[Cites 0, Cited by 0]

State of West Bengal - Act

The West Bengal Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2011

WEST BENGAL
India

The West Bengal Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2011

Rule THE-WEST-BENGAL-ELECTRICITY-REGULATORY-COMMISSION-TERMS-AND-CONDITIONS-OF-TARIFF-REGULATIONS-2011 of 2011

Published on 25 April 2011
Commenced on 25 April 2011
[This is the version of this document from 25 April 2011.]
[Note: The original publication document is not available and this content could not be verified.]

The West Bengal Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2011Published vide Notification Kolkata Gazette, Extraordinary, Part 1, dated 29.4.2011, vide Notification No. 48/WBERC, Kolkata, the 25th April, 2011.Notification No. 48/WBERC Kolkata, the 25th April, 2011. - In exercise of the powers conferred by sub-sections (1) and (2) of section 181 read with section 41. sub-section (2) of section 45, sections 51, 61, 62, 63, 64, 65 and sub-section (1) of section 86 of the Electricity Act, 2003 (36 of 2003), the Electricity [Removal of Difficulties] Third Order, 2005 and the Electricity [Removal of Difficulties] Eighth Order, 2005 and all powers enabling on that behalf and in supersession of the Notification No. 31/WBERC dated 9th February, 2007 published in the Kolkata Gazette, Extraordinary on February 9, 2007, with all amendments, the West Bengal Electricity Regulatory Commission (WBERC) hereby makes the following regulations.Chapter - 1 General

1. 1. Short title, commencement and interpretation.

- These regulations may be called the West Bengal Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2011(i)They extend to the whole of West Bengal.(ii)They shall come into force on the date of their publication in the Official Gazette and apply for :(a)Determination of tariff for the year 2011-12 and onwards;(b)Annual Performance Review for the year 2009-10 and onwards subject to other conditions as specified in these regulations;(c)Fuel and Power Purchase Cost Adjustment for the year 2010-11 and onwards and for 2009-10 related to cases where Fuel and Power Purchase Cost Adjustment has not yet been determined;(d)Monthly Fuel Cost Adjustment and Monthly Variable Cost Adjustment as provided in these regulations.(iii)They shall apply to determination of tariff by the Commission in accordance with Section 62 of the Act;(iv)They shall apply for regulating purchase and procurement process of distribution licensees which may include the price at which electricity shall be procured from the generating companies or the licensees or from other sources through agreement for purchase of power for distribution and supply within the state;(v)They shall not apply to the following types of cases for the purpose of determination of tariff. but shall apply to such cases for the purpose of determination of wheeling and/or transmission charges and/or avoidable cost for applicable cross subsidy charge;(a)Use of electricity from captive generating plants for own consumption by the owner of the captive generating plant;(b)In such cases where there is direct commercial relationship through supply by a generating station to a consumer under open access mode;(c)In such cases where there is direct commercial relationship through supply by an electricity trader to a consumer:(d)In such cases where there is direct commercial relationship through supply by a distribution licensee to a consumer of another distribution licensee under open access mode;(e)In such cases where there is direct commercial relationship through supply by an electricity trader to a distribution licensee;(f)In such cases where the supply is by a person exempted under section 13 or under 8th proviso to section 14 of the Act to consumer or distribution licensees or electricity trader through open access by using the electrical network of any licensee.

1.2Definitions. -

1.2.1- In these regulations, unless the context otherwise requires :

(i)"Act" means the Electricity Act, 2003 (36 of 2003):

(ii)"ABT" means Availability Based Tariff as specified in Chapter - 6 and Schedule - 1 and applicable within the State of West Bengal;

(iii)"Accounts" means regulatory accounts as may be specified by the Commission and till such time these are specified by the Commission, the said accounts shall be the accounts as maintained in accordance with the Companies Act, 1956 (1 of 1956) or the relevant statutes or repealed statutes under which the licensee or the generating company is incorporated or created but subject to such deviations as specified n these regulations and/or prescribed in the rules made under sub-section (1) of section 69 of the Electricity Supply Act, 1948;

(iv)"Accounting Statement" means for each financial year, the following statements, together with notes thereto, incorporating modifications required under these regulations and such other supporting statements and information as the Commission may direct from time to time;

(a)Balance sheet, prepared in accordance with the statute of incorporation;

(b)Profit and loss account, prepared in accordance with the statute of incorporation;

(c)Cash flow statement prepared in accordance with the accepted norms:

(d)Report of the statutory auditors;

(e)Proforma A to F under Cost Accounting Records (Electricity Industry) Rules, 2001 to the extent applicable;

(f)Cost Audit Reports where such audit has been ordered by a competent authority or where such audit has been done and the report has been directed to be circulated by the Central Government as applicable in the case of a company;

(v)"Accredited Energy Auditor" means any of the following : -

(a)Accredited Energy Auditor as defined in the Energy Conservation Act, 2001;

