in kWh]
(a) Actual loss in calorific value of coal between “as billed by supplier” and “as received at generating station”, subject to the maximum loss in calorific value of 650 kcal/kg; and
MSPGCL requested to adopt the "As Received" basis for GCV to ensure the actual recovery of fuel costs. MSPGCL submitted that the GERC in draft tariff Regulation 2023, and CERC MYT Regulation 2024, in calculation of ECR have allowed GCV on "As received" basis. Further, MSPGCL submitted that most of the SERCs are following the approach of GCV “As received” in line with CERC MYT Regulations and some of the SERCs even allowed actual GCV loss based on GCV “As fired”. This approach would also promote a level playing field in the competitive power sector. Failure to do so could worsen the financial condition of MSPGCL. Further it is suggested that stacking loss for non-pit head station to be retained as 120 kcal/kg as specified in existing MERC MYT Regulation 2019.
Prayash Energy Group requested to retain the allowable GCV loss of 300 kcal/kg between the loading and unloading point. Further, it is also requested to setup a committee to undertake an in-depth assessment of the causes for GCV loss between the loading and unloading points.
Union of Chemist and Shri Krushna Bhojar requested to considered "As received" GCV for Tariff determination. It is also requested to review the actual stacking loss of generating stations and accordingly determine the stacking loss limit or keep the Stacking Loss allowed limit at 120kcal/kg.
AEML requested to allow GCV “As received” at the unloading point, along with a specified stacking loss to arrive at normative as fired GCV, instead of considering a GCV loss between “As Billed” and “As Received”, subject to 650 kcal/kg limit. In case, the Commission continues with the approach of allowing a normative GCV loss between “As Billed” and “As Received”, the same may be increased to 800 kcal/kWh.
Maharashtra Rajya Magasvargiya Vidyut Karmachari Union and Graduate Engineer’s Association requested to considering "As received" GCV for calculation of ECR as the control of GCV gap between Loading end to Unloading end is beyond the jurisdiction of MAHAGENCO. Graduate Engineer’s Association requested to consider 120 kcal/kg stacking loss for MAHAGENCO’s generating stations.
MSEDCL submitted that, GCV loss shall be allowed as per Third Party sampling or GCV “As billed”. MSEDCL requested to revise the clause as per the CERC Tariff Regulation 2024.
Tata Power suggested to the actual stacking loss should be subjected to a maximum ceiling of 120 kcal/kg for non-pithead station, and actual loss in calorific value of coal between “as billed
by supplier” and “as received at generating station”, subject to the maximum loss in calorific value of 650 kcal/kg for domestic coal and 100 kCal/kg for imported coal-based plants.
The Commission had proposed to consider the GCV as billed, for the purpose of computation of Energy Charges, as discussed in the Explanatory Memorandum. The Commission in MYT Regulations 2019 had allowed maximum loss of 300 kcal/kg which was subsequently relaxed by the Commission vide MTR review Order in Case No. 132 of 2023, dated February 01, 2024 and allowed GCV loss of 650 kCal/kg for FY 24 and FY 25, as this was the target specified for the 1st year of the 4th Control Period. While allowing the additional GCV loss of 650 KCal/kg the Commission has noted that,
“However, the Commission also directs MSPGCL to take all the necessary and adequate steps to minimize the grade slippage and submit the efforts taken by MSPGCL during the MYT Petition for considering the relaxed norms approved in this Order on its merit. In case the actual washed coal utilization is lower than the washed coal utilization as per fuel utilization plan submitted as part of MTR Petition, the Commission will take an appropriate view regarding additional GCV loss allowed at the time of truing up.”
The data submitted by the MSPGCL, shows that, the actual Average GCV loss of Mahagenco stations is 760 Kcal/kg. In view of relaxation provided by the Commission in review Order, efforts demonstrated by MSPGCL for sampling methodology and actual average GCV losses, the Commission is inclined to revise the allowable GCV loss from 650 Kcal/kg proposed in the draft MYT Regulations to 750 Kcal/kg in the final MYT Regulations 2024.
However, as noted in recent Order of February 01, 2024, the MSPGCL is expected to take efforts to minimize the grade slippage and submit the steps taken during the MYT Petition for next control period.
Further, Stacking Loss for Pit head station and Non-Pit head station are considered same as 85 Kcal/kg in line with the philosophy outlined in the Explanatory Memorandum. It is also noted that, there is no specific recommendation from CEA to allow stacking loss for imported coal-based plants. Accordingly, the Commission has not considered submission of Gencos to allow stacking loss of 100 Kcal/kg for imported Coal based plants.
Hence, the revised Regulation in the MYT Regulations 2024 is as under:
“
51.6 Energy Charge Rate (ECR) in INR/kWh shall be computed up to three decimal places and shall be the sum of the cost of normative quantities of primary and secondary fuel for delivering ex-bus one kWh of electricity, and shall be computed as per following formula:
$$\text{ECR} = \frac{[P_p \times (Q_p)_h + P_s \times (Q_s)_h + \text{SRC} \times \text{LPR}]}{[1 - (\text{AUX}n + \text{AUX}{en})]} \quad (\text{INR/kWh})$$
Provided that, the provision of SRC and LPR shall be applicable only for stations where FGD mandate & approval is notified by MERC.
Where,
Pp = landed cost of primary fuel, namely coal or lignite or gas or liquid fuel and limestone, if applicable, in INR/kg or INR/cum or INR/litre, as the case may be;
(Qp)n = Quantity of primary fuel required for generation of one kWh of electricity at generator terminals in kg or litre or standard cubic metre, as the case may be, and shall be computed on the basis of normative Gross Station Heat Rate (less heat contributed by secondary fuel oil for coal/lignite based Generating Stations) and gross calorific value of coal/lignite or gas or liquid fuel as billed by supplier less:
(a) Actual loss in calorific value of coal between “as billed by supplier” and “as received at generating station”, subject to the maximum loss in calorific value of 750 kcal/kg; and
(b) actual stacking loss subject to the maximum stacking loss of 85 kcal/kg for pithead stations and non-pithead stations;
Ps = landed cost of Secondary fuel oil in INR/ml,
(Qs)n = Normative Quantity of Secondary fuel oil in ml/kWh as per Regulations 46.11 and 46.12, and
SRC = Specific reagent consumption on account of revised emission standards (in g/kWh);
LPR = Weighted average landed price of reagent for Emission Control System (in INR/kg);
AUXn = Normative Auxiliary Energy Consumption as % of gross generation as per Regulations 46.13 to 46.17;
AUXen = Normative Auxiliary Energy Consumption of Emission Control System as % of gross generation as per Regulation 46.18”
“Incentive:
50.11 Incentive shall be payable at a flat rate of 50.0 paise/kWh for actual energy generation in excess of ex-bus energy corresponding to target Plant Load Factor during peak hours and at a flat rate of 25.0 paise/kWh for actual energy generation in excess of ex-bus energy corresponding to target Plant Load Factor during off-peak hours, on a cumulative basis within each Season (High Demand Season or Low Demand Season, as the case may be), as specified in Regulation 46.3 of these Regulations.”
MSPGCL requested to align the provisions of Incentive with the CERC Tariff Regulations 2024. The CERC in Final regulations 2024 has increased incentive for actual energy generation more than ex-bus scheduled energy corresponding to target PLF. AEML requested to adopt the provisions of the CERC Regulations to align the philosophy of providing adequate incentive to Utilities above target norm.
As per MERC Tariff Regulations, 2019, the Peak and Off-Peak incentives are 50 paise/kWh and 25 paise/kWh respectively for energy supplied over the normative PLF. It is observed that there has been an increasing gap between the Peak and Off-Peak Tariff discovered in the open market with the ratio of average Off-Peak and Peak Tariff in the range of 1:1.3 to 1:1.6.
In view of the above, the incentive for energy generated in excess of the NAPLF during Peak Hours is increased to 75 paise/kWh and during the Off-Peak Hours is increased to 55 paise/kWh in line with CERC Tariff Regulation 2024. Hence, the revised Regulation is as under:
Hence, the revised Regulation in the MYT Regulations 2024 is as under:
“51.11 Incentive shall be payable at a flat rate of 75.0 paise/kWh for actual energy generation in excess of ex-bus energy corresponding to target Plant Load Factor during peak hours and at a flat rate of 55.0 paise/kWh for actual energy generation in excess of ex-bus energy corresponding to target Plant Load Factor during off-peak hours, on a cumulative basis within each Season (High Demand Season or Low Demand Season, as the case may be), as specified in Regulation Error! Reference source not found. of these Regulations.”
"51.4 The PAFM shall be computed in accordance with the following formula:
$$\text{PAFM} = \frac{100 \times \sum_{i=1}^N \text{DC}_i / {N \times \text{IC} \times (1 - \text{AUX})}}{N} %$$
Where,
AUX = Normative auxiliary energy consumption in percentage
DCi = Declared capacity (in ex-bus MW) for the ith day of the month which the Station can deliver for at least three hours, as certified by the MSLDC after the day is over.
IC = Installed capacity (in MW) of the complete Generating Station
N = Number of days in the month
Note: DCi and IC shall exclude the capacity of generating units not declared under commercial operation and in case of a change in IC during the concerned period, its average value shall be taken."
MSPGCL has submitted that in case of water shortage and dam water going below MDDL, the generator cannot declare any capacity and thus the PAFM during the period will be "zero". As per the formula for recovery of Capacity charge, with "zero" PAFM, there will be "zero" recovery of capacity charge. However, as the water shortage is a force-majeure un-controllable event for the hydro generator, the under-recovery (or no recovery) of capacity charges is penalty on the generator. To avoid such situation, the following needs to be added to the formula for PAFM, so that the generator can claim recovery of capacity charge under such force-majeure events.
"Provided that in case if no capacity declaration is possible due to uncontrollable factors like water level below MDDL, no water release instruction from Water Resources Department etc., the relevant period to be excluded."
The Commission notes the submission of the MSPGCL. MSPGCL has raised the case specific concern which can be delt separately on case-to-case basis. MSPGCL need to substantiate the case specific issue with supporting data at the time of Tariff proceedings. Further, the Commission notes that, current provision of the Regulation 51.4 for computation of PAFM is in line with the CERC Tariff Regulations, 2024, and the MERC MYT Regulations, 2019.
No changes in provision of draft MERC MYT Regulations, 2024.
51.8 In case the Energy Charge Rate (ECR) for a Hydro Generating Station, as computed in Regulation 51.6, exceeds ninety paise per kWh, and the actual saleable energy in a Year exceeds ${DE \times (1 - AUX)}$ kWh, the Energy Charge for the energy in excess of the above shall be billed at one hundred and twenty (120) paise per kWh only.
MSPGCL requested to remove 90 paise/kWh minimum ECR criteria for sale of power at higher ECR in case of generation exceeding design generation and allow all the hydro stations to charge the excess net generation over the net normative sent out expected at design generation at a rate equal to 1.33 times of the approved ECR.
The purpose of the Regulation 51.8 of the Draft MERC MYT Regulation 2024 is to provide the incentive for the secondary energy (above the design energy) generated by the hydro power plant. However, the Commission notes that, the majority of hydro power plants in the state are not able to avail the benefits of incentive to secondary energy as their energy charge is below 90 Paise per kWh. Considering this issue, the Commission finds merit in the submission of MSPGCL that the secondary energy may be sold to at 1.33 times the Energy Charge of that hydro plant determined by the Commission. However, the Commission is of the view that, the above provision for energy charge for secondary energy should be capped at 120 paise/kWh in line with the existing provision of the Draft MERC MYT Regulations 2024. Accordingly, the Commission has revised the provision of the Draft MERC MYT Regulations 2024 as below.
The proposed revised provision of the MERC MYT Regulations, 2024 is as below.
*52.8 In case the actual saleable energy in a Year exceeds { $DE \times (1 - AUX)$ } kWh, the excess Energy of the Hydro Generating Station shall be billed at the rate 1.33 times the Energy Charge Rate (ECR), as computed in Regulation Error! Reference source not found., or one hundred and twenty (120) paise per kWh whichever is lower.*
"54.1 Variations between actual net injection and scheduled net injection for the generating stations, and variations between actual net drawl and scheduled net drawl for the Beneficiary/ies shall be treated as their respective deviations, and charges for such deviations shall be governed by the Maharashtra Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters) Regulations, 2019:
.....
MSEDCL submitted that, after receipt of DSM bill, there is noticeable difference in the actual drawl v/s. MSEDCL's revised schedule drawl which results in additional charges for deviation without any fault of MSEDCL. MSEDCL suggested that additional deviation charges paid by distribution licensee shall be allowed to recover from tariff. AEML SEEPZ and AEML requested that the MYT Regulations may recognize the possibility of an additional DSM charges becoming applicable on account of uncontrollable factors and in such cases, such ADSM charges shall be allowed as pass through in tariff.
The Commission is of the view that, the issues raised by stakeholders are not generic in nature which can be dealt through Regulatory framework. Allowing additional DSM Charges as pass through would release the Buyers from responsibility of precise scheduling without taking onus of consequences of the Deviation. This would defeat the purpose of the Deviation settlement mechanism and it is against the intent and spirit of the DSM Regulations, 2019. Hence, no modification are proposed in the aid Regulation.
No changes in provision of draft MERC MYT Regulations, 2024.
“55.1 Input price of coal or lignite from the integrated mine(s) shall be determined based on the following components:
(i) Run of Mine (ROM) Cost; and
(ii) Additional charges:
a) crushing charges;
b) transportation charge within the mine up to the washery end or coal handling plant associated with the integrated mine, as the case may be;
c) handling charges at mine end;
d) washing charges; and
e) transportation charges beyond the washery end or coal handling plant, as the case may be, and up to the loading point:
Provided that one or more components of additional charges may be applicable in case of the integrated mine(s), based on the scope and nature of the mining activities:
Provided further that the input price of lignite shall be computed based on Run of Mine (ROM) based on the technology such as bucket excavator-conveyor or belt-spreader or its combination and handling charges, if any.
Provided also that Statutory Charges, as applicable, shall be allowed as passthrough expenses:
Provided also that the Input Price of coal or lignite determined above shall be capped to the delivered price of coal at the upper price band notified by Coal India Limited for the same Grade of coal from time to time:
Provided also that if the coal rejects generated out of the coal washery are used in own/captive generating plant, then the basic cost of coal rejects shall be considered as Nil, and actual transportation charges, subject to prudence check, shall be considered as input cost.”
MSPGCL needs the clarity on what exactly constitutes the "delivered price of coal". It includes the landed price of coal or includes all the levy and taxes. Further it is requested to clarify, if there is any case, where coal supply from an integrated mine to a generating company at same rate as that of Coal India Ltd for the same grade of coal, the method for recovering any under-recovered amount of the input price of coal remains unclear.
The Provision of the Regulation 55.1 is amply clear. The Commission has already added the proviso to take care of any additional charges based on the scope and nature of the mining activities. Further, the proviso has been also added to take care of Statutory Charges, as applicable and same shall be allowed as passthrough expenses. With regards to case specific query raised by MSPGCL, the Commission notes that, currently there is no integrated mine is operational in the State.
No changes in provision of draft MERC MYT Regulations, 2024.
"56.2 Run of Mine Cost of coal in case of integrated mine allocated through allotment route under Coal Mines (Special Provisions) Act, 2015 shall be worked out as under:
ROM Cost = [(Annual Extraction Cost / ATQ) + Mining Charge] + (Fixed Reserve Price).
Where,
i. Annual Extraction Cost is the cost of extraction of coal as computed in accordance with Regulation 60 of these Regulations;
ii. Mining Charge is the charge per tonne of coal paid by the generating company to the Mine Developer and Operator engaged by the Generating Company for mining, wherever applicable; and
iii. Fixed Reserve Price is the fixed reserve price per tonne along with subsequent escalation, if any, as provided in the Coal Mine Development and Production Agreement or Allotment Agreement:
Provided that in case the Mining Charge includes the Annual Extraction Cost payable to the MDO, then the Annual Extraction Cost shall not be payable separately."
MSPGCL submitted that the production beyond ATQ may be possible, to meet the generation requirement as per GOI's directions. Hence, if extraction beyond 100% is achieved, additional incentive should be provided, as increased domestic coal extraction will reduce the dependence on the imported coal and will reduce the overall cost of production. Further, if production
achieved is lesser than 85% during any particular year on account of reasons beyond the control of mining company, relaxation in ATQ should be allowed and RoM cost shall be computed based on ATQ with relaxation.
The Commission notes that, proposed clauses are in line with the CERC MYT Regulations, 2024 and MERC MYT Regulations, 2019. Currently, there is no integrated mine operational in the State. Hence, the Commission finds no merit in changing the proposed clause as suggested by the MSPGCL without any supporting provisions.
No changes in provision of draft MERC MYT Regulations, 2024.
"58.1 The expenditure incurred, including IDC, duly certified by the Auditor, for development of the integrated mine(s) up to the date of commercial operation, shall be considered for arriving at the capital cost."
"58.3 Capital expenditure incurred on infrastructure for crushing, transportation, handling, washing and other mining activities required for mining operations shall be arrived at separately in accordance with these Regulations:
Provided that where crushing, transportation, handling or washing are undertaken by the Generating Company, the expenditure incurred on infrastructures of these components shall be capitalized:
Provided further that where mine development and operation, with or without any component of crushing, transportation, handling or washing are undertaken by the Generating Company by engaging Mine Developer and Operator or an agency other than Mine Developer and Operator, the capital expenditure incurred by Mine Developer and Operator or such agency shall not be capitalised by the Generating Company and shall not be considered for the determination of input price."
