Terms and Conditions for… Bare Act

The source publishes this enactment as a single document rather than provision by provision, so the whole text is below and there are no per-section pages for it. Nothing has been shortened.

Type	Regulations
Year	2003
Jurisdiction	State of Bihar
Status	In force as published by the source
Text	Published as one document, as the source published it
Subjects	environment

1 REGISTERED NO. PT-40 7 VAISHAKHA 1929 (S) (NO. PATNA 426) PATNA, FRIDAY 27TH APRIL 2007 BIHAR ELECTRICITY REGULATORY COMMISSION, PATNA TERMS AND CONDITIONS FOR DETERMINATION OF TARIFF NOTIFICATION The 24th April 2007 No. BERC/Regl-10/06-2/2007 – In exercise of the powers conferred under section 181 read with sections 45(2), 61 and 62 of the Electricity Act, 2003 (36 of 2003) and all powers enabling it in that behalf, the Bihar Electricity Regulatory Commission hereby makes the following regulations for prescribing the terms and conditions for determination of Tariff, namely:

Chapter 1 General

1. Short title and commencement

(1) These regulations shall be called the Bihar Electricity Regulatory Commission (Terms and conditions for determination of Tariff) Regulations, 2007.

(2) These regulations shall come into force from the date of publication in the official gazette.

2. Scope and extent of application

(1) Where tariff for generation and transmission has been determined through transparent process of bidding in accordance with the guidelines issued by the Central Government, the Commission shall adopt such tariff in accordance with the provisions of the Act.

(2) These regulations shall be applicable in all other cases.

Provided that the Commission may prescribe the relaxed norms of operation, including the norms of target availability and Plant Load Factor as well as lower return on equity, than those contained in these regulations for a generating station, transmission system and distribution system under the control of an integrated utility or a generating company or transmission licensee or distribution licensee, for determination of tariff.

3. Definitions

(1) In these regulations unless the context otherwise requires:-

(i) ‘Act’ means Electricity Act 2003 (36 of 2003) as amended from time to time;

(ii) ‘Authority’ means Central Electricity Authority constituted under Section 70 of the Electricity Act 2003;

(iii) ‘Combined average unit cost of supply’ means the total Revenue Requirement for the year adjusted by the revenue gaps of the previous years divided by the total energy sold during the year;

(iv) ‘Commission’ means Bihar Electricity Regulatory Commission constituted by the State Government (under section 82 of the Act);

(v) ‘Control Period’ means the period before which the long term tariff principles for distribution entities takes effect.

(vi) ‘Current year’ means the year in which petition for determination of tariff is filed;

(vii) ‘Force Majeure Event’ means event beyond the control of the integrated utility or generating company or the licensee, including and not limited to, earthquake, cyclone, flood, storm, war, terrorist attack, civil commotion or similar other such occurrence that may lead to any act that would involve a breach of relevant provisions in laws or regulations;

(viii) ‘FPPCA’ means Fuel and Power Purchase Cost Adjustment;]

(ix) ‘Integrated utility’ means the Bihar State Electricity Board in its present form or the successor entity of the Board performing one or more of the functions of generation, transmission, distribution and trading after restructuring of the Board;

1. Sl.Nos. "(viii), (xiii), (xiv)" of Regulation 3(1) are inserted by the BERC (Terms and Conditions for Determination of Tariff) [1st Amendment] Regulations, 2012 vide Bihar Gazette No. 452 dated 3rd September, 2012 (w.e.f. 03.09.2012) 3

(x) ‘Licensee’ means a person who has been granted a license under section 14 of the Act;

(xi) ‘Regulations’ means Regulations for determination of Tariff notified by the Bihar Electricity Regulatory Commission contained in these Regulations.

(xii) ‘State Government’ means Government of Bihar;

(xiii) ‘Schedule’ refers to the schedule appended to these Regulations;]

(xiv) ‘Secretary’ means Secretary of the Bihar Electricity Regulatory Commission;]

(xv) ‘Tariff’ means schedule of charges for generation, transmission, distribution and trading of electricity as well as various charges for providing open access of electricity, as determined by the Commission from time to time;

(xvi) ‘Year’ means financial year;

(2) The words and expressions, specifically applicable to various functions such as generation, transmission, distribution etc have been defined in the respective chapters detailed hereunder;

(3) Words and expressions not defined in these regulations but defined in the Act shall have the meaning assigned to them under the Act.

4. Guidelines for determination of tariffs:

The Commission shall be guided in determination of tariff by the following:

(1) The principles and guidelines specified by the Central Electricity Regulatory Commission for determination of tariff applicable to an integrated utility or generating company or transmission licensee from time to time.

(2) National Electricity Policy and Tariff Policy as laid down by the Government of India.

(3) Guidelines laid down in Section 61 of the Electricity Act, 2003.

5. Application for determination of tariff

(1) An integrated utility or a generating company or a transmission licensee, or a distribution licensee, as the case may be, may make an application before the Commission for determination of tariff in respect of completed units of the generating stations, the lines / sub stations of the transmission system or for the areas of supply for the distribution system.

(2) In the case of existing generating station or the existing transmission system, the integrated utility or generating company or the transmission 1[ 1[ 4 licensee, as the case may be shall make an application for determination of tariff as per the formats given in Appendices A to C to these Regulations. For distribution licensee, these shall be as per the ARR formats given in Appendix D to these Regulations. The Commission may make appropriate modifications from time to time in the formats, as it deems fit.

(3) (a) In case of a generating station or a transmission system or part thereof declared under commercial operation on or after the notified date of these Regulations an application for determination of tariff shall made in two stages, namely:

Stage I: An integrated utility or a generating company or a transmission licensee may make an application as per the formats specified by the Commission for determination of provisional tariff in advance of the anticipated date of completion of the project based on the capital expenditure actually incurred upto the end of the month preceeding to the date of making of the application, accompanied by annual accounts of the financial year ending prior to the date of application duly audited and certified by the statutory auditors, and the provisional tariff shall be charged from the date of commercial operation of the respective unit of the generating station or the transmission system.

Stage II: An integrated utility or a generating company or a transmission licensee shall make a fresh application in the same format, as above, for determination of final tariff based on the actual capital expenditure incurred upto the date of commercial operation of the generating station or the transmission system, duly audited and certified by the statutory auditors.

(b) An integrated utility or a distribution licensee shall file the Annual Revenue Requirement (ARR) only once in a year before the Commission during the control period.

6. Procedure for filing application

(1) An application shall be filed before the Commission in the prescribed formats for determination of tariff by:

(i) the integrated utility or generating company as in Appendices A and B.

(ii) the integrated utility or transmission licensee as in Appendix C.

(iii) the integrated utility or distribution licensee in Annual Revenue Requirement format in *Appendix D.

* All 34 Formats of Appendix D have been deleted and appended to BERC (Multi Year Distribution Tariff) Regulations, 2015 notified vide Bihar Gazette No. 1046 dt.

15.09.20151 (w.e.f. 15.09.2015) 5

(2) Each application shall be accompanied by such fee as may be prescribed by the Commission from time to time.

(3) The application shall be sent by registered post Ack due or by Hand delivery.

(4) The application shall be supported with an affidavit by an authorised person or a person, who is acquainted with all facts, stated in the application

(5) The applicant shall publish the application in such abridged form and manner as may be specified by the Commission, inviting suggestions/objections/comments thereon from general public and stakeholders in at least two daily newspapers, one in English and another in Hindi language having wide circulation in the area of supply on the dates specified by the Commission. The applicant shall also submit within 7 days of publication of the notice an affidavit to the Commission with details of the notice and also file copies of the newspapers wherein the notice has been published.

(6) All suggestions / objections in response to the public notice shall be sent to the Secretary of the Commission at its headquarters office with a copy to the applicant.

(7) The applicant shall file his comments / remarks on the suggestions / objections received, if any, within 10 days from the last date of receipt of such suggestions/objections.

(8) The distribution licensee shall file ARR along with date in prescribed formats as given in Appendix-D of these Regulations for each financial year by 15th November of proceeding year.

7. Core business For the purpose of these regulations, core business means the regulated activities of generation or any regulated business as per section 12 of the Act and does not include any other business or activity of an integrated utility or a generating company or a transmission licensee or a distribution licensee.

8. Tariff determination

(1) Tariff in respect of a generating station under these regulations shall be determined stage – wise, unit – wise or for the whole generating station and tariff for the transmission shall be determined line – wise, unit – wise, sub station – wise and system – wise, as the case may be, and these may be aggregated to stage – level tariff. For distribution licensee, the tariff shall be set for the entire licensed area on an aggregated basis for each class of consumer.

(2) For the purpose of determination of tariff, the capital cost of generation / transmission project shall be broken up into stages and by distinct units forming part of the project. Where the stage – wise, unit – wise, line – wise or substation –wise breakup of the capital cost of the project is not available and in case of on – going projects, common facilities shall be apportioned on the basis of the installed capacity of the units and lines or sub stations. In the case of multi – purpose hydro – electric projects with irrigation, flood control etc, the power component of the project only shall be considered for determination of tariff.

Note: The term “Project” includes a generating station and/or the transmission system.

9. Norms of operation The norms of operation specified in these regulations shall be the norms to be made applicable and these shall not preclude the integrated utility or generating company or the transmission licensee or distribution licensee, as the case may be, and the beneficiaries from agreeing to improved norms of operation and in case the improved norms are agreed to, such improved norms shall be applicable for the determination of tariff.