(b)Authority;

(c)Such auditors as may be notified by State Government;

(vi)"Agency" or "Entity" means a term used in these regulations to refer to a person exempted under section 13 or 8th proviso to section 14 of the Act within the State, or a licensee under section 14 of the Act or a generating company or a generating station or a captive generating plant or an electricity trader or an open access customer, under the purview of the Commission;

(vii)"Aggregate Revenue Requirement" or "ARR" means the requirement of fund for activities related to the business of electricity of a licensee or a generating company, as the case may be. for recovery of allowable expenses, allocations, return on equity and other permitted allowances, for any specific period as a part of revenue recoverable through tariff in accordance with these regulations;

(viii)"Allocation Statement" means for each financial year, a statement in respect of each of the separate businesses of the licensee, showing the amounts of any cost, revenue. asset, liability, reserve or provision, which has been either;

(a)Charged from or to each such separate business together with a description of the basis of that charge; or

(b)Determined by apportionment or allocation between the core business and every other separate business of the licensee, together with a description of the basis of the apportionment or allocation;

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

(x)"Annexure" or "Annex" means the annexure to these regulations;

(xi)"Annual Performance Review" or "annual performance review" or "APR" means the annual performance review as specified in regulation 2.6 of these regulations;

(xii)"Applicant" means a licensee or a generating company who has made an application for determination of tariff or for approval of Power Purchase Agreement, as the case may be, in accordance with the Act and these regulations and includes a licensee or a generating company whose tariff is the subject of a review by the Commission;

(xiii)"Area Load Despatch Centre" or 'AMC" means the area load despatch centre as defined in the state grid code;

(xiv)"Auxiliary Consumption" in relation to a period, means the quantum of energy consumed by auxiliary equipment of the generating station and transformer losses within the generating station as mentioned in the accounts on the basis of measurement through meter, and shall be expressed as a percentage of the summated gross energy generated at the generator terminals of all the units of the generating station:

(xv)"Auxiliary Services" means such services, other than direct utilization of the assets, which are explored for generating additional Income such as advertisements on bill face, bill boards and hoardings set up in establishments, etc. by using the business process of core business of the licensee;

(xvi)"Availability" in terms of Availability Based Tariff in relation to

(a)transmission system for a given period means the time in hours in that period the transmission system is capable of transmitting electricity at its rated voltage expressed in percentage of total hours in the given period;

(b)thermal generating station for any period means the average of the daily average declared capacities for all the days during that period expressed as a percentage of the installed capacity (in MW) of the generating station minus normative auxiliary consumption as specified in these regulations and shall be computed in accordance with the following formula;

Availability = 10000 xN∑Dci/ {Nx IC x (100- AUXn}%

i = 1

Where -N = Number of time blocks in the given period as may decided by the Commission from time to time;DCi = Average Declared ex-bus Capacity in MW for the ith time block in such period;IC = Installed Capacity of the generating station in MW;AUXn = Normative auxiliary consumption as a percentage of gross generation:

(xvii)"Balancing and Settlement Code" refers to such code as may be published by the SLDC with the approval of the Commission or as may be specified by the Commission, for the balancing of energy accounts and settlement of differences between energy scheduled and actual energy transacted among the users of the grid in the state:

(xviii)"Base Year" means the financial year immediately preceding the first year of the control period;

(xix)"Beneficiary" in relation to a generating station means the person, other than a consumer, buying power generated from such a generating station on payment of annual capacity charges;

(xx)'Block" in relation to a combined cycle thermal generating station includes combustion turbine - generator(s), associated waste heat recovery boiler(s), connected steam turbine - generators and auxiliaries,

(xxi)"Bulk Power Transmission Agreement" means the agreement as defined in open access regulations;

(xxii)"Bulk Power Wheeling Agreement" means the agreement as defined in open access regulations;

(xxiii)"Captive Generating Plant" means the Captive Generating Plant as defined in the Act and qualifies as per the provisions of the Electricity Rules, 2005 or any subsequent amendment or replacement of the said rules;

(xxiv)"Capital Expenditure" means the fund, where the equity or debt or both, actually deployed and paid in cash or cash equivalent for creation or acquisition of a useful asset and does not include commitments or liabilities for which no payment has been released.