"58.4 The capital expenditure shall be determined by considering, but not limited to, the Mining Plan, detailed project report, mine closure plan, cost audit report and such other details as deemed fit by the Commission."
MSPGCL requested, the Commission should account for the incremental coal cost and allow for adjustments accordingly. Delays in project completion would led to the higher capital costs, which in turn increase the price of coal from the integrated mine. Since this cost might surpass
that of coal from other sources, it is essential to account for such incremental coal cost to ensure complete recovery of cost.
The Commission is of the view that, the MSPGCL should make effort to complete the project in time and then approach the Commission with case specific issues for delay. It would not be appropriate to consider these issues while framing the Regulations. Further, the Commission also notes that, the proposed clauses are in line with the CERC MYT Regulations, 2024. The Commission finds no merit in revising the proposed clause as suggested by MSPGCL.
No changes in provision of draft MERC MYT Regulations, 2024.
“60.1 The Annual Extraction Cost of integrated mine(s) shall consist of the following components:
MSPGCL needs clarification of the statutory charges defined under Annual Extraction cost. MSPGCL submitted that those charges typically include various components such as Royalty, District Mineral Foundation (DMF) contributions, National Mineral Exploration Trust (NMET) and any other applicable taxes. Also, it is essential to specify the GST rate associated with these charges for the integrated mine to ensure clarity.
The proposed clauses are in line with CERC MYT Regulations, 2024 and it has provision of consideration of statutory charges if applicable. The Royalty, District Mineral Foundation (DMF) contributions, National Mineral Exploration Trust (NMET) and any other applicable
taxes as highlighted by MSPGCL can be examined at the time of tariff order. The Commission finds no merit in revising the proposed clause as suggested by MSPGCL.
No changes in provision of draft MERC MYT Regulations, 2024.
“67.1 The input charges of coal or lignite shall be recovered as under:
Input Charges = [Input Price x Quantity of coal or lignite supplied] + Statutory charges, as applicable:
Provided that energy charge rate based on input price of coal does not lead to higher energy charge rate throughout the tenure of power purchase agreement than that, which would have been obtained as per terms and conditions of the existing power purchase agreement.
67.2 The Generating Company shall work out the comparative energy charge rate based on the input price of coal and notified price of Coal India Limited for the commensurate grade of coal for every month from the date of commercial operation of integrated mine(s) and share the same with beneficiaries.”
MSPGCL requested to clarify regarding final input price of coal to be considered as per actual or subject to capping to CIL coal rate in Reg 67.1. Recovery of input charges is allowed as per input price of coal, whereas Proviso 4 of Regulation 55 provides that input price of coal shall be capped to the delivered price of coal notified by CIL for the same grade of coal. MSPGCL also requested to clarify on imposition of royalties either on base price of CIL or input price of integrated mine coal.
The Commission notes that, the provision of the Draft Regulations are amply clear. The proviso of 56.1 clarifies that, the Input Price of coal or lignite determined shall be capped to the delivered price of coal at the upper price band notified by Coal India Limited for the same Grade of coal from time to time. Further the proviso of Regulation 56.1 and formula of input charge clarifies that, the statutory charges are payable additionally. The proposed clauses are in line with the CERC MYT Regulations, 2024 and MERC MYT Regulations, 2019.
No changes in provision of draft MERC MYT Regulations, 2024.
“74.3 All the new intra-State transmission systems costing above a Threshold Limit and meeting other conditions as laid out in Annexure-IV, shall be developed through Tariff Based Competitive Bidding in accordance with the guidelines issued by the Central Government under Section 63 of the Act.”
The Threshold Limit for Intra-State Transmission System to be developed through Tariff Based Competitive Bidding shall be Rupees Five Hundred (500) Crore excluding land cost.
All new Intra-State Transmission Systems excluding the schemes involving the upgradation / augmentation of Assets forming part of the existing Transmission Licensee and excluding the schemes, which appears in the Licence of the Transmission Licensee, costing Rupees Five Hundred (500) Crore or more excluding land cost shall be implemented by STU through Tariff Based Competitive Bidding in accordance with the competitive bidding guidelines notified by the Central Government from time to time.
AEMIL and AEML proposed some changes with regard to the reference regulations corresponding to Annexure-IV. It is submitted to consider exclusion of ROW and Reinstatement charges, in addition to Land Cost. This is required because ROW charges widely vary per location. In Mumbai, the incidence of both ROW and Reinstatement charges is significantly higher than in other areas, making projects in Mumbai and the rest of Maharashtra incomparable. Hence, this component should also be excluded along with land cost from total project cost for testing against the threshold of Rs. 500 Cr. The schemes to be implemented through the latest technologies such as Battery Energy Storage, Marine EHV cables, HVDC VSC technology, etc. should be excluded from the scope of TBCB.
Prayas Energy Group suggested to reduce the threshold for TBCB from Rs 500 Crores to Rs 100 Crores. As TBCB threshold limit for other states are in the range of 100-250 Cr. As per estimated cost as communicated by, the Cost Committee constituted by National Committee on Transmission (NCT) and methodology for calculation of tariff as per CERC norms.
AEML submitted that, Exclusion of ROW and Reinstatement charges, in addition to Land Cost – This is required because ROW charges widely vary as per locations. In Mumbai, the incidence of both ROW and Reinstatement charges is significantly more compared to other
areas, which makes projects in Mumbai and rest of Maharashtra incomparable. Hence, this component should also be excluded along with land cost from total project cost for testing against the threshold of Rs. 500 Crore. Schemes to be implemented through latest technologies such as Battery Energy Storage, Marine EHV cables, HVDC VSC technology, etc. should be excluded from the scope of TBCB.
STU suggested to reduce the Threshold limit to Rs 200 Crore excluding land cost, based on experience for Centre and other states regarding TBCB Limit as shown below:
Centre: ISTS projects have seen significant proportion of projects executed via TBCB with capex of INR 1.48 lac crores in last 5 years (40-50% of total capex).
Uttar Pradesh: UP has been aggressive in executing intrastate transmission projects under TBCB by routing all projects including and above 220kV voltage via TBCB route. This is equivalent to a limit of INR 100 to 150 Crore.
Madhya Pradesh: MP has awarded 4 projects under TBCB route worth INR 3,000-4,000 crores so far. While TBCB threshold for the state is INR 250 crore, they bundled projects by dividing the state into two halves, eastern and western region seeing participation from major players such as PGCIL, Sterlite, Adani etc.
MSEDCL proposed the threshold limit for the transmission project for strengthening/upgradation of existing transmission network for Mumbai Area & rest of Maharashtra may be reduce from INR 500 Crores for encouraging competition in transmission business.
Maharashtra Rajya Magasvargiya Vidyut Karmachari Union requested that to increase the threshold limit to INR 1000 Crores.
The Commission has noted the suggestions of the stakeholders. The Commission has also compared the TBCB limits proposed at national level and other SERCs. The STU has suggested to revise the TBCB limit to INR 200 Crores excluding land cost. The Commission finds it appropriate to consider the recommendation of STU as STU is transmission planning authority under the EA 2003. Further the Commission also notes that the Mumbai transmission licensees have requested to exclude the Reinstatement (RI) Charges while deciding the TBCB limit. The Commission has noted that, the Reinstatement charges are part of the project estimate and paid to local authority as per the circulars notified by them. In many cases specifically in metro cities, RI charges form substantial part of the project and more than the cable cost (material +labour cost). It is also observed that, many cable projects may cross the proposed revised TBCB limit of INR 200 Crores just because of higher RI charges. In view of the above, the Commission has decided to exclude the RI Charges while deciding the TBCB limit for the State.
With regards to submission of stakeholders for relaxation of TBCB limit in specific condition the following proviso is already provided in the draft regulations which addresses the concerns of the STU and other stakeholders.
In case the STU intends to implement any Intra-State Transmission System above the Threshold Limit through cost-plus approach under Section 62 of the Act, due to some specific reasons such as project is of critical nature (e.g., Transmission System being developed for Defence, Railways, Airport, etc.) or the Project may lead to ownership or interface issues, i.e., the ownership of new Intra-State Transmission System cannot be delineated from the assets of existing transmission assets, the STU shall obtain prior approval of the Commission for the same. Further, in case the STU intends to implement any Intra-State Transmission System below the Threshold Limit through Tariff Based Competitive Bidding, due to some specific reasons, STU can decide to implement such projects through Tariff Based Competitive Bidding with valid reasons to do so and with prior approval of the Commission.
The revised provision of the Annexure-IV of the final MERC MYT Regulations 2024 is as below:
with the competitive bidding guidelines notified by the Central Government from time to time.
“76.3 In case of new Transmission Licensees are added to the intra-state transmission network during the control period, then the TTSC, Base Transmission Capacity Rights and Base Transmission Tariff shall be re-determined for each remaining year as per the provisions under “Determination of Intra-State Transmission Tariff” section.”
MSEDCL submitted that, revision in Transmission Charges due to the addition of an Intra-State Transmission Licensee shall be done only at the time of process of the Tariff Petition filed by STU before MERC. Frequent revision in intra-state transmission charges would result in uncertainty among beneficiaries and other stakeholders.
The Commission noted the submission of MSEDCL. As the Commission has discontinued the provision of the mid-term review, the provision of revision of transmission tariff during the control period in case of addition of new transmission licensee would be required and it may happen any time during the control period. The Commission has specified normative parameters for new transmission licensee which can be referred by the distribution licensees to estimate the likely impact on the TTSC for the remaining control period.
No changes in provision of draft MERC MYT Regulations, 2024.
“Target availability for the Transmission Licensee shall be as under:
(a) For full recovery of Annual Transmission Charges:
(i) AC system: 98 per cent
(ii) HVDC bi-pole links and HVDC back-to-back stations: 95 per cent
(b) For Incentive consideration:
(i) AC system: 99 per cent;
(ii) HVDC bi-pole links and HVDC back-to-back stations: 96 per cent
.....”
APTCL requested to keep the benchmark availability for consideration of incentive should be 98 % for AC system. APTCL recommended to includes provision of incentive between 98% and 99% such that it will encourage the transmission licensee to keep the availability consistently at higher levels and at the same time improving their profitability.
MSETCL states that, HVDC is not able to achieve target availability required for recovery of Annual Transmission Charges due to ageing of assets. Thus, it is requested to lower the availability norm for HVDC to 92% .
Further, MSETCL requested to amend Regulation 78.1 (b) such that incentive consideration for AC system shall be applicable as per norms specified under CERC Tariff Regulations, 2024. It should be 98.50% instead of 99%.
Tata Power submitted that, The CERC Tariff Regulations, 2024 allow 15.5% RoE as well as incentive for higher Availability; however, the Commission is allowing lower RoE and allowing difference up to 15.5% against achievement of higher Availability, which is not in accordance with the CERC Tariff Regulations, 2024.
The draft Regulations specified the normative Transmission Availability of 98% for full recovery of Annual Transmission Charges and 99% for Additional Rate of Return on Equity consideration for the AC system and the normative Transmission Availability of 92% for full recovery of Annual Transmission Charges and 93% for Additional Rate of Return on Equity consideration for HVDC system. In this regard, for achieving the higher transmission availability, the Commission is already allowing adequate O&M expenses for the maintenance of the transmission assets in the MYT Regulations to achieve higher availability.
Further, the Commission revised the performance linked RoE parameters under financial chapter of the MERC MYT regulations 2024 wherein 1.5% of the RoE is linked with the performance parameters. Hence, the Commission finds no merit in revisiting the operational norms.
The Commission has discussed, the allowance of appropriate additional RoE linked to the Transmission Availability and the data telemetry and communication system up to load dispatch centre or protection in the Financial Chapter of MERC MYT Regulations 2024.
MYT regulations for applicability of annual escalation rates for amount to be paid by one utility for its bays maintenance or the bays that are under premises of other utilities.
6.12 MSETCL submitted that, the minimum expenditure of R&M expenses shall be increased gradually above 20% as and when the assets of the transmission licensee are nearing the completion of useful life of the asset.
6.13 Tata Power submitted that, when composite O&M norms are specified, such a restriction should neither be specified nor are they implementable. It is requested to remove this criterion for the Transmission Business.
6.14 APTCL requested to delete the reference regulation. APTCL submitted that these regulations limit the other O&M expenses to 80% and any increase in the same would not be compensated with R&M expenses. The licensee should be allowed to allocate expenses under different heads such as R&M, A&G and employee expenses as per their business requirements.
The Commission has retained its methodology proposed for computation of O&M charges in the Draft MYT Regulations, 2024. However, the Commission has noted the submissions of the stakeholders of lower recovery of the O&M Expenses as compared to the norms derived in MYT Regulations, 2019. To address the concerns of the stakeholders, the Commission has first estimated the O&M Expenses for the 5th Control Period by escalating the actual approved O&M expenses of FY 2021-22 (post sharing of gains and losses) with actual 5 years average of CPI: WPI having the ratio of 70:30 upto the Base Year i.e. FY 2024-25. Such derived normalised for base year O&M and then further escalated over the 5th Control Period with the inflation rate of 5.33% and post adjustment of the 1% efficiency factor.
The Commission, while specifying the O&M expense norms, has calculated the escalation rate that is used to escalate the O&M expenses for the period FY 2024-26 to FY 2029-30, based on the CPI and WPI data as available till March 2023. As the actual data till the third quarter of FY 2023-24 was available, the same has been considered for computing the escalation rate. The average increase in WPI for 2019-20 to 2023-24 (till December 2023) works out to 4.93%, while the CPI for the same period works out as 5.73%. Considering the 70:30 weights for CPI and WPI, respectively, the escalation rate works out to 5.33% for the Distribution Licensees.
The Commission while estimating the norms at the time of Draft Regulations had considered normative allocation of the O&M Expenses in terms of Lines, Bays and MVA Capacity. However, the transmission licensee as part of their submissions have submitted their respective actual allocations, which have been considered while estimating the revised norms. Such actual allocation ratio is applied on the estimated O&M Expenses for 5th Control Period and the same is linked with the average transmission line length, number of bays and transformation capacity have been considered from the data submitted by the licensees in lines with the methodology adopted in the Explanatory Memorandum. Further, the Commission notes that ATIL, JPTL, APTCL and VIPL-T does not have any transformation capacity, hence, the Commission has proposed to allocate the O&M expense of substation assets to bays only.
With regards to the wage revision, the Commission has noted the submission of the various stakeholders. The Commission clarifies that, the impact of wage revision which was approved by the Commission separately has been considered while considering the past period O&M Expenses while deriving the norms. The Commission is of the view that, the wage revision is
part of employee expenses and shall be treated as controllable factor and compared vis-à-vis normative O&M expense.
Further, the Commission shall consider the impact of arrears of wage revision, if any, booked as part of employee expense in any particular year separately and shall be normalised annually over the Control Period and shall be treated under sharing of gains and loss for the purpose of true-up of O&M expense of respective years.
With regards to AEMIL's HVDC, the Commission notes the submission of AEMIL that the HVDC Scheme executed by AEMIL is different from the existing HVDC of MSTECL in terms of technology and the additional charges incurred which are not levied on State owned Licensees. However, the Commission at this point of time does not have any reference to the operational cost of similar projects. Hence, for the fifth control period if any of the upcoming HVDC line having different technology, the Commission may determine the separate norms for such line on case-to-case basis in accordance with these Regulations.
Regarding AEMIL's submission of allowing the Normative O&M expense entitlement for the unutilised bays, the Commission is of the view that while deriving the norms, the Commission has not considered the unutilised bays which has overstated the O&M norms. Thus, Commission intends not to allow any additional O&M expense to carry out any maintenance of stand-by assets.
The provision of the Regulation 80 of the MERC MYT Regulations 2024 is revised appropriately.
"79.11 Within the O&M expenses, the expenditure on Repairs & Maintenance shall be minimum 20% of the total O&M expenses.
Provided that, if the expenses on R&M falls below 20% of total O&M expenses allowed under these Regulations, then such savings in R & M shall not be set off against other heads of O&M expenses:
Provided also that this minimum limit of R&M shall not be applicable for Transmission Licensee for the first five years after commencement of operations as a Transmission Licensee."
APTCL, AEMIL, ATIL, MSEGPTCL and AEMIL requested to delete the reference regulation. It is submitted that these regulations limit the other O&M expenses to 80% and any increase in the same would not be compensated with R&M expenses. Hence, the licensee should be
allowed to allocate expenses under different heads such as R&M, A&G and employee expenses as per their business requirements. Once the Commission has prescribed output – based norms for O&M cost, there is no need to specify micro targets for individual heads of O&M cost. Licensees should be permitted the flexibility to manage their operations and individual expenses as per their discretion and so long as the defined performance parameters are being achieved. It is submitted that CERC Regulations 2024 does not provide any separate breakup for components of O&M expenses. Further, as per APTEL Judgement, the Commission ought not to go into every sub-component of a controllable expense under normative system of approvals.
MSETCL requested to reconsider before introducing such stringent the Provision. It is stated that, Transmission Licensee is not directly related to consumer. Transmission Licensee is already regulated/incentivised through Transmission System Availability. As Transmission System Availability is indirectly responsible for maintaining reliability of supply. It is also submitted that, as far as quality of supply, it is already regulated through IEGC/State Grid Code. So, an additional regulation may not be required.
MSEDCL submitted that, the minimum expenditure of R&M expenses shall be increased gradually above 20% as and when the assets of the transmission licensee are nearing the completion of useful life of the asset.
Tata Power submitted that, when composite O&M norms are specified, such a restriction should neither be specified nor are they implementable. It is requested to remove this criterion for the Transmission Business.
The Commission in the explanatory memorandum has already discussed that some the Transmission Licensees have not been spending enough on Repairs & Maintenance, on account of various reasons, and are diverting the funds allocated to R&M to employee expenses and A&G expenses or vice versa.
However, the Commission also notes the stakeholder's comments that such performance parameter may also reduce the flexibility to manage expenses by the licensee. Further, the Commission also notes that the Transmission Licensee is already regulated/incentivised through Transmission System Availability which is indirectly responsible for maintaining reliability of supply with appropriate expenditure on R&M activities. Accordingly, the Commission finds it appropriate to delete the proviso in the final MYT Regulations 2024.
The provision of the Regulation 80.11 of the MERC MYT Regulations 2024 is deleted appropriately.
79.13
....
“Provided further that if actual O&M expenses including the cost of some schemes considered under O&M rather than Capital Investment are higher than normative O&M expenses on this account, then no sharing of efficiency losses shall be done”.
Tata Power submitted that due to reclassification of the scheme from Capex to Opex, the Licensee already loses RoE on the capital investment and if the loss in O&M is also not allowed to be shared, then it will not be financially viable for Licensee to execute such schemes. Tata Power also submitted that the entire excess O&M expenses on this account should be passed through, without any sharing, as the higher O&M expenses as compared to the norms are on account of shifting of certain expenses that were classified as Capex to now being treated as O&M expenses. It appears that the intent of the Commission is also the same, though the wording of the Draft Regulations can lead to a different interpretation.
The Commission finds merit in the submission of TPC-T that the intention of this clause is to ensure that utility shall not bear the losses if any of the CAPEX is shifted into the OPEX, because while computing the norms, the Commission has not considered the one-time R&M expense due to reclassification of the scheme from CAPEX to OPEX. Accordingly, the Commission has revised the Proviso of the Regulation 80.11 appropriately.
The Proviso of the Regulations 80.11 is revised as below:
80.11 The Commission may consider any request for revision of the normative O&M expenses of the Transmission Licensee on account of consideration of some Schemes under O&M rather than Capital Investment on case-to-case basis, depending on the justification to be submitted by the Applicant and the life-cycle cost analysis:
Provided that if actual O&M expenses are lower than such revised normative O&M expenses on this account, then no sharing of efficiency gains shall be done to that extent.
“80.2 The Non-Tariff Income shall include:
.....
c)Income from investments;
d)Income from investments of Contingency Reserves;
.....
l)Income Other than allowable Regulatory Income shown in books of Account;
Provided that the interest earned from investments made out of Return on Equity corresponding to the regulated Business of the Transmission Licensee shall not be included in Non-Tariff Income.”
JPTL required clarity on clause (c) (Income from investments) included in the list of non-tariff income by transmission licensees. JPTL needs clarity whether it is income from investments for regulated business or income from the returns generated by the licensee. Further, JPTL recommends removing the clause (c) from the list or else give clear instructions to specify that it is income from regulated business or income from returns generated by licensee.
AEML submitted that only non-tariff income related to regulated business of a transmission licensee can be considered in the ARR. All income generated from the Company’s un-regulated activities, if any, appearing its books of accounts, cannot be considered for pass through, as that amounts to cross-subsidisation of regulated business, by un-regulated business. Further, the Licensee will present a reconciliation statement where all expenses and income appearing in the Books of Accounts and as per ARR will be reconciled.
AEMIL requested to add the clause "Any other Non-Tariff Income" for the transmission corresponding to regulations for Generation, Distribution wires and Distribution-Retail supply.
MSEDCL submitted that any other income which is derived by the Transmission Licensee other than the business of transmission of electricity shall be included in the Non-Tariff Income of Transmission Licensee. It is suggested that appropriate clause may be included specifying the same so that there is no ambiguity regarding any other income.
Tata Power requested to delete “Income Other than allowable Regulatory Income shown in books of Account” under Non-Tariff Income as no rational or justification for considering income other than that recognised as regulatory income under Non-Tariff Income.
The Commission Notes the submission of the stakeholders. It is observed that, sometimes utilities consider the income from non-regulated business in the regulated business’s books of
account for cross-subsidisation. However, the Commission has considered the submission of the utilities and revised the provision of the (l) under Regulation 81.2 of the MERC MYT Regulations 2024 in line with the provisions of MYT Regulations 2019.
Further, the Commission clarifies that the Income from investments included in the list of non-tariff income by transmission licensees are the income from investments for regulated business or income from the returns generated by the licensee.
The provision of the Regulations 81.2 of MERC MYT Regulations 2024 is revised as below:
“81.2 The Non-Tariff Income shall include:
...
l) Any other Non-Tariff Income.”
“82.2 The Commission shall approve yearly ‘Base Transmission Capacity Rights’ as average of Coincident Peak Demand and Non-Coincident Peak Demand for TSUs as projected for 12 monthly period of each year (t) of the Control Period, representing the ‘Capacity Utilisation’ of Intra-State transmission system and accordingly determine yearly ‘Base Transmission Tariff’, in accordance with the following formula:
.....”
“82.3 Base Transmission Tariff for each Year shall be determined as ratio of approved ‘TTSC’ for intra-State transmission system and approved ‘Base Transmission Capacity Rights’ and shall be denominated in terms of “INR/kW/month” (for long term/medium-term usage) or in terms of “INR/kWh” (for short-term bilateral open access transactions usage, short-term collective transactions over Power Exchange and for Renewable Energy transactions) in accordance with the following formula:
Base Transmission Tariff(t) (long-term/medium-term) = TTSC(t) / Base TCR(t)
(INR/kW/month or INR/MW/day)
.....”
AEML submitted that as per MERC DSM Regulations, 2019, State Volume limit is allocated in proportion of share of Own demand. However, the variation due to changeover consumer (COC) demand is reflected in the Network Demand to whom the consumers are connected, and it doesn’t at all reflect in Supply Licensee demand as COC demand is considered on scheduled
basis. Thus, the Supply Licensee gets insulated from deviation in COC demand whereas the Wires licensee bears the DSM / ADSM charges for any variation in COC demand. Hence the Volume limit is to be allocated considering NCPD of network demand (i.e. inclusive of change-over consumer demand). This will ensure that the Volume Limit for Wires Licensee is appropriately increased to offset the liability of deviation in COC demand, which are anyway not Wires Licensee's customers and hence it should not be liable for variation in their demand, in any case.
STU requested to consider contracted capacity of all TSUs and devise appropriate mechanism for determination of transmission tariff.
MSEDCL submitted that, the Commission may not allow any changes in CPD and NCPD during the Control Period so that the transmission charges can be uniform during the control period. It is also submitted that, the actual CPD and NCPD may be re-determined, and the transmission charges may be accordingly computed only during the true-up exercise.
The methodology adopted for determination of specifying the Base Transmission Tariff for each Year is same as that followed during the MYT Regulations, 2019. The Commission notes the submission of the AEML regarding the demand of change over consumers. The Commission has discussed this issue in length while framing the MERC DSM Regulations and subsequent Orders passed by the Commission for removal of difficulties in the implementation of the DSM framework in the State.
In view of the above, the Commission has retained the provisions of the draft Regulations. Further the Commission has given its justification for re-determination of TTSC, Base Transmission Capacity Rights and Base Transmission Tariff in paragraphs 6.20 below.
No changes in provision of draft MERC MYT Regulations, 2024.
“82.5 The State Transmission Utility shall file the Petition for determination of Intra-State Transmission Tariff for the MYT Control Period latest by November 30, 2024 on the basis of Base Transmission Capacity Rights of each TSU, and the summation of the Aggregate Revenue Requirement projected by the Transmission Licensees for each Year of the Control Period:
Provided that the State Transmission Utility shall file the Petition for true-up of share of intra-State transmission tariff for FY 2025-26 to FY 2028-29 and provisional true-up of share of intra-State transmission tariff for FY 2029-30 latest by November 30, 2029 on the basis of the actual CPD and NCPD of Transmission System Users in the respective years, or the quantum
of Short-term/Medium-Term Open Access applied for by the Deemed Distribution Licensee for the available period, as applicable:
Provided further that in case of a Deemed Distribution Licensee whose monthly CPD and NCPD data is not available for 12 months at the time of determination of Base TCR, the monthly CPD and NCPD data if available for at least 4 months, or the quantum of Short-term/Medium-Term Open Access applied for by the Deemed Distribution Licensee for the available period, shall be considered in lieu of the average monthly CPD and NCPD for calculating the Base Transmission Capacity Rights.”
STU submitted that due to efforts are repeat in preparation/ updating of petition including revised management approval for filing. STU submitted that since InSTS petition is mainly sourcing of figures of other licensees the timeline for petition be modified accordingly. Thus, STU proposed to provide the time of four weeks from the date of admittance of all transmission licensee's petition:
As discussed in the General Chapter of the SOR above, the Commission has discontinued with the provision of Mid-Term Review from this Control Period for all Generation Companies, Transmission Licensees and other Utilities covered under MYT Framework except Distribution Licensee and move towards the Multi Year Tariff Framework in letter and spirit. Accordingly, the Commission has proposed the timelines for filing the Petition by STU for determination of Intra-State Transmission Tariff in the Draft MYT Regulations 2024.
Further, the Commission is of the view that during the control period if any new licensee is added into the intra state transmission system, there should be an enabling clause for re-determination of TTSC, Base Transmission Capacity Rights and Base Transmission Tariff for the recovery of its transmission system cost.
No changes in provision of draft MERC MYT Regulations, 2024.
83.1 The long-term Transmission System Users shall share the TTSC of the intra-State transmission system in the proportion of Base Transmission Capacity Rights of each Transmission System User to the total Base Transmission Capacity Rights allotted in the intra-State transmission system.
Provided that a Partial Open Access Consumer shall pay the Transmission Charges to the Distribution Licensee instead of the Transmission Licensee for using a transmission network which shall be passed on to the STU within the stipulated time period as specified under Regulations 14.5 of MERC Distribution Open Access Regulation, 2016 and its amendment thereof.
Provided also that the Distribution Licensee shall submit demand of Partial Open Access consumers to STU on monthly basis."
Provided that the Allotted Capacity for long-term Open Access Users excluding partial Open Access Users, shall be considered in lieu of the average monthly CPD and NCPD for calculating the Base TCR for such Open Access Users:
MSEDCL requested to review both the clauses so that licensee such as MSEDCL is not getting burdened with the same charges twice. In case the Commission plans to calculate the Base Transmission Rights including demand of partial open access consumers then the transmission charges recovered from partial open access consumers may be retained by the Distribution Licensee. MSEDCL submitted that, as per the clause the partial open access consumers are to pay the transmission charges to Distribution Licensees which are in turn to be passed on to the STU. Due to such clause Distribution Licensee such as MSEDCL is burdened with the transmission charges on account of partial open access consumers twice. Once while determination of Base Transmission Rights and for the second time while passing on the charges received from partial open access consumers to STU. It is therefore requested to kindly review both the clauses so that licensee such as MSEDCL is not burdened with the same charges twice. In case the Commission plans to calculate the Base Transmission Rights including demand of partial open access consumers then the transmission charges recovered from partial open access consumers may be retained by the Distribution Licensee.
Tata Power requested to allow to retain recovery of such charges from OA with particular Distribution Licensee. Tata Power submitted that, the Allotted Capacity for LTOA consumers must also be considered. It is submitted that the revenue remitted for LTOA to STU shall not be utilized to reduce the charges for the other TSUs, unless this revenue is also considered, and the denominator also considers the Allotted Capacity.
AEML SEEPZ requested to allow distribution licensees to retain transmission charges it bills to its partial open access consumers, as that is the only way to fully reimburse the distribution licensee's customers. AEML requested to allow distribution licensee to retain the transmission charges it bills to its partial open access consumers, as that is the only way to fully reimburse the distribution licensee's customers. AEML Suggested to consistent approach to be follow for the TCR computation is to be taken for the transmission charges, STU and MSLDC fees and charges.
The Commission has noted the submission of the stakeholders. Further
Appeal in Hon'ble APTEL has also issued the judgement dated 5 July 2024 in APPEAL NO.95 OF 2024 & IA No. 2630 OF 2023 wherein MSEDCL had approached before the Hon'ble APTEL against the Order passed by the Commission on the review Petition filed by MSEDCL dated 07.11.2023 in Review Petition No. 95 of 2023 and impugned Order dated 31.03.2023 in Case No. 239 of 2022. The Hon'ble APTEL has noted as below:
17. From a reading of the afore-mentioned provision, it is evident that for calculating yearly Base Transmission Capacity Rights (TCR), average of Coincident Peak Demand (CPD) and Non-Coincident Peak Demand of TSUs is to be considered as projected for 12 monthly periods of each year of control period and as per the proviso, the allotted capacity for long term Open Access users is to be considered excluding partial Open Access users. It is not in dispute that the monthly/yearly transmission charges of STU is to be shared by all the consumers of Maharashtra including POA consumers and accordingly recovered from them in entirety. As stated in the impugned order dated 07.11.2023, the monthly Transmission charges determined by STU is based on the average CPD and NCPD which includes POA demand data. In our view, as per Regulation 64.2 for calculating Base TCR, average of 12 monthly CPD and NCPD is considered and in line with its proviso the demand of POA is to be reduced while working out Allotted Capacity for long-term Open Access Users, in lieu of the average monthly CPD and NCPD. Thus, in our view, inclusion of Demand of POA, in the demand of Appellant for calculation of its Base TCR cannot be said to be in line with the regulation as stated by State commission in the impugned orders.
The Commission clarifies that, provisions of the MERC MYT Regulations 2019 for exclusion of demand of partial OA consumers while calculating the based TCR of the TSUs is in line with the findings of the Hon'ble APTEL, however while actually calculating the TTSC, the Commission was considering the demand of partial OA consumers in the Discom's demand as discoms demand excluding partial OA consumer's demand was not available.
In view of the above clarifications, the Commission has reviewed the provisions of the Regulations 83.1 of the Draft MERC MYT Regulations 2024 and revised the provisions of sharing of TTSC by TSUs appropriately. The Commission will calculate the TTSC for long term TSUs first by considering the current methodology of average of CPD and NCPD of the TSUs including Open Access demand and then separately work out the TTSC for long term TSU by adjusting the TTSC with adjusted base TCR, where adjusted base TCR will be calculated by deducting the billed demand of partial OA users. The Commission is of the view that, the Billed demand of Partial OA users will be available with Discoms as they are billing on monthly basis to the Partial OA Users. This would address the concerns of the Discoms and also in line with the findings of the Hon'ble APTEL vide the judgement referred above.
Further similar approach has been taken by the Commission for calculating the MSLDC's and STU's fees and charges and sharing of these charges by TSUs.
84.1 The long-term Transmission System Users shall share the TTSC of the intra-State transmission system in the proportion of Adjusted Base Transmission Capacity Rights of each Transmission System User to the total Adjusted Base Transmission Capacity Rights allotted in the intra-State transmission system.
Provided that a Partial Open Access Consumer shall pay the Transmission Charges to the Distribution Licensee instead of the Transmission Licensee for using a transmission network which shall be passed on to the STU within the stipulated time period as specified under Regulations 14.5 of MERC Distribution Open Access Regulation, 2016 and its amendment thereof.
Provided also that the Distribution Licensee shall submit billed Open Access Demand of Partial Open Access consumers to STU and MSLDC on monthly basis for calculating Adjusted Base Transmission Capacity Rights.
84.2 The Annual Transmission Charge payable by Transmission System User shall be computed in accordance with the following formula:
$$ATC(u){(t)} = TTSC{(t)} \times ([Adjusted\ Base\ TCR(u)]{(t)} / \sum{u=1}^n [Adjusted\ Base\ TCR(u)]_{(t)})$$
Where,
$ATC(u)_{(t)}$ = Annual Transmission Charges to be shared by Transmission System User (u) for the yearly period (t);
$Adjusted\ Base\ TCR(u) = Base\ TCR(u) - Billed\ OA\ Demand\ of\ POA(u)$
Where,
Adjusted Base TCR represents the Base Transmission Capacity Right of each Transmission System User (u) adjusted for billed OA Demand of a Partial Open Access Users for the yearly period (t);
85.1 The STU shall raise monthly bill for Intra-State Transmission Charges on every Transmission System User (TSU) on the first working day of the month for the Transmission Charges of preceding month:
85.2 The monthly bill for transmission Tariff shall be payable within thirty days of date of bill by the STU.
85.3 All TSUs shall ensure timely payment of Transmission Tariff to STU so as to enable STU to make timely settlement of claims raised by Transmission Licensees.
MSEDCL submitted that as per definition of due date, in the absence of any agreement the monthly bill for transmission Tariff shall be payable within forty-five days of date of bill by the STU. MSEDCL requested to modify the clause and revised due days for payment to forty-five days. MSEDCL also submitted that if in BPTA, provision of billing days is less than 45 days, then LPS rules clause shall be retained and the same will be applicable to MSEDCL.
The Commission noted the submission of MSEDCL. The Commission also notes that, payment due date will be applicable for payment of generator or transmission licensee or STU or MSLDC as the case may be. The payment due date related provisions should be uniform across all utilities.
Accordingly, the Commission has revised the definition 2.1(40) of due date in the final MERC MYT Regulations 2024. The Commission has removed the reference of the, provision of due date in the Bilateral Agreement. The Bilateral Agreement between TSU and STU or in case of Generator and beneficiary may have provisions different than the normative provisions. Further the linkage of due date is with consideration of receivables while calculating the interest on working capital for generator or licensee or STU or MSLDC. The tariff determination process under MERC MYT Regulations 2024 is on annual basis whereas bilateral agreements may be for any period as mutually agreed. The provisions of the Tariff Regulations should be normative and at par across all the utilities.
Accordingly, the Commission has revised the definition of, “Due date” to remove the reference of bilateral agreement and also deleted the Regulation 86.2 to delete the reference of payment to transmission licensees within 30 days. With this revisions, all the payments i.e. payment due for generator, transmission licensee or STU or MSLDC shall be payable with due date i.e. within 45 days from the submission of bills.
(40) “Due date” means the date by which the bill for the charges for power supplied by the Generating Company or ESSD or for the transmission service provided by a Transmission Licensee are to be paid, in accordance with the Agreement, as the case may be, and if not specified in the Agreement, within forty-five days from the date of presentation of the bill by such Generating Company or ESSD or Transmission Licensee or STU or MSLDC;”
“85.2 The monthly bill for transmission Tariff shall be payable within thirty days of date of bill by the STU.”
127.2 The monthly bill for MSLDC Charges shall be payable within thirty days of receipt of bill by the Long term Beneficiaries and the Medium Term Open Access consumers.
137.2 The monthly bill for STU Charges shall be payable within thirty days of receipt of bill by the Long term Beneficiaries and the Medium Term Open Access consumers.
86.1 The energy losses in the intra-State transmission system, as determined by the State Load Despatch Centre and approved by the Commission, shall be considered as Transmission Losses and borne by the Transmission System Users in proportion to their usage of the intra-State transmission system:
Provided that the quantum of energy consumed by the auxiliary equipment of a transmission sub-station and the station transformer losses within the sub-station shall not be accounted for under the Transmission Losses:
Provided further that the energy consumed for supply of power by the transmission sub-station to the associated offices of the Licensee, its housing colony and other facilities, and for construction works at the sub-station, shall not be considered as energy consumed by the auxiliary equipment of a transmission sub-station.
MSEDCL Suggested that, for calculation of yearly InSTS Grid loss needs to be reviewed and may be brought in line with the methodology adopted at regional level i.e. weekly InSTS Grid loss may be computed and drawl schedule of Transmission system users (TSUs) shall be prepared considering the transmission losses of the week preceding the last week. Further, MSEDCL submitted that, the drawl of Intra State generators for running in condenser mode (Reactive energy compensation) for the system requirement needs to be accounted as transmission loss and shall not be added in the drawl of beneficiaries of such generators.
The Commission notes the suggestion of MSEDCL that the drawl of Intra State generators for running in condenser mode (Reactive energy compensation) for the system requirement needs to be accounted as transmission loss and shall not be added in the drawl of beneficiaries of such generators. The Commission is of the view that, this issue is related to Energy account and Reactive power management. The MSEDCL may refer this issue to DSM Working Group constituted by the Commission for DSM implementation. The DSM working Group may discuss and also review the practices followed by the RLDC for accounting of active energy consumed by generators operating in synchronous condenser mode or synchronous capacitors operating in the InSTS system for reactive power management and suggest the Commission appropriately.
Further, the Commission in the Draft MYT Regulations 2024 has already specified that the energy losses in the intra-State transmission system shall be determined by the State Load Despatch Centre. Thus, the methodology for calculation of yearly InSTS Grid loss shall be taken up by MSEDCL to MSLDC separately.
No changes in provision of draft MERC MYT Regulations, 2024.
88.3 The Commission may direct the Distribution Licensee to file separate Petitions for determination of Tariff for the Distribution Wires Business and Retail Supply Business.
Provided that the Commission may require the Distribution Licensee to file separate Petitions for determination of Tariff for specified geographic area out of its Licence Area of operation for Distribution Wire Business and Retail Supply Business for catering to consumers within such specified geographic area in case there are more than one distribution licensee hold licence to distribute electricity within such geographic area.
AEML SEEPZ Limited and AEML submitted that, the Ceiling Tariff mechanism should not be adopted in the present Control Period. In case the provisions are implemented as proposed, the Regulation 88.3 must clarify that separation of ARR will be a mandatory requirement for areas where Retail Supply businesses of the competing distribution licensees operate under Ceiling Tariff, with no true-up.
MSEDCL requested to allowed sufficient time to submit separate accounting statements for two business in the next control period. The Commission may be issuing a detailed guidelines for the allocation of wire and supply business in case of implementation of the provision of the Ceiling Tariff. It was further submitted that if such separate petition is allowed, the revenue gap may be trued up every year.
The provision of the implementation of the Ceiling Tariff has been modified and shall be implemented by the Commission based on the amenable conditions provided under the applicable Regulations. With regards to provision of filing separate petition for wire and supply business, was also specified in the MERC MYT Regulations 2019. The Commission may direct the Distribution Licensee to file a separate Petition for wire and supply business as per the requirement. The Commission under the relevant Regulations for Ceiling Tariff may specify the detailed procedure for the implementation of the 'Ceiling Tariff'. The guidance for the separation of the Wires and Retail Supply accounts shall be provided under such detailed procedure.
No changes in provision of draft MERC MYT Regulations, 2024.
“.....
Provided further that the Wheeling Charges shall be determined separately for LT voltage, HT voltage, and EHT voltage, as applicable: .....”
Indrayani Ferrocast Pvt Ltd, Sant Gyaneswar Steel Pvt Ltd, Nilanjan Iron Pvt Ltd, Minakshi Ferro Ingots Pvt Ltd, Roop Rajat Pvt Ltd, Arya Steel Rolling (I) Pvt Ltd, and others has suggested modify Regulation 90.2 of draft Regulation, 2024 to determine the voltage level wise wheeling charges as against only LT or HT or EHT voltage wise as proposed in the draft Regulations. By placing all HT consumers in one basket, Regulation 73.2 shall discriminate against the consumers by substantially increasing the wheeling charges for HT Consumers who received power at HT like 33 kV or 22 kV whereas reducing the wheeling charges for 11 kV. The said Regulation is contrary to the Provision of Section 42(2) and Section 45(4) of Electricity Act, 2003 by placing entities procuring electricity at different voltage in same class. The Regulation 73.2 is contrary to the judgment of the Hon'ble APTEL in M/s Ispat Industries Limited v/s MSEDCL & Others - Appeal No 13 of 2010, Appeal no 198 of 2010 and Appeal No 42 of 2011 order dated July 26, 2012.
The Commission is of the view that the Wheeling Charges are not dependent only on the asset base at the respective voltage level but also depends on factors like feeding voltage level, demand and energy handled. For determination of voltage level wise wheeling charges the utilities are required to maintain the voltage category wise assets data, and other components of the ARR.
Currently no such data is being maintained by the utilities. In the absence of such voltage level wise data, the Commission intends to determine separate Wheeling Charges for EHT, HT and LT voltages, uniformly for all the Distribution Licensees, and has accordingly specified the same in the draft MYT Regulations, to ensure consistent approach in determining Wheeling Charges for all Distribution Licensees.
No changes in provision of draft MERC MYT Regulations, 2024.
Prayas Energy submitted to reduce the skewness and to increase accountability for delay and cost-overruns in capital expenditure. It is required that, detailed capital investment plans be specified on a circle basis. Investments required at the utility level can be reported separately but should include details of all works towards addition/ strengthening of networks mentioned in the plan. Network strengthening in areas with poor performance in supply quality indicators or high R&M requirements should be prioritized.
The capital investment plans should also consider increased network requirements due to open access, captive, grid interactive RE and increased embedded generation. The Commission and the DISCOM can also identify areas in each circle where open access/captive/net metering or billing was constrained due to issues with network capacity and incorporate works to address them. The approved plan for 5 years is trued-up at the end of the control period. However, progress of ongoing works should be reported every quarter on the licensee's website. Mumbai Discoms might be exempted from circle-wise reporting.
The suggestions of the Prayas Energy are mainly related to the capex planning and execution of the capex projects. The Commission has notified separate Regulations MERC (Approval of the Capital Investment Schemes) Regulations, 2022 for approval of the Capital Expenditure and Capitalisation of the Schemes proposed by the utilities. Hence, the scope of the suggestions made by PEG are very limited in this present MYT Regulations and the same is more specific for approval of the Capital Investments and allowing the actual expenditure during tariff proceedings by undertaking due diligence of the capitalisation proposed by the utilities as against the approved capex projects.
No changes in provision of draft MERC MYT Regulations, 2024.
MSEDCL has submitted that, the Commission has linked O&M expenses with GFA and Consumer Base. However, the given norms are decreasing over the years. Further, the draft norms have been linked to 1% efficiency factor, however, as per the MERC (MYT) Regulation, 2019, such linkage to 1% efficiency factor is based on the increase in consumer base, which was more than 2% in the past years. Hence, the same shall not be considered while finalising the norms. The O&M Expenses calculated for the 5th Control Period is lower than the O&M Expenses calculated based on norms stipulated under MERC (MYT) Regulations, 2011 and 2019. Most of the States have linked to norms to sales, GFA, etc. and further escalation with linked to CPI and WPI. Hence, normative O&M Expenses increases every year. Hence, MSEDCL has requested the Commission to revise the norms reflecting the actual O&M Expenses for the 5th Control Period. MSEDCL further submitted that assets created out of consumer
contribution, grants, etc. are also require periodical maintenance. Therefore, regulatory GFA shall not be considered while computing O&M and actual GFA maintained in the accounts of MSEDCL shall be consider for the computation of normative O&M expenses.
In addition to the above, MSEDCL submitted to consider only A&G and R&M Expenses at the time of true-up sharing of gains/losses, since, employee expenses increase based on the State Government's notifications, hence, uncontrollable in nature. Further, the actual R&M expenses booked during the past years are in the range of 12-15%, hence, maintaining 20% of R&M Expenses is not feasible for MSEDCL. Thus, actual R&M Expenses shall be considered at the time of true-up and minimum restrictions shall be removed.
With regards to the Wage Revision, MSEDCL submitted that, the wage revision (pending to be released for past years and upcoming in future years) is nowhere getting accounted in the norms specified by the Commission. Wage revision is a periodic activity which certainly not in control of MSEDCL. It is submitted that the impact of wage revision can never be accounted in the norms of O&M expenses and therefore it is requested to treat wage revision as a separate expense as and when it occurs in the audited accounts of MSEDCL. Hence, impact of wage revision shall be treated as uncontrollable factor and shall be allowed on actuals while truing up. Further, the impact of wage revision shall be approved in employee expense as per actuals at the time of true-up.
Tata Power submitted that, retain the practice of specifying the principles for determination of normative O&M expenses for the Distribution wires business. It is suggested that the respective data of GFA and Consumer base for the Wires Business and Supply Business should be considered, rather than the combined GFA and consumer base. The final O&M norm is specified to be multiplied with the average GFA and number of consumers for each year of the next MYT Control Period, hence, the O&M expenses as % of GFA and per 1000 consumers should also be considered on average basis, rather than on opening or closing basis. It is submitted that, to consider the escalation rate of 5.86% approved in the recent MTR Orders for FY 2023-24 and FY 2025-26, for the next Control Period also or 5.25 % as considered by the CERC, in its Tariff Regulations, 2024. With regards to Wage Revision, it is submitted that, impact of the subsequent Wage Revision will not be addressed merely by the escalation factor and has to be allowed separately and thus requested the Commission to accept this rationale and allowed the same separately in the MERC MYT Regulations, 2019 and the same practice may be retained.
AEML requested that, while determination of O&M Norms, the Commission should consider Gross GFA (inclusive of assets funded through consumer contribution) for working out the norms. Further, the norms so worked need to be multiplied with the gross GFA only to determine the GFA component of O&M expenses. The O&M norms for both Distribution Wires and Distribution Supply must provide for an Inflation Factor to represent year on year growth, similar to the way inflation factor is provided in case of transmission O&M norms. The normative O&M of both Distribution Wires and Supply businesses need to redetermined at the time of true-up based on actual gross GFA and actual consumer numbers, and then actuals
to be compared with the same. AEML further requested the Commission to consider the impact of wage revision separately.
BEST proposed to change the philosophy of arriving at Normative O&M expense. As per the proposed norms, the normative O&M for FY 2021-22 worked out to be Rs.55 Crores which is lower than the actual O&M expenses approved for BEST. Further, BEST will be availing 60% grant for improvement of distribution infrastructure through RDSS of Ministry of Power, GoI. Due to this, the Growth in GFA will not be significant thereby affecting the Normative O&M. The Grant to be availed is only towards CAPEX not covering the O&M expense for maintaining these assets. Hence, it is suggested to consider the booked GFA for arriving at Normative O&M expenses. BEST further requested the Commission to consider the impact of wage revision separately
GEPL, KRCIPPL, MBPPL, and NUPLLP requested to continue with the earlier approach of determining O&M expenses based on WPI: CPI method, where inflation is getting controlled. O&M expenses for SEZ area where CAPEX is limited, the GFA will remain constant or slight increase in GFA, whereas the O&M cost including employee cost and A&G cost will increase due to inflation. Further, the wage revision component should be treated independently, as in previous MYTs, and not included as part of O&M expense.
Jawaharlal Nehru Port Authority and Juridical Institute of Power submitted that, all DDL (SEZs) have very small consumer base around 20 to 50 consumers, thus benchmark should be 10 and not 100. it is also submitted that, the SEZ have substantial consumption out of small consumer base and the O&M required is for larges infrastructure due to consumption through consumer are less. It is also submitted that 5-year time continued as the O&M expenses do not change with time, it has fixed pattern.
Maharashtra State National Electrical Worker Federation requested the Commission to consider the salary & salary revision in the administrative budget and direct the utility accordingly. It has further requested to allow pay scale revision along with pension in the ARR, since the pay revision is based on the experience and inflation rate in the interval of 5 years corresponding to Central and State Government.
Prayas Energy Group suggested that O&M expenses be estimated on a circle-wise basis for MSSEDCL. Common and administrative costs should be apportioned on a pro-rata basis. This exercise should be completed and required data should be submitted within six months such that it can be used during the tariff determination process for estimation of costs. Separate O&M norms for ten circles which require the most attention.
For the ten circles with the least network and consumer density and with significant issued of network availability, the O&M norms applicable should be 2% higher than the norm for the rest of MSSEDCL. The additional amounts allocated due to 2% higher O&M norm for these 10 circles should be spent in these circles and cannot be used in any other circles. Regulations should specify that R&M expenses should account for at least 20% of O&M expenses in each circle.
For smart meters cost passthrough, Prayas Energy Group submitted that, the smart meter rollout plan (for the next five years) for each circle should be provided to the Commission for approval through a public process before the roll-out is initiated. The metering plan submitted by the AMISP, additional requirements as well as monthly progress reports submitted by the AMISP (regarding installation of meters, SLA performance reports etc) should be submitted to the Commission. An aggregate annual report based on the AMISP reports should be shared on the ERC website.
The claimed/ targeted benefits from smart metering need to be clearly established through baseline studies. The Commission should specify a rigorous methodology for assessing the realisation of claimed benefits. Regulatory scrutiny of realised benefits should take place through a public process given the scale of investments and potential tariff impact. The cost passthrough will be contingent on meeting the target benefits and only on the basis of the performance of the smart meters (this should include all performance parameters of the program).
The Commission has retained the output based methodology proposed for computation of O&M charges in the Draft MYT Regulations, 2024. However, the Commission has noted the submissions of the stakeholders of lower recovery of the O&M Expenses as compared to the norms derived in MYT Regulations, 2019. In order to address the concerns of the stakeholders, the Commission has first estimated the O&M Expenses for the 5th Control Period by escalating the actual approved O&M expenses of FY 2021-22 (post sharing of gains and losses) with actual 5 years average of CPI: WPI having the ratio of 70:30 upto the Base Year i.e. FY 2024-25. Such derived normalised for base year O&M and then further escalated over the 5th Control Period with the inflation rate of 5.33% and post adjustment of the 1% efficiency factor.
The Commission, while specifying the O&M expense norms, has calculated the escalation rate that is used to escalate the O&M expenses for the period FY 2024-26 to FY 2029-30, based on the CPI and WPI data as available till March 2023. As the actual data till the third quarter of FY 2023-24 was available, the same has been considered for computing the escalation rate. The average increase in WPI for 2019-20 to 2023-24 (till December 2023) works out to 4.93%, while the CPI for the same period works out as 5.73%. Considering the 70:30 weights for CPI and WPI, respectively, the escalation rate works out to 5.33% for the Distribution Licensees.
The estimated O&M Expenses for each Distribution Licensee for the respective years of the 5th Control Period are then allocated in the ratio of 65:35 to Wires and Retail Supply Business. Such allocated O&M Expenses respective to Wires and Retail Supply Business are then linked with the approved average GFA and Closing Number of Consumers for FY 2024-25 over the 5th Control Period without any growth rate as advance estimation of the GFA and consumer growth may not be realistic. In the case of Wires Business, the allocated O&M Expenses are linked with the Average GFA and Number of Consumers in the ratio of 90:10, respectively, while in the case of Retail Supply the ratio changes to 10:90.
Further, with regards to the submission of a few stakeholders to consider the GFA booked as per the annual audited accounts, which includes the GFA booked under Grants and Consumer
Contribution, instead of approved GFA in the Tariff Order, the Commission is of the view that, such a trajectory of GFA inclusive of Grants and consumer contribution is not being separately maintained. Hence, at the time of the Tariff Petition, the Distribution Licensee shall submit the detailed break-up of the GFA funded through Debt, Grant and Consumer Contribution duly certified by the Auditor and the books of account for the respective years, while estimating its O&M Expenses based on the Proposed Norms.
As submitted by Tata Power, in the case of Wires Business, the Commission in the Draft MYT Regulations, had considered a complete consumer base i.e. (Direct + Changeover) for estimating the O&M norms, since the details of the actual Direct Consumers for the respective years from FY 2017-18 to FY 2021-22 was not available. The same has been provided as part of the suggestions and accordingly, the wires O&M norms for Tata Power are estimated considering its Direct consumers, whereas the remaining Changeover Consumers of Tata Power are considered on AEML's wires (i.e., AEML Consumers + Changeover Consumers of Tata Power).
With regards to the restriction of 20% O&M Expenses to R&M Expenses, the Commission has decided to continue and retain the proposed provision, to ensure that, Distribution Licensees shall spend enough funds on R&M without diverting to other heads of O&M expenses like employee expenses and A&G expenses. The optimum R&M expenses are essential to maintain the quality of supply to consumers. Hence, the Commission has continued the restriction of minimum 20% O&M Expenses to R&M Expenses.
With regards to the wage revision, the Commission has noted the submission of the various stakeholders. The Commission clarifies that, the impact of wage revision which was approved by the Commission separately and pertaining to that year has been considered while considering the past period O&M Expenses while deriving the norms. The Commission is of the view that, the wage revision is part of employee expenses and shall be treated as controllable factor and compared vis-à-vis normative O&M expense.
Further, the Commission shall consider the impact of arrears of wage revision, if any, booked as part of employee expense in any particular year separately and shall be normalised annually over the Control Period and shall be treated under sharing of gains and loss for the purpose of true-up of O&M expense of respective years.
Further, with regards to the suggestion of the PEG for circle wise estimations of O&M Expenses, utilities are required to maintain the circle wise data. The suggestion of PEG can be considered in the future period.
In view of the above the Commission has modified the Regulations as under:
“ .....
93.2 .....
| MSEDCL | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
|---|---|---|---|---|---|
| O&M (% of Average GFA - Wires) | 9.66% | 10.10% | 10.55% | 11.03% | 11.52% |
| O&M (INR Lakhs/'000 Consumers) | 2.16 | 2.25 | 2.35 | 2.46 | 2.57 |
| TPC-D | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Wires) | 5.16% | 5.40% | 5.64% | 5.89% | 6.16% |
| O&M (INR Lakhs/'000 Consumers) | 9.72 | 10.16 | 10.62 | 11.09 | 11.59 |
| AEML-D | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Wires) | 9.56% | 9.99% | 10.44% | 10.91% | 11.40% |
| O&M (INR Lakhs/'000 Consumers) | 3.23 | 3.38 | 3.53 | 3.69 | 3.85 |
| BEST | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Wires) | 14.43% | 15.08% | 15.76% | 16.46% | 17.20% |
| O&M (INR Lakhs/'000 Consumers) | 4.43 | 4.63 | 4.84 | 5.06 | 5.28 |
| MBPPL | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Wires) | 5.91% | 6.18% | 6.45% | 6.74% | 7.05% |
| O&M (INR Lakhs/'00 Consumers) | 25.02 | 26.14 | 27.32 | 28.54 | 29.83 |
| GEPL | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Wires) | 4.67% | 4.88% | 5.10% | 5.33% | 5.57% |
| O&M (INR Lakhs/'00 Consumers) | 17.84 | 18.64 | 19.47 | 20.35 | 21.26 |
| KRCIPPL | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Wires) | 1.94% | 2.02% | 2.12% | 2.21% | 2.31% |
| O&M (INR Lakhs/'00 Consumers) | 8.14 | 8.51 | 8.89 | 9.29 | 9.71 |
Provided that in case of the Distribution Licensee or the Deemed Distribution Licensee tariff is yet to be determined by the Commission till coming into force of these Regulations, the Commission may determine the O&M Norms on case-to-case basis.
93.3. Wage revision, if any, during the Control Period, shall be treated as part of employee expense as controllable parameter and compared vis-à-vis normative O&M expense. Hence, the impact of arrears of wage revision, if any, booked as part of employee expense in any particular year, shall be normalised annually over Control Period and shall be subject to treatment as per sharing of gains and loss as per Regulation 11 for the purpose of true-up of O&M expense of respective years, subject to prudence check.
.....
103.2.
.....
| MSEDCL | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Retail Supply) | 5.20% | 5.44% | 5.68% | 5.94% | 6.20% |
| O&M (INR Lakhs/'000 Consumers) | 10.44 | 10.91 | 11.40 | 11.92 | 12.45 |
| TPC-D | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Retail Supply) | 3.26% | 3.40% | 3.56% | 3.72% | 3.88% |
| O&M (INR Lakhs/'000 Consumers) | 11.39 | 11.90 | 12.43 | 12.99 | 13.57 |
| ------------------------------------------- | -------------- | -------------- | -------------- | -------------- | -------------- |
| AEML-D | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Retail Supply) | 7.66% | 8.01% | 8.37% | 8.74% | 9.13% |
| O&M (INR Lakhs/'000 Consumers) | 19.33 | 20.19 | 21.10 | 22.05 | 23.04 |
| BEST | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Retail Supply) | 4.51% | 4.71% | 4.93% | 5.15% | 5.38% |
| O&M (INR Lakhs/'000 Consumers) | 39.47 | 41.24 | 43.09 | 45.03 | 47.05 |
| MBPPL | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Retail Supply) | 7.00% | 7.32% | 7.65% | 7.99% | 8.35% |
| O&M (INR Lakhs/'00 Consumers) | 121.25 | 126.69 | 132.38 | 138.33 | 144.54 |
| GEPL | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Retail Supply) | 4.99% | 5.22% | 5.45% | 5.70% | 5.95% |
| O&M (INR Lakhs/'00 Consumers) | 86.43 | 90.31 | 94.37 | 98.61 | 103.04 |
| KRCIPPL | FY 26 | FY 27 | FY 28 | FY 29 | FY 30 |
| O&M (% of Average GFA - Retail Supply) | 4.51% | 4.71% | 4.93% | 5.15% | 5.38% |
| O&M (INR Lakhs/'00 Consumers) | 39.47 | 41.24 | 43.09 | 45.03 | 47.05 |
Provided that in case of the Distribution Licensee or the Deemed Distribution Licensee tariff is yet to be determined by the Commission till coming into force of these Regulations, the Commission may determine the O&M Norms on case-to-case basis.
103.3. Wage revision, if any, during the Control Period, shall be treated as part of employee expense as controllable parameter and compared vis-à-vis normative O&M expense. Hence, the impact of arrears of wage revision, if any, booked as part of employee expense in any particular year, shall be normalised annually over Control Period and shall be subject to treatment as per sharing of gains and loss as per Regulation 11 for the purpose of true-up of O&M expense of respective years, subject to prudence check.
.....”
MSEDCL requested to maintain the current methodology for calculating Wheeling Charges until the allocation of voltage-wise assets is finalized post segregation of Wires and Supply accounts. The implementation of Uniform Wheeling charges in a parallel licensee area would create disparity in wheeling charges for various other areas of MSEDCL. The under-recovery or over-recovery of wheeling charges shall be adjusted at the time of true-up, however, due to discontinuation of MTR petition, the settlement of under-recovery at the end of Control Period will hamper the financial stability. Hence, the wheeling charges for each utility shall be defined
separately based on its wires network and wires sales corresponding to the voltage and should align with cross subsidy principles.
Tata Power submitted that, for the purpose of computation of Wheeling Charges in Maharashtra, the term "Wheeling Sales" as metered at the delivery point, needs to be considered. It was suggested to initiate more discussion with all stakeholders so that all the pros and cons can be thoroughly disseminated, and feasible framework can be designed for implementation in the next-to-next control period. It is also submitted that, no explanation or justification for the proposed framework for determination of Uniform Wheeling Charges and Wheeling Losses, in the Explanatory Memorandum. It is also submitted that, without adequate explanation of the need for such a framework, details of how the framework will operate, and how the proposed framework is expected to help solve any problems faced in the parallel licence area served by more than one Distribution Licensee.
AEML SEEPZ Limited and AEML submitted that there is no mechanism in the existing laws, which could permit the pooling of wheeling charges of competing distribution licensees. Introduction of competition in Retail Supply Business would discourage the competition in network business. It was suggested that, instead of pooling of wheeling charges, it would be better to address the existing issues of Case 182 framework and strengthen the same to prevent wastage and duplication of network.
BEST requested to allow the settlement of wheeling charges on monthly basis amongst distribution licensees. It shall be on realised basis not on the basis of billed charges.
GEPL, KRCIPPL, MBPPL, and NUPLLP requested to not to determine Uniform Fixed Charges and Uniform Wheeling Charges for multiple distribution licensees. By giving the reference of Section 62 (3) of EA 2003, it is submitted that there is no mechanism in the existing laws which permit pooling of wheeling charges of competing distribution licensees. The SERCs may not practically determine Uniform Wheeling Charges due to reasons of difference in CAPEX, Usage of electricity on the infrastructure, employee cost for the discom, total consumption by the consumers etc. Further, it is submitted that Uniform Wheeling charges may result in under/over recovery in retail supply tariff and may affect open access.
Power Foundation of India submitted that, the networks are established to cater to different consumers and demand mix, thus cost of averaging of network as mentioned in the draft Regulations is not appropriate methodology. It is also submitted that, through such methodology recovery of surplus/deficit, in wheeling charges is not mentioned in the draft Regulation which will create Regulatory imbalance for DISCOMs and Open Access consumers.
The Commission has noted the submissions of the stakeholders and would like to clarify that, the concept of uniform wheeling charges was proposed to introduce the competition in the Retail Supply Business of the multiple distribution licensees operating in a common
geographical area of supply. Hence, in the case of adoption of the Ceiling Tariff, the licensee-specific wheeling charges or losses and other applicable charges to the consumers would defeat the purpose of promoting Competition. Further, as discussed in the Explanatory Memorandum, the proposed mechanism would ensure the complete recovery of the Wheeling ARR for the respective licensees.
The Commission while finalising the MYT Regulations has modified the conditions for provisioning of uniform wheeling charges and now shall be subject to conditions stipulated for ceiling tariff determination as and when the Commission deems it appropriate and necessary to introduce ceiling tariff. The modalities for implementation of such Ceiling tariff shall include the determination of uniform wheeling charge along with associated conditions for implementation thereof.
The entire Regulation 96 along with its provisos relating to Uniform Wheeling Charges are moved under Regulation 114 of MERC MYT Regulations, 2024.
97.1
....
“Provided further that, in case the Commission adopts the Uniform Wheeling Charge approach, for specified geographic area of supply served by more than one distribution licensee(s), the Commission may stipulate a common trajectory for Wheeling Losses in case of in accordance with Regulation 7 as part of the MYT Order on the Petition filed by the Distribution Licensee.”
Tata Power submitted, the concept of Uniform Wheeling Losses may be combined with the implementation of the Uniform Wheeling Charges, as and when all the issues are clearly understood, and a feasible framework is in place. Few modifications in the second proviso were suggested, where the term “in case of” may be deleted and the term “may” be replaced by “shall” as there cannot be a framework wherein the Wheeling Charges are uniform, but the Wheeling Losses are different.
The Commission is of the view that, the suggestion of combining the Uniform Wheeling Losses with Uniform Wheeling charges and replacement of term “may” to “shall” could be considered once there is an actual implementation of the Uniform Wheeling Charges and losses and have enough clarity of operationalising the same. Further, the Commission has removed the suggested inadvertent typing error.
The second proviso shall be replaced as under:
97---
“Provided further that, in case the Commission adopts the Uniform Wheeling Charge approach, for specified geographic area of supply served by more than one distribution licensee(s), the Commission may stipulate a common trajectory for Wheeling Losses in accordance with Regulation 7 as part of the MYT Order on the Petition filed by the Distribution Licensee.”
MSEDCL requested to consider selected AG and additional feeder data while finalising the AG Consumption norms and approval of AG sale. MSEDCL also submitted that, it will convert all AG feeders to feeder input billing mechanism in subsequent years. Hence, once all feeders were converted to feeder input billing mechanism, then actual feeders’ data shall be considered for AG sales.
AEML SEEPZ and AEML requested to clarify that the term 'Sales Forecast' does not only mean energy forecast, but it should include a forecast of category wise sales, demand and customer numbers as well.
The Commission is of the view that, the AG consumption sales estimation is case specific and dealt separately in the respective Tariff Orders of MSEDCL. MSEDCL may submit its views specific to AG consumption at the time of tariff proceedings.
Further, the present regulations are clear in terms of the requirements of Sales Forecast at consumer category levels and consistent with the Power Purchase and Load forecast for the ensuing years of the Control Period.
No changes in provision of draft MERC MYT Regulations, 2024.
GEPL, KRCIPPL, MBPPL, and NUPLLP submitted that being a Deemed Distribution Licensee, the offices are small and have few Sub-stations out including main receiving Sub-station. Except the lighting load there is no load on the Residential substations. Thus,
specifying conservation trajectory for the distribution licensees like SEZs shall be excluded from regulations. Further, addition of said provision will also increase employee cost in dealing these issues.
Prayas Energy Group suggested that 0.5% of ARR each year should be allocated for Energy Efficiency schemes. It is also suggested that a detailed list of schemes which qualify under the stipulation need to be specified.
The Commission is consistent in its approach to encourage Demand Side Management/ Energy Conservation as it help to optimise the utilities' demand and peak time power procurement. The requirement of Demand Side Management / energy conservation programs is not linked with utilities' size. All the utilities are expected to implement the DSM measures considering its benefits to the utility.
With regards to submission of PEG, the Commission is not inclined to allocate the specific provision of ARR to DSM programs. The requirement of DSM programs and its budget may vary across the utilities. It may be appropriate that utilities may plan their DSM programs as per the requirement.
No changes in provision of draft MERC MYT Regulations, 2024.
MSDCL suggested that till the time tariff are not brought to $\pm 20%$ of average cost of supply, cross subsidy surcharge shall be at actual without any ceiling.
As discussed under the Explanatory Memorandum, the Ministry of Power through its amendments to the Electricity Rules, 2022, dated December 29, 2022, provides the determination of surcharge by the Commission under Section 86(1)(a) of the Electricity Act, 2003, for the consumers seeking Open Access shall be within 20% of the ACoS. The relevant extract of the referred rule is provided as under:
“13. Surcharge payable by Consumers seeking Open Access. - The surcharge, determined by the State Commission under clause (a) of Sub-Section (1) of Section 86 of the Electricity Act, 2003 shall not exceed twenty per cent of the average cost of Supply.” (Emphasis added).
No changes in provision of draft MERC MYT Regulations, 2024.
MSEDCL requested to adopt the CEA Methodology for the computation of Distribution Loss and trajectory thereof to have uniformity in Trajectory and easier evaluation.
Tata Power required clarification on applicability of Regulation 109.2. It is submitted that Tata Power has not entered any such Agreements/Programmes with the Central/State Governments.
AEML SEEPZ and AEML submitted that at present, distribution loss is a controllable parameter- over performance or under-performance which results in efficiency gains or losses, respectively. If supply businesses will be operating under the proposed ceiling tariff, the issue that will arise is - which business-wire or supply - is responsible for controlling distribution losses and hence entitled to efficiency gains or losses.
The Commission has explained in the Explanatory Memorandum that in the present methodology, the MYT proceeding specifies the trajectory for the Distribution Losses required for the Power Purchase and Energy Balance of the Licensee, which is on an accrual basis. Whereas the Collection Efficiency, which is linked with the AT&C losses is linked to Cash Receipts. Thus, consideration of the AT&C loss trajectory for the determination of Tariff would tend to double accounting of the Commercial Loss component. Hence, the Commission has decided to continue with the existing practice of Distribution Losses trajectory. However, AT&C's loss trajectory for the MYT Control Period shall be specified in compliance with the MoP Electricity Amendment Rules, 2023 dated July 26, 2023 for the monitoring purposes in the respective Tariff Orders of the Licensees. Further, even in case the Distribution Licensees do not submit the details of its AT&C loss trajectory to either of State or Central Government under any National Scheme, still the Distribution Licensee shall propose AT&C loss trajectory for the 5th Control Period as part of its Tariff Petition.
No changes in provision of draft MERC MYT Regulations, 2024.
“...
110.2
Provided that depending on the local requirements, additional or reduced tariff could be imposed in certain areas, as appropriate:
Provided further that the recovery of Road Reinstatement (RI) charges shall commence only after the concerned asset is put to use:
Provided also that the period of recovery of additional RI Charges from the consumers of the local area shall be one year or such additional period as may be approved by the Commission in the relevant Order:
Provided also that no carrying cost shall be allowed in case recovery of additional RI Charges is spread over more than 1 year.
110.3 The retail supply tariff for different consumer categories shall be determined on the basis of the Average Cost of Supply, computed as the ratio of the Aggregate Revenue Requirement of the Distribution Licensee for the Year determined in accordance with Regulation 81, and including unrecovered revenue gaps of previous years to the extent proposed to be recovered, to the total sales of the Distribution Licensee for the respective Year.
110.4 The Commission shall endeavour to gradually reduce the cross-subsidy between consumer categories with respect to the Average Cost of Supply in accordance with the provisions of the Act: Provided that Average Cost of Supply of Retail Supply Business shall be considered for determining cross-subsidy of consumer category.
110.5 While determining the tariff, the Commission shall also keep in view the cost of supply at different voltage levels and the need to minimise tariff shock to consumers.”
AEML submitted that proposal in case of reinstatement charges is too complicated to implement. Further, there are legal issues also involved with this kind of recovery in terms of both natural justice as well as issues about unfair recovery as there can be no one to one mapping of a particular scheme with a particular set of consumer beneficiaries.
BEST submitted that, to avoid tariff shock to the consumers, it is necessary to spread the recovery of additional Road Reinstatement (RI) Charges over more than 1 year with carrying cost.
GEPL, KRCIPPL, MBPPL, and NUPLLP proposed that the Average Cost of Supply (ACoS) for the entire business should be considered, rather than solely focusing on retail supply ACoS, when calculating Cross Subsidy Surcharge (CSS) to ensure a more realistic assessment. It's noted that full open access consumers may not pay fixed charges, which can lead to a discrepancy in revenue recovery. Additionally, it's essential to recognize that fixed revenue recovery may not always align with fixed charges.
The Commission is of the view that Regulation 110.3 read with 110.4 of the draft MYT Regulations, 2024 refers to the ARR of the Distribution Licensee determined in accordance with Regulation 81 of the draft MYT Regulations, 2024, which specifies the components of ARR of Retail Supply Tariff. Further, the Commission has specified Regulation 110.5 wherein
the Commission has clarified that, while setting the tariff the Commission would take care to avoid the tariff shock.
Further with regards to RI charges, the Commission is separately dealing in the Capex Regulations while approving the proposals submitted by the utilities.
No changes in provision of draft MERC MYT Regulations, 2024.
“ ...
111.2 In case more than one Distribution Licensees are operating within the same geographic area, the Commission shall determine consumer category wise uniform Demand / Fixed Charges for all Distribution Licensee in that area:
Provided that the determination of such Uniform Demand/Fixed Charges by the Commission, shall be same for a specific consumer category across all the Distribution Licensees in that area.”
Tata Power requested to add the terms “Annual Fixed Cost of the Retail Supply Business including the fixed cost of power purchase” before the term “Contracted Capacity”. It is submitted that, since Contracted Capacity is applicable for HT categories and some LT categories, the term “Sanctioned Load” may also be included appropriately. Tata Power also submitted that, the “connected number of consumers” are not the correct parameter for the Retail Supply Business, as Fixed/Demand Charges are applicable for all the consumers to whom the Supply Licensee is supplying electricity, including consumers who are connected to the network of the other parallel licensee.
GEPL, KRCIPPL, MBPPL, and NUPLLP submitted that in case of multiple distribution licensee having uniform fixed charges, then the same will contradict the first proviso of clause 111 (1) of draft Regulations.
Power Foundation of India submitted that, the Commission must mention specific methodology for determining the uniform Demand/Fixed charges for consumer categories across all the Distribution Licensees operating within the same geographic area. It is also submitted that, the Commission not specified in the draft Regulations as to how we can have uniform Fixed charges for different and distinct DISCOMs operating in the same region when we have different parameter for each DISCOM like Power Purchase portfolio (legacy PPAs),
O&M Cost, Loan Rates, etc. All these parameters combined forms part of the Aggregate Revenue Requirement (ARR) of DISCOMs.
The Commission has noted the submissions of the stakeholders. The Commission has revised the provisions of the ceiling tariff, uniform wheeling charge and uniform demand charge appropriately. The Commission may introduce the ceiling tariff where two or more distribution licensees are operating in the parallel subject to conditions specified in the Regulations.
The appropriate Regulations are revised accordingly in the final MERC MYT regulations 2024.
112.1 The Commission in exercise to the powers conferred under second proviso of the Section 62 (1) of the Electricity Act, 2003, shall fix the maximum ceiling of tariff for the retail sale of the electricity to promote competition in case of distribution of electricity in the same area by two or more Distribution Licensees.
112.2 In case more than one Distribution Licensees are operating within the same geographical area, the Commission shall determine 'Ceiling Tariff' in that area of supply within three years from the date of operationalisation of the second distribution licensee or if the difference between Average Cost of Supply for Retail Supply Business of such licensees is less than INR 0.50/kVAh (or kWh) or any other higher number, as decided by the Commission subject to the maximum upto INR 1.00/kVAh (or kWh), whichever is earlier:
Provided that in case, the Commission decided not to introduce 'Ceiling Tariff', reasons for the same shall be recorded in the Order.
112.3 'Ceiling Tariff' shall be determined based on following methodology:
a. Uniform Wheeling Charges shall be determined as per Regulation 96 A*
b. Uniform Demand/Fixed Charges shall be decided as per Regulation 111.2.*
c. Consumer category-wise or uniform ceiling rate for Energy Charge shall be decided to ensure that approved Retail Supply Aggregate Revenue Requirement of respective Distribution Licensee shall be recovered without creating revenue gap of more than 10% or any other number decided by the Commission by considering the approved sales forecast for that Distribution Licensee.*
d. Energy Charge for certain category of consumers which requires to be provided with lower tariff, shall be fixed by the Commission and licensee shall levy same tariff to such consumer category:
Provided that to maintain level playing field, parallel licensees in that area shall endeavour to maintain proportion of sales of such consumer categories in its total sales for a given month equal to proportion of total sale of such consumer categories in total sales in that area.
Provided further that in case any Distribution Licensee not able to maintain such proportion of sales of such consumer categories then it shall pay for quantum of such lower proportion 'at the rate of prevalent cross-subsidy for such consumer category (i.e. difference of Average Billing Rate and Average Cost of Supply of licensee with higher proportion of sale of such consumer category)' for such consumer category to other parallel Distribution Licensee who has higher proportion of such sales on monthly basis.
Provided that Distribution licensee may revise such 'Energy Charge' on quarterly basis to factor in variation in power purchase expenses:
Provided further that during 'Ceiling Tariff' situation, Distribution Licensee may undertake new power procurement without seeking prior approval of the Commission.
Provided further that under 'Ceiling Tariff' circumstances, Distribution Licensee shall incorporate $Z_{FAC}$ in their Energy Charge.
112.4 Based on above principles, the Commission in its Tariff Order granting 'Ceiling Tariff' shall laydown detailed procedure for the implementation of the 'Ceiling Tariff'.
MSEDCL submitted that, the Commission in its Draft Regulation has only taken care of the compensation of cross subsidy of subsidized consumers only in the parallel license area. It is requested that, the clause in case of MSEDCL on similar lines may be extended to consumers of entire state and the recovery of the cross-subsidy amount for all such consumers in the State may be done from the parallel licensee in particular area of supply. The recovery of loss of Cross-Subsidy in the parallel license area shall be allowed and mechanism shall be provided in this regulation.
AEML SEEPZ and AEML submitted that there are a lot of issues still need to be thought through with respect to tariff setting in competition. Changes of this magnitude, if implemented in a half-hearted manner, will only be counterproductive. AEML recommended that the existing mechanism of regulated tariff may continue with changes in network development framework to ensure no duplication. At the same time, a consultative process for Ceiling Tariff may be separately initiated.
GEPL, KRCIPPL, MBPPL, and NUPLLP requested that a detailed methodology for arriving at Ceiling Tariff ought to be given in the Regulations. They submitted that draft Regulations only mention the broad aspects of Ceiling tariff. However, the basic methodology of how to arrive at a Ceiling Tariff itself is not given in the Regulations i.e. whether Ceiling Tariff shall be the lower of the two Retail ACoS or higher or any other methodology. The only indication in this regard, from the draft Regulations, is that Ceiling Tariff shall be set such that it does not leave a revenue gap of more than 10%.
GEPL, KRCIPPL, MBPPL, and NUPLLP requested that not to determine Uniform Fixed Charges and Uniform Wheeling Charges for multiple distribution licensees. By giving the reference of Section 62 (3) of EA 2003, it is submitted that there is no mechanism in the existing laws which permit pooling of wheeling charges of competing distribution licensees. The SERCs may not practically determine Uniform Wheeling Charges due to reasons of difference in CAPEX, Usage of electricity on the infrastructure, employee cost for the discom, total consumption by the consumers etc. Further, it is submitted that Uniform Wheeling charges may result in under/over recovery in retail supply tariff and may affect open access. The incumbent distribution licensee may have inherent advantage of having higher proportion of sales and gradually the consumers may shift to the New Distribution Licensee. Hence sharing such cross subsidy will be detrimental to old Distribution Licensee.
GEPL, KRCIPPL, MBPPL, and NUPLLP submitted that the regulation 112.3(f) provides that the supply business shall incorporate ZFAC in their Energy Charge, but there is no clarity on implementation of the same in the regulations.
Power Foundation of India submitted that, the Commission has to mention the reasoning for capping the difference between ACoS for retail supply Business of licensees up to Rs 1.00/kVAh. It is also submitted that, the Commission needs to mention in the regulation as to how we can have a ceiling tariff for different and distinct DISCOMs operating in the same region when we have different parameter for each DISCOM like Sales mix, Power Purchase portfolio, cost of supply, revenue recovery, etc. It is also submitted that formulation of Ceiling Tariff should be executed in such a way that it promotes Competition in distribution sector promoting different DISCOMs to supply electricity in a particular region. But such competition should take care of the recovery of existing cost of legally enforceable different & distinct Power Purchase Agreements of multiple DISCOMs operating in the same region. Since, Ceiling Tariff is arriving out by aggregating / considering the costs of all DISCOMs operating in a particular region i.e., Power Purchase Cost, O&M Cost, Financing Cost, Depreciation, Return on Equity etc.
Tata Power submitted that, the proposed framework for Ceiling Tariff determination does not appear to be practical in the way it is proposed. Tata Power submitted to several concerns such as on condition for introducing ceiling tariff, Methodology for determining Ceiling Tariff for Parallel licence areas, tariff determination for subsidised categories, Energy Charges lower than Ceiling Energy Charge, True up in case of Ceiling Tariff, and it is submitted to require the clarification on those issues.
The Commission notes the submission of stakeholders on the issue of the introduction of the Ceiling Tariff and modalities for the introduction of the same. The introduction of uniform wheeling charge and ceiling tariff shall be subject to the conditions as outlined under earlier paragraphs. The Commission has noted the objections about the creation of the regulatory asset and removed the conditions that lead to an interpretation of the creation of the regulatory asset, which is not the intent of the Regulations. The Commission at the time of MYT Order or MTR Order, may review the conditions specified under the relevant Regulations and if it finds it favourable for the implementation of the Ceiling Tariff, the Commission may determine the uniform wheeling charge and uniform demand charges and ceiling tariff for the parallel licensees operating in that common area of supply.
The applicability of the Ceiling Tariff shall be based on the conditions defined under Regulation 112 and subject to the condition that the same would be introduced only after careful consideration of various factors and until then the Retail Supply Tariff determination even under parallel distribution licensee regime shall be based on the existing provisions of the MYT Regulations.
The provision for the applicability of the Ceiling Tariff modified as under:
“114.1. The Commission in exercise of the powers conferred under second proviso of the Section 62 (1) of the Electricity Act, 2003, may fix the maximum ceiling of tariff for the retail sale of the electricity to promote competition in case of distribution of electricity in the same area by two or more Distribution Licensees.
114.2. The Commission may determine ‘Ceiling Tariff’ upon careful consideration of various factors including but not limited to following factors such as:
114.3. On scrutiny of above factors, if it is decided to levy Ceiling Tariff, then 'Ceiling Tariff' may be determined based on following methodology:
Provided that to maintain level playing field, parallel licensees in that area shall endeavour to maintain proportion of sales of such consumer categories in its total sales for a given month equal to proportion of total sale of such consumer categories in total sales in that area.
Provided further that in case any Distribution Licensee not able to maintain such proportion of sales of such consumer categories then it shall pay for quantum of such lower proportion 'at the rate of prevalent cross-subsidy for such consumer category (i.e. difference of Average Billing Rate and Average Cost of Supply of licensee with higher proportion of sale of such consumer category)' for such consumer category to other parallel Distribution Licensee who has higher proportion of such sales on monthly basis.
Provided that Distribution licensee may revise such 'Energy Charge' on quarterly basis to factor in variation in power purchase expenses:
Provided further that during 'Ceiling Tariff' situation, Distribution Licensee may undertake new power procurement without seeking prior approval of the Commission.
Provided further that under 'Ceiling Tariff' circumstances, Distribution Licensee shall incorporate $Z_{FAC}$ in their Energy Charge.
In case more than one distribution licensees are operating within the specified geographic area out of distribution licence area, the Commission may determine uniform
wheeling charge at different voltage level for the use of distribution wires by users/consumers of distribution wire business within the same geographic area, as per the following formula:
A. Uniform Wheeling Charge for HT Consumers:
$$(INR/kVAh) = \frac{\Sigma(W_{HT1}, W_{HT2}, \dots, W_{HTn}) \times 10}{\Sigma(EW_{HT-D1}, EW_{HT-D2}, \dots, EW_{HT-Dn})}$$
Where,
$W_{HTn}$ = ARR of the $n^{th}$ Distribution Wires Business pertaining to HT level in INR Crore
$EW_{HT-Dn}$ = Projected Wheeling Energy pertaining to HT level of $n^{th}$ Distribution Wires Business in Million kVAh or MkVAh.
B. Uniform Wheeling Charge for LT Consumers:
$$(INR/kWh) \text{ or } (INR/kVAh) = \frac{\Sigma(W_{LT1}, W_{LT2}, \dots, W_{LTn}) \times 10}{\Sigma(EW_{LT-D1}, EW_{LT-D2}, \dots, EW_{LT-Dn})}$$
Where,
$W_{LTn}$ = ARR of the $n^{th}$ Distribution Wires Business pertaining to LT level in INR Crore
$EW_{LT-Dn}$ = Projected Wheeling Energy pertaining to LT level of $n^{th}$ Distribution Wires Business in MU or MkVAh, as the case may be.
Provided that the Commission may stipulate the modalities for operationalisation of the Uniform Wheeling Charge and Uniform Wheeling Loss through separate Order or Practice Directions from time to time, as may be necessary.
114.4. In case more than one Distribution Licensees are operating within the same geographic area, the Commission may determine consumer category wise uniform Demand / Fixed Charges for all Distribution Licensee in that area:
Provided that the determination of such Uniform Demand/Fixed Charges by the Commission, shall be same for a specific consumer category across all the Distribution Licensees in that area.
114.5. The development of distribution wire network in case of more than one Distribution Licensee catering to the same geographic area shall be guided through competitive framework, as far as practicable and principles for development of distribution network shall be outlined through separate Order or practice directions by the Commission from time to time.
114.6. The settlement of the Uniform Wheeling Charges on monthly basis to the extent of the consumers wheeling energy from the wires of the other Distribution Licensee, shall be ensured amongst the Distribution Licensees.
114.7. Provided that in case of under-recovery or over-recovery by either of the Distribution Licensees shall be adjusted at the time of truing-up, subject to prudence check.
114.8. Based on above principles, the Commission in its Tariff Order granting 'Ceiling Tariff' shall laydown detailed procedure for the implementation of the 'Ceiling Tariff'."
"113.1 The Time-of-Day Tariff shall be applicable to all the Distribution Licensees operating in the State from the date of issuance of the MYT Tariff Order for the Control Period.
113.2 Distribution Licensee shall propose ToD tariff for its consumers with load of 10 kW and above based on following indicative time slots and tariff as percentage of Energy Charge:
| ToD Tariff (Additional Charges or (Rebate) in INR/kVAh (or kWh) | ||||
|---|---|---|---|---|
| 09:00 to 16:00 Hrs |
16:00 to 20:00 Hrs |
20:00 to 00:00 Hrs |
00:00 to 06:00 Hrs |
06:00 to 09:00 Hrs |
| 80% of the normal rate of Energy Charge | 120% of the normal rate of Energy Charge | 110% of the normal rate of Energy Charge | 80% of the normal rate of Energy Charge | 110% of the normal rate of Energy Charge |
Provided that Distribution Licensee may proposed seasonal ToD tariff in its Tariff Petition:
Provided that the Commission at the time of MYT Order proceedings may extend the applicability of the ToD Tariff to the other consumer categories after assessing the growth in the demand."
MSEDCL submitted that it has experienced the shift of peak hours in past and experienced high market prices during non-solar time slots. Thus, night rebate may be disallowed as there is marginal growth in demand during night hours (which was the purpose of such rebate) in the 4th Control Period. Further, MSEDCL will be unable to give rebate during daytime from April 2025, since the renewable energy projects under MSKVY 2.0 shall be operational after 2 years. The installation of smart meters is also expected in coming year to understand the hourly consumption patterns. Accordingly, MSEDCL will submit a Time of Day (ToD) proposal during the mid-term review petition or at appropriate stage.
Tata Power submitted that, the MOP Rules stipulate the applicability of the ToD tariff for all consumers immediately after the installation of Smart Meter, which is not incorporated in the Draft Regulations. Further, Tata Power requested the Commission to provide clarification on whether the Distribution Licensee is free to propose ToD timeslots and ToD tariffs different from the ‘indicative’ time slots.
BEST suggested to implement the proposed ToD tariff for consumers between 10 kW to 20 kW from FY 2026-27 onwards, since consumers meters under such sanctioned load does not have the ToD recording facility. The smart metering work is expected to be completed by FY 2025-26. In addition, BEST requested to increase the ToD rebate from 80% to 90% during 09:00 to 16:00 Hrs slot to ensure the full recovery of the approved Tariff.
NUPLLP submitted that, each Distribution licensee may have a different demand curve based on the nature of consumers, their business activity, and the consumption pattern. Hence, the Distribution licensee may be allowed to determine the time slot in case of different demand curve.
EON Kharadi Infrastructure Pvt. Ltd. requested to grant the exemption on ToD tariff based on consumer categories and the Distribution Licensee’s scale.
Prayas Energy Group suggested that the MYT regulations provide an enabling framework for Seasonal variation in Time-of-Day Tariffs. Slots in which incentives/ penalties will be levied (Morning and evening peak penalties, daytime rebates). Range within which incentives and penalties to be offered in each slot for the control period.
The Commission is of the view that, based on the recommendations of the ToD Study Report and in compliance to the applicable MoP Rules, a common indicative ToD Slots have been proposed in the Draft Regulation, with a liberty to the Distribution Licensee to design its ToD Tariff in similar lines with a seasonal variations and the applicability of the ToD may be extended at the time of MYT Order proceedings. However, to have more clarity an additional proviso has been added, where the Distribution Licensee at the time of MYT/MTR can propose their ToD time slots with rebate/penalty in compliance to MoP Rules.
The additional proviso is as under:
“Provided further that the distribution licensee to propose their ToD time slots with slot-wise rebate/penalty at the time of MYT or MTR Tariff filing subjected to compliance of the applicable MoP Rules.”
MSEDCL submitted that MSLDC should maintain transparency in collection and utilisation of LDC development fund. It is submitted that this fund is created on account of ARR approved for MSLDC which is collected by all beneficiaries and therefore it necessary for the beneficiaries to be aware of the balance and utilisation. MSLDC may take prior approval of the Commission before utilisation of such funds and the same may be intimated to all beneficiaries. MSLDC may submit monthly/quarterly statements of utilisation and balance corpus available in the LDC funds for ensuring transparency in the process.
The Commission notes that, the Regulation 116.5 of MERC MYT Draft Regulations 2024 has the provision that, MSLDC shall maintain separate records of the LDC development fund and maintain the year wise utilisation of funds and details of assets created out of it. These records shall be submitted to the Commission during the filing of Truing-up Petition.
No changes in provision of draft MERC MYT Regulations, 2024.
MSEDCL submitted that, RLDC fees and charges are part of MSLDC budget/ARR. Therefore, the same shall be paid by MSLDC directly to RLDC and not through MSEDCL. Therefore, MSLDC will pay monthly RLDC fees and charges to WRPC directly including any other charges raised by WRPC for Maharashtra.
RLDC Fees and Charges bills are raised by RLDC on the Regional pool participants. As per the existing practices MSEDCL is a regional pool participant, and bills are raised to MSEDCL by RLDC. Currently, MSLDC is not pool participant as it is part of MSETCL and it does not have separate PAN other than MSETCL, hence it is not possible to pay the charges along with deduction of TDS. As per current practices, the Commission is approving the RLDC Fees and Charges in the ARR of MSLDC and MSLDC is regularly reimbursing the same to MSEDCL.
No changes in provision of draft MERC MYT Regulations, 2024.
"122.1 The MSLDC shall recover the following Fees as approved by the Commission from time to time:
AEML Submitted that, re-scheduling is specifically undertaken by entities to reduce deviation, which, in turn, helps reduce deviation at State level, thereby helping the grid. Also, the re-scheduling is being undertaken through SLDC scheduling software and manual efforts to SLDC personnel are virtually not there. Thus, AEML SEEPZ and AEML requested in order to remain consistent with the practice at regional level, distribution licensees should be exempt from paying re-scheduling charges at MSLDC.
AEML SEEPZ and AEML submitted that there is a discrepancy in provisos of Reg 83.2, 121.1 and 130.1. In proviso to Regulation 83.2, POA users are not mentioned at all. In proviso to Regulation 121.1, the word “excluding” is used and in proviso to Regulation 130.1, the word “including” is used. ASL submits that these may kindly be made consistent. Ideally, POA users should not be counted as their demand is already included in the CPD / NCPD of host distribution licensee. Alternatively, the allotted capacity of POA consumers could be netted off from the CPD / NCPD of the host distribution licensee.
MSEDCL submitted that, to devise the timeline wherein due date for payment by POA consumers should be earlier than the due date for payment by discoms. MSEDCL also submitted that, Rescheduling charges of Rs. 1000 per revision shall not be recovered from TSUs as rescheduling which is not only the part of scheduling but also one of the main activity/ functions of SLDC and all it is done to preserve valuable resources as per the system condition. Further, it is also submitted that TSUs are already contributing annual fees and charges of MSLDC. However, the same may be recovered from non TSUs.
The Transmission System Users (TSUs) are already contributing to SLDC fees and charges and scheduling charges are included in the ARR of SLDC. Hence, TSUs are exempted from paying scheduling charges. However, rescheduling charges are not considered in the SLDC Fees and Charges. It is noted that, the number of revisions of schedules are sometime more than 100 during a day. Such rescheduling activities requires efforts by SLDC staff. Hence Rescheduling charges were proposed by MSLDC and same were approved by the Commission in past ARR of MSLDC. Further it may be noted that, the excess amount if any collected against Rescheduling charges, it is adjusted to ARR and overall ARR reduces to that extent.
No changes in provision of draft MERC MYT Regulations, 2024.
MSEDCL Submitted that, MSLDC shall not be incentivised as it has not been undertaking its function defined under various regulations. MSEDCL submitted that, MSLDC is not complying with provisions of the MERC DSM Regulations. Further, it is reflecting incorrect demand of MSEDCL with showing difference of State demand and Mumbai demand and therefore demand of SEZs/Railways is also included in MSEDCL's demand. MSLDC has not given T<>D interface data even after rigorous follow-up with MSLDC.
Tata Power requested to, include the timelines for issuance of Grid availability certificate/other certificates as a part of KPI for MSLDC. It is also suggested to include issuance of Grid availability certificate by MSLDC within 45 days.
The Commission in its Explanatory Memorandum to MYT Regulations 2024 has provided the rationale of introducing the performance parameters and incentive against it. The SLDC contributes significantly in reliable, secure, economic and sustainable operation of the interconnected grid formed by assets owned by diverse utilities. The evidence-based inputs from SLDC to policymakers, regulators and planners are critical for strategic decision-making at the highest level. The success of reform initiatives in the power sector largely depends on the efficiency of SLDC's internal processes. Thus, the services of the SLDC are mostly intangible, and the economic value of the interventions of SLDC in the system is widely shared among the stakeholders at large. To ensure the altruistic, ethical and frugal character of SLDC, it is desirable that the performance of the SLDC be de-coupled from commercial profits of any kind.
Considering the recommendations of the CABIL report and the proposal of the MSLDC, the Commission has framed the KPIs under each category. The proposed KPI and incentives are in line with the CERC (fees and charges for the RLDC and other related matters) Regulations
It may not be appropriate to consider any case specific example for not allowing the performance linked incentive to MSLDC. With regards to compliance of DSM Regulations, the Commission has constituted DSM Working Group to monitor the implementation of the DSM framework. MSEDCL may approach the working group if any specific issue is being faced by MSEDCL.
MSLDC is issuing Transmission availability certificates to relevant transmission companies depending on the data available with MSLDC and data being submitted by the concern utilities. The certificates are being issued regularly; hence, they need not be considered under KPIs.
Revised provision of the Performance Linked incentive is as below:
126.4 MSLDC shall be allowed to recover an incentive maximum upto 3% of its Net Annual Revenue Requirement for a performance level of 90% against the KPIs. The performance of the previous year ending on 31st March shall be considered for calculation and recovery of incentive in the year.
Provided that the incentive shall increase by 1% of Net Annual Revenue Requirement for every 5% increase of performance above 90% on a pro-rata basis.
Provided further that incentive shall be reduced by 1% on a pro-rata basis for every 3% decrease in performance level below 90%.
STU requested that, unless the Commission issues any additional specific directions to other concerned stakeholder(s), in absence of any precedence/studies entire restructuring effort would solely rely on proposed MYT Regulations and, STU will have to strive to comply with the regulations. Even though the Commission is empowered to regulate the STU, but it is also to note that the CERC is yet to lay down principles and norms for determination of fees and charges of CTUIL. The restructuring process is expected to take substantial time and to provide separate books of accounts duly audited and certified by the Statutory Auditor may be difficult immediately from start of Control Period. Further, accounts on assumption/ allocation matrix as proposed by STU and hence, the Annual Fixed Charges determined may vary vis-à-vis actual performance.
Further, STU in its capacity as a new entrant to fees and charges filling/determination exercise before the Commission it ought to be given opportunity to propose/decide and be made part of. This is more important especially when the Commission has allowed other experienced stakeholders repeated opportunities. It is requested to accept as an interim measure, to allow flexible approach towards while applying proposed Fees and Charges to STU, which is relatively new to this exercise and to provide necessary clarification on this aspect in the Regulations itself.
STU submitted that it would put its best effort in coordination with MSETCL to comply with the regulations; however, till the time complete segregation of MSLDC and STU is pending, the Commission may accept as an interim measure, accounts on assumption/ allocation matrix as proposed by STU. In case the exercise is completed in first/second year of control period, STU would endeavour to submit the audited accounts at the time of true-up.
Unlike other stakeholders where generating companies/licensees and SLDC have gained rich experience in tariff filing/determination over a period of more than a decade, STU is entirely new entrant for entire tariff exercises. Further, accounts on assumption/ allocation matrix as proposed by STU and hence, the Annual Fixed Charges determined may be vary vis-à-vis actual performance. Therefore, STU should be allowed to file MYT Petition for Fees and Charges with Mid- term review provision. Further, in case there is variation of 20% against approved ARR/Annual Fixed Charges for any respective financial year that may result in sudden, steep, and sustained increase in tariff, then STU may be allowed to file a Petition at any time during the Control Period. This will reduce the carrying cost burden.
The Commission notes the submission of STU. The major roll of STU is for planning of InSTS for whole Maharashtra wherein all other transmission licensees are also operating. In order to have efficient and reliable planning of InSTS, it is felt necessary that STU shall file Fee and Charges petition by separation from MSETCL.
The Commission is of the view that, introduction of the separation Fees and Charges for STU would initiate the process of separate accounting of STU and would lead to restructuring of STU in this control period. The Commission is aware of the implementation of MSLDC Fees and Charges and time taken for it.
Further, at national level, though the CERC has not introduced separate provisions for CTUIL's fees and charges, the CERC has issued the Order for interim arrangement. Separation of CTUIL from PGCIL has already completed. The Commission has taken step to separate out Fees and Charges for STU from MSETCL as first measure.
The Commission is of the view that, STU should function independently to deliver its planning function to address the upcoming challenges of the power sector. By introducing the separate section for STU's fees and charges the Commission has taken the first step of STU restructuring. With regards to filing a petition with MSETCL would defeat the purpose of introducing the separate section for Fees and Charges of STU.
The Commission has noted other submissions of the STU regarding filing of the Petition at the time of Mid-term review. The provision for Mid-Term Review petition other than MSEDCL had been discontinued under MYT Regulations 2024. The STU may approach the Commission at the time of MYT filing if it faces any specific issue. The Commission may take appropriate at the time of MYT proceedings.
The revised provision of the draft MERC MYT Regulations, 2024 is as below:
“Provided further that, till such time separate books accounts for STU are maintained, which shall not be later than one year from date of notification of these Regulations, STU shall submit the interim accounts based on Allocation Statement comprising assets, liabilities, revenue and expenses for STU function and its reconciliation statement with audited accounts, duly certified by the statutory auditor for the purpose of filing of MYT Petition.”
127.1 The Annual Fixed Charges to be levied by the STU shall provide for the recovery of the Aggregate Revenue Requirement of the STU for the respective Year of the Control Period, as
reduced by the amount of Non-Tariff Income as approved by the Commission and comprising the following:
....
STU submitted that all charges recovered from Distribution Licensees/MSLDC/ Open Access consumers are disbursed by STU to Transmission licensees as per the approved allocation ratio. This is a zero-sum game account. STU requested to remove the “Income from Open Access Charges, General Network Access (GNA)” part from the part of Annual Fixed charges.
The Commission considers the suggestions of STU regarding the “Income from Open Access Charges, General Network Access (GNA)” part from the part of Annual Fixed charges. Accordingly, the Commission revises the provision of “Income from Open Access Charges, GNA” to “Income from application fee from Open Access and General Network Access (GNA).”
The revised provision of the draft MERC MYT Regulations, 2024 is as below:
130.1----
STU submitted that, in case of any penalties by the STU to any party for failure to meet its obligations or damages, the same shall be allowed as pass through in ARR. Performance Linked Incentives not to be treated as non-tariff income and same should be allowed to be retained under a separate fund. The Commission may consider creating STU Development
Fund in line with MSLDC. In such case a separate Regulations on STU Development Fund may be inserted in the Regulations. Fees and penalties received towards the grant of time extension for grant of grid connectivity to InSTS not to be treated as non-tariff income and same can be allowed to be contribute fund a STU Development Fund.
The Commission has clarified in the Explanatory Memorandum that, performance linked incentives shall be part of STU's income and will be considered to reduce overall ARR. Currently, there is not any uncertain income that has been envisaged for STU similar to SLDC. Since the Commission is considering all the expenses sources of STU in the ARR, it would be appropriate to consider all the income sources also in the ARR.
Currently the Commission is not envisaging any requirement to create separate STU Development Funds like SLDC Development Fund. The Commission may consider the same at later stage if required.
No changes in provision of draft MERC MYT Regulations, 2024.
130.1(b)----
Provided that the escalation rate for FY 2022-23, FY 2023-24 and FY 2024-25 shall be computed by considering 20% weightage to the average yearly inflation derived based on the monthly Wholesale Price Index of the respective past five financial years as per the Office of Economic Advisor of Government of India and 80% weightage to the average yearly inflation derived based on the monthly Consumer Price Index for Industrial Workers (all-India) of the respective past five financial years as per the Labour Bureau, Government of India, as reduced by an efficiency factor of 1% of Average escalation factor or as may be stipulated by the Commission from time to time, to arrive at the permissible Operation and Maintenance expenses for each year of the Control Period:
MSSEDCL submitted that the ratio of WPI to CPI shall be considered at 30:70 as methodology adopted for arriving at the escalation for all Transmission Licensees. If actual O&M expenses are lower than the normative O&M expenses, the actual O&M expenses may be allowed at the time of True-up without any sharing of gains and losses.
The Commission has considered the ratio of WPI to CPI 20:80 for STU in MYT Regulation 2024 as majority cost of STU is related to manpower expenses.
No changes in provision of draft MERC MYT Regulations, 2024.
MSEDCL suggested to include any other income that is earned by the STU which is other than the business income shall be included in non-tariff income. It is also suggested, any interest income on investments made from RoE shall be included in non-tariff income and benefit of the same shall be passed on to the consumers.
The filing of Tariff Petition by STU is being considered separately under MYT Regulations, 2024 for the first time. Hence, it will be too early to decide on interest income on investment made through RoE. The Commission will take appropriate view during tariff proceedings appropriately under, "Any other non-tariff Income."
No changes in provision of draft MERC MYT Regulations, 2024.
MSEDCL submitted that, the Commission has adopted different approach in computation of Base TCR for allocation of InSTS charges and in computation of Base TCR for allocation and STU charges. Therefore, it is submitted to bring uniformity in computation of Base Transmission Rights for allocations of InSTS charges and STU charges.
The Commission has noted the comments submitted by the stakeholders. The Commission revised the approach for allocation of TTSC to long term OA users and Partial OA users. It is now linked with Billed Demand of the OA users. Similar approach is adopted sharing of STU charges and MSLDC charges by Open Access Users.
134.1 The long-term Transmission System Users shall share the STU Charges in the proportion of Adjusted Base Transmission Capacity Rights of each Transmission System User to the total Adjusted Base Transmission Capacity Rights allotted in the intra-State transmission system.
Provided that a Partial Open Access Consumer shall pay the STU Charges to the Distribution Licensee instead of the Transmission Licensee for using a transmission network which shall be passed on to the STU within the stipulated time period as specified under Regulations 14.5 of MERC Distribution Open Access Regulation, 2016 and its amendment thereof.
Provided also that the Distribution Licensee shall submit billed Open Access Demand of Partial Open Access consumers to STU and MSLDC on monthly basis for calculating Adjusted Base Transmission Capacity Rights.
132.1 STU shall submit its actual performance against each of the key performance indicators to the Commission on an annual basis along with supporting documents.
132.2 The Commission shall evaluate the overall performance of the STU, on the basis of weightage specified in the table below.
132.3 STU shall be allowed to recover an incentive of 3% of Net ARR for an aggregate performance level of above 90%. The incentive shall increase by 1% on a pro-rata basis for every 5% increase in performance level above 90% with a maximum limit of 5% of total Aggregate Revenue Requirement.
Provided that no incentive shall be payable if the performance level is below 90%.
132.4 Recovery of incentive by the STU shall be based on the achievement of the Key Performance Indicators (KPIs) as specified below or such other parameters as may be specified by the Commission.
Key Performance Indicators for STU
....”
STU Submitted that, Explanatory Memorandum does not cite any such practices/approach followed at the central level for treatment of various expense or any such activities/studies performed by Forum of Regulators or by other states. It is suggested that,
(a) to fix only 3 to 4 key parameters in this Control Period such as timely filing, planning & coordination, Open Access, raising transmission bills. This will provide STU necessary momentum to build upon necessary financial independence.
(b) STU shall be allowed to recover an incentive of 3% of Net ARR for an aggregate performance level of above 70%, 75%, 80%, 85% and 90% for each respective financial year of the Control Period. Based on performance, the Commission may cap them next Control Period.
MSEDCL submitted that the incentive of 1% of Net ARR for performance above 90% shall be allowed instead of 3%. The maximum ceiling may be kept at 3% instead of 5%. It is also submitted that STU shall be penalized if performance is not observed up to marks as per the standards set by the Commission.
Tata Power requested to include the timelines for issuance of 5-year STU Plan/prudence check as a part of KPI for STU. It is also suggested to includes following KPIs under stakeholder satisfaction in Regulation 132.4 as suggested below:
“1. Planning: Release of 5-Year STU Plan by 20th April of every year
The Commission notes the submission of the stakeholders. The Commission has revised the KPI considering the suggestions of the stakeholders. Further with regards to incentives, the Commission has reduced it to 3%. The Commission does not find any merit in reducing it to 1% as suggested by MSEDCL. The incentives for STU are being proposed in place of Additional RoE.
Regulation 136.4 of draft MERC MYT Regulations, 2024 is revised appropriately.
STU submitted that once, the proposed draft regulations come into effect from April 01, 2025, till such time revenue stream in finalized/established MSETCL will have to continue to support STU expenses. MSETCL may continue to do the same. Further, with effect from April 01, 2025, STU shall be required to maintain a separate account and once the revenue stream for STU is finalized, expenses incurred by MSETCL for STU expenses may be reimbursed with carrying cost. Requisite direction in this regard may be given by the Commission.
The Commission while instructing the STU for filing separate petition has directed STU for separation of accounts of STU from MSETCL. In the absence of separate accounts the Commission has also allowed allocation statement. The Commission expects STU and MSETCL to implement the directives of the Commission and file separate MYT Petition as per the provisions of the MYT Regulations 2024 within specified timelines. Any reimbursement or the other matters raised by MSETCL shall be decided by the Commission during MYT proceedings of the STU.
No changes in provision of draft MERC MYT Regulations, 2024.
" 134.1 The Regulations specified in this Part shall apply to the determination of Tariff for Energy Storage Systems including Pumped Storage Hydro Project.
134.2 .....
(c)where the Distribution Licensee is engaged in the business of Energy Storage of electricity, in determining the conversion price at which off-peak electricity is converted into peak electricity by the Energy Storage business of the Distribution Licensee to its Retail Supply business."
AEML SEEPZ and AEML have not clarity as to why ESS is mentioned in Part E of the Regulations, when it has a dedicated Part L for itself, which deals with all aspects of ARR and Incentives for ESS. Further, as per part E, the Regulations will only apply for ESS with capacity of 25 MW or more, but no such qualification is mentioned in Part L. It is submitted that, since Part L specifically deals with ARR and tariff determination for ESS, there is no reason to mention ESS in Part E. Further, the qualification of 25 MW or more, if intended to apply to ESS plants as well, should be mentioned in Part L, to clarify that the regulated tariff determination shall apply only to BESS plant capacities of 25 MW or higher at one location.
AEML SEEPZ and AEML requested to clarify that there is no case mentioned in the regulations where ESS is set by the Supply business as its own generating plant, under CAPEX Model. Further, the Regulations may also clarify that in case a capacity limit for regulated tariff determination for ESS is there, whether the same would apply to ESS set up at a single location, or whether capacities at multiple locations will be aggregated. Furthermore, AEML SEEPZ and AEML requested to clarify whether the ESS schemes already approved under capital expenditure plans of distribution licensees will be excluded from the provisions of Part L and Part L will only apply to ESS schemes set up on or after April 01, 2025.
STU requested to clarify what constitutes COD in case of Standalone ESS or ESS as part of generation or transmission or distribution. Further, requested to clarify if in case of a transmission licensee engaged in business of Energy Storage of Electricity, whether their ARR would form part of TTSC. How the investment will be treated, in case of a transmission licensee engaged in business of Energy Storage of Electricity for optimum utilisation of its assets (i.e., enabling optimum / higher utilization of transmission network, transmission capex deferral, etc.). Also requested to clarify if it will be treated as 'Income from Other Business' under Regulation 41. Also the Commission may clarify if in case of a generation or transmission licensee engaged in business of Energy Storage of Electricity, whether it's capital cost would be governed by the MERC (Approval of Capital Investment Schemes) Regulations, 2022. The
STU also requested to clarify if open access be granted to Standalone ESS, in case of Standalone ESS not co-located but owned and operated by generator.
MSEDCL requested to add the provision for useful life of Renewable Hybrid Energy Project with Storage as “Useful life of Renewable Hybrid Energy Project with Storage: Minimum of Useful Life of different RE technologies combined for Renewable Hybrid Energy project assuming that there is no storage.” MSEDCL suggested that change definition of Energy Storage system.
Tata Power requested for clarification regarding the applicability of Regulation 134 for the installation of BESS intended for captive use, particularly when the entity is not involved in the energy storage business. It is also submitted that, Operations and Maintenance (O&M) expenses for such cases should be structured to include the costs of charging, in addition to other relevant charges. It is requested to reconsider and revise regulation 134.2 based on above suggestions.
The Commission has noted the submission of the stakeholders. It is to clarify that, Distribution licensee can develop Energy Storage system as a part of retail supply business as specified in the Regulations. It is specified under Regulation 138.2 of the MERC MYT Regulations. Further sr. no. “S” of Regulation 3.9 of the Capex Regulations 2022 also refers development of BESS under distribution business in capex mode. However, the licensees should also note the views expressed by the Commission in Explanatory Memorandum for development of ESS through competitive bidding under Section 63 of the Act as below.
“11.11.9 The Commission would like to clarify that, though the Regulatory framework for determination of Tariff for ESS is being proposed in the Draft MYT Regulations, 2024, the Utilities take all efforts and measures to develop/procure ESS through competitive bidding guidelines under Section 63 of the Act and approach the Commission for adoption of Tariff for ESS discovered through the Competitive Bidding Process.”
The Regulations does not specify any capacity limit for ESS for tariff determination. Capacities of ESS at multiple locations can be aggregated for tariff determination purpose. The Regulations shall apply for the ESS schemes set up on or after April 01 2025. Development of ESS under Captive arrangement is not governed by the provisions of the MYT Regulations 2024. Installation of BESS intended for Captive use and their O&M charges shall not be governed by the provisions of the MYT Regulations 2024.
COD of ESS shall be as in line with Guidelines for Procurement and Utilization of Battery Energy Storage Systems as part of Generation, Transmission and Distribution assets, along with Ancillary Services issued by MOP dated 10 March 2022.
If ESS is developed as transmission assets, its ARR will be part of TTSC as it will benefit to InSTS network and ESS assets shall be treated as transmission assets. If transmission licensee develops ESS for transmission deferment it will be treated as transmission assets and it will
part of transmission ARR but GFA of ESS assets shall be treated separately for computation of ROE, interest on loan and other financial parameters. The benefits/income from ESS shall be treated as income from other businesses.
Provision of ESS is already specified in Capex Regulations and if ESS is developed under Capex provisions, its capitalisation shall be considered while determining the ARR of the utility as specified in the MYT Regulations.
As per MOP guidelines ESS assets can seek a separate connectivity, hence it is also eligible to seek Open Access to InSTS network.
With regards to query of Tata power, development of ESS under Captive arrangement is not governed by the provisions of the MYT Regulations 2024.
No changes in provision of draft MERC MYT Regulations, 2024.
Prayas Energy Group submitted that, the section 63 as a framework is best for scaling, cost-reduction and innovation required for BESS contracting by DISCOMs. So, it is suggested to delete the Regulation 137 which defines the cost-plus tariff framework for determination of BESS and suggested that BESS procurement only takes place through Section-63 in Maharashtra. AEML SEEPZ and AEML requested that Normative BESS Round Trip Efficiency for the first year may be considered as 75% for each month and then the same may be decreased by 0.5% per year. AEML SEEPZ and AEML requested that, for the next Control Period at least, the normative availability of BESS may be specified as 85%, in line with what is specified for generating stations. AEML SEEPZ and AEML requested to consider Battery Pack degradation at 2.5% per year wherein Battery capacity shall be 68% of its installed Capacity after the 12th year. It is also requested to consider Battery Pack degradation at 2.5% per year wherein Battery capacity shall be 68% of its installed Capacity after the 12th year.
AEML SEEPZ and AEML Requested to consider battery pack of BESS as separate equipment having life of 12 years with depreciation rate of 7.5% (considering 95% depreciable value).
AEML SEEPZ and AEML submits that these Regulations should therefore be reworded to clarify that Incentive of 20 paise / kWh is payable on energy supplied above 75% normative Round-Trip Efficiency.
ATIL and MEGPTCL requested that, Rate of RoE for ESS should be same as the rate of RoE for generating stations which is specified as 15.5%. ATIL and MEGPTCL submitted that the compensation structure should be fair to the ESS generating company. Even the compensation structure as per MYT Regulations 2019 is not adequate as the project cannot be financed solely
through debt. Further, equity contribution cannot be expected at the same rate as debt financing, it is well known that equity always has a higher cost.
Power Foundation of India submitted that, the Round-trip Efficiency of BESS shall be minimum 75% for each monthly operating period which is significantly lower than the global standards. It is suggested that, to consider Round-trip efficiency of BESS is 85%, as NREL 2023 ATB and GUVNL Phase-II Standalone BESS tender has considered round trip efficiency of BESS as 85%. It is also submitted that, post-tax 18% RoE for BESS appears to be on higher side as compared to 19% pre-tax RoE for Solar and Wind during (Terms and Conditions for determination of RE Tariff) Regulations, 2010 provided by MERC.
Tata Power submitted that the State of Charge should be taken into consideration instead of rated capacity. If the BESS is in discharge mode as per scheduled discharge and its State of Charge is below a certain threshold (i.e., lesser than 75 % of rated capacity), the ramp rate should be limited to 75% of the available capacity only. It is suggested consider Average Ramp Rate for BESS as 75% of rated capacity or the State of Charge (whichever is higher) /minute.
Tata Power proposed to set useful life at 10 years. It is suggested that the useful life of the Balance of System components, excluding Transformers, also be adjusted to 10 years. Tata Power submitted that, formula may modify to considered MVAh instead of MWh, in Regulation 137.11 for of BESS for Var compensation.
The Commission has clarified in Explanatory Memorandum for development of ESS through competitive bidding under Section 63 of the Act as below;
11.11.9 The Commission would like to clarify that, though the Regulatory framework for determination of Tariff for ESS is being proposed in the Draft MYT Regulations, 2024, the Utilities take all efforts and measures to develop/procure ESS through competitive bidding guidelines under Section 63 of the Act and approach the Commission for adoption of Tariff for ESS discovered through the Competitive Bidding Process.
However, the provision of determination of tariff under section 62 of EA 2003 would still continue subject due prudence check.
The Commission notes that stakeholders have provided the suggestions on the technical parameters of the ESS, however, no supporting have been provided by stakeholders while proposing the changes in the technical parameters of the ESS under Draft MYT Regulations 2024.
The Commission is proposing retain the technical parameters of the draft Regulations, however, while approving the ESS proposal, the Commission may consider the performance norms on technical parameters taking into consideration performance benchmarks as well as technological advances and views of Expert Agencies such as CEA, MNRE, Academic
Institutions or Experts engaged by Commission on case to case basis at the time of approval of ARR.
No changes in provision of draft MERC MYT Regulations, 2024.
a. The Monthly Cycle Efficiency of PSH shall be minimum 75% with respect to metering point.
....
iii. $MU_i(B)$ = Despatch Schedule provided by Distribution Licensee to PSH for Generation/Pumping in the $i$ th time block, in MUs.
a. Base Return on equity shall be computed in rupee terms on the equity base arrived under Regulation 138.4 at the rate of Eighteen Percentage (18%).
.....”
MSEDCL suggested to include the number of hours during which there has been no scheduled or actual injection or no scheduled or actual drawl in this formula to compute the correct availability of Pumped Hydro Storage Plant. The formula does not correctly indicate the availability of pumped Hydro Storage Plant.
Prayas Energy Group requested to set appropriate RoE in the range of 11-13% for PSP. The proposed base RoE is 18% which is much higher than RoE proposed for any other projects.
The Commission in draft regulations had proposed 18% ROE + additional 2% performance linked RoE for ESS. However, considering the comments received from stakeholders the Commission has revised the total RoE as 18% at the time of MYT Petition. (16%+2% linked with performance parameters)
Accordingly, RoE at 18% grossed up with effective tax approved at the time MYT projections and adjustments with linkage to shortfall in performance by way of reducing RoE upto 2.00%. The performance linked RoE shall be linked with Performance parameters defined under the regulations for the respective licensees grossed up with effective tax rate approved at the time of truing up.
With regards to availability formula, the Commission has considered the availability formula in line with the Ministry of Power's bidding guidelines for Energy storage. For overall availability of ESS, availability of ESS in pumping /charging mode and availability of ESS in generation/discharging mode both are considered.
No changes in provision of draft MERC MYT Regulations, 2024.
Tata Power suggested to add Protection Relays in Depreciation Schedule. It is submitted that Protection Relays incorporate electronic components subject to rapid technological advancements necessitating frequent replacements. It is suggested to re-draft "q" of Annexure-I and Annexure-II as suggested below:
"q. Software, SCADA system, protection relays: 30%"
The Commission has considered the depreciation schedule in line with the depreciation schedule specified by the CERC in its MYT Tariff Regulations 2024.
No changes in provision of draft MERC MYT Regulations, 2024.
Sd/-
(Surendra J. Biyani)
Member
Sd/-
(Anand M. Limaye)
Member
Sd/-
(Sanjay Kumar)
Chairperson
Annexure: I
| Sr No | Name Of Stakeholders |
|---|---|
| 1 | Rupesh Navthale |
| 2 | Indrayani Ferro cast Pvt Ltd |
| 3 | Sant Gyaneshwar Steel Pvt Ltd |
| 4 | Nilanjan Iron Pvt Ltd |
| 5 | Arya Steels Rolling (I) Pvt Ltd |
| 6 | Bharat Agrawal Power loom Charitable Association |
| 7 | Meenakshi Ferro Ingots Pvt Ltd |
| 8 | Roop Rajat Steel Pvt Ltd |
| 9 | CA Mahaveer Jain |
| 10 | Shri Karvir Nivasini Mahalaxmi Ispat Pvt. Ltd. |
| 11 | Ganaraj Ispat Pvt Ltd |
| 12 | Ambika Waste Management Pvt Ltd |
| 13 | Brihanmumbai Electric Supply & Transport (BEST) Undertaking |
| 14 | Jaigad Power Transco Ltd |
| 15 | EON Kharadi Infrastructure Pvt Ltd EON I and II |
| 16 | Amravati Power Transmission Company Limited (APTCL) |
| 17 | Sachin Choradiya |
| 18 | Bhuleshwar Steel & Alloys (P) Ltd. |
| 19 | Maharashtra State Power Generation Company Ltd (MSPGCL) |
| 20 | Krushna Bhoyar |
| 21 | Balaji Electro Smelter Pvt Ltd |
| 22 | MITC Rolling Mills Pvt Ltd |
| 23 | Prayash Energy Group |
| 24 | Adani Electricity Mumbai Infra Ltd (AEMIL) |
| 25 | Adani Electricity Mumbai Ltd (AEML) |
| 26 | AEML SEEPZ |
| 27 | Adani Transmission India Ltd (ATIL) |
| 28 | State Transmission Utilities (STU) |
| 29 | Maharashtra State Electricity Transmission Company Ltd (MSETCL) |
| 30 | Maharashtra States National Electrical Worker Federation |
| 31 | Gigaplex Estate Pvt Ltd (GEPL) |
| 32 | Graduate Engineer Association |
| 33 | Jawaharlal Nehru Port Authority |
| 34 | KRC Infrastructure & Projects Pvt Ltd (KRCIPPL) |
| 35 | Mindspace Business Parks Pvt Ltd (MBPPL) |
| 36 | Maharashtra State Electricity Distribution Company Ltd (MSEDCL) |
| 37 | New Age Markets of Energy Pvt. Ltd. (NAME) OTC Plateform |
| 38 | Nidar Utilities Panvel LLP (NUPLLP) |
| 39 | Regulatory Assistance Project (RAP) |
| 40 | Juridical Institute of Power |
| 41 | Tata Power Company Ltd (TPC) |
| 42 | Maharashtra Eastern Grid Power Transmission Company Ltd (MEGPTCL) |
| 43 | Maharashtra Rajya Magasvargiya Vidyut Karmachari Sanghatan |
| 44 | Jalgaon Industries Association |
| 45 | Union of Chemist |
| 46 | Khandesh Industrial Development Association |
| 47 | Ekvira Alloys Pvt Ltd |
| 48 | Power Foundation of India (PFI) |
| 49 | Kaygaon Paper Mills Pvt Ltd |
| 50 | N. Ponrathnam |