(1) The Commission may decide to defer from the normative parameters or extend the deadline of the implementation of the given normative parameters on a case to case basis for existing plants due to mix of vintage, size, technology (eg. old technology, CFBC technology etc) fuel grades, site specific conditions etc that might have a bearing on the efficiency of the unit. The Commission shall review the past operations in detail while providing any relaxation. The Commission shall provide the relaxation on a time bound basis provided the unit can outline a road map to boost its efficiency.

10. Deviation from norms The tariff for sale of electricity by an integrated utility or a generating company may also be fixed in deviation of the norms specified in these regulations subject to the conditions that:

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

(ii) Any such deviation shall come into effect from the date of approval by the Commission.

11. Multi year Tariff principles and guidelines

(1) The Commission may adopt multiyear tariff principles for matters relating to calculation of revenue requirements and tariff determination of the integrated utility / generating company and licensees including extent of investment, reduction of loss levels, other efficiency gains, revision in charges, changes in tariff structure and such other matters as the Commission may by general or special order direct.

The Commission shall fix, as and when it considers appropriate, a date for adoption of the MYT principles.

(2) The Commission may, as and when it considers appropriate, issue guidelines for filing Revenue Requirement and Tariff Proposals for a period in excess of a financial year and unless waived by the Commission, an integrated utility / a generating company shall follow such guidelines issued by the Commission.

12. Charging of permissible tariff An integrated utility / a generating company or a licensee shall not charge tariff in excess of the tariff fixed by the Commission. If any integrated utility or a generating company or a licensee recovers a price or charge exceeding the tariff determined by the Commission, the excess amount shall be recoverable by the person who has paid such price or charge along with interest equivalent to the Bank rate without prejudice to any other liability incurred by the integrated utility or generating company or licensee.

13. Excess or under recovery with respect to norms / targets

(1) The generating company or the licensee, as the case may be, shall retain the entire gain arising from over achievement of the norms / targets laid down by the Commission from time to time.

(2) The generating company or the licensee, as the case may be, shall bear the entire loss an account of its failure to achieve the norms / targets laid down by the Commission from time to time.

14. Cross Subsidy

(1) The cross subsidy for a consumer category means the difference between the average per unit rate based on tariff schedule of the Commission for that category and the combined average cost of supply per unit expressed in percentage terms as a portion of the combined average cost of supply.

(2) In the first phase, the Commission shall determine the tariff so that it progressively reflects the combined average cost of supply of electricity and also reduce and eliminate cross subsidies within a reasonable period. In 8 the second phase, the Commission shall consider moving towards category – wise cost of supply as a basis for determination of tariff.

15. Subsidy

(1) The State Government may, at any time as it considers appropriate, propose any subsidy to any consumer or classes of consumers in the tariff determined or to be determined by the Commission under Section 62 of the Act, the State Government shall, notwithstanding any direction which may be given under Section 108 of the Act, pay, in advance and in such manner as may be specified, the amount to compensate the licensee affected by the grant of subsidy in the manner and terms and conditions for such payment of subsidy as the Commission may direct. The State Government shall send a proposal for this purpose to the Commission.

(2) If the payment of subsidy is not made by the State Government in accordance with the provisions contained in section 65 of the Act, the amount, which the State Government has failed to pay, shall be added in the tariff and charged to the concerned class or classes of consumers.

(3) The Distribution licensee shall furnish the required information to the Commission that the subsidy amount received by it from the State Government has been duly accounted for and utilised for the purpose for which the subsidy is received.

16. Tax on income

(1) Tax on income of an integrated utility or a generating company or the transmission licensee or the distribution licensee, as the case may be, from its core business, shall be computed as an expense and shall be recovered from the beneficiaries or consumers.

(2) 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 Income Tax Act, 1961, as certified by the statutory auditors. An integrated utility or the generating company or the transmission licensee / distribution licensee, as the case may be, may make such adjustments directly.

Provided that

(i) tax on any income, other than core business, shall not constitute a pass through component in tariff and the tax on such other income shall be borne by the integrated utility or generating company or the transmission / distribution licensee, as the case may be.

(ii) the generating station–wise profit before tax in the case of integrated utility or the generating company, and the area of supply–wise profit before tax for the transmission and distribution licensee respectively estimated for a year in advance shall constitute the basis for distribution of the corporate tax liability to all the generating stations and the transmission and distribution licensees respectively.

(iii) the benefit of tax – holiday as applicable in accordance with provisions of Income Tax Act, 1961 shall be passed on to the beneficiaries.

(iv) in the absence of any equitable basis, the credit for carry forward losses and unabsorbed depreciation shall be given in the proportion as provided in sub clause (ii) above.

(v) income – tax allocated to the thermal generating station shall be charged to the beneficiaries in the same proportion as annual fixed charges; income tax allocated to the hydro – generating station shall be charged to the beneficiaries in the same proportion as annual capacity charges and in the case of intra-state transmission, the sharing of income – tax shall be in the same proportion as annual transmission charges.

17. Extra Rupee Liability Extra rupee liability towards interest payment and loan repayment corresponding to the normative foreign debt and actual foreign debt, as the case may be, in the relevant year shall be permissible provided it arises directly due to Foreign Exchange Rate Variation. The integrated utility or the generating company or the transmission license / or distribution licensee shall recover the foreign exchange rate variation on a year to year basis as income or expense for the period in which it arises.

18. Decision of the Commission The Commission shall, after considering the suggestions / objections received in response to the public notice, and the comments / remarks of the applicant thereon.

(i) issue a tariff order accepting the application with such modification or such conditions as it may consider appropriate after giving an opportunity of hearing to the applicant, the beneficiary or any person who has filed objections / suggestion or any one or more of them, if so required, before issue of tariff order.

(ii) reject the application for reasons to be recorded in writing, if the application is not in accordance with these regulations, or the Act, the 10 rules and regulations made thereunder or a provision of any other law in force. The applicant shall be given an opportunity of being heard before rejecting the application.

19. Hearing and communication of decision of the Commission on Tariff The Commission shall initiate a proceeding on the revenue calculations and tariff proposals given by the Transmission or Distribution licensee and hold public hearing(s) to decide on such revenue calculations and tariff proposals.

Considering the proceedings of the hearing(s) as well as suggestions/objections received in response to the public notice, the Commission shall issue an order communicating its decision on the revenue calculations and Tariff proposals to the Transmission or Distribution licensee, as the case may be. The Commission shall forward within 7 days of making the order, a copy of the order to the State Government, the Central Electricity Authority, the concerned licensees and other authorities, as may be necessary.

20. Tariff publication

(1) While issuing an order as above or at any time thereafter, the Commission shall direct the Licensee for the publication of tariff determined by it, which the Transmission or Distribution Licensee shall charge from the different consumers/customers or categories thereof in the ensuing period determined by it.

(2) The Transmission/Distribution licensee shall publish the tariff, approved by the Commission in the newspapers at least in two newspapers on in English and other in Hindi language having wide circulation in its area of supply in the form and manner as directed by the Commission.

(3) The tariff as determined shall take effect from the date as given in the order of the Commission.

21. Periodicity of tariff determination and revision thereof

(1) No tariff or any part thereof shall ordinarily be amended more frequently than once in any financial year, except in respect of any charges expressly permitted under the terms of the Fuel and Power Purchase Cost Adjustment formula as specified in the Schedule appended to these Regulations.]

(2) The orders, which the Commission may issue to give effect to the subsidy which the State Government may grant from time to time, shall not be construed as amendment to tariff. The Distribution licensee shall make appropriate adjustments for the subsidy amount as the Commission may direct.

2. Substituted Regulation 21(1) by the BERC (Terms and Conditions for Determination of Tariff) [1st Amendment] Regulations, 2012 vide Bihar Gazette No. 452 dated 3rd September, 2012 (w.e.f. 03.09.2012) 11

22. Review and Truing up

(1) The Commission shall undertake a review along with next Tariff Order, of the expenses and revenues approved by the Commission in the current year Tariff Order. While doing so, the Commission shall consider variations between approvals and revised estimates / pre-actuals of the sale of electricity, income and expenditure for the relevant year and permit necessary adjustments / changes in case such variations are for adequate and justifiable reasons. Such an exercise shall be called ‘Review’.

(2) After audited accounts of the year are made available, the Commission shall undertake a similar exercise as in sub-clause (1) above based on the final actual figures as per the audited accounts. This exercise based on the audited accounts shall be called ‘Truing up’.

The truing up exercise for any year shall not ordinarily be considered after more than one year gap after ‘Review’.

(3) The Revenue gap of next year shall be adjusted as a result of Review and Truing up exercises.

(4) While approving adjustments towards revenue / expenses in future years, arising out of Review / Truing up exercises, the Commission may allow the carrying costs as determined by the Commission of such expenses / revenues, Carrying costs shall be limited to the interest rate approved for working capital borrowings.

(5) For any revision of approvals, the licensee shall satisfy the Commission that the revision is necessary for the reasons beyond its control. In case additional supply is required to be made to any particular category, the licensee may, at any time during the year, make an application to the Commission for its approval, duly explaining the need for such change of consumer mix and additional supply of power and also indicating the manner in which the licensee proposes to meet the cost for such change of consumer mix and additional supply of power.

The Commission may consider according approval to such proposals provided the cost of additional supply of power is met by the beneficiary category.

23. Objection for recovery of income – tax and foreign exchange rate variation In case of any objection from the beneficiaries or the consumers for the recovery / adjustment as in Regulation 16(2)(i) above, the integrated utility or generating company or the transmission / distribution licensee, as the case may be, may make an application to the Commission for a decision.

24. Regulatory Asset In extraordinary circumstances, the Commission may allow creation of regulatory Asset in case the Revenue gap is very substantial and is on account of one-time factor beyond the control of the integrated utility or generating company or the licensee and its full recovery in a single year will result in tariff shock to consumers. The Regulatory Asset so created along with carrying cost shall be liquidated in a maximum of 3 years’ period immediately following the year in which it is created.

25. Tariff of Electricity Trader

(1) The Commission shall approve the tariff for Power Purchase and procurement by the Distribution licensee from the Electricity Trader. On such approval by the Commission, the Electricity Trader shall be entitled to sell electricity to the Distribution licensee subject to the terms and conditions of the Power Purchase Agreement approved by the Commission.

(2) The Commission shall, from time to time, fix the trading margin of the Electricity Trader for intra – state trading in electricity in the State of Bihar. The sale of electricity by the Electricity Trader shall be subject to such further terms and conditions as may be laid down by the Commission for the purpose from time to time.

26. Generation Tariff

(1) The Commission may approve the tariff for the power purchase except central sector and procurement by the Distribution licensee from the integrated utility or a generating company. On such approval by the Commission, the integrated utility or the generating company shall be entitled to sell the energy to a Distribution licensee as per the tariff and the terms and conditions contained in the Power Purchase Agreement approved by the Commission.

(2) In cases, other than those covered under clause (1) above, the integrated utility or a generating company may file an application before the Commission for determination of tariff for electricity generated by it for the sale of electricity in the State of Bihar giving details of the fixed and variable costs associated with the generation.

(3) The application by an integrated utility or a generating company under clause (2) above may be filed for determination of tariff for sale of electricity to any specific purchaser, including Distribution Licensee or to more than one purchaser or for general sale who may desire to purchase from it.

(4) The Commission may determine the tariff for sale of electricity by an integrated utility or generating company, which may thereafter enter into agreements for the sale based on the tariff determined and subject to the terms and conditions laid down by the Commission.

(5) The determination of tariff for generation, under this regulation shall not entitle an integrated utility or the generating company to sell energy to the Distribution licensee on long term or on short term basis except in accordance with the Power Purchase Agreement or procurement to be finalised by the Distribution licensee subject to the terms and conditions which the Commission may lay down for the purpose from time to time.

27. Right to vary terms and conditions The terms and conditions for determination of tariff specified in these regulations are in the nature of general framework on the basis of which the tariff shall be determined. The Commission reserves its right to vary these terms and conditions, as and when deems fit.

28. Power to remove difficulties If any difficulty arises in giving effect to these regulations, the Commission may, suo-motu or otherwise, by an order make such provisions, not inconsistent with these regulations, as it may consider appropriate for removing such difficulties.

29. Limitation of Power of Commission Nothing in these regulations shall be deemed to limit the powers of the Commission to deal with any matter or exercise any power under the relevant Acts for which no regulations have been made / framed and to make such orders as it may consider appropriate to meet the ends of justice in any case.

30. Powers to amend The Commission may, at any time as it deems fit, amend, after or modify these regulations to remove any defect or error noticed by it in performance of its functions.

Chapter 2 Thermal Power Generating Station

31. Definitions Unless the context otherwise requires for the purposes of this chapter:

(i) ‘Additional Capitalisation’ means the capital expenditure actually incurred after the date of commercial operation of a generating station and admitted by the Commission after prudent check subject to the provisions of Regulation 35;

(ii) ‘Auxiliary Energy Consumption’ or ‘Aux’ in relation to a period means the quantum of energy consumed by the auxiliary equipment of the generating station and transformer losses within the generating station which shall be expressed as a percentage of the sum of gross electrical energy generated at generator terminals of all the units of the generating station.

(iii) ‘Availability’ in relation to a generating station for any period means the average of the daily declared capacities (DCs) for all the days during the period expressed as a percentage of the installed capacity of the station minus normative auxiliary power consumption in MW and shall be computed in accordance with the following formula:

Availability = where:

IC = installed capacity of the generating station in MW DCi = Averaged declared capacity for the i th day of the period in MW N = No. of days during the period; and Aux n = Normative Auxiliary Energy Consumption as a percentage of the gross generation.

(iv) ‘Beneficiary’ in relation to generating station means the person buying the power generated at such a generating station on payment of Annual Fixed Charges.

(v) ‘Block’ in relation to a combined cycle thermal generating station includes combustion turbine generator (s), associated waste heat recovery boiler (s), connected steam turbine – generator and auxiliaries;

(vi) ‘Cut off date’ means date of the first financial year closing after one year of the date of commercial operation of the generating station.

(vii) ‘Date of Commercial Operation’ or ‘COD’, in relation to a unit, means the date declared by the integrated utility or generating company after demonstrating the “Maximum Continuous Rating” (MCR) or Installed Capacity (IC) through a successful trail run after notice to the beneficiaries; and in relation to the generating station, the date of commercial operation means the date of commercial operation of the last unit or block of the generation station.

(viii) ‘Declared Capacity’ or ‘DC’ means the capability of the generating station to deliver ex-bus electricity in MW declared by such generating N 10000 x ∑DCi NxICx(100 – Aux n) % i =1 15 station in relation to any period of the day or whole of the day, duly taking into account the availability of the fuel.

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

(ix) ‘Existing Generating Station’ means a generating station declared under Commercial Operation from a date prior to the notified date of the Tariff Regulations as per Regulation 1(2).

(x) ‘Gross Calorific Value’ or GCV in relation to a thermal power generation means the heat produced in k -Cal 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.

(xi) ‘Gross Station Heat Rate’ or ‘GHR’ means the heat energy input in k/Cal required to generate one kWh of electrical energy at generator terminal.

(xii) ‘Infirm Power’ means electricity generated prior to commercial operation of the generating unit or a generating station.

(xiii) ‘Installed Capacity ‘ or “IC” means the summation of the name plate capacities of all units of a generating station or the capacity of a generating station (reckoned at the generator terminals) as approved by the Commission from time to time.

(xiv) ‘Maximum Continuous Rating’ or ‘MCR’ in relation to a unit of a thermal power generating station means the maximum continuous out put at the generator terminals, guaranteed by the manufacturer at rated parameters; and in relation to a unit or a block of combined cycle thermal power generating station means the maximum continuous output at the generator terminals, guaranteed by the manufacturer with water / steam injection (if applicable) and corrected to 50 Hz grid frequency and specified site conditions.

(xv) ‘Operation and Maintenance Expenses’ or ‘O&M Expenses’ means the expenditure incurred on operation and maintenance of the generating station and includes expenditure on manpower, repairs, spares, consumables, utility expenses, insurance, overheads etc.

(xvi) ‘Original Project Cost’ means the actual expenditure incurred by the integrated utility / generating company as per original scope of the project upto the first financial year closing, after one year from the date of commercial operation of the last unit, as admitted by the Commission for the determination of generation tariff;

(xvii) ‘Plant Load Factor’ or ‘PLF’ for a given period means the total sent out energy corresponding to scheduled generation during the period, expressed as a percentage of sent-out energy in relation to installed capacity in that period and shall be computed in accordance with the following formula:

where IC= installed capacity of the generating station in MW SGi= Scheduled generation in MW for the i th time block of the period N = No. of time blocks during the period; and Auxn =Normative Auxiliary Energy Consumption as a percentage of the gross generation.

(xviii) ‘Project’ means generating station

(xix) ‘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 Despatch Centre.

Note: For the gas turbine generating station or a combined cycle generating station if the average frequency for any time block is below

49.52 Hz but not below 49.02 Hz and the scheduled generation is more than 98.5% of the declared capacity, the scheduled generation shall be deemed to have been reduced to 98.5% of the declared capacity and if the average frequency for any time block is below 49.02 Hz and the scheduled generation is more than 96.5% of the declared capacity, the scheduled generation shall be deemed to have been reduced to 96.5% of the declared capacity.

(xx) ‘Small Gas Turbine Power Generating Station’ means and includes gas turbine / combined cycle generating stations with gas turbine in the capacity range of 50 MW and below.

(xxi) ‘Unit’ in relation to a thermal power generating station means steam – generator, turbine generator and auxiliaries or in relation to a combined N PLF= 10000X ∑SGi i = 1 i=I NxICx(100-Auxn) % i=I 17 cycle thermal power generating station means turbine generator and auxiliaries.

32. Components of tariffs

(1) 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.

(2) The annual capacity (fixed) charges shall consist of:

(a) interest on capital

(b) Depreciation, including Advance Against Depreciation

(d) Operation and Maintenance expenses, and

(e) Interest on working capital

(3) The energy (variable) charges shall cover fuel cost

(4) Where the existing Power Purchase Agreement (including any changes, in the norms or parameters, made in the Power Purchase Agreement following renegotiation between the integrated utility and concerned generating company) lay down different parameters, such parameters shall continue to govern the parties for the term of the contract, but not for any renewal of the contract or any extension of the term of the contract subsequent to commencement of these regulations. Upon expiry of the existing term of PPA the parties shall be governed by the provisions contained in these regulations as amended from time to time.

33. Norms of Operation The norms of operation as given here under shall apply:

(1) Target availability for recovery of full capacity (fixed) charges:

(a) Tariff availability for all thermal power generating stations: 80%

(b) Recovery of capacity (fixed) charges below the level of target availability shall be on pro rata basis. At zero availability, no capacity charges shall be payable.

(2) Target Plant Load Factor for incentive:

(a) Tariff load factor for all thermal power generation stations: 80%

(b) Where the existing Power Purchase Agreement (including any changes, in the norms of parameters, made in the Power Purchase Agreement following renegotiation between the integrated utility and the concerned generating company) lay down a different parameter of PLF for the recovery of full fixed charges, such a parameter shall continue to govern the parties for the term of the contract, but not for any renewals of the contract or any extension of the term of the contract subsequent to the commencement of these 18 Regulations. Upon expiry of the term of the PPA, the parties shall be governed by the provisions of these Regulations as amended from time to time.

(3) Gross Station Heat rate:

(a) Coal based thermal power generating stations; other than those covered under sub-clause (b) and (c) below:

200/210/250 MW sets 500 MW and above sets During stabilization period 2600 K Cal / kWh 2550 K Cal / kWh Subsequent period 2500 K Cal / kWh 2450 K Cal / kWh

(i) In respect of 500 MW and above units where the boiler feed pumps are electrically operated, the gross station heat rate shall be 40 K Cal / kWh lower than the station heat rate indicated above.

(ii) For generating stations having combination of 200/210/250 MW sets and 500 MW and above sets, the normative gross station heat rate shall be the weighted average station heat rate.

For coal unit sizes smaller than 210 MW, the Commission may allow a different normative heat rate based on scrutiny of past operational performance.

(iii) Where existing Power Purchase Agreement (including any changes, in the norms of parameters, made in the Power Purchase Agreement following renegotiation between the integrated utility and the concerned generating company) lay down a different parameter of Heat Rate, such a parameter shall govern the parties for the term of the contract, but not for any renewals of the contract or any extension of the term of the contract. Upon expiry of the term of the PPA, the parties shall be governed by the provisions of these Regulations as amended from time to time.

(b) Lignite – fired power generating stations:

For lignite – fired generating stations, gross heat rates specified under sub-clause (a) above for coal based thermal power generating stations shall be completed, using multiplying factors as given below:

(i) for lignite having 50% moisture Multiplying factor of 1.10

(ii) for lignite having 40% moisture Multiplying factor of 1.07

(iii) for lignite having 30% moisture Multiplying factor of 1.04 19

(iv) for other values of moisture content, the multiplying factor shall be pro – rated for moisture content between 30-40 and 40-50 depending upon the rated values of multiplying factor for the respective range given under sub-clauses (i) to (iii) above

(i) Existing generating stations The normative heat rates shall be specified by the Commission duly studying the past performance and the performance of similar technology / size machines owned by other utilities outside the State, including Central Power Sector Units, Private Power Institutions, State Electricity Boards etc. Till the completion of the study, the normative heat rate shall be 2100 K Cal / kWh under closed cycle operation.

(ii) Generating Stations declared under commercial operation:

Advance class Machines E/EA/FC/E Class Machine Open cycle 2685 K Cal / kWh 2830 K Cal / kWh Combined cycle 1850 K Cal / kWh 1950 K Cal / kWh

(iii) Small Gas Turbine Power Generating Station: The normative heat rates shall be as specified by the Commission. For setting the normative heat rates, the Commission shall study the past performance and the performance of similar technology / size machines owned by other utilities outside the State, including Central Power Sector Units, Private Power Institutions, State Electricity Boards etc.

(4) Secondary fuel oil consumption During stabilization period Subsequent period Coal based thermal power generating stations

4.5.ml / kWh 2.0 ml / kWh Lignite fired generating stations

5.0 ml / kWh 3.0 ml / kWh Note: Where the existing Power Purchase Agreement (including any changes, in the norms of parameters, made in the Power Purchase Agreement following renegotiation between the integrated utility and the concerned generating company) lay down a different parameter for secondary fuel consumption, such a parameter shall govern the parties for the term of the contract but not for any renewal of 20 contract or any extension of the term of the contract subsequent to the commencement of these Regulations. Upon expiry of the term of the existing PPA, the parties shall be governed by the provisions of these Regulations as amended from time to time.

(5) Auxiliary Energy Consumption:

With cooling tower Without cooling tower

(a) Coal based generating stations

(i) 200 MW services

(ii) 500 MW services steam driven boiler feed pumps Electrically driven feed pumps 9%

7.5%

9.0%

8.5%

7.0%

8.5%

(b) Gas turbine / combined cycle generating stations:

(i) Combined cycle

(ii) Open cycle

3.0%

1.0%

(c) Lignite – fired power generating station The auxiliary energy consumption norms shall be 0.5% more than the above auxiliary energy consumption norms of coal – based generating stations.

1) During the stabilization period, the normative auxiliary consumption shall be reckoned at 0.5% more than the norms indicated at (a), (b) and (c) above.

2) The normative auxiliary energy consumption rates for units smaller than 210 MW shall be specified by the Commission. The Commission may study the past performance and the performance of similar technology / size machines owned by other utilities outside the state, including CPSUs, IPPs, SEBs etc.

3) Where the existing Power Purchase Agreement (including any changes, in the norms of parameters, made in the PPA following renegotiation between the integrated utility and the concerned generating company) lay down a different parameter for auxiliary consumption, such a parameter shall govern the parties for the term of the contract but not for any renewal of contract or any extension of the term of the contract subsequent to the commencement of these Regulations. Upon expiry of the term of the PPA, the parties shall be governed by the provisions of these Regulations as amended from time to time.

(6) Stabilization period: In relation to a generation unit, the stabilization period shall be reckoned commencing from the date of commercial operation of that unit, as follows, namely:

(a) Coal based and lignite fired generating stations 180 days

(b) Gas turbine / combined cycle generating stations 90 days

34. Capital Cost Subject to prudent check by the Commission, the actual expenditure incurred on completion of the project shall form the basis for the determination of final tariff. The final tariff shall be based on the admitted capital expenditure actually incurred upto the date of commercial operation of the generating station and shall include capitalised initial spares subject to following ceiling norms as a percentage of the original project cost as on the cut off date:

(i) Coal based / lignite fixed generating station 2.5%

(ii) Gas turbine / combined cycle generating station 4.0%

Provided :

(i) where the Power Purchase Agreement entered into between the generating company and the beneficiaries provides a ceiling of actual expenditure, the capital expenditure shall not exceed such a ceiling for determination of tariff.

(ii) in case of existing generating station, the capital cost admitted by the Commission prior to the notified date of these regulations as per Regulation 1(2) of these Regulations shall form the basis for determination of tariff. The capital cost of the unbundled generating stations shall be the asset value as per the opening balance sheet.

(iii) The Commission shall scrutiny the project cost estimates by limiting to the reasonableness of the capital cost, financial plan, interest during construction, use of efficient technology and such other matters for determination of tariffs.

(iv) An application for the review of the capital cost may be forwarded to the Commission along with a copy of the detailed Project Report by the Project Sponsor’s technical advisers.

35. Additional Capitalization

(1) The following actual capital expenditure incurred after the date of commercial operation and upto the cut off date, which is within the original scope of work, may be admitted by the commission subject to prudent check:

(i) deferred liabilities;

(ii) works deferred for execution;

(iii) procurement of initial capital spares in the original scope of work subject to the ceiling specified under Regulation 34;

(iv) liabilities to implement award of arbitration or for compliance of the order or decree of a court of law; and

(v) on account of change in law.

Provided that:

(i) the original scope of work along with the estimates of expenditure shall be submitted along with the application for determination of provisional tariff;

(ii) a list of 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 station.

(2) Subject to the provisions of clause (3), below the capital expenditure of the following nature actually incurred after the cut off date may be admitted by the Commission after prudent check:

(i) deferred liabilities relating to works / services within the original scope of work;

(ii) liabilities to implement award of arbitration or compliance of the order or decree of a court.

(iii) on account of change of law;

(iv) any additional work or services which have become necessary for efficient and successful operation of generating station but not included in the original project cost.

(v) Deferred work relating to ash pond or ash handling system in the original project cost.

(3) Any other expenditure on minor items / assets like normal tools and tackles, personal computers, furniture, air – conditioners, voltage stabilizers, refrigerators, fans, coolers, TV, washing machines, heat converters, carpets, mattresses etc, bought after cut off date shall not be considered for additional Capitalisation for determination of tariff with effect from the date of notification of these regulations by the Commission.

Note: The above list is only illustrative but not exhaustive.

(4) Impact of additional Capitalisation in tariff revision may be considered by the Commission twice in a tariff period, including revision of tariff after cut off date.

Note: (1) Any expenditure admitted on account of committed liabilities within the original scope of work and the expenditure deferred on techno – economic grounds but falling within the scope of original work shall be serviced in the normative debt-equity ratio specified in Regulation 37.

(2) Any expenditure on replacement of old assets shall be considered after writing off the gross value of the original assets from the project cost except such items as are listed under clause (3) above

(3) Any expenditure admitted by the Commission for determination of tariff on account of new works not in the original scope of work shall be serviced in the normative debt – equity ratio specified in Regulation 37.

(4) Any expenditure admitted by the Commission for determination of tariffs on renovation and modernisation and life extension shall be serviced on normative debt – equity ratio specified in Regulation 37 after writing off the original amount from the original project cost, if any replacement of existing assets is involved.

36. Sale of Infirm Power Any revenue (other than the recovery of fuel cost) earned by the integrated utility / generating company from sale of infirm power, shall be taken as a reduction in capital cost and shall not be treated as revenue.

37. Debt – equity ratio

(1) In case of all generating stations, the debt – equity ratio as on the date of commercial operation shall be 70:30 for determination of tariff. The Commission may in appropriate cases consider equity higher than 30% for purpose of determination of tariff, where the integrated utility / generating company is able to establish to the satisfaction of the Commission that the deployment of equity more than 30% is in the interest of general public.

Provided that

(i) in case of a generating station, where actual equity employed is less than 30%, the actual debt and equity shall be considered for determination of tariff

(ii) in case of existing projects the actual debt: equity ratio shall be used for tariff determination. However any expansion shall be governed by clause (1) above.

(2) The debt and equity amount arrived at in accordance with clause (1) shall be used for calculation of interest on loan, return on equity, Advance Against Depreciation and foreign exchange rate variation.

38. Computation of capacity (Fixed) charges The capacity (fixed) charges shall be computed on the following basis and their recovery shall be related to target availability:

(1) Interest on Capital

(a) Interest on loan capital shall be computed loan – wise on the loans indicated in Regulation 37.

(b) In the case of existing projects, the actual debt-equity ratio shall be used for tariff determination and interest on loans shall be paid at actuals. However any expansion shall be governed as per Regulation

37.

(c) The integrated utility / generating company shall make every effort to refinance the loan as long as it results in net benefit to the beneficiaries. The costs associated with such refinancing shall be borne by the beneficiaries.

(d) The changes to the loan terms and conditions shall be effected from the date of such swapping and benefit passed on to the beneficiaries.

(e) In case of any dispute, any of the parties may approach the Commission with proper application. However, pending receipt of the orders of the Commission on the application, the beneficiaries shall not withhold any payment of the integrated utility / generating company during the pendency of any dispute relating to the swapping of the loan.

(f) In case any moratorium period is availed by the integrated utility / generating company, depreciation provided in the tariff during the period of moratorium shall be treated as repayment during those years and interest on loan capital shall be calculated accordingly.

(g) The integrated utility / generating company shall not make any profit on account of refinancing of loan and interest thereon.

(h) The integrated utility / generating company , at its descretion, swap loans having floating rate of interest with loans having fixed rate of interest, or vice versa at its own cost and gains or losses as a result of such swapping shall accrue to the generating company.

Provided that the beneficiaries shall be liable to pay interest for loan initially contracted, whether on floating or fixed rate of interest.

(2) Depreciation, including Advance Against Depreciation

(a) Depreciation For purpose of tariff, depreciation shall be computed in the following manner:

(i) The value base for the purpose of depreciation shall be the historicalcost of the asset.

(ii) Depreciation shall be calculated annually, based on the straight-line method over the useful life of the asset and at rates prescribed by the Central Electricity Regulatory Commission.

25 The residual value of the asset shall be considered as 10% and the depreciation shall be allowed upto a maximum of 90% of the historical capital cost of the asset. The land is not a depreciable asset and its cost shall be excluded from the capital cost while computing 90% of the historical cost of the asset. The historical capital cost of the asset shall include Additional Capitalisation on account of Foreign Exchange Rate Variation as allowed by the Central Government / Central Electricity Regulatory Commission

(iii) On repayment of entire loan, the remaining depreciable value of the asset shall be spread over the balance useful life of the asset.

(iv) Depreciation shall be chargeable from the first year of operation of the asset. For part of the year, depreciation shall be charged on pro rata basis.

Note: Where existing Power Purchase Agreement (including any change in the norms or parameters, made in the Power Purchase Agreement following renegotiation between the integrated utility and concerned generating company) lay down a different parameter of depreciation such a parameter shall continue to govern as per the terms of the contract, but not for any renewal of contract or any extension of the term of the contract. Upon expiry of the term of the existing Power Purchase Agreement, the parties shall be governed by the provisions of these regulations as amended from time to time.

(b) Advance Against Depreciation (AAD) In addition to permissible depreciation, the integrated utility / generating company shall be entitled to Advance Against Depreciation, computed in the manner indicated below:

AAD= Loan repayment as per Regulation 38(1) subject to a ceiling of 1/10th of the loan amount as per Regulation 37 minus depreciation upto that year.

Note:

(i) The Advance Against Depreciation shall be permitted only if the cumulative repayment upto a particular year exceeds the cumulative depreciation upto that year.

(ii) The Advance Against Depreciation shall be restricted to the extent of the difference between the cumulative repayment and cumulative depreciation upto that year.

All efforts shall be made for aligning the tenure of the long term debt with permissible rate of depreciation to reduce front loading of tariff through various mechanisms including resorting to take out finance to elongate debt repayment period so that there will be no need for any Advance Against Depreciation.

(3) Return on Equity

(a) The return on equity shall be computed on the equity base determined in accordance with Regulation 37 @ 14% per annum.

(b) In the case of existing projects, the actual debt equity shall be used for tariff determination. However, any expansion shall be governed by Regulation 37.

(c) Equity invested in foreign currency shall be allowed a return upto the prescribed limit in the same currency and the repayment on this account shall be made in Indian Rupee based on the exchange rate prevailing on the due date of billing.

(d) The premium raised by the integrated utility / generating company, while issuing share capital and investment of internal resources created out of its free reserve, if any, for funding the project, shall also be reckoned as a paid up capital for the purpose of computing return on equity, provided such premium amount and internal resources are actually utilised for meeting the capital expenditure of the generating station and forms part of approved financial package.

The definition of equity thus would involve all net worth deployed in the capital works of the unit.

(e) Where existing Power Purchase Agreement (including any changes, in the norms or parameters made in the Power Purchase Agreement following renegotiation between the integrated utility and the concerned generating company) lay down a different parameter of Return on Equity, such a parameter shall continue to govern the parties for the existing term of the agreement but not for any renewal of the contract or any extension of the contract. On expiry of the period of agreement, the parties shall be governed by the provisions of these regulations, as amended from time to time.

(4) Operation and Maintenance Expenses The normative operation and maintenance expenses shall be as follows:

(a) The Commission shall, for the purpose of fixing normative rates of operation and maintenance expenses, study the past performance and the performance of similar technology / size machines owned by other utilities outside the State including Public State Units, Private Power Institutions, State Electricity Boards etc.

(b) The normative rates shall be fixed as under.

(1) Coal based generating station:

(i) For generating stations having a combination of 200/210/250 MW sets and 500 MW sets and above, the weighted average value of operation and maintenance expenses shall be adopted.

(ii) For smaller units less than 210 MW, the Commission shall specify rates to be adopted by the generating station on completion of the study as indicated under clause (a) above.

(2) For Gas Turbine / combined cycle generating stations (other than small gas turbine generating stations): The Commission shall fix separate rates based on weighted average of the operation and maintenance expenses separately.

(a) For the stations having warranty spares

(b) For those stations which are not having warranty spares.

(i) For small gas turbine power generating stations the Commission shall fix separate rates which are having spares without warranty.

(ii) For lignite – fired generating stations, the Commission shall fix separate rates.

In respect of small gas turbine power generating stations / lignite fired generating stations (without warranty spares) the Commission shall fix separate rates.

(c) The operation and maintenance expenses include employee costs, Repair and Maintenance (R&M) and Administrative and General (A&G) expenses.

(5) Interest on Working capital

(a) Working capital for purposes of calculation of interest shall be:

(I) For Coal based / Lignite fired generating stations:

(i) cost of coal or lignite for one and half months for pit – head 28 generating stations and two months for non pit – head generating stations, corresponding to the target availability;

(ii) Cost of secondary fuel oil for two months corresponding to target Availability;

(iii) Operation and Maintenance expenses for one month;

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

(v) Receivables equivalent to two months of fixed and variable charges for sale of electricity calculated on the target availability.

(II) Gas Turbine / Combined cycle generating stations:

(i) Fuel cost for one month corresponding to the target availability duly taking into account the mode of operation of the generating station on gas and liquid fuel.

(ii) Liquid fuel stock for ½ month

(iii) Operation and maintenance expenses for one month

(iv) Maintenance spares at 1% of the historical cost escalated at 6% per annum from the date of commercial operation.

(v) Receivables equivalent to two months of fixed and variable charges for sale of electricity calculated on target availability.

(b) Rate of interest on working capital: The rate of interest on working capital shall be equal to the short – term Prime Landing Rate of State Bank of India on 1st April of the year in which the generating station or a unit there of is declared under commercial operation. Interest on working capital shall be payable on normative basis not withstanding that the integrated utility or generating company has not taken working capital loan from any outside agency.

Note: Where existing Power Purchase Agreement (including any changes in the norms or parameters made in the PPA following renegotiation between the integrated utility and the generating company) lay down a different rate of parameter of O&M rates, such a parameter shall continue to govern the parties for the period of agreement but not for any renewal or extension of the terms of agreement. On expiry of the existing period of PPA, the parties shall be governed by the provisions of these regulations as amended from time to time.

(c) Capacity charges: Full capacity charges shall be recoverable at target availability specified under Regulation 33(1) . Recovery of capacity 29 (fixed) charges below the level of target availability shall be on prorata basis. At zero availability, no capacity charges shall be payable.

(d) Payment of capacity charges shall be on monthly basis in proportion to the allocated capacity.

39. Energy Charges

(1) Generating stations covered under Availability Based Tariff (ABT):

Energy (variable) charges shall cover fuel costs which shall be worked out based on the ex-bus energy scheduled to be sent out from the generating station as per the following formula:

Energy charges(Rs.) = Rate of energy charges in Rs/kWh X Schedule energy (ex-bus) for the month in kWh corresponding to the scheduled generation.

(2) Generating Stations other than covered under ABT: Energy (variable) charges shall cover fuel costs and shall be worked out on the basis of exbus energy delivered / sent out from the generating station as per the following formula:

Energy charges (Rs.) = Rate of energy charges in Rs. / kWh X scheduled energy delivered (ex-bus) for the month in kWh) Where, Rate of Energy Charges (REC) shall be the sum of the cost of normative quantities of primary and secondary fuel for delivering ex-bus one kWh of energy in Rs. / kWh and shall be computed as under:

REC = 100 (Pp X Qp)n + PsXQs)n (Rs. / kWh) [100 – (Auxn) where, Pp = Price of primary fuel (coal / lignite / gas / liquid fuel) in Rs. / Kg or Rs.

/ cum. Or Rs. / litre, as the case may be.

(Qp)n= Quantity of primary fuel required for generation of one kWh of electricity at generator terminal in kg or litre or cum, as the case may be, and shall be computed on the basis of normative Gross Station Heat Rate (less heat contributed by secondary fuel oil for coal / lignite – based generating stations) and gross calorific value of coal / lignite / gas / liquid fuel as fired.

Ps= Price of secondary fuel oil in Rs. / ml.

(Qs)n= Normative quantity of secondary fuel oil in ml / kWh as per Regulation 33 (4), (Aux)n= Normative Auxiliary Energy Consumption as % of gross generation as per regulation 33 (5).

(3) Adjustment of rate of energy charge (REC) on account of variation in price or heat rate of fuels:

Initially Gross Calorific value of coal / lignite / gas liquid fuel shall be taken as per actuals of the preceeding three months. Any variation shall be adjusted on month to month basis on the basis of gross calorific value of coal / lignite gas / liquid fuel received and burnt and landed cost incurred by the integrated utility / generating company for procurement of the coal / lignite / oil / gas / liquid fuel as the case may be. No separate petition shall be filed before the Commission for fuel price adjustment. In case of any dispute, an appropriate application shall be made before the Commission for its orders.

(4) Landed cost of coal Subject to Regulation 2(2), the landed cost of coal shall include price of coal corresponding to the grade / quality of coal 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 charges, it shall be arrived at after considering normative transit and handling losses as percentage of quantity of coal dispatched by the coal supply company during the month as follows:

Pit heat generating station - 0.3% Non – pit heat generating station - 0.8%

40. Incentive Incentive shall be payable to the generation company at a flat rate of 25 paise / kWh for ex-bus scheduled energy corresponding to schedule generation in excess of ex-bus energy corresponding to target Plant Load Factor.

41. Unscheduled interchange (UI)

(1) Variation between actual generation or actual drawal and scheduled generation or scheduled drawal shall be accounted for through unscheduled Inter-change (UI) charges. UI for a generating station shall be equal to its actual generation minus its scheduled generation. UI for a beneficiary shall be equal to its actual total drawal minus its total scheduled drawal. UI shall be worked out for each 15 minutes block. Charges for all UI transactions shall be based on average frequency of the time block and the following rates shall apply:

31 Average frequency of time block (Hz) Below Not below UI Rate (Paise / kWh) - 50.50 0.0

50.50 50.48 6.0

50.48 50.46 12.0

49.84 49.82 204.0

49.82 49.80 210.0

49.80 49.78 219.0

49.78 49.76 228.0

49.04 49.02 561.0

49.02 570.0 (Each 0.02 Hz step is equivalent to 6.0 paise / kWh in the 50.5 – 49.8 Hz frequency range and to 9.0 paise / kWh in the 49.8 – 49.0 Hz frequency range).

Note: The above frequency range and UI rates are subject to change through a separate order by the Commission.

(2) (i) Any generation upto 105% of the declared capacity in any time block of 15 minutes and upto 101% of the average declared capacity over a day shall not be construed as gaming, and the integrated utility or generating company shall be entitled to UI charges for such excess generation above the scheduled generation (SG).

(ii) For any generation beyond the prescribed limits, the State Load Despatch Centre shall investigate so as to ensure that there is no gaming, and if gaming is found by the State Load Despatch Centre, the corresponding UI charges due to the generating station on account of such excess generation shall be reduced to zero and the amount shall be adjusted in UI account of beneficiaries in the ratio of their capacity share in the generating station.

42. Rebate For payment of bills for capacity charges and energy charges through a letter of credit on presentation, a rebate of 2% shall be allowed. If the payments are made by a mode other than through a letter of credit but within a period of one month of presentation of bills by the integrated utility / generating company, a rebate of 1% shall be allowed.

43. Late payment surcharge In the case of payment of bills for capacity charges and energy charges by the beneficiary or beneficiaries is delayed beyond a period of one month from the date of billing, late payment surcharge at the rate of 1.25% per month or part thereof shall be levied by the integrated utility / generating company.

44. Scheduling The methodology of scheduling and calculation of availability shall be as follows:

(i) (a) The integrated utility / generating company shall make an advance declaration of the capability of its generating station which shall be actually made available to the Transmission Licensee / Distribution Licensee.

(b) The capability declared, referred to as the declared capability, shall form the basis for generation scheduling

(ii) The electricity shall be deliverable at ex-bus MW for the next day either as one figure for the whole day or as different figures for different periods of the day.

(iii) While declaring or revising its capability, the integrated utility / generating company shall ensure that the declared capability during non- peak hours is not less than during other hours. Exception to this rule shall be allowed in the case of tripping / re-synchronisation of units as a result of forced outage of units.

(iv) Generation scheduling shall be done according to operation procedure stipulated in the Indian Electricity Grid Code / State Electricity Grid Code.

(v) As per the declaration of the integrated utility / generating company, the state Load Despatch Centre shall communicate their shares to the beneficiaries against which they can submit their requirements.

(vi) Based on the requirement of the beneficiaries, the State Load Despatch Centre shall prepare the economically optimal generation schedules and drawal schedules, taking into account technical limitations on verifying the generation and transmission system constraints, and communicate the same to the integrated utility / generating company and also to the beneficiaries.

The State Load Despatch Centre shall also formulate a procedure for meeting contingencies both in the long run and in the short run (Daily scheduling).

(vii) The scheduled generation and actual generation shall be at ex-bus at the generating station. For the beneficiaries, the scheduled and actual net deliveries shall be at their respective receiving points.

(viii) For the net drawal schedules of the beneficiaries, the transmission losses shall be apportioned to their drawal scheduled for the time being. A refinement may however be suggested by the Commission in future 33 depending on the preparedness of the respective State Load Despatch Centre.

(ix) In the case of a forced outage of a unit, the State Load Despatch Centre shall revise the schedules on the basis of revised declared capability. The revised declared capability and the revised schedules shall be effective from the fourth time block, counting the time block in which revision is advised by the integrated utility or generating company to be the first one.

(x) In the case of any bottle neck in evacuation of power due to any constraint, outage, failure or limitation the transmission system, associated switchyard and sub – station owned by the State Transmission Utility or any other transmission licensee involved in intra– state transmission (as certified by the State Load despatch Centre) necessitating in reduced generation, the SLDC shall revise the schedules which shall become effective from the 4th time block, counting the time block in which the bottleneck in evacuation of power has taken place to be the first one. During the first, second and third time blocks of such an event, the scheduled generation of the generating station shall be deemed to have been revised to be equal to actual generation and the scheduled drawals of beneficiaries shall be deemed to have been revised to be equal to their actual drawls.

(xi) In the case of grid disturbance, the scheduled generation of all the generating stations and scheduled drawls of all the beneficiaries shall be deemed to have been revised to be equal to their actual generation / drawal for all the time blocks affected by the grid disturbance.

Certification of grid disturbance and its duration shall be done by the SLDC.

(xii) Revision of declared capability by the integrated utility / generating company / companies and requisition by beneficiary(ies) for the remaining period of the day shall also be permitted with advance notice.

Revised schedules / declared capability in such cases shall become effective from the 6th block, counting the time block in which request for revision has been received in the SLDC to be the first one.

(xiii) If, at any point of time, the SLDC observes that there is need for revision of the schedules in the interest of better system operation, it may do so on its own and in such cases, the revised schedules shall come into effect from the fourth time block, counting the time block in which the revised schedule is issued by the SLDC to be the first one.

(xiv) Generation schedules and drawal schedules issued / revised by the SLDC shall become effective from the designated time block.

(xv) For any revision of scheduled generation, including post fact deemed revision, there shall be a corresponding revision of scheduled drawals of the beneficiaries.

(xvi) A procedure for recording communication of changes to schedules duly taking into the time factor shall be evolved by the State Transmission Utility in consultation with the SLDC as well as other stakeholders, and it shall be to the extent possible in line with the prevailing practices at the national level.

(xvii) In the case of a generating station, contracting to supply power to two or more states, the scheduling, metering and energy accounting shall be carried out by the Regional Load despatch Centre.

45. Demonstration of Declared Capability

(1) The integrated utility/generating company shall demonstrate the declared capability of its generating station as and when asked by the SLDC. In the event of the generating company failing to do so, the capacity charges due to the integrated utility/generating company shall be reduced as a measure of penalty.

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

For the second mis-declaration, the penalty shall be equivalent to fixed charges for four days and for subsequent mis-declarations, the penalty shall be multiplied in geometrical progression.

(3) The operating log books of the generating station shall be made available for review by the SLDC. These books shall contain the record of machine operation and maintenance.

46. Metering and Accounting Metering arrangements, including installation, testing and operation and maintenance of meters and collections, transportation and processing of data required for accounting of energy exchanges and average frequency on 15 minute time block basis shall be the responsibility of the State Transmission Utility / State Load Despatch Centres. All the concerned entities (in whose premises the special energy meters are installed) shall fully cooperate with the STU / SLDC and extend necessary assistance by taking weekly meter readings and transmit them to SLDC.

The SLDC shall in turn forward necessary data / schedules to the regional level in line with the regulations framed by Central Electricity Regulatory 35 Commission. UI accounting procedures within the state shall be governed by the orders of the Commission.

In case of a generating station, contracting to supply power to two or more states, the scheduling, metering and energy accounting shall be carried out by the Regional Load Despatch Centre.

47. Billing and payment of capacity charges The billing and payment of capacity charges shall be done on a monthly basis as under:

(i) Each beneficiary shall pay the capacity charges in proportion to its percentage share in installed capacity of the generating station.

(1) The beneficiaries could be the various distribution licensees or the Trading Companies.

(2) If the capacity remains unutilised during day-to-day operation, the SLDC shall advise all beneficiaries in the region or other SLDCs so that such capacity may be utilized through bilateral arrangements either with or the concerned generating company or beneficiary(ies) under intimation to the SLDC.

(3) The information regarding un-requisitioned capacity shall be made available by the SLDC through their respective websites.

(ii) The capacity charges shall be paid by the beneficiary(ies) to the generating company every month in accordance with the following formulae:

(a) Total capacity charges payable to the generating company for 1st Month (1XACC 1) ÷12 2nd Month (2XACC 2 - 1XACC 1) ÷12 3rd Month (3XACC 3 - 2XACC 2 ) ÷12 4th Month (4XACC 4 -3XACC 3 ) ÷12 5th Month (5XACC 5 - 4XACC 4) ÷12 6th Month (6XACC 6 - 5XACC 5) ÷12 7th Month (7XACC 7 - 6XACC 6 ) ÷12 8th Month (8XACC 8 - 7XACC 7 ) ÷12 9th Month (9XACC 9 - 8XACC 8 ) ÷12 10th Month (10XACC 10 - 9XACC 9 ) ÷12 11th Month (11XACC 11 - 10XACC 10 ) ÷12 12th Month (12XACC 12 - 11XACC 11) ÷12 Note: ACC1 to ACC 12 are the amounts of Annual capacity charges corresponding to availability for the cumulative period upto the end of 1st to 12th Months each respectively.

(b) Each beneficiary having firm allocation in capacity of generating station shall pay for 36 1st Month [ACC 1X WB 1] ÷1200 2nd Month [2 ACC 2 X WB 2 – 1 XACC 1 X WB 1] ÷ 1200 3rd Month [3 ACC 3 X WB 3 – 2 XACC 2 X WB 2] ÷ 1200 4th Month [4 ACC 4 X WB 4 – 3 XACC 3 X WB 3 ]÷ 1200 5th Month [5 ACC 5 X WB 5 – 4 XACC 4 X WB 4] ÷1200 6th Month [6 ACC 6 X WB 6 – 5 XACC 5 X WB 5 ]÷ ]1200 7th Month [7 ACC 7 X WB 7 – 6 XACC 6 X WB 6] ÷ 1200 8th Month [8 ACC 8 X WB 8 – 7 XACC 7 X WB 7]÷ 1200 9th Month [9 ACC 9 X WB 9 – 8 XACC 8 X WB 8 ]÷ 1200 10th Month [10 ACC 10 X WB 10 – 1 ACC 9 X WB 9] ÷ 1200 11th Month [11 ACC 11 X WB 11– 10 ACC 10 X WB 10] ÷ 1200 12th Month 12 [ACC 12 X WB 12 – 11 ACC 1 X WB 11] ÷ 1200 Note: WB1 to WB12 are the weighted average of percentage allocated capacity share of the beneficiary during the cumulative period upto 1st to 12 months each respectively.

Chapter 3 Hydro Power Generating Station

48. Definitions Unless the context otherwise requires for the purpose of this chapter:

(i) ‘Additional Capitalisation’ means the capital expenditure actually incurred after the date of commercial operation of the station and admitted by the Commission after prudent check subject to provisions of Regulation 51’.

(ii) ‘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 at the integrated utility’s or generating company’s terminals of all units of the generation station;

(iii) ‘Beneficiary’ in relation to generating station means the person buying power generated at such generating station on payment of Annual Fixed Charges.

(iv) ‘Capacity Index’ means the average of the daily capacity indices over one year;

(v) ‘Cut off date’ means the date of first financial year closing after one year of the date of commercial operation of the generating station.

(vi) ‘Daily Capacity Index’ means the declared capacity expressed as a percentage of the maximum available capacity for the day and shall be mathematically expressed as here-under:

Daily Capacity Index = Declared Capacity (MW) Maximum Available Capacity (MW) X 100 Daily Capacity Index shall be limited to 100%.

(vii) ‘Date of commercial operation’ or ‘COD’ in relation to a unit means the date declared by the integrated utility / generating station after demonstrating the ‘Maximum Continuous Rating (MCR) or installed capacity through a successful trial run after notice to the beneficiaries and in relation to the generating station, the date of commercial operation of the last unit or block of the generating station.

(viii) ‘Declared Capacity or DC’ means :

(a) for run-of – river power station with pondage and storage type power stations, the declared capacity means the ex-bus capacity in MW expected to be available from the generating station during the peak hours of the next day, as declared by the integrated utility / generating company, taking into account the availability of water, optimum use of water and the availability of machines.

For this purpose, the peak hours shall not be less than 3 hours within a 24 hour period; and

(b) In the case of purely run-of-river power stations, the declared capacity means the ex-bus capacity in MW expected to be available from the generating station during the next day, as declared by the generating station, taking into account the availability of water, optimum use of water and availability of machines;

(ix) ‘Deemed Generation’ means the energy which a generating station was capable of generating but could not generate due to conditions of grid or power system, beyond the control of the generating station resulting in spillage of water.

(x) ‘Design Energy’ means the quantum of energy, which could be generated in a 90% dependable year with 95% installed capacity of the generating station;

(xi) ‘Existing generating station’ means a generating station declared under commercial operation from the date prior to the notified date of tariff Regulations by the Commission as per regulation 1(2).

(xii) ‘Installed Capacity’ or ‘IC’ means the summation of the name plate capacities of all the units of a generating station or the capacity of a generating station (received at the generator terminals) as approved by the Commission from time to time.

(xiii) ‘Infirm Power’ means electricity generated prior to the commercial operation of the unit of a generating station.

(xiv) ‘Maximum Available Capacity’ means the following:

(a) Run–of–river power stations with pondage and storage type power stations; The maximum capacity in MW, the generating station can generate with all generating units running, under the prevailing conditions of water levels and flows, over the peak hours of the next day.

Explanation: The peak hours for the purpose shall not be less than 3 hours within a 24 hour period.

(b) Purely run-of-river power stations: The generating station can generate maximum capacity in MW, with all units running, under the prevailing conditions of water levels and flows over the next day.

(xv) ‘Primary Energy’ means the quantum of energy generated upto the design energy on per year basis at the generating station;

(xvi) ‘Project’ means a generating station and includes the complete hydro power generating facility covering all components such as dam, intake, water conductor system, power generating station and generating units of the scheme as apportioned to power generation;

(xviii) ‘Operation and Maintenance Expenses’ or ‘O&M Expenses’ means the expenditure incurred on operation and maintenance of the generating station and includes expenditure on man-power, repairs, spares, consumables, utility expenses, insurance and overheads.

(xix) ‘Original Project Cost’ means the actual expenditure incurred by the integrated utility or generating company as per original scope of the project upto the first financial closing after one year from the date of commercial operation of the last unit as admitted by the Commission for the determination of tariff.

(xx) ‘Run-of-river power station with pondage’ means a hydro electric power station with sufficient pondage for meeting the diurnal variation of power demand;

(xxi) ‘Storage type power station’ means a hydro electric power generating station associated with large storage capacity to enable variation of generation of power according to demand;

(xxii) Saleable Primary Energy means the quantum of primary energy available for sale (ex-bus);

(xxiii) ‘Secondary Energy’ means the quantum of energy generated in excess of the design energy on per year basis at the generating station;

(xxiv) ‘Saleable Secondary Energy ’ means the quantum of secondary energy available for sale (ex-bus);

(xxv) ‘Scheduled Energy’ means the quantum of energy to be generated at the generating station over a 24 hour period, as scheduled by the SLDC;

49. Norms of operation

(1) Normative capacity index for recovery of full capacity charges:

(a) During first year of commercial operation of the generating station:

(i) Purely Run – of – river Power Stations 85%

(ii) Storage type and Run-of-river power stations with pondage 80%

(b) After first year of commercial operation of the generating station

(i) Purely Run – of – river Power Stations 90%

(ii) Storage type and Run-of-river power stations with pondage 85%

(c) There shall be prorata recovery of capacity charges in case the generation station achieves capacity index below the prescribed normative levels. At zero capacity index, no capacity charges shall be payable to the generating station.

(2) Auxiliary Energy Consumption

(a) Surface hydroelectric power generating station with rotating exciters mounted on generator shaft

0.2% of energy generated

(b) Surface hydroelectric power generating station with static excitation system

0.5% of energy generated

0.4% of energy generated

(d) Under ground hydro electric power generating station with static excitation system

0.7% of energy generated

(3) Transmission losses From generation voltage to Transmission Voltage

0.5% of energy generated

50. Capital Cost Subject to prudent check by the commission, the actual expenditure incurred upto completion of the project shall form the basis for the determination of final tariff. The final tariff shall be based on the admitted capital expenditure actually incurred upto the date of commercial operation of the generating station and shall include capitalised initial spares subject to a ceiling norm of 1.5% of the original project cost as on the cut off date:

Provided :

(i) where the Power Purchase Agreement (PPA) entered into between integrated utility / the generating company and the beneficiaries provides a ceiling of actual expenditure, the capital expenditure shall not exceed such a ceiling for determination of tariff.

(ii) in case of existing generating station, the capital cost admitted by the Commission prior to the notified date of tariff regulations by the Commission as per Regulation 1(2) shall form the basis for determination of tariff.

Note: The Commission shall scrutiny the project cost estimates limited to the reasonableness of the capital cost, financial plan, interest during construction, use of efficient technology and such other matters for the purpose of determination of tariffs.

51. Additional Capitalisation

(1) The following actual capital expenditure incurred within the original scope of work after the date of commercial operation and upto the cut off date may be admitted by the commission subject to prudent check:

(i) deferred liabilities;

(ii) works deferred for execution;

(iii) procurement of initial capital spares within the original scope of work subject to the ceiling specified under Regulation 50

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

(v) on account of change in law.

Provided that:

(i) the original scope of work along with the estimates of expenditure shall be submitted to the Commission along with the application for provisional tariff.

(ii) a list of deferred liabilities and works deferred for execution shall be submitted to the Commission along with the application for final tariff after the date of commercial operation of the generating station.

(2) Subject to the provisions of clause (3) of this Regulation, the capital expenditure of the following nature actually incurred after the cut off date may be admitted by the Commission after prudent check:

(i) deferred liabilities relating to works /services within the original scope of work

(ii) liabilities to meet award of arbitration or compliance of the order or decree of a court.

(iii) on account of change of law

(iv) any additional works/services which have become necessary for efficient and successful operation of the plant but not included in the original capital cost.

(3) Any other expenditure on minor items / assets like tools and tackles, personal computers, furniture, air – conditioners, voltage stabilizers, refrigerators, fans, coolers, TV, washing machines, heat convectors, carpets, mattresses etc, bought after cut off date shall not be considered for additional Capitalisation for determination of tariff with effect from the notified date of the tariff regulations by the Commission as per Regulation 1(2).

Note: The above list is illustrative but not exhaustive.

(4) Impact of additional Capitalisation in tariff revision may be considered by the Commission twice in a tariff period, including revision of tariff after cut off date.

Note: (1) Any expenditure admitted on account of committed liabilities within the original scope of work and expenditure deferred on techno – economic grounds but falling within the scope of original work shall be serviced in the normative debt-equity ratio specified in Regulation 53.

(2) Any expenditure admitted by the Commission for determination of tariff on account of new works not in the original scope of work shall be serviced in the normative debt – equity ratio specified in Regulation 53.

(3) Any expenditure admitted by the Commission for determination of tariffs on renovation and modernisation and life extension shall be serviced on normative debt – equity ratio specified in Regulation 53.

(4) Any expenditure on replacement of old assets shall be considered after writing off the gross value of the original assets from the original capital cost except such items as are listed in clause (3) above.

52. Sale of Infirm Power Any revenue earned by the integrated utility / generating company from sale of infirm power shall be taken as reduction in capital cost and shall not be treated as revenue. The rate for infirm power shall be the same as the primary energy rate of the generating station.

53. Debt equity ratio

(1) In case of all generating stations, the debt – equity ratio as on the date of commercial operation shall be 70:30 for determination of tariffs, provided that the commission may in appropriate cases consider equity higher than 30% for purpose of determination of tariff, where the generating company is able to establish to the satisfaction of the Commission that the deployment of equity more than 30% was in the interest of general public.

Provided that 42

(i) in case of a generating station, the actual equity employed is less than 30%, the actual debt and equity employed shall be taken for determination of tariff

(ii) in case of existing projects the actual debt: equity ratio shall be used for tariff determination. However any expansion shall be governed by clause (1) above.

54. Computation of Annual Charges The two-part tariff for sale of electricity from a hydro power generating station shall comprise of recovery of capacity charges and primary energy charges:

(i) Capacity charges: The capacity charges shall be computed in accordance with the following formula:

Capacity charges = (Annual fixed charge – Primary Energy charge) Note: Recovery through primary energy charge shall not be more than Annual Fixed Charge.

(ii) Annual Fixed Charges: Annual Fixed charges shall consist of;

(a) Interest on capital

(b) Depreciation, including Advance Against Depreciation

(d) Operation and Maintenance expenses; and

(e) Interest on working capital

55. Computation of annual fixed charges The annual fixed charges shall be computed on the following basis:

(1) Interest on capital

(i) Interest on loan capital shall be computed loanwise on the loans arrived at in manner indicated in Regulation 53.

(ii) In the case of existing projects, the actual debt equity ratio shall be used for tariff determination. However, any expansion shall be governed by Regulation 53.

(iii) The generating company / integrated utility shall make every effort to refinance the loan as long as it results in net benefit to the beneficiaries. The costs associated with such refinancing shall be borne by the beneficiaries.

(iv) The charges on loan terms and conditions shall be reflected from the date of such swapping and benefit shall be passed to the beneficiaries.

(v) In case of any dispute, any of the parties may approach the Commission with proper application. The beneficiaries shall not, however, withhold payment to the generating company / integrated utility during pendancy of the dispute, unless the Commission specifically directs such non-payment, relating to swapping of the loan.

(vi) In case any moratorium period is availed of by the integrated utility / generating company, depreciation provided for in the tariffs during the period of moratorium shall be treated as repayment during those years and interest on loan capital shall be calculated accordingly.

(vii) The integrated utility or the generating company shall not make any profit on account of swapping of loan and interest thereon.

(viii) The integrated utility or the generating company, may at its descretion, swap loans having floating rate of interest with loans having fixed rate of interest or vice – versa at its own cost and gains or losses as a result of such swapping shall accrue to the utility / generating company.

Provided that the beneficiaries shall be liable to pay interest for the loans initially contracted whether on floating or fixed rate of interest.

(2) Depreciation including Advance Against Depreciation

(a) Depreciation For purpose of tariff, depreciation shall be computed in the following manner:

(i) The value base for the purpose of depreciation shall be the historical cost of the asset.

(ii) Depreciation shall be calculated annually, based on the straight-line method over the useful life of the asset and at rates prescribed by the Central Electricity Regulatory Commission

(iii) The residual value of the asset shall be considered as 10% and the depreciation shall be allowed upto a maximum of 90% of the historical capital cost of the asset. Land is not a depreciable asset and its cost shall be excluded from the capital cost for purposes of depreciation while computing 90% of the historical cost of the asset.

The historical capital cost for purposes of depreciation of the asset shall include Additional Capitalisation on account of Foreign Exchange Rate Variation as allowed by the Central Government / Central Electricity Regulatory Commission 44

(iv) On repayment of entire loan, the remaining depreciable value shall be spread over the balance useful life of the asset.

(v) Depreciation shall be chargeable from the first year of operation of the asset. For part of the year, depreciation shall be charged on pro rata basis.

(b) Advance Against Depreciation (AAD) In addition to allowable depreciation, the integrated utility / generating company shall be entitled to Advance Against Depreciation, computed in the manner detailed below:

AAD= Loan repayment amount as per Regulation 53 subject to a ceiling of 1/10th of the loan amount as per Regulation 51 minus depreciation as per schedule.

Provided that:

(i) Advance Against Depreciation shall be allowed only if the cumulative repayment upto a particular year exceeds the cumulative depreciation upto that year.

(ii) Advance Against Depreciation in a year shall be restricted to the extent of depreciation between the cumulative repayment and cumulative depreciation upto that year.

All efforts shall be made for aligning the tenure of the long term debt with permissible rate of depreciation to reduce front loading of tariff through various mechanisms including resort to take out finances to elongate debt repayment period. In such a case there will be no need for any Advance Against Depreciation.

(3) Return on Equity

(a) The return on equity shall be computed on the equity base determined in accordance with Regulation 53 @ 14% per annum.

(b) In the case of existing projects, the actual debt equity shall be used for tariff determination. However, any expansion shall be governed by Regulation 53.

(c) Equity invested in foreign currency shall be allowed a return upto the prescribed limit in the same currency and the repayment on this accou

Terms and Conditions for Determination of Tariff Regulations, 2007 (all amendments upto 31.05.2017)

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