(xxv)"CERC" means Central Electricity Regulatory Commission established under section 76 of the Act;

(xxvi)"CESC" means the CESC Limited;

(xxvii)"Commercial Plantation" to denote a class of consumers means supply of electricity to such consumer for watering or dewatering of plantations of a tea garden or horticulture or tissue culture or floriculture or herbal/medicinal/bio-diesel farming;

(xxviii)"Commission" means the West Bengal Electricity Regulatory Commission;

(xxix)"Conduct of Business Regulations" means such regulations as may be specified by the Commission under sub-sections (1) and (4) of section 91, sub-section (1) of section 92, sub-section (1) of section 127, section 130 and sub-section (1) of section 181 read with clauses (z1), (zn), (zo) and (zp) of sub-section (2) of section 181 of the Act;

(xxx)"Control Period" means a period consisting of number of year(s) fixed by the Commission from time to time under the multi year tariff framework for which the licensee or generating company will file the application for tariff determination. Third control period will consist of three ensuing years of 2011-12, 2012-13 and 2013-14. Thereafter, each control period shall be normally for a period of five ensuing years or such other periods of number of ensuing years, as may be decided by the Commission from time to time;

(xxxi)"Controllable factor" means those elements of ARR for which the entitlement is controllable or the expenditure can be controlled by the concerned licensee or generating company for whom ARR is determined at the amount for such element permitted by the Commission in the tariff order subject to specific conditions as permitted under these regulations;

(xxxii)"Core Business" means the electricity generation business for a generating company or the business of transmission or distribution of electricity as per licence of the licensee excluding embedded generation business, if any;

(xxxiii)"Cut-off Date" means the date of closing of the first financial year after two year from the date of commercial operation of a project;

(xxxiv)"Date of commercial operation" or COD means,-

(a)In relation to a unit, the date declared by the generator after demonstrating the maximum continuous rating (MCR) or installed capacity (IC) through a successful trial run after notice to the beneficiaries;

(b)In relation to a generating station, the date of commercial operation of the last unit or block of the generating station in accordance with clause (a) above:

(c)In case of (a) above, the date of commercial operation shall not be more than 90 days from the date of unit synchronization to the grid;

(xxxv)"Date of Synchronization" means the date on which synchronization as defined in clause (cv) of this regulation has taken place with the bus bar.

(xxxvi)"Declared Capacity" or "DC"-

(a)for a thermal generating station means the capability of the generating station to deliver ex-bus electricity in MW declared by such generating station in relation to any period of the day or whole of the day, duly taking into account the availability of fuel; In case of a gas turbine generating station or a combined cycle generating station, the generating station shall declare the capacity for units and modules on gas fuel and liquid fuel separately, and these shall be scheduled separately. Total declared capacity and total scheduled generation for the generating station shall be the sum of the declared capacity and scheduled generation for gas fuel and liquid fuel for the purpose of computation of availability and Plant Load Factor respectively;

(b)for a run-of-river hydro-generating station with pondage and storage-type or pumped storage hydro-generating station means the ex-bus capacity in MW expected to be available from the generating station over the peaking hours of next day, as declared by the generator, taking into account the availability of water, optimum use of water and availability of machines and for this purpose, the peaking hours shall not be less than 3 hours within 24 hour period;

(c)for a purely run-of-river hydro generating station 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;

(xxxvii)"Deemed Generation" means the energy which a hydro-generating station was capable of generating but could not generate due to a force majeure event resulting in spillage of water;

(xxxviii)"Design Energy" in relation to a hydro-generating station means the quantum of energy, which could be generated in a 90 per cent dependable year with 95 per cent installed capacity of the generating station;

(xxxix)"Distribution Business" means the business of operating and maintaining a distribution system for supplying electricity in the area of supply of a distribution licensee:

(xl)"Distribution charge" means the revenue requirement for an ensuing year of a licensee only for its distribution system after deducting the revenue requirement for that ensuing year of its generating station(s) and power purchase cost from the overall ARR of the distribution licensee for that ensuing year;

(xli)"Distribution charge (Recoverable)" means the Distribution charge plus the adjustment arising out of APR for any year pertaining to distribution system only

(xlii)"Distribution Licensee" means a person exempted under section 13 of the Act within the State or a person who has been granted a licence by the Commission under section 14 of the Act including a deemed licensee under the purview of the Commission in pursuance to first, third, fourth proviso to section 14 of the Act and licensee created in accordance with fifth proviso to section 14 of the Act to distribute electricity within its area of supply;

(xliii)"Distribution Loss" means the difference between the energy inputs in the distribution system and the sum of energy sold, energy consumed by the licensee for its own purposes in its own premises within its area of supply and the energy delivered at the drawal point of the open access customer after wheeling by the licensee including normative technical loss of energy due to wheeling as per Open Access Regulations;

(xliv)"DPL" means The Durgapur Projects Limited;

(xlv)"DPR" means the detailed project report;

(xlvi)"DPSCL" means DPSC Limited,

(xlvii)"DVC" means Damodar Valley Corporation incorporated under DVC Act, 1948;

(xlviii)"Ensuing Year" means the year(s) in the control period for which applicable tariff and charge would be determined by the Commission in subsequent years following the base year in the control period and one, two, three, four, five in reference to ensuing year means first, second, third, fourth and fifth years respectively immediately subsequent to such base year;

(xlix)"Emergency Supply" is a supply not exceeding 15 days at a time with a prior notice of two working days. However, for in-situ captive generating plant such period may be extended as required;

(l)"ERC" or "Expected Revