Joint Electricity Regulatory Commission , Government of Mizoram, India

JOINT ELECTRICITY REGULATORY COMMISSION

FOR MANIPUR & MIZORAM

AIZAWL ::: MIZORAM

N O T I F I C A T I O N

Dated Aizawl, the 9^th June, 2014

No. H. 13011/25/10-JERC : In exercise of the powers conferred by sub-section (2) of section 181 read with Section 36, Section 39, Section 40, Section 41, Section 51, Section 61, Section 62, Section 63, Section 64, Section 65 and Section 86 of the Electricity Act, 2003 (36 of 2003) and all other powers enabling on that behalf, the Joint Electricity Regulatory Commission for Manipur and Mizoram (JERC M&M) hereby makes the following Regulations, namely:

CHAPTER 1: PRELIMINARY

1 Short title, extent, applicability and commencement

1.1 These Regulations may be called the Joint Electricity Regulatory Commission for Manipur and Mizoram (Multi Year Tariff) Regulations, 2014.

1.2 These Regulations shall come into force in the state from the date of its publication in the Official Gazettes of Manipur and Mizoram respectively.

1.3 These Regulations shall extend to the whole of the States of Manipur and Mizoram.

1.4 (i) These Regulations shall be applicable for determination of tariff in all cases covered under these Regulations from April 1, 2015 and onwards;

(ii) These Regulations shall be applicable to all existing and future Generating Companies, Transmission Licensees and Distribution Licensees and their successors, if any;

(iii) These Regulations repealed the “Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and conditions for determination of Tariff) Regulations, 2010.”

2 Definitions

(1) “Accounting Statement” means for each financial year, the following statements, namely:

(i) balance sheet, prepared in accordance with the form contained in Part I of Schedule VI to the Companies Act, 1956 as amended from time to time;

(ii) profit and loss account, complying with the requirements contained in Part II of Schedule VI to the Companies Act, 1956;

(iii) cash flow statement, prepared in accordance with the Accounting Standard on Cash Flow Statement (AS-3) of the Institute of Chartered Accountants of India;

(iv) report of the statutory auditors;

(v) cost records prescribed by the Central Government under Section 209(1)(d) of the Companies Act, 1956; together with notes thereto, and such other supporting statements and information as the Commission may direct from time to time:

Provided that if Accounting Statement is not maintained in accordance with the Companies Act, 1956 as above, the accounting system shall be converted in accordance with the Companies Act 1956 for the purpose of filing MYT Petition and the Licensee should start maintaining Accounting Statement mentioned above in accordance with the Companies Act 1956 from the effective date of these Regulations.

Provided that in case of any local authority engaged in the business of distribution of electricity, the Accounting Statement shall mean the items, as mentioned above, prepared and maintained in accordance with the relevant Acts or Statutes as applicable to such local authority:

Provided further that once the Commission notifies the Regulations for submission of Regulatory Accounts, the applications for tariff determination and truing up shall be based on the Regulatory Accounts.

(2) “Act” means the Electricity Act, 2003 (36 of 2003), as amended from time to time;

(3) “Allocation Statement” means for each financial year, a statement in respect of each of the separate businesses of the of the Generating Company or Transmission Licensee or Distribution Licensee, showing the amounts of any revenue, cost, asset, liability, reserve or provision etc, which has been either:

(i) charged from or to each such Other Business together with a description of the basis of that charge; or

(ii) determined by apportionment or allocation between different businesses of the licensee including the Licensed Businesses, together with a description of the basis of the apportionment or allocation:

Provided that for the purpose of this Regulation, the licensed business of the Distribution Licensee for an area of supply would be separated as Distribution Wires and Retail Supply business:

Provided further that such allocation statement in respect of a generating station, owned and/or maintained and/or operated by the distribution licensee, shall be maintained in a manner so as to enable tariff determination, stage- wise, Unit wise and/or for the whole generating station.

(4) “Allotted Transmission Capacity” means the power transfer in MW between the specified point(s) of injection and point(s) of drawal allowed to a long-term customer or a medium-term customer on the intra-State transmission system under the normal circumstances and the expression "allotment of transmission capacity" shall be construed accordingly:

Provided that the Allotted Transmission Capacity to a long-term transmission customer or a medium-term transmission customer shall be sum of the generating capacities allocated to the long-term transmission customer or the medium-term transmission customer from the generating stations and the contracted power, if any;

(5) “Applicant” means a Generating Company or Transmission Licensee or Distribution Licensee who has made an application for determination of Aggregate Revenue Requirement and tariff in accordance with the Act and these Regulations and includes a Generating Company or Transmission Licensee or Distribution Licensee whose tariff is the subject of a review by the Commission either on suo-motu basis or on a petition filed by any interested or affected person or as part of a Truing-up exercise;

(6) “Aggregate Revenue Requirement” means the requirement of the Transmission Licensee or Distribution Licensee for recovery, through tariffs, of allowable expenses and return on equity pertaining to its Licenced Business, in accordance with these Regulations;

(7) "Area of Supply” means the area within which a distribution licensee is authorised by his licence to supply electricity;

(8) “Authority” means Central Electricity Authority referred to in Section 70 of the Act;

(9) “Auxiliary Energy Consumption” in relation to a period, means the quantum of energy consumed by auxiliary equipment of the 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 for the purpose of these Regulations, auxiliary energy consumption for a generating station shall include transformer losses within the generating station:

Provided further that colony consumption of a generating station shall not be included as part of the auxiliary consumption for the purpose of these Regulations.

(10) “Availability” in relation to a thermal generating station for any period means the average of the daily average declared capacities as certified by the State Load Despatch Centre (SLDC) for all the days during that period expressed as a percentage of the installed capacity of the generating station minus normative auxiliary consumption as specified in these Regulations, and shall be computed in accordance with the following formula:

Availability = 10000 x ∑ DC _i/ {N x IC x (100 – AUX _n)}%

i =1

Where,

N = number of days in the given period;

DCi = Average Declared Capacity in MW for the ith day in such period;

IC = Installed Capacity of the generating station in MW;

AUX = Normative Auxiliary Consumption, expressed as a percentage of gross generation;

(11) “Availability” in relation to a transmission system for a given period means the time in hours during that period the transmission system is capable of transmitting electricity at its rated voltage expressed in percentage of total hours in the given period and shall be calculated as provided in Annexure II to these Regulations;

(12) “Bank Rate” shall mean the Bank Rate declared by the Reserve Bank of India from time to time;

(13) “Beneficiary” in relation to a generating station means the person purchasing electricity generated at such a generating station whose tariff is determined under these Regulations;

(14) “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;

(15) “Bulk Power Transmission Agreement” means an executed Agreement that contains the terms and conditions under which a Transmission System User is entitled to access an intra-State transmission system of a Transmission Licensee;

(16) “Business Plan” shall comprise of elements as specified in Regulation 7 of these Regulations;

(17) “change in law” means occurrence of any of the following events:

(i) the enactment, bringing into effect, adoption, promulgation, amendment, modification or repeal of any law; or

(ii) change in interpretation of any law by a competent Court, Tribunal or Indian Governmental Instrumentality, which is the final authority under law for such interpretation; or

(iii) change by any competent statutory authority, in any consent, approval or licence.

(18) “Commission” means the Joint Electricity Regulatory Commission for Manipur and Mizoram constituted by the Government of India vide notification dated 18.01.2005 (under section 83 of the Act);

(19) “Control Period” means the period of three years from April 1, 2015 to March 31, 2018, and for every block of five years thereafter, for submission of forecast in accordance with Chapter-2 of these Regulations;

(20) “Cut-off Date” means 31st March of the year closing after two years of the year of commercial operation of the project, and in case the project is declared under commercial operation in the last quarter of a year, the cut-off date shall be 31^st March of the year closing after three years of the year of commercial operation;

(21) “Day” means the 24 hour period starting at 00:00 hour;

(22) “Date of Commercial Operation” (COD) means:

(i) in relation to a unit or block of a thermal generating station, the date declared by the generating company, after demonstrating the Maximum Continuous Rating (MCR) or the Installed Capacity (IC) through a successful trial run after notice to the beneficiaries, from 00:00 hour of which scheduling process as per the Commission's Order is fully implemented;

(ii) in relation to the generating station, the date of commercial operation means the date of commercial operation of the last unit of the generating station;

(iii) in relation to a unit of a hydro generating station, the date declared by the Generating Company from 00:00 hour of which, after notice to the beneficiaries, scheduling process in accordance with the Commission’s Order is fully implemented, and in relation to the generating station as a whole, the date declared by the Generating Company after demonstrating peaking capability corresponding to installed capacity of the generating station through a successful trial run, after notice to the beneficiaries;

Note:

a. In case the hydro generating station with pondage or storage is not able to demonstrate peaking capability corresponding to the installed capacity for the reasons of insufficient reservoir or pond level, the date of commercial operation of the last unit of the generating station shall be considered as the date of commercial operation of the generating station as a whole, provided that it will be mandatory for such hydro generating station to demonstrate peaking capability equivalent to installed capacity of the generating unit or the generating station as and when such reservoir/pond level is achieved.

b. In case of purely run-of-river hydro generating station, if the unit or the generating station is declared under commercial operation during lean inflows period when the water is not sufficient for such demonstration, it shall be mandatory for such hydro generating station or unit to demonstrate peaking capability equivalent to installed capacity as and when sufficient inflow is available.

(iv) in relation to the transmission system, the date declared by the transmission licensee from 00:00 hour of which an element of the transmission system is in regular service after successful charging and trial operation:

Provided that the date shall be the first day of a calendar month and transmission charge for the element shall be payable and its availability shall be accounted for, from that date:

Provided further that in case an element of the transmission system is ready for regular service but is prevented from providing such service for reasons not attributable to the transmission licensee, its suppliers or contractors, the Commission may approve the date of commercial operation prior to the element coming into regular service.

(23) “Declared Capacity” means

(i) for a thermal generating station, the capability of the generating station to deliver ex-bus electricity in MW declared by such generating station in relation to any period of the day or whole of the day, duly taking into account the availability of fuel:

Provided that in case of a gas turbine generating station or a combined cycle generating station, the generating station shall declare the capacity for units and modules on gas fuel and liquid fuel separately, and these shall be scheduled separately. Total declared capacity and total scheduled generation for the generating station shall be the sum of the declared capacity and scheduled generation for gas fuel and liquid fuel for the purpose of computation of availability and Plant Load Factor, respectively;

(ii) for hydro power generating stations, the ex-bus capacity in MW expected to be available from the generating station for the ith day of the month, which the station can deliver for at least three (3) hours, as certified by the State Load Despatch Centre after the day is over, taking into account the availability of water;

(24) “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;

(25) “Distribution Business” means the business of operating and maintaining a distribution system for supplying electricity in the area of supply of the Distribution Licensee;

(26) “Distribution Wires Business” means the business of operating and maintaining a distribution system for wheeling of electricity in the area of supply of the Distribution Licensee;

(27) “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 tariffs;

(28) “Existing Generating Unit/Station” means a generating unit/station declared under commercial operation prior to the date of effectiveness of these Regulations;

(29) “Existing Project” means a project declared under commercial operation prior to the date of effectiveness of these Regulations;

(30) “Event” means an unscheduled or unplanned occurrence in the intra-State transmission system including faults, incidents and breakdowns;

(31) “Force Majeure Event” means, with respect to any party, any event or circumstance, 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, would include the following events:

(i) acts of God, including but not limited to lightning, storm, action of the elements, earthquakes, flood, torrential rains, drought and natural disaster;

(ii) strikes, lockouts, go-slow, bandh or other industrial disturbances not instigated by any party;

(iii) acts of public enemy, wars (declared or undeclared), blockades, insurrections, riots, revolution, sabotage, vandalism and civil disturbance;

(iv) unavoidable accident, including but not limited to fire, explosion, radioactive contamination and toxic dangerous chemical contamination;

(v) any shutdown or interruption of the grid, which is required or directed by the State or Central Government or by the Commission or the Mizoram State Load Despatch Centre;

(32) “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 a supply to be so given, or (ii) supply of electricity to any Licensee in accordance with the Act and the rules and Regulations made thereunder and, (iii) supply of electricity to any consumer subject to the Regulations made under sub-section (2) of section 42 of the Act;

(33) “Gross Calorific Value” in relation to a thermal generating station means the heat produced in kilocalories by complete combustion of one kilogram of solid fuel or one litre of liquid fuel or one standard cubic metre of gaseous fuel, as the case may be;

(34) “Gross Station Heat Rate” means the heat energy input in kcal required to generate one kWh of electrical energy at generator terminals;

(35) “High Tension” or “HT” means the voltage higher than 440 Volts, but which does not exceed 33000 Volts under normal condition, subject to the percentage variation allowed by the Central Electricity Authority (CEA) from time to time;

(36) “Infirm power” means electricity injected into the grid prior to the commercial operation of a Unit or Block of the generating station;

(37) “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) as approved by the Commission from time to time;

(38) “Maximum Continuous Rating” or 'MCRâ€Ÿ in relation to a unit of the thermal generating station means the maximum continuous output at the generator terminals, guaranteed by the manufacturer at rated parameters, and in relation to a Block of a combined cycle thermal generating station means the maximum continuous output at the generator terminals, guaranteed by the manufacturer with water or steam injection (if applicable) and corrected to 50 Hz grid frequency and specified site conditions;

(39) “Mid-term Review” means a review to be undertaken in accordance with the second proviso to Regulation 4.2 (i) and the proviso to Regulation 7.1 of these Regulations;

(40) “New Generating Unit/Station” means a generating unit/station declared under commercial operation on or after the date of coming into force of these Regulations;

(41) “Normative Annual Plant Availability Factor” or “NAPAF” in relation to a thermal generating station means the availability factor specified in Regulation 47.1 for thermal generating stations and in relation to a hydro generating station means the availability factor specified in Regulation 52.1 for hydro generating stations;

(42) “Non-Tariff Income” means income relating to the regulated business other than from tariff, excluding any income from Other Business and, in case of the Retail Supply Business of a Distribution Licensee, excluding income from wheeling and receipts on account of cross-subsidy surcharge and additional surcharge on charges of wheeling;

(43) “Operation and Maintenance expenses” or “O&M expenses”:

(i) In relation to a Generating Company, the expenditure incurred on operation and maintenance of the project of a Generating Company, or part thereof, and includes the expenditure on manpower, repairs, spares, consumables, insurance and overheads;

(ii) In relation to a Transmission Licensee or Distribution Licensee, the expenditure incurred on operation and maintenance of the system by the Transmission Licensee or Distribution Licensee, and includes the expenditure on manpower, repairs, spares, consumables, insurance and overheads;

(44) “Original Project Cost” means the capital expenditure incurred by the Generating Company or the Transmission Licensee, as the case may be, within the original scope of the project up to the cut-off date as admitted by the Commission;

(45) “Other Business” means any business undertaken by the Generating Company, Transmission Licensee or Distribution Licensee, other than the businesses regulated by the Commission;

(46) “Project” means a generating station or the transmission system, as the case may be, and in case of a hydro generating station includes all components of 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 of the scheme, as apportioned to power generation;

(47) “Rated Voltage” means the manufacturer’s design 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;

(48) “Regulated Business” means any electricity business, which is regulated by the Commission.

(49) “Retail Supply Business” means the business of sale of electricity by a Distribution Licensee to his consumers in accordance with the terms of his licence;

(50) “Run-of-river generating station” means a hydro generating station, which does not have upstream pondage;

(51) “Run-of-river generating station with pondage” means a hydro generating station with sufficient pondage for meeting the diurnal variation of power demand;

(52) “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;

(53) “Scheduled Generation” or “SG” at any time or for any period or time block means schedule of generation in MW ex-bus given by the State Load Dispatch Centre;

(54) “Storage type power station” means a hydro power generating station associated with large storage capacity to enable variation in generation of electricity according to demand;

(55) “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;

(56) “Transmission System User” means a person who has been allotted transmission capacity rights to access an intra-State transmission system pursuant to a Bulk Power Transmission Agreement, except as provided in the Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and Conditions for Open) Regulations, 2010, as applicable and as amended from time to time;

(57) “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 hydro generating station means turbine-generator and its auxiliaries;

(58) “Useful life” in relation to a unit of a generating station, transmission system and distribution system from the date of commercial operation shall mean the following, namely:

(i) Coal/Lignite based thermal generating station: 25 years;

(ii) Gas/Liquid fuel based thermal generating station: 25 years;

(iii) Hydro generating station: 35 years;

(iv) AC and DC sub-station: 25 years;

(v) Transmission line: 35 years;

(vi) Distribution line: 35 years;

(59) “Year” means a financial year (FY);

(60) The words and expressions used in these Regulations and not defined herein but defined in the Act shall have the meaning assigned to them under the Act.

