ELECTRICITY ACT, 2003.
No. MERC/Tech/Regulation/2024/0512.— In exercise of the powers conferred by clause (h), (i), (j), (l), (m), (o), (y), (zd), (ze), (zf), (zg), (zh) and (zp) of sub-section (2) of Section 181 read with the proviso to sub-section (1) of Section 36, sub-clause (ii) of clause (d) of sub-section (2) of Section 39, second proviso to sub-clause (ii) of clause (d) of sub-section (2) of Section 39, sub-clause (ii) of clause (c) of Section 40, second proviso to sub-clause (ii) of clause (c) of Section 40, first proviso to Section 41, first proviso to Section 51, Section 61, sub-sections (2) and (5) of Section 62, sub-sections (1) and (3) of Section 64, Section 65 and clause (b) of sub-section (1) of Section 86 of the Electricity Act, 2003 (36 of 2003) and all other powers enabling it in that behalf, the Maharashtra Electricity Regulatory Commission hereby makes the following Regulations. These Regulations supersede the Maharashtra Electricity Regulatory Commission (Multi Year Tariff) Regulations, 2019 as amended from time to time.
Provided that issues relating to determination of Aggregate Revenue Requirement and Tariff, review matters pertaining to the period till March 31, 2025, shall be governed by the provisions of the “then MERC Tariff Regulations” applicable at that point of time.
2.1 In these Regulations, unless the context otherwise requires:
Provided that separate Accounting Statements shall be prepared and submitted to the Commission for each licensed business in accordance with the Licence conditions, and for each regulated business:
Provided further that, in case separate Accounting Statements are not submitted for each licensed business in accordance with the Licence conditions and for each regulated Business for the Financial Year (FY) 2025-26 onwards, the Petitions filed by the Generating Company or Licensee or MSLDC or STU or ESSD, may be rejected by the Commission after giving the Petitioner a reasonable opportunity of being heard:
Provided further that the Generating Company or Licensee or MSLDC or STU shall submit the Statutory Auditor's comments, observations and notes to Accounts, along with the Accounting Statements, and a summary of the key issues highlighted by the Statutory Auditor and the steps taken to address them:
Provided also that, in respect of a Local Authority engaged in the business of distribution of electricity, the Accounting Statement shall mean the items mentioned above as prepared and maintained in accordance with the relevant statutes applicable to such Local Authority:
Provided also that till the MSLDC and STU remains a part of it, separate books of accounts for MSLDC and STU shall be maintained by the Maharashtra State Electricity Transmission Company Limited and shall be audited and certified by the statutory auditor:
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;
or Distribution Licensee undertaken for optimum utilisation of its assets, showing the amounts of any revenue, cost, asset, liability, reserve or provision, etc., which has been charged from or to each such other business together with a description of the basis of that charge; or determined by apportionment or allocation between different businesses of the Generating Company or Licensee, together with a description of the basis of the apportionment or allocation:
Provided that, for the purposes of these Regulations, the licensed business of a Distribution Licensee for its area of supply would be bifurcated into Distribution Wires Business and Retail Supply Business:
Provided further that such allocation statement in respect of a Generating Station owned and/or maintained and/or operated by a Distribution Licensee shall be prepared such as to enable Tariff determination, stage-wise, Unit-wise and/or for the entire Generating Station;
Provided that in case the integrated mine(s) of coal or lignite is ready for supply of coal or lignite as per the Mining Plan but is prevented due to reasons not attributable to the Generating Company, the Commission may relax the Annual Target Quantity up to a maximum of 15% of the quantity of coal or lignite to be extracted during a year as specified in the Mining Plan:
Provided further that the quantum of relaxation of Annual Target Quantity shall be allowed in accordance with the provisions of the Coal Mining Agreements already signed by the Generating Companies before the date of notification of these Regulations;
generating Station, and shall be expressed as a percentage of the sum of gross energy generated at the generator terminals of all the Units of the Generating Station:
Provided that it shall not include energy consumed for supply of power by the generating Station to its housing colony and other facilities, and for construction works at the generating Station and integrated mine;
$$\text{Availability} = 100 \times \frac{\sum_{i=1}^N \text{DC}_i}{{N \times \text{IC} \times (1 - \text{AUX}_n - \text{AUXen})}} %$$
where - N = number of time blocks in the given period
DC = Average Declared Capacity in MW for the $i^{\text{th}}$ time block in such period
IC = Installed Capacity of the Generating Station/Unit in MW
AUX = Normative Auxiliary Consumption in MW, expressed as a percentage of gross generation:
AUXen = Normative Auxiliary Consumption for Emission Control System in MW, expressed as a percentage of gross generation:
Provided that Availability of a thermal Generating Station/Unit for any period shall not exceed hundred percent;
of transmitting electricity at its rated voltage, expressed in percentage of total hours in the given period, and shall be computed as provided in Annexure-VI to these Regulations:
Provided that Availability of a transmission system for any period shall not exceed hundred per cent
Provided that if the period of default lies in two or more financial years, the Base Rate of Delayed Payment Charge shall be calculated separately for the periods falling in different years;
transmission of electricity and / or utilise the distribution system of a Licensee in the State for wheeling of electricity and / or avail the services of the MSLDC or STU relating to scheduling and real-time grid operations, State energy accounting, operation of pool account, connectivity, GNA operationalisation, pooling and recovery of transmission charges etc.;
(16) “Block” in relation to a combined cycle thermal Generating Station includes combustion turbine – generators, associated waste heat recovery boilers, connected steam turbine – generators and auxiliaries;
(17) “Bulk Power Transmission Agreement” means an executed Agreement that contains the terms and conditions under which a Transmission System User is entitled to access to an intra-State transmission system of a Transmission Licensee;
(18) “Capital Cost” means the capital cost as determined in Regulation 24 of these Regulations in respect of generating station or transmission system or distribution system, as the case may be, and Regulation 59 in respect of integrated mine(s);
(19) “Change in Law” means occurrence of any of the following events:
a. enactment, bringing into effect or promulgation of any new Indian law; or
(20) “Charges” means payments to be collected by the Generating Company or Licensee or MSLDC or STU or ESSD for the services rendered by it;
(21) “Coincident Peak Demand” means the demand as measured at G-T interface for the Distribution Licensee occurring at the time of system peak demand for the State;
(22) “Commission” means the Maharashtra Electricity Regulatory Commission;
(23) “Competitive Bidding” means a transparent process for procurement of power, equipment, services and works in which bids are invited by the procurer by open advertisement covering the scope and specifications of the power requirement, equipment, services and works required, and the terms and conditions of the proposed contract as well as the criteria by which bids shall be evaluated, and shall include domestic competitive bidding and international competitive bidding;
(24) “Contracted Capacity” means the capacity in MW contracted by a long-term Transmission System User as part of its long-term and medium-term power procurement plan through a power purchase agreement or arrangement, and shall be equivalent to the deemed Transmission Capacity Right of a Transmission System User as specified under the Regulations of the Commission governing Transmission Open Access;
(25) “Control Period” means the period comprising five Years from April 1, 2025 to March 31, 2030, and as may be extended by the Commission;
(26) “Cut-off Date” means the last day of the financial year after thirty-six months from the date of commercial operation of the project, except in case of integrated mine(s);
(27) “Cycle Efficiency of Energy Storage System” means, the ratio of discharge capacity of ESS to charge capacity of ESS in a single cycle, regardless of the self- discharge loss of the ESS;
(28) “Day” means the 24-hour period starting at 0000 hour;
(29) “Date of Commencement of Production” in respect of integrated mine(s) means the date of touching of coal or lignite, as the case may be, as declared by the Generating Company;
(30) “Date of Commercial Operation” or “COD” in respect of a thermal generating station or hydro generating station or transmission system or communication system shall have the same meaning as provided in the MERC (State Grid Code), 2020, as amended from time to time:
Provided that;
The date of commercial operation in case of integrated mine(s), shall mean the earliest of: -
b) the first date of the year succeeding the year in which the value of production estimated in accordance with the provisions of these regulations, exceeds total expenditure in that year; or
c) the date of two years from the date of commencement of production:
Provided that on the earliest occurrence of any of the events under sub-clauses (a) to (c) of Clause (2) of this Regulation, the generating company shall declare the date of commercial operation of the integrated mine(s) under the relevant sub-clause with one-week prior intimation to the beneficiaries of the end-use or associated generating station(s):
Provided further that in case the integrated mine(s) is ready for commercial operation but is prevented from declaration of the date of commercial operation for reasons not attributable to the generating company or its suppliers or contractors or the Mine Developer and Operator, the Commission, on an application made by the generating company, may approve such other date as the date of commercial operation as may be considered appropriate after considering the relevant reasons that prevented the declaration of the date of commercial operation under any of the subclauses of Clause (2) of this Regulation:
Provided also that the generating company seeking the approval of the date of commercial operation under the preceding proviso shall give prior notice of one month to the beneficiaries of the end-use or associated generating station(s) of the integrated mine(s) regarding the date of commercial operation:
iii. the date of two years from the date of commencement of production:
Provided that on earliest occurrence of any of the events under sub-clauses (i) to (iii) of Clause (e) of this Regulation, the Generating Company shall declare the date of commercial operation of the integrated mine(s) under the relevant sub-clause with one-week prior intimation to the beneficiaries of the end-use or associated generating station(s):
Provided further that in case the integrated mine(s) is ready for commercial operation but is prevented from declaration of the date of commercial operation for reasons not attributable to the Generating Company or its suppliers or contractors or the Mine Developer and Operator, the Commission, on an application made by the Generating Company, may approve such other date as the date of commercial operation as may be considered appropriate after considering the relevant reasons that prevented the declaration of the date of commercial operation under any of the sub-clauses of Clause (e) of this Regulation:
Provided also that the Generating Company seeking the approval of the date of commercial operation under the preceding proviso shall give prior notice of one month to the beneficiaries of the end-use or associated generating station(s) of the integrated mine(s) regarding the date of commercial operation:
Provided also that the Date of Commercial Operation in case of integrated mine shall be considered in accordance with the provisions of the Coal Mining Agreements already signed by the Generating Companies before the date of notification of these Regulations;
(31) "De-capitalisation" means the reduction in Gross Fixed Assets corresponding to the removal of assets as approved by the Commission;
(32) "Declared Capacity" means, in relation to a generating Station, the capability to deliver ex-bus electricity in MW declared by such generating Station in respect of any time-block of the day as defined in the State Grid Code or whole of the day, taking into account the availability of fuel and/or water, and subject to further qualification in the relevant Regulation;
(33) "Deemed Distribution Licensee" means a person deemed to be a Distribution Licensee under Section 14 of the Act;
(34) "Depth of Discharge" A battery's depth of discharge (DoD) indicates the percentage of the battery that has been discharged relative to the overall
capacity of the battery. Depth of Discharge is defined as the capacity that is discharged from a fully charged battery, divided by battery nominal capacity;
(35) “Design Energy” in relation to a hydro power Generating Station means the quantum of energy, which could be generated in a 90 per cent dependable year with 95 per cent installed capacity of the Generating Station;
(36) “Distribution Business” means the Business of operating and maintaining a distribution system for supplying electricity in the area of supply of a Distribution Licensee;
(37) “Distribution Licensee” means a Licensee, Deemed Distribution Licensee, Exempt Licensee authorised to operate and maintain a distribution system for supplying electricity to consumers in its area of supply;
(38) “Distribution Wires Business” means the Business of operating and maintaining a distribution system for wheeling of electricity in the area of supply of a Distribution Licensee;
(39) “Detailed Project Report Scheme” (or “DPR Scheme”) means a capital expenditure Scheme with projected capital cost exceeding the limits specified in these Regulations, for which the Generating Company or Licensee or MSLDC or STU is required to obtain prior in-principal approval by submitting a Detailed Project Report (DPR) in accordance with MERC (Approval of Capital Investment Schemes) Regulations 2022;
(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 or STU or MSLDC are to be paid 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;
(41) “Emission Control System” means a set of equipment, or devices required to be installed in coal or lignite based thermal generating station or unit thereof to meet the revised emission standards;
(42) “Energy Storage System” or “ESS” in relation to the electricity system, means a facility where electrical energy is converted into any form of energy which can be stored, and subsequently reconverted into electrical energy and injected back into the grid;
(43) “Energy Storage System Developer” or “ESSD” shall mean the entity owning/operating the ESS facility for storage and supply of power to the beneficiary under these Regulations;
(44) “Extra High Tension” (or “EHT”) means all voltages above 33 kilo Volt;
(45) “Expected Revenue from Tariff and Charges” means the revenue estimated to accrue to the Generating Company or Transmission Licensee or Distribution Licensee from the Regulated Business at the prevailing level of Tariff and Charges;
(46) “Existing Generating Unit/Station” means a Generating Unit or Station declared as under commercial operation prior to April 1, 2025;
(47) “Event” means an unscheduled or unplanned occurrence in the intra-State transmission system, including faults, incidents and breakdowns;
(48) “Extended Life” means the life of a generating Station or Unit thereof or of a transmission system or element thereof beyond the period of Useful Life, as may be approved by the Commission on a case-to-case basis;
(49) “Fees” means the payments to be collected by the MSLDC or STU for services rendered on account of registration, membership or any other account as determined by the Commission;
(50) “Force Majeure Event” means, with respect to any party, any event or circumstance, or combination of events or circumstances, which is not within the reasonable control of, and is not due to an act of omission or commission of that party and which, by the exercise of reasonable care and diligence, could not have been prevented; and, without limiting the generality of the foregoing, shall include the following events or circumstances:
acts of God, including but not limited to lightning, storm, action of the elements, earthquakes, flood, torrential rains, drought and natural disaster;
(51) “Generation Business” means the Business of production of electricity from a Generating Station for the purpose of (i) giving supply to any premises or
enabling supply to be so given, or (ii) for the purpose of supply of electricity to any Distribution Licensee in accordance with the Act and the Rules and Regulations made thereunder, or (iii) subject to the Regulations made under sub-section (2) of Section 42 of the Act, supply of electricity to any consumer;
(52) "Generating Company" means any company or body corporate or association or body of individuals, whether incorporated or not, or artificial juridical person, which owns or operates or maintains a generating Station;
(53) "Generating Station" (or "Station") means a Station or a Unit thereof for generating electricity, including any building and plant with step-up transformer, switch-gear, switch yard, cables or other appurtenant equipment used for that purpose and the site thereof; a site intended to be used for a generating Station, and any building used for housing the operating staff of a generating Station, and where electricity is generated by water-power, includes penstocks, head and tail works, main and regulating reservoirs, dams and other hydraulic works, but does not include any sub-Station;
(54) "Gross Calorific Value" (or "GCV") in relation to a thermal Generating Station means the heat produced in kilocalories (kcal) by complete combustion of one kilogram (kg) of solid fuel or one litre of liquid fuel or one standard cubic metre of gaseous fuel, as the case may be;
(55) "Gross Station Heat Rate" means the heat energy input in kcal required to generate one kilo Watt hour (kWh) of electrical energy at generator terminals;
(56) "High Tension" (or "HT") means all voltages above and including 11 kiloVolt and up to and including 33 kiloVolt;
(57) "Indian Governmental Instrumentality" means the Government of India, State Government and any Ministry or Department or Board or Agency controlled by Government of India or the Government of the State where the Project is located, or regulatory or quasi-judicial authority constituted under the relevant statutes in India;
(58) "Infirm power" means electricity injected into the grid prior to the commercial operation of a Unit or Block of the Generating Station;
(59) "Installed Capacity" means the summation of the name plate capacities of all the Units of the Generating Station or the capacity of the Generating Station (reckoned at the generator terminals);
(60) "Intra-State Transmission System" (or "InSTS") means any system for conveyance of electricity by transmission lines within the area of the State of
Maharashtra, and includes all transmission lines, sub-stations and associated equipment of Transmission Licensees in the State:
Provided that the definition of point of separation between a transmission system and distribution system and between a Generating Station and transmission system shall be guided by the Regulations notified by the Central Electricity Authority under clause (b) of Section 73 of the Act;
hauling systems (except movable equipment unless the same is embedded in land for permanent beneficial enjoyment thereof), land demarcated for afforestation and land for rehabilitation and resettlement of persons affected by mining operations under the relevant law;
part thereof, and includes the expenditure on manpower, repairs, spares, consumables, insurance and overheads, but excludes fuel expenses; and, in respect of a Licensee, means the expenditure incurred on operation and maintenance by a Transmission Licensee or Distribution Licensee or MSLDC or STU or ESS or part thereof, and includes the expenditure on manpower, repairs, spares, consumables, insurance and overheads:
Provided that for integrated mine(s), the Operation and Maintenance Expenses shall not include the mining charge paid to the Mine Developer and Operator, if any, engaged by the Generating Company, and the mine closure expenses;
N
$$\text{Plant Load Factor (%)} = 100 \times \sum_{i=1}^N \text{SG}_i / {N \times \text{IC} \times (1 - \text{AUX}n - \text{AUX}{\text{en}})%$$
Where,
N = number of time blocks in the given period;
SGi = Scheduled Generation in MW for the ith time block in such period;
IC = Installed Capacity of the Generating Station in MW;
AUXn = Normative Auxiliary Consumption in MW, expressed as a percentage of gross generation;
AUXen = Normative Auxiliary Consumption for Emission Control System in MW, expressed as a percentage of gross generation;
(83) "Pool Account" means the accounts for payments relating to Unscheduled Interchanges ('UI Account') applicable under the Inter-State Availability Based Tariff (ABT) mechanism or Intra-State ABT Settlement Charges as identified under the Intra-State ABT mechanism operating in the State, or Reactive Energy Exchanges (Reactive Energy Account) or Deviation Settlement Mechanism under the Maharashtra Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters) Regulations, 2019 or any other such Accounts, which may be operated by the MSLDC in accordance with the Regulations or directions of the Commission;
(84) "Project" means a Generating Station, Energy Storage System or the transmission system, as the case may be and, in case of a hydro Generating Station, includes all components of the generating facility such as penstocks, head and tail works, main and regulating reservoirs dams and other hydraulic works, intake water conductor system, power Generating Station and generating Units, as apportioned to power generation;
Provided that, in case of Pumped Storage Hydro Project, includes all components of the storage facility such as Upper Reservoir, Lower Reservoir, penstocks, head and tail works, main and regulating reservoirs dams and other hydraulic works, intake water conductor system, tail water conductor system, surge well, power Station and generating/pumping Units;
(85) "Prudence Check" means the scrutiny of reasonableness of expenditure incurred or proposed to be incurred, financing plan, use of efficient
technology, cost and time over-run and such other factors as may be considered appropriate by the Commission for determination of Aggregate Revenue Requirement and Tariff or Fees and Charges;
(86) "Pumped Storage Hydro Generating Station" means a hydro Station which generates power through energy stored in the form of water energy, pumped from a lower elevation reservoir to a higher elevation reservoir;
(87) "Rated Voltage" means the voltage at which the transmission system is designed to operate or such lower voltage at which the line is charged, for the time being, in consultation with Transmission System Users;
(88) "Revised Emission Standards" in respect of thermal generating station means the revised norms notified as per Environment (Protection) Amendment Rules, 2015 or any other Rules as may be notified from time to time;
(89) "Retail Supply Business" means the Business of sale of electricity by a Distribution Licensee to its consumers in accordance with the terms of its Licence;
(90) "Run-of-river Generating Station" means a hydel Generating Station, which does not have upstream pondage;
(91) "Run-of-river Generating Station with pondage" means a hydel Generating Station with sufficient pondage for meeting the diurnal variation of power demand;
(92) "Scheduled Energy" means the quantum of energy scheduled by the concerned Load Despatch Centre to be injected into the grid by a generating station for a given time period;
(93) "Scheduled Generation" or "SG" at any time or for any period or time block means schedule of ex-bus generation in MW or MWh, given by the concerned Load Despatch Centre;
(94) "Small Gas Turbine Generating Station" means and includes open cycle gas turbine or combined cycle Generating Stations with gas turbines in the capacity range of 50 MW or below;
(95) "Storage-type Power Station" means a hydel power Generating Station associated with large storage capacity to enable variation in generation of electricity according to demand;
(96) "State Grid Code" means the Code specified by the Commission under clause (h) of sub-section (1) of Section 86 of the Act;
(97) "Thermal Generating Station" means a generating Station or a Unit thereof that generates electricity using fossil fuels such as coal, lignite, gas, liquid fuel or combination of these as its primary source of energy;
(98) "Transaction of Business Regulations" means the Regulations of the Commission governing its Transaction of Business;
(99) "Transmission System" means a line or a group of lines with or without associated sub-Station, and includes equipment associated with transmission lines and sub-stations;
(100) "Transmission Capacity Rights" means the right of a Transmission System User to transfer power in MW, under normal circumstances, between such points of injection and drawal as may be set out in the Bulk Power Transmission Agreement;
(101) "Transmission Licensee" means a Licensee authorised by the Commission to establish or operate transmission lines under Section 14 of the Act;
(102) "Transmission System User" for the purpose of these Regulations means the Distribution Licensees and long-term Open Access Users;
(103) "Unit" in relation to a thermal Generating Station (other than combined cycle thermal Generating Station) means steam generator, turbine-generator and auxiliaries or, in relation to a combined cycle thermal Generating Station, means turbine-generator and auxiliaries; and, in relation to a hydel Generating Station, means turbine-generator and its auxiliaries;
(104) "Useful Life" in relation to a Unit of a Generating Station, transmission system, distribution system and communication system from the date of commercial operation shall mean the following, namely:
i. Coal/Lignite based thermal generating Station: 25 years;
viii. Distribution line: 35 years;
ix. Optical Ground Wire (OPGW) 15 years;
x. IT system, SCADA and communication system
excluding OPGW 15 years;
xi. Integrated Mine(s) as per the Mining plan
Provided that in the case of coal/lignite based thermal generating stations and hydro generating stations, the Operational Life may be 35 years and 50 years, respectively:
Provided further that the extension of life of the projects beyond the completion of their Useful Life shall be decided by the Commission;
Provided that the first year in case of new project or integrated mine(s) shall commence from the date of commercial operation and end on the immediately following 31st March;
2.2 Words or expressions used in these Regulations but not defined herein shall have the meanings assigned to them in the Act or Rules or Regulations framed thereunder.
3.1 The Commission shall determine the Aggregate Revenue Requirement, Tariff and Fees and Charges, including terms and conditions thereof, in accordance with these Regulations for all matters for which the Commission has jurisdiction under the Act, including the following: -
(i) For supply of electricity by a Generating Company, except from Renewable Sources of energy to a Distribution Licensee;
(ii) For use of Energy Storage System;
(iii) For Intra-State transmission of electricity;
(iv) For use of intervening transmission facilities;
(v) For Wheeling of electricity;
(vi) For Retail supply of electricity;
(vii) For MSLDC, in terms of Fees and Charges;
(viii) For STU, in terms of Fees and Charges;
(ix) For Surcharge in addition to the charges for wheeling under the first proviso to sub-section (2) of Section 42 of the Act, in accordance with the Regulations of the Commission governing Distribution Open Access and Orders issued by the Commission;
(x) For Additional surcharge on the charges for wheeling under sub-section (4) of Section 42 of the Act, in accordance with the Regulations of the Commission governing Distribution Open Access and Orders of the Commission:
Provided that the Commission shall determine such Tariff and Fees and Charges, having regard to the terms and conditions contained in Parts E, F, G, H, I, J, K and L of these Regulations, as may be applicable.
3.2 Notwithstanding anything contained in these Regulations, the Commission shall adopt the Tariff if such Tariff has been determined through a transparent process of bidding in accordance with the guidelines issued by the Central Government under Section 63 of the Act:
Provided that the Petitioner shall provide such information as the Commission may require to satisfy itself that the guidelines issued by the Central Government have been duly followed.
4.1 The Commission shall determine the Tariff and Fees and Charges for matters covered in Regulation 3.1, under a Multi-Year Tariff framework with effect from April 1, 2025.
4.2 The Multi-Year Tariff framework shall be based on the following elements, for computation of Aggregate Revenue Requirement and expected revenue from Tariff and Charges for Generating Companies, Energy Storage System Developer (ESSD), Transmission Licensees, Distribution Wires Business, Retail Supply Business, Fees and Charges of MSLDC and Fees and Charges of STU;
Provided that the Distribution Licensee shall propose the category-wise Tariffs for each year of the Control Period:
Provided further that the performance parameters whose trajectories have been specified in these Regulations shall form the basis of projection for the Aggregate Revenue Requirement for the entire Control Period;
Provided that the Commission shall also approve the sharing proportion amongst the Transmission System Users of the MSLDC Fees and Charges and STU Fees and Charges for the Control Period;
of the Control Period, shall be submitted by the Distribution Licensees for Wires Business and Retail Supply Business;
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.
(vi) The mechanism for sharing of approved gains or losses arising out of controllable factors as specified by the Commission in these Regulations.
5.1 The Petitions to be filed in the Control Period under these Regulations are as under:
a) Multi-Year Tariff Petition, which is complete in all aspects as per these Regulations, shall be filed by November 1, 2024 by Generating Companies, Transmission Licensees, ESSD, MSLDC and STU, and by November 30, 2024, by Distribution Licensees, comprising:
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:
iv. 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 comprising;
d) True-up Petition, which is complete in all aspects as per these Regulations, for the third and fourth year of the Control Period shall be filed by November 30, 2029 by Distribution Licensees comprising;
e) In case of a Licensee whose tariff is yet to be determined by the Commission till March 31, 2025, the Commission may relax the timelines for submission of the Multi-Year Tariff Petition, and Truing-up Petitions, in case such specific relaxation is sought by such Licensee. Such Deemed Distribution Licensee may be permitted to first file a Petition for approval of a ceiling or other provisional tariff in its area of supply, followed by a Petition for approval of Power Purchase Agreement or arrangement, after which the Multi-Year Tariff Petition may be filed;
f) If the Petition is not filed within the specified timelines and/or data sought by the Commission for processing the Petition is not submitted within the stipulated time, then the corresponding revenue loss and associated carrying cost due to consequential delay in issue of the Order, shall not be allowed to the Generating Company or Energy Storage System Developer, Transmission Licensee or Distribution Licensees or MSLDC or STU, as the case may be.
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 applying disincentive of INR One Crore per default at the time of approval of the ARR;
Provided that, in case complete accounting segregation has not been done between the Distribution Wires Business and Retail Supply Business of a Distribution Licensee, its Aggregate Revenue Requirement shall be apportioned between the Distribution Wires Business and Retail Supply Business in accordance with the Allocation Matrix specified in Part H of these Regulations.
Provided that each such separate Petition shall contain all necessary details of expenses, revenue, assets, liabilities, capitalisation, and category-wise tariff to enable the Commission to determine the Aggregate Revenue Requirement and Tariff for each separate area for which it has been filed:
Provided further that such expenses, revenue, assets, liabilities, and capitalisation considered for each such area shall be excluded while submitting the Petition for the remaining area of supply:
Provided also that the Distribution Licensee shall submit the reconciliation statement for expenses, revenue, assets, liabilities, and capitalisation between the entity as a whole and each such separate area of supply for which the Distribution Licensee has filed a separate Petition.
6.1** The Multi-Year Tariff Petition shall include a forecast of Aggregate Revenue Requirement and expected revenue from Tariff for each year of the Control Period in the manner specified in these Regulations and be accompanied by applicable fees.
6.2** The forecast of Aggregate Revenue Requirement may be based on assumptions relating to the behaviour of individual variables during the Control Period, including category-wise sales and demand projections, power procurement plan, capital investment plan, financing plan and physical targets, in accordance with guidelines and formats as may be prescribed by the Commission.
6.3** The capital investment plan shall show, separately, on-going projects that will spill over into the Control Period, and new projects (along with justification) that will commence in the Control Period but may be completed within or beyond it, for which relevant technical and commercial details shall be provided as per the provisions of the Maharashtra Electricity Regulatory Commission (Approval of Capital Investment Schemes) Regulations, 2022 and amendments thereof.
6.4** The Distribution Licensees shall project the realistic power purchase requirement from all Generating Stations including Energy Storage system(s) considering the provisions of the Maharashtra Electricity Regulatory Commission (Framework for Resource Adequacy) Regulations, 2024 and the amendments thereof. Distribution Licensees while submitting the MYT Petitions, shall submit the details of approved power procurement plan by the Commission and variation in the actual power procurement vis-à-vis approved power procurement plan in compliance to the provisions of the MERC (Framework for Resource Adequacy) Regulations, 2024:
Provided that, the distribution Licensees shall also consider the Merit Order Despatch principles, the Renewable Purchase Obligation (RPO), Energy Storage Obligations (ESO) specified by the Commission under the relevant Regulations, and the target set, if any, for Energy Efficiency (EE), Energy Conservation (EC) and Demand Side Management (DSM) schemes, in accordance with Energy Conservation (Amendment) Act, 2022 and guidelines thereof and or Regulations framed on these aspects, while preparing power procurement plan:
Provided further that Merit Order Despatch principles shall not apply to purchase of power from Renewable Energy sources.
6.5** The forecast of expected revenue from Tariff and charges shall be based on the following:
(a) In the case of a Generating Company, estimates of quantum of electricity to be generated by each Unit/Station for each year of the Control Period;
(b) In the case of a Transmission Licensee, estimate of Aggregate Revenue Requirement or estimates of transmission capacity allocated to Transmission System Users, as appropriate, for each year of the Control Period;
(c) In the case of a Distribution Licensee, estimates of quantum of electricity to be supplied to consumers and wheeled on behalf of Distribution System Users for each year of the Control Period:
Provided that the Distribution Licensee shall submit relevant details of category-wise sales separately for each Distribution Franchisee area, including the Input Energy and the Input Rate;
6.6 Based on the forecast of Aggregate Revenue Requirement and expected revenue from Tariff and charges, Generating Company, ESSD or Distribution Licensee or MSLDC or STU shall submit the proposed Tariff or Fees and Charges, category-wise if applicable, for each year of the Control Period, that would meet the gap, if any, in the Aggregate Revenue Requirement, including unrecovered revenue gaps of previous years to the extent proposed to be recovered.
6.7 Full details supporting the forecast shall be provided, including but not limited to details of past performance, proposed initiatives for achieving efficiency or productivity gains, technical studies, contractual arrangements and secondary research, to enable the Commission to assess the reasonableness of the forecast.
6.8 On receipt of the Petition, the Commission shall either issue an Order approving the Aggregate Revenue Requirement and Tariff for the Control Period, subject to such modifications and conditions as it may stipulate; or reject the Petition for reasons to be recorded in writing, after giving the Petitioner a reasonable opportunity of being heard.
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.
8.1 Petition shall include information in such form as may be stipulated by the Commission, together with the Accounting Statements, extracts of books of account and such other details, including Cost Accounting Reports or extracts thereof, as it may require assessing the reasons for and extent of any difference in operational and financial performance from the approved forecast of Aggregate Revenue Requirement and expected revenue from Tariff and charges.
8.2 The scope of the Mid-term Review shall be a comparison of the actual operational and financial performance vis-à-vis the 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, and proposed category-wise Tariffs for the fourth and fifth year of the Control Period:
Provided that as part of the Mid-term Review, the Commission may inter-alia modify the category-wise sales, power purchase expenses, O&M expenses, capital expenditure related expenses, principles/basis of tariff categorisation, applicability of charges, Wheeling Charges, and category-wise Tariff, as considered appropriate based on the data made available for the first three years of the Control Period:
Provided further that necessary justification for the modifications made in the Mid-term Review shall be elaborated in the Mid-term Review Order.
8.3 Upon completion of the Review under Regulation 8.2, the Commission shall attribute any variations or expected variations in performance, for variables specified under Regulation 9, to factors within the control of the Petitioner (controllable factors) or to factors beyond its control (uncontrollable factors):
Provided that any variations or expected variations in performance, for variables other than those specified under Regulation 9.1, shall not ordinarily be reviewed by the Commission during the Control Period and shall be attributed entirely to controllable factors:
Provided further that, where the Petitioner believes, for any variable not specified under Regulation 9.1, that there is a material variation or expected variation in performance for any year on account of uncontrollable factors, it may apply to the Commission for inclusion of such variable.
8.4 Upon completion of the Mid-term Review, the Commission shall pass an order recording-
9.1 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:
9.2 Variations or expected variations in the performance of the Petitioner, which may be attributed by the Commission to controllable factors include, but are not limited to the following:
(e) Variation in Coal transit losses.
10.1 The aggregate gain or loss to a Generating Company on account of variation in cost of fuel from the sources considered in the Tariff Order, including blending ratio of coal procured from different sources, shall be passed through as an adjustment in its Energy Charges on a monthly basis, as specified in Regulation 51.10.
10.2 The aggregate gain or loss to a Distribution Licensee on account of variation in cost of fuel, power purchase, Inter-State Transmission Charges and Intra-State Transmission Charges covered under Regulation 9.1, shall be passed through under the Fuel Adjustment Charge (FAC) component of the Z-factor Charge ( $Z_{FAC}$ ), as an adjustment in its Tariff on a monthly basis, as specified in these Regulations and as may be determined in orders of the Commission passed under these Regulations, and shall be subject to ex-post facto approval by the Commission on a quarterly basis:
Provided that in case Distribution Licensee fails to compute and charge $Z_{FAC}$ within the timeline stipulated in these Regulations, except in case of any Force Majeure, its right for recovery of such cost shall be forfeited and Distribution Licensee shall not allow to recover such cost in True-up also.
Provided further that in case $Z_{FAC}$ computed for any month is negative i.e. saving in expenses, then such saving shall be deposited in 'FAC Stabilisation Fund'. Amount accrued along with holding cost in such Fund shall be used for offsetting positive $Z_{FAC}$ i.e. increased expenses, before levying it to the consumers.
10.3 The $Z_{FAC}$ component shall be applicable to the entire sales of a Distribution Licensee without any exemption to any consumer.
10.4 The $Z_{FAC}$ component shall be computed and charged on the basis of actual variation in cost of fuel and power purchase, and Inter-State Transmission Charges and Intra-State Transmission Charges relating to power procured during any month subsequent to such costs being incurred, in accordance with these Regulations, and shall not be computed on the basis of estimated or expected variations in fuel and/or power purchase costs.
10.5 Distribution Licensee shall submit the details of variation in fuel costs relating to power generated from its own generation stations, cost of power procured, Inter-State Transmission Charges and Intra-State Transmission Charges on a quarterly basis within 60 days of the close of each quarter, for post facto approval:
Provided also that the Distribution Licensee shall submit the $Z_{FAC}$ levied to all consumers for the preceding quarter vis-a-vis the $Z_{FAC}$ recoverable, along with the detailed computations and supporting documents as may be required, for verification by the Commission:
Provided also that the Distribution Licensee shall provide details of the Commission's approval of levy of $Z_{FAC}$ on its internet website.
10.6 The formula for computation of the FAC component of Z-factor Charge is as follows:
$$Z_{FAC} (\text{INR crore}) = F + C + B,$$
Where,
$Z_{FAC}$ = Z-factor Charge component for FAC;
F = Change in fuel cost of own generation, cost of power purchase, Inter-State Transmission Charges and Intra-State Transmission Charges as covered under Regulation 9.1;
C = Carrying Cost for any under recovery/over recovery, computed at the Base Rate prevailing at the beginning of the month, plus 150 basis points;
B = Adjustment factor for over-recovery/under-recovery.
10.7 The calculation for FAC to be charged for the month "n" is as follows:
$$Z_{FAC\ n} (\text{INR Crore}) = F_{n-2} + C_{n-2} + B_{n-2},$$
Where,
$F_{n-2}$ = Change in fuel cost of own generation, cost of power purchase, Inter-State Transmission Charges and Intra-State Transmission Charges, for the month "n-2", and shall be computed as,
$$F (\text{INR Crore}) = A_{FC,Gen} + A_{FC,PP} + A_{ITC} + A_{InTC},$$
Where,
$A_{FC,Gen}$ = Change in fuel cost of own generation, to be computed based on the directives and norms approved by the Commission, including heat rate, auxiliary consumption, etc.;
$A_{FC,PP}$ = Change in variable and/or fixed cost of power procured from other sources, which would be allowed to the extent it satisfies
the criteria prescribed in these Regulations and the prevailing Tariff Order, and subject to applicable norms;
$A_{ITC}$ = Change in Inter-State Transmission Charges;
$A_{ISTC}$ = Change in Intra-State Transmission Charges including MSLDC and STU Fees and Charges;
$C_{n-2}$ = Carrying cost for any under recovery/over recovery for the month "n-2";
$B_{n-2}$ (INR Crore) = $Z_{FAC\ n-4} - R_{n-2}$
Where:
$B_{n-2}$ = Adjustment factor for over-recovery / under-recovery for the month "n-2";
$Z_{FAC\ n-4}$ = $Z_{FAC}$ for the month "n-4";
$R_{n-2}$ = $Z_{FAC}$ for the month "n-4" actually recovered in the month "n-2";
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":
Provided that, in case of unmetered consumers, the $Z_{FAC}$ 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, where the actual cumulative distribution losses of the Distribution Licensee exceed the level approved by the Commission, the amount of $Z_{FAC}$ corresponding to the excess distribution losses (in kWh terms) shall be deducted from the total $Z_{FAC}$ recoverable.
10.9 The $Z_{FAC}$ per kWh for a particular Tariff category/sub-category/consumption slab shall be computed as per the following formula:
$Z_{FAC\ Cat}$ (INR/kWh or INR/kVA) = $[Z_{FAC} / (\text{Metered sales} + \text{Unmetered consumption estimates} + \text{Excess distribution losses})] * k * 10$ ,
Where:
$Z_{FAC\ Cat}$ = $Z_{FAC}$ component for a particular Tariff category/sub-category/consumption slab in 'Rupees per kWh' or 'Rupees per kVAh' terms as approved by the Commission in the Tariff Order;
$k = \text{Average Billing Rate} / \text{ACOS};$
Average Billing Rate = Average Billing Rate for a particular Tariff category/sub-category/consumption slab under consideration in 'Rupees per kWh' or 'Rupees per kVAh' as approved by the Commission in the Tariff Order:
Provided that the Average Billing Rate for the unmetered consumers shall be based on the estimated sales to such consumers, computed in accordance with such methodology as may be stipulated by the Commission:
ACOS = Average Cost of Supply in 'Rupees per kWh' or 'Rupees per kVAh' as approved for recovery by the Commission in the Tariff Order:
Provided that the monthly $Z_{FAC}$ shall not exceed 20% of the variable component of Tariff or such other ceiling as may be stipulated by the Commission from time to time:
Provided further that any under-recovery in the $Z_{FAC}$ 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.
10.10 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 ( $Z_{OUC}$ ) 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.
10.11 The $Z_{OUC}$ shall be determined based on a Petition filed by the concerned the Generating Companies, Transmission Licensees, Distribution Licensees, MSLDC, STU and ESSD.
11.1 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.
11.2 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:
Where the Commission has, at any time prior to April 1, 2025, approved a power purchase agreement or arrangement between a Generating Company and a Distribution Licensee or has adopted the Tariff contained therein for supply of electricity from an existing generating Unit/Station, then the Tariff for supply of electricity by such Generating Company to the Distribution Licensee shall be in accordance with the Tariff mentioned in such power purchase agreement or arrangement for such period as so approved or adopted by the Commission.
Where, as on April 1, 2025, the power purchase agreement or arrangement between a Generating Company or Energy Storage system Developer as the case may be and a Distribution Licensee for supply of electricity from an existing generating Unit/Station or the Tariff therein has not been approved by the Commission, or where there is no power purchase agreement or arrangement, the supply of electricity by such Generating Company or providing energy storage services to the Distribution Licensee after April 1, 2025 shall be in accordance with a power purchase agreement or Energy Storage Service Agreement as the case may be approved by the Commission in accordance with Part C of these Regulations:
Provided that the Petition for approval of such power purchase agreement or arrangement shall be filed by the Distribution Licensee with the Commission considering the provisions of the MERC (Framework for Resource Adequacy) Regulations 2024 and amendments thereof, within three months from the date of notification of these Regulations:
Provided further that the supply of electricity shall be allowed to continue under the present agreement or arrangement until such time as the Commission approves such power purchase agreement and shall be discontinued forthwith if the Commission rejects it, for reasons to be recorded in writing.
The Tariff for the supply of electricity by a Generating Company to a Distribution Licensee from a new generating Unit/Station shall be in accordance with the Tariff determined in accordance with Part E of these Regulations.
The Tariff for providing Energy Storage Services, shall be determined by the Commission in accordance with Part L of these Regulations.
Where a Distribution Licensee also undertakes the business of generation of electricity, the transfer price at which electricity is supplied by its Generation Business to its Retail Supply Business shall be determined by the Commission:
Provided that the Commission shall have regard to the terms and conditions specified in Part E of these Regulations in determining the transfer price for such supply.
The Distribution Licensee shall maintain a separate record for its Generation Business and an Allocation Statement so as to enable the Commission to identify the direct and indirect costs relating to such Business and return on equity capital accruing to it.
13.5 The Distribution Licensee shall submit, along with the separate Petition for determination of Tariff for retail supply of electricity, the information required under Part E of these Regulations relating to the Generation Business.
14.1 The Commission shall determine the Aggregate Revenue Requirement and Tariff for Transmission Licensees, Distribution Wires Business, Retail Supply Business, Fees and Charges for MSLDC and STU, upon consideration of a Petition filed by the Licensee or MSLDC or STU, as the case may be, in accordance with the procedure contained in this Regulation.
14.2 The Commission shall determine the Tariff for the Licensee or Fees and Charges for the MSLDC or STU for;
14.3 The Petitioner shall provide, as part of its Petition and in such form as may be stipulated by the Commission, details of computation of the Aggregate Revenue Requirement and expected revenue from Tariff and charges, and thereafter shall furnish such further information or particulars or documents as the Commission or its Secretary or any officer designated for the purpose by the Commission may reasonably require assessing such calculation:
Provided that the Petition shall be accompanied, where relevant, by a detailed Tariff revision proposal showing category-wise Tariffs and how such revision would meet the gap, if any, in Aggregate Revenue Requirement for each year of the Control Period:
Provided further that the Commission may stipulate different formats for details to be submitted by the Petitioner as it may reasonably require for assessing the Aggregate Revenue Requirement and for determining the Tariff:
Provided also that the Commission may conduct a Technical Validation Session prior to admission of the Petition.
14.4 Petitioner shall submit a duly completed draft Public Notice for the Commission's approval as per the stipulated template, for publication as and when intimated by the Commission.
14.5 Upon receipt of a complete Petition accompanied by the requisite information, particulars and documents in compliance with the requirements specified in this Regulation, the Petition shall be admitted, and the Commission or its Secretary
or designated Officer shall intimate to the Petitioner that it is ready for publication.
Provided that the Petitioner shall make available a hard copy and soft copy of the complete Petition to any person, at such locations and at such rates as may be stipulated by the Commission:
Provided further that the Petitioner shall also provide on its internet website, in text-searchable format or in downloadable spreadsheet format and showing detailed computations, the Petition filed before the Commission along with all regulatory filings, information, particulars and documents in the manner stipulated by the Commission:
Provided also that the web link to the information mentioned in the second proviso to this Regulation shall be easily accessible, archived for downloading and be prominently displayed on the Petitioner's internet website:
Provided also that Distribution Licensee shall intimate its consumer about filing of such Tariff Petition, period of public consultation, date of Public Hearing etc. through appropriate message printed on electricity bill and or message sent through SMS gateway or email.
Provided also that the Petitioner may be exempted by the Commission from providing any such information, particulars or documents as are confidential in nature.
Explanation – For the purpose of this Regulation, the term “downloadable spreadsheet format” shall mean one (or multiple, linked) spreadsheet software files containing all assumptions, formulae, calculations, software macros and outputs forming the basis of the Petition.
to it, including abstracts of books and records (or certified true copies thereof) on such terms and conditions as may be specified in Regulations of the Commission governing its Transaction of Business.
16.1 No Tariff or part of any Tariff may ordinarily be amended more frequently than once in a year, except in respect of any changes expressly permitted under Z-factor Charge as specified in Regulation 10.
16.2 If any Generating Company or ESSD or Transmission Licensee or Distribution Licensee or MSLDC or STU recovers a price or charge exceeding the Tariff determined under Section 62 of the Act and in accordance with these Regulations, the excess amount shall be payable to the person who has paid such price or charge, along with interest equivalent to the Bank Rate declared by the Reserve Bank of India prevailing during the relevant period, without prejudice to any other liability to which such Generating Company or ESSD or Transmission Licensee or Distribution Licensee or MSLDC or STU may be subjected to:
Provided that such interest payable to any party shall not be allowed to be recovered through the Aggregate Revenue Requirement of the Generating Company or Energy Storage System Developer or Transmission Licensee or Distribution Licensee or MSLDC or STU:
Provided also that the Generating Company or Energy Storage System Developer or Transmission Licensee or Distribution Licensee or MSLDC or STU shall maintain separate details of such interest paid or payable by it and shall submit them to the Commission along with its Petition.
16.3 The Generating Company or Transmission Licensee or Distribution Licensee or MSLDC or STU shall submit periodic returns as may be required by the Commission, containing operational and cost data to enable it to monitor the implementation of its Order.
17.1 The tariff determined in accordance with these Regulations shall be a ceiling tariff, and the Generating Company or Energy Storage System Developer or Transmission Licensee and their Beneficiaries may mutually agree to charge a lower tariff.
17.2 The Generating Company or Transmission Licensee may opt to charge a lower tariff for a period not exceeding the validity of these Regulations on agreeing to deviation from operational parameters, reduction in Operation and Maintenance expenses, reduced Return on Equity and incentive specified in these Regulations.
18.1 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.
19.1 The Distribution Licensee shall undertake its power procurement during the year in accordance with the power procurement plan for the Control Period, which may include long-term, medium-term and short-term power procurement, approved by the Commission in accordance with Maharashtra Electricity Regulatory Commission (Framework for Resource Adequacy) Regulations, 2024.
19.2 The Distribution Licensee shall follow the guidelines contained in this Part with respect to:
19.3 All future procurement of short-term or medium-term or long-term power shall invariably be undertaken through competitive bidding in accordance with Guidelines notified by the Government of India under Section 63 of the Act.
Provided that in case either no competitive bids are received, or the bids received are higher than the prevailing market rates or on any other sufficient reason, then the Distribution Licensee may procure medium-term or long-term power under Section 62 of the Act, subject to fulfilling the conditions specified in Regulation 21 of these Regulations.
Provided that while preparing power procurement plan, the Distribution Licensee shall ensure availability of adequate inter-state and intra-state transmission network as per STU transmission plan or highlight transmission constraints or network augmentation requirements to cater to its proposed power procurement arrangements outlined under their procurement plan.
Provided further that such power procurement plan approved under MERC (Framework for Resource Adequacy) Regulations, 2024 for the Control Period commencing on April 1, 2025, shall be filed 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.
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).
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 21.3 to 21.5 shall be followed.
21.4 Upon receipt of a complete Petition accompanied by the requisite information, particulars and documents in compliance with the requirements specified in this Regulation, the Petition shall be admitted and the Commission or its Secretary or designated Officer shall intimate to the Petitioner that the Petition is ready for publication.
21.5 The Petitioner shall, within three days of an intimation given to it in accordance with Regulation 21.4, 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 salient features of the proposed agreement or arrangement for power procurement and the impact on the power procurement cost and Tariff, and such other matters as may be stipulated by the Commission, and inviting suggestions and objections from the public:
Provided that the Petitioner shall make available a hard copy of the complete Petition to any person at such locations and at such rates as may be stipulated by the Commission;
Provided further that the Petitioner shall also provide the Petition filed before the Commission along with all regulatory filings, information, particulars and documents in the manner stipulated by the Commission on its internet website:
Provided also that the web-link to the information mentioned in the second proviso to this Regulation shall be easily accessible, archived for downloading and shall be prominently displayed on the Petitioner's internet website:
Provided also that the Petitioner may be exempted by the Commission from providing any such information, particulars or documents as are confidential in nature.
21.6 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:
(a) Requirement of power procurement under the approved power procurement plan;
(b) Adherence to a transparent process of bidding in accordance with guidelines issued by the Central Government under Section 63 of the Act or Adherence to the terms and conditions for determination of Tariff specified under Part E and Part L of these Regulations;
(c) Competitiveness of the Tariff vis-a-vis the Tariff prevalent in the market and/or Tariff discovered through competitive bidding under Section 63 of the Act;
(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;
(e) Need to promote co-generation and generation of electricity from renewable sources of energy.
21.7 Upon completion of its consideration of the power procurement agreement or arrangement, the Commission shall:
22.1 The Distribution Licensee may undertake additional power procurement during the year, over and above the power procurement plan for the Control Period approved by the Commission, in accordance with this Regulation.
22.2 Where there has been an unanticipated increase in the demand for electricity or a shortfall or failure in the supply of electricity from any approved source of supply during the Year or when the sourcing of power from existing tied-up sources becomes costlier than other available alternative sources, the Distribution Licensee may enter into additional agreement or arrangement for procurement of power.
22.3 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:
Provided that the five per cent limit shall not apply to variation in the cost of power procured on account of changes in the price of fuel for own generation or the fixed or variable cost of power purchase that is allowed to be recovered in accordance with Regulation 10.
22.4 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.
23.1 The Generating Company or Energy Storage System Developer or Licensee or STU or MSLDC shall manage its finances in an optimum and prudent manner:
23.2 In determining the Aggregate Revenue Requirement and Tariff, Charges and Fees of the Generating Company or ESSD or Licensee or MSLDC or STU, the Commission shall assess the financial prudence exercised with regard to the following factors:
Provided that the Commission may disallow a part of the Aggregate Revenue Requirement, as an efficiency measure, if it finds the exercise of such prudence to have been deficient.
23.3 The financial prudence with respect to revenue shall be assessed in terms of the following parameters:
(viii) whether revenue collected is in line with the projections made in the Petition and approved by the Commission.
23.4 The financial prudence with respect to revenue expenditure shall be assessed in terms of the following parameters:
Provided that, in case the excess of revenue expenditure over the revenue earned exceeds 5%, the Generating Company or ESSD or Licensee shall submit detailed justification for the mismatch along with its Petition for True-up, including a comparison of the revenue expenditure and revenue estimated in the Petition with the amounts approved by the Commission and with the actual amount of revenue expenditure and revenue, under key heads;
Provided further that the Generating Company or ESSD or Licensee shall submit a detailed cash flow statement for the respective business showing the various sources of revenue, the actual amount of cash collected against the amount billed to different consumer categories for sale of electricity, the comparison of the actual revenue expenditure and capital expenditure with the projected and approved revenue expenditure and capital expenditure:
Provided also that, in case its payment obligations to other entities are not regularly met, the Generating Company or ESSD or Licensee shall provide justification for such shortfall with reference to its cash flow statement:
Provided also that the Generating Company or ESSD or Licensee shall submit the Cost Audit Report along with the true-up Petition to justify the revenue expenses incurred as well as inventory management policies.
23.5 The financial prudence with respect to capital expenditure shall be assessed as per the provisions of the MERC (Approval of Capital Investment Schemes) Regulations, 2022, in terms of the following parameters:
Provided that, the financial prudence with respect to 'Opex expenditure' shall be assessed as per the provisions of the MERC (Approval of Capital Investment Schemes) Regulations, 2022.
24.1 The Capital Investment Scheme of the Generating Company or ESSD or Transmission Licensee or Distribution Licensee or STU throughout the Control Period shall be in accordance with the principles set out under Regulation 3 of the MERC (Approval of Capital Investment Schemes) Regulations, 2022, as amended from time to time.
24.2 Capital cost for a capital investment Project shall include:
(a) the expenditure incurred or projected to be incurred, including interest during construction and financing charges, as admitted by the Commission after prudence check;
(b) capitalised initial spares subject to the ceiling rates specified in this Regulation;
(c) expenses incurred by the Licensee on obtaining right of way, as admitted by the Commission after prudence check;
(d) additional capitalisation determined under Regulation 25;
(e) any gain or loss on account of foreign exchange rate variation pertaining to the loan amount availed up to the cut-off date, as admitted by the Commission after prudence check;
(f) Capital expenditure on account of biomass handling equipment and facilities, for co-firing:
Provided that any gain or loss on account of foreign exchange rate variation pertaining to the loan amount availed up to the date of commercial operation shall be adjusted only against the debt component of the capital cost:
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 or ESSD or transmission system:
Provided also that the Generating Company, ESSD or Transmission Licensee or Distribution Licensee or MSLDC or STU shall submit documentary evidence in support of its claim of assets being put to use:
Provided also that the Commission may undertake a sample check to verify the assets put to use as submitted by the Generating Company, ESSD or Licensee or MSLDC or STU, as the case may be, independent of the tariff determination process:
Provided also that any capital expenditure incurred based on the specific requirement of a Generating Company or ESSD or Licensee shall be substantiated with necessary documentary evidence of such request and undertaking received:
Provided also that the following shall be excluded from the capital cost of the existing and new projects:
Provided that in case replacement of transmission asset is recommended by State Transmission Utility, such asset shall be decapitalised only after its redeployment;
Provided further that unless shifting of an asset from one project to another is of permanent nature, there shall be no de-capitalization of the concerned assets.
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 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 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.
considered by the Commission subject to prudence check and in accordance with the conditions and methodology specified in Regulation 39:
Provided that, in case the actual capital cost is lower than the approved capital cost, the actual capital cost, subject to prudence check and in accordance with the conditions and methodology specified in Regulation 39 for the capital cost of new generating Unit/Station, shall be considered for determination of Tariff of the Generating Company.
24.5 The Petitioner may project the capital expenditure and capitalisation plan for each year of the Control Period as per its projected capital investment outlay and annual phasing plan with due justifications in accordance with provisions outlined under MERC (Approval of Capital Investment Schemes) Regulations, 2022, as amended from time to time.
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.
24.7 The capital cost of the concerned asset/s shall be considered after deducting the amount of accumulated depreciation computed till the period of asset utilisation for unregulated business or for the period the assets remain unutilised, for the purpose of tariff determination, in the following instances:
24.8 The actual capital expenditure on a scheme as on COD for the original scope of work based on audited accounts of the Generating Company, ESSD or Licensee or MSLDC or STU or Project, as the case may be, shall be considered subject to prudence check by the Commission.
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 Average capital expenditure of past three years actually incurred or 30% 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 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.
24.10 Where the power purchase agreement or bulk power transmission agreement provides for a ceiling on capital cost, the capital cost to be considered shall not exceed such ceiling.
24.11 The revenue earned from sale of infirm power prior to the COD in excess of fuel cost as specified under Regulation 45, shall be adjusted against the Capital Cost.
24.12 Supply of Coal or Lignite prior to the Date of Commercial Operation of Integrated Mine:
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).
24.13 The capital cost may include initial spares capitalised as a percentage of the Plant and Machinery cost up to the cut-off date, subject to the following ceiling norms:
| hydro generating Stations: | 4.0%; |
| (d) Battery Energy Storage System | 1.0% |
| (e) Transmission System and Distribution System | |
| i. Transmission & Distribution Line including underground cable: | 1.0%; |
| ii. Transmission & Distribution sub-Station (green-field): | 4.0%; |
| iii. Transmission sub-Station (brown-field): | 6.0%; |
| iv. Series compensation devices and HVDC sub-Station: | 4.0%; |
| v. Gas Insulated sub-Station (GIS): | 5.0%; |
| vi. Communication System: | 3.5%; |
| vii. Static Synchronous Compensator: | 6.0%. |
| viii. Integrated Mine: | As per Mining Plan: |
Provided that where the Emission Control System is installed, the norms of initial spares specified in this Regulation for coal based/ lignite fired Generating Stations as the case may be, shall apply.
Provided that any benefit from such revaluation shall be passed on to persons sharing the capacity charge in case of a Generating Company, to long-term intra-State open access customers of the Transmission Licensee or Distribution Licensee or retail supply consumers of Distribution Licensees, at the time of MYT Tariff determination or in case of Distribution Licensee Mid-Term Review or final Truing-up for the Control Period, as the case may be.
Net Value of Replaced Assets = OCRA – AD;
Where;
OCRA: Original Capital Cost of Replaced Assets;
AD: Accumulated depreciation pertaining to the Replaced Assets:
Provided that, in case the original capital cost of the replaced asset is not available for any reason, it shall be considered by the Commission on a case to case basis:
Provided also that, such condition shall not be applicable for cases where 'Special Allowance' has been provided for as part of approved Aggregate Revenue Requirement of Generating Company:
Provided further that the amount of insurance proceeds received, if any, towards damage to any asset requiring its replacement shall be first adjusted towards outstanding actual or normative loan; and the balance amount, if any, shall be utilised to reduce the capital cost of such replaced asset, and any further balance amount shall be considered as Non-Tariff Income.
Explanation – For the purpose of this Regulation, the term 'renovation and modernisation' shall have the same meaning as in Section 80 IA of the Income-Tax Act, 1961.
25.1 The capital expenditure, actually incurred or projected to be incurred, on the following counts within the original scope of work, after the date of commercial operation and up to the cut-off date, may be admitted by the Commission subject to prudence check:
Provided that the details of works included in the original scope of work along with estimates of expenditure, liabilities recognized to be payable at a future date and the works deferred for execution shall be submitted along with the Petition for determination of final Tariff after the date of commercial operation of the Generating Unit/Station or transmission system.
25.2 The capital expenditure incurred or projected to be incurred in respect of a new Project on the following counts within the original scope of work after the cut-off date may be admitted by the Commission, subject to prudence check:
(i) Liabilities to meet award of arbitration or for compliance of directions or order of any statutory authority or order or decree of any court of law;
(ii) Change in law or compliance of any existing law;
(iii) Deferred works relating to ash pond or ash handling system in the original scope of work;
(iv) Any liability for works executed prior to the cut-off date, after prudence check of the details of such undischarged liability, total estimated cost of package, reasons for such withholding of payment and release of such payments, etc.;
(v) Any additional capital expenditure which has become necessary for efficient operation:
Provided that the claim shall be substantiated with the technical justification duly supported by documentary evidence like test results carried out by an independent agency in case of deterioration of assets, damage caused by natural calamities, obsolescence of technology, up-gradation of capacity for the technical reason such as increase in fault level:
Provided further that the approval of additional capital expenditure for efficient operation shall be subject to submission of report on impact assessment done by any reputed third-party technical expert/agency on the benefits realised from previous investments under this head in the last five years;
Provided that in case of replacement of assets deployed under the original scope of the existing project after cut-off date, the additional capitalization may be admitted by the Commission, subject to prudence check on the following grounds:
a) The useful life of the assets is not commensurate with the useful life of the project and such assets have been fully depreciated in accordance with the provisions of these Regulations;
b) The replacement of the asset or equipment is necessary on account of change in law or Force Majeure conditions;
c) The replacement of such asset or equipment is necessary on account of obsolescence of technology; and
d) The replacement of such asset or equipment has otherwise been allowed by the Commission.
25.3 The capital expenditure, in respect of existing generating Station or the transmission system including communication system, incurred or projected to be incurred on the following counts beyond the original scope, may be admitted by the Commission, subject to prudence check:
Provided that any expenditure, which has been claimed under Renovation and Modernisation or repairs and maintenance under O&M expenses, shall not be claimed under this Regulation.
25.4 The additional capital expenditure required to be undertaken by the existing generating station for compliance of the Revised Emissions Standards, may be admitted by the Commission, subject to prudence check based on the following details to be submitted by the Generating Company:
(i) details of proposed technology as specified by the Central Electricity Authority or alternative technology based on appropriate justification;
(ii) scope of work;
(iii) phasing of expenditure;
(iv) schedule of completion;
(v) estimated completion cost including foreign exchange component, if any;
(vi) detailed computation of indicative impact on tariff to the beneficiaries; and
(vii) any other information considered to be relevant by the Generating Company:
Provided that the Commission may grant approval after due consideration of the reasonableness of the cost estimates, financing plan, schedule of completion, interest during construction, use of efficient technology, cost-benefit analysis, and such other factors, as may be considered relevant by the Commission.
25.5 Impact of additional capitalisation on Tariff, if any, shall be considered during the subsequent tariff determination process.
26.1 The expenses on the following categories of works carried out by the Generating Company or Licensee or MSLDC or STU shall be treated as specified in Regulation 26.2:
26.2 The expenses on such capital works shall be treated as follows:-
27.1 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 24, 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:
Provided further that the Generating Company or Licensee or MSLDC or STU or Energy Storage system Developer shall substantiate such investment of return on equity and income thereon through documentary evidence:
Provided also that if the equity actually deployed is more than 30% of the capital cost, equity in excess of 30% shall be treated as normative loan for the Generating Company or Licensee or MSLDC or STU or ESSD for determination of Tariff:
Provided also that where equity actually deployed is less than 30% of the capital cost of the capitalised asset, the actual equity shall be considered for determination of Tariff:
Provided also that the equity invested in foreign currency shall be designated in Indian rupees on the date of each investment.
Explanation.- The premium, if any, raised by the Generating Company or the Licensee while issuing share capital and investment of internal resources created out of its free reserves, for the funding of the Scheme, shall be reckoned as paid up capital for the purpose of computing return on equity, provided such premium amount and internal resources are actually utilised for meeting the capital expenditure of the Generating Station or the transmission system or the distribution system, and are within the ceiling of 30% of capital cost approved by the Commission.
27.2 In case of the Generating Company or Licensee, if any fixed asset is capitalised on account of capital expenditure Scheme prior to April 1, 2025, the debt-equity ratio allowed by the Commission for determination of Tariff for the period ending March 31, 2025 shall be considered:
Provided that in case of retirement or replacement or de-capitalisation of the assets, the balance equity capital invested in the regulated business approved in accordance with Regulation 27.1, shall be deducted from the regulatory equity of the business:
Provided further that in case of retirement or replacement or de-capitalisation of the assets, the debt capital approved as mentioned above, shall be reduced to the extent of outstanding debt component based on documentary evidence, or the outstanding normative loan component, as the case may be, of the original cost of such assets.
28.1** The Generating Company, Licensee, ESSD, MSLDC and STU shall be permitted to recover depreciation on the value of fixed assets used in their respective businesses, computed in the following manner:
(a) The approved original cost of the fixed assets shall be the value base for calculation of depreciation:
Provided that the depreciation shall be allowed on the entire capitalised amount of the new assets after reducing the approved original cost of the retired or replaced or de-capitalised assets.
Provided that the Generating Company or Licensee or ESSD or MSLDC or STU shall ensure that once the individual asset is depreciated to the extent of seventy percent, remaining depreciable value as on 31st March of the year closing after the period of twelve years from the Commercial Operation Date or the date of assets capitalised shall be spread over the balance Useful Life of the asset including the Extended Life, as provided in this Regulation:
Provided further that the Generating Company or Licensee or ESSD or MSLDC or STU shall submit all such details or documentary evidence as may be required, to substantiate the above claims.
Explanation: 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 principally approved by the Commission before the notification of these Regulations for the Generating Company or Licensee or MSLDC or STU or ESSD.”
Provided that the Generating Company or Licensee or MSLDC or STU or ESSD shall ensure that once the individual asset is depreciated to the extent of seventy percent, remaining depreciable value as on 31st March of the year closing after the period of fifteen years from the Commercial Operation Date or the date of assets capitalised shall be spread over the balance Useful Life of the asset including the Extended Life, as provided in this Regulation:
Provided further that the Generating Company or ESSD or Licensee or MSLDC or STU shall submit all such details or documentary evidence as may be required, to substantiate the above claims.
Explanation: The term “New Capital Schemes” or “New Assets” here means the Capital Schemes or the Assets, which not covered under Existing Assets.
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 that the salvage value for IT equipment and software shall be considered as NIL or 0.00% and 100% or entire value of the assets shall be considered depreciable.
(e) Where the Emission Control System is implemented within the original scope of the generating station and the date of commercial operation of the generating station or unit thereof and the date of operation of the Emission Control System are the same, depreciation of the generating station or unit thereof including the Emission Control System shall be computed in accordance with Clauses (a) to (c) of this Regulation.
(f) Depreciation of the Emission Control System of an existing or a new generating station or unit thereof where the date of operation of the emission control system is subsequent to the date of commercial operation of the generating station or unit thereof, shall be computed annually from the date of operation of such emission control system based on straight line method, with salvage value of 10%, over a period of —
(i) twenty-five years, in case the generating station or unit thereof is in operation for fifteen years or less as on the date of operation of the emission control system; or
28.2** Land other than the land held under lease and the land for reservoir in case of Hydro Generating Station or Pumped Storage Hydro Project shall not be a depreciable asset and its cost shall be excluded from the capital cost while computing depreciable value of the assets.
28.3** In case of existing assets, the balance depreciable value as on April 1, 2025, shall be worked out by deducting the cumulative depreciation as admitted by the Commission up to March 31, 2025, from the gross depreciable value of the assets: Provided that depreciation shall be chargeable from the first year of commercial operation.
28.4** In case of projected commercial operation of the assets for part of the year, depreciation shall be computed based on the average of opening and closing value of assets.
28.5** The depreciation on capital investment schemes undertaken by Generating Companies shall be allowed proportionately correlated to the remaining tenure of the Power Purchase Agreement with the Distribution Licensee.
28.6** Depreciation on capital investment schemes shall be computed annually from the date of operation of such capital investment based on straight line method, with salvage value of 10%, over a period of —
(i) Twenty-five years, in case the principal asset is in operation for fifteen years or less as on the date of operation of the capital investment; or
(ii) balance useful life of the principal asset plus fifteen years, in case the principal asset is in operation for more than fifteen years as on the date of operation of the capital investment.
28.7 Depreciation shall be re-computed for assets capitalised at the time of Truing-up along with the Mid-term Review (in case of Distribution Licensees) or at the end of the Control Period, based on documentary evidence of assets capitalised by the Petitioner, subject to the prudence check of the Commission, such that the depreciation is allowed proportionately from the date of capitalisation.
28.8 The Generating Company or Licensee or MSLDC or STU shall submit the depreciation computations separately for assets added upto March 31, 2025 and assets added on or after April 1, 2025.
29.1 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.
Performance Linked Return on Equity considered at the time of MYT Proceedings shall be reviewed and allowed at the time of truing up of respective year based on actual performance, after prudence check by the Commission.
29.4 In case of a thermal generating Unit, with effect from April 1, 2025, at the time of true-up performance linked RoE allowed in MYT proceeding shall be retained subject to performance related to Ramp Rate, Mean Time Between Failure and Free Governor Mode of Operation as follows:
(a) For a Coal/Lignite based Thermal Unit, Performance Linked Return on Equity for Ramp Rate (incremental/decremental) shall be allowed as per the following schedule, subject to the ceiling of Performance Linked RoE of 0.50%:
(ii) For Ramp Rate $\geq 0.9%$ but $< 1%$ per minute, then reduction of Performance Linked RoE of 0.25%;
(iii) For Ramp Rate $\geq 0.8%$ but $< 0.9%$ per minute, then reduction of Performance Linked RoE of 0.50%;
Provided that the MSLDC shall formulate the procedure for certification of Ramp Rate of thermal plants and submit for the approval of the Commission upon undertaking the due consultation of the stakeholders.
Provided that the MSLDC shall formulate the procedure for certification of Ramp Rate of Gas based thermal plants and submit for the approval of the Commission upon undertaking the due consultation of the stakeholders.
Provided that the Mean Time Between Failure (MTBF) shall be computed as provided in Annexure-VII to these Regulations:
Provided that the MSLDC shall certify Plant wise the operationalisation and availability of FGMO during the control period.
29.5 In case of a hydro generating Unit, with effect from 1.4.2025, at the time of true-up performance linked RoE allowed in MYT proceeding shall be retained subject to performance related to Mean Time Between Failure and Free Governor Mode of Operation as follows:
(a) Performance Linked Return on Equity for Mean Time Between Failure (MTBF) shall be allowed as per the following schedule, subject to the ceiling of Performance Linked RoE of 0.75%:
Provided that the Mean Time Between Failure (MTBF) shall be computed as provided in Annexure-VII to these Regulations:
(b) In case of an existing and new hydro generating unit, a Performance Linked Return on Equity of 0.75% shall be reduced, if the new hydro generating station declares commercial operational without Free Governor Mode Operation (FGMO) or until existing hydro generating station declares put to use of FGMO.
Provided that the MSLDC shall certify Plant wise the operationalisation and availability of FGMO during the control period.
29.6 In case of Transmission, a Performance Linked of Return on Equity considered in MYT Order shall be retained based on Transmission Availability, at time of truing up as per the following schedule:
(a) For the AC Transmission System, the Performance Linked RoE shall be allowed based on the following schedule, subject to the maximum reduction linked to performance parameters of 1.50%;
(i) For Availability 99.75% and above, no reduction in Performance Linked RoE;
(ii) For Availability $< 99.75%$ and $\geq 99.50%$ , then reduction of Performance Linked RoE of $0.25%$ ;
(b) For the HVDC bi-pole links and HVDC back-to-back stations, the Performance Linked RoE shall be allowed based on the following schedule, subject to the maximum reduction linked to performance parameters of $1.50%$ ;
(i) For Availability $96.75%$ and above, no reduction in Performance Linked RoE;
Provided further that Target Availability for additional rate of Return on Equity shall be as per Regulation 79.
29.7 In case of Distribution Wires Business, a Performance Linked Return on Equity considered in MYT Order shall be retained based on Wires Availability at the time of true-up as per the following schedule, subject to the maximum reduction linked to performance parameters of $1.50%$ :
(a) The target Wires Availability for recovery of Return on Equity (Base + Performance Linked) shall be $99.50%$ for all Distribution Licensees;
(b) The Performance Linked RoE for the Distribution Wires Availability shall be allowed as per the following schedule, subject to the maximum reduction linked to performance parameters of $1.50%$ ;
(i) For Availability 99.50% and above, no reduction in Performance Linked RoE;
(c) Wires Availability shall be computed in accordance with the following formula:
$$\text{Wires Availability} = (1 - (\text{SAIDI} / 8760)) \times 100:$$
Provided that the System Average Interruption Duration Index (SAIDI) shall be calculated from the automated measurement records through Smart Meters and in accordance with the definition specified in MERC (Electricity Supply Code and Standards of Performance for Distribution Licensees, including Power Quality) Regulations, 2021, as amended from time to time.
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 | $\geq 99%$ | 0.00% |
| < 99% and $\geq 95%$ | Reduction of 0.50% of RoE | |
| < 95% | Reduction of 1.00% of RoE | |
| Assessed Billing | $\leq 1.5%$ | 0.00% |
| > 1.50% and $\leq 5.00%$ | Reduction of 0.50% of RoE | |
| > 5.00% | Reduction of 1.00% of RoE |
29.9 The Commission may either disallow the capitalisation claimed against the respective DPR Scheme, in part or in full, as appropriate, or allow lower Return on Equity on such investment in the following cases:
29.10 In case of an Energy Storage Systems, with effect from April 1, 2025, at the time of true-up Performance Linked Return on Equity considered in MYT Order shall be retained based on average Ramp Rate at the time of true-up as per the following schedule, subject to the maximum reduction linked to performance parameters of 2.0%.
Provided that the MSLDC shall formulate the procedure for certification of Ramp Rate of ESS and submit for the approval of the Commission upon undertaking the due consultation of the stakeholders.
29.11 MSLDC and STU 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%.
30.1 The loans arrived at in the manner indicated in Regulation 27 on the assets put to use shall be considered as gross normative loan for calculation of interest on loan:
Provided that in case of retirement or replacement or de-capitalisation of assets, the loan capital approved as mentioned above, shall be reduced to the extent of outstanding loan component of the original cost of such assets based on documentary evidence.
30.2 The normative loan outstanding as on April 1, 2025, shall be worked out by deducting the cumulative repayment as admitted by the Commission up to March 31, 2025, from the gross normative loan.
30.3 The loan repayment during each year of the Control Period from FY 2025-26 to FY 2029-30 shall be deemed to be equal to the depreciation allowed for that year.
30.4 Notwithstanding any moratorium period availed, the repayment of loan shall be considered from the first year of commercial operation of the Scheme and shall be equal to the annual depreciation allowed.
30.5 The rate of interest shall be the weighted average rate of interest computed on the basis of the actual long-term loan portfolio at the beginning of each year:
Provided that at the time of Truing-up, the weighted average rate of interest computed on the basis of the actual long-term loan portfolio during the concerned year shall be considered as the rate of interest:
Provided further that if there is no actual long-term loan for a particular year but normative long-term loan is still outstanding, the last available weighted average rate of interest for actual long-term loan shall be considered:
Provided also that if Generating Company or Licensee or MSLDC or STU or ESSD as the case may be, does not have actual long-term loan even in the past, the weighted average rate of interest of its other businesses regulated by the Commission shall be considered:
Provided also that if Generating Company or Licensee or MSLDC or STU or ESSD as the case may be, does not have actual long-term loan, and its other businesses regulated by the Commission also do not have actual long-term loan even in the past, then the weighted average rate of interest of the entity as a whole shall be considered:
Provided also that if the entity as a whole does not have actual long-term loan, then the Base Rate at the beginning of the respective year shall be considered as the rate of interest for the purpose of allowing the interest on the normative loan.
30.6 The interest on loan shall be computed on the normative average loan of the year by applying the weighted average rate of interest:
Provided that at the time of Truing-up, the normative average loan of the concerned year shall be considered on the basis of the actual asset capitalisation approved by the Commission for the year.
30.7 The above interest computation shall exclude interest on loan amount, normative or otherwise, to the extent of capital cost funded by Consumer Contribution, Deposit Works, Grants or Capital Subsidy, Contingency Reserves.
30.8 The finance charges incurred for obtaining loans from financial institutions for any Year shall be allowed by the Commission at the time of Truing-up, subject to prudence check.
30.9 The excess interest during construction on account of time and/or cost overrun as compared to the approved completion schedule and capital cost or on account of excess drawal of the debt funds disproportionate to the actual requirement based on Scheme completion status, shall be allowed or disallowed partly or fully on a case to case basis, after prudence check by the Commission based on the justification to be submitted by the Generating Company or Transmission Licensee or Distribution Licensee along with documentary evidence, as applicable:
Provided that where the excess interest during construction is on account of delay attributable to an agency or contractor or supplier engaged by the Generating Entity or the Transmission Licensee, any liquidated damages recovered from such agency or contractor, or supplier shall be taken into account for computation of capital cost:
Provided further that the extent of liquidated damages to be considered shall depend on the amount of excess interest during construction that has been allowed by the Commission:
Provided also that the Commission may also take into consideration the impact of time overrun on the supply of electricity to the concerned Beneficiary/ies.
30.10 The Generating Company or Licensee or MSLDC or STU or ESSD, 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:
Provided that refinancing shall not be done if it results in net increase on interest:
Provided further that rate of interest of the refinanced loan shall be lower than the than the rate of interest of the loan, which is being refinanced;
Provided also that the re-financing shall not be subject to any adverse terms and conditions and additional cost and conditions of refinanced loan agreement shall not be considered for the purpose of determination of ARR:
Provided further that if refinancing is done and it results in net increase on interest, 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:
Provided also that the Generating Company or the Licensee or the MSLDC or the STU or ESSD, as the case may be, shall submit documentary evidence of the costs associated with such re-financing:
Provided also that the net savings in interest shall be computed after factoring all the terms and conditions, and based on the weighted average rate of interest of actual portfolio of loans taken from Banks and Financial Institutions recognised by the Reserve Bank of India for Indian institutions, before and after re-financing of loans:
Provided also that the net savings in interest shall be calculated as an annuity for the term of the loan, and the annual net savings shall be shared between the entity and Beneficiaries in the specified ratio.
30.11 Interest shall be allowed only on the amount held in cash as security deposit from Transmission System Users, Distribution System Users and Retail consumers at the Bank Rate as on 1st April of the Year for which the interest is payable:
Provided that at the time of Truing-up, the interest on the amount of security deposit for the year shall be considered on the basis of the actual interest paid by the Licensee during the year, subject to prudence check by the Commission.
31.1 The Generating Company or Licensee may hedge foreign exchange exposure in respect of the interest on foreign currency loan and repayment of foreign loan acquired for the generating Station or the transmission system or distribution system, in part or in full at its discretion.
31.2 The Generating Company or Licensee shall be permitted to recover the cost of hedging of foreign exchange rate variation corresponding to the foreign debt, in the relevant year as expense, subject to prudence check by the Commission, and extra rupee liability corresponding to such variation shall not be allowed against the hedged foreign debt.
31.3 To the extent that the foreign exchange exposure is not hedged, any extra rupee liability towards interest payment and loan repayment corresponding to the foreign currency loan in the relevant year shall be allowed subject to prudence check by the Commission, provided it is not attributable to such Generating Company or the Licensee or its suppliers or contractors.
31.4 The Generating Company or ESSD or Licensee shall follow prudent contract practice by incorporating necessary safeguard clauses against risk of price increment on account of Foreign Exchange Rate Variation on imported material.
31.5 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.
(a) In case of coal based/lignite-fired Generating Stations, working capital shall cover:
minus
Provided that in case the Fuel Supply Agreement provides for payment of cost of fuel in advance, the payables for fuel shall not be deducted for the purpose of computing the working capital requirement to the extent of actual payment of such advance, as substantiated by documentary evidence:
Provided further that for the purpose of Truing-up, the working capital shall be computed based on the scheduled generation or target availability of the generating Station, whichever is lower:
Provided also that for the purpose of Truing up, the working capital shall be computed based on the actual average stock of coal or lignite and limestone or normative stock of coal or lignite and limestone of the generating Station, whichever is lower:
Provided also that for the purpose of Truing-up for any year, the working capital requirement shall be re-computed on the basis of the values of revised normative Operation & Maintenance expenses and actual Revenue from sale of electricity excluding incentive, if any, and other components of working capital approved by the Commission in the Truing-up before sharing of gains and losses:
Provided also that in case of multi-fired fuel based generating stations, the interest on working capital shall be allowed on actual basis at the time of Truing-up, subject to prudence check.
(aa) In case of Emission Control System of coal or lignite based thermal generating stations, working capital in addition to working capital computed in accordance with Regulation 32.1 (a) shall be allowed covering:
(i) Cost of limestone or reagent towards stock for 20 days for generation corresponding to the target availability;
(b) In case of oil-fired Generating Stations, working capital shall cover:
(i) Cost of oil for thirty days towards stock, if applicable, for generation corresponding to target availability, or the maximum oil stock storage capacity, whichever is lower;
(ii) Cost of oil for thirty days for generation corresponding to target availability;
(iii) Normative Operation and Maintenance expenses for one month;
(iv) Maintenance spares at one per cent of the opening Gross Fixed Assets for the Year; and
(v) Receivables for sale of electricity equivalent to forty-five days of the sum of annual fixed charges and energy charges approved in the Tariff Order for ensuing year/s, computed on target availability and excluding incentive, if any;
Provided that for the purpose of Truing-up, the working capital shall be computed based on the scheduled generation or target availability of the generating Station, whichever is lower:
Provided further that for the purpose of Truing-up for any year, the working capital requirement shall be re-computed on the basis of the values of revised normative Operation & Maintenance expenses and actual Revenue from sale of electricity excluding incentive, if any, and other components of working capital approved by the Commission in the Truing-up before sharing of gains and losses;
(c) In case of Open Cycle Gas Turbine/Combined Cycle Generating Stations, working capital shall cover:
(v) Receivables for sale of electricity equivalent to forty-five days of the sum of annual fixed charges and energy charges approved in the Tariff Order for ensuing year/s, computed on target availability and excluding incentive, if any:
minus
Provided that for the purpose of Truing-up, the working capital shall be computed based on the scheduled generation or target availability of the generating Station, whichever is lower:
Provided further that for the purpose of Truing-up for any year, the working capital requirement shall be re-computed on the basis of the values of revised normative Operation & Maintenance expenses and actual Revenue from sale of electricity excluding incentive, if any, and other components of working capital approved by the Commission in the Truing-up before sharing of gains and losses;
(d) In case of Hydro power Generating Stations, working capital shall cover:
(i) Normative Operation and maintenance expenses for one month;
(ii) Maintenance spares at one per cent of the opening Gross Fixed Assets for the Year; and
(iii) Receivables for sale of electricity equivalent to forty-five days of the annual fixed charges for ensuing year/s, approved in the Tariff Order, computed on normative capacity index and excluding incentive, if any:
Provided that for the purpose of Truing-up for any year, the working capital requirement shall be re-computed on the basis of the values of revised normative Operation & Maintenance expenses and actual Revenue from sale of electricity excluding incentive, if any, and other components of working capital approved by the Commission in the Truing-up before sharing of gains and losses;
(e) In case of own Generating Stations of the Retail Supply Business, no amount shall be allowed towards receivables, to the extent of supply of power by the Generation Business to the Retail Supply Business, in the computation of working capital in accordance with this Regulation.
(f) Rate of interest on working capital shall be on normative basis and shall be equal to the Base Rate as on the date on which the Petition for determination of Tariff is filed, plus 150 basis points:
Provided that for the purpose of Truing-up for any year, interest on working capital shall be allowed at a rate equal to the weighted average Base Rate prevailing during the concerned Year plus 150 basis points.
Provided further that for the purpose of Truing-up for any year, the working capital requirement shall be re-computed on the basis of the values of revised normative Operation & Maintenance expenses and actual Revenue from Transmission Charges excluding incentive, if any, and other components of working capital approved by the Commission in the Truing-up before sharing of gains and losses;
Provided that for the purpose of Truing-up for any year, interest on working capital shall be allowed at a rate equal to the weighted average Base Rate prevailing during the concerned Year plus 150 basis points.
(a) The working capital requirement of the Distribution Wires Business shall cover:
(i) Normative Operation and maintenance expenses for one month;
(ii) Maintenance spares at one per cent of the opening Gross Fixed Assets for the Year; and
(iii) One and half month equivalent of the expected revenue from charges for use of Distribution Wires at the Tariff approved by the Commission for ensuing year(s);
minus
Provided further that for the purpose of Truing-up for any year, the working capital requirement shall be re-computed on the basis of the actual Revenue from sale of electricity excluding incentive, if any, and other components of working capital approved by the Commission in the Truing-up before sharing of gains and losses;
Provided that for the purpose of Truing-up for any year, interest on working capital shall be allowed at a rate equal to the weighted average Base Rate prevailing during the concerned Year plus 150 basis points.
minus
Provided that in case of power procurement from own Generating Stations of the Retail Supply Business, no amount shall be reduced from working capital requirement towards payables, to the extent of supply of power by the Generation Business to the Retail Supply Business, in the computation of working capital in accordance with these Regulations:
Provided further that for the purpose of Truing-up for any year, the working capital requirement shall be re-computed on the basis of actual Revenue from sale of electricity excluding incentive, if any, and other components of working capital approved by the Commission in the Truing-up before sharing of gains and losses;
Provided that for the purpose of Truing-up for any year, interest on working capital shall be allowed at a rate equal to the weighted average Base Rate prevailing during the concerned Year plus 150 basis points.
(a) The working capital requirement of the MSLDC shall cover:
(i) Operation and maintenance expenses for one month;
(ii) One and a half months equivalent of the expected revenue from levy of Annual Fixed Charges approved by the Commission for ensuing year(s):
Provided further that for the purpose of Truing-up for any year, the working capital requirement shall be re-computed on the basis of the values of revised normative Operation & Maintenance expenses and actual Revenue from sale of electricity excluding incentive, if any, and other components of working capital approved by the Commission in the Truing-up before sharing of gains and losses;
Provided that for the purpose of Truing-up for any year, interest on working capital shall be allowed at a rate equal to the weighted average Base Rate prevailing during the concerned Year plus 150 basis points.
(a) The working capital requirement of the STU shall cover:
Provided further that for the purpose of Truing-up for any year, the working capital requirement shall be re-computed on the basis of the values of revised normative Operation & Maintenance expenses and actual Revenue from sale of electricity excluding incentive, if any, and other components of working capital approved by the Commission in the Truing-up before sharing of gains and losses;
(b) Rate of interest on working capital shall be on normative basis and shall be equal to the Base Rate as on the date on which the Petition for determination of Fees and Charges is filed, plus 150 basis points:
Provided that for the purpose of Truing-up for any year, interest on working capital shall be allowed at a rate equal to the weighted average Base Rate prevailing during the concerned Year plus 150 basis points.
32.7 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 ESSD 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 11:
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 exceeds 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.
33.1 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.
34.1 The Income Tax for the Generating Company or ESSD or Licensee 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:
Provided 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, subject to prudence check;
Provided further that no Income Tax shall be considered on the amount of efficiency gains and incentive approved by the Commission, irrespective of whether or not the amount of such efficiency gains and incentive are billed separately:
Provided further that no Income Tax shall be considered on the amount of income from Delayed Payment Charges or Interest on Delayed Payment or Income from Other Business, as well as on the income from any source that has not been considered for computing the Aggregate Revenue Requirement:
Provided also that the Income Tax rate shall be considered for the Generating Company or ESSD as a whole, and not Unit-wise/Station-wise:
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.
Provided that in case the Generating Company or ESSD 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.
Rate of pre-tax return on equity = Rate of Return on Equity / (1-t),
Where “t” is the actual tax rate including surcharge and cess.
Provided that where the amount of such Contingency Reserves exceeds five (5) per cent of the original cost of fixed assets, no further contribution shall be allowed:
Provided further that such contribution shall be invested in securities authorised under the Indian Trusts Act, 1882 such as Treasury Bills, Sovereign Bonds, Zero Coupon Bonds or similar kind of financial instruments, within a period of six months of the close of the Year:
Provided also that if the Licensee does not invest the amount of contribution to Contingency Reserves in authorised securities within a period of six months of the close of the Year, then the contribution allowed in the calculation of Aggregate Revenue Requirement shall be disallowed at the time of true-up:
Provided also that if the Licensee does not invest the amount of contribution to Contingency Reserves in authorised securities for two consecutive Years, then
the contribution to Contingency Reserves shall not be allowed in the calculation of Aggregate Revenue Requirement from the subsequent Year onwards.
35.2 The Contingency Reserve shall not be drawn upon during the term of the Licence except to meet such charges on account of:
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 26.1 of these Regulations.
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.
35.3 No diminution in the value of Contingency Reserve as mentioned above shall be allowed to be adjusted as a part of Tariff.
36.1 For payment of bills of generation Tariff or ESS or transmission charges or MSLDC Fees and Charges or STU Fees and Charges within 7 days of presentation of bills, through Letter of Credit or otherwise or through NEFT/RTGS, a rebate of 1% on billed amount, excluding the taxes, cess, duties, etc., shall be allowed.
36.2 For payment of bills of retail Tariff by the consumers within 7 days of issue of bills, a rebate of 1% on the billed amount, excluding the taxes, cess, duties, etc., shall be allowed.
36.3 A discount on the monthly bill (excluding taxes and duties) shall be provided to Low Tension category consumers for payment of electricity bills through various
modes of digital payment such as credit cards, debit cards, UPI, BHIM, internet banking, mobile banking, mobile wallets, etc.:
Provided that the rate of such discount shall be stipulated by the Commission in the relevant Tariff Order.
36.4 All rebates or incentives earned by the Generating Company or ESSD or Licensee or MSLDC or STU shall be considered under its Non-Tariff Income, while all rebates or incentives given by the Generating Company or ESSD or Licensee or MSLDC or STU shall be allowed as an expense for the Generating Company or Licensee or MSLDC or STU.
36.5 Penalties paid, if any, by the Generating Company or Licensee shall not be allowed as an expense for the Generating Company or Licensee.
37.1 In case the payment of bills of Generation Tariff or ESSD or Transmission Charges or MSLDC Fees and Charges or STU Fees and Charges by the Beneficiary is delayed beyond the due date, Delayed Payment Charge at the Base Rate of Delayed Payment Charge shall be payable on the payment outstanding for the first month of default, notwithstanding anything to the contrary as may have been stipulated in the Agreement or Arrangement with the Beneficiaries:
Provided that the rate of Delayed Payment Charge for the successive months of default shall increase by 0.5 percent for every month of delay subject to the condition that the Delayed Payment Charge shall not be more than three percent higher than the Base Rate of Delayed Payment Charge at any time:
Provided further that the rate at which Delayed Payment Charge shall be payable, shall not be higher than the rate of Late Payment Surcharge specified in the Agreement, if any.
37.2 In case the payment of bills of retail Tariff by the consumers is delayed beyond a period of 15 days for High Tension consumers and Extra High Tension consumers and 21 days for Low Tension consumers from the date of billing, Delayed Payment Charge on the billed amount, including the taxes, cess, duties, etc., shall be levied on simple interest basis at the rate of 1.25% on the billed amount for the first month of delay:
Provided that for delay in payment of bills of retail Tariff beyond 60 days and up to 90 days from the date of billing, Interest on Delayed Payment on the billed amount, including the Delayed Payment Charges, taxes, cess, duties, etc., shall be levied on simple interest basis at the rate of 12% per annum:
Provided further that for delay in payment of bills of retail Tariff beyond 90 days from the date of billing, Interest on Delayed Payment on the billed amount, including the Delayed Payment Charges, taxes, cess, duties, etc., shall be levied on simple interest basis at the rate of 15% per annum.
Provided that any adjustment towards Delayed Payment Charge shall be done in the manner as specified in Regulation 37.5.
38.1 The Regulations specified in this Part shall apply to the determination of Tariff for supply of electricity to a Distribution Licensee from conventional sources of generation along with Energy Storage Systems if any or hydro generating stations of capacity exceeding 25 MW:
Provided that determination of Tariff for supply of electricity to a Distribution Licensee from Renewable Energy sources of generation shall be in accordance with terms and conditions specified in the relevant Regulations of the Commission.
38.2 The Commission shall be guided by the terms and conditions contained in this Part in determining the Tariff for supply of electricity by a Generating Company to a Distribution Licensee, in the following cases:
39.1 A Generating Company shall file a Petition for determination of Tariff for supply of electricity to Distribution Licensees in accordance with the provisions of Part B of these Regulations.
39.2 Tariff in respect of a Generating Station, under these Regulations may be determined Stage-wise, Unit-wise or for the whole Generating Station:
Provided that the terms and conditions for determination of Tariff for Generating Stations specified in this Part shall apply in like manner to Stages or Units or the Generating Station, as the case may be.
39.3 Where the Tariff is being determined for a Stage or Unit of a Generating Station, the Generating Company shall adopt a reasonable basis for allocation of capital
cost relating to common facilities and allocation of joint and common costs across all Stages or Units, as the case may be:
Provided that the Generating Company shall maintain an Allocation Statement providing the basis for allocation of such costs, which shall be duly audited and certified by the statutory auditors and submit such audited and certified statement to the Commission along with the Petition for determination of Tariff:
Provided further that in case the Commission has undertaken study for allocating common cost to unit/station of Generating Company, then such Generating Company shall allocate the cost as per Commission's Order in that regards.
Provided that the Generating Company shall continue to bill the Beneficiaries at the Tariff approved by the Commission and applicable as on March 31, 2025 for the period starting from April 1, 2025 till approval of Tariff by the Commission in accordance with these Regulations.
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.
39.7** In the case of new projects, the Generating Company may be allowed provisional Tariff by the Commission from the anticipated date of commercial operation, based on the projected capital expenditure, subject to prudence check.
39.8** If the date of commercial operation is likely to be delayed beyond six months from the date of issue of the order approving the provisional Tariff, the Generating Company may submit a Petition for seeking extension of the validity of the applicability of the provisional Tariff, giving details of the present status of completion and justification for the delay in project completion, which may be considered by the Commission after necessary prudence check.
39.9 The Generating Company shall file the Petition for determination of final Tariff for new Generating Station within six months from the date of commercial operation of Generating Unit or Stage or Generating Station as a whole, as the case may be, based on the audited capital expenditure and capitalisation as on the date of commercial operation:
Provided that in case of more than one Unit in the Generating Station, such Petition shall be filed for each Unit as and when such Unit achieves COD and without waiting for the COD of the entire Station.
39.10 The final Tariff determination for the new Generating Station shall be done by the Commission based on prudence check of the audited capital expenditure and capitalisation as on the date of commercial operation.
39.11 Where the actual Capital Cost incurred on year to year basis is less than the Capital Cost approved for determination of provisional Tariff by the Commission, by five percent or more, the Generating Company shall refund to the Beneficiaries the excess Tariff realised corresponding to excess Capital Cost, along with interest at the Base Rate, as prevalent on the first day of April of the respective Year, plus 150 basis points.
39.12 Where the actual Capital Cost incurred on year to year basis is more than the Capital Cost approved for determination of provisional Tariff by the Commission, by five percent or more, the Generating Company shall, subject to the approval of the Commission, recover from the Beneficiaries the shortfall in Tariff corresponding to such decrease in Capital Cost, along with interest at the Base Rate, as prevalent on the first day of April of the respective Year, plus 150 basis points.
39.13 A Generating Company with integrated mine(s) shall file a Petition for determination of input price of coal or lignite from the integrated mine(s) not later than 60 days from the date of commercial operation of the integrated mine(s)
Provided that the Generating Company having integrated mine(s) shall file Petition before the Commission for determination of the input price of coal or lignite from the integrated mine(s) containing the details of expenditure incurred and projected to be incurred duly certified by the Auditor, in accordance with the Formats that may be stipulated by the Commission.
39.14 In relation to multi-purpose hydroelectric Projects with irrigation, flood control and power components, the capital cost chargeable to the power component of the Project only shall be considered for determination of Tariff.
40.1 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.
40.2 The Fuel Utilisation Plan should ensure that fuel quantum is allocated to different generating Stations/Units in accordance with the merit order of different generation Stations/Units in terms of variable cost:
Provided that the fuel allocation should be such that, subject to system and other constraints, the least cost generating Stations/Units are operated at maximum availability and other generating Stations/Units are operated at maximum availability thereafter in the ascending order of variable cost.
40.3 The Fuel Utilisation Plan shall comprise the following:
Provided that the forecast or estimates for the Control Period from FY 2025-26 to FY 2029-30 shall be prepared for each month over the Control Period:
Provided further that Fuel Utilisation Plan shall be prepared based on past data and reasonable assumptions for future.
40.4 The beneficiary/ies shall file comments/suggestions on such Plan during proceedings of Tariff Petition as per Regulation 13.
40.5 The Commission shall approve the Fuel Utilisation Plan and rationalise the variable cost of generation for Generating Unit/Station based on such Plan and
suggestions and comments received from the beneficiary/ies for the Control Period as part of its Order on the MYT Petition.
42.1** The Annual Fixed Charges shall comprise the following components:
(a) Operation & Maintenance Expenses;
(b) Depreciation;
(c) Interest on Loan Capital;
(d) Interest on Working Capital;
(e) Return on Equity Capital;
Provided that Depreciation, Interest on Loan Capital, Interest on Working Capital, Return on Equity, and Income tax for Thermal and Hydro Generating Stations shall be allowed, in accordance with the provisions specified in Part D of these Regulations:
Provided that Special Allowance in lieu of R&M, if opted in accordance with the provisions of the Regulation 44 of these regulations, shall be recovered separately and shall not be considered for computation of working capital.
Provided further that prior period income/expenses shall be allowed by the Commission at the time of Truing-up based on audited accounts, on a case-to-case basis, if the income/expenses in that prior period have been allowed on actual basis, subject to prudence check:
Provided also that all penalties and compensation payable by the Generating Company to any party for failure to comply with any directions or for damages, as a consequence of the orders of the Commission, Courts, etc., shall not be allowed to recover through the Aggregate Revenue Requirement:
Provided also that the Generating Company shall maintain separate details of such penalties and compensation paid or payable by the Generating Company, if any, and shall submit them to the Commission along with its Petition.
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, record of consultation with Beneficiaries 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;
43.2 Approval of such proposal for Renovation and Modernisation shall be granted after consideration of reasonableness of the cost estimates, schedule of completion, use of efficient technology, cost-benefit analysis, and such other factors as may be considered relevant by the Commission.
43.3 In case of gas/ liquid fuel based open/combined cycle thermal generating Unit, any expenditure, which has become necessary for renovation of gas turbines/steam
turbine and any expenditure necessitated due to obsolescence or non-availability of spares for efficient operation of the stations shall be allowed:
Provided that any expenditure included in the Renovation and Modernisation on consumables and cost of components and spares, which is generally covered in the O&M expenses during the major overhaul of gas turbine, shall be suitably deducted after prudence check, from the Renovation and Modernisation expenditure to be allowed.
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.
44.2 In case, if the generation plant opts for Special allowance, such Special Allowance shall be included in the annual fixed cost, however, any upward revision of the capital cost or relaxation in the applicable operational norms if any allowed by the Commission shall not be allowed.
Provided that such option shall not be available for a generating station or unit thereof for which Renovation and Modernization has been undertaken and the expenditure has been admitted by the Commission before the commencement of these Regulations;
Provided further that, if the generating plant or unit opted for the Special Allowance for the Control Period and subsequently plans for Renovation and Modernisation during the Control Period, such Plant or Unit shall not be entitled for Specific Allowance for the remaining Control Period from the date of approval of R&M proposal of the Plant or Unit 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.
Provided that special allowance allowed in the MYT Order shall be trued up at the end of Control Period on cumulative basis and unutilized special allowance shall be adjusted in the ARR with the holding cost, if any.
Provided that any revenue earned by the Generating Company from supply of Infirm Power after accounting for the fuel cost shall be used for reduction in Capital Cost and shall not be treated as revenue.
Provided that the Generating Company shall submit full details of its forecast of Non-Tariff Income to the Commission in such form as may be stipulated by the Commission.
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:
Provided further that all supply of electricity by the Generating Company to the housing colonies of its operating staff and for construction works at the generating Station, shall be metered and billed separately:
Provided also that the tariff for supply of electricity by the Generating Company to the housing colonies of its operating staff and supply of electricity by the Generating Company for construction works at the generating Station, shall be the same as the Tariff approved by the Commission for the supply of electricity to the respective consumer category by the Distribution Licensee for that area of supply.
| 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.
| 200/210/250 MW sets | 300 MW sets | 500 MW sets (sub-critical boilers) | 600 MW and above sets (super-critical boilers) |
|---|---|---|---|
| 2415 kcal/kWh | 2385 kcal/kWh | 2375 kcal/kWh | 2230 kcal/kWh |
In respect of 500 MW Units, where the boiler feed pumps are electrically operated, the Gross Station Heat Rate shall be 40 kcal/kWh lower than the gross Station Heat Rate specified above.
For Generating Stations having combination of 200/210/250 MW sets and 300 MW and 500 MW sets, the normative gross Station Heat Rate shall be the weighted average Station Heat Rate.
| Koradi excluding Unit No. 8, 9 and 10 (kCal/kWh) | Khaparkheda excluding Unit No. 5 (kCal/kWh) | Chandrapur excluding Unit No. 8 and 9 (kCal/kWh) | Nashik TPS (kCal/kWh) | Bhusawal excluding Unit No. 4 and 5 (kCal/kWh) |
|---|---|---|---|---|
| 2622 | 2630 | 2688 | 2754 | 2787 |
Provided that the Commission may revise the Gross Station Heat Rate norms for these Generating Stations in case any Renovation & Modernisation is undertaken or these plants/Unit avails for the Special Allowance.
Provided that the Commission may revise the Gross Station Heat Rate norms for this Generating Station in case any Renovation & Modernisation is undertaken or avail for the Special Allowance.
| Mode of operation | Uran GTPS of MSPGCL (kcal/kWh) |
Unit-7 of TPC-G (kcal/kWh) |
|---|---|---|
| Combined Cycle | 2035 | 2035 |
| Open Cycle | 2900 | 2900 |
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:
Provided that the Design Heat Rate shall not exceed the following maximum design Unit Heat Rates depending upon the pressure and temperature ratings of the Units:
| Pressure Rating (kg/cm 2 ) | 150 | 170 | 170 | 247 | 247 | 270 | 270 |
|---|---|---|---|---|---|---|---|
| SHT/RHT (°C) | 535/535 | 537/537 | 537/565 | 537/565 | 565/593 | 593/593 | 600/600 |
| Type of Boiler Feed Pump | Electrical Driven | Turbine driven | Turbine driven | Turbine driven | Turbine driven | Turbine driven | Turbine driven |
| Maximum Turbine Cycle Heat Rate (kcal/kWh) | 1955 | 1950 | 1935 | 1900 | 1850 | 1810 | 1800 |
| Minimum Boiler Efficiency | |||||||
| Sub-Bituminous Indian Coal | 0.86 | 0.86 | 0.86 | 0.86 | 0.86 | 0.865 | 0.865 |
| Bituminous Imported Coal | 0.89 | 0.89 | 0.89 | 0.89 | 0.89 | 0.895 | 0.895 |
| Maximum Design Unit Heat Rate (kcal/kWh) | |||||||
| Sub-Bituminous Indian Coal | 2273 | 2267 | 2250 | 2222 | 2151 | 2105 | 2081 |
| Bituminous Imported Coal | 2197 | 2191 | 2174 | 2135 | 2078 | 2034 | 2022 |
Provided further that in case pressure and temperature parameters of a Unit are different from above ratings, the maximum design Unit Heat Rate of the nearest class shall be taken:
Provided also that where Unit Heat Rate has not been guaranteed but turbine cycle Heat Rate and boiler efficiency are guaranteed separately by the same supplier or different suppliers, the Unit Design Heat Rate shall be arrived at by using guaranteed turbine cycle Heat Rate and boiler efficiency:
Provided also that where the boiler efficiency is below 86% for sub-bituminous Indian coal and 89% for bituminous imported coal, the same shall be considered as 86% and 89%, respectively, for sub-bituminous Indian coal and bituminous imported coal for computation of Gross Station Heat Rate:
Provided also that maximum turbine cycle Heat Rate shall be adjusted for type of dry cooling system:
Provided also that if one or more Units are declared under commercial operation prior to the date of coming into effect of these Regulations, the Heat Rate norms for those Units as well as Units declared under commercial operation on or after the effectiveness of these Regulations shall be lower of the Heat Rate norms arrived at by the above methodology and the norms specified in Regulation 47.4:
Provided also that in case of lignite-fired Generating Stations (including stations based on Circulating Fluidised Bed Combustion [CFBC] technology), maximum design Heat Rates shall be increased using the following factors for moisture content:
For other values of moisture content, multiplying factor shall be pro-rated for moisture content between 30-40% and 40-50% depending upon the rated values of multiplying factor for the respective range given under sub-clauses (a) to (c) above.
Note: In respect of Units where the boiler feed pumps are electrically operated, the maximum design Unit Heat Rate shall be 40 kcal/kWh lower than the maximum design Unit Heat Rate specified above with turbine driven boiler feed pumps.
47.9 Gross Station Heat Rate for New Gas-based/Liquid-based Thermal Generating Unit(s) achieving COD after April 1, 2025 shall be:
= 1.05 x Design Heat Rate of the Unit/Block for Natural Gas and Re-gassified Liquefied Natural Gas (RLNG) (in kcal/kWh)
= 1.071 x Design Heat Rate of the Unit/Block for Liquid Fuel (kcal/kWh)
Where the Design Heat Rate of a Unit shall mean the guaranteed Heat Rate for a Unit at 100% MCR and at site ambient conditions; and the Design Heat Rate of a Block shall mean the guaranteed Heat Rate for a Block at 100% MCR, site ambient conditions, zero percent make up, design cooling water temperature/back pressure.
47.10 In case a Generating Station or Unit is directed by MSLDC to operate below normative loading but at or above technical minimum schedule on account of grid security or due to the lower schedule given by the Beneficiaries, increase in Gross Station Heat Rate may be considered by the Commission based on the provisions of Technical Minimum and compensation thereof in Regulation 34 of Maharashtra (State Grid Code), 2020, subject to prudence check.
47.11 Secondary fuel oil consumption norm for all thermal Generating Stations, except those covered under Regulation 47.12 shall be:
47.12 Secondary fuel oil consumption norm for the following MSPGCL Stations shall be:
| Stations | Secondary Fuel Oil Consumption (ml/kWh) |
|---|---|
| Koradi TPS excluding Unit No. 8, 9 and 10 | 2.81 |
| Khaparkheda TPS excluding Unit No. 5 | 1.20 |
| Chandrapur TPS excluding Unit No. 8 and 9 | 1.00 |
| Nashik TPS | 1.00 |
| Bhusawal TPS excluding Unit No. 4 and 5 | 1.40 |
Provided that the Commission may revise the secondary fuel oil consumption norms for these Generating Stations in case any Renovation & Modernisation is undertaken or avail for Special Allowance.
47.13 Auxiliary Energy Consumption for new 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) 300/330/350/500 MW & above | |
| Steam driven boiler feed pumps | 5.75% |
| Electrically driven boiler feed pumps | 8.00% |
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:
Provided further that additional Auxiliary Energy Consumption as follows may be allowed for plants with Dry Cooling Systems:
| Type of Dry Cooling System | (% of gross generation) |
|---|---|
| Direct cooling air cooled condensers with mechanical draft fans | 1.0% |
| Indirect cooling system employing jet condensers with pressure recovery turbine and natural draft tower | 0.5% |
Provided also that for thermal Generating Stations with any additional equipment that has been mandated by Statutory Authorities, additional Auxiliary Energy Consumption shall be allowed on case-to-case basis after prudence check.
47.14 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 | 8.67% |
| 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.
| Particulars | With Natural Draft cooling tower or without cooling tower |
|---|---|
| (i) 200/250 MW series | 8.50% |
| (ii) 300/500 MW & above | |
| Steam driven boiler feed pumps | 6.00% |
| Electrically driven boiler feed pumps | 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:
Provided further that additional Auxiliary Energy Consumption as follows may be allowed for plants with Dry Cooling Systems:
| Type of Dry Cooling System | (% of gross generation) |
|---|---|
| Direct cooling air cooled condensers with mechanical draft fans | 1.0% |
| Indirect cooling system employing jet condensers with pressure recovery turbine and natural draft tower | 0.5% |
Provided also that for thermal Generating Stations with Flue Gas De-Sulphuriser (FGD), additional Auxiliary Energy Consumption shall be allowed as follows:
Provided also that for thermal Generating Stations with any additional equipment that has been mandated by Statutory Authorities, additional Auxiliary Energy Consumption shall be allowed on case-to-case basis after prudence check.
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;
Provided that additional actual Auxiliary Energy Consumption is allowed, subject to ceiling of 3.00% for Combined Cycle Generating Stations located in coastal regions and using sea water Cooling water system.
Provided that for the lignite fired stations using CFBC technology, the auxiliary energy consumption norms shall be 1.5 percentage points higher than the auxiliary energy consumption norms of coal based Generating Stations specified in Regulation 47.13.
| Sl. | Name of Technology | AUXen (as per cent of gross generation) |
|---|---|---|
| (1) | For reduction of emission of sulphur dioxide | |
| a) | Wet Limestone based FGD system (without Gas to Gas heater) | 1.0% |
| b) | Lime Spray Dryer or Semi dry FGD System | 1.0% |
| c) | Dry Sorbent Injection System (using Sodium bicarbonate) | NIL |
| d) | For CBFC Power plant (furnace injection) | NIL |
| e) | Sea water based FGD system (without Gas to Gas heater) | 0.7% |
| (2) | For reduction of emission of oxide of nitrogen | |
| a) | Selective Non-Catalytic Reduction system | NIL |
| b) | Selective Catalytic Reduction system | 0.2% |
Provided that where the technology is installed with “Gas to Gas” heater, AUXen specified above shall be increased by 0.3% of gross generation.
The specific limestone consumption (g/kWh) shall be worked out by following formula:
$$[K \times \text{SHR} \times S / \text{CVPF}] \times [85 / \text{LP}]$$
Where,
S = Sulphur content in percentage;
LP= Limestone Purity in percentage;
SHR= Gross station heat rate, in kcal per kWh;
CVPF = (a) Weighted Average Gross calorific value of coal as received, in kcal per kg for coal based thermal generating stations less 85 kcal/kg on account of variation during storage at generating station;
(b)Weighted Average Gross calorific value of lignite as received, in kcal per kg, as applicable for lignite based thermal generating stations:
Provided that value of K shall be equivalent to (35.2 x Design SO2 Removal Efficiency/96%) for units to comply with SO2 emission norm of 100/200 mg/Nm3 or (26.8 x Design SO2 Removal Efficiency/73%) for units to comply with SO2 emission norm of 600 mg/Nm3;
Provided further that the limestone purity shall not be less than 85%.
(b) For Lime Spray Dryer or Semi-dry Flue Gas Desulphurisation (FGD) system: The specific lime consumption shall be worked out based on minimum purity of lime (LP) as at 90% or more by applying formula $[6 \times 90 / \text{LP}]$ g/kWh;
(c) For Dry Sorbent Injection System (using sodium bicarbonate): The specific consumption of sodium bicarbonate shall be 12 g per kWh at 100% purity.
(d) For CFBC Technology (furnace injection) based generating station: The specific limestone consumption for CFBC based generating station (furnace injection) shall be computed with the following formula:
$$[62.9 \times S \times \text{SHR} / \text{CVPF}] \times [85 / \text{LP}]$$
Where
S = Sulphur content in percentage;
LP = Limestone Purity in percentage;
SHR = Gross station heat rate, in kcal per kWh;
CVPF = (a) Weighted Average Gross calorific value of coal as received, in kcal per kg for coal based thermal generating stations less 85 kcal/kg on account of variation during storage at generating station;
(b) Weighted Average Gross calorific value of lignite as received, in kcal per kg as applicable for lignite based thermal generating stations;
(e) For Sea Water based Flue Gas Desulphurisation (FGD) system: The reagent used in sea water-based Flue Gas Desulphurisation (FGD) system shall be NIL
(2) The normative consumption of specific reagent for various technologies for reduction of emission of oxide of nitrogen shall be as below:
(a) For Selective Non-Catalytic Reduction (SNCR) System: The specific urea consumption of SNCR system shall be 1.2 g per kWh at 100% purity of urea.
(b) For Selective Catalytic Reduction (SCR) System: The specific ammonia consumption of SCR system shall be 0.6 g per kWh at 100% purity of ammonia.
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% |
Provided that in case of pit head stations if coal or lignite is procured from sources other than the pit head mines, which is transported to the Station through rail, normative transit loss of 0.8% shall be applicable:
Provided further that the above norms shall be applicable for domestic coal and washed coal:
Provided also that in case of imported coal, the normative transit and handling losses shall be 0.2%:
Provided also that for procurement of coal on delivery basis, no transit and handling loss shall be allowed.
Provided that, the impact of the wage revision if any during the Trued-up year shall be included in the O&M expenses while determining the norms for the O&M expenses for the future year.
Provided that the average of such Operation and Maintenance expenses shall be considered as Operation and Maintenance expenses for the Year ended March 31, 2022, and shall be escalated at the respective escalation rate for FY 2022-23, FY 2023-24 and FY 2024-25, to arrive at the Operation and Maintenance expenses for the base year ending March 31, 2025:
Provided further that the escalation rate for FY 2022-23, FY 2023-24 and FY 2024-25 shall be computed by considering 50% 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 50% 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:
Provided also that at the time of true-up for each Year of this Control Period, the Operation and Maintenance expenses, excluding water charges and including insurance, shall be derived on the basis of the Final Trued-up Operation and Maintenance expenses after adding/deducting the sharing of efficiency gains/losses, for the base year ending March 31, 2025, excluding abnormal expenses, if any, subject to prudence check by the Commission, and shall be considered as the Base Year Operation and Maintenance expenses.
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 50% weightage to the average yearly inflation derived based on the monthly Consumer Price Index for Industrial Workers (all-India) of the 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:
Provided that, in the Truing-up of the O&M expenses for any particular year of the Control Period, an inflation factor with 50% weightage to the average yearly inflation derived based on the monthly Wholesale Price Index of the respective past five financial years (including the year of Truing-up) and 50% 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 (including the year of Truing-up), as reduced by an efficiency factor of 1% of Average Escalation factor or as may be stipulated by the Commission from time to time, shall be applied to arrive at the permissible Operation and Maintenance Expenses for that year.
Provided that in the MYT Order, the Commission shall provisionally approve the Water Charges for each year of the Control Period based on the actual Water Charges as per latest Audited Accounts available for the Generating Company, subject to prudence check.
e) 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.
f) Provisioning of expenses shall not be considered as actual expenses at the time of true-up, and only expenses as actually incurred shall be considered.
g) A Generating Company may undertake Opex schemes for system automation, new technology and IT implementation, etc., and such expenses may be allowed over and above normative O&M Expenses, subject to prudence check by the Commission as per the provisions of the MERC (Approval of Capital Investment Schemes) Regulations, 2022:
Provided that the Generating Company shall submit detailed justification, cost benefit analysis, and life-cycle cost analysis (in accordance with Format specified at Annexure V) of such schemes as against capex schemes, and savings in O&M expenses, if any as per the provisions of the MERC (Approval of Capital Investment Schemes) Regulations, 2022.
Provided that if actual O&M expenses are lower than normative O&M expenses on this account, then no sharing of efficiency gains shall be done to that extent.
| Particulars | 200/210/250 MW Sets INR Lakh/MW |
300/330/350 MW Sets INR Lakh/MW |
500 MW Sets INR Lakh/MW |
600/660 MW Sets and above INR Lakh/MW |
|---|---|---|---|---|
| FY 2025-26 | 41.33 | 30.24 | 28.60 | 24.21 |
| FY 2026-27 | 43.12 | 31.35 | 30.10 | 25.26 |
| FY 2027-28 | 44.99 | 32.49 | 31.68 | 26.36 |
| FY 2028-29 | 46.94 | 33.66 | 33.34 | 27.50 |
| FY 2029-30 | 48.97 | 34.86 | 35.09 | 28.69 |
Provided that for the Generating Stations having combination of above Sets, the weighted average value for operation and maintenance expenses shall be allowed:
Provided further that the norms shall be multiplied by the following factors for arriving at norms of O&M expenses for additional Units in respective Unit sizes for the Units whose COD occurs on or after 1.4.2025 in the same Station:
| 200/210/250 MW | Additional 5 th & 6 th Units | 0.90 |
| Additional 7 th & more Units | 0.85 | |
| 300/330/350 MW | Additional 4 th & 5 th Units | 0.90 |
| Additional 6 th & more Units | 0.85 | |
| 500 MW and above | Additional 3 rd & 4 th Units | 0.90 |
| Additional 5 th & above Units | 0.85 |
b) For Lignite based Generating Stations:
| Particulars | Lignite based Unit/Stations INR Lakh/MW |
|---|---|
| FY 2025-26 | 21.43 |
| FY 2026-27 | 22.36 |
| FY 2027-28 | 23.33 |
| FY 2028-29 | 24.34 |
| FY 2029-30 | 25.39 |
c) Gas Turbine/Combined Cycle Generating Stations
| Particulars | Gas Turbine/Combined Cycle Generating Stations INR Lakh/MW |
Small Gas Turbine Generating Stations (less than 50 MW Unit size) INR Lakh/MW |
Advance F Class Machines INR Lakh/MW |
|---|---|---|---|
| FY 2025-26 | 16.17 | 22.23 | 14.90 |
| FY 2026-27 | 16.87 | 23.19 | 15.55 |
| FY 2027-28 | 17.60 | 24.20 | 16.22 |
| FY 2028-29 | 18.37 | 25.25 | 16.93 |
| FY 2029-30 | 19.16 | 26.34 | 17.66 |
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.
49.1 The following Normative Annual Plant Availability Factor (NAPAF) shall apply to hydro Generating Stations:
| Sl. | Particulars | Normative Annual Plant Availability Factor |
|---|---|---|
| a) | Storage and Pondage type plants with head variation between Full Reservoir Level (FRL) and Minimum Draw Down Level (MDDL) of up to 8%, and where plant availability is not affected by silt | 90% |
| b) | Storage and Pondage type plants with head variation between FRL and MDDL of more than 8%, and where plant availability is not affected by silt | The month-wise peaking capacity as provided by the Project authorities in the Detailed Project Report, approved by the relevant authority, shall form the basis of fixation of NAPAF. |
| c) | Pondage type plants where plant availability is significantly affected by silt | 85% |
| d) | Run-of-river type plants | To be determined plant-wise, based on 10-day design energy data, moderated by past experience where available/relevant |
Provided that a further allowance may be made by the Commission in NAPAF determination under special circumstances, e.g., abnormal silt problem or other operating conditions, and known plant limitations.
49.2 The following Normative Auxiliary Energy Consumption shall apply to hydel Generating Stations:
| Type of Station | Installed Capacity above 200 MW | Installed Capacity up to 200 MW |
|---|---|---|
| Surface Hydro Generating Station | ||
| Rotating Excitation | 0.7% | 0.7% |
| Static Excitation | 1.0% | 1.2% |
| Underground Hydro Generating Station | ||
| Rotating Excitation | 0.9% | 0.9% |
| Static Excitation | 1.2% | 1.3% |
Provided that, the impact of the wage revision if any during the Trued-up year shall be included in the O&M expenses while determining the norms for the O&M expenses for the future year.
Provided that the average of such Operation and Maintenance expenses shall be considered as Operation and Maintenance expenses for the Year ended March 31, 2022, and shall be escalated at the respective escalation rate for FY 2022-23, FY 2023-24 and FY 2024-25, to arrive at the Operation and Maintenance expenses for the base year ending March 31, 2025:
Provided further that the escalation rate for FY 2022-23, FY 2023-24 and FY 2024-25 shall be computed by considering 50% 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 50% 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:
Provided also that at the time of true-up for each Year of this Control Period, the Operation and Maintenance expenses, including insurance, shall be derived on the basis of the Final Trued-up Operation and Maintenance expenses, after adding/ deducting the sharing of efficiency gains/ losses, for the year ending March 31, 2025, excluding abnormal expenses, if any, subject to prudence check by the Commission, and shall be considered as the Base Year Operation and Maintenance expenses.
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.
Provided that the Generating Company shall submit detailed justification, cost benefit analysis, and life-cycle cost analysis of such schemes as against capex schemes, and savings in O&M expenses, if any.
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.
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 ( $CC_y$ ) = Sum of Capacity Charge for three months of High Demand Season + Sum of Capacity Charge for nine months of Low Demand Season.
Capacity Charge for the Month ( $CC_m$ ) = Capacity Charge for Peak Hours of the Month ( $CC_p$ ) + Capacity Charge for Off-Peak Hours of the Month ( $CC_{op}$ )
Where,
High Demand Season:
$$CC_{p1} = (0.20 \times AFC) \times \left(\frac{1}{12}\right) \times \left(\frac{PAFMp1}{NAPAF}\right) \text{ subject to ceiling of } (0.20 \times AFC) \times \left(\frac{1}{12}\right)$$
$$CC_{p2} = {(0.20 \times AFC) \times \left(\frac{1}{6}\right) \times \left(\frac{PAFMp2}{NAPAF}\right) \text{ subject to ceiling of } (0.20 \times AFC) \times \left(\frac{1}{6}\right)} - CC_{p1}$$
$$CC_{p3} = {(0.20 \times AFC) \times \left(\frac{1}{4}\right) \times \left(\frac{PAFMp3}{NAPAF}\right) \text{ subject to ceiling of } (0.20 \times AFC) \times \left(\frac{1}{4}\right)} - (CC_{p1} + CC_{p2})}$$
$$CC_{op1} = {(0.80 \times AFC) \times \left(\frac{1}{12}\right) \times \left(\frac{PAFMop1}{NAPAF}\right) \text{ subject to ceiling of } (0.80 \times AFC) \times \left(\frac{1}{12}\right)}$$
$$CC_{op2} = {(0.80 \times AFC) \times \left(\frac{1}{6}\right) \times \left(\frac{PAFMop2}{NAPAF}\right) \text{ subject to ceiling of } (0.80 \times AFC) \times \left(\frac{1}{6}\right)} - CC_{op1}$$
$$CC_{op3} = {(0.80 \times AFC) \times \left(\frac{1}{4}\right) \times \left(\frac{PAFMop3}{NAPAF}\right) \text{ subject to ceiling of } (0.80 \times AFC) \times \left(\frac{1}{4}\right)} - (CC_{op1} + CC_{op2})}$$
Low Demand Season:
$$CC_{p1} = {(0.20 \times AFC) \times \left(\frac{1}{12}\right) \times \left(\frac{PAFMp1}{NAPAF}\right) \text{ subject to ceiling of } (0.20 \times AFC) \times \left(\frac{1}{12}\right)}$$
$$CC_{p2} = {(0.20 \times AFC) \times \left(\frac{1}{6}\right) \times \left(\frac{PAFMp2}{NAPAF}\right) \text{ subject to ceiling of } (0.20 \times AFC) \times \left(\frac{1}{6}\right)} - CC_{p1}$$
$$CC_{p3} = {(0.20 \times AFC) \times \left(\frac{1}{4}\right) \times \left(\frac{PAFMp3}{NAPAF}\right) \text{ subject to ceiling of } (0.20 \times AFC) \times \left(\frac{1}{4}\right)} - (CC_{p1} + CC_{p2})$$
$$CC_{p4} = {(0.20 \times AFC) \times \left(\frac{1}{3}\right) \times \left(\frac{PAFMp4}{NAPAF}\right) \text{ subject to ceiling of } (0.20 \times AFC) \times \left(\frac{1}{3}\right)} - (CC_{p1} + CC_{p2} + CC_{p3})$$
$$CC_{p5} = {(0.20 \times AFC) \times \left(\frac{5}{12}\right) \times \left(\frac{PAFMp5}{NAPAF}\right) \text{ subject to ceiling of } (0.20 \times AFC) \times \left(\frac{5}{12}\right)} - (CC_{p1} + CC_{p2} + CC_{p3} + CC_{p4})$$
$$CC_{p6} = {(0.20 \times AFC) \times \left(\frac{1}{2}\right) \times \left(\frac{PAFMp6}{NAPAF}\right) \text{ subject to ceiling of } (0.20 \times AFC) \times \left(\frac{1}{2}\right)} - (CC_{p1} + CC_{p2} + CC_{p3} + CC_{p4} + CC_{p5})$$
$$CC_{p7} = {(0.20 \times AFC)x \left(\frac{7}{12}\right) x \left(\frac{PAFMp7}{NAPAF}\right)} \text{ subject to ceiling of } (0.20 \times AFC)x \left(\frac{7}{12}\right) - (CC_{p1} + CC_{p2} + CC_{p3} + CC_{p4} + CC_{p5} + CC_{p6})$$
$$CC_{p8} = {(0.20 \times AFC)x \left(\frac{2}{3}\right) x \left(\frac{PAFMp8}{NAPAF}\right)} \text{ subject to ceiling of } (0.20 \times AFC)x \left(\frac{2}{3}\right) - (CC_{p1} + CC_{p2} + CC_{p3} + CC_{p4} + CC_{p5} + CC_{p6} + CC_{p7})$$
$$CC_{p9} = {(0.20 \times AFC)x \left(\frac{3}{4}\right) x \left(\frac{PAFMp9}{NAPAF}\right)} \text{ subject to ceiling of } (0.20 \times AFC)x \left(\frac{3}{4}\right) - (CC_{p1} + CC_{p2} + CC_{p3} + CC_{p4} + CC_{p5} + CC_{p6} + CC_{p7} + CC_{p8})$$
$$CC_{op1} = {(0.80 \times AFC)x \left(\frac{1}{12}\right) x \left(\frac{PAFMop1}{NAPAF}\right)} \text{ subject to ceiling of } (0.80 \times AFC)x \left(\frac{1}{12}\right)$$
$$CC_{op2} = {(0.80 \times AFC)x \left(\frac{1}{6}\right) x \left(\frac{PAFMop2}{NAPAF}\right)} \text{ subject to ceiling of } (0.80 \times AFC)x \left(\frac{1}{6}\right) - CC_{op1}$$
$$CC_{op3} = {(0.80 \times AFC)x \left(\frac{1}{4}\right) x \left(\frac{PAFMop3}{NAPAF}\right)} \text{ subject to ceiling of } (0.80 \times AFC)x \left(\frac{1}{4}\right) - (CC_{op1} + CC_{op2})$$
$$CC_{op4} = {(0.80 \times AFC)x \left(\frac{1}{3}\right) x \left(\frac{PAFMop4}{NAPAF}\right)} \text{ subject to ceiling of } (0.80 \times AFC)x \left(\frac{1}{3}\right) - (CC_{op1} + CC_{op2} + CC_{op3})$$
$$CC_{op5} = {(0.80 \times AFC)x \left(\frac{5}{12}\right) x \left(\frac{PAFMop5}{NAPAF}\right)} \text{ subject to ceiling of } (0.80 \times AFC)x \left(\frac{5}{12}\right) - (CC_{op1} + CC_{op2} + CC_{op3} + CC_{op4})$$
$$CC_{op6} = {(0.80 \times AFC)x \left(\frac{1}{2}\right) x \left(\frac{PAFMop6}{NAPAF}\right)} \text{ subject to ceiling of } (0.80 \times AFC)x \left(\frac{1}{2}\right) - (CC_{op1} + CC_{op2} + CC_{op3} + CC_{op4} + CC_{op5})$$
$$CC_{op7} = {(0.80 \times AFC)x \left(\frac{7}{12}\right) x \left(\frac{PAFMop7}{NAPAF}\right)} \text{ subject to ceiling of } (0.80 \times AFC)x \left(\frac{7}{12}\right) - (CC_{op1} + CC_{op2} + CC_{op3} + CC_{op4} + CC_{op5} + CC_{op6})$$
$$CC_{op8} = {(0.80 \times AFC)x \left(\frac{2}{3}\right) x \left(\frac{PAFMop8}{NAPAF}\right)} \text{ subject to ceiling of } (0.80 \times AFC)x \left(\frac{2}{3}\right) - (CC_{op1} + CC_{op2} + CC_{op3} + CC_{op4} + CC_{op5} + CC_{op6} + CC_{op7})$$
$$CC_{op9} = {(0.80 \times AFC)x \left(\frac{3}{4}\right) x \left(\frac{PAFMop9}{NAPAF}\right)} \text{ subject to ceiling of } (0.80 \times AFC)x \left(\frac{3}{4}\right) - (CC_{op1} + CC_{op2} + CC_{op3} + CC_{op4} + CC_{op5} + CC_{op6} + CC_{op7} + CC_{op8})$$
Where,
$CC_m$ = Capacity Charge for the Month;
$CC_p$ = Capacity Charge for the Peak Hours of the Month;
$CC_{op}$ = Capacity Charge for the Off-Peak Hours of the Month;
$CC_{pn}$ = Capacity Charge for the Peak Hours of nth Month in a specific Season;
$CC_{opn}$ = Capacity Charge for the Off-Peak of nth Month in a specific Season;
AFC = Annual Fixed Cost;
$PAFM_{pn}$ = Plant Availability Factor achieved during Peak Hours upto the end of nth Month in a Season;
$PAFM_{\text{opn}}$ = Plant Availability Factor achieved during Off-Peak Hours upto the end of nth Month in a Season;
NAPAF= Normative Annual Plant Availability Factor.
Provided that in case of generating station or unit thereof under shutdown due to Renovation and Modernisation or installation of Emission Control System (ECS), as the case may be, the Generating Company shall be allowed to recover O&M expenses and interest on loan only.
Provided further that the Generating Company should plan interconnection of ECS with Generating Station during annual overhaul:
Provided also that the Commission shall consider the costs associated with shutdown due to ECS based on prudence check after installation of ECS on case-to-case basis.
51.3 Normative Plant Availability Factor for “Peak” and “Off-Peak” Hours in a month shall be equivalent to the NAPAF specified in Regulations 47.1 and 47.2 of these Regulations. The number of hours of “Peak” and “Off-Peak” periods during a day shall be four and twenty respectively. Hours of Peak and Off-Peak periods during a day shall be declared by MSLDC at least a week in advance. High Demand Season (period of three months, consecutive or otherwise) and Low Demand Season (period of remaining nine months, consecutive or otherwise) in the State shall be declared by MSLDC, at least six months in advance:
Provided that the MSLDC, after duly considering the comments of the concerned stakeholders, shall declare Peak Hours and High Demand Season in such a way as to coincide with the Peak Hours and High Demand Season of the State.
51.4 Any under-recovery or over-recovery of Capacity Charge as a result of under-achievement or over-achievement, vis-à-vis the NAPAF in Peak and Off-Peak Hours of a Season (High Demand Season or Low Demand Season, as the case may be) shall not be adjusted with under-achievement or over-achievement, vis-à-vis the NAPAF in Peak and Off-Peak Hours of the other Season:
Provided that within a Season, the shortfall in recovery of Capacity Charge for cumulative Off-Peak Hours derived based on NAPAF, shall be allowed to be offset by over-achievement of PAF, if any, and consequent notional over-recovery of Capacity Charge for cumulative Peak Hours in that Season:
Provided further that within a Season, the shortfall in recovery of Capacity Charge for cumulative Peak Hours derived based on NAPAF, shall not be allowed to be
off-set by over-achievement of PAF, if any, and consequent notional over-recovery of Capacity Charge for cumulative Off-Peak Hours in that Season:
Provided also that full Capacity Charges shall be recoverable at target availability specified in Regulations 47.1 and 47.2, and recovery of Capacity Charges below the level of Target Availability shall be on pro-rata basis, irrespective of the reasons for the lower Availability, and no part of the Capacity Charges shall be recoverable except to the extent of Availability:
Provided that at zero availability, no Capacity Charges shall be payable.
Energy Charges (INR) = (Energy Charge Rate in INR/kWh) x [Scheduled Energy (ex-bus) for the month in kWh]
Provided also that in case of supply of coal or lignite from the integrated mine(s), the landed cost of primary fuel shall be based on the input price of coal or lignite, as the case may be, as computed in accordance with these Regulations.
$$ECR = \frac{[P_p \times (Q_p)_n + P_s \times (Q_s)n + SRC \times LPR]}{[1-(AUX_n + AUX{en})]} \quad (INR/kWh)$$
Provided that, the provision of SRC and LPR shall be applicable only for stations where FGD mandate & approval is notified by MERC.
Where,
$P_p$ = 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;
$(Q_p)_n$ = 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:
$P_s$ = landed cost of Secondary fuel oil in INR/ml,
$(Q_s)_n$ = Normative Quantity of Secondary fuel oil in ml/kWh as per Regulations 47.11 and 47.12, 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 47.13 to 47.17;
AUXen = Normative Auxiliary Energy Consumption of Emission Control System as % of gross generation as per Regulation 47.18:
Provided that the landed cost of primary fuel and secondary fuel for tariff determination shall be based on actual weighted average cost of primary fuel and secondary fuel of the three preceding months, and in the absence of landed costs for the three preceding months, latest procurement price of primary fuel and secondary fuel for the generating Station, preceding the first month for which the Tariff is to be determined for existing stations, and immediately preceding three months in case of new generating stations shall be taken into account:
Provided further that the landed cost of fuel shall mean the total cost of coal, lignite or the gas delivered to the generating station and shall include the base price of fuel corresponding to the grade/quality/calorific value of fuel inclusive of royalty, taxes and duties as applicable, washery charges as applicable, transportation cost by rail/road/gas pipe line or any other means, charges for third-party sampling, and, for the purpose of computation of energy charges, shall be arrived at after considering normative transit and handling losses as
percentage of the quantity of fuel dispatched by the fuel supply company during the month as specified in Regulation 47.20:
Provided also that in case of blending of fuel from different sources, the weighted average Gross Calorific Value of primary fuel shall be arrived in proportion to blending ratio:
Provided also that any refund of taxes and duties along with any amount received on account of penalties from fuel supplier shall have to be adjusted in fuel cost:
Provided also that the Energy Charges, for the purpose of billing/Fuel Surcharge shall be worked out Station-wise/Unit-wise based on weighted average rate based on scheduled generation from each Unit.
Provided also that where biomass fuel is used for blending with coal, the landed cost of biomass fuel shall be worked out based on the delivered cost of biomass at the unloading point of the generating station, inclusive of taxes and duties as applicable:
Provided also that the energy charge rate of the blended fuel shall be worked out considering consumption of biomass based on blending ratio as specified by Authority or actual consumption of biomass, whichever is lower:
Provided also that the Generating Company may opt for higher blending ratio subject to techno-economic viability and the benefits in terms of lower tariff being entirely passed through to the beneficiaries, and loss, if any, being entirely borne by the Generating Company.
Provided that the difference between the input price of coal determined under these Regulations and the input price of coal so adopted prior to such determination, for the quantity of coal billed, shall be adjusted in accordance with Regulation 51.9.
the last available pooled lignite price as determined by the Commission for transfer price of lignite or the estimated price available in the investment approval, whichever is lower:
Provided that the difference between the input price of lignite determined under these Regulations and the input price of lignite so fixed prior to such determination, for the quantity of lignite billed, shall be adjusted in accordance with Regulation 51.9.
51.9** In case of excess or short recovery of input price under Regulation 51.7 or Regulation 51.8, the Generating Company shall refund the excess amount or recover the shortfall amount, as the case may be, with simple rate of interest, equal to the Base Rate, as prevalent on the first day of April of the respective Year, plus 150 basis points, in six equal monthly instalments.
51.10** Adjustment of ECR [Fuel Surcharge Adjustment] on account of variation in price or heat value of fuels:
Any variation in Price and Gross Calorific Value of coal/lignite or gas or liquid fuel as billed by supplier less actual GCV loss subject to maximum limit specified in the Regulation 51.6 of these Regulations vis-a-vis approved values shall be adjusted on month to month basis on the basis of average Gross Calorific Value of coal/lignite or gas or liquid fuel in stock received and weighted average landed cost incurred by the Generating Company for procurement of coal/lignite, oil, or gas or liquid fuel, as the case may be for a power Station:
Provided that the Generating Company shall upload all GCV related data and supporting for claim for Fuel Surcharge on the website for public scrutiny.
Provided that in its bills, the Generating Company shall indicate Energy Charge Rates at base price of primary and secondary fuel approved by the Commission and the Fuel Surcharge to it separately:
Provided further that the Generating Company shall provide to the Beneficiaries of the generating Station, the details of parameters of GCV and price of fuel for each type of fuel, i.e., domestic coal, imported coal, e-auction coal, lignite, natural gas, RLNG, liquid fuel, etc., as per the forms prescribed by the Commission:
Provided also that in case of part or full use of alternative source of fuel supply by coal based thermal generating stations other than as agreed by the Generating Company and beneficiary/ies in their power purchase agreement for supply of contracted power on account of shortage of fuel or optimization of economical operation through blending, the use of alternative source of fuel supply shall be permitted to generating station:
Provided also that in such case, prior permission from beneficiaries shall not be a precondition, unless otherwise agreed specifically in the power purchase agreement:
Provided also that the weighted average price of alternative source of fuel shall not exceed 5% of base price of primary and secondary fuel approved by the Commission:
Provided also that where the Energy Charge Rate based on weighted average price of fuel upon use of alternative source of fuel supply exceeds 5% of base Energy Charge Rate as approved by the Commission for that year, prior consultation with beneficiary/ies shall be made at least three days in advance:
Provided also that in case use of alternative source of fuel is not opted for, based on prior consultation with beneficiary/ies, then the Generating Company shall be entitled to consider deemed Availability to the extent of reduced Availability on account of fuel non-availability, for the purpose of Availability computations for recovery of Annual Fixed Charges in accordance with Regulation 51.2:
Provided also that the details of blending ratio of the imported coal with domestic coal, proportion of e-auction coal and the weighted average GCV of the fuels as billed by supplier shall also be provided separately, along with the bills of the respective month:
Provided also that copies of the bills and details of parameters of GCV and price of fuel, i.e., domestic coal, imported coal, e-auction coal, lignite, natural gas, RLNG, liquid fuel, etc., details of blending ratio of the imported coal with domestic coal, proportion of e-auction coal shall also be displayed month-wise on the website of the Generating Company, and should be available on its website for a period of three months.
$$AFC \times 0.5 \times NDM / NDY \times (PAFM / NAPAF) \text{ (in Rupees)}$$
Where,
AFC = Annual fixed cost specified for the year, in Rupees.
NAPAF = Normative Annual Plant Availability Factor in percentage
NDM = Number of days in the month
NDY = Number of days in the year
PAFM = Plant availability factor achieved during the month, in Percentage
$$N$$
$$PAFM = 100 \times \sum_{i=1}^N DC_i / {N \times IC \times (1 - AUX)} %$$
$$i = 1$$
Where,
AUX = Normative auxiliary energy consumption in percentage
$DC_i$ = Declared capacity (in ex-bus MW) for the $i^{th}$ 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.
Energy Charges in INR = (Energy Charge Rate in INR / kWh) x {Scheduled Energy (ex-bus)} for the month in kWh
$$ECR = AFC \times 0.5 / {DE \times (1 - AUX)}$$
Where,
DE = Annual Design Energy specified for the Hydro Generating Station, in kWh, subject to Regulation 52.7.
52.7** In case the saleable scheduled energy (ex-bus) of a Hydro Generating Station during a year is less than the saleable Design Energy (ex-bus) for reasons beyond the control of the Generating Company, the following treatment shall be applied on a rolling basis on a Petition filed by the Generating Company:
(i) Shortfall in Energy Charges in comparison to fifty percent of the Annual Fixed Cost shall be allowed to be recovered in six equal monthly instalments:
Provided that in case actual generation from a hydel generating Station is less than the Design Energy for a continuous period of 4 years on account of hydrology factor, the generating Station shall approach the Central Electricity Authority with relevant hydrology data for revision of design energy of the Station.
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 52.6, or one hundred and twenty (120) paise per kWh whichever is lower.
52.9 The MSLDC shall finalise the schedules for the Hydro Generating Stations, in consultation with the Beneficiaries, for optimal utilization of all the energy declared to be available, which shall be scheduled for all Beneficiaries in proportion to their respective allocations in the Generating Station.
Provided that, the MSLDC shall be also guided by the scheduling related provisions specified in the MERC (State Grid Code) Regulations, 2020 and procedures thereof for day-to-day scheduling of Hydro Generating Stations.
53.1 The Generating Company may be required to demonstrate the declared capacity of its Generating Station as and when asked by the MSLDC as per the procedure specified in the Regulation 32 of the MERC State Grid Code, 2020 as amended for time to time.
53.2 In the event of the Generating Company failing to demonstrate the declared capacity, the Annual Fixed Charges due to the Generating Company shall be reduced as a measure of penalty.
53.3 The quantum of penalty for the first mis-declaration for any duration/block in a day shall be the charges corresponding to two days fixed charges.
53.4 For the second mis-declaration, the penalty shall be equivalent to fixed charges for four days and for subsequent mis-declarations in the year, the penalty shall be multiplied in the geometrical progression.
53.5 The operating logbooks of the Generating Station shall be available for scrutiny by the MSLDC, and these books shall keep record of machine operation and maintenance.
54.1 The Billing and Payment of Annual Fixed Charges, Energy Charges, Fuel Surcharge Adjustments and Incentive for Thermal Generating Stations, and of Capacity Charges and Energy Charges for Hydro Generating Stations including Pumped Storage Plants, shall be done on a monthly basis.
Provided that the Deviation Charges paid or earned by the Generating Company/ies in accordance with Regulation 9 of the Maharashtra Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters) Regulations, 2019 and Additional Charges for Deviation in accordance with Regulation 10 of the Maharashtra Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters) Regulations, 2019, shall not be recoverable/adjusted from the Beneficiary/ies through Tariff:
Provided further that the Deviation Charges paid or earned by the Distribution Licensees in accordance with Regulation 9 of the Maharashtra Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters) Regulations, 2019 shall be recoverable/adjusted from the Beneficiary/ies through Tariff:
Provided also that the Additional Charges for Deviation paid or earned by the Distribution Licensees in accordance with Regulation 10 of the Maharashtra Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters) Regulations, 2019, shall not be recoverable from the Beneficiary/ies through Tariff.
56.1 Input price of coal or lignite from the integrated mine(s) shall be determined based on the following components:
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 pass-through 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.
57.1 Run of Mine Cost of coal in case of integrated mine(s) allocated through auction route under Coal Mines (Special Provisions) Act, 2015 shall be worked out as under: ROM Cost = (Quoted Price of coal) + (Fixed Reserve Price)
Where,
i. Quoted Price of coal is the Final Price Offer of coal in respect of the concerned coal block or mine, along with subsequent escalation, if any, as provided in the Coal Mine Development and Production Agreement or Allotment Agreement:
Provided that additional premium, if any, quoted by the generating company during auction, shall not be considered in the Run of Mine Cost;
ii. 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: and
iii. Capital cost under Regulation 59 and additional capital expenditure under Regulation 60 shall not be admissible for the purpose of ROM cost in respect of integrated mine(s) allocated through auction route.
57.2 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 61 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.
57.3 Run of Mine Cost of lignite in case of integrated mine(s) for lignite shall be worked out as under:
ROM Cost = [(Annual Extraction Cost / ATQ) + (Mining Charge)]
Where,
i. Annual Extraction Cost is the cost of extraction of lignite as computed in accordance with Regulation 61 of these Regulations; and
ii. Mining Charge is the charge per tonne of lignite paid by the Generating Company to the Mine Developer and Operator engaged by the Generating Company for mining, wherever applicable.
57.4 The Generating Company shall adhere to the Mining Plan for extraction of coal or lignite on annual basis and shall submit a certificate to that effect from the Coal Controller or the competent authority:
Provided that deviations from the Mining Plan shall be considered only if such deviations have been approved by the Coal Controller or the revised Mining Plan has been approved by the competent authority.
57.5 Run of Mine Cost of coal and lignite shall be worked out in terms of Rupees per tonne.
58.1 Where crushing or transportation or handling or washing are undertaken by the Generating Company without engaging Mine Developer and Operator or an agency other than Mine Developer and Operator, additional charges shall be worked out as under:
(i) Crushing Charges = Annual Crushing Cost/Quantity;
(ii) Transportation Charges = Annual Transportation Cost/Quantity:
Provided that separate transportation charges, as applicable, shall be considered from mine up to washery end or coal handling plant associated with the integrated mine(s) and beyond washery end or coal handling plant associated with the integrated mine(s) and up to the loading point, as the case may be;
(iii) Handling charges = Annual Handling Cost/Quantity; and
(iv) Washing Charges = Annual Washing Cost/Quantity.
Where,
a. Annual Crushing Cost, Annual Transportation Cost, Annual Handling Cost and Annual Washing Cost shall be worked out on the basis of following components, for which the generating company shall submit the capital cost separately:
vi. Statutory charges, if applicable.
b. Quantity shall be the quantity of coal or lignite in tonne crushed or transported or handled or washed, as the case may be, during the year duly certified by the Auditor.
58.2 Where crushing, transportation, handling or washing are within the scope of the Mine Developer and Operator engaged by the Generating Company, no additional charges shall be admitted, as the same shall be recovered through Mining Charge of the Mine Developer and Operator.
58.3 Where crushing, transportation, handling or washing are undertaken by the Generating Company by engaging an agency other than Mine Developer and Operator, the annual charges of such agencies shall be considered as part of the Operation and Maintenance Expenses, provided that the charges have been discovered through a transparent competitive bidding process.
58.4 The crushing charges, transportation charges, handling charges, and washing charges shall be admitted by the Commission after prudence check, considering charges of Coal India Limited or similarly placed coal mines or any other reference charges.
58.5 The crushing charges, transportation charges, handling charges, and washing charges shall be worked out in terms of Rupees per tonne.
59.1 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.
59.2 Capital expenditure incurred shall be admitted by the Commission after prudence check.
59.3 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.
60.1** The expenditure, in respect of the integrated mine(s), incurred or projected to be incurred after the date of commercial operation and up to the date of achieving the Peak Rated Capacity may be admitted by the Commission, subject to prudence check and shall be capitalized in the respective year of the Control Period as additional capital expenditure corresponding to the Annual Target Quantity of the year as specified in the Mining Plan or actual extraction in that year, whichever is higher, on following counts:
a) expenditure incurred on activities as per the Mining Plan;
b) expenditure for works deferred for execution and un-discharged liabilities recognized for works executed prior to date of commercial operation;
c) expenditure for works required to be carried out for complying with directions or orders of any statutory authorities;
d) liabilities arising out of compliance of order or decree of any court of law or award of arbitration;
e) expenditure for procurement and development of land as per the Mining Plan;
f) expenditure for procurement of additional heavy earth moving machineries for replacement, on completion of their useful life; and
g) liabilities due to Change in Law or Force Majeure events:
Provided that in case of replacement of any assets, the additional capitalization shall be worked out after adjusting the gross fixed assets and cumulative depreciation of the assets replaced on account of de- capitalization:
Provided further that the Generating Company shall prepare guidelines for procurement and replacement of heavy mining equipment such as Heavy Earth Moving Machineries and share the same with the beneficiaries and submit it to the Commission along with its Petition.
the Commission subject to prudence check, and shall be capitalized as Additional Capital Expenditure, corresponding to the Annual Target Quantity of the respective years as specified in the Mining Plan, on following counts:
Provided that in case of replacement of any assets, the additional capitalization shall be worked out after adjusting the gross fixed assets, cumulative depreciation and cumulative repayment of loan of the assets replaced on account of de-capitalization.
60.3 The expenditure on following counts shall not be considered as additional capital expenditure for the purpose of these Regulations:
61.1 The Annual Extraction Cost of integrated mine(s) shall consist of the following components:
a) Depreciation;
b) Interest on Loan;
c) Return on Equity;
d) Operation and Maintenance Expenses, excluding mining charge;
e) Interest on Working Capital;
f) Mine closure expenses, if not included in mining charge; and
g) Statutory charges, if applicable.
Provided that,
63.3 The salvage value of an asset shall be considered as 10% of the capital cost of the asset:
Provided that the salvage value shall be:
63.4 Depreciation in respect of integrated mine(s) shall be arrived at annually by applying depreciation rates or on the basis of expected useful life specified in Annexure-II of these Regulations:
Provided that specialized mining equipment shall be depreciated as per the useful life and depreciation rate as notified by the Ministry of Corporate Affairs under the Companies Act, 2013.
64.1 The Operation and Maintenance expenses in respect of integrated mine(s) of coal, for the Control Period ending on March 31, 2025 shall be allowed based on the projected Operation and Maintenance Expenses for each year of the tariff period subject to prudence check by the Commission:
Provided that the Operation and Maintenance expenses allowed under this clause shall be trued up based on actual expenses for the Control Period ending on March 31, 2025.
64.2 Where the development and operation of the integrated mine(s) is undertaken by the Generating Company by engaging Mine Developer and Operator, the Mining Charge of such Mine Developer and Operator shall not be included in Operation and Maintenance Expenses under Regulation 64.1.
64.3 Where an agency other than Mine Developer and Operator is engaged by the Generating Company, through a transparent competitive bidding process, for crushing or transportation or handling or washing or any combination thereof, the annual charges of such agency shall be considered as part of Operation and Maintenance Expenses under Regulation 64.1, subject to prudence check by the Commission.
65.1 The working capital of the integrated mine(s) of coal shall cover:
Provided that,
a) the amount deposited in the Escrow Account as per the Mining Plan prior to the Date of Commercial Operation of the integrated mine(s) shall be indicated separately and shall be recovered over the useful life of the integrated mine(s) in the form of annuity linked to the borrowing rate;
b) the amount deposited in the Escrow Account as per the Mining Plan or any expenditure incurred towards mine closure shall be excluded from the capital cost for computing input price;
66.2** The amount towards mine closure shall be deposited in the Escrow Account as per the Mining Plan and shall be recovered as part of input price irrespective of the expenditure incurred towards mine closure during any of the years of the Control Period.
66.3** Where mine closure is within the scope of Mine Developer and Operator engaged by the Generating Company and mine closure expenses are part of the Mining Charge of Mine Developer and Operator, the mine closure expenses shall be met out of the Mining Charge and no mine closure expenses shall be admissible to the Generating Company separately:
Provided that,
a) the amount deposited in the Escrow Account by the Mine Developer and Operator or by the Generating Company and any amount received from the Escrow Account against expenditure incurred towards mine closure shall not be considered for computing input price; and
66.4** Where the mine closure is within the scope of Mine Developer and Operator engaged by the Generating Company only for a part of useful life of the integrated mine(s) and the Generating Company undertakes the mine closure for the balance useful life, the treatment of mine closure during the period undertaken by the Generating Company shall be in accordance with Regulation 66.1 and mine closure during the period undertaken by the Mine Developer and Operator shall be in accordance with Regulation 66.3:
Provided that the treatment of mine closure at the end of useful life of the integrated mine(s) shall be decided by the Commission on case-to-case basis.
Input Price = [ROM Cost + Additional charges]
67.2 The credit arising on account of adjustment due to shortfall in overburden removal, GCV Adjustment and Non-tariff Income, if any, shall be dealt separately in the manner specified in these Regulations.
67.3 Statutory Charges, as applicable, shall be allowed.
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.
69.3 In case of excess of overburden removal during a year, the generating company shall be allowed to carry forward such excess for adjustment against the shortfall, if any, during subsequent three years.
69.4 Where the shortfall of overburden removal of any year is not made good by the generating company in accordance with Clause (2) of this Regulation, the adjustment on account of shortfall of overburden removal (OB Adjustment) for that year shall be worked out as under:
Where,
Mining Charge is the charge per tonne of coal or lignite paid by the Generating Company to the Mine Developer and Operator engaged by the Generating Company for mining, wherever applicable.
69.5 The provisions of this Regulation regarding adjustment on account of shortfall of overburden removal shall not be applicable in case of the integrated mine(s) allocated through auction route under Coal Mines (Special Provisions) Act, 2015.
70.1 In case the weighted average GCV of coal extracted from the integrated mine(s) in a year is higher than the declared GCV of coal for such mine(s), no GCV adjustment shall be allowed.
70.2 In case the weighted average GCV of coal extracted from the integrated mine(s) in a year is lower than the declared GCV of coal of such mine(s), the GCV adjustment in that year shall be worked out as under:
70.3 Where the integrated mine(s) are allocated through auction route under Coal Mines (Special Provisions) Act, 2015:
$$\text{GCV Adjustment} = (\text{Quoted Price of coal} + \text{Fixed Reserve Price}) \times [(\text{Declared GCV of coal} - \text{Weighted Average GCV of coal extracted in the year}) / (\text{Declared GCV of coal})]$$
Where,
Provided that additional premium, if any, quoted by the Generating Company in auction, shall not be considered; and
(ii) Declared GCV of coal shall be the GCV of coal as specified or quoted in the auction.
a) Where the integrated mine(s) are allocated through allotment route under Coal Mines (Special Provisions) Act, 2015:
$$\text{GCV Adjustment} = [(\text{Annual Extraction Cost/ATQ}) + (\text{Mining Charge})] \times [(\text{Declared GCV of coal} - \text{Weighted Average GCV of coal extracted in the year}) / (\text{Declared GCV of coal})]$$
Where,
71.1 Adjustment on account of Non-Tariff Income (NTI Adjustment) for any year, such as income from sale of washery rejects in case of integrated mine of coal and profit, if any, from supply of coal to the Coal India Limited or merchant sale of coal as allowed under the Coal Mines (Special Provisions) Act, 2015 shall be worked out as under:
$$\text{NTI Adjustment} = (\text{All Non-Tariff Income during the year}) / (\text{Actual quantity of coal or lignite extracted during the year})$$
Provided that the price of sale of washery rejects shall not be lesser than actual transport cost incurred.
71.2 The adjustment on account of Non-Tariff Income worked out in accordance with this Regulation shall not be applicable in case of the integrated mine(s) allocated through auction route under Coal Mines (Special Provisions) Act, 2015.
72.1 The credit arising on account of OB Adjustment, GCV Adjustment and NTI Adjustment shall be dealt through Credit Adjustment Note for any year.
72.2 The Credit Adjustment Note shall be issued in favour of the specified end use generating stations on account of OB Adjustment, GCV Adjustment or NTI Adjustment, as the case may be, for that year as under:
72.3 The amount in Credit Adjustment Note shall be adjusted against the charges of coal or lignite supplied after the date of issue of Credit Adjustment Note and the integrated mine(s) shall prepare an annual reconciliation statement of such adjustment and furnish the same to all the end use plants and also publish the same on its website.
73.1 The quality of coal or lignite supplied from the integrated mine(s) shall be measured at the loading point through third party sampling as per the guidelines and procedure specified by the Ministry of Coal, Government of India and records of such measurement of quality of coal shall be made available to the beneficiaries on demand.
74.1 Provisions of Part D of these Regulations shall not be applicable in case of integrated mine(s), except to the extent specifically provided for or referred to in Part F.
Provided that the financial parameters required for determination of input price of coal or lignite from integrated mine(s), if not specifically provided for or referred to in Part F shall be considered as per provisions of these Regulations as applicable to the coal or lignite based generating stations.
75.1 The Regulations contained in this Part shall apply to the determination of Tariff for access and use of the Intra-State transmission system pursuant to a Bulk Power Transmission Agreement or other arrangement entered into with a Transmission System User, which is not covered under Regulation 75.3 dealing with the adoption of tariff through Tariff Based Competitive Bidding (TBCB) Route under Section 63 of the Act:
Provided that in case a new transmission system set up by a new Transmission Licensee is added to the existing system during the Control Period, the Commission shall redetermine the Tariff for the remaining years of the Control Period having regard to the Petition for determination of Aggregate Revenue Requirement submitted by such Transmission Licensee for the remaining years of the Control Period.
75.2 The Commission shall be guided by the terms and conditions contained in this Part in specifying the rates, charges, terms and conditions for use of intervening transmission facilities pursuant to a Petition filed in this regard by a Transmission Licensee under the proviso to Section 36 (1) of the Act.
75.3 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.”
76.1 The transmission charges for access to and use of the intra-State transmission system shall comprise any of the following components or a combination of the following components:
76.2 Any person who is eligible to apply for access to the intra-State transmission system shall be entitled to obtain such access in accordance with the Regulations of the Commission governing Transmission Open Access and shall be liable to pay the charges for obtaining such access as specified in this Regulation.
Explanation: For the purpose of this Regulation, such person who, being eligible for transmission open access, has applied for allocation of transmission capacity rights and has agreed to the carrying out of works for obtaining such access shall hereinafter be referred to as the “intending Transmission System User”, and may include an existing Transmission System User in respect of any increase in allocated transmission capacity rights applied for by such existing user.
76.3 Where the access of the intending Transmission System User entails works, relating to the intra-State transmission system, the Transmission Licensee shall recover the expenses relating to such works through annual transmission charges for each Year of the Control Period, in accordance with Regulation 76.9 of these Regulations.
76.4 Where any works for obtaining access have been carried out by the intending Transmission System User, the Transmission Licensee shall be entitled to recover supervision charges at the rate of 15 per cent of the cost of labour employed for carrying out such works and shall not be entitled to recover any other expenses with regard to such works:
Provided that such supervision charges shall form part of the Non-Tariff Income of the respective Transmission Licensee and shall also be treated as O&M expense incurred by the intending transmission system users, which shall be capitalised in the respective year of asset capitalisation.
76.5 The works for providing access to the intra-State transmission system shall be maintained by the Transmission Licensee for the duration of the Bulk Power Transmission Agreement between the Transmission Licensee and the Transmission System User.
76.6 Where the Transmission System User has paid for the works carried out to provide it access to the intra-State transmission system, the Transmission System User shall be entitled to the depreciated value of such works paid for by it upon termination of the Bulk Power Transmission Agreement:
Provided that where the Transmission System User has carried out the works to provide it access to the intra-State transmission system of the Transmission Licensee, the Transmission System User shall be entitled to retain such works upon termination of the Bulk Power Transmission Agreement.
76.7 The transmission system access charges may be recovered by any one of the following methods, in accordance with the terms of the Bulk Power Transmission Agreement:
76.8 Any dispute between the Transmission Licensee and the intending Transmission System User with regard to the works to be carried out to give access to the intending Transmission System User or with regard to the transmission system access charges shall be referred to the Commission for adjudication or to such other forum as may be stipulated.
76.9 The Annual Transmission Charges for each Year of the Control Period shall provide for the recovery of the Aggregate Revenue Requirement of the Transmission Licensee for the respective Year of the Control Period, as approved by the Commission and comprising the following components:
Provided that Depreciation, Interest on Loan Capital, Interest on working capital and deposits from Transmission System Users, Contribution to Contingency Reserves, Return on Equity, and Income Tax for Transmission Licensees shall be allowed in accordance with the provisions specified in Part D of these Regulations:
Provided further that the components of the Aggregate Revenue Requirement corresponding to the transmission lines owned by Maharashtra State Electricity
Transmission Company Limited (MSETCL) and conveying electricity to other States, being recovered through transmission charges under General Network Access in accordance with the Regulations and Orders of the Central Electricity Regulatory Commission, shall not be recovered from the Annual Transmission Charges determined under these Regulations:
Provided also that in case any such components have already been recovered through the intra-State transmission tariff, then such excess recovery shall be deducted from the Aggregate Revenue Requirement of MSETCL for the future years, along with associated holding cost, as applicable:
Provided also that prior period income/expenses shall be allowed by the Commission at the time of truing up based on audited accounts, on a case to case basis, if the income/expenses in that prior period have been allowed on actual basis, subject to prudence check:
Provided also that all penalties and compensation payable by the Licensee to any party for failure to meet any Standards of Performance or for damages, as a consequence of the orders of the Commission, Courts, etc., shall not be allowed to be recovered through the Aggregate Revenue Requirement:
Provided also that the Transmission Licensee shall maintain separate details of such penalties and compensation paid or payable by the Licensee, if any, and shall submit them to the Commission along with its Petition.
77.1 A new Transmission Licensee shall file the Petition for determination of provisional Tariff, six months prior to the anticipated date of commercial operation of the transmission assets.
77.2 The new Transmission Licensee shall file a Petition for determination of provisional Tariff 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
78.1 The Transmission Licensee shall submit a detailed capital investment plan, financing plan and physical targets for each year of the Control Period for strengthening and augmentation of the intra-State transmission system of the Transmission Licensee, meeting the requirement of load growth, improvement in quality of supply, reliability, metering, reduction in congestion, etc., to the Commission for approval, as a part of the Multi-year Aggregate Revenue Requirement for the entire Control Period.
78.2 The Capital Investment Plan shall be a least cost plan for undertaking investments and shall cover all capital expenditure projects of a value as specified in the Regulation 4.1 of the MERC (Approval of Capital Investment Schemes) Regulations, 2022. The Capital Investment Plan shall be accompanied by such information, particulars and documents as may be required including but not limited to the information such as number of bays, name, configuration and location of grid substations, substation capacity (MVA), transmission line length (circuit kilometres) showing the need for the proposed investments, alternatives considered, cost-benefit analysis and other aspects that may have a bearing on the transmission charges.
78.3 The Capital Investment Plan of the Transmission Licensee shall be consistent with the transmission system plan for the intra-State transmission system developed by the State Transmission Utility bearing in mind the transmission system plan for the inter-State transmission system developed by the Central Transmission Utility:
Provided that any capital expenditure incurred by the Transmission Licensee based on the specific requirement of a Generating Company or Distribution Licensee shall be substantiated with necessary documentary evidence in the form of request for the same and undertaking given as appropriate.
78.4 The Commission shall consider the Capital Investment Plan along with the Multi-year Aggregate Revenue Requirement for the entire Control Period submitted by the Transmission Licensee taking into consideration the prudence of the proposed expenditure and estimated impact on transmission charges and also taking into considerations factors outlined under Regulation 24.5 and Regulation 24.6 of these Regulations.
78.5 The Transmission Licensee shall submit, along with the Petition for determination of Aggregate Revenue Requirement or along with the Petition for truing up, as the case may be, details showing the progress of capital expenditure projects,
together with such other information, particulars or documents as the Commission may require assessing such progress.
79.1 Target availability for the Transmission Licensee shall be as under:
Recovery of annual transmission charges below the level of target availability shall be on pro-rata basis, and at zero availability, no transmission charges shall be payable.
The target availability shall be computed in accordance with procedure provided in the Annexure-VI to these Regulations and be certified by MSLDC.
Provided that for AC system, two tripping per element per year shall be allowed, and after two tripping in a year, additional 12 hours outage for that particular element for each such tripping shall be considered in addition to the actual outage: Provided further that in case of outage of a transmission element affecting evacuation of power from a generating Station, outage hours shall be multiplied by a factor of 2.0.
Provided also that the computation of additional rate of Return on Equity shall be undertaken as per these Regulations.
80.1 The norms for O&M expenses for existing and new Transmission Licensees have been specified on the basis of circuit kilometre of transmission lines, number of Bays and MVA Capacity of Transformers in the substation of the Transmission Licensee, as given below:
Explanation: For the purpose of applying normative O&M expenses under these Regulations, a 'Bay' shall mean a set of accessories that are required to connect an electrical equipment such as Transmission Line, Bus Section Breakers,
Potential Transformer, Power Transformers, Inter-Connecting Transformers, Capacitors and Transfer Breaker and the feeders emanating from the bus at sub-Station of Transmission Licensee. Further, the Bays referred to shall include only the Bays at the Transmission substation and shall exclude any Bays of the Generating Station switchyard whose maintenance is usually the responsibility of the Generating Company.
Further, for the purpose of applying normative O&M expenses under these Regulations, 'Transformation Capacity' shall be considered as the capacity of the Inter-Connecting Transformer or the Power Transformer as the case may be.
Provided that for computing the allowable O&M expenses for any Year, 50 per cent of the circuit kilometre of transmission lines, number of Bays and transformation capacity in the substation of the Transmission Licensee added during the Year shall also be considered.
Provided further that at the time of Truing up at the end of the Control Period, the allowable O&M expenses for any Year shall be based on the norms for O&M expenses specified by the Commission in this Regulation and documentary evidence of assets capitalised by the Petitioner, subject to the prudence check of the Commission:
Provided also that the number of Bays considered for allowing O&M expenses shall exclude the unutilised Bays and unutilised transformation capacity;
Provided that, the Commission may determine the separate O&M norms on case to case basis for HVDC having technology other than Back to Back stations or Bipole scheme technology in accordance with provision of these Regulations.
Norms for O&M expenses for the Maharashtra State Electricity Transmission Company Limited shall be:
| Voltage Level | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| HVDC (INR Lakh) | 1800.00 | 1905.00 | 2010.00 | 2130.00 | 2252.93 |
| INR Lakh/ckt km | |||||
| 400 kV | 4.02 | 4.20 | 4.38 | 4.57 | 4.78 |
| Less than 400 kV and greater than 66 kV | 1.59 | 1.66 | 1.74 | 1.81 | 1.90 |
| 66 kV and less | 0.95 | 1.00 | 1.04 | 1.09 | 1.14 |
| INR Lakh/Bay | |||||
| 765 kV | 50.62 | 52.89 | 55.26 | 57.74 | 60.34 |
| 400 kV | 36.16 | 37.78 | 39.48 | 41.25 | 43.10 |
| Less than 400 kV and greater than 66 kV | 5.24 | 5.47 | 5.72 | 5.98 | 6.24 |
| 66 kV and less | 1.09 | 1.14 | 1.19 | 1.25 | 1.30 |
| INR Lakh/MVA | 0.51 | 0.53 | 0.55 | 0.58 | 0.61 |
| Voltage Level | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| INR Lakh/ckt km | |||||
| >66 kV & <400 kV | 7.37 | 7.70 | 8.04 | 8.41 | 8.78 |
| INR Lakh/Bay | |||||
| above 66 kV and less than 400 kV | 13.07 | 13.66 | 14.27 | 14.91 | 15.58 |
| 66 kV and less | 2.73 | 2.85 | 2.98 | 3.12 | 3.26 |
| INR Lakh/MVA | 0.84 | 0.88 | 0.91 | 0.96 | 1.00 |
| Voltage Level | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| INR Lakh/ckt km | |||||
| 220 kV | 6.12 | 6.39 | 6.68 | 6.98 | 7.29 |
| INR Lakh/Bay | |||||
| 220 kV | 9.28 | 9.70 | 10.13 | 10.59 | 11.06 |
| 33 kV | 1.94 | 2.03 | 2.12 | 2.21 | 2.31 |
| INR Lakh/MVA | 0.56 | 0.59 | 0.62 | 0.64 | 0.67 |
| Voltage Level | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| INR Lakh/ckt km | |||||
| 400 kV | 0.54 | 0.56 | 0.59 | 0.61 | 0.64 |
| INR Lakh/Bay | |||||
| 400 kV | 95.83 | 100.14 | 104.63 | 109.33 | 114.24 |
| Voltage Level | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| INR Lakh/ckt km | |||||
| 765 kV | 1.31 | 1.37 | 1.43 | 1.49 | 1.56 |
| 400 kV | 0.66 | 0.69 | 0.72 | 0.76 | 0.79 |
| INR Lakh/Bay | |||||
| 765 kV | 124.22 | 129.80 | 135.63 | 141.72 | 148.08 |
| 400 kV | 61.19 | 63.94 | 66.81 | 69.81 | 72.95 |
| INR Lakh/MVA | 0.95 | 0.99 | 1.04 | 1.08 | 1.13 |
| Voltage Level* | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| INR Lakh/ckt km | |||||
| 400 kV | 0.85 | 0.89 | 0.93 | 0.97 | 1.02 |
| INR Lakh/Bay | |||||
| 400 kV | 186.51 | 194.89 | 203.64 | 212.78 | 222.33 |
* No Transformer capacity; recovery only through lines and bays
| Voltage Level | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| INR Lakh/ckt km | |||||
| 220 kV | 3.07 | 3.20 | 3.35 | 3.50 | 3.66 |
| INR Lakh/Bay | |||||
| 220 kV | 15.71 | 16.42 | 17.15 | 17.92 | 18.73 |
* No Transformer capacity; recovery only through lines and bays
| Voltage Level | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| INR Lakh/ckt km | |||||
| 400 kV | 0.83 | 0.86 | 0.90 | 0.94 | 0.98 |
| INR Lakh/Bay | |||||
| 400 kV | 179.94 | 188.02 | 196.46 | 205.29 | 214.50 |
* No Transformer capacity; recovery only through lines and bays
| Voltage Level | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| HVDC Station* | |||||
| HVDC Back-to-Back stations (INR Lakh per MW) | 2.15 | 2.27 | 2.41 | 2.55 | 2.70 |
| HVDC bipole scheme (INR Lakh per MW) | 1.13 | 1.20 | 1.27 | 1.34 | 1.42 |
| INR Lakh/ckt km | |||||
| 765 kV | 1.31 | 1.37 | 1.43 | 1.49 | 1.56 |
| 400 kV | 0.54 | 0.56 | 0.59 | 0.61 | 0.64 |
| Less than 400 kV and greater than 66 kV | 1.59 | 1.66 | 1.74 | 1.81 | 1.90 |
| 66 kV and less | 0.95 | 1.00 | 1.04 | 1.09 | 1.14 |
| INR Lakh/Bay | |||||
| 765 kV | 124.22 | 129.80 | 135.63 | 141.72 | 148.08 |
| 400 kV | 95.83 | 100.14 | 104.63 | 109.33 | 114.24 |
| Voltage Level | FY 2025-26 | FY 2026-27 | FY 2027-28 | FY 2028-29 | FY 2029-30 |
|---|---|---|---|---|---|
| Less than 400 kV and greater than 66 kV | 5.24 | 5.47 | 5.72 | 5.98 | 6.24 |
| 66 kV and less | 1.09 | 1.14 | 1.19 | 1.25 | 1.30 |
| INR Lakh/MVA | 0.51 | 0.53 | 0.55 | 0.58 | 0.61 |
Explanation: The term "New Transmission Licensee" shall mean the transmission Licensee(s) for which Transmission Licence is granted by the Commission prior to or after the date of coming into effect of these Regulations, and for whom the O&M norms have not been specified in Regulations 80.1 to 80.9.
The O&M expenses for the GIS bays shall be allowed as worked out by multiplying 0.70 to the normative O&M expenses for bays as allowed in Regulations 80.1 to 80.9.
80.10 A Transmission Licensee may undertake Opex schemes for system automation, new technology and IT implementation, etc., and such expenses may be allowed over and above normative O&M Expenses, subject to prudence check by the Commission:
Provided that the Transmission Licensee shall submit detailed justification, cost benefit analysis, and life cycle cost analysis of such schemes as against capex schemes, and savings in O&M expenses, if any as per the provisions of the MERC (Approval of Capital Investment Schemes) Regulations, 2022.
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.
81.1 The amount of non-Tariff income relating to the Transmission Business as approved by the Commission shall be deducted from the Aggregate Revenue Requirement in determining the Annual Transmission Charges of the Transmission Licensee:
Provided that the Transmission Licensee shall submit full details of its forecast of non-Tariff income to the Commission in such form as may be stipulated by the Commission.
81.2 The Non-Tariff Income shall include:
Income from rent of land or buildings;
b) Income from sale of scrap;
c) Income from investments;
d) Income from investments of Contingency Reserves;
e) Interest income on advances to suppliers/contractors;
f) Income from rental from staff quarters;
g) Income from rental from contractors;
h) Income from hire charges from contractors and others;
i) Supervision charges for capital works;
j) Income from advertisements;
k) Income from sale of tender documents;
l) Any other Non-Tariff Income
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.
82.1 Where the Transmission Licensee has engaged in any Other Business under Section 41 of the Act for optimum utilisation of its assets, an amount equal to two-third of the revenues from such Other Business after deduction of all direct and indirect costs attributed to such Other Business shall be deducted from the Aggregate Revenue Requirement in calculating the Annual Transmission Charges of the Transmission Licensee:
Provided that the Transmission Licensee shall follow a reasonable basis for allocation of all joint and common costs between the Transmission Business and the Other Business and shall submit the Allocation Statement, duly certified by the Statutory Auditor, to the Commission along with its Petition for determination of Aggregate Revenue Requirement:
Provided further that where the sum total of the direct and indirect costs of such Other Business exceeds the revenues from such Other Business, no amount shall be allowed to be added to the Aggregate Revenue Requirement of the Transmission Licensee on account of such Other Business.
83.1 The aggregate of the yearly revenue requirement for all Transmission Licensees shall form the "Total Transmission System Cost" (TTSC) of the Intra-State
transmission system, to be recovered from the Transmission System Users (TSUs) for the respective year of the Control Period, in accordance with the following Formula:
$$TTSC_{(t)} = \sum_{i=1}^n ARR_i$$
Where,
$TTSC_{(t)}$ = Pooled Total Transmission System Cost of year (t) of the Control Period;
n = Number of Transmission Licensee(s);
$ARR_i$ = Yearly revenue requirement approved by the Commission for $i^{th}$ Transmission Licensee for the yearly period (t) of the Control Period:
Provided that in case of transmission system projects undertaken in accordance with the Guidelines for competitive bidding for transmission under Section 63 of the Act, the Aggregate Revenue Requirement as per the annual Transmission Service Charges (TSC) quoted by such projects, shall be considered, for aggregation under the TTSC.
$$\begin{aligned} \text{Base Transmission Capacity Rights} \ \text{(Base TCR) for the yearly period (t)} \end{aligned} = \sum_{u=1}^n ([CPD(t) + NCPD(t)]/2)$$
Where,
$CPD_{(t)}$ = Average of projected monthly Coincident Peak Demand for the yearly period (t) of Control Period for each Transmission System User (u)
$NCPD_{(t)}$ = Average of projected monthly Non-Coincident Peak Demand for the Yearly period (t) of Control Period for each Transmission System User (u):
Provided that for the first year of the Control Period, the Base Transmission Capacity Rights for all Transmission System Users shall be determined based on average monthly CPD and NCPD of the Transmission System Users prevalent during the 12 months prior to date of coming into effect of these Regulations or
12 months prior to filing of the Petition by the Transmission Licensees, depending on availability of such data:
Provided further that the Allotted Capacity for long-term Open Access Users shall be considered in lieu of the average monthly CPD and NCPD for calculating the Base Transmission Capacity Rights:
Provided also 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:
Provided also that the Yearly CPD and NCPD or the Allotted capacity, as the case may be, to be considered for determination of the subsequent yearly Base Transmission Capacity Rights shall be computed at the beginning of the Control Period based on the past trend and on the basis of demand projections made by various TSUs connected to the Intra-State transmission system as part of their MYT Petitions for the Control Period:
83.3 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) = $\frac{TTSC_{(t)}}{\text{Base TCR}_{(t)}}$ (INR/kW/month or INR/MW/day)
Base Transmission Tariff(t)
(Short-term) (INR/kWh) = $\frac{TTSC_{(t)}}{\sum_{i=1}^n (\text{Energy Transmitted by Tx } i)}$
Where,
TTSC(t) = Pooled cost for InSTS for yearly period (t) of the Control Period;
Base TCR(t) = Base Transmission Capacity Rights for the yearly period (t);
n = Total number of Transmission Licensee(s) in that particular year of Control Period;
$Tx_i = i^{\text{th}}$ Transmission Licensee:
Provided that the energy units transmitted by the Transmission Licensees shall be based on the energy input requirement of the Distribution Licensees at Generation-InSTS interface point, as projected by each Distribution Licensee as part of its MYT Petition for the Control Period and as approved by the Commission:
Provided further that any revisions in Base Transmission Capacity Rights and Base Transmission Tariff as determined in Regulations 83.2 and 83.3 due to the variation in the actual and approved CPD and NCPD shall be made at the end of the Control Period for the subsequent years:
Provided also that in case 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 as referred under Regulations 83.1, 83.2 and 83.3 shall be re-determined for each remaining Year of the Control Period.
83.4 The Base Transmission Tariff shall continue to be billed at the Tariff approved by the Commission and applicable as on March 31, 2025 for the period starting from April 1, 2025 till approval of Base Transmission Tariff by the Commission in accordance with these Regulations.
83.5 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.
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 amendments 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 charges for intra-State transmission usage shall be shared among various TSUs in the following manner:
payment of Short-Term Transmission Charges for the recorded demand in excess of Base TCR.
Provided that the calculation of the Short-Term Transmission Charges and Additional Regulatory Charge shall be based on the 15-minute time block basis or as amended time to time:
Provided further that the applicability and calculation of the Short-Term Transmission Charges and Additional Regulatory Charge shall be as shown in the Table below:
| Sr. No. | Scenario | Applicable Charges | Calculations of charges on 15-minute time block basis |
|---|---|---|---|
| a. | RD < Base TCR < CC | Only Monthly Transmission Charges (MTC) | STTC will not apply as RD is within Base TCR. TSU pays Transmission charges upto Base TCR. |
| b. | Base TCR < RD < CC | STTC in accordance with Regulation 85 b) of these Regulations | STTC = (RD – Base TCR) in kW x S.T. Rate (INR/kWh) |
| c(i) | CC < RD < Base TCR | Only MTC | STTC will not apply as RD is within Base TCR. TSU pays Transmission charges upto Base TCR. |
| Sr. No. | Scenario | Applicable Charges | Calculations of charges on 15-minute time block basis |
|---|---|---|---|
| c(ii) | Base TCR < CC < RD | STTC in accordance with Regulation 85 b) of these Regulations. ARC equal to 25% of the LTTC for the use of InSTS in excess of its CC in accordance with Regulation 85 (c) of these Regulations and Regulation 14.5 of MERC (Transmission Open Access) Regulations, 2016. | STTC = (RD – Base TCR) in kW x S.T. Rate (INR/kWh) ARC = (RD – CC) in kW x 0.25 x LTTC (INR/kW/month) |
| c(iii) | CC < Base TCR < RD | STTC in accordance with Regulation 85 (b) of these Regulations. ARC=25% of the LTTC for the use of an InSTS in excess of its Base TCR.in accordance with 14.5 of MERC (Transmission Open Access) Regulations, 2016. | STTC = (RD – Base TCR) in kW x S.T. Rate (INR/kWh) ARC = (RD – Base TCR) in kW x 0.25 x LTTC (INR/kW/month) |
86.1 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:
86.2 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.
86.3 Consumer setting up manufacturing Units exclusively for Green Hydrogen Manufacturing during the period from April 1, 2025 to March 31, 2030 shall be exempted from levy of intra-state transmission charges to the extent stipulated in table below, on the Renewable Energy sourced through Open Access:
| Sr | Category | Period of COD | Number of years from COD | % of Transmission Charges Waiver |
|---|---|---|---|---|
| 1 | Existing Exclusive Manufacturing Units for Green Hydrogen | 10 | 100% | |
| 2 | Exclusive Manufacturing Units for Green Hydrogen | 1.4.2025 to 31.03.2027 | 10 | 100% |
| 3 | Exclusive Manufacturing Units for Green Hydrogen | 1.4.2027 to 31.03.2028 | 10 | 75% |
| Sr | Category | Period of COD | Number of years from COD | % of Transmission Charges Waiver |
|---|---|---|---|---|
| 4 | Exclusive Manufacturing Units for Green Hydrogen | 1.4.2028 to 31.03.2030 | 10 | 50% |
87.1 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.
88.1 A Generating Station shall inject/absorb the reactive energy into the grid on the basis of machine capability as per the provisions of MERC (State Grid Code) Regulations, 2020 and directions of MSLDC.
88.2 Reactive energy exchange, only if made as per the directions of MSLDC, for the applicable duration (injection or absorption) shall be compensated/levied by the MSLDC to the Generating Station, as specified in the MERC (State Grid Code) Regulations, 2020 and amendments thereof.
88.3 The Transmission System Users shall be subjected to Incentive/Disincentive to be compensated/levied by the MSLDC for maintaining the reactive energy balance in the transmission system, as specified in the MERC (State Grid Code) Regulations, 2020 and amendments thereof.
89.1 Every Distribution Licensee shall maintain separate accounting records for the Distribution Wires Business and Retail Supply Business and shall prepare an Allocation Statement to enable the Commission to determine the Tariff separately for:
(a) Distribution Wires Business;
(b) Retail Supply of electricity:
89.2 Distribution Licensee shall follow guidelines stipulated in Annexure III for allocation of asset and cost:
Provided that in case complete accounting segregation has not been done between the Distribution Wires Business and Retail Supply Business of the Distribution Licensee, the Aggregate Revenue Requirement of the Distribution Licensee shall be apportioned between the Distribution Wires Business and Retail Supply Business in accordance with the following Allocation Matrix:
| Particulars | Distribution Wires Business (%) | Retail Supply Business (%) |
|---|---|---|
| Power Purchase Expenses | 0% | 100% |
| Inter-State Transmission Charges | 0% | 100% |
| Intra-State Transmission Charges | 0% | 100% |
| Operation & Maintenance Expenses | 65% | 35% |
| Depreciation | 90% | 10% |
| Interest on Long-term Loan Capital | 90% | 10% |
| Interest on Working Capital | 10% | 90% |
| Interest on Consumer Security Deposits | 10% | 90% |
| Provision for Bad & Doubtful Debts | 10% | 90% |
| Income Tax | 90% | 10% |
| Contribution to Contingency Reserves | 90% | 10% |
| Return on Equity | 90% | 10% |
| Non-Tariff Income | 10% | 90% |
Provided further that the above Allocation Matrix shall be applied for all or any of the heads of expenditure and revenue, where actual accounting separation has not been done between the Distribution Wires Business and Retail Supply Business:
89.3 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.
90.1 The Regulations contained in this Part shall apply to the determination of Wheeling Charges payable for usage of distribution wires of a Distribution Licensee by a Distribution System User.
91.1 The Wheeling Charges of the Distribution Licensee shall provide for the recovery of the Aggregate Revenue Requirement of the Distribution Wires Business for the respective Years of the Control Period, as approved by the Commission and comprising the following components:
minus:
Provided that Depreciation, Interest on Loan Capital, Interest on working capital, Interest on deposits from consumers and Distribution System Users, Contribution to Contingency Reserves, Return on Equity, and Income Tax for Distribution Wires Business shall be allowed in accordance with the provisions specified in Part D of these Regulations:
Provided further that prior period income/expenses shall be allowed by the Commission at the time of truing up based on audited accounts, on a case to case basis, if the income/expenses in that prior period have been allowed on actual basis, subject to prudence check:
Provided also that all penalties and compensation payable by the Licensee to any party for failure to meet any Standards of Performance or for damages, as a consequence of the orders of the Commission, Courts, Consumer Grievance Redressal Forum, and Ombudsman, etc., shall not be allowed to be recovered through the Aggregate Revenue Requirement:
Provided also that the Distribution Licensee shall maintain separate details of such penalties and compensation paid or payable by the Licensee, if any, and shall submit them to the Commission along with its Petition.
Provided that the Wheeling Charges may be denominated in terms of Rupees/kWh or Rupees/kVAh or Rupees/kW/month or Rupees/kVA/month, for the purpose of recovery from the Distribution System User, or any such denomination, as may be stipulated by the Commission:
Provided further that the Wheeling Charges shall be determined separately for LT voltage, HT voltage, and EHT voltage, as applicable:
Provided also that in case of a Deemed Distribution Licensee whose tariff is yet to be determined by the Commission till the date of coming into of these Regulations, the Commission may determine the ceiling Wheeling Charges that may be charged by such Deemed Distribution Licensee till such time as considered appropriate by the Commission.
quality of supply, reliability, metering, reduction in congestion, etc., to the Commission for approval, as a part of the Multi-Year Tariff Petition for the entire Control Period
Provided that the Distribution Licensee shall submit separate details of Capital Investment being undertaken in each Distribution Franchisee area within its Licence area.
Explanation: For the purpose of applying normative O&M expenses with respect to Gross Fixed Assets (GFA) growth under these Regulation, the average
GFA pertaining to Distribution Wires Business (in INR Crore) shall be multiplied by the O&M Norms in terms of “percentage of Average GFA”, for the respective years.
93.2 For applying normative O&M expenses with respect to Consumer’s growth, the O&M Norms in terms of “INR Lakhs/’000 Consumers” or “INR Lakhs/’00 Consumers” (in case of Deemed Distribution Licensees) shall be multiplied by the closing total Wheeling Consumers inclusive of full Open Access Consumers, if any, of the Distribution Wires Business, during the respective financial year.
Provided that the Partial Open Access consumers are embedded within the Wheeling Consumers of the Distribution Wires Business, hence, no separate addition of such Partial Open Access consumers will be allowed to avoid double accounting:
Provided further that the Distribution Licensee shall submit the details of its consumer base having the break-up of its direct consumers, Partial Open Access consumers and Full Open Access consumers for the respective years at the time of filing MYT Petition for Distribution Wires Business.
| MSDECL | 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/’000 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/’000 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.
93.4 In case the expenditure on Repairs & Maintenance falls below 20% of total O&M expenses allowed under these Regulations, then such savings in Repairs & Maintenance shall not be set off against other heads of O&M expenses:
Provided that this limitation shall not be applicable for Deemed Distribution Licensees for the first five years after commencement of operations as a Distribution Licensee.
93.5 A Distribution Licensee may undertake Opex schemes for system automation, new technology and IT implementation, etc., and such expenses may be allowed over and above normative O&M Expenses, subject to prudence check by the Commission:
Provided that the Distribution Licensee shall submit detailed justification, cost benefit analysis, and life-cycle cost analysis of such schemes as against capex schemes, and savings in O&M expenses, if any
93.6 The Commission may consider any request for revision of the normative O&M expenses of the Distribution 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.
94.1 In the MYT Order, for each Year of the Control Period, the Commission may allow a provision for writing off of bad and doubtful debts up to 1.5% of the amount shown as Trade Receivables or Receivables from Wheeling Charges in the latest Audited Accounts of the Distribution Licensee in accordance with the procedure laid down by the Licensee, subject to prudence check:
Provided that the Commission shall true up the bad debts written off in the Aggregate Revenue Requirement, based on the actual write off of bad debts during the year, subject to the above ceiling of 1.5% of the amount shown as Trade Receivables or Receivables from Wheeling Charges in the audited accounts of the Distribution Licensee for that Year, after prudence check:
Provided further that if subsequent to the write off of a particular bad debt, revenue is realised from such bad debt, the same shall be included as an uncontrollable item under the Non-Tariff Income of the year in which such revenue is realised:
Provided also that in the Year when the cumulative provisioning for write-off of bad and doubtful debts allowed by the Commission, duly allocated for the Distribution Wires Business, exceeds five per cent of the amount shown as Trade Receivables or Receivables from Wheeling Charges in the audited accounts of the Distribution Licensee, no such appropriation shall be allowed, which would have the effect of increasing the cumulative provisioning beyond the said maximum:
Provided also that for Distribution Licensees having agricultural sales in excess of 20 percent of their total sales, the ceiling of cumulative provisioning in the above proviso shall be 7.5 per cent of the amount shown as Trade Receivables or Receivables from Wheeling Charges in the audited accounts of the Distribution Licensee.
95.1 The amount of Non-Tariff Income relating to the Distribution Wires Business as approved by the Commission shall be deducted from the Aggregate Revenue Requirement in determining the Wheeling Charges of the Distribution Wires Business:
Provided that the Distribution Licensee shall submit full details of its forecast of Non-Tariff Income to the Commission in such form as may be stipulated by the Commission.
95.2 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 Distribution Wires Business shall not be included in Non-Tariff Income.
96.1 Where the Distribution Wires Business of the Distribution Licensee has engaged in any Other Business under Section 51 of the Act for optimum utilisation of its assets, an amount equal to two-thirds of the revenues from such Other Business after deduction of all direct and indirect costs attributed to such Other Business shall be deducted from the Aggregate Revenue Requirement in determining the Wheeling Charges of Distribution Wires Business:
Provided that the Distribution Licensee shall follow a reasonable basis for allocation of all joint and common costs between the Distribution Wires Business and the Other Business and shall submit the Allocation Statement, duly certified by the Statutory Auditor of the Company, to the Commission along with its Petition for determination of Wheeling Charges:
Provided further that where the sum total of the direct and indirect costs of such Other Business exceeds the revenues from such Other Business, no amount shall be allowed to be added to the Aggregate Revenue Requirement of the Distribution Wires Business on account of such Other Business.
97.1 The Commission shall determine the Wheeling Charges for High Tension (HT) and Low Tension (LT) voltage level for the Distribution Wires Business in terms of the following formula:
Wheeling Charges for HT Consumers
$$(\text{INR/kVAh}) = \frac{W_{ARR(HT)} * 10}{EW_{HT}}$$
Where,
$W_{ARR(HT)}$ = ARR of Distribution Wires Business pertaining to HT level in INR Crore.
$EW_{HT}$ = Projected Wheeling Energy pertaining to HT level in Million kVAh or M kVAh.
Wheeling Charge for LT Consumers
$$(\text{INR/kWh}) \text{ or } (\text{INR/kVAh}) = \frac{W_{ARR(LT)} * 10}{EW_{LT}}$$
Where,
$W_{ARR(LT)}$ = ARR of Distribution Wires Business pertaining to LT level in INR Crore.
$EW_{LT}$ = Projected Wheeling Energy pertaining to LT level in Million kWh or MU or MkVAh as the case may be.
Provided that in case the Commission adopts the kVAh based Tariff at LT level, the Wheeling Charges for LT Consumers shall then be determined in INR/kVAh.
97.2 The Distribution Licensee shall submit the actual allocation of its voltage wise assets in accordance with the Guidelines stipulated in Annexure III, as part of its Tariff Petition:
Provided that the Annual Revenue Requirement of the Distribution Wires Business pertaining to HT and LT voltage level may be allocated by considering such actual voltage wise asset details submitted by the Distribution Licensee.
98.1 The Distribution Wires Business shall be allowed to recover, in kind, the approved target level of Wheeling Losses arising from the operation of the distribution system:
Provided that the Commission may stipulate a trajectory for Wheeling Losses at different voltage level in accordance with Regulation 7 as part of the Order on the Multi-Year Tariff Petition filed by the Distribution Licensee.
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.
99.1 The Regulations contained in this Part shall apply to the determination of Tariff for retail supply of electricity by a Distribution Licensee to its consumers.
100.1 The Tariff for retail supply of the Distribution Licensee shall provide for the recovery of the Aggregate Revenue Requirement of the Retail Supply Business for the respective Years of the Control Period, as approved by the Commission and comprising the following components:
Provided that Depreciation, Interest on Loan Capital, Interest on working capital, Interest on consumer security deposits, Contribution to Contingency Reserves, Supply Margin, and Income Tax for Retail Supply Business shall be allowed in accordance with the provisions specified in Part D of these Regulations:
Provided further that prior period income/expenses shall be allowed by the Commission at the time of truing up based on audited accounts, on a case to case basis, if the income/expenses in that prior period have been allowed on actual basis, subject to prudence check:
Provided also that all penalties and compensation payable by the Licensee to any party for failure to meet any Standards of Performance or for damages, as a consequence of the orders of the Commission, Courts, Consumer Grievance Redressal Forum, and Ombudsman, etc., shall not be allowed to be recovered through the Aggregate Revenue Requirement:
Provided also that the Distribution Licensee shall maintain separate details of such penalties and compensation paid or payable by the Licensee, if any, and shall submit them to the Commission along with its Petition.
Provided that the Aggregate Revenue Requirement of the Distribution Licensee shall be allocated or apportioned between the Distribution Wires Business and Retail Supply Business in accordance with the provisions of Regulation 89:
Provided further that the Tariff for retail supply may comprise any combination of fixed/demand charges, energy charges, and any other charges, for the purpose of recovery from the consumers, as may be stipulated by the Commission:
Provided also that the Commission may determine the area-wise Tariff for Distribution Licensee based on the performance parameters as may be stipulated by the Commission:
Provided also that in case of Parallel Distribution Licensee operating in same geographical area, the Commission may determine 'Ceiling Retail Tariff' subject to fulfilment of the certain specified conditions so as to enable retail supply competition:
Provided also that in case of a Deemed Distribution Licensee whose tariff is yet to be determined by the Commission till the date of coming into effect of these Regulations, the Commission may determine the ceiling Tariff for retail supply that may be charged by such Distribution Licensee till such time as considered appropriate by the Commission.
2025 for the period starting from April 1, 2025 till approval of Tariff for retail supply by the Commission in accordance with these Regulations.
100.4 The Distribution Licensee may propose other rebates for inter-alia, taking supply at higher voltages, bulk consumption, power factor, etc., as a part of their Petition, and the revenue impact of rebates shall be passed on through the Aggregate Revenue Requirement and tariffs, subject to the Commission's approval.
100.5 The Distribution Licensee may offer a rebate to the consumers on the Tariff and charges determined by the Commission:
Provided that the Distribution Licensee shall submit details of such rebates to the Commission every quarter, in the manner and format, as stipulated by the Commission:
Provided further that the impact of such rebates on the Distribution Licensee shall be borne entirely by the Distribution Licensee and the impact of such rebate shall not be passed on to the consumers, in any form:
Provided also that such rebates shall not be offered selectively to any consumer/s and shall have to be offered to the entire consumer category/sub-category/consumption slab in a non-discriminatory manner.
101.1 The Distribution Licensee shall submit a month-wise forecast of the expected sales of electricity to each Tariff category/sub-category and to each Tariff slab within such Tariff category/sub-category to the Commission for approval along with the Multi-Year Tariff Petition, as specified in these Regulations:
Provided that the Distribution Licensee shall submit relevant details regarding category-wise sales separately for each Distribution Franchisee area within its Licence area, as well as the aggregated category-wise sales in its Licence area.
101.2 The sales forecast shall be consistent with the load forecast prepared as part of the power procurement plan under Part C of these Regulations and shall be based on past data and reasonable assumptions regarding the future:
Provided that where the Commission has stipulated a methodology for forecasting sales to any particular Tariff category, the Distribution Licensee shall incorporate such methodology in developing the sales forecast for such Tariff category.
102.1 The Distribution Licensee shall submit a detailed Capital Investment Plan, financing plan and physical targets for each Year of the Control Period for
meeting the requirement of growth in number of consumers, reduction in distribution losses, metering, etc., to the Commission for approval, as a part of the Multi-Year Tariff Petition for the entire Control Period.
Explanation: For the purpose of applying normative O&M expenses with respect to Gross Fixed Assets (GFA) growth under these Regulation, the average GFA pertaining to Retail Supply Business (in INR Crore) shall be multiplied by the O&M Norms in terms of “percentage of Average GFA”, for the respective years.
Provided that the Partial Open Access consumers are embedded within the Retail Supply Consumers of the Retail Supply Business, hence, no separate addition of such Partial Open Access consumers will be allowed to avoid double accounting:
Provided further that the Distribution Licensee shall submit the details of its consumer base having the break-up of its direct consumers and Partial Open Access consumers for the respective years at the time of filing MYT Petition for its Retail Supply Business.
| 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) | 7.77% | 8.12% | 8.48% | 8.87% | 9.26% |
| O&M (INR Lakhs/'000 Consumers) | 21.48 | 22.44 | 23.45 | 24.50 | 25.60 |
| 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.
103.4 In case the expenditure on Repairs & Maintenance falls below 20% of total O&M expenses allowed under these Regulations, then such savings in Repairs & Maintenance shall not be set off against other heads of O&M expenses:
Provided that this limitation shall not be applicable for Deemed Distribution Licensees for the first five years after commencement of operations as a Distribution Licensee.
103.5 The Distribution Licensee may undertake Opex schemes for system automation, new technology and IT implementation, etc., and such expenses may be allowed over and above normative O&M Expenses, subject to prudence check by the Commission:
Provided that the Distribution Licensee shall submit detailed justification, cost benefit analysis, and life-cycle cost analysis of such schemes as against capex schemes, and savings in O&M expenses, if any.
103.6 In the case of a Deemed Distribution Licensee whose tariff is yet to be determined by the Commission till the coming into force of these Regulations, the Commission may determine the Operation and Maintenance expenses on a case-to-case basis.
103.7 The Commission may consider any request for revision of the normative O&M expenses of the Distribution 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.
104.1 The Distribution Licensee shall consider the implementation of Energy Efficiency Schemes under the provision of the MERC (Approval of Capital Investment Schemes) Regulations, 2022 as amended from time to time.
104.2 The Distribution Licensee shall endeavour to reduce its self-consumption by implementing Energy Efficiency/Conservation measures which shall include but not limited to Distribution Transformer efficiency improvement schemes, deployment of LED bulbs and deployment of energy efficiency fans (BLDC fans, etc.), deployment of five star rated air conditioning units at its offices and other substations related establishments, schemes for voltage management measures and Power Factor improvement, Energy Efficiency monitoring and analytical hardware and software tools.
104.3 The Distribution Licensee shall submit its existing level of own energy consumption and Energy Conservation measure at the beginning of the Control Period and provide the trajectory for the reduction of such own energy consumption through the implementation of Energy Efficiency improvement scheme/plan under Capital Expenditure or Opex Expenditure as part of the MYT Petition alongwith the target of Energy Efficiency related savings, and monitoring plan in line with principles provided the MERC (Demand Side Management Implementation Framework) Regulations, 2010 as amended from time to time.
Provided that, the Distribution Licensee shall submit its Energy Efficiency Programmes'/Scheme's Cost Effectiveness Assessment for the expected trajectory.
104.4 The Commission shall specify the Energy Conservation Trajectory for the Control Period for the Distribution Licensee and shall review the actual performance at the time of truing-up, subject to prudence check.
105.1 In the MYT Order, for each Year of the Control Period, the Commission may allow a provision for writing off bad and doubtful debts up to 1.5% of the amount shown as Trade Receivables or Receivables from Sale of Electricity in the latest
Audited Accounts of the Distribution Licensee in accordance with the procedure laid down by the Licensee, subject to prudence check:
Provided that the Commission shall true up the bad debts written off in the Aggregate Revenue Requirement, based on the actual write off bad debts during the year, subject to the above ceiling of 1.5% of the amount shown as Trade Receivables or Receivables from Sale of Electricity in the audited accounts of the Distribution Licensee for that Year, after prudence check:
Provided further that if subsequent to the write off of a particular bad debt, revenue is realised from such bad debt, the same shall be included as an uncontrollable item under the Non-Tariff Income of the year in which such revenue is realised:
Provided also that in the Year when the cumulative provisioning for write-off of bad and doubtful debts allowed by the Commission, duly allocated for the Retail Supply Business exceeds five per cent of the amount shown as Trade Receivables or Receivables from Sale of Electricity in the audited accounts of the Distribution Licensee, no such appropriation shall be allowed, which would have the effect of increasing the cumulative provisioning beyond the said maximum:
Provided also that for Distribution Licensees having agricultural sales in excess of 20 percent of their total sales, the ceiling of cumulative provisioning in the above proviso shall be 7.5 per cent of the amount shown as Trade Receivables or Receivables from Sale of Electricity in the audited accounts of the Distribution Licensee.
106.1 The amount of Non-Tariff Income relating to the Retail Supply Business as approved by the Commission shall be deducted from the Aggregate Revenue Requirement in determining the Tariff for retail supply of electricity by the Distribution Licensee:
Provided that the Distribution Licensee shall submit details of its forecast of Non-Tariff income to the Commission in such form as may be stipulated by the Commission.
106.2 The Non-Tariff Income shall include:
a) Income from rent of land or buildings;
b) Income from sale of scrap;
c) Income from investments;
d) Interest income on advances to suppliers/contractors;
e) Income from rental from staff quarters;
f) Income from rental from contractors;
g) Income from hire charges from contractors and others;
h) Supervision charges for capital works;
i) Income from consumer charges levied in accordance with Schedule of Charges approved by the Commission;
j) Income from recovery against theft and/or pilferage of electricity;
k) Income from advertisements;
l) Income from sale of tender documents;
m) Any other Non-Tariff Income:
Provided that the interest earned from investments made out of Return on Equity corresponding to the regulated Business of the Retail Supply Business shall not be included in Non-Tariff Income.
107.1 Where the Retail Supply Business of the Distribution Licensee has engaged in any Other Business under Section 51 of the Act for optimum utilisation of its assets, an amount equal to two-thirds of the revenues from such Other Business after deduction of all direct and indirect costs attributed to such Other Business shall be deducted from the Aggregate Revenue Requirement in calculating the Tariff for retail supply of electricity by the Distribution Licensee:
Provided that the Distribution Licensee shall follow a reasonable basis for allocation of all joint and common costs between the Retail Supply Business and the Other Business and shall submit the Allocation Statement, duly certified by the Statutory Auditor of the Company, to the Commission along with its Petition for determination of Tariff:
Provided further that where the sum total of the direct and indirect costs of such Other Business exceeds the revenue from such Other Business, no amount shall be allowed to be added to the Aggregate Revenue Requirement of the Retail Supply Business on account of such Other Business.
108.1 The Cross-Subsidy Surcharge determined by the Commission as part of the MYT Tariff Order in accordance with the Regulation 14.7 of the MERC (Distribution Open Access) Regulations, 2016, as amended from time to time.
Provided that the Cross-Subsidy Surcharge determined by the Commission for the respective consumer categories shall not be exceeding the 20% (twenty percent) of the Average Cost of Supply approved by the Commission for the respective financial years over the Control Period.
108.2 The amount received by the Distribution Licensee by way of Cross-Subsidy Surcharge, as approved by the Commission, shall be deducted from the Aggregate Revenue Requirement in determining the Tariff for retail supply of electricity by such Distribution Licensee.
109.1 The Additional Surcharge determined by the Commission as part of the MYT Tariff Order in accordance with the Regulation 14.8 of the MERC (Distribution Open Access) Regulations, 2016, as amended from time to time.
Provided that the Additional Surcharge determined by the Commission for the respective consumer categories shall not be more than the per unit fixed cost of power purchase of the Distribution Licensee concerned.
109.2 The amount received by the Distribution Licensee by way of Additional Surcharge, as approved by the Commission, shall be deducted from the Aggregate Revenue Requirement for determining the Tariff for retail supply of electricity by such Distribution Licensee.
110.1 The power purchase requirement of the Distribution Licensee at the Transmission-Distribution interface point, shall be computed by grossing up the sales with the distribution losses approved by the Commission:
Provided that the Commission may stipulate the target distribution losses in accordance with Regulation 7 as part of the Order on the Multi-Year Tariff Petition:
Provided that the Distribution Licensee shall submit the details of area-wise distribution losses for the relevant years, in accordance with the formats prescribed by the Commission:
Provided also that the area-wise distribution losses shall separately indicate the distribution losses in each Distribution Franchisee area within its Licence area, for the relevant years.
Provided that the Commission may stipulate trajectory for AT&C losses in its Order on the MYT Petition filed by Distribution Licensee.
111.1** The Commission may categorize consumers on the basis of their load factor, power factor, voltage, total consumption of electricity during any specified period or the time at which the supply is required or the geographical position of any area, the nature of supply and the purpose for which the supply is required.
111.2** The Commission may determine additional or reduced area-specific charges to reflect instances of area peculiarity in terms of high/low distribution losses, high/low reliability of power supply, high reinstatement charges levied by the local body, capital expenditure incurred for purposes beyond Universal Service Obligation and safety measures, etc.:
Total Capital Investment against all Schemes in FY 2021-22 in a local area = INR 500 Crore;
Total RI Charges included in above Capital Investment = INR 250 Crore;
Total expenditure recoverable as Capital Investment = INR 375 Crore (i.e., INR 250 Crore + 50% of INR 250 Crore of RI);
Balance expenditure recoverable as Additional Charges from concerned Local Area on account of RI in FY 2022-23 = INR 125 Crore (i.e., 50% of INR 250 Crore of RI);
Total Sales of concerned Local Area in FY 2022-23 = 5000 Million Units;
Additional Energy Charges for all categories of consumers in concerned Local Area on account of RI in FY 2022-23 = INR 0.25 per kWh ( $125 \times 10 / 5000$ )
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.
111.3 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 100, 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.
111.4 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.
111.5 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.
112.1 The Commission shall determine the consumer category wise Demand/Fixed Charges for the respective Distribution Retail Supply Licensee based on the Contracted Capacity (in kVA or kW) and number of Connections for the respective financial year of the Control Period:
Provided that such Demand/Fixed Charges shall be gradually increased year-on-year basis to recover Fixed Cost of the Licensee from such Demand/Fixed Charges:
Provided further that the basis for the determination of consumer category wise Demand/Fixed Charges for the respective years of the Control Period, shall be in terms of their actual Billing Demand at HT and LT Level, change in Load Factor, change in number of connections in case of LT level, etc.
Provided further that the Distribution Licensee shall submit the details of the actual Billing Demand, Contracted Capacity, Load Factor and Connected number of Consumers for the respective Consumer categories as part of the MYT Tariff Petition.
113.1 The Commission shall determine the consumer category wise Energy Charges for the respective Distribution Retail Supply Licensee taking into consideration consumer's load factor, power factor, voltage, total consumption of electricity during any specified period or time at which the supply is required or the geographical position of any are, the nature of supply and the purpose for which the supply is required, prevalent cross-subsidy, adherence to tariff policy provisions etc., for the respective financial year of the Control Period:
Provided that such Energy Charges shall be gradually revised year-on-year basis to reduce the level of cross-subsidy as permissible as per provisions of Tariff Policy and also encourage efficient use of energy by various consumer categories:
Provided further that the basis for the determination of consumer category wise Energy Charges for the respective years of the Control Period, shall be in terms of their actual consumption at HT and LT Level, change in Load Factor, incremental consumption rebate, if any, time of use charge implications, etc.
Provided further that the Distribution Licensee shall submit the required details of the consumption of various consumer categories and slab-wise consumption details for the respective Consumer categories as part of the MYT Tariff Petition.
114.1 The Commission in exercise to 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:
a. Uniform Wheeling Charges to be determined as per Regulation 114.4
b. Uniform Demand/Fixed Charges to be decided as per Regulation 114.5.
c. Consumer category-wise or uniform ceiling rate for Energy Charge to be decided to ensure that approved Retail Supply Aggregate Revenue Requirement of respective Distribution Licensee shall be recovered 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, to 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.
114.4 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:
$$(INR/kVAh) = \frac{\sum(W_{HT1}, W_{HT2}, \dots, W_{HTn}) * 10}{\sum(EW_{HT-D1}, EW_{HT-D2}, \dots, EW_{HT-Dn})}$$
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.
$$(INR/kWh) \text{ or } (INR/kVAh) = \frac{\sum(W_{LT1}, W_{LT2}, \dots, W_{LTn}) * 10}{\sum(EW_{LT-D1}, EW_{LT-D2}, \dots, EW_{LT-Dn})}$$
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.
114.5 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.
114.6 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.
114.7 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.
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.
115.1** 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.
115.2** 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 | 16:00 to 20:00 | 20:00 to 00:00 | 00:00 to 06:00 | 06:00 to 09:00 |
| Hrs | Hrs | Hrs | Hrs | Hrs |
| 80% of the normal rate of Energy Charge | 120% of the normal rate of Energy Charge | 110% of 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 propose seasonal ToD tariff in its Tariff Petition:
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:
Provided further 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.
116.1 The Regulations contained in this Part shall apply in determining the Fees and Charges to be levied by the MSLDC after April 1, 2025.
117.1 The MSLDC shall submit a detailed capital investment plan considering the provisions of the MERC (Approval of Capital Investment Schemes) Regulations, 2022, financing plan and physical targets for each Year of the Control Period based on the operational requirements prescribed by the Commission and recommendations of various Committees constituted for looking into matters related to strengthening and ring fencing of the State Load Despatch Centres by the Ministry of Power, Government of India or any such other statutory authorities, to the Commission for approval, as a part of the Multi-Year Aggregate Revenue Requirement for the entire Control Period.
117.2 The Capital Investment Plan shall be a least cost plan for undertaking investments and shall cover all capital expenditure projects of a value exceeding the limits prescribed by the Commission from time to time under the MERC (Approval of Capital Investment Schemes) Regulations, 2022.
117.3 The Capital Investment Plan shall be accompanied by such information, particulars and documents as may be required showing the need for the proposed investments, alternatives considered, cost/benefit analysis and other aspects that may have a bearing on the MSLDC Fees and Charges.
117.4 The Commission shall consider the Capital Investment Plan along with the Multi-Year Aggregate Revenue Requirement for the entire Control Period submitted by the MSLDC taking into consideration the prudence of the proposed expenditure and estimated impact on MSLDC Fees and Charges.
117.5 The MSLDC shall submit, along with the Petition for determination of Aggregate Revenue Requirement, details showing the progress of capital expenditure projects, together with such other information, particulars or documents as the Commission may require assessing such progress.
118.1 The Commission may permit MSLDC to create and maintain a separate development fund for such purposes and from such sources of income, as the Commission may consider appropriate, on a Petition filed by MSLDC.
Provided that the income earned through these investments will be passed on to the Beneficiaries as part of the Non-Tariff Income.
Provided that in case the excess corpus is not invested by MSLDC in appropriate interest-bearing instruments, then the normative interest income, computed at the weighted average Bank Rate, as applicable for the year, shall be included under the non-tariff income of the MSLDC.
respective Year of the Control Period, as reduced by the amount of Non-Tariff Income as approved by the Commission and comprising the following:
minus:
Provided that Depreciation, Interest on Loan, and Return on Equity for the MSLDC shall be allowed in accordance with the provisions specified in Part D of these Regulations:
Provided further that prior period income/expenses shall be allowed by the Commission at the time of truing up based on audited accounts, on a case to case basis, if the income/expenses in that prior period have been allowed on actual basis, subject to prudence check:
Provided also that all penalties and compensation payable by the MSLDC to any party for failure to meet its obligations or for damages, as a consequence of the orders of the Commission and Courts shall not be allowed to be recovered through the Aggregate Revenue Requirement:
Provided also that the MSLDC shall maintain separate details of such penalties and compensation paid or payable by the MSLDC, if any, and shall submit the same to the Commission along with the Petitions to be submitted under these Regulations.
120.1 The Operation and Maintenance expenses for the MSLDC shall be computed in accordance with this Regulation.
120.2 The Operation and Maintenance expenses 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:
Provided that, the impact of the wage revision if any during the Trued-up year shall be included in the O&M expenses while determining the norms for the O&M expenses for the future year. Provided that the average of such Operation and Maintenance expenses shall be considered as Operation and Maintenance expenses for the Year ended March 31, 2022, and shall be escalated at the respective escalation rate for FY 2022-23, FY 2023-24 and FY 2024-25, to arrive at the Operation and Maintenance expenses for the base year ending March 31, 2025:
Provided further 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.
Provided also that at the time of true-up for each Year of this Control Period, the Operation and Maintenance expenses shall be derived on the basis of the Final Trued-up Operation and Maintenance expenses after adding/deducting the sharing of efficiency gains/losses, for the year ending March 31, 2025, excluding abnormal expenses, if any, subject to prudence check by the Commission, and shall be considered as the Base Year Operation and Maintenance expenses:
Provided that, in the Truing-up of the O&M expenses for any particular year of the Control Period, an inflation factor with 20% weightage to the average yearly
inflation derived based on the monthly Wholesale Price Index of the respective past five financial years (including the year of Truing-up) 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 (including the year of Truing-up), as reduced by an efficiency factor of 1% of derived inflation factor or as may be stipulated by the Commission from time to time, shall be applied to arrive at the permissible Operation and Maintenance Ex
120.4 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.
120.5 Provision of expenses shall not be considered as actual expenses at the time of true-up, and only expenses as actually incurred shall be considered.
120.6 The MSLDC may undertake Opex schemes for system automation, new technology and IT implementation, etc., and such expenses may be allowed over and above normative O&M Expenses, subject to prudence check by the Commission:
Provided that the MSLDC shall submit detailed justification, cost benefit analysis, and life-cycle cost analysis of such schemes as against capex schemes, and savings in O&M expenses, if any.
120.7 The Commission may consider any request for revision of the normative O&M expenses of MSLDC 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.
120.8 The HRD expenses shall be booked under Employee expenses instead of A&G expenses from the first year of the Control Period. Projected HRD expenses will be minimum Five Percentage (5%) of the Employee Expenses for the respective financial year.
Provided that, if the expenses towards HRD falls below 5% of total Employee expenses allowed under these Regulations, then such savings in HRD expenses shall not be set off against Employee expenses.
121.1** The RLDC Fees and Charges payable by the MSLDC in accordance with the relevant Orders issued by the Central Electricity Regulatory Commission from time to time shall be allowed to be recovered by the MSLDC through the Fees and Charges as approved by the Commission.
121.2** The WRPC Charges payable to the WRPC's Secretariat shall be allowed to be recovered by the MSLDC through the Fees and Charges as approved by the Commission.
121.3** The MSLDC shall have to produce documentary proof towards payment of such Charges at the time of Truing up:
Provided that any variation between the approved RLDC Fees and Charges and WRPC Charges and that actually paid by the MSLDC shall be considered during the true-up as per audited accounts, subject to prudence check and any other factor considered appropriate by the Commission.
Provided that the MSLDC shall submit full details of its forecast of Non-Tariff Income to the Commission in such form as may be stipulated by the Commission.
122.2** The Non-Tariff Income shall include:
a) Income from sale of scrap;
b) Income from investments;
c) Interest income on advances to suppliers/contractors;
d) Income from rental from staff quarters;
e) Income from sale of tender documents;
f) Any other Non-Tariff Income:
Provided that the interest earned from investments made out of Return on Equity of the MSLDC shall not be included in Non-Tariff Income.
123.1 The MSLDC Charges payable by the Transmission System Users shall be computed in accordance with the following formula:
$$AFC(u){(t)} = AFC{(t)} \times ([Base\ TCR(u)]{(t)} / \sum{i=1}^n [Base\ TCR(u)]_{(t)})$$
Where,
$AFC(u)_{(t)}$ = MSLDC Charges to be shared by the Beneficiary (u) for the Yearly period (t);
$AFC(t)$ = Total MSLDC Charges to be shared by the Beneficiaries for the Yearly period (t);
Base TCR (u) = $[CPD(u){(t)} + NCPD(u){(t)}] / 2$
Where,
Base TCR represents the Base Transmission Capacity Right of each Beneficiary (u) for the Yearly period (t);
$CPD(u)_{(t)}$ = Average Coincident Peak Demand of the Beneficiary (u) for the Yearly period (t);
$NCPD(u)(t)$ = Average Non-coincident Peak Demand of the Beneficiary (u) for the Yearly period (t);
124.1 The long-term Transmission System Users shall share the MSLDC 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 MSLDC Charges to the Distribution Licensee instead of the Transmission Licensee for using a transmission network which shall be passed on to the MSLDC 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.
124.2 The Annual MSLDC Charge payable by Transmission System User shall be computed in accordance with the following formula:
$$\text{Monthly MSLDC Charges (INR/MW/Month)} = [\text{AFC}(u){(0)} \div \sum{i=1}^n [\text{Adjusted Base TCR}(u)]_{(i)}] \div 12$$
Where,
$$\text{Adjusted Base TCR}(u) = \text{Base TCR}(u) - \text{Billed OA Demand of POA}(u)$$
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);
124.3 The MSLDC Charges approved for the Year shall be equally spread over the 12 months of the Year and MSLDC Charges per MW per month shall be computed by MSLDC in accordance with the following Formula:
$$\text{Monthly MSLDC Charges (INR/MW/Month)} = [\text{AFC}(u){(0)} \div \sum{i=1}^n [\text{Base TCR}(u)]_{(i)}] \div 12$$
124.4 The Open Access consumers excluding those covered under Regulation 124.1 shall be liable for payment of the MSLDC Charges in proportion to the duration for which they were granted Open Access during the concerned billing period.
124.5 The Charges to be recovered by MSLDC shall continue to be billed at the Tariff approved by the Commission and applicable as on March 31, 2025 for the period starting from April 1, 2025 till approval of Charges by the Commission in accordance with these Regulations.
125.1 The MSLDC shall recover the following Fees as approved by the Commission from time to time:
e) Any other Fees approved by the Commission from time to time.
125.2 The revenue from such Fees shall be considered for adjustment of Annual Fixed Charges in subsequent Years unless the same forms part of the LDC Development Fund.
126.1 Recovery of incentive by the MSLDC 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.
126.2 MSLDC shall submit its actual performance against each of the key performance indicators to the Commission on an annual basis alongwith with supporting documents.
126.3 The Commission shall evaluate the overall performance of the MSLDC, on the basis of weightage specified in the table 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%.
| S.No. | Parameters | Marks | Performance/ Marks obtained | |
|---|---|---|---|---|
| 1 | (A) Stakeholders Satisfaction (Overall Weightage 40%) |
Maintain 99.95% availability of MSLDC website, Web based Scheduling system and Web based STOA websites |
80 | P= IF (A>=99.95, 100, (100-(99.95-A))/100*80 A= Weighted average monthly performance of 3 websites. Monthly Performance= (M-O)/M M: Minutes in a month (43,800) O: Total minutes of outage i.e. non- availability in month |
| 2 | Issuance of weekly DSM bill / |
80 | P=IF (A=52,80, IF(A>45,60, IF(A>=40,40,0))) A= Number of weeks in a year for issuance |
| S.No. | Parameters | Marks | Performance/ Marks obtained | |
|---|---|---|---|---|
| Reactive bills to Stake holders | of weekly DSM/Reactive bill to stakeholder. | |||
| 3 | Issuances of monthly State Energy Account Statement | 80 | P=IF (A<=20,80, IF(A>20,60, IF(A>30,40,0))) A= Number of working days (in M+1 month for M month-for 12 months in year) after issuing DSM bill. |
|
| 4 | Declaration of Monthly State Transmission Loss | 80 | P=IF (A<=25,80,0) A= Number of Months in a year for issuance of Monthly State Transmission Loss. |
|
| 5 | Submission of Detailed Grid Disturbance report (1000 MW load / generation loss or tripping of 765kV and 400 kV bus in 765/400 kV substation) timely to MERC | 80 | P=IF (A<=15,80, IF(A<=20,60,IF(A<=25,40,0))) A= Number of working days within which 100% of detail Grid Disturbance Report is submitted in prescribed format to WRLDC/MERC |
|
| Sub-total | 400 | |||
| 6 | (B) Financial Prudence (Over-all weightage 20%) |
Variance in Capex Utilization: Minimum variance (+/-) of actual CAPEX from CAPEX as allowed by MERC | 80 | P= IF (V<=15, 100, 100-(85-(100-V)))/10080 V= Mode(A-B)/B100 A: Actual Expenditure incurred B: CAPEX approved by MERC Target= 15% or less Variance |
| 7 | Statutory Compliance of the following Audits: i. Internal Audit (Phase I) ii. Internal Audit (Phase II) iii. Physical Verification Audit |
120 | P= A/B*120 A: Number of Audits complied during the year Target (B)= 4 Audits |
|
| Subtotal | 200 |
| S.No. | Parameters | Marks | Performance/ Marks obtained | |
|---|---|---|---|---|
| 8 | (C) Learning & Growth (Over-all weightage 20%) |
New technology adoption / R&D | 60 | P= IF (A>=B, 60,0) A: number of new technologies adopted B: Target number (1) |
| 9 | Lessons learnt and knowledge dissemination by way of data intensive reports | 60 | P= IF (A>=B, 60, IF (A=1, 30, 0)) A: Number of reports released B: Target number (2) |
|
| 10 | Adequacy of HR - % of certified operators among eligible operators: 80% or more certified operators among eligible employees | 40 | P= IF (A>= 80, 100, 100-(80-A))/10040 A= No. of employees certified as on last date of the financial year/No. of employees eligible for certification as on last date of the financial year100 |
|
| 11 | Capacity Building: No. of man- days per year per eligible employee | 40 | P= {100-(100-A)/2}/100*40 A= Percentage no. of employees trained for more than or equal to mandated 7 days as on last date of the financial year |
|
| Subtotal | 200 | |||
| 12 | (D) Internal Process (Over-all weightage 20%) |
Availability of Decision Support System – SCADA | 80 | P= IF (A>=99.95, 100, (100-(99.95-A))/100*80 A= Average of monthly performance Monthly Performance= (M-D)/M M: Hours in a month D: Downtime in hours in case Monthly Performance of any month is 75% or below, Marks shall be zero |
| 13 | Availability of IT infrastructure hardware and software: such as Servers, Firewalls, Routers, Backup Appliances, Managed switches, Websites, IT infrastructure on Cloud etc. | 60 | P= A/B*60 A= Number of days particular facility/infrastructure available in working condition) B= No. of days in the corresponding year |
| S.No. | Parameters | Marks | Performance/ Marks obtained | |
|---|---|---|---|---|
| 14 | ISO Certification | 20 | $P = A/B \times 20$ A= Number of ISO standards that are active for all days in a year. B=Number of ISO standards (4) |
|
| 15 | Process Documentation – Black Start, Reactive Power: Update Black Start Procedure by 31st January every year and Update Reactive Power Document by 31st December every year | 40 | $P = IF(A=2,40, IF(A=1,20,0))$ A= Number of documents updated and uploaded within stipulated time. |
|
| Subtotal | 200 | |||
| Total | 1000 |
127.1 The MSLDC shall raise monthly bill for MSLDC Charges on every Long-term Beneficiary and Medium-Term Open Access consumer on the first working day of the month for the MSLDC Charges of preceding month.
128.1 The Regulations contained in this Part shall apply in determining the Fees and Charges to be levied by the State Transmission Utility (STU) after April 1, 2025.
129.1 The STU shall submit a detailed capital investment plan, financing plan and physical targets for each Year of the Control Period based on the operational requirements prescribed by the Commission or the Ministry of Power, Government of India or any such other statutory authorities, to the Commission for approval, as a part of the Multi-Year Aggregate Revenue Requirement for the entire Control Period.
129.2 The Capital Investment Plan shall be a least cost plan for undertaking investments and shall cover all capital expenditure projects of a value exceeding INR One Crore or any other limit as may be stipulated by the Commission from time to time and shall be in such form as may be stipulated by the Commission.
129.3 The Capital Investment Plan shall be accompanied by such information, particulars and documents as may be required showing the need for the proposed investments, alternatives considered, cost/benefit analysis and other aspects that may have a bearing on the STU Fees and Charges.
129.4 The Commission shall consider the Capital Investment Plan along with the Multi-Year Aggregate Revenue Requirement for the entire Control Period submitted by the STU taking into consideration the prudence of the proposed expenditure and estimated impact on STU Fees and Charges.
129.5 The STU shall submit, along with the Petition for determination of Aggregate Revenue Requirement, details showing the progress of capital expenditure projects, together with such other information, particulars or documents as the Commission may require assessing such progress.
130.1 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:
(a) Operation and Maintenance expenses;
(b) Depreciation;
(c) Interest on Loan Capital;
(d) Interest on working capital
(e) Return on Equity Capital;
minus:
Provided that Depreciation, Interest on Loan, and Return on Equity for the STU shall be allowed in accordance with the provisions specified in Part D of these Regulations.
Provided further that prior period income/expenses shall be allowed by the Commission at the time of Truing up based on audited accounts, on a case to case basis, if the income/expenses in that prior period have been allowed on actual basis, subject to prudence check:
Provided also that all penalties and compensation payable by the STU to any party for failure to meet its obligations or for damages, as a consequence of the Orders of the Commission and Courts shall not be allowed to be recovered through the Aggregate Revenue Requirement:
Provided also that the STU shall maintain separate details of such penalties and compensation paid or payable by the STU, if any, and shall submit the same to the Commission along with the Petitions to be submitted under these Regulations.
131.1 The Operation and Maintenance Expenses for the STU shall be computed in accordance with this Regulation as below.
FY 2022-23, FY 2023-24 and FY 2024-25, to arrive at the Operation and Maintenance expenses for the base year ending March 31, 2025:
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:
Provided also that at the time of true-up for each Year of this Control Period, the Operation and Maintenance expenses, including insurance, shall be derived on the basis of the Final Trued-up Operation and Maintenance expenses, after adding/ deducting the sharing of efficiency gains/ losses, excluding abnormal expenses, if any, subject to prudence check by the Commission, and shall be considered as the Base Year Operation and Maintenance expenses.
Provided that if actual O&M expenses are lower than normative O&M expenses on this account, then no sharing of efficiency gains shall be done to that extent.
131.2 The STU may undertake Opex schemes for system automation, new technology and IT implementation, etc., and, such expenses may be allowed over and above normative O&M Expenses, subject to prudence check by the Commission:
132.1 The amount of Non-Tariff Income relating to the STU as approved by the Commission shall be deducted from the Aggregate Revenue Requirement in determining the Fees and Charges of the STU:
Provided that the STU shall submit full details of its forecast of Non-Tariff Income to the Commission in such form as may be stipulated by the Commission.
The Non-Tariff Income shall include:
Provided that the interest earned from investments made out of Return on Equity of the STU shall not be included in Non-Tariff Income.
133.1 The STU Charges payable by the Transmission System Users shall be computed in accordance with the following formula:
$$AFC(u)(t) = AFC(t) \times (Base\ TCR(u) / \sum ni=1Base\ TCR(u))$$
Where,
$AFC(u)(t)$ = STU Charges to be shared by the Beneficiary (u) for the Yearly period (t);
$AFC(t)$ = Total STU Charges to be shared by the Beneficiaries for the Yearly period (t);
$$Base\ TCR\ (u) = [CPD(u)(t) + NCPD(u)(t)] / 2$$
Where,
Base TCR represents the Base Transmission Capacity Right of each Beneficiary (u) for the Yearly period (t);
CPD (u)(t) = Average Coincident Peak Demand of the Beneficiary (u) for the Yearly period (t);
NCPD (u)(t) = Average Non-coincident Peak Demand of the Beneficiary (u) for the Yearly period (t);
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.
134.2 The Annual MSLDC Charge payable by Transmission System User shall be computed in accordance with the following formula:
$$\text{Monthly STU Charges (INR/MW/Month)} = [\text{AFC}(u){(t)} \div \sum{t=1}^n [\text{Adjusted Base TCR}(u)]_{(t)}] \div 12$$
Where,
$$\text{Adjusted Base TCR (u)} = \text{Base TCR}(u) - \text{Billed OA Demand of POA}(u)$$
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);
134.3 The STU Charges approved for the Year shall be equally spread over the 12 months of the Year and STU Charges per MW per month shall be computed by STU in accordance with the following Formula:
$$\text{Monthly STU Charges (INR/MW/Month)} = [\text{AFC}(u){(t)} \div \sum{t=1}^n [\text{Base TCR}(u)]_{(t)}] \div 12$$
134.4 The Open Access consumers excluding those covered under Regulation 134.1 shall be liable for payment of the STU Charges in proportion to the duration for which they were granted Open Access during the concerned billing period.
134.5 The Charges to be recovered by STU shall continue to be billed at the Tariff approved by the Commission and applicable as on March 31, 2025 for the period starting from April 1, 2025 till approval of Charges by the Commission in accordance with these Regulations.
135.1 The STU shall recover the following Fees as approved by the Commission from time to time:
The revenue from such Fees shall be considered for adjustment of Annual Fixed Charges in subsequent Years.
136.1 STU shall submit its actual performance against each of the key performance indicators to the Commission on an annual basis along with supporting documents.
136.2 The Commission shall evaluate the overall performance of the STU, on the basis of weightage specified in the table below.
136.3 STU 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%.
136.4 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.
| S.No. | Parameters | Marks | Performance/ Marks obtained | |
|---|---|---|---|---|
| 1 | (A) Stakeholders Satisfaction |
Planning: Planning of new proposals of InSTS with the use of field data, study and finalization of planning. | 100 | Use of field data for finalization of planning of new InSTS proposals. Percentage of use of latest field data for planning proposals shall be taken in to consideration deciding marks obtained. |
| 2 | Open Access: Grant of non-discriminatory open access to InSTS through grant of Connectivity & GNA. | 100 | Number of applications in a year for issuance of connectivity and GNA. No. of connectivity not granted and GNA not approved for which no compliance is needed from applicant shall be considered for determining the marks obtained. | |
| 3 | Project Monitoring: STU is responsible for monitoring of projects. On line data from various projects. | 100 | Number of ongoing projects of intra-state transmission licensees and details progress reports of project collected. STU efforts for monitoring intra state projects and submitting the progress of on going project to the Commission shall be used for determining the percentage marks obtained. |
|
| 4 | STU is the Nodal Agency for TBCB projects. Monitoring of progress of TBCB projects | 100 | On going TBCB projects within the state and detail progress reports of project collected and informed to MERC. The progress report submitted to the Commission compared to ongoing projects under TBCB shall be considered for determining the percentage marks obtained. |
|
| 5 | Coordination with CTU for CTU-STU projects by providing state specific data. | 100 | No. of CTU-STU coordination meeting conducted in year. No. of meetings STU represented by the state and cleared obtained for STU projects shall be considered for the percentage marks obtained. |
|
| 6 | Coordination meetings with intra-state entities for various planning activities. | 100 | No. of intra-state meetings conducted in years for intra state planning. No. of clearance for intra state projects shall be considered for the percentage marks obtained. |
| S.No. | Parameters | Marks | Performance/ Marks obtained | |
|---|---|---|---|---|
| 7 | Submission of 5-year STU plan proposal to the Commission and updating the proposal every year. | 100 | STU shall submit 5-year plan proposal to the Commission in stipulated time. Every one month delay and part thereof shall reduce 10 marks obtained by STU for every month delay in submission of 5-year plan. |
|
| Sub-total | 700 | |||
| 8 | (B) Financial Prudence |
STU is responsible for raising transmission bills, collection and disbursement of transmission charges to InSTS transmission licensees. | 100 | Issuance of transmission charges bills as per InSTS order, collection of transmission charges and disbursement of transmission charges to transmission licensees. Short fall of transmission charges for disbursement among transmission licensees. Any delay by one (1) day for issuance and disbursement of transmission charges bills shall reduce 5 % percentage. Overall annual performance shall be considered for determination marks obtained. |
| 9 | Statutory Compliance of the following Audits: i. Internal Audit (Phase I) ii. Internal Audit (Phase II) iii. Physical Verification Audit |
100 | $P = A/B * 100$ A: Number of Audits complied during the year Target (B) = 4 Audits |
|
| Subtotal | 200 | |||
| 10 | (C) Learning & Growth |
New technology adoption / R&D/new software deployed. | 50 | $P = IF (A \geq B, 50, 0)$ A: number of new technologies adopted B: Target number (1) |
| 11 | Availability of IT software: such as Load Flow software, Short Circuit Studies etc. | 50 | $P = IF (A \geq B, 50, IF (A = 1, 30, 0))$ A: Number of times software used. B: Target number (2) |
|
| 12 | Capacity Building: No. of man- days per year per eligible employee | 50 | $P = {100 - (100 - A)/2} / 100 * 50$ A= Percentage no. of employees deputed for training/Seminar/Workshops for more than or equal to mandated 7 days as on last date of the financial year |
| S.No. | Parameters | Marks | Performance/ Marks obtained | |
|---|---|---|---|---|
| 13 | ISO Certification | 50 | P= A/B*50 A= Number of ISO standards that are active for all days in a year. B=Number of ISO standards |
|
| Subtotal | 200 | |||
| Total | 1100 |
137.1 The STU shall raise monthly bill for STU Charges on every Long-term Beneficiary and Medium-Term Open Access consumer on the first working day of the month for the STU Charges of preceding month.
138.1 The Regulations specified in this Part shall apply to the determination of Tariff for Energy Storage Systems including Pumped Storage Hydro Project.
138.2 The Commission shall be guided by the terms and conditions contained in this Part in determining the Tariff for ESS, in the following cases:
139.1 An ESSD shall file a Petition for determination of Tariff in accordance with the provisions of Part B of these Regulations:
139.2 Tariff in respect of ESS, under these Regulations may be determined Stage-wise, Unit-wise or for the whole ESS:
Provided that the terms and conditions for determination of Tariff for ESS specified in this Part shall apply in like manner to Stages or Units or the ESS, as the case may be.
139.3 Where the Tariff is being determined for a Stage or Unit of an ESS, the ESSD shall adopt a reasonable basis for allocation of capital cost relating to common facilities and allocation of joint and common costs across all Stages or Units, as the case may be:
Provided that the ESSD shall maintain an Allocation Statement providing the basis for allocation of such costs, which shall be duly audited and certified by the statutory auditors and submit such audited and certified statement to the Commission along with the Petition for determination of Tariff.
139.4 The ESSD shall file the Petition for determination of provisional Tariff for new ESS, at least six months prior to the anticipated date of commercial operation of ESS Unit or Stage or System as a whole, as the case may be.
139.5 The ESSD shall file a Petition for determination of provisional Tariff for new ESS 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.
139.6 In the case of new projects, the ESSD may be allowed provisional Tariff by the Commission from the anticipated date of commercial operation, based on the projected capital expenditure, subject to prudence check.
139.7 If the date of commercial operation is likely to be delayed beyond six months from the date of issue of the order approving the provisional Tariff, the ESSD may submit a Petition for seeking extension of the validity of the applicability of the provisional Tariff, giving details of the present status of completion and justification for the delay in project completion, which may be considered by the Commission after necessary prudence check.
139.8 The ESSD shall file the Petition for determination of final Tariff for ESS within six months from the date of commercial operation of Energy Storage Unit or Stage or System as a whole, as the case may be, based on the audited capital expenditure and capitalisation as on the date of commercial operation:
Provided that in case of more than one Unit in the ESS, such Petition shall be filed for each Unit as and when such Unit achieves COD and without waiting for the COD of the entire Station.
Provided that the Petitioner shall provide such information as the Commission may require to satisfy itself that the guidelines issued by the Central Government have been duly followed.
141.1** The Tariff for ESS shall comprise of two parts, namely, Capacity Charge and Incentive for Cycle Efficiency above Design Cycle Efficiency.
141.2** The Annual Fixed Charges shall comprise the following components:
Operation & Maintenance Expenses;
d. Interest on Working Capital;
e. Return on Equity Capital;
Provided that Return on Equity for the ESS shall be allowed in accordance with the provisions specified in Part D of these Regulations.
Provided that all penalties and compensation payable by the ESS Developer or Generating Company or Licensee to any party for failure to comply with any directions or for damages, as a consequence of the orders of the Commission, Courts, etc., shall not be allowed to recover through the Aggregate Revenue Requirement:
Provided also that the ESSD or Generating Company or Licensee shall maintain separate details of such penalties and compensation paid or payable by the ESSD or Generating Company or Licensee, if any, and shall submit them to the Commission along with its Petition.
142.1 The Petition for BESS shall include the details like:
142.2 Capital Cost: Capital cost shall be considered in the manner as specified under Regulations 24 of these Regulations and the provisions of the MERC (Approval of Capital Investment Schemes) Regulations, 2022.
142.3 Additional Capital Expenditure: Additional capital expenditure shall be considered in the manner as specified under MERC (Approval of Capital Investment Schemes) Regulations, 2022.
142.4 Capital Structure:
142.5 Operating Parameters for BESS
$$\text{Monthly Round Trip Efficiency of BESS} = \frac{\text{Monthly Energy Discharged}}{\text{Monthly Energy consumed for Charging}} \times 100$$
Annual Availability of BESS = Mean of the system availabilities of all time blocks during the year in which Beneficiary has scheduled power for charging/discharging the BESS.
$$\text{Availability in a time block} = \frac{\text{Actual Injection or Drawal MUI (A)}}{\text{Scheduled Injection or Drawal MUI (B)}} \times 100$$
Where,
i. i refers to the ith time-block (15 minutes) in the year where MUI (B) ≠ 0.
ii. MUI(A)= Agreed Despatch Schedule between Licensee or Beneficiary and BESSD which shall be finally sent to MSLDC for Charging/Discharging in the ith time block, in MUs
iii. MUI(B)= Despatch Schedule provided by Distribution Licensee or Beneficiary to BESSD for Charging/Discharging in the ith time block, in MUs.
c. Normative Depth of Discharge for BESS shall be 90%
d. Battery pack performance degradation shall be considered as 1% per year.
c. Average Ramp Rate for BESS shall be 75% of rated capacity/minute
Provided that the remaining depreciable value as on 31st March of the year closing after a period of 15 years from the effective date of commercial operation of the station shall be spread over the balance useful life of the assets.
Provided that, Useful life of Battery Pack shall be 12 Years whereas balance of system's useful life shall be 25 years.
Provided that,
Provided also that any depreciation disallowed on account of lower availability of the BESS or transmission system, as the case may be, shall not
be allowed to be recovered at a later stage during the useful life or the extended life.
Provided that, the Operation and Maintenance expenses for each subsequent year and in the Truing-up of the respective years of the Control Period shall be determined in the same manner as specified in Regulation 48.1 (c)
Provided also that, the Normative O&M expenses shall be Trued up at the end of the Control Period and Treatment to the variation in the normative and actual O&M expenses shall be as per Regulation 11.
a. The fixed cost of BESS achieving COD after April 1, 2025 shall be computed on annual basis, based on norms specified under these Regulations, and recovered on monthly basis as Capacity Charge.
b. The Capacity Charge shall be payable by the Beneficiaries in proportion to their respective allocation in the saleable capacity of the BESS:
$$\text{Monthly BESS Availability} = \frac{\sum \text{Actual Injection or Drawal MWh (i)(A)}}{\sum \text{Scheduled Injection or Drawal MWh (i)(B)}} \times 100$$
Where,
Monthly Capacity Charge payment for BESS linked to Monthly Availability Factor shall be payable as per following formula:
$$CC1 = (AFC) \times (1/12) \times (EAFM1 / NAEAF)$$
$$CC2 = (AFC) \times (1/6) \times (EAFM2 / NAEAF) \text{ subject to ceiling of } {(AFC) \times (1/6)} - {CC1}$$
$$CC3 = (AFC) \times (1/4) \times (EAFM3 / NAEAF) \text{ subject to ceiling of } {(AFC) \times (1/4)} - {CC1 + CC2}$$
$$CC4 = (AFC) \times (1/3) \times (EAFM4 / NAEAF) \text{ subject to ceiling of } {(AFC) \times (1/3)} - {CC1 + CC2 + CC3}$$
$$CC5 = (AFC) \times (5/12) \times (EAFM5 / NAEAF) \text{ subject to ceiling of } {(AFC) \times (5/12)} - {CC1 + CC2 + CC3 + CC4}$$
$$CC6 = (AFC) \times (1/2) \times (EAFM6 / NAEAF) \text{ subject to ceiling of } {(AFC) \times (1/2)} - {CC1 + CC2 + CC3 + CC4 + CC5}$$
$$CC7 = (AFC) \times (7/12) \times (EAFM7 / NAEAF) \text{ subject to ceiling of } {(AFC) \times (7/12)} - {CC1 + CC2 + CC3 + CC4 + CC5 + CC6}$$
$$CC8 = (AFC) \times (2/3) \times (EAFM8 / NAEAF) \text{ subject to ceiling of } {(AFC) \times (2/3)} - {CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7}$$
$$CC9 = (AFC) \times (3/4) \times (EAFM9 / NAEAF) \text{ subject to ceiling of } {(AFC) \times (3/4)} - {CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7 + CC8}$$
$CC10 = (AFC)x (5/6) x (EAFM10 / NAEAF)$ subject to ceiling of ${(AFC)x (5/6)} - {CC_1 + CC_2 + CC_3 + CC_4 + CC_5 + CC_6 + CC_7 + CC_8 + CC_9}$
$CC11 = (AFC)x (11/12) x (EAFM11 / NAEAF)$ subject to ceiling of ${(AFC)x (11/12)} - {CC_1 + CC_2 + CC_3 + CC_4 + CC_5 + CC_6 + CC_7 + CC_8 + CC_9 + CC_{10}}$
$CC12 = (AFC)x (EAFM11 / NAEAF)$ subject to ceiling of ${(AFC) - {CC_1 + CC_2 + CC_3 + CC_4 + CC_5 + CC_6 + CC_7 + CC_8 + CC_9 + CC_{10} + CC_{11}}$
CCn= Capacity Charge for the Month (n);
AFC = Annual Fixed Cost;
EAFMn = Monthly BESS Availability Factor achieved during nth Month;
NAEAF= Normative Annual BESS Availability Factor.
Provided that, the Availability of BESS shall be considered in both Charging and Discharging mode for the computation of Capacity Charge as specified above.
Provided also that there would be adjustment at the end of the year based on actual generation and actual energy consumed by the BESS during the year.
Provided that in case the energy generated in a month is less than the 75% of the energy consumed for the month, then the Incentive payable by the Beneficiaries shall be zero.
i. Capital Cost of PSH,
ii. Availability of PSH
iii. Cycle Efficiency of the PSH,
iv. Design parameters of number of Cycles (Generation and pumping) during the useful life,
v. Useful life of PSH,
vi. Operation and Maintenance Expenses,
vii. Design parameters of Number of hours of Pumping and Number of Hours of Generation during 24 hour duration of each operating day,
viii. Annual deration factor (if any) over useful life
ix. Pumping power requirement and arrangement for PSH.
143.2 Capital Cost: Capital cost shall be considered in the manner as specified under Regulations 24.
143.3 Additional Capital Expenditure: Additional capital expenditure shall be considered in the manner as specified under MERC (Approval of Capital Investment Schemes) Regulations, 2022.
$$\text{Monthly/Annual Cycle Efficiency of PSH} = \frac{\text{Annual Energy Generated}}{\text{Annual Energy consumed for Pumping}} \times 100$$
PSH Annual Availability = Mean of the system availabilities of all time blocks during the year in which Beneficiary has scheduled power for Pumping/ Generation by PSH.
$$\text{Availability in a time block} = \frac{\text{Actual Injection or Drawal MUi (A) by PSH}}{\text{Scheduled Injection or Drawal MUi (B) by PSH}} \times 100$$
Provided that the remaining depreciable value as on 31st March of the year closing after a period of 15 years from the effective date of commercial operation of the station shall be spread over the balance useful life of the assets.
Provided that, Useful life of PSH shall be 40 years from the date of COD.
Provided that,
Provided that the salvage value shall be:
Provided also that any depreciation disallowed on account of lower availability of the PSH station or unit or transmission system, as the case may be, shall not be allowed to be recovered at a later stage during the useful life or the extended life.
Provided that, the Operation and Maintenance expenses for each subsequent year and in the Truing-up of the respective years of the Control Period shall be determined in the same manner as specified in Regulation 48.1 (c)
Provided also that, the Normative O&M expenses shall be Trued up at the end of the Control Period and Treatment to the variation in the normative and actual O&M expenses shall be as per Regulation 11.
The Capacity Charge payable to PSH for a calendar month shall be:
Monthly Availability factor for PSH shall be determined as per following formula:
$$\text{Monthly PSH Availability} = \frac{\sum \text{Actual Injection or Drawal MWh (i)(A)}}{\sum \text{Scheduled Injection or Drawal MWh (i)(B)}} \times 100$$
Where,
Monthly Capacity Charge payment for PSH linked to Monthly Availability Factor shall be payable as per following formula:
$$CC1=(AFC)x(1/12) \times (EAFM1 / NAEAF)$$
$$CC2=(AFC)x(1/6) \times (EAFM2 / NAEAF) \text{ subject to ceiling of } {(AFC)x(1/6)} - {CC1}$$
$$CC3=(AFC)x(1/4) \times (EAFM3 / NAEAF) \text{ subject to ceiling of } {(AFC)x(1/4)} - {CC1 + CC2}$$
$$CC4=(AFC)x(1/3) \times (EAFM4 / NAEAF) \text{ subject to ceiling of } {(AFC)x(1/3)} - {CC1 + CC2 + CC3}$$
$CC5 = (AFC)x (5/12) x (EAFM5 / NAEAF)$ subject to ceiling of ${(AFC)x (5/12)} - {CC1 + CC2 + CC3 + CC4}$
$CC6 = (AFC)x (1/2) x (EAFM6 / NAEAF)$ subject to ceiling of ${(AFC)x (1/2)} - {CC1 + CC2 + CC3 + CC4 + CC5}$
$CC7 = (AFC)x (7/12) x (EAFM7 / NAEAF)$ subject to ceiling of ${(AFC)x (7/12)} - {CC1 + CC2 + CC3 + CC4 + CC5 + CC6}$
$CC8 = (AFC)x (2/3) x (EAFM8 / NAEAF)$ subject to ceiling of ${(AFC)x (2/3)} - {CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7}$
$CC9 = (AFC)x (3/4) x (EAFM9 / NAEAF)$ subject to ceiling of ${(AFC)x (3/4)} - {CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7 + CC8}$
$CC10 = (AFC)x (5/6) x (EAFM10 / NAEAF)$ subject to ceiling of ${(AFC)x (5/6)} - {CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7 + CC8 + CC9}$
$CC11 = (AFC)x (11/12) x (EAFM11 / NAEAF)$ subject to ceiling of ${(AFC)x (11/12)} - {CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7 + CC8 + CC9 + CC10}$
$CC12 = (AFC)x (EAFM11 / NAEAF)$ subject to ceiling of ${(AFC) - {CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7 + CC8 + CC9 + CC10 + CC11}$
Where,
CCn= Capacity Charge for the Month (n);
AFC = Annual Fixed Cost;
EAFMn = Monthly PSH Availability Factor achieved during nth Month;
NAEAF= Normative Annual PSH Availability Factor.
Provided that, the Availability of PSH shall be considered in both Pumping and Generation mode for the computation of Capacity Charge as specified above.
Provided also that there would be adjustment at the end of the year based on actual generation and actual energy consumed by the PSH during the year.
Provided that in case the energy generated in a month is less than the 75% of the energy consumed for the month, then the Incentive payable by the Beneficiaries shall be zero.
distribution losses up to the bus bar of the generating Station, and in return, Beneficiaries shall be entitled to energy equivalent to 75% of the energy utilized in pumping the water from the lower elevation reservoir to the higher elevation reservoir, from the generating Station as requested by the Beneficiaries and the PSH Plant shall be under obligation to supply such quantum of electricity.
144.1 The ESS may be required to demonstrate the Ramp Rate capability of its ESS as and when asked by the MSLDC as per the provisions of the Regulation 32 of the MERC State Grid Code, 2020.
144.2 In the event of the ESS failing to demonstrate the Average Ramp rate, the Performance linked Return on Equity shall be reduced as a measure of penalty.
Provided that the MSLDC shall formulate the procedure for certification of Ramp Rate of ESS and submit for the approval of the Commission upon undertaking the due consultation of the stakeholders.
144.3 The operating logbooks of the ESS shall be available for scrutiny by the MSLDC, and these books shall keep record of machine operation and maintenance.
145.1 The Billing and Payment of Annual Fixed Charges, Capacity Charges and Incentives for ESS, shall be done on a monthly basis.
146.1 Provisions of the MERC (Deviation Settlement Mechanism and Related matters) Regulations, 2019, Procedure thereunder and its Amendments shall be applicable to the ESS.
Provided that, ESS when operating in Charging/Pumping mode shall be treated as Buyer and ESS when operating in Discharging/Generation mode shall be treated as Seller and relevant provisions of MERC (Deviation Settlement Mechanism and Related matters) Regulations, 2019, applicable to Buyer and Seller shall be applicable to ESS appropriately.
Provided that the Deviation Charges paid or earned by the ESS in accordance with Regulation 9 of the MERC (Deviation Settlement Mechanism and Related matters) Regulations, 2019 and Additional Charges for Deviation in accordance with Regulation 10 of the MERC (Deviation Settlement Mechanism and Related matters) Regulations, 2019, shall not be recoverable/adjusted from the Beneficiary/ies through Tariff:
147.1 If the State Government requires the grant of any subsidy to any consumer or class of consumers in the Tariff determined by the Commission, the State Government shall pay in advance the amount to compensate the Distribution Licensee/person affected by the grant of subsidy in the manner specified in this Regulation, with prior intimation to the Commission.
147.2 The amount of subsidy agreed to by the State Government shall be provided in the form of grant by the State Government.
147.3 The subsidy shall be passed on to eligible consumers through credit in their electricity bills only in proportion to the extent to which the total requirement of the Distribution Licensee is paid by the State Government:
Provided that in case of shortfall in actual release of subsidy, either because of errors in estimation or for any other reason, such shortfall, shall be shown clearly in the consumers' bills and shall be distributed proportionately between the concerned eligible consumers until such time as it is reduced or eliminated.
147.4 The Distribution Licensee shall clearly indicate the following details in the consumers' bills:
147.5 The Distribution Licensee shall submit to the Commission on quarterly report consisting of details w.r.t demands of subsidy raised by Distribution Licensee to the State Government during the relevant quarter based on the accounts of the energy consumed by the subsidised category and consumer category wise per unit subsidy declared by the State Government, the actual payment of subsidy in accordance with section 65 of the Act and the gap in subsidy due and paid as well as other relevant details, as may be specified by the Commission and / or Ministry of Power vide its Rules framed under the provisions of the Electricity Act 2003. The report on subsidy status shall be hosted on the Distribution Licensee's website.
148.1 Subject to the provisions of the Act, the Commission may from time to time, issue Orders and Practice Directions in regard to implementation of these Regulations.
149.1 The Commission may by general or special order, for reasons to be recorded in writing, and after giving an opportunity of hearing to the parties likely to be affected, may relax any of the provisions of these Regulations on its own motion or on an application made before it by an interested person.
150.1 The Commission may, at any time, vary, alter, modify or amend any provisions of these Regulations.
151.1 If any difficulty arises in giving effect to the provisions of these Regulations, the Commission may, by an order, make such provisions, not inconsistent to the provision of the Act and these Regulations, as may appear to be necessary for removing the difficulty.
Mumbai
___/08/2024
(Secretary)
Maharashtra Electricity Regulatory Commission
| Sr. No. | Depreciation of Assets | Depreciation Rate (Straight line method) - for Existing Assets or Schemes |
|---|---|---|
| A | LAND UNDER FULL OWNERSHIP | 0.00% |
| B | LAND UNDER LEASE | |
| (a) | for investment in the land | 3.34% |
| (b) | For the cost of clearing the site | 3.34% |
| (c) | Land for reservoir in case of hydro generating station | 3.34% |
| C | ASSETS PURCHASED NEW | |
| (a) | Plant & Machinery in generating stations | |
| (i) | Hydro electric | 5.28% |
| (ii) | Steam electric | 5.28% |
| (iii) | NHRB & waste heat recovery boilers | 5.28% |
| (iv) | Diesel electric and gas plant | 5.28% |
| (b) | Cooling towers & circulating water systems | 5.28% |
| (c) | Hydraulic works forming part of the Hydro-generating stations | |
| (i) | Dams, Spillways, Weirs, Canals, Reinforced concrete flumes and siphons | 5.28% |
| (ii) | Reinforced concrete pipelines and surge tanks, steel pipelines, sluice gates, steel surge tanks, hydraulic control valves and hydraulic works | 5.28% |
| d. | Building & Civil Engineering works | |
| (i) | Offices and showrooms | 3.34% |
| (ii) | Containing thermo-electric generating plant | 3.34% |
| (iii) | Containing hydro-electric generating plant | 3.34% |
| (iv) | Temporary erections, such as wooden structures | 100.00% |
| (v) | Roads other than Kutchra roads | 3.34% |
| (vi) | Others | 3.34% |
| e. | Transformers, Kiosks, sub-station equipment & other fixed apparatus (including plant) | |
| (i) | Transformers, including foundations having a rating of 100 KVA and over | 5.28% |
| (ii) | Others | 5.28% |
| f. | Switchgear, including cable connections | 5.28% |
| g. | Lightning arrestor | |
| (i) | Station type | 5.28% |
| (ii) | Pole type | 5.28% |
| (iii) | Synchronous condenser | 5.28% |
| h. | Batteries | 9.50% |
| (i) | Underground cable, including joint boxes and disconnected boxes | 5.28% |
| (ii) | Cable duct system | 5.28% |
| i. | Overhead lines, including cable support | |
| (i) | Lines on fabricated steel operating at terminal voltages higher than 66 KV | 5.28% |
| Sr. No. | Depreciation of Assets | Depreciation Rate (Straight line method) - for Existing Assets or Schemes |
|---|---|---|
| (ii) | Lines on steel supports operating at terminal voltages higher than 13.2 KV but not exceeding 66 KV | 5.28% |
| (iii) | Lines on steel on reinforced concrete support | 5.28% |
| (iv) | Lines on treated wood support | 5.28% |
| j. | Meters | 5.28% |
| k. | Self-propelled vehicles | 9.50% |
| l. | Air Conditioning Plants | |
| (i) | Static | 5.28% |
| (ii) | Portable | 9.50% |
| m. | ||
| (i) | Office furniture and furnishing | 6.33% |
| (ii) | Office equipment | 6.33% |
| (iii) | Internal wiring, including fittings and apparatus | 6.33% |
| (iv) | Street Light fittings | 5.28% |
| n. | Apparatus let on hire | |
| (i) | Other than motors | 9.50% |
| (ii) | Motors | 6.33% |
| o. | Communication equipment | |
| (i) | Radio and high frequency carrier system | 15.00% |
| (ii) | Telephone lines and telephones | 15.00% |
| (iii) | Fibre Optic/OPGW | 6.33% |
| p. | I. T Equipment | 15.00% |
| q. | Software, SCADA system | 15.00% |
| r. | Any other assets not covered above | 5.28% |
| Depreciation of Assets | Depreciation Rate (Straight line method) - for New Assets or Schemes |
|
|---|---|---|
| A | LAND UNDER FULL OWNERSHIP | 0.00% |
| B | LAND UNDER LEASE | |
| (a) | for investment in the land | 3.34% |
| (b) | For the cost of clearing the site | 3.34% |
| (c) | Land for reservoir in case of hydro generating station | 3.34% |
| C | ASSETS PURCHASED NEW | |
| (a) | Plant & Machinery in generating stations | |
| (i) | Hydro electric | 4.22% |
| (ii) | Steam electric | 4.22% |
| (iii) | NHRB & waste heat recovery boilers | 4.22% |
| (iv) | Diesel electric and gas plant | 4.22% |
| (b) | Cooling towers & circulating water systems | 4.22% |
| (c) | Hydraulic works forming part of the Hydro-generating stations | |
| (i) | Dams, Spillways, Weirs, Canals, Reinforced concrete flumes and siphons | 4.22% |
| (ii) | Reinforced concrete pipelines and surge tanks, steel pipelines, sluice gates, steel surge tanks, hydraulic control valves and hydraulic works | 4.22% |
| d. | Building & Civil Engineering works | |
| (i) | Offices and showrooms | 3.34% |
| (ii) | Containing thermo-electric generating plant | 3.34% |
| (iii) | Containing hydro-electric generating plant | 3.34% |
| (iv) | Temporary erections, such as wooden structures | 100.00% |
| (v) | Roads other than Kutcha roads | 3.34% |
| (vi) | Others | 3.34% |
| e. | Transformers, Kiosks, sub-station equipment & other fixed apparatus (including plant) | |
| (i) | Transformers, including foundations having a rating of 100 KVA and over | 4.22% |
| (ii) | Others | 4.22% |
| f. | Switchgear, including cable connections | 4.22% |
| g. | Lightning arrestor | |
| (i) | Station type | 4.22% |
| (ii) | Pole type | 4.22% |
| (iii) | Synchronous condenser | 4.22% |
| h. | Batteries | 9.50% |
| (i) | Underground cable, including joint boxes and disconnected boxes | 4.22% |
| (ii) | Cable duct system | 4.22% |
| vi. | Overhead lines, including cable support |
| Depreciation of Assets | Depreciation Rate (Straight line method) - for New Assets or Schemes |
|
|---|---|---|
| (i) | Lines on fabricated steel operating at terminal voltages higher than 66 KV | 4.22% |
| (ii) | Lines on steel supports operating at terminal voltages higher than 13.2 KV but not exceeding 66 KV | 4.22% |
| (iii) | Lines on steel on reinforced concrete support | 4.22% |
| (iv) | Lines on treated wood support | 4.22% |
| j. | Meters | 4.22% |
| k. | Self-propelled vehicles | 9.50% |
| (i) | Static | 4.22% |
| (ii) | Portable | 9.50% |
| m. | ||
| (i) | Office furniture and furnishing | 6.33% |
| (ii) | Office equipment | 6.33% |
| (iii) | Internal wiring, including fittings and apparatus | 6.33% |
| (iv) | Street Light fittings | 4.22% |
| n. | Apparatus let on hire | |
| (i) | Other than motors | 9.50% |
| (ii) | Motors | 6.33% |
| o. | Communication equipment | |
| (i) | Radio and high frequency carrier system | 15.00% |
| (ii) | Telephone lines and telephones | 15.00% |
| (iii) | Fibre Optic/OPGW | 6.33% |
| p. | I. T Equipment | 15.00% |
| q. | Software, SCADA system | 15.00% |
| r. | Any other assets not covered above | 4.22% |
| Sr. No. | Asset Particulars | Life in Years |
|---|---|---|
| 1 | Land Freehold@ | 999 |
| 2 | Land Leasehold | &&& |
| 3 | Temporary erections | 1 |
| 4 | HEMMS | 8 |
| 5 | Roads, bridges, culverts, helipads | 25 |
| 6 | Main Plant Buildings | 30 |
| 7 | Machinery other than HEMM | 15 |
| 8 | Water Supply, Drainage, and sewerage | 15 |
| 9 | Furniture and Fixtures | 15 |
| 10 | Office equipment/s other than computers | 15 |
| 11 | Hospital equipment(s) | 15 |
| 12 | EDP, WP machines, SATCOM & communication equipment | 15 |
| Sr. No. | Asset Particulars | Life in Years |
|---|---|---|
| 13 | Electrical installations | 15 |
| 14 | Self-propelled vehicles | 10 |
| 15 | Computers, Software | 6.33 |
| 16 | Mine Development Expenses and Evaluation and Exploration# | 20 or life of mine, whichever is lower |
| 17 | Evaluation and Exploration# | 20 or life of mine, whichever is lower |
| 18 | Others not covered above | 15 |
| * | Salvage Value shall be other than 5% for the following assets - a. IT Equipment, software Zero (0) b. Zero or as agreed with the state Government in case of land c. For specialized mining equipment as specified by the Ministry of Corporate affairs Mine Development expenses, Evaluation and Exploration Zero (0) |
|
| @ | Petitioner to submit if the Freehold Land is attached with any conditions for return. If yes submit the conditions and period after which the land is to be returned. In such a case, the land shall be depreciable based on such details. | |
| &&& | To be filled by petitioner, least of lease agreement/mine life/right to use period | |
| $ | List of individual HEMM with the cost of each HEMM be provided separately | |
| # | In a generic sense Mine Development Expenditure is the expenditure incurred to bring the mine n into usable condition after ensuring the economic viability and decision is taken by the Mine Owner to develop the mine. While filling under this head, details to the extent feasible are to be given separately. Evaluation and exploration expenditure is generally the expenditure incurred associated with finding the mineral by carrying out topographical, geological, geochemical, and geophysical studies, exploratory drilling, trenching, sampling, expenditure for activities in relation to evaluation of technical feasibility and commercial viability, acquisition of rights to explore etc. While filling under this head, details to the extent feasible are to be given separately. |
indicative. The Distribution Licensees may propose inclusion of other assets and facilities within this group, citing adequate reasoning and justification.
| Main Group | Suggested bundle | Inclusions |
|---|---|---|
| Boundary assets | Distribution Substation (33/11kV or 22/11kV or 33/22kV or Multi-winding) | Power Transformer, all associated civil structures, land, cables and wiring, relays, switchgear, control panels, lightning arrestors, capacitor banks, station batteries, station transformers, earthing equipment and all other appurtenant apparatus being part of the substation |
| Boundary assets | Consumer Substation (11/0.4kV or 22/0.4 kV or 33/0.4 kV) | Distribution Transformer, all associated civil structures, associated land, relays, cables and wiring, if any, switchgear, control panel, capacitor banks, earthing equipment and other appurtenant apparatus, being part of the substation |
| Voltage Identifiable | Line – 33kV Line – 11kV Line – LT (depending upon voltage rating) |
Overhead Line and associated towers, tower plinth, insulators, gantry and other installed equipment |
| Underground cable and cable ducts, if any Relays, if any, installed and in case of LT lines, including Distribution Pillars / Boxes, tiles, joints, etc. as installed |
||
| Voltage identifiable | Grid Meters | Grid Meters as per voltage of installation |
| Meter housing, boards | ||
| Metering accessories, CT/PT and associated wiring | ||
| Common to Voltage | Others | Maintenance vehicles |
| SCADA, DMS, OMS, Network Planning software and hardware | ||
| Tools and equipment not voltage specific |
requirements manually, till such time they install SAP system with appropriate modules to handle asset base data.
3.1. As shown above, the three main Asset Groups for Wires function shall be the following, along with the basis of allocation of the same over different voltage levels:
3.2. This shall include only the distribution lines, cables and associated meters (not including consumer meters, as they are part of retail supply business). These assets shall be allocated to individual voltages depending upon the voltage rating of the line. These assets are clearly earmarked to specific voltage and exist for distribution of power at that specific voltage or for the purpose of recording energy travelling at that specific voltage, as the case may be.
3.2.1.1. This group shall include asset bundles of “Distribution Substation” and “Consumer Substation” as shown above.
3.2.1.2. Distribution Substations of 33/11kV or 22/11kV or 33/22kV, should be identified and allocated as per secondary side voltage. The Distribution Substation refers to the said bundle of assets as shown above i.e. including associated civil and electrical assets and appurtenant apparatus.
3.2.1.3. Consumer Substations of 11/0.4 kV or 22/0.4 kV or 33/0.4 kV, as the case may be, shall be identified and allocated to LT voltage level. The Consumer Substation refers to the said bundle of assets as shown above i.e. including associated civil structures, electrical assets and other appurtenant apparatus.
3.2.2.1. There are some other assets that exist for the various purposes of electricity network business but cannot be classified as identifiable with any specific voltage. These assets serve and exist for the purpose of network as a whole, rather than being dedicated to any specific voltage level. Some examples could include Vehicles used in network maintenance, in general, or SCADA / DMS / OMS, which exist for the whole of distribution network, or could serve only the HT network common to all voltages of HT. Network planning software such as CymeDist could also be categorized under this block, as such assets are again not dedicated to any specific voltage class.
3.2.2.2. The allocation of these assets to specific voltage levels is proposed to be done in the same proportion as the proportion of voltage identifiable + boundary assets put together bears over different voltages, as obtained from above.
3.3. The above list of assets is just for illustrative purpose and should not be considered an exhaustive list. The Licensees are directed to identify all such
assets that are otherwise utilised only for network (wires) function but have no voltage rating or cannot be identified with any specific voltage or have use across all voltage levels. All such assets are required to be categorized under this Group/Bundle.
| Consumer -driven | Network-driven | |||||
|---|---|---|---|---|---|---|
| GFA value of Common to Business assets, allocated to Wires function (A) | 50% of A | 50% of A | ||||
| EHT | HT | LT | EHT | HT | LT | |
| Allocation to Voltages in ratio of → | % of EHT consumers to total consumers | % of HT consumers to total consumers | % of LT consumers to total consumers | % of EHT line length in Ckt-km to total distribution line length in Ckt-km | % of HT line length in Ckt-km to total distribution line length in Ckt-km | % of LT line length in Ckt-km to total distribution line length in Ckt-km |
*Distribution line length will include Service Lines as well
4.3. As shown above, 50% value of total GFA value of allocated Common to Business assets shall be considered as Consumer-driven and shall be allocated to the different voltage levels of distribution on the basis of the proportion of number of consumers served by the Licensee at each level. Similarly, the balance 50% value of total GFA value of allocated Common to Business assets shall be considered as Network-driven and shall be allocated to the voltage levels of distribution in the proportion of line length (including service lines) in ckt-km at each voltage level.
4.4. The number of consumers to be considered shall include the retail consumers irrespective of whose wires are used to supply such consumers. Further, the number of consumers and line length shall be the closing numbers pertaining to the latest audited financial year.
| Voltage | Network Asset Group | Non-network asset group | Supply | Total | ||
|---|---|---|---|---|---|---|
| Voltage Identifiable | Boundary assets | Common to Network | Common to Business Consumer / Network – 50:50 | |||
| EHT | A 1 | B 1 | C 1 | D 1 | - | A 1 to D 1 |
| HT | A 2 | B 2 | C 2 | D 2 | - | A 2 to D 2 |
| LT | A 3 | B 3 | C 3 | D 3 | - | A 3 to D 3 |
| TOTAL Wire | A | B | C | D | - | A to D |
| Supply | D4 | E1 | D4 +E1 | |||
| Total | AΣ | BΣ | CΣ | DΣ | EΣ | AΣ+EΣ |
| Asset Ratios | EHT | HT | LT | Supply |
|---|---|---|---|---|
| Network Assets (P) | (A 1 +B 1 +C 1 ) / (A+B+C) | (A 2 +B 2 +C 2 ) / (A+B+C) | (A 3 +B 3 +C 3 ) / (A+B+C) | - |
| Non-Network Assets (Q) | (D 1 ) / (D) | (D 2 ) / (D) | (D 3 ) / (D) | - |
| Total Wire (T) | TEHTW = (A1+B1+C1+D1) / (A+B+C+D) | THTW = (A2+B2+C2+D2) / (A+B+C+D) | TLTW = (A3+B3+C3+D3) / (A+B+C+D) | - |
| Total GFA (TGFA) | TEHTT = (A1+B1+C1+D1) / (AΣ+BΣ+CΣ+DΣ+EΣ) | THTT = (A2+B2+C2+D2) / (AΣ+BΣ+CΣ+DΣ+EΣ) | TLTt = (A3+B3+C3+D3) / (AΣ+BΣ+CΣ+DΣ+EΣ) | TST = (D4+E1) / (AΣ+BΣ+CΣ+DΣ+EΣ) |
for Voltage Identifiable Assets and Boundary Assets shall be determined for different voltage levels directly as the historical cost and accumulated depreciation of each individual asset(s) shall be available directly from the Fixed Asset Register of the Licensee. The Licensees shall, preferably make this categorization of assets in their SAP system itself, so that, to this extent, voltage-wise depreciation can be made available directly from the system.
different voltages using the same principles as applied for allocation of RoE.
"Life-cycle Cost Analysis" means the process of assessing the total cost of ownership of an asset over its entire Useful Life, after taking into account all costs of acquiring, owning, maintaining and disposing of such asset."
Name of Applicant: _____
Project Detail/Code: _____
Discounted Factor (%): _____
| Summary | |
|---|---|
| NPV | ₹ - |
| O&M Expense | ₹ - |
| Capital Investment | ₹ - |
| Difference | ₹ - |
| Life Cycle Cost Analysis | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Year | 0 | 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 | 9 | 10 |
| Discount Factor |
| Operation and Maintenance | ₹ | - | NPV | |
|---|---|---|---|---|
| Generation, Transmission and Distribution Businesses | ||||
| Employee Expenses | ₹ | |||
| M&M Expenses | ₹ | |||
| M&C Expenses | ₹ | |||
| Total | ₹ |
| Capital Investment | ₹ | - | NPV | |
|---|---|---|---|---|
| Generation, Transmission and Distribution Businesses | ||||
| Return on Equity Capital | ₹ | |||
| Depreciation | ₹ | |||
| Interest on Loans Capital | ₹ | |||
| Total | ₹ |
% Availability for AC system
$$= \frac{o \times AV_o + p \times AV_p + q \times AV_q + r \times AV_r}{o + p + q + r} \times 100$$
% Availability for HVDC system
$$= \frac{s \times AV_s + t \times AV_t}{s + t} \times 100$$
Where
o = Total number of AC lines;
SIL rating for various voltage levels and conductor configurations is given in Appendix-I. However, for the voltage levels and/or conductor configurations not listed in Appendix-I, appropriate SIL based on technical considerations may be used for availability calculation under intimation to long-term transmission customers/DICs.
For compensated AC line, SIL shall be as certified by the Maharashtra State Power Committee (MSPC) Secretariat considering the compensation on the line.
For shunt compensated line, the reduced value of SIL shall be taken in accordance with the location of the reactor. Similarly, in case of the lines with series compensation, the higher SIL shall be taken as per the percentage of compensation.
| Sl. No. | Line voltage (kV) | Conductor Configuration | SIL (MW) |
|---|---|---|---|
| 1 | 765 | Quad Bersimis | 2250 |
| 2 | 400 | Quad Bersimis | 691 |
| 3 | 400 | Twin Moose | 515 |
| 4 | 400 | Twin AAAC | 425 |
| 5 | 400 | Quad Zebra | 647 |
| 6 | 400 | Quad AAAC | 646 |
| 7 | 400 | Triple Snowbird | 605 |
| 8 | 400 | ACKC(500/26) | 556 |
| 9 | 400 | Twin ACAR | 557 |
| 10 | 220 | Twin Zebra | 175 |
| 11 | 220 | Single Zebra | 132 |
| 12 | 132 | Single Panther | 50 |
| 13 | 66 | Single Dog | 10 |
$$AV_o(\text{Availability of } o \text{ no. of AC lines}) = \frac{\sum_{i=1}^o \frac{W_i(T_i - T_{NAi})}{T_i}}{\sum_{i=1}^o W_i}$$
$$AV_s(\text{Availability of } s \text{ no. of HVDC pole}) = \frac{\sum_{j=1}^s \frac{W_j(T_j - T_{NAj})}{T_j}}{\sum_{j=1}^s W_j}$$
$$AV_q(\text{Availability of } q \text{ no. of ICTs}) = \frac{\sum_{k=1}^q \frac{W_k(T_k - T_{NAk})}{T_k}}{\sum_{k=1}^q W_k}$$
$$AV_r(\text{Availability of } r \text{ no. of SVCs}) = \frac{\left[ \sum_{l=1}^r \frac{0.5 W_{rl}(T_{rl} - T_{NArl})}{T_{rl}} + \sum_{l=1}^r \frac{0.5 W_{cl}(T_{cl} - T_{ACl})}{T_{cl}} \right]}{\left[ \sum_{l=1}^r 0.5 W_{rl} + \sum_{l=1}^r 0.5 W_{cl} \right]}$$
$$AV_p(\text{Availability of } p \text{ no. of Switched Bus reactors}) = \frac{\sum_{m=1}^p \frac{W_m(T_m - T_{NA m})}{T_m}}{\sum_{m=1}^p W_m}$$
$$AV_t(\text{Availability of } t \text{ no. of HVDC Back-to-back Blocks}) = \frac{\sum_{n=1}^t \frac{W_n(T_n - T_{NAn})}{T_n}}{\sum_{n=1}^t W_n}$$
Where $W_i$ = Weightage factor for $i^{\text{th}}$ transmission line
$W_j$ = Weightage factor for $j^{\text{th}}$ HVDC pole
| $W_k$ | = | Weightage factor for $k^{\text{th}}$ ICT |
| $W_{il} & W_{cl}$ | = | Weightage factors for inductive & capacitive operation of $i^{\text{th}}$ SVC |
| $W_m$ | = | Weightage factor for $m^{\text{th}}$ bus reactor |
| $W_n$ | = | Weightage factor for $n^{\text{th}}$ HVDC back to back block. |
| $T_i, T_j, T_k, T_l, T_{cl}, =$ | The total hours of $i^{\text{th}}$ AC line, $j^{\text{th}}$ HVDC pole, $k^{\text{th}}$ ICT, $l^{\text{th}}$ SVC (Inductive Operation), $l^{\text{th}}$ SVC (Capacitive Operation), $m^{\text{th}}$ Switched Bus Reactor & $n^{\text{th}}$ HVDC back-to-back block during the period under consideration (excluding time period for outages not attributable to Transmission Licensee for reasons given in Para 6 of the procedure) | |
| $T_m & T_n$ | ||
| $T_{NAi}, T_{NAj}, T_{NAk} =$ $T_{NAcl}, T_{NAM},$ |
The non-availability hours (excluding the time period for $T_{NAi}$ , outages not attributable to transmission Licensee taken as $T_{NAi}$ , deemed availability as per Para 5 of the procedure) for $i^{\text{th}}$ AC line, $j^{\text{th}}$ HVDC pole, $k^{\text{th}}$ ICT, $l^{\text{th}}$ SVC (Inductive Operation), $l^{\text{th}}$ SVC (Capacitive Operation), $m^{\text{th}}$ Switched Bus Reactor and $n^{\text{th}}$ HVDC back-to-back block. |
Mean Time Between Failure means the arithmetic mean of time between failures of the Generating Unit, excluding planned outages.
Mean Time Between Failures shall be computed as under:
$$\text{Mean Time Between Failure (MTBF) in days} = \frac{\Sigma(Dt_i - Ut_i)}{N}$$
Dt = Start of Downtime, i.e., time at which event of tripping of Generator of Generating or Unit has happened;
Ut = Start of Uptime, i.e., time at which Generator has been restored in the grid after preceding forced outage or failure;
N = Number of failures or forced outages in the year; and
n = Time period, i.e., one year
Provided that planned outages, grid failure, zero scheduling, and reserve shutdown shall not be considered for computation of Mean Time Between Failure:
Provided further that the difference between Start of Downtime (Dt) and Start of Uptime (Ut) shall be calculated in days or fractions thereof:
Provided also that the Generating Company shall submit MTBF for each Generating Station or Unit, as the case may be, for respective year at the time of truing up, duly certified by MSLDC.
Mumbai,
Dated 19th August, 2024.
DR. RAJENDRA G. AMBEKAR,
Secretary,
Maharashtra Electricity Regulatory Commission.