3 Scope of Regulation and extent of application

3.1 The Commission shall determine tariff within the Multi-Year Tariff framework, for all matters for which the Commission has jurisdiction under the Act, including in the following cases:

(i) Supply of electricity by a Generating Company to a Distribution Licensee:

Provided that where the Commission believes that a shortage of supply of electricity exists, it may fix the minimum and maximum ceiling of tariff for sale or purchase of electricity in pursuance of an agreement, entered into between a Generating Company and a Distribution Licensee or between distribution licensees, for a period not exceeding one year to ensure reasonable prices of electricity;

(ii) Intra-State transmission of electricity;

(iii) Intra-State Wheeling of electricity;

(iv) Retail supply of electricity:

Provided that in case of distribution of electricity in the same area by two or more Distribution Licensees, the Commission may, for promoting competition among Distribution Licensees, fix only maximum ceiling of tariff for retail sale of electricity:

Provided further that where the Commission has allowed open access to certain consumers under sub-section (2) of Section 42 of the Act, such consumers, notwithstanding the provisions of clause (d) of sub-section (1) of Section 62 of the Act, may enter into an agreement with any person for supply or purchase of electricity on such terms and conditions (including tariff) as may be agreed upon by them:

Provided further that the Commission, while determining tariff upon an application made to it under this Regulation, shall also have regard to the terms and conditions of tariff as may be specified by the State Commission of such other State and/or the terms and conditions of tariff as may be specified by the Central Commission where any of the Parties to such transaction come under the jurisdiction of such State Commission or of the Central Commission.

3.2 The Commission may also determine the rate at which the Distribution Licensee can supply power to other Distribution Licensees in the State.

3.3 In accordance with the principles laid out in these Regulations, the Commission shall determine separate Aggregate Revenue Requirement (ARR) for:

(i) Distribution Wires Business; and

(ii) Retail Supply Business.

3.4 The Distribution Licensee shall file Petition containing separate details for determination of ARR for Distribution Wires Business and Retail Supply Business, based on the allocation matrix specified in these Regulations:

Provided that once the Commission notifies the Regulations for submission of Regulatory Accounts, the Petition containing separate details for determination of ARR for Distribution Wires Business and Retail Supply Business shall be based on the Regulatory Accounts.

3.5 The ARR determined for the Distribution Wires Business will be the basis for the fixation of the wheeling tariff/charges.

3.6 The ARRs determined for the Distribution Wires Business and Retail Supply Business will be the basis for the fixation of the Retail Supply Tariff for retail sale of electricity.

3.7 The Commission shall also determine 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 Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and Conditions for Open Access) Regulations, 2010 as applicable and as amended through Orders issued by the Commission from time to time.

3.8 The Commission shall also determine additional surcharge on the charges for wheeling under sub-section (4) of Section 42 of the Act, in accordance with the Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and Conditions for Open Access) Regulations, 2010 as applicable and as amended through Orders issued by the Commission from time to time.

3.9 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 pursuant to Section 63 of the Act.

CHAPTER 2: GENERAL PRINCIPLES

4 Multi-Year Tariff framework

4.1 The Commission shall determine the tariff for matters covered under clauses (i), (ii), (iii), and (iv) of Regulation 3.1 above, under a Multi-Year Tariff framework with effect from April 1, 2015:

Provided that the Commission may, either on suo-motu basis or upon application made to it by an applicant, exempt the determination of tariff of a Generating Company or Transmission Licensee or Distribution Licensee under the Multi-Year Tariff framework for such period as may be contained in the Order granting such an exemption.

4.2 The Multi-Year Tariff framework shall be based on the following elements, for determination of Aggregate Revenue Requirement and expected revenue from tariff and charges for Generating Company, Transmission Licensee, Distribution Wires Business and Retail Supply Business:

(i) A detailed Business Plan based on the principles specified in these Regulations, for each year of the Control Period, shall be submitted by the applicant for the Commission's approval:

Provided that the performance parameters, whose trajectories have been specified in the Regulations, shall form the basis of projection of these performance parameters in the Business Plan:

Provided further that a Mid-term Review of the Business Plan may be sought by the Generating Company, Transmission Licensee and Distribution Licensee through an application filed three (3) months prior to the filing of Petition for truing-up for the second year of the Control Period and tariff determination for the fourth year of the Control Period;

(ii) Based on the Business Plan, the applicant shall submit the forecast of Aggregate Revenue Requirement (ARR) for the entire Control Period with year-wise details and expected revenue from existing tariffs for the first year of the Control Period, and the Commission shall determine ARR for the entire Control Period and the tariff for the first year of the Control Period for the Generating Company, Transmission Licensee, Distribution Wires Business and Retail Supply Business;

(iii) Truing up of previous year's expenses and revenue based on Audited Accounts vis-à-vis the approved forecast and categorisation of variation in performance as those caused by factors within the control of the applicant (controllable factors) and those caused by factors beyond the control of the applicant (uncontrollable factors), shall be undertaken by the Commission:

Provided that once the Commission notifies the Regulations for submission of Regulatory Accounts, the applications for tariff determination and truing up shall be based on the Regulatory Accounts;

(iv) The mechanism for pass-through of approved gains or losses on account of uncontrollable factors as specified by the Commission in these Regulations;

(v) The mechanism for sharing of approved gains or losses on account of controllable factors as specified by the Commission in these Regulations;

(vi) Annual determination of tariff for Generating Company, Transmission Licensee, Distribution Wires Business and Retail Supply Business, for each financial year within the Control Period, based on the approved forecast and results of the truing up exercise.

5 Accounting statement and filing under MYT

5.1 The filing under MYT by the Generating Company, Transmission Licensee, and Distribution Licensee, shall be done as per the timelines specified in these Regulations and in compliance with the principles for determination of ARR as specified in these Regulations, in such form as may be prescribed by the Commission from time to time.

5.2 The filing for the Control Period under these Regulations shall be as under:

(i) MYT Petition for the first Control Period shall comprise of:

a. Truing up for FY 2010-11, FY 2011-12 and FY 2012-13 to be carried out under the Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and Conditions for Determination of Tariff) Regulations, 2010;

b. Annual Performance Review for FY 2013-14 to be carried out under the Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and Conditions for Determination of Tariff) Regulations, 2010;

b. Multi-year Aggregate Revenue Requirement for the entire Control Period with year-wise details;

c. Revenue from the sale of power at existing tariffs and charges and projected revenue gap, for the first year (viz., FY 2015-16) of the first Control Period under these Regulations;

d. Application for determination of tariff for FY 2015-16.

(ii) From the first year of the Control Period and onwards, the Petition shall comprise of:

a. Truing Up for FY 2013-14 and Annual Performance Review for FY 2014-15 and to be carried out under the Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and Conditions for Determination of Tariff) Regulations, 2010, and Truing Up for FY 2014-15 and onwards in accordance with these Regulations;

b. Revenue from the sale of power at existing tariffs and charges for the ensuing year;

c. Revenue gap for the ensuing year calculated based on ARR approved in the Tariff Order or MYT Order and truing up for the previous year;

d. Application for determination of tariff for the ensuing year.

(iii) In case of Mid-term Review of Business Plan under Regulation 4.2 (i), the Petition shall comprise of :

a. Truing Up for the previous year;

b. Modification of the ARR for the remaining years of the Control Period, if any, with adequate justification for the same;

c. Revenue from the sale of power at existing tariffs and charges for the ensuing year;

d. Revenue gap for the ensuing year calculated based on ARR approved in the MYT Order and truing up for the previous year;

e. Application for determination of tariff for the ensuing year.

5.3 The Generating Company, Transmission Licensee, and Distribution Licensee for the Distribution Wires Business and Retail Supply Business, shall file separate audited accounting statements with the application for determination of tariff and truing up under Regulation 10:

Provided that in case complete accounting segregation has not been done between the Wires Business and Supply Business, the ARR of the Distribution Licensee shall be apportioned between Wires Business and Retail Supply Business in accordance with the allocation matrix specified in Chapter-6 of these Regulations.

5.4 In case of a vertically integrated business, the Utility shall be required to file separate applications for determination of ARR and tariff for Generation Business, Transmission Business, Wires Business and Retail Supply Business:

Provided that for the distribution business, the Distribution Licensee shall file Petitions as per Regulation 3.4 of these Regulations:

Provided further that in case complete accounting segregation has not been done between the various Businesses, the Utility shall have to do so within one year of notification of these Regulations. Till such time there is a complete segregation of audited accounts between Generation, Transmission, Wheeling and Supply Businesses, the application for determination ARR and tariff and truing up for each Business shall be supported by an Allocation Statement that contains the apportionment of costs and revenues to that Business. The Allocation Statement shall also contain the methodology that has been used for the apportionment.

6 Applicability

6.1 The Multi-Year Tariff framework shall apply to applications made for determination of tariff for a Generating Company, Transmission Licensee, and Distribution Licensee for Distribution Wires Business and Retail Supply Business.

7 Business Plan

7.1 The Generating Company, Transmission licensee, and Distribution Licensee for Distribution Wires Business and Retail Supply Business, shall file a Business Plan for the first Control Period of three (3) financial years from 1stApril 2015 to 31st March 2018 and for every block of five years thereafter, which shall comprise but not be limited to detailed category-wise sales and demand projections, power procurement plan, capital investment plan, financing plan and physical targets, in accordance with guidelines in these Regulations as amended from time to time:

Provided that a mid-term review of the Business Plan/Petition may be sought by the Generating Company, Transmission Licensee and Distribution Licensee through an application filed three (3) months prior to the specified date of filing of Petition for truing up for the first year of the Control Period and tariff determination for the third year of the Control Period.

7.2 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 the Control Period. The Commission shall consider and approve the capital investment plan for which the Generating Company, Transmission Licensee, and Distribution Licensee for the Distribution Wires Business and Retail Supply Business, may be required to provide relevant technical and commercial details.

7.3 The Distribution Licensee shall project the power purchase requirement based on the Merit Order Despatch principles of all Generating Stations considered for power purchase, the Quantum of Renewable Purchase Obligation (RPO) under Joint Electricity Regulatory Commission for the States of Manipur & Mizoram (Renewable Purchase Obligation and its Compliance) Regulations, 2010 as amended from time to time and the target set, if any, for Energy Efficiency (EE) and Demand Side Management (DSM) schemes.

7.4 The Generating Company, Transmission Licensee, and Distribution Licensee for the Distribution Wires Business and Retail Supply Business, shall get the Business Plan approved by the Commission.

8 Multi-Year Tariff Application

8.1 The applicant shall submit the forecast of Aggregate Revenue Requirement for the entire Control Period and tariff proposal for the first year of the Control Period, in such manner, and within such time limit as provided in these Regulations and as per formats provided in Appendix A - for Generation Business, Appendix B – for Transmission Business and Appendix C, D & E – for Distribution Business in respect of Distribution Total Business, Wheeling Business and Retail Supply Business respectively accompanied by such fee payable, as may be specified under Joint Electricity Regulatory Commission for Manipur and Mizoram (Fees, Fines & Charges) Regulations, 2010, as amended from time to time.

8.2 The applicant shall develop the forecast of Aggregate Revenue Requirement using the assumptions relating to the behaviour of individual variables that comprise the Aggregate Revenue Requirement during the Control Period.

8.3 The applicant shall develop the forecast of expected revenue from tariff and charges based on the following:

(i) In the case of a Generating Company, estimates of quantum of electricity to be generated by each Unit/Station for ensuing financial year within the Control Period;

(ii) In the case of a Transmission Licensee, estimates of transmission capacity allocated to Transmission System Users for ensuing financial year within the Control Period;

(iii) In the case of a Distribution Licensee, estimates of quantum of electricity to be supplied to consumers and to be wheeled on behalf of Distribution System Users for ensuing financial year within the Control Period;

(iv) Prevailing tariffs as on the date of making the application.

8.4 Based on the forecast of Aggregate Revenue Requirement and expected revenue from tariff and charges, the Generating Company, Transmission Licensee, and Distribution Licensee for the Distribution Wires Business and Retail Supply Business, shall propose the tariff that would meet the gap, if any, in the Aggregate Revenue Requirement.

8.5 The applicant shall provide full details supporting the forecast, including but not limited to details of past performance, proposed initiatives for achieving efficiency or productivity gains, technical studies, contractual arrangements and/or secondary research, to enable the Commission to assess the reasonableness of the forecast.

8.6 On receipt of application, the Commission shall either:

(i) issue an Order approving the ARR for the entire Control Period and the tariff for the first year of the Control Period, subject to such modifications and conditions as it may specify in the said Order; or

(ii) reject the application for reasons to be recorded in writing, as the Commission may deem appropriate:

Provided that the applicant shall be given a reasonable opportunity of being heard before rejecting his application.

9 Specific trajectory for certain variables

9.1 While approving the Business Plan/MYT Petition, the Commission shall stipulate a trajectory for the variables, which shall include, but not be limited to Operation & Maintenance expenses, target plant load factor and distribution losses:

Provided that the Generating Company, Transmission Licensee and Distribution Licensee may seek a review of the trajectory at the time of mid-term review of Business Plan.

10 Truing Up

10.1 Where the Aggregate Revenue Requirement and expected revenue from tariff and charges of a Generating Company or Transmission Licensee or Distribution Licensee is covered under a Multi-Year Tariff framework, then such Generating Company or Transmission Licensee or Distribution Licensee, as the case may be, shall be subject to truing up of expenses and revenue during the Control Period in accordance with these Regulations.

10.2 The Generating Company or Transmission Licensee or Distribution Licensee shall file an Application for Truing up of the previous year and determination of tariff for the ensuing year, within the time limit specified in these Regulations:

Provided that the Generating Company or Transmission Licensee or Distribution Licensee, as the case may be, shall submit to the Commission information in such form as may be prescribed by the Commission, together with the Audited Accounts, extracts of books of account and such other details as the Commission may require to assess the reasons for and extent of any variation in financial performance from the approved forecast of Aggregate Revenue Requirement and expected revenue from tariff and charges:

10.3 The scope of the truing up shall be a comparison of the performance of the Generating Company or Transmission Licensee or Distribution Licensee with the approved forecast of Aggregate Revenue Requirement and expected revenue from tariff and charges and shall comprise of the following:

(i) a comparison of the audited performance of the applicant for the previous financial year with the approved forecast for such previous financial year, subject to the prudence check including pass-through of impact of uncontrollable factors;

(ii) Review of compliance with directives issued by the Commission from time to time;

(iii) Other relevant details, if any.

10.4 In respect of the expenses incurred by the Generating Company, Transmission Licensee and Distribution Licensee during the year for controllable and uncontrollable parameters, the Commission shall carry out a detailed review of performance of an applicant vis-a-vis the approved forecast as part of the truing up.

10.5 Upon completion of the truing up under Regulation 10.4 above, the Commission shall attribute any variations or expected variations in performance for variables specified under Regulation 11 below, to factors within the control of the applicant (controllable factors) or to factors beyond the control of the applicant (uncontrollable factors):

Provided that any variations or expected variations in performance, for variables other than those specified under Regulation 11.1 below shall be attributed entirely to controllable factors.

10.6 Upon completion of the Truing Up, the Commission shall pass an order recording:

(i) the approved aggregate gain or loss to the Generating Company or Transmission Licensee or Distribution Licensee on account of controllable factors, and the amount of such gains or such losses that may be shared in accordance with Regulation 13 of these Regulations;

(ii) Components of approved cost pertaining to the uncontrollable factors, which were not recovered during the previous year, shall be pass through as per Regulation 12 of these Regulations;

(iii) Tariff determined for the ensuing year.

11 Controllable and uncontrollable factors

11.1 For the purpose of these Regulations, the term “uncontrollable factors” shall comprise of the following factors, which were beyond the control of the applicant, and could not be mitigated by the applicant:

(i) Force Majeure events;

(ii) Change in law, judicial pronouncements and Orders of the Central Government, State Government or Commission;

(iii) Variation in the price of fuel and/ or price of power purchase according to the FPPPA formula approved by the Commission from time to time;

(iv) Variation in the number or mix of consumers or quantities of electricity supplied to consumers:

Provided that where there is more than one Distribution Licensee within the area of supply of the applicant, any variation in the number or mix of consumers or in the quantities of electricity supplied to consumers within the area served by two or more such Distribution Licensees, on account of migration from one Distribution Licensee to another, shall be attributable to controllable factors:

Provided further that if any consumer or category of consumers within the area of supply of the applicant is eligible for open access under sub- section (3) of Section 42 of the Act, then any variation in the number or mix of such consumers or quantities of electricity supplied to such eligible consumers shall be attributable to controllable factors;

(v) Transmission Loss;

(vi) Variation in market interest rates;

(vii) Taxes and Statutory levies;

(viii) Taxes on Income:

(ix) Non Tariff Income;

Provided that where the applicant or any interested or affected party believes, for any variable not specified above, that there is a material variation or expected variation in performance for any financial year on account of uncontrollable factors, such applicant or interested or affected party may apply to the Commission for inclusion of such variable at the Commission’s discretion, under this Regulation for such financial year.

11.2 Some illustrative variations or expected variations in the performance of the applicant, which may be attributed by the Commission to controllable factors include, but are not limited to, the following:

(i) Variations in capitalisation on account of time and/or cost overruns/ efficiencies in the implementation of a capital expenditure project not attributable to an approved change in scope of such project, change in statutory levies or force majeure events;

(ii) Variation in Interest and Finance Charges, Return on Equity, and Depreciation on account of variation in capitalisation, as specified in clause (i) above;

(iii) Variations in technical and commercial losses of Distribution Licensee;

(iv) Variations in performance parameters;

(v) Variations in working capital requirements;

(vi) Failure to meet the standards specified in the Joint Electricity Regulatory Commission for the states of Manipur and Mizoram (Standard of Performance for Distribution and Transmission Licensees) Regulations, 2010, as amended from time to time except where exempted in accordance with those Regulations;

(vii) Variations in labour productivity;

(viii) Variation in operation & maintenance expenses;

(ix) Variation in Wires Availability.

12 Mechanism for pass through of gains or losses on account of uncontrollable factors

12.1 The approved aggregate gain or loss to the Generating Company or Transmission Licensee or Distribution Licensee on account of uncontrollable factors shall be passed through as an adjustment in the tariff of the Generating Company or Transmission Licensee or Distribution Licensee over such period as may be specified in the Order of the Commission passed under these Regulations.

12.2 The Generating Company or Transmission Licensee or Distribution Licensee shall submit such details of the variation between expenses incurred and revenue earned and the figures approved by the Commission, to the Commission, along with the detailed computations and supporting documents as may be required for verification by the Commission.

12.3 Nothing contained in this Regulation 12 shall apply in respect of any gain or loss arising out of variations in the price of fuel and power purchase, which shall be dealt with as specified by the Commission from time to time.

13 Mechanism for sharing of gains or losses on account of controllable factors

13.1 The approved aggregate gain to the Generating Company or Transmission Licensee or Distribution Licensee on account of controllable factors shall be dealt with in the following manner:

(i) One-third of the amount of such gain shall be passed on as a rebate in tariffs over such period as may be stipulated in the Order of the Commission under Regulation 10.6;

(ii) The balance amount, which will amount to two-thirds of such gain, may be utilised at the discretion of the Generating Company or Transmission Licensee or Distribution Licensee.

13.2 The approved aggregate loss to the Generating Company or Transmission Licensee or Distribution Licensee on account of controllable factors shall be dealt with in the following manner:

(i) One-third of the amount of such loss may be passed on as an additional charge in tariffs over such period as may be stipulated in the Order of the Commission under Regulation 10.6; and

(ii) The balance amount of loss, which will amount to two-thirds of such loss, shall be absorbed by the Generating Company or Transmission Licensee or Distribution Licensee.

14 Determination of Tariff

14.1 The proceedings to be held by the Commission for determination of tariff shall be in accordance with the Joint Electricity Regulatory Commission for the States of Manipur & Mizoram (Conduct of Business) Regulations, 2010, as amended from time to time.

14.2 Notwithstanding anything contained in these Regulations, the Commission shall at all times have the authority, either on suo motu basis or on a Petition filed by any interested or affected Party, to determine the tariff, including terms and conditions thereof, of any Generating Company or Transmission Licensee or Distribution Licensee:

Provided that such determination of tariff may be pursuant to an agreement or arrangement or otherwise whether or not previously approved by the Commission and entered into at any time before or after the applicability of these Regulations.

14.3 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:

Provided that the applicant shall provide such information as the Commission may require to satisfy itself that the guidelines issued by the Central Government have been duly followed.

15 Determination of Generation Tariff

15.1 The Commission shall determine the tariff for generation of electricity, in accordance with the terms and conditions contained in Chapter-4 of these Regulations.

15.2 Existing generating station:

Where the Commission has, at any time prior to the date of effectiveness of these Regulations, 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, the tariff for supply of electricity by the Generating Company to the Distribution Licensee shall be in accordance with tariff mentioned in such power purchase agreement or arrangement for such period as may be so approved or adopted by the Commission.

(ii) Where, as on the date of effectiveness of these Regulations, the power purchase agreement or arrangement between a Generating Company and a Distribution Licensee for supply of electricity from an existing generating station has not been approved by the Commission or the tariff contained therein has not been adopted by the Commission or where there is no power purchase agreement or arrangement, the supply of electricity by such Generating Company to such Distribution Licensee after the date of effectiveness of these Regulations shall be in accordance with a power purchase agreement approved by the Commission:

Provided that an application for approval of such power purchase agreement or arrangement shall be made by the Distribution Licensee to the Commission within a period of three (3) 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, as the case may be, until such time as the Commission approves of such power purchase agreement and shall be discontinued forthwith if the Commission rejects, for reasons recorded in writing, such power purchase agreement or arrangement.

15.3 New generating stations:

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 tariff as per power purchase agreement approved by the Commission.

15.4 Own generating stations:

(i) Where the Distribution Licensee also undertakes the business of generation of electricity, the transfer price at which electricity is supplied by the Generation Business of the Distribution Licensee to his Retail Supply Business shall be determined by the Commission.

(ii) The Distribution Licensee shall maintain separate records for the Generation Business and shall maintain an Allocation Statement so as to enable the Commission to clearly identify the direct and indirect costs relating to such business and return on equity accruing to such business:

Provided that once the Commission notifies the Regulations for submission of Regulatory Accounts, the applications for tariff determination and truing up shall be based on the Regulatory Accounts.

15.5 The Distribution Licensee shall submit, along with the separate application for determination of tariff for retail supply of electricity, the information required under Chapter-4 of these Regulations relating to the Generation Business.

16 Determination of Tariff for Transmission, Distribution Wires Business and Retail Supply Business

(i) The Commission shall determine the tariff for Transmission Business, Distribution Wires Business and Retail Supply Business based on an application made by the Licensee in accordance with the procedure contained in these Regulations.

(ii) The Commission shall determine the tariff for:

a. Transmission of electricity, in accordance with the terms and conditions contained in Chapter-5 of these Regulations;

b. Distribution Wires Business, in accordance with the terms and conditions contained in Chapter-6 of these Regulations; and

c. Retail Supply Business, in accordance with the terms and conditions contained in Chapter-7 of these Regulations.

17 Filing Procedure

17.1 The applicant shall provide, based on the approved Business Plan, as part of his application to the Commission, in full details of his calculation of the Aggregate Revenue Requirement and expected revenue from tariff and charges, and thereafter, he shall furnish such further information or particulars or documents as the Commission or the Secretary or any Officer designated for the purpose by the Commission may reasonably require to assess such calculation:

Provided that the application shall be accompanied where relevant, by a detailed tariff revision proposal showing category-wise tariff and how such revision would meet the gap, if any, in Aggregate Revenue Requirement for the respective year of the Control Period:

Provided further that the Commission may specify additional/alternative formats for details to be submitted by the applicant, from time to time, as it may reasonably require for assessing the Aggregate Revenue Requirement and for determining the tariff.

17.2 Upon receipt of a complete application accompanied by all requisite information, particulars and documents in compliance with all the requirements specified in these Regulations, the application shall be deemed to be received and the Commission or the Secretary or the designated Officer shall intimate to the applicant that the application is registered and ready for publication.

17.3 The application made shall be supported by affidavit of the person acquainted with the facts stated in the application.

17.4 The applicant shall, within 7 days after registration of the application, publish a notice of his application in at least two daily newspapers, one in English language and one in vernacular language, having wide circulation in relevant area.

17.5 The suggestions and objections, if any, on the proposal for determination of tariff, may be filed before the Secretary, Joint Electricity Regulatory Commission for Manipur and Mizoram, by any person within 30 days of publication of this notice with a copy to the applicant.

17.6 The applicant shall within 7 days from the date of publication of the notice as aforesaid submit to the Commission on affidavit the details of the notice published and shall also file copies of the newspapers wherein the notice has been published.

17.7 The applicant shall file his comments on the suggestions and objections, if any, received in response within the time limit specified in Joint Electricity Regulatory Commission for the States of Manipur & Mizoram (Conduct of Business) Regulations, 2010, as amended from time to time.

17.8 The applicant shall file his Petition for approval of truing up of previous year and tariff for ensuing financial year by 30^t^h November of the current financial year:

Provided that the MYT Petition for the Control Period shall be filed along-with the Business Plan.

18 Tariff Order

18.1 The Commission shall, within one hundred and twenty (120) days from the date of registration of a complete application and after considering all suggestions and objections received from the public:

(i) issue a Tariff Order accepting the application with such modifications or such conditions as may be specified in that Order; or

(ii) reject the application for reasons to be recorded in writing if such application is not in accordance with the provisions of the Act and the rules and Regulations made thereunder or the provisions of any other law for the time being in force:

Provided that an applicant shall be given a reasonable opportunity of being heard before rejecting his application.

18.2 The tariffs so published shall be in force from the date specified in the said Order and shall, unless amended or revoked, continue to be in force for such period as may be stipulated therein.

19 Adherence to Tariff Order

19.1 No tariff or part of any tariff may be ordinarily amended, more frequently than once in any financial year, except FPPPA based on FPPPA formulae approved by the Commission from time to time.

19.2 The Commission, may, after satisfying itself for reasons to be recorded in writing, allow revision of tariff.

19.3 If any Generating Company or Transmission Licensee or Distribution Licensee 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 of the Reserve Bank of India without prejudice to any other liability incurred by such Generating Company or Transmission Licensee or Distribution Licensee.

19.4 The Transmission Licensee or Distribution Licensee shall submit periodic returns as may be required by the Commission, containing operational and cost data to enable the Commission to monitor the implementation of its Order.

20 Annual determination of tariff

20.1 The Commission shall determine the tariff of a Generating Company or Transmission Licensee or Distribution Licensee covered under a Multi-Year Tariff framework for each financial year during the Control Period, at the commencement of such financial year, having regard to the following:

(i) The approved forecast of Aggregate Revenue Requirement including the incentive available for the Generating Company or Transmission Licensee or Distribution Licensee and expected revenue from tariff and charges for such financial year, including modifications approved at the time of mid- term review, if any; and

(ii) Approved gains and losses to be passed through in tariffs, following the Truing Up of previous year.

21 Subsidy Mechanism

21.1 With effect from the first day of April 2015, 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, notwithstanding any direction which may be given under Section 108 of the Act, pay in advance the amount to compensate the Distribution Licensee/person affected by the grant of subsidy, as a condition for the Licensee or any other person concerned to implement the subsidy provided for by the State Government, in the manner specified in these Regulations:

Provided that no such direction of the State Government shall be operative if the payment is not made in accordance with the provisions contained in these Regulations and the tariff fixed by the Commission shall be applicable from the date of issue of orders by the Commission in this regard.

CHAPTER 3: FINANCIAL PRINCIPLES

22 Debt-equity ratio

22.1 For the purpose of determination of tariff, debt-equity ratio as on the date of commercial operation in case of a new generating station, transmission or distribution line or substation commissioned or capacity expanded after 1.4.2015 shall be 70:30. Where equity employed is more than 30%, the amount of equity for the purpose of tariff shall be limited to 30% and the balance amount shall be considered as loan. Where actual equity employed is less than 30%, the actual equity shall be considered:

Provided that in case of the Generating Company, Transmission Licensee and Distribution Licensee, if any fixed asset is capitalised on account of capital expenditure project prior to April 1, 2015, debt-equity ratio allowed by the Commission for determination of tariff for the period ending March 31, 2015 shall be considered:

Provided further that in case of retirement or replacement of assets, the equity capital approved as mentioned above, shall be reduced to the extent of 30% (or actual equity component based on documentary evidence, if it is lower than 30%) of the original cost of the retired or replaced asset:

Provided further that for the Generating Company or the Transmission Licensee or the Distribution Licensee formed as a result of a transfer scheme, the date of the transfer scheme shall be the effective date for the determination of equity capital.

23 Capital Cost and capital structure

23.1 Capital cost for a project shall include:

(i) the expenditure incurred or projected to be incurred, including interest during construction and financing charges, any gain or loss on account of foreign exchange rate variation on the loan during construction up to the date of commercial operation of the project, as admitted by the Commission after prudence check;

(ii) capitalised initial spares subject to the ceiling rates specified in these Regulations; and

(iii) additional capitalisation determined under Regulation 24:

Provided that the assets forming part of the project but not put to use or not in use, shall be taken out of the capital cost.

23.2 The capital cost admitted by the Commission after prudence check shall form the basis for determination of tariff:

Provided that prudence check may include scrutiny of the reasonableness of the capital expenditure, financing plan, 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.

23.3 The approved Capital Cost shall be considered for determination of tariff and if sufficient justification is provided for any escalation in the Capital Cost, the same may be considered by the Commission subject to the prudence check:

Provided that in case the actual capital cost is lower than the approved capital cost, then the actual capital cost will be considered for determination of tariff of the Generating Company or Transmission Licensee or Distribution Licensee.

23.4 The actual capital expenditure on COD for the original scope of work based on audited accounts of the Company limited to original cost may be considered subject to the prudence check by the Commission.

23.5 Where the power purchase agreement or bulk power transmission agreement provides for a ceiling of capital cost, the capital cost to be considered shall not exceed such ceiling.

23.6 The capital cost may include capitalised initial spares:

(i) upto 2.5% of original capital cost in case of coal based/lignite fired generating stations;

(ii) upto 4.0% of original capital cost in case of gas turbine/combined cycle generating stations;

(iii) upto 1.5% of original capital cost in case of hydro-generating stations; and

(iv) upto 1.5% of original capital cost in case of Transmission Licensee and Distribution Licensee.

23.7 Impact of revaluation of assets shall be permitted during the Control Period, provided it does not result in increase in tariff of Generating Company, Transmission Licensee and Distribution Licensee. Any benefit from such revaluation shall be passed on to persons sharing the capacity charge in case of a Generating Company and to long-term intra-State open access customers of transmission licensee or distribution licensee, or retail supply consumers in case of distribution licensees, at the time of annual truing up.

23.8 Any expenditure on replacement, renovation and modernization or extension of life of old fixed assets, as applicable to Generating Company, Transmission Licensee and Distribution Licensee, shall be considered after writing off the net value of such replaced assets from the original capital cost and will be calculated as follows:

Net Value of Replaced Assets = OCFA – AD – CC;

Where;

OCFA: Original Capital Cost of Replaced Assets;

AD: Accumulated depreciation pertaining to the Replaced Assets;

CC: Total Consumer Contribution pertaining to the Replaced Assets.

24 Additional capitalisation

24.1 The following 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 the prudence check:

(i) Due to Un-discharged liabilities within the original scope of work;

(ii) On works within the original scope of work, deferred for execution;

(iii) To meet award of arbitration and compliance of final and unappealable order or decree of a court arising out of original scope of works;

(iv) On account of change in law;

(v) On procurement of initial spares included in the original project costs subject to the ceiling norm laid down in Regulation 23.6;

(vi) Any additional works/services, which have become necessary for efficient and successful operation of a generating station or a transmission system or a distribution system but not included in the original capital cost:

Provided that original scope of work along with estimates of expenditure shall be submitted as a part of Business Plan:

Provided further that a list of the deferred liabilities and works deferred for execution shall be submitted along with the application for final tariff after the date of commercial operation of the generating Unit/Station or transmission system or distribution system.

Provided further that the assets forming part of the project but not put to use, shall not be considered.

24.2 Impact of additional capitalization on tariff, as the case may be, shall be considered during Truing Up of each financial year of the Control Period.

25 Consumer contribution, Deposit Work and Grant

25.1 The following nature of work carried out by the Transmission Licensee and Distribution Licensee shall be classified under this category:

(i) Works after obtaining a part or all of the funds from the users in the context of deposit works;

(ii) Capital works undertaken by utilising grants received from the State and

Central Governments, including funds under RGGVY, APDRP, etc;

(iii) Any other grant of similar nature and such amount received without any obligation to return the same and with no interest costs attached to such subvention.

26 Return on Equity

26.1 Return on equity shall be computed on the paid up equity capital determined in accordance with Regulation 22 relatable to the Generating Company or Transmission Licensee or Distribution Licensee as the case may be and shall be allowed at the rate of 15.5% for Generating Companies, including hydro generation stations above 25 MW, Transmission Licensee, and Distribution Licensee:

Provided that in case of generating projects commissioned on or after 1st April, 2015, an additional return of 0.5% shall be allowed if such projects are completed within the timeline specified in Annexure-III:

Provided further that the additional return of 0.5% shall not be admissible if the project is not completed within the timeline specified above for reasons whatsoever:

Provided that for Generating Company, Transmission Licensee and Distribution Licensee, Return on Equity shall be allowed on the amount of allowed equity capital for the assets put to use at the commencement of each financial year and on 50% of equity capital portion of the allowable capital cost for the investments put to use during the financial year:

Provided further that for the purpose of truing up for the Generating Company, Transmission Licensee and Distribution Licensee, return on equity shall be allowed on pro-rata basis based on documentary evidence provided for the assets put to use during the year.

26.2 The premium raised by the Generating Company or the Transmission Licensee or Distribution Licensee while issuing share capital and investment of internal resources created out of free reserve, if any, shall also be reckoned as paid up capital for the purpose of computing return on equity, provided such premium amount and internal resources are actually utilized for meeting capital expenditure.

26.3 Equity invested in foreign currency shall be converted to rupee currency based on the exchange rate prevailing on the date(s) it is subscribed.

27 Interest and finance charges on loan capital

27.1 The loans arrived at in the manner indicated in Regulation 22 shall be considered as gross normative loan for calculation of interest on loan:

Provided that interest and finance charges on capital works in progress shall be excluded:

Provided further that in case of retirement or replacement of assets, the loan capital approved as mentioned above, shall be reduced to the extent of outstanding loan component of the original cost of the retired or replaced assets, based on documentary evidence.

27.2 The normative loan outstanding as on April 1, 2015, shall be worked out by deducting the cumulative repayment as admitted by the Commission up to March 31, 2015 from the gross normative loan.

27.3 The repayment for the year during the tariff period from FY 2015-16 to FY2017-18 and every block of five years thereafter shall be deemed to be equal to the depreciation allowed for that year.

27.4 Notwithstanding any moratorium period availed by the Generating Company or the Transmission Licensee or the Distribution Licensee, as the case may be, the repayment of loan shall be considered from the first year of commercial operation of the project and shall be equal to the annual depreciation allowed.

27.5 The rate of interest shall be the weighted average rate of interest calculated on the basis of the actual loan portfolio at the beginning of each year applicable to the Generating Company or the Transmission Licensee or the Distribution Licensee:

Provided that if there is no actual loan for a particular year but normative loan is still outstanding, the last available weighted average rate of interest shall be considered:

Provided further that if the Generating Company or the Transmission Licensee or the Distribution Licensee, as the case may be, does not have actual loan, then the weighted average rate of interest of the Generating Company or the Transmission Licensee or the Distribution Licensee as a whole shall be considered.

27.6 The interest on loan shall be calculated on the normative average loan of the year by applying the weighted average rate of interest.

27.7 The above interest computation shall exclude interest on loan amount, normative or otherwise, to the extent of capital cost funded by Consumer Contribution, Grants or Deposit Works carried out by Transmission Licensee or Distribution Licensee or Generating Company, as the case may be.

27.8 The Generating Company or the Transmission Licensee or the Distribution Licensee, 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 the Generating Company or the Transmission Licensee or the Distribution Licensee, as the case may be, in the ratio of 2:1.

27.9 Interest shall be allowed on the amount held as security deposit held in cash from Transmission System Users, Distribution System Users and Retail consumers at the Bank Rate as on 1stApril of the financial year in which the Petition is filed.

28 Depreciation

28.1 The value base for the purpose of depreciation shall be the Capital Cost of the asset admitted by the Commission.

28.2 The Generation Company or Transmission Licensee or Distribution Licensee shall be permitted to recover depreciation on the value of fixed assets used in their respective Business computed in the following manner:

(i) The approved original cost of the project/fixed assets shall be the value base for calculation of depreciation;

(ii) Depreciation shall be computed annually based on the straight line method at the rates specified in the Annexure I to these Regulations:

Provided that the remaining depreciable value as on 31st March of the year closing after a period of 12 years from date of commercial operation shall be spread over the balance useful life of the assets:

Provided further that for a Generating Company or a Transmission Licensee or a Distribution Licensee formed as a result of a Transfer Scheme, the depreciation on assets transferred under the Transfer Scheme shall be charged as per rates specified in these Regulations for a period of 12 years from the date of the Transfer Scheme, and thereafter depreciation will be spread over the balance useful life of the assets:

Provided further that the depreciation already charged after the date of the

Transfer Scheme, shall not be restated:

Provided further that the Generating Company or Transmission Licensee or Distribution Licensee, shall submit all such details or documentary evidence, as may be required under these Regulations and as stipulated by the Commission, from time to time, to substantiate the above claims;

(iii) The salvage value of the asset shall be considered at 10 per cent of the allowable capital cost and depreciation shall be allowed upto a maximum of 90 per cent of the allowable capital cost of the asset:

Provided that in the case of hydro generating station, the salvage value shall be as provided in the agreement, if any, signed by the developers with the State Government.

28.3 Land other than the land held under lease and the land for reservoir in case of hydro generating station shall not be a depreciable asset and its cost shall be excluded from the capital cost while computing depreciable value of the asset.

28.4 In case of the existing projects, the balance depreciable value as on April 1, 2015, shall be worked out by deducting the cumulative depreciation as admitted by the Commission upto March 31, 2015, from the gross value of the assets.

28.5 In case of projected commercial operation of the asset for part of the year, depreciation shall be calculated based on the average of opening and closing value of asset, approved by the Commission:

Provided that depreciation will be re-calculated during truing-up for assets capitalised at the time of Truing Up of each year of the Control Period, based on documentary evidence of asset capitalised by the applicant, subject to the prudence check of the Commission, such that the depreciation is calculated proportionately from the date of capitalisation.

29 Interest on Working Capital

29.1 Generation:

(i) In case of coal based/oil-based/lignite-fired generating stations, working capital shall cover:

(a) Cost of coal or lignite for one (1) month for pit-head generating stations and one and a half (1½) months for non-pit-head generating stations, corresponding to target availability; plus

(b) Cost of oil for one (1) month corresponding to target availability; plus

(d) Operation and Maintenance expenses for one (1) month; plus

(e) Maintenance spares at one (1) per cent of the historical cost escalated at 6% from the date of commercial operation; plus

(f) Receivables for sale of electricity equivalent to one (1) month of the sum of annual fixed charges and energy charges calculated on target availability:

Provided that in case of own generating stations, 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 these Regulations.

(ii) In case of Gas Turbine/Combined Cycle generating stations, working capital shall cover:

(a) Fuel cost for one (1) month corresponding to target availability factor, duly taking into account the mode of operation of the generating station on gas fuel and /or liquid fuel; plus

(b) Liquid fuel stock for fifteen (15) days corresponding to target availability; plus

(d) Maintenance spares at one (1) per cent of the historical cost escalated at 6% from the date of commercial operation; plus

(e) Receivables equivalent to one (1) month of capacity charge and energy charge for sale of electricity equivalent calculated on normative plant availability factor, duly taking into account mode of operation of the generating station on gas fuel and liquid fuel:

(iii) In case of hydro power generating stations, working capital shall cover:

(a) Operation and maintenance expenses for one (1) month;

(b) Maintenance spares at one (1) per cent of the historical cost escalated at 6% from the date of commercial operation; and

(iv) Interest on working capital shall be allowed at a rate equal to the State Bank Advance Rate (SBAR) as on 1stApril of the financial year in which the Petition is filed.

29.2 Transmission:

(i) The Transmission Licensee shall be allowed interest on the estimated level of working capital for the financial year, computed as follows:

(a) Operation and maintenance expenses for one month; plus

(b) Maintenance spares at one (1) per cent of the historical cost escalated at 6% from the date of commercial operation; plus

(d) Amount, if any, held as security deposits except the security deposits held in the form of Bank Guarantee from Transmission System Users.

(ii) Interest shall be allowed at a rate equal to the State Bank Advance Rate (SBAR) as on 1stApril of the financial year in which the Petition is filed.

29.3 Distribution Wires Business

(i) The Distribution Licensee shall be allowed interest on the estimated level of working capital for the Distribution Wires Business for the financial year, computed as follows:

(a) Operation and maintenance expenses for one month; plus

(b) Maintenance spares at one (1) per cent of the historical cost escalated at 6% from the date of commercial operation; plus

(c) Receivables equivalent to one (1) month of the expected revenue from charges for use of Distribution Wires at the prevailing tariffs; minus

(d) Amount, if any, held as security deposits under clause (b) of sub- section (1) of Section 47 of the Act from Distribution System Users except the security deposits held in the form of Bank Guarantees.

(ii) Interest shall be allowed at a rate equal to the State Bank Advance Rate (SBAR) as on 1stApril of the financial year in which the Petition is filed.

29.4 Retail Supply of Electricity

(i) The Distribution Licensee shall be allowed interest on the estimated level of working capital for the financial year, computed as follows:

(a) Operation and maintenance expenses for one month; plus

(b) Maintenance spares at one (1) per cent of the historical cost escalated at 6% from the date of commercial operation; plus

(c) Receivables equivalent to one (1) month of the expected revenue from sale of electricity at the prevailing tariffs; minus

(d) Amount held as security deposits under clause (a) and clause (b) of sub-section (1) of Section 47 of the Act from consumers except the security deposits held in the form of Bank Guarantees;

(ii) Interest shall be allowed at a rate equal to the State Bank Advance Rate (SBAR) as on 1stApril of the financial year in which the Petition is filed.

30 Tax on income

30.1 The Commission in its MYT Order shall provisionally approve Income Tax payable for each year of the Control Period, if any, based on the actual income tax paid as per latest Audited Accounts available for the applicant, subject to prudence check.

30.2 Variation between Income Tax actually paid and approved, if any, on the income stream of the regulated business of Generating Companies, Transmission Licensees and Distribution Licensees shall be reimbursed to/recovered from the Generating Companies, Transmission Licensees and Distribution Licensees, based on the documentary evidence submitted at the time of truing up of each year of the Control Period, subject to prudence check.

30.3 Under-recovery or over-recovery of any amount from the beneficiaries or the consumers on account of such tax having been passed on to them shall be adjusted every year on the basis of income-tax assessment under the Income- Tax Act, 1961, as certified by the statutory auditors. The Generating Company, or the Transmission Licensee or Distribution Licensee, as the case may be, may include this variation in its truing up Petition:

Provided that tax on any income stream other than the core business shall not be a pass through component in tariff and tax on such other income shall be borne by the Generating Company or Transmission Licensee or the Distribution Licensee, as the case may be.

31 Rebate

31.1 For payment of bills of generation tariff or transmission charges or wheeling charges through Letter of Credit or otherwise, within 7 days of presentation of bills, by the Generating Company or the Transmission Licensee or the Distribution Licensee, as the case may be, a rebate of 2% on billed amount, excluding the taxes, cess, duties, etc., shall be allowed. Where payments are made subsequently through opening of Letter of Credit or otherwise, but within a period of one month of presentation of bills by the Generating Company or the Transmission Licensee or the Distribution Licensee, as the case may be, a rebate of 1% on billed amount, excluding the taxes, cess, duties, etc., shall be allowed or otherwise as per the rebate scheme offered by the Generating Company or the Transmission Licensee or the Distribution Licensee and approved by the Commission.

32 Delayed Payment Surcharge

32.1 In case the payment of bills of generation tariff or transmission charges or wheeling charges by the beneficiary or beneficiaries is delayed beyond a period of 30 days from the date of billing, late payment surcharge at the rate of 1.25% per month on billed amount shall be levied for the period of delay by the Generating Company or the Transmission Licensee or the Distribution Licensee, as the case may be or otherwise as per the scheme mutually agreed by the interest party(s) and dully approved by the Commission.

33 Foreign Exchange Rate Variation

33.1 The Generating Company or the Transmission Licensee or the Distribution Licensee, as the case may be, 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 full, at the discretion of the Generating Company or the Transmission Licensee or the Distribution Licensee.

33.2 Every Generating Company and Transmission Licensee and Distribution Licensee shall recover the cost of hedging of foreign exchange rate variation corresponding to the normative foreign debt, in the relevant year on year-to- year basis as expense in the period in which it arises and extra rupee liability corresponding to such foreign exchange rate variation shall not be allowed against the hedged foreign debt.

33.3 To the extent the Generating Company or the Transmission Licensee or the Distribution Licensee is not able to hedge the foreign exchange exposure, the extra rupee liability towards interest payment and loan repayment corresponding to the normative foreign currency loan in the relevant year shall be permissible provided it is not attributable to the Generating Company or the Transmission Licensee or the Distribution Licensee or its suppliers or contractors.

34 Recovery of cost of hedging Foreign Exchange Rate Variation

34.1 Every Generating Company and the Transmission Licensee and the Distribution Licensee shall recover the cost of hedging and foreign exchange rate variation on year-to-year basis as income or expense in the period in which it arises.

CHAPTER 4: GENERATION

35 Applicability

35.1 The Regulations specified in this Chapter shall apply for determining the tariff for supply of electricity to a Distribution Licensee from conventional sources of generation and hydro generation stations of capacity more than 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 as stipulated in the relevant Regulations/Orders of the Commission.

35.2 The Commission shall be guided by the Regulations contained in this Chapter in determining the tariff for supply of electricity by a Generating Company to a Distribution Licensee in the following cases:

(i) where such tariff is pursuant to a power purchase agreement or arrangement entered into subsequent to the date of effectiveness of these Regulations; or

(ii) where such tariff is pursuant to a power purchase agreement or arrangement entered into prior to the date of effectiveness of these Regulations and either the Commission has not previously approved such agreement/arrangement or the agreement/arrangement envisages that the tariff shall be based on the JERC Tariff Regulations; or

(iii) where the Distribution Licensee is engaged in the business of generation of electricity, in determining the transfer price at which electricity is supplied by the Generation Business of the Distribution Licensee to its Retail Supply Business:

Provided that the Commission may deviate from the norms contained in this Chapter or specify alternative norms for particular cases, where it so deems appropriate, having regard to the circumstances of the case:

Provided further that the reasons for such deviation(s) shall be recorded in writing.

35.3 Notwithstanding anything contained in this Chapter 4, 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.

36 Petition for determination of generation tariff

36.1 A Generating Company is required to file a Petition for determination of tariff for supply of electricity to Distribution Licensees in accordance with the provisions of Chapter 2 of these Regulations.

36.2 Tariff in respect of a Generating Station under these Regulations may be determined Stage-wise, Unit-wise or for the whole Generating Station. The terms and conditions for determination of tariff for Generating Stations specified in this Part shall apply in like manner to Stages or Units, as the case may be, as to Generating Stations.

36.3 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 application for determination of tariff.

36.4 A Generating Company may file a Petition for determination of provisional tariff in advance of the anticipated Date of Commercial Operation of the Unit or Stage or Generating Station as a whole, as the case may be, based on the capital expenditure actually incurred up to the date of making the Petition or a date prior to making of the Petition, duly audited and certified by the statutory auditors and the provisional tariff shall be charged from the date of commercial operation of such Unit or Stage or Generating Station, as the case may be.

36.5 A Generating Company shall file a fresh Petition in accordance with these Regulations, for determination of final tariff based on actual capital expenditure incurred up to the date of commercial operation of the Generating Station duly certified by the statutory auditors based on Annual Audited Accounts.

36.6 Any difference in provisional tariff and the final tariff determined by the Commission and not attributable to the Generating Company may be adjusted at the time of determination of final tariff for the following year as directed by the Commission.

36.7 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.

37 Components of Tariff

37.1 Components of Tariff for thermal generation

(i) Tariff for sale of electricity from a thermal power generating station shall comprise of two parts, namely, the recovery of annual capacity (fixed) charges and energy (variable) charges (for recovery of primary and secondary fuel cost) to be worked out in the manner provided hereinafter.

(ii) The fixed cost of a generating station eligible for recovery through annual capacity charges shall consist of:

(a) Return on equity as may be allowed

(b) Interest on Loan Capital;

(d) Interest on Working Capital;

(e) Depreciation, including Advance Against Depreciation as may be allowed.

(f) Taxes on Income

(g) Cost of secondary fuel oil (for coal based and lignite fired generating stations only)

(iii) The energy charges shall cover primary fuel charges

(iv) The annual capacity charges recoverable shall be worked out by deducting other income from the total annual expenses.

37.2 Components of tariff for hydro power generation:

(i) Tariff for supply of electricity from a hydro power generating station shall comprise of two parts, namely, annual capacity charges and energy charges to be in the manner provided hereinafter.

(ii) The fixed cost of a generating station eligible for recovery through annual capacity charges shall consist of:

(a) Return on equity as may be allowed

(b) Interest on Loan Capital;

(d) Interest on Working Capital;

(e) Depreciation as may be allowed by the Commission.

(f) Taxes on Income

(ii) The annual capacity charges recoverable shall be worked out by deducting other income from the total expenses.

38 Annual Fixed Charges

38.1 Components of Annual Fixed charges:

(i) The Annual Fixed Charges shall comprise of the following elements:

(a) Depreciation;

(b) Operation & Maintenance Expenses; (c) Return on Equity;

(d) Interest and Finance Charges on Loan Capital;

(e) Interest on Working Capital; minus:

(f) Non-Tariff Income:

Provided that Depreciation, Interest and finance charges on Loan Capital, Interest on Working Capital and Return on Equity for Thermal and Hydro Generating Stations shall be allowed in accordance with the provisions specified in Chapter 3 of these Regulations.

39 Capital cost

Capital Cost for a project shall include:

(i) The expenditure incurred including interest during construction and financing charges, as admitted by the Commission after prudence check;

(ii) Capitalised initial spares subject to the ceiling rates; and

(iii) Additional capital expenditure determined under these Regulations:

Provided that the cost of the common assets forming part of the project, should be considered based on suitable allocation, duly audited and certified by the statutory auditors, and such allocated cost shall form part of the capital cost:

Provided further that the assets forming part of the project, but not in use, shall be taken out of the capital cost.

39.2 The Capital Cost admitted by the Commission after prudence check shall form the basis for determination of tariff:

Provided that where the Power Purchase Agreement entered into between the Generating Company and the Distribution Licensee provides a ceiling of actual expenditure, the original cost of project shall not exceed such ceiling for the purpose of these Regulations:

Provided further that prudence check may include scrutiny of the reasonableness of the capital expenditure, financing plan, 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 in case of the existing Generating Stations, the capital cost of the project as admitted by the Commission prior to the date of effectiveness of these Regulations and the additional capital expenditure projected to be incurred and capitalised for the respective year of the Control Period, as may be admitted by the Commission, shall form the basis for determination of tariff:

Provided further that in case the site of a Hydro Generating Station is awarded to a developer (not being a State controlled or owned company) by the State Government by following a transparent process of bidding or otherwise, any expenditure incurred or committed to be incurred including the premium payable to the State Government by the project developer for getting the project site allotted, shall not be included in the capital cost.

39.3 Additional Capitalisation: The following capital expenditure within the original scope of work actually incurred after the date of commercial operation and up to the cut off date may be allowed by the Commission for inclusion in the original cost of project, subject to prudence check:

(i) Deferred/un-discharged liabilities;

(ii) Works deferred for execution;

(iii) Procurement of initial capital spares in the original scope of work, subject to ceiling specified in Regulation 23.6;

(iv) Liabilities to meet award of arbitration or for compliance of the order or decree of a court; and

(v) On account of change in law.

Provided that the details of works included in the original scope of work along with estimates of expenditure, un-discharged liabilities and the works deferred for execution shall be submitted along with the application for determination of tariff.

39.4 The capital expenditure of the following nature actually incurred after the cut- off date may be allowed by the Commission for inclusion in the original cost of project, subject to prudence check:

(i) Liabilities to meet award of arbitration and for compliance of an un- appealable order or decree of a court;

(ii) On account of change in law;

(iii) Deferred works relating to ash pond or ash handling system in the original scope of work; and

(iv) In case of hydro generating station, any expenditure which has become necessary on account of damage caused by natural calamities (but not due to flooding of power house attributable to the negligence of the Generating Company) including due to geological reasons after adjusting for proceeds from any insurance scheme, and expenditure incurred due to any additional work, which has become necessary for successful and efficient plant operation.

39.5 Any expenditure on other items/assets, not being generating assets, including, but not limited to, normal tools and tackles, personal computers, furniture, air- conditioners, voltage stabilizers, refrigerators, fans, coolers, heat-convectors, etc., bought after the cut-off date may be capitalised, with the prior approval of the Commission.

39.6 Renovation & Modernisation:

(i) The Generating Company, for meeting the expenditure on Renovation and Modernization for the purpose of extension of life beyond the useful life of the generating station or a unit thereof, shall file an application before the Commission for approval of the proposal 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 information considered to be relevant by the Generating Company:

Provided that in case of coal-based/lignite fired thermal generating station, the Generating Company, may, at its discretion, avail of a “special allowance” in accordance with the norms specified in Clause (iv), as compensation for meeting the requirement of expenses including Renovation and Modernisation beyond the useful life of the generating station or a unit thereof, and in such an event, revision of the capital cost shall not be considered and the applicable operational norms shall not be relaxed but the special allowance shall be included in the Annual Fixed Cost:

Provided also that such option shall not be available for a generating station or Unit for which Renovation and Modernization has been undertaken and the expenditure has been admitted by the Commission before the date of effectiveness of these Regulations.

(ii) Where the Generating Company files an application for approval of its proposal for Renovation and Modernisation, the approval shall be granted after due 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.

(iii) Any expenditure incurred or projected to be incurred and admitted by the Commission after prudence check based on the estimates of Renovation and Modernization expenditure and life extension, and after deducting the accumulated depreciation and corresponding equity contribution, already recovered from the original project cost, shall be considered for determination of tariff.

(iv) A Generating Company, on opting for the alternative in the first proviso to clause (i) of this Regulation, for a coal-based/lignite fired thermal generating station, shall be allowed special allowance @ Rs. 5 lakh/MW/year in FY 2015-16 and thereafter escalated @ 5.72 % every year during the Control Period, Unit-wise from the next financial year from the respective date of the completion of useful life with reference to the date of commercial operation of the respective unit of generating station:

Provided that in respect of a Unit in commercial operation for more than 25 years as on 1.4.2015, this allowance shall be admissible from FY 2015-16.

40 Sale of Infirm Power

40.1 The tariff for sale of infirm power from a thermal generating station to the Distribution Licensee shall be equivalent to the actual fuel cost, including the secondary fuel cost, as the case may be, incurred during that period subject to prudence check:

Provided that any revenue other than the recovery of fuel cost earned by the Generating Company from sale of infirm power shall be used for reduction in capital cost and shall not be treated as revenue.

41. Non-Tariff Income

41.1 The amount of Non-Tariff Income relating to the Generation Business as approved by the Commission shall be deducted from the Annual Fixed Cost in determining the Annual Fixed Charge of the Generation Company:

Provided that the Generation 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 from time to time.

The indicative list of various heads to be considered for Non-Tariff Income shall be as under:

(i) Income from rent of land or buildings;

(ii) Income from sale of scrap;

(iii) Income from statutory investments;

(iv) Income from sale of Ash/rejected coal;

(v) Interest on delayed or deferred payment on bills;

(vi) Interest on advances to suppliers/contractors;

(vii) Rental from staff quarters;

(viii) Rental from contractors;

(ix) Income from hire charges from contactors and others;

(x) Income from advertisements, etc.:

(xi) Other income:- All Income other than income from sale of energy and net U I charges gained (after introduction of intra-state ABT) shall be grouped as other income. UI penalties shall not be netted off from other income. The UI penalties shall be borne by the generating company.

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.

42. SLDC and Connectivity Charges

42.1 SLDC and Connectivity charges are determined by the Commission and payable by the generating companies shall be considered as expenses; SLDC and Transmission charges paid for the energy sold outside the state shall not be considered as expenses for determining generation tariff.

43. Unscheduled Interchange (UI) charges (Intra State ABT scenario)

43.1 Variation between actual generation or actual drawal and scheduled generation or scheduled drawal shall be accounted for through Unscheduled Interchange (UI) Charges. UI for a generating station shall be equal to its actual generation minus its scheduled generation. UI shall be worked out for each 15 minutes time block. Charges for all UI transactions shall be based on average frequency of the time block and rates as specified by CERC from time to time.

43.2 UI charges for intra-state transactions will arise after intra-state ABT is notified by the Commission and becomes effective.

44. Demonstration of declared capacity

44.1 The Generating Company may be required to demonstrate the declared capacity of its generating station as and when asked by State Load Despatch Centre. In the event of the Generating Company failing to demonstrate the declared capacity, the capacity charges due to the Generating Company shall be reduced as a measure of penalty.

44.2 The quantum of penalty for the first miss-declaration for any duration/block in a day shall be the charges corresponding to two days fixed charges. 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.

44.3 The operating logbooks of the generating station shall be available for review by the State Load Despatch Centre. These books shall keep record of machine operation and maintenance.

45. Billing and Payment of Charges

45.1 The Billing and Payment of Annual Fixed Charges, Energy Charges and Fuel Surcharge Adjustments shall be done on a monthly basis subject to adjustments at the end of the year.

45.2 The Billing and Payment of Capacity Charges and Energy Charges for Hydro Generating Stations shall be done on a monthly basis.

46. Reactive Energy Charges

46.1 A generating station shall inject/absorb the reactive energy into the grid as per the directions of State Load Despatch Centre. Such injection/absorption may be undertaken on the basis of machine capability and in accordance with the directions issued by SLDC. Reactive energy exchange, only if made as per the directions of State Load Despatch Centre, for the applicable duration (injection or absorption) shall be compensated to the generating station at the rate of 10.00 paise/kVArh for FY 2015-16 escalated at 0.5 paise/kVArh annually in subsequent years of the Control Period, unless otherwise revised by Commission.

47. Norms of operation for Thermal Generating Stations

47.1 Recovery of capacity charge, energy charge and incentive by the generating company shall be based on the achievement of the operational norms. The norms of operation as given below shall apply to thermal generating stations:

(i) Normative Annual Plant Availability Factor (NAPAF)

(a) All Thermal generating station 85 %

(b) Lignite fired generating station using

Circulatory Fluidized Bed Combustion (CFBC) Technology

(1) First three years from COD 75 %

(2) From next year after completion of 3 years of COD 80 %

(ii) Gross Station Heat Rate

(a) Coal-based thermal power generating stations,

During stabilization period 2600 kCal / kWh

Subsequent period 2500 kCal / kWh

(b) Gas Turbine / Combined Cycle generating stations

Open cycle 2830 kCal / kWh

Combined cycle 1950 kCal / kWh

(iii) Secondary fuel oil consumption

(a) Coal-based generating stations - 1.0 ml / kwh

(b) Lignite fired generating stations - 2.0 ml/kWh

(iv) Auxiliary Energy Consumption

(a) Coal-based generating stations with natural draft cooling tower or without cooling tower:

(1) 200 MW series - 8.5%

(2) 500 MW and above

Steam driven boiler feed pumps - 6.0%

Electricity driven boiler feed pumps - 8.5%

Provided that for thermal generating stations with induced draft cooling towers, the norm shall be further increased by - 0.5%

(b) Gas turbine / combined cycle generating stations:

(i) Combined cycle - 3.0%

(ii) Open cycle - 1.0%

(d) All generating stations with 200 MW sets and above:

The auxiliary energy consumption norms shall be 0.5% more than the auxiliary consumption norms of coal-based generating stations as in (b) (i) above

For lignite fired stations using CFBC technology the auxiliary consumption norm shall be 1.5% more than the auxiliary consumption norms of coal based generating stations as in (iv) (a) above.

48. Operation & Maintenance Expenses

48.1 Operation and Maintenance Expenses (O&M Expenses) shall mean the total of all expenditure under the following heads:-

(i) Employee Cost;

(ii) Repairs and Maintenance; and

(iii) Administration and General Expenses.

48.2 The generating company shall prepare a budget for Operation and Maintenance Expenses indicating for each head of account actual expenditure of the last year, estimate for the current year and projection for the next year and submit it to the Commission along with the tariff petition.

(i) The generating company shall provide adequate explanations for the basis of allocation of Operation and Maintenance expenditure among the generating stations.

(ii) The Commission shall verify the budget estimates and projections and allow the amount depending on its views about the reasonableness of the projections.

48.3 In verifying the budget for operation and maintenance the generating company may be guided by the following norms laid down in CERC Tariff Regulations, 2009 and its amendments.

Normative operation and maintenance expenses shall be as follows, namely:

(i) Coal based and lignite fired generating stations

Rs. lakh / MW)

Year

200/210/250

MW sets upto 4 Units

300/330/350

MW sets upto 3 Units

500 MW sets upto 2 units

600 MW and above sets upto 2 units

2009-10

18.20

16.00

13.00

11.70

2010-11

19.24

16.92

13.74

12.37

2011-12

20.34

17.88

14.53

13.08

2012-13

21.51

18.91

15.36

13.82

2013-14

22.74

19.99

16.24

14.62

Provided that the above norms shall be multiplied by the following factors for additional units in respective unit sizes for the units whose COD occurs on or after 1-4-2014 in the same station

200/210/250 MW	Additional 5th & 6th Units	0.9
	Additional 7th & more Units	0.85
300/330/350 MW	Additional 4th & 5th Units	0.9
	Additional 6th & more Units	0.85
500 MW and above	Additional 3rd & 4th Units	0.9
	Additional 5th Units	0.85

(ii) Open Cycle Gas Turbine / Combined cycle generating station

(Rs. lakh / MW)

Year

Gas Turbine / Combined Cycle generating stations other than small gas turbine power generating stations

Small gas turbine power generating station

2009-10

14.80

22.90

2010-11

15.65

24.21

2011-12

16.54

25.59

2012-13

17.49

27.06

2013-14

18.49

28.61

(iii) Lignite Fired generating stations

(Rs. lakh / MW)

Year

125 MW sets

2009-10

24.00

2010-11

25.37

2011-12

26.82

2012-13

28.36

2013-14

29.98

In case of coal – based or lignite fired thermal generating station, a separate compensation allowance unit wise shall be admissible to meet expenses on new assets of capital nature including the nature of minor assets, in the following manner, from the year following the year of completion of 10,15 or 20 years of useful life:

Year of operation

Compensation Allowance

(Rs. lakh / MW / year)

0-10

Nil

11-15

0.15

16-20

0.35

21-25

0.65

49. Expenses on secondary fuel oil consumption for coal-based, lignite-fired generating station

49.1 Expenses on secondary fuel oil in Rupees shall be computed corresponding to normative secondary fuel oil consumption (SFC) in accordance with the following formula:

SFC x LPSFi x NAPAF x 24 x NDY x IC x 10

Where,

SFC – Normative Specific Fuel Oil consumption in ml/kWh

LPSFi – Weighted Average Landed Price of Secondary Fuel in Rs./ml considered initially

NAPAF – Normative Annual Plant Availability Factor in percentage

NDY – Number of days in a year

IC -Installed Capacity in MW.

49.2 Initially, the landed cost incurred by the generating company on secondary fuel oil shall be taken based on actuals of the weighted average price of the three preceding months and in the absence of landed costs for the three preceding months, latest procurement price for the generating station, before the start of the year.

49.4 The secondary fuel oil expenses shall be subject to fuel price adjustment at the end of the each year of tariff period as per the following formula:

SFC x NAPAF x 24 x NDY x IC x 10 x (LPSFy – LPSFi)

Where,

LPSFy = The weighted average landed price of secondary fuel oil for the year in Rs. /ml

50. Computation and payment of capacity charge and energy charge for thermal generation stations

A. Annual Fixed Charges:

50.1 The total Annual Fixed Charges shall be computed based on the norms specified under these Regulations and recovered on monthly basis under capacity charge. The total capacity charge payable for a generating station shall be shared by its beneficiaries as per their respective percentage share / allocation in the capacity of the generating station.

50.2 The capacity charge (inclusive of incentive) payable to a thermal generating station for a calendar month shall be calculated in accordance with the following formulae:

(a) Generating stations in commercial operation for less than ten (10) years on 1st April of the financial year :

AFC x ( NDM / NDY ) x ( 0.5 + 0.5 x PAFM / NAPAF ) (in Rupees);

Provided further that in case the plant availability factor achieved during a financial year (PAFY) is less than 70%, the total capacity charge for the year shall be:

AFC x ( 0.5 + 35 / NAPAF ) x ( PAFY / 70 ) (in Rupees).

(ii) For generating stations in commercial operation for ten (10) years or more on 1st April of the year:

AFC x (NDM / NDY ) x ( PAFM / NAPAF ) (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 percent;

PAFY = Plant availability factor achieved during the year, in percent.

50.3 The PAFM and PAFY shall be computed in accordance with the following formula:

PAFM or PAFY = 10000 x Σ DCi / { N x IC x ( 100 - AUX ) } %

i = 1

Where,

AUX = Normative auxiliary energy consumption in percentage;

DCi = Average declared capacity (in ex-bus MW), subject to Regulation 50.4 below, for the ith day of the period, i.e., the month or the year as the case may be, as certified by the concerned load dispatch centre after the day is over;

IC = Installed Capacity (in MW) of the generating station;

N = Number of days during the period i.e. the month or the year as the case may be.

Note: DCi and IC shall exclude the capacity of generating units not declared under commercial operation. In case of a change in IC during the concerned period, its average value shall be taken.

50.4 In case of fuel shortage in a thermal generating station, the generating company may propose to deliver a higher MW during peak-load hours by saving fuel during off-peak hours. The State Load Despatch Centre may then specify a pragmatic day-ahead schedule for the generating station to optimally utilize its MW and energy capability, in consultation with the beneficiaries. DCi in such an event shall be taken to be equal to the maximum peak-hour ex-power plant MW schedule specified by the concerned Load Despatch Centre for that day.

B. Energy Charge:

50.4 The energy charge shall cover the primary fuel cost and shall be payable by every beneficiary for the total energy scheduled to be supplied to such beneficiary during the calendar month on ex-power plant basis, at the energy charge rate of the month (with fuel price adjustment). Total Energy charge payable to the generating company for a month shall be:

= (Energy charge rate in Rs./kWh) x

{Scheduled energy (ex-bus) for the month in kWh.}

50.5 Energy charge rate (ECR) in Rupees per kWh on ex-power plant basis shall be determined to three decimal places in accordance with the following formulae:

(i) For coal based and lignite fired stations

ECR = { (GHR – SFC x CVSF) x LPPF /

CVPF + LC x LPL } x 100 / (100 – AUX)

(ii) For gas and liquid fuel based stations

ECR = GHR x LPPF x 100 / {CVPF x (100 – AUX) }

Where,

AUX = Normative auxiliary energy consumption in percentage.

CVPF = Gross calorific value of primary fuel as fired, in kCal per kg, per litre or per standard cubic metre, as applicable.

CVSF = Calorific value of secondary fuel, in kCal per ml.

ECR = Energy charge rate, in Rupees per kWh sent out.

GHR = Gross station heat rate, in kCal per kWh.

LC = Normative limestone consumption in kg per kWh.

LPL = Weighted average landed price of limestone in Rupees per kg.

LPPF = Weighted average landed price of primary fuel, in Rupees per kg, per litre or per standard cubic metre, as applicable, during the month.

SFC = Specific fuel oil consumption, in ml per kWh.

50.6 The landed cost of fuel for the month shall include price of fuel corresponding to the grade and quality of fuel inclusive of royalty, taxes and duties as applicable, transportation cost by rail / road or any other means, and, for the purpose of computation of energy charge, and in case of coal/lignite shall be arrived at after considering normative transit and handling losses as percentage of the quantity of coal or lignite dispatched by the coal or lignite supply company during the month as given below :

(i) Pit head generating stations : 0.2%

(ii) Non-pit head generating stations : 0.8%

51. Operation and Maintenance expenses for thermal Generating Stations

51.1 Existing Generating Stations

(i) The Operation and Maintenance expenses excluding water charges and including insurance, shall be derived on the basis of the average of the actual Operation and Maintenance expenses excluding water charges and including insurance for the three (3) years ending March 31, 2014, subject to prudence check by the Commission.

(ii) The average of such operation and maintenance expenses excluding water charges and including insurance shall be considered as operation and maintenance expenses excluding water charges and including insurance for the financial year ended March 31, 2013 and shall be escalated at the escalation factor of 4 % to arrive at operation and maintenance expenses excluding water charges and including insurance for FY 2015-16.

(iii) The O&M expenses excluding water charges and including insurance for each subsequent year will be determined by escalating the base expenses determined above for FY 2015-16, at the escalation factor of 5.72 % to arrive at permissible O&M expenses excluding water charges and including insurance for each year of the Control Period:

Provided that water charges shall be allowed separately as per actuals, subject to prudence check.

Provided further that in case an existing generating station has been in operation for less than three (3) years as on the date of effectiveness of these Regulations, the O&M Expenses shall be as specified by Regulation 51.2 for New Generating Stations.

51.2 New Generating Stations

(i) For coal based generating Units/Stations:

(Rs. Lakh/MW)

Particulars	O&M Expense Norms
FY 2015-16	18.15
FY 2016-17	19.19
FY 2017-18	20.29

Provided that the above norms shall be multiplied by the following factors for the additional Units whose COD occurs on or after 1.4.2011 in the same Station:

Additional 4th & 5th Units : 0.90

Additional 6th & more Units : 0.85

(ii) For lignite based generating stations:

(Rs. Lakh/MW)

Particulars	O&M Expense Norms
FY 2015-16	27.02
FY 2016-17	28.56
FY 2017-18	30.19

(iii) Gas Turbine/Combined Cycle generating stations:

(Rs. Lakh/MW)

Year

Gas Turbine / Combined Cycle generating stations

FY 2015-16

20.67

FY 2016-17

21.85

FY 2017-18

23.10

51.3 Fuel Price Adjustment:

Adjustment of Energy Charge Rate (ECR) [Fuel Price Adjustment] on account of variation in price or heat value of fuels shall be computed and charged as stipulated by the Commission from time to time.

51.4 Landed Cost of fuel:

The landed cost of fuel shall include price of fuel corresponding to the grade/quality/calorific value of fuel inclusive of royalty, taxes and duties as applicable, transportation cost by rail/road/gas pipe line or any other means, 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 these Regulations.

52 Norms of operation for Hydro Generating Stations

The norms of operation shall be as under:

52.1 Normative annual plant availability factor (NAPAF)

Particulars

Normative Annual Plant

Availability Factor

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%

Storage and Pondage type plants with head

variation between FRL and MDDL of more than 8%, where plant availability is not affected by silt

Plant-specific allowance to be provi - ded in NAPAF for reduction in MW output capability as reservoir level falls over the months. As a general guideline the allowance on this acco – unt in terms of a multiplying factor may be worked out from the pro-jection of annual average of net head, applying the formula:

(Average head / Rated head) + 0.02

Alternatively, in case of a difficulty in making such projection, the mult-iplying factor may be determined as:

(Head at MDDL/Rated head) x 0.5 +

0.52

Pondage type plants where plant availability is significantly affected by silt

85%

Run-of-river type plants

To be determined plant-wise, based on 10-day design energy data, mode-rated by past experience where available/relevant

Note:

(i) A further allowance may be made by the Commission under special circumstances, eg. Abnormal silt problem or other operating conditions, and known plant limitations.

(ii) A further allowance of 5 % may be allowed for difficulties in the North East Region.

(iii) In case of new hydro electric project the developer shall have the option of approaching the Commission in advance for further above norms.

52.3 Auxiliary energy consumption

(i) Surface hydro electric power generating stations with rotating exciters mounted on the generator shaft : 0.7% of energy generated.

(ii) Surface hydro electric power generating stations with static excitation system: 1.0% of energy generated.

(iii) Underground hydro electric power generating stations with rotating exciters mounted on the generator shaft : 0.9% of energy generated.

(iv) Underground hydro electric power generating stations with static excitation system : 1.2% of energy generated.

52.4 Transformation losses

From generation voltage to transmission voltage : 0.5% of energy generated

53 Operation and Maintenance Expenses for Hydro Generating Stations

53.1 For Existing Station

(i) The Operation and Maintenance expenses including insurance shall be derived on the basis of the average of the actual Operation and Maintenance expenses for the three (3) years ending March 31, 2014, subject to prudence check by the Commission.

(ii) The average of such operation and maintenance expenses shall be considered as operation and maintenance expenses for the financial year ended March 31, 2013 and shall be escalated at the escalation factor of 4 % to arrive at operation and maintenance expenses for FY 2015-16.

(iii) The O&M expenses for each subsequent year will be determined by escalating the base expenses determined above for FY 2015-16, at the escalation factor of 5.72% to arrive at permissible O&M expenses for each year of the Control Period.

53.2 For New Stations

(1) O&M expenses for the first year of operation will be 2% of the original project cost (excluding cost of rehabilitation and resettlement works).

(2) The O&M expenses for each subsequent year will be determined by escalating the base expenses determined above, at the escalation factor of 5.72%.

54. Computation and Payment of Capacity Charges and Energy Charges for Hydro Generating Stations

54.1 The Annual Fixed Charges of a Hydro Generating Station shall be computed on annual basis, based on norms specified under these Regulations, and recovered on monthly basis under capacity charge (inclusive of incentive) and Energy Charge, which shall be payable by the beneficiaries in proportion to their respective share in the capacity of the generating station.

Provided that during the period between the date of commercial operation of the first unit of the generating station and the date of commercial operation of the generating station, the annual fixed cost shall provisionally be worked out based on the latest estimate of the completion cost for the generating station, for the purpose of determining the capacity charge and energy charge payment during such period.

54.2 The capacity charge (inclusive of incentive) payable to a hydro generating station for a calendar month shall be:

AFC x 0.5 x NDM / NDY x (PAFM / NAPAF) (in Rupees);

Where;

AFC = Annual fixed cost specified for the year, in Rupees;

NAPAF = Normative 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.

54.3 The PAFM shall be computed in accordance with the following formula :

PAFM =10000 x Σ DCi / { N x IC x ( 100 - AUX ) } %

i = 1

Where;

AUX = Normative auxiliary energy consumption in percentage;

DCi = Declared capacity (in ex-bus MW) for the ith day of the month which the station can deliver for at least three (3) hours; as certified by the Gujarat State Load Despatch Centre after the day is over.

IC = Installed capacity (in MW) of the complete generating station;

N = Number of days in the month.

55.4 The Energy Charge shall be payable by every beneficiary for the total energy supplied to the beneficiary during the calendar month on ex-power plant basis, at the computed Energy Charge rate. Total Energy Charge payable to the Generating Company for a month shall be :

(Energy Charge Rate in Rs. / kWh) x { Energy (ex-bus)} for the month in kWh

54.5 Energy Charge Rate (ECR) in Rupees per kWh on ex-power plant basis, for a Hydro Generating Station, shall be determined up to three decimal places based on the following formula:

ECR = AFC x 0.5 x 10 / { DE x ( 100 – AUX ) } ;

Where;

DE = Annual Design Energy specified for the hydro generating station, in MWh, subject to the provision in Regulation 60.6 below.

54.6 In case actual total energy generated by a Hydro Generating Station during a year is less than the Design Energy for reasons beyond the control of the Generating Company, the following treatment shall be applied on a rolling basis:

(i) in case the energy shortfall occurs within ten years from the date of commercial operation of a generating station, the ECR for the year following the year of energy shortfall shall be computed based on the formula specified in these Regulations with the modification that the DE for the year shall be considered as equal to the actual energy generated during the year of the shortfall, till the Energy Charge shortfall of the previous year has been made up, after which normal ECR shall be applicable;

(ii) in case the energy shortfall occurs after ten years from the date of commercial operation of a generating station, the following shall apply:

Suppose the specified annual Design Energy (DE) for the station is DE MWh, and the actual energy generated during the relevant (first) and the following (second) financial years are A1 and A2 MWh, respectively, A1 being less than DE. Then, the Design Energy to be considered in the formula in these Regulations for calculating the ECR for the third financial year shall be moderated as (A1 + A2 – DE) MWh, subject to a maximum of DE MWh and a minimum of A1 MWh;

Actual energy generated (e.g., A1, A2) shall be arrived at by multiplying the net metered energy sent out from the station by 100 / (100 – AUX).

54.7 In case the Energy Charge Rate (ECR) for a hydro generating station, as computed in Regulation 54.5 above, exceeds eighty paise per kWh, and the actual saleable energy in a year exceeds { DE x ( 100 – AUX ) / 10000 } MWh, the Energy Charge for the energy in excess of the above shall be billed at eighty paise per kWh only:

Provided that in a year following a year in which the total energy generated was less than the design energy for reasons beyond the control of the Generating Company, the Energy Charge Rate shall be reduced to eighty paise per kWh after the energy charge shortfall of the previous year has been made up.

54.8 The State Load Despatch Centre 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.

55. Incentive for completion of hydro electric power generating stations ahead of schedule

55.1 In case of commissioning of a hydro electric power generating station or an unit thereof ahead of schedule, the generating station shall become eligible for incentive of an amount equal to the pro-rata amount of reduction in interest during construction achieved by such commissioning, ahead of schedule.

Provided the hydro generating station shall obtain the Commission’s approval of project calendar, prior to its implementation for the purpose of claiming the incentive (s).

55.2 The incentive shall be recovered through tariff in twelve equal monthly instalments during the first year of operation of the generating station.

55.3 In case of delay in commissioning, interest during construction for the period of delay shall not be allowed to be capitalized for determination of tariff, unless the delay is not attributable to the generating Company.

CHAPTER 5: INTRA-STATE TRANSMISSION

56 Applicability

56.1 The Regulations contained in this Chapter shall apply to determination of tariff for access and use of the intra-State transmission system in the States of Manipur and Mizoram:

Provided that the Commission may deviate from the norms contained in this Part or stipulate alternative norms for particular cases, where it so deems appropriate, having regard to the circumstances of the case:

Provided further that the reasons for such deviation shall be recorded in writing.

56.2 The Commission shall be guided by the Regulations contained in this Chapter in specifying the rates, charges, terms and conditions for use of intervening transmission facilities pursuant to an application made in this regard by a Licensee under the proviso to Section 36 of the Act.

57. Components of tariff

Annual Transmission Charges for each year of the Control Period:

57.1 The Annual Transmission Charges for each financial year of the Control Period shall provide for the recovery of the Aggregate Revenue Requirement of the Transmission Licensee for the respective financial year of the Control Period, as reduced by the amount of Non-Tariff Income, income from Other Business and short-term transmission charges of the previous year, as approved by the Commission:

Provided that in case of competitively awarded transmission system projects in pursuance of Section 63 of the Act and in accordance with guidelines for competitive bidding for transmission, the annual transmission charges shall be as per the annual Transmission Service Charges (TSC) quoted by such competitively awarded transmission projects.

57.2 The Annual Transmission Charges of the Transmission Licensee shall be determined by the Commission on the basis of an application for determination of Aggregate Revenue Requirement made by the Transmission Licensee in accordance with Chapter-2 of these Regulations.

58. Business Plan

58.1 Each Transmission Licensee shall submit a Business Plan in the manner specified in Chapter-2 of these Regulations.

59. Capital Investment Plan

59.1 The Transmission 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 load growth, improvement in quality of supply, reliability, metering, reduction in congestion, etc., to the Commission for approval, as a part of the Business Plan:

Provided that the Capital Investment Plan shall be submitted for each year of the Control Period:

Provided further that 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 (ckt-km) showing the need for the proposed investments, alternatives considered, cost/benefit analysis and other aspects that may have a bearing on the transmission charges.

59.2 The Capital Investment Plan of the Transmission Licensee shall be consistent with the transmission system plan for the intra-State transmission system.

60. Capital Cost

60.1 For the purpose of determination of tariff, the Capital Cost for a Transmission Project and additional capitalisation thereof, shall be allowed in accordance with the provisions outlined under Regulation 23 and Regulation 24, respectively.

61. Norms for operation

61.1 Target availability for full recovery of annual transmission charges:

(i)	AC system	: 98 per cent;
(ii)	HVDC bi-pole links	: 92 per cent;
(iii)	HVDC back-to-back stations	: 95 per cent;

Note 1:

Recovery of annual transmission charges below the level of target availability shall be on pro rata basis. At zero availability, no transmission charges shall be payable.

Note 2:

The actual availability shall be calculated in accordance with the procedure provided in Annexure-II to these Regulations and shall be certified by the concerned State Load Despatch Centre.

62. Calculation of Aggregate Revenue Requirement

62.1 Aggregate Revenue Requirement of transmission licensee shall comprise the following components, viz.

(i) Return on Equity (ROE);

(ii) Interest and Finance Charges on Loan Capital;

(iii) Depreciation;

(iv) Operation and maintenance expenses;

(v) Interest on working capital and deposits from Transmission System Users;

(vi) Contribution to contingency reserves, if any; minus:

(vii) Non-Tariff Income;

(viii) Revenue from short-term transmission charges projected on the basis of latest audited figures; and

(ix) Income from Other Business, to the extent specified in these Regulations.

62.2 Return on Equity:

The Transmission Licensee shall be allowed a return on equity as specified in Regulation 26 of these Regulations.

62.3 Interest and Finance Charges on Loan Capital:

The Transmission Licensee shall be allowed Interest and Finance Charges on loan capital as specified in Regulation 27 of these Regulations.

62.4 Depreciation:

The Transmission Licensee shall be permitted to recover depreciation on the value of fixed assets as specified in Regulation 28 of these Regulations.

62.5 Operation and Maintenance expenses:

Existing Transmission Licensee:

(a) Operation and Maintenance Expenses or O&M Expenses shall mean the total of all expenditure under the following heads:-

(1) Employee Cost

(2) Repairs and Maintenance

(3) Administration and General Expenses.

(b) The Licensee shall submit O&M expenses budget indicating the expenditure under each head of account showing actuals of the last financial year, estimates for the current year and projections for the next financial year.

(c) The norms for O&M expenses on the basis of circuit kilometers of transmission lines, transformation capacity and number of bays in substations shall be submitted for approval of the Commission.

(d) The Commission shall verify the budget estimates and projections and allow the expenditure depending on its views about the reasonableness of the projections.

(e) Increase in O& M expenses due to natural calamities or insurgency or other factors not within its control may be approved by the Commission.

(ii) For New Transmission Licensee:

For the New transmission licensees, the year-wise O&M norms shall be determined on case to case basis:

Provided that the same shall not be applicable to those new projects, which are awarded on a competitive bidding basis.

Explanation 1: The term "New Transmission Licensee" shall mean the transmission licensee(s) for which transmission licence is granted by the Commission after the date of effectiveness of these Regulations, and whose transmission project assets are commissioned after 31st March 2015.

Explanation 2: For the purpose of deriving normative O&M expenses under Regulations 62.5(i), “Bay” shall mean a set of accessories that are required to connect an electrical equipment such as Transmission Line, Bus Section Breakers, Potential Transformers, Power Transformers, Capacitors and Transfer Breaker and the feeders emanating from the bus at Sub-station of Transmission Licensee. Further, the Bays referred herein 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.

62.6 Interest on working capital:

The Transmission Licensee shall be allowed interest on the estimated level of working capital, as specified in Regulation 29 of these Regulations.

62.7 Contribution to contingency reserve:

(i) Where the Transmission Licensee has made an appropriation to the Contingency Reserve, a sum not more than 0.5 per cent of the original cost of fixed assets shall be allowed annually towards such appropriation in the calculation of aggregate revenue requirement:

Provided that where the amount of such Contingency Reserve exceeds five (5) per cent of the original cost of fixed assets, no such appropriation shall be allowed, which would have the effect of increasing the reserve beyond the said maximum:

Provided further that the amount so appropriated shall be invested in securities authorised under the Indian Trusts Act, 1882 within a period of six months of the close of the financial year.

(ii) The Contingency Reserve shall not be drawn upon during the term of the licence except to meet such charges as may be approved by the Commission as being:

(a) Expenses or loss of profits arising out of accidents, natural calamities or circumstances which the management could not have prevented;

(b) Expenses on replacement or removal of plant or works other than expenses requisite for normal maintenance or renewal;

Provided that such drawal from Contingency Reserve shall be computed after making due adjustments for any other compensation that may have been received by the Licensee as part of an insurance cover.

(iii) No diminution in the value of contingency reserve as mentioned above shall be allowed to be adjusted as a part of tariff.

63 Non-Tariff Income

63.1 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 annual transmission charges of the Transmission Licensee:

Provided that the Transmission Licensee shall submit full details of his forecast of Non-Tariff Income to the Commission along with its application for determination of Aggregate Revenue Requirement.

The indicative list of various heads to be considered for Non-Tariff Income shall be as under:

a) Income from rent on land or buildings or poles;

b) Income from sale of scrap;

c) Income from statutory investments;

d) Interest on delayed or deferred payment on bills;

e) Interest on advances to suppliers/contractors;

f) Rental from staff quarters;

g) Rental from contractors;

h) Income from hire charges from contactors and others;

i) Income from advertisements, etc.;

j) Miscellaneous receipts;

k) Excess found on physical verification;

l) Interest on investments, fixed and call deposits and bank balances;

m) Prior period income;

n) Income from departmental / agency charge on execution of deposit work;

o) Income from sale of tender document;

p) Income from usage of poles / tower / earth wire etc;

q) Any other income other than sale of electricity tariff.

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.

64 Income from Other Business

64.1 Where the Transmission Licensee has engaged in any Other Business, an amount equal to one-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 audited and certified by the Statutory Auditor, to the Commission along with his application for determination of tariff:

Provided further that where the sum total of the direct and indirect costs of such Other Business exceed 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.

65 Sharing of charges for intra-State Transmission Network

65.1 Determination of Monthly Transmission Tariff (MTT):

(i) The aggregate of the yearly revenue requirement for all Transmission Licensees, less the deductions, as approved by the Commission over the Control Period, shall form the “Total Transmission Cost" (TTC) of the Intra- State transmission system, to be recovered from the Long term and Medium term Transmission System Users (TSUs) for the respective year of the Control Period, in accordance with the following Formula:

ð‘– =1

TTC(t) = Æ©

(ARRi - NTi -Oi) – STR(t-2)

Where,

TTC(t) = Total Transmission Cost of year (t) of the Control Period

N = Number of Transmission Licensee(s)

ARRi = Aggregate Revenue Requirement approved by the Commission for ith Transmission Licensee for the yearly period (t) of the Control Period

NTi = Approved level of non-tariff income for ith Transmission Licensee for the yearly period (t) of the Control Period

Oi = Approved level of income from other business of the ith Transmission Licensee for the yearly period (t) of the Control Period

STR(t-2) = Revenue from short term open access charges earned during previous yearly period (t-2):

Provided that the revenue from short-term open access charges for each yearly period (t) of Control Period shall be taken to be same as that prevalent during the yearly period one year before the commencement of the Control Period. However, the adjustments due to variation in actual revenue from short term open access charges shall be undertaken during annual truing up:

Provided further that ARR of the Transmission Licensee in case of competitively bid transmission projects shall be Transmission Service Charge (TSC) for relevant yearly period as adopted by the Commission in accordance with Section 63 of the Act.

(ii) The Total Transmission Cost (TTC) as determined by the Commission as per Regulation 65.1(i) above, shall be shared by all long-term and medium-term open access customers on monthly basis (including existing Distribution Licensees) in the ratio of their allotted capacities, in accordance with the following formula:

Monthly Transmission Tariff (MTT) = TTC/(ACs x 12) (in Rs./MW/month);

Where;

TTC = Total Transmission Cost determined by the Commission for the transmission system for the relevant year (in Rs), and

ACs = sum of capacities allocated to all long-term and medium-term open access customers in MW.

Provided that Monthly Transmission Tariff shall also be shared by a Generating Company if power from such Generating Company is sold to a consumer outside the State of Gujarat, to the extent of capacity contracted outside the State:

Provided further that the transmission tariff payable by any long-term or medium-term open access customer utilizing the transmission system for part of a month shall be determined as under:

Transmission Tariff = TTC/(ACs x 8760) (in Rs./MWh);

Where;

TTC = Total Transmission Cost determined by the Commission for the transmission system for the relevant year (in Rs), and

ACs = sum of capacities allocated to all long-term and medium-term open access customers in MW.

66 Incentive

66.1 The Transmission Licensee shall be entitled to incentive for increase in annual availability beyond the target availability prescribed under Regulation 61, in accordance with the following formula:

Incentive = ATC x [Annual availability achieved – Target Availability]

Target Availability

Where;

ATC= Annual Transmission Charges determined by the Commission for the transmission system of the Transmission Licensee for the concerned year.

66.2 Incentive shall be shared by the long-term and medium-term customers in the ratio of their average allotted transmission capacity for the year.

67 Usage of Intra-State Transmission System

67.1 All the matters related to Open Access Transactions shall be dealt in accordance with the Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and Conditions for Open Access) Regulations, 2010 as applicable and as amended from time to time.

67.2 The charges for intra-State transmission usage shall be shared among various TSUs as specified in these Regulations.

68 Transmission losses

68.1 The energy losses in the transmission system of the Transmission Licensee, as determined by the State Load Despatch Centre, shall be borne by the Transmission System Users in proportion to their usage of the intra-State transmission system.

69 Scheduling and Metering

69.1 All the provisions, including the methodology for scheduling, dispatch and metering for the generating station shall be as specified in the Commission’s Order issued from time to time.

CHAPTER 6: DISTRIBUTION WIRES BUSINESS

70 Applicability

70.1 The Regulations contained in this Chapter shall apply to the determination of tariff payable for usage of distribution wires of a Distribution Licensee by a Distribution System User.

71 Components of Aggregate Revenue Requirement for Distribution Wires Business

71.1 The wheeling charges for Distribution Wires Business of the Distribution Licensee shall provide for the recovery of the Aggregate Revenue Requirement, as provided in Regulation 76 of these Regulations: and shall comprise the following:

(i) Return on Equity;

(ii) Interest and Finance Charges on Loan Capital;

(iii) Depreciation;

(iv) Operation and maintenance expenses;

(v) Interest on working capital and deposits from Distribution System Users;

(vi) Contribution to contingency reserves, if any;

minus:

(vii) Non-Tariff Income; and

(viii) Income from Other Business, to the extent specified in these Regulations; and

(ix) Receipts on account of additional surcharge on charges for wheeling:

Provided that the wheeling charges of the Distribution Licensee shall be determined by the Commission on the basis of an application for determination of tariff made by the Distribution Licensee in accordance with Chapter-2 of these Regulations:

Provided further that the Wheeling Charges may be denominated in terms of Rupees/kWh, for the purpose of recovery from the Distribution System User, or any such denomination, as stipulated by the Commission from time to time.

72 Allocation Matrix

72.1 The Wheeling Charges of the Distribution Licensee shall be determined by the Commission on the basis of segregated accounts of Distribution Wires Business:

Provided that where the Distribution Licensee is not able to submit audited and certified separate accounts for Distribution Wires Business and Retail Supply Business, the following allocation matrix shall be applicable:

Table: Allocation matrix for segregation of expenses between Distribution Wires Business and Retail Supply Business

Particulars	Wires Business (%)	Retail Supply Business (%)
Power Purchase Expenses	0%	100%
Standby Charges	0%	100%
Employee Expenses	60%	40%
Administration & General Expenses	50%	50%
Repair & Maintenance Expenses	90%	10%
Depreciation	90%	10%
Interest on Long-term Loan Capital	90%	10%
Interest on Working Capital and on consumer security deposits	10%	90%
Bad Debts Written off	0%	100%
Income Tax	90%	10%
Transmission Charges intra-State	0%	100%
Contribution to contingency reserves, if any	100%	0%
Return on Equity	90%	10%
Non-Tariff Income	10%	90%

Provided further that the operation and maintenance expenses shall be allocated between the Distribution Wires Business and Retail Supply Business, by considering the above-specified percentages for employee expenses, administration and general expenses, and repair and maintenance expenses, as weights for determining the weighted average allocation percentage for operation and maintenance expenses:

Provided further that once the Commission notifies the Regulations for submission of Regulatory Accounts, the wheeling charges of the Distribution Licensee shall be determined by the Commission on the basis of segregated accounts of Distribution Wires Business.

73 Business Plan

73.1 The Distribution Licensee shall submit a Business Plan in the manner as specified in Chapter-2 of these Regulations.

74 Capital Investment Plan

74.1 The Distribution Licensee shall submit detailed capital investment plan, financing plan and physical targets for each year of the Control Period for meeting the requirement of load growth, reduction in distribution losses, improvement in quality of supply, reliability, metering, consumer services, etc., to the Commission for approval, as a part of the Business Plan:

74.2 The Distribution Licensee shall be required to ensure optimum investments to enhance efficiency, productivity and meet performance standards prescribed by the Commission.

75 Capital cost

75.1 The approved Business Plan of the Distribution Licensee shall be the basis for determining the annual allowable capital cost for each financial year for any capital expenditure project initiated on or after April 1, 2015.

75.2 For each capital expenditure project, the sum total of annual allowable capital cost from the date of commencement of such project till the date of commissioning shall be the original cost of such project.

75.3 The capital cost shall be allowed as specified in Regulation 23.

76 Calculation of Aggregate Revenue Requirement

76.1 Return on Equity:

The Distribution Licensee shall be allowed a return on equity for Distribution Wires Business, as specified in Regulation 26 of these Regulations.

76.2 Interest and Finance Charges on Loan Capital:

The Distribution Licensee shall be allowed Interest and Finance Charges on loan capital for Distribution Wires Business, as specified in Regulation 27 of these Regulations.

76.3 Depreciation:

The Distribution Licensee shall be permitted to recover depreciation on the value of fixed assets used in the Distribution Wires Business as specified in Regulation m 28 of these Regulations.

76.4 Operation and Maintenance expenses:

(i) The Operation and Maintenance expenses shall be derived on the basis of the average of the actual Operation and Maintenance expenses for the three (3) years ending March 31, 2014, subject to prudence check by the Commission.

(ii) The average of such operation and maintenance expenses shall be considered as operation and maintenance expenses for the financial year ended March 31, 2013 and shall be escalated at the escalation factor of 4% to arrive at operation and maintenance expenses for FY 2015-16.

(iii) The O&M expenses for each subsequent year will be determined by escalating the base expenses determined above for FY 2015-16, at the escalation factor of 5.72 % to arrive at permissible O&M expenses for each year of the Control Period:

Provided that in case, the Distribution Licensee has been in operation for less than three (3) years as on the date of effectiveness of these Regulations, the O&M Expenses shall be determined on case to case basis.

76.5 Interest on working capital:

The Distribution Licensee shall be allowed interest on the estimated level of working capital for the Distribution Wires Business, as specified in Regulation 29 of these Regulations.

76.6 Contribution to contingency reserves:

(i) Where the Distribution Licensee has made an appropriation to the Contingency Reserve, a sum not more than 0.5 per cent of the original cost of fixed assets shall be allowed annually towards such appropriation in the calculation of aggregate revenue requirement:

Provided further that the amount so appropriated shall be invested in securities authorised under the Indian Trusts Act, 1882 within a period of six months of the close of the financial year.

(ii) The Contingency Reserve shall not be drawn upon during the term of the licence except to meet such charges as may be approved by the Commission as being:

(a) Expenses or loss of profits arising out of accidents, natural calamities or circumstances which the management could not have prevented;

(b) Expenses on replacement or removal of plant or works other than expenses requisite for normal maintenance or renewal;

Provided that such drawal from Contingency Reserve shall be computed after making due adjustments for any other compensation that may have been received by the Licensee as part of an insurance cover.

(iii) No diminution in the value of contingency reserve as mentioned above shall be allowed to be adjusted as a part of tariff.

77 Non-Tariff Income

77.1 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 Distribution Wires Business of the Distribution Licensee:

Provided that the Distribution Licensee shall submit full details of its forecast of Non-Tariff Income to the Commission along with its application for determination of wheeling charges.

The indicative list of various heads to be considered for Non-Tariff Income shall be as under:

a) Income from rent of land or buildings or poles;

b) Income from sale of scrap;

c) Income from statutory investments;

d) Interest on delayed or deferred payment on bills;

e) Interest on advances to suppliers/contractors;

f) Rental from staff quarters;

g) Rental from contractors;

h) Income from hire charges from contactors and others;

i) Income from advertisements, etc.;

j) Miscellaneous receipts;

k) Interest on advances to suppliers;

l) Excess found on physical verification;

m) Prior period income;

n) Income from testing fees/charges;

o) Income from departmental/agency charge for execution of deposit work;

p) Income from sale of tender documents;

q) Income from usage of poles/tower/earth wire etc;

r) Any other income not affected by electricity tariff.

Provided that the interest earned from investments made out of Return on Equity corresponding to the Distribution Wires Business of the Distribution Licensee shall not be included in Non-Tariff Income.

78 Income from Other Business

78.1 Where the Distribution Licensee has engaged in any Other Business, an amount equal to one-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 determining the wheeling charges of Distribution Wires Business of the Distribution Licensee:

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 to the Commission, duly audited and certified by the statutory auditors, along with his application for determination of wheeling charges:

Provided further that where the sum total of the direct and indirect costs of such Other Business exceed the revenues from such Other Business, no amount shall be allowed to be added to the Aggregate Revenue Requirement of the Distribution Licensee on account of such Other Business:

Provided further that nothing contained in these Regulations shall apply to a local authority engaged, before the commencement of the Act, in the business of distribution of electricity.

79 Determination of Wheeling Charges

79.1 The Commission shall specify the wheeling charge of Distribution Wires Business of the Distribution Licensee in its Order passed under sub-section (3) of Section 64 of the Act:

Provided that the wheeling charges payable by a Distribution System User, other than the retail consumers getting electricity supply from the same Distribution Licensee, may comprise any combination of fixed/demand charges, and variable charges, as may be stipulated by the Commission in such Order.

Provided further that the revenue from wheeling charges paid by the Distribution System Users under the above proviso shall be used to reduce the Aggregate Revenue Requirement of the Wire Business to be recovered from the retail consumers of the concerned Distribution Licensee, in accordance with the Regulations in Chapter 7.

80 Receipts on account of Additional surcharge

80.1 The amount received by the Distribution Licensee by way of additional surcharge on charges of Distribution Wires Business, as approved by the Commission in accordance with the Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and Conditions for Open Access) Regulations, 2010, as applicable and as amended from time to time, from consumers connected to wires of the Distribution Licensee, shall be deducted from the Aggregate Revenue Requirement in calculating the wheeling charges of such Distribution Licensee.

81 Wheeling Losses

81.1 The Distribution Licensee shall be allowed to recover, in kind, the approved level of wheeling losses arising from the operation of the distribution system:

Provided that the Commission may stipulate a trajectory for wheeling losses in accordance with these Regulations, as part of the Order on the Business Plan filed by the Distribution Licensee:

Provided further that any variation between the actual level of wheeling losses and the approved level shall be dealt with, as part of the Truing Up of each year of the Control Period, in accordance with the mechanisms provided in these Regulations.

82 Wires Availability

82.1 The target Wires Availability for full recovery of Return on Equity for Wires Business shall be as under:

(a) Rural Areas 90 percent;

(b) Towns and cities 95 percent;

Provided that the Commission may stipulate a trajectory for achieving the target Availability for Wires Business of the Distribution licensee as part of the Order on the Business Plan filed by the Distribution Licensee:

Provided further that for every 1 percent under-achievement in Wires Availability vis-a-vis target availability, Rate of Return on Equity shall be reduced by 0.1%:

Provided further that for every 1 percent over-achievement in Wires Availability vis-a-vis target availability, Rate of Return on Equity shall be increased by 0.1%.

82.2 Wires Availability shall be computed for the year in accordance with the following formula:

Wires Availability = {1- (SAIDI / 8760)} x 100;

Where;

SAIDI will be calculated as per formulae specified in the Joint Electricity Regulatory Commission for the states of Manipur and Mizoram (Standard of Performance for Distribution and Transmission Licensees) Regulations, 2010 as amended from time to time.

CHAPTER 7: RETAIL SUPPLY BUSINESS

83 Applicability

83.1 These Regulations shall apply to determination of tariff for retail supply of electricity by a Distribution Licensee to its consumers.

84 Components of Tariff

84.1 The tariff for retail supply by a Distribution Licensee shall provide for recovery of the Aggregate Revenue Requirement of the Distribution Licensee for the financial year, as approved by the Commission and comprising the following:

(i) Return on Equity;

(ii) Interest and Finance Charges on Loan Capital;

(iii) Depreciation;

(iv) Cost of own power generation /power purchase expenses;

(v) Transmission charges;

(vi) Operation and Maintenance expenses;

(vii) Interest on working capital and on consumer security deposits;

(viii) Bad debts written off, if any;

(ix) Balance Aggregate Revenue Requirement for Distribution Wires Business, as determined under Chapter 6 of these Regulations, after deducting income from wheeling charges payable by Distribution System Users other than the retail consumers getting electricity supply from the same Distribution Licensee in accordance with the Regulation 79;

minus:

(x) Non-Tariff Income;

(xi) Income from Other Business, to the extent specified in these Regulations;

(xii) Receipts on account of cross-subsidy surcharge:

Provided that the receipt of revenue on account of cross-subsidy surcharge shall be considered only at the time of truing up exercise, based on actual receipts as per Audited Accounts.

84.2 The tariff for retail supply by a Distribution Licensee shall be determined by the Commission on the basis of segregated accounts of Distribution Retail Supply Business:

Provided that where the Distribution Licensee is not able to submit audited and certified separate accounts for Distribution Wires Business and Retail Supply Business, the allocation matrix as given in Regulation 72 shall be applicable:

Provided further that the operation and maintenance expenses shall be allocated between the Distribution Wires Business and Retail Supply Business, by considering the percentages specified in the allocation matrix for employee expenses, administration and general expenses, and repair and maintenance expenses, as weights for determining the weighted average allocation percentage for operation and maintenance expenses:

Provided further that once the Commission notifies the Regulations for submission of Regulatory Accounts, the retail supply tariff of the Distribution Licensee shall be determined by the Commission on the basis of segregated accounts of Distribution Retail Supply Business.

84.3 The tariff for retail supply by the Distribution Licensee shall be determined by the Commission on the basis of an application for determination of tariff made by the Distribution Licensee in accordance with Chapter-2 of these Regulations.

84.4 The Distribution Licensee shall be allowed to offer a rebate to the consumers on 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 from time to time:

Provided further that the impact of such rebates given by the Distribution licensee shall be borne entirely by the Distribution Licensee and impact of such rebate will not be allowed to be passed through to the consumers, in any form:

Provided further 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.

85 Business Plan

85.1 The Distribution Licensee shall submit a Business Plan with full details as stipulated by the Commission from time to time, in the manner as specified in Chapter-2 of these Regulations.

86 Capital Investment Plan

86.1 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 load growth, reduction in distribution losses, increase in collection efficiency, metering, consumer services, etc., to the Commission for approval, as a part of the Business Plan.

86.2 The Distribution Licensee shall be required to ensure optimum investments to enhance efficiency, productivity and meet performance standards prescribed by the Commission.

86.3 The Distribution licensee shall submit the Capital Investment Plan as specified in Chapter-2 of these Regulations.

87 Capital Cost

87.1 The approved Business Plan of the Distribution Licensee shall be the basis for determining the annual allowable capital cost for each financial year for any capital expenditure project initiated on or after April 1, 2015.

87.2 For each capital expenditure project, the sum total of allowable capital cost from the date of commencement of such project till the date of commissioning shall be the original cost of such project.

87.3 The capital cost shall be allowed as provided in Regulation 23.

88 Sales forecast

88.1 The Distribution Licensee shall submit a 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 Business Plan, as specified in these Regulations.

88.2 The Distribution Licensee shall submit the application for determination of tariff, based on the approved sales forecast in the Order on Business Plan.

88.3 The sales forecast shall be consistent with the load forecast prepared as part of the long-term power procurement plan submitted as a part of Business Plan under 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.

89 Calculation of Aggregate Revenue Requirement

89.1 Return on Equity:

The Distribution Licensee shall be allowed a return on equity for Retail Supply Business, as specified in Regulation 26 of these Regulations.

89.2 Interest and Finance Charges on Loan Capital:

The Distribution Licensee shall be allowed Interest and Finance Charges on loan capital for Retail Supply Business, as specified in Regulation 27 of these Regulations.

89.3 Depreciation:

The Distribution Licensee shall be permitted to recover depreciation on the value of fixed assets used in the Retail Supply Business, as specified in Regulation 28 of these Regulations.

89.4 Cost of power generation/power purchase:

The Distribution Licensee shall be allowed to recover the cost of power generated by the Generation Business or purchased from approved sources for supply to consumers based on the power procurement plan of the Distribution Licensee, approved by the Commission.

89.5 Transmission charges:

The Distribution Licensee shall be allowed to recover transmission charges payable for access to and use of the intra-State transmission system in accordance with the tariff approved by the Commission under Chapter-5 of these Regulations.

89.6 Operation and Maintenance expenses:

(ii) The average of such operation and maintenance expenses shall be considered as operation and maintenance expenses for the financial year ended March 31, 2013 and shall be escalated at the escalation factor of 4% to arrive at operation and maintenance expenses for FY 2015-16.

(iii) The O&M expenses for each subsequent year will be determined by escalating the base expenses determined above for FY 2015-16, at the escalation factor of 5.72 % to arrive at permissible O&M expenses for each year of the Control Period:

89.7 Interest on Working Capital:

The Distribution Licensee shall be allowed interest on the estimated level of working capital for the Retail Supply Business, as specified in Regulation 29 of these Regulations.

89.8 Bad debts written off:

The Commission may allow bad debts written off as a pass through in the aggregate revenue requirement, subject to prudence check.

90 Non-Tariff Income

90.1 The amount of Non-Tariff Income relating to the Retail Supply of electricity as approved by the Commission 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 submit full details of his forecast of Non-Tariff Income to the Commission along with his application for determination of tariff.

The indicative list of various heads to be considered for Non-Tariff Income shall be as under:

a) Income from rent of land or buildings or poles;

b) Income from sale of scrap;

c) Income from statutory investments;

d) Interest on delayed or deferred payment on bills;

e) Interest on advances to suppliers/contractors;

f) Rental from staff quarters;

g) Rental from contractors;

h) Income from hire charges from contactors and others;

i) Income from advertisements, etc.;

j) Meter/metering equipment/service line rentals;

k) Service charges;

l) Customer charges;

m) Revenue from late payment surcharge;

n) Recovery for theft and pilferage of energy;

o) Miscellaneous receipts;

p) Prior period income;

q) Income from testing fees/charges;

r) Income from departmental/agency charge for execution of deposit work;

s) Income from sale of tender document;

t) Income from usage of poles/tower/earth wire etc;

v) Any other income not affected by electricity tariff;

Provided that the interest earned from investments made out of Return on Equity corresponding to the Retail Supply Business of the Distribution Licensee shall not be included in Non-Tariff Income:

Provided further that any income earned by a Distribution Licensee by sale of power to other Distribution Licensees or to consumers as per Section 49 of the Act using the existing power purchase agreements or bulk supply capacity allocated to the Distribution Licensee’s area of supply shall be reduced from the Aggregate Revenue Requirement of the Distribution Licensee for the purpose of determination of tariff.

91 Income from Other Business

91.1 Where the Distribution Licensee has engaged in any Other Business, an amount equal to one-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 tariff from 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 Distribution Business and the Other Business and shall submit the Allocation Statement, duly audited and certified by the statutory auditors, to the Commission along with his application for determination of tariff;

Provided further that where the sum total of the direct and indirect costs of such Other Business exceed the revenues from such Other Business, no amount shall be allowed to be added to the Aggregate Revenue Requirement of the Distribution Licensee on account of such Other Business:

Provided further that nothing contained in these Regulations shall apply to a local authority engaged, before the commencement of the Act, in the business of distribution of electricity.

92 Receipts on account of cross-subsidy surcharge

92.1 The amount received by the Distribution Licensee by way of cross-subsidy surcharge, as approved by the Commission in accordance with the Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and Conditions for Open Access) Regulations, 2010 as applicable and as amended from time to time, shall be deducted from the Aggregate Revenue Requirement in calculating the tariff for retail supply of electricity by such Distribution Licensee, at the time of truing up.

93 Distribution Losses

93.1 The Distribution Licensee shall recover the approved level of distribution losses arising from the Retail Supply of electricity:

Provided that the Commission may stipulate a trajectory for distribution losses for Retail Supply of electricity in accordance with these Regulations as part of the Order on the Business Plan filed by the Distribution Licensee:

Provided further that any variation between the actual level of distribution losses and the approved level shall be dealt with, as part of the Truing up exercise.

CHAPTER 8: MISCELLANEOUS

94. Power to remove difficulties

If any difficulty arises in giving effect to any of the provisions of these regulations, the Commission may, by general or special order, do or undertake or direct the licensees to do or undertake things, which in the opinion of the Commission is necessary or expedient for the purpose of removing the difficulties.

95 Deviation from norms

95.1 Tariff for sale of electricity by a generating company may also be determined in deviation of the norms specified in these Regulations subject to the conditions that:

(i) The overall per unit tariff of electricity over the entire life of the asset, calculated on the basis of the norms in deviation does not exceed the per unit tariff calculated on the basis of the norms specified in these Regulations; and

(ii) Any such deviation shall come into effect only after approval by the Commission.

96. Power to Amend

The Commission may, at any time add, vary, alter, modify or amend any provisions of these regulations.

97. Power of relaxation

The Commission may in public interest and for reason recorded in writing, relax any of the provision of these regulations

98. Interpretation

If a question arises relating to the interpretation of the provisions of these regulations, the decision of the Commission shall be final.

99. Review of Regulations

The Commission at the end of five years from the date of publishing these regulations or even earlier, if considered just, proper and desirable by it considering the circumstances then prevailing shall undertake a comprehensive review of these regulations with the objective of improvement in the principles, procedures and methodologies.

100. Savings

(i) Nothing in these regulations shall be deemed to limit or otherwise affect the inherent power of the Commission to make such orders as may be necessary for ends of justice to meet or to prevent abuses of the process of the Commission.

(ii) Nothing in these regulations shall bar the Commission from adopting, in conformity with the provisions of the Act, a procedure, which is at variance with any of the provisions of these regulations, if the Commission, in view of the special circumstances of a matter or class of matters and for reasons to be recorded in writing, deems it necessary or expedient for dealing with such a matter or class of matters.

(iii) Nothing in these regulations shall, expressly or impliedly, bar the Commission dealing with any matter or exercising any power under the Act for which no regulations or codes have been framed, and the Commission may deal with such matters, powers and functions in a manner it thinks fit in the public interest.

(vi) Notwithstanding such repeal, any proceedings before the Commission pertaining to the period prior to the commencement of the Control Period, including Petitions for True up of expenses, annual performance review, etc, shall be governed by the “Joint Electricity Regulatory Commission for Manipur and Mizoram (Terms and conditions for determination of Tariff) Regulations, 2010.”

101. Sharing of CDM Benefits. The proceeds of carbon credit from approved CDM project shall be shared in the following manner, namely –

(i) 100% of the gross proceeds on account of CDM to be retained by the project developer in the first year after the date of commercial operation of the generating station or the transmission system, as the case may be;

(ii) in the second year, the share of the beneficiaries shall be 10% which shall be progressively increased by 10% every year till it reaches 50%, where after the proceeds shall be shared in equal proportion, by the generating company or the transmission licensee, as the case may be, and the beneficiaries.

By Order of the Commission

Sd/- RICHARD ZOTHANKIMA

Assistant Secretary

Annexure I

Depreciation Schedule

Sl. No	Asset Particulars	Useful life (Years)	Depreciation (Straight line) (%)
A	Land under full ownership	Infinite	0
B	Land under lease
(a)	for investment in the land	The period of lease or the period remaining unexpired on the Assignment of the lease	0
(b)	for cost of clearing the site	The period of lease remaining unexpired at the date of clearing the date	0
C	Assets purchased new
(a)	Plant and Machinery in generating plants
(i)	Hydro electric	35	5.28%
(ii)	Coal based and WHRB based thermal plants	25	5.28%
(iii)	Diesel electric and gas plant	15	6.33%
(b)	Cooling towers & Circulating Water Systems	25	5.28%
(c)	Hydraulic works forming part of the Hydro-electric project
(i)	Dams, Spillways, Weirs, Canals, Reinforced concrete flumes and siphons	50	5.28%
(ii)	Reinforced concrete pipelines and surge tanks, steel pipelines, sluice gates, steel surge tanks, hydraulic control valves and hydraulic works	35	5.28%

Sl. No	Asset Particulars	Useful life (Years)	Depreciation (Straight line) (%)
D	Building & Civil Engineering works of a permanent character, not mentioned above
(i)	Offices and showrooms	50	3.34%
(ii)	Containing thermo- electric generating plant	25	3.34%
(iii)	Containing hydro-electric generating plant	35	3.34%
(iv)	Temporary erections such as wooden structures	-	100%
(v)	Roads other than Kutcha roads	50	3.34%
(vi)	Others	50	3.34%
E	Transformers, Transformer Kiosk, Sub-Station equipment & other fixed apparatus (including plant foundations)
(i)	Transformers including foundations having rating of 100 KVA and over	25	5.28%
(ii)	Others	25	5.28%
F	Switchgear including cable connections	25	5.28%
G	Lightning arrestors:
(i)	Station type	25	5.28%
(ii)	Pole type	15	6.33%
(iii)	Synchronous condenser	35	5.28%
H	Batteries	5	18.0%
I	Underground cable including joint boxes and disconnected boxes	35	5.28%
J	Cable duct system	50	5.28%
K	Overhead lines including supports
(i)	Lines on fabricated steel towers operating at nominal voltages higher than 66 KV	35	5.28%

Sl. No	Asset Particulars	Useful life (Years)	Depreciation (Straight line) (%)
(ii)	Lines on steel supports operating at nominal voltages higher than 13.2 KV but not exceeding 66 KV	25	5.28%
(iii)	Lines on steel or reinforced concrete supports	25	5.28%
(iv)	Lines on treated wood supports	25	5.28%
L	Meters	15	6.33%
M	Self propelled vehicles	5	18.00%
N	Air Conditioning Plants
(i)	Static	15	6.33%
(ii)	Portable	5	18.00%
O	Office equipments
(i)	Office furniture and furnishing	15	6.33%
(ii)	Office equipment	15	6.33%
(iii)	Internal wiring including fittings and apparatus	15	6.33%
(iv)	Street Light fittings	15	6.33%
P	Apparatus let on hire
(i)	Other than motors	5	18.00%
(ii)	Motors	15	6.33%
Q	Communication equipment
(i)	Radio and high frequency carrier system	15	6.33%
(ii)	Telephone lines and telephones	15	6.33%
R	IT equipments	6	15.00%
S	Any other assets not covered above	15	6.33%

Annexure II

Procedure for calculation of Transmission System Availability

1. Transmission system availability factor for a calendar month (TAFM) shall be calculated by the respective Transmission Licensee certified by the SLDC, separately for each AC and HVDC transmission system and grouped according to sharing of transmission charges.

2. TAFM, in percent, shall be equal to (100 – 100 x NAFM), where NAFM is the non- availability factor in per unit for the month, for the transmission system / sub- system.

3. NAFM for A.C. systems / sub-systems shall be calculated as follows :

L T

NAFM = [ å (OH 1 x Cktkm1 x NSC1) + å (OH t x MVAt x2.5)

l=1 t=1

R L

+å (OH r x MVAR r x 4)] ÷ THM x [ å (Cktkm 1 x NSC 1)

r=1 l=1

T R

+å (MVA t x 2.5) + å (MVAR r x 4)]

t=1 r=1

Where:

l = identifies a transmission line circuit t identifies a transformer / ICT

r = identifies a bus reactor, switchable line reactor or SVC

L = total number of line circuits

T = total number of transformers and ICTs

R = total number of bus reactor, switchable line reactor and SVC

OH = Outage hours or hours of non-availability in the month, excluding the duration of outages not attributable to the Transmission Licensee, if any, as per clause (5)

Ckt km = Length of a transmission line circuit in km

NSC = Number of sub-conductors per phase

MVA = MVA rating of a transformer / ICT

MVAR = MVAR rating of a bus reactor, switchable line reactor or an SVC (in which case it would be the sum of inductive and capacitive capabilities)

THM = Total hours in the month

4. NAFM for each HVDC system shall be calculated separately, as follows :

NAFM = [ Σ (TCR x hours) ] ÷ [ THM x RC ]

Where,

TCR = Transmission capability reduction of the system in MW

RC = Rated capacity of the system in MW.

For the above purpose, the HVDC terminals and directly associated EHV / HVDC lines of an HVDC system shall be taken as one integrated system.

5. The transmission elements under outage due to following reasons shall be deemed to be available:

(i) Shut down availed for maintenance or construction of elements of another transmission scheme. If the other transmission scheme belongs to the Transmission Licensee, SLDC may restrict the deemed availability period to that considered reasonable for the work involved.

(ii) Switching off of a transmission line to restrict over voltage and manual tripping of switched reactors as per the directions of SLDC.

6. Outage time of transmission elements for the following contingencies shall be excluded from the total time of the element under period of consideration.

(i) Outage of elements due to acts of God and force majeure events beyond the control of the Transmission Licensee. However, onus of satisfying the SLDC that element outage was due to aforesaid events and not due to design failure shall rest with the Transmission Licensee. A reasonable restoration time for the element shall be considered by SLDC and any additional time taken by the Transmission Licensee for restoration of the element beyond the reasonable time shall be treated as outage time attributable to the Transmission Licensee. SLDC may consult the Transmission Licensee or any expert for estimation of reasonable restoration time. Circuits restored through ERS (Emergency Restoration System) shall be considered as available.

Outage caused by grid incident/disturbance not attributable to the Transmission Licensee, e.g. faults in substation or bays owned by other agency causing outage of the transmission licensee’s elements, and tripping of lines, ICTs, HVDC, etc. due to grid disturbance. However, if the element is not restored on receipt of direction from SLDC while normalizing the system following grid incident/disturbance within reasonable time, the element shall be considered not available for the period of outage after issuance of SLDCâ€Ÿs direction for restoration.

Annexure III

Timeline for completion of Projects

1. The completion time schedule shall be reckoned from the date of investment approval by the Board (of the Generating Company), up to the date of commercial operation of the Units or Block.

2. The time schedule has been indicated in months in the following paragraphs and tables:

A. Thermal Power Projects:

Coal/Lignite Power Plant:

Unit size 200/210/250/300/330 MW and 125 MW CFBC technologies:

1. 33 months for first Unit of green field projects. Subsequent Units at an interval of 4 months each.

2. 31 months for first Unit of extension projects. Subsequent Units at an interval of 4 months each.

Unit size 250 MW CFBC technology:

1. 36 months for first Unit of green field projects. Subsequent Units at an interval of 4 months each.

2. 34 months for first Unit of extension projects. Subsequent Units at an interval of 4 months each.

Unit size 500/600 MW:

1. 44 months for first Unit of green field projects. Subsequent Units at an interval of 6 months each.

2. 42 months for first Unit of extension projects. Subsequent Units at an interval of 6 months each.

Unit size 660/800 MW:

1. 52 months for first Unit of green field projects. Subsequent Units at an interval of 6 months each.

2. 50 months for first Unit of extension projects. Subsequent Units at an interval of 6 months each.

Combined Cycle Power Plant:

Gas Turbine size upto 100 MW (ISO rating):

1. 26 months for first Block of green field projects. Subsequent Blocks at an interval of 2 months each.

2. 24 months for first Block of extension projects. Subsequent Blocks at an interval of 2 months each.

Gas Turbine size above 100 MW (ISO rating):

1. 30 months for first Block of green field projects. Subsequent Blocks at an interval of 4 months each.

2. 28 months for first Block of extension projects. Subsequent Blocks at an interval of 4 months each.

B. Hydro Electric Projects:

The completion time schedule for hydro electric projects shall be as stated in the original concurrence issued by the Central Electricity Authority under Section 8 of the Act.

JERC for M&M (Multi Year Tariff) Regulations, 2014 (Notified on 9.6.2014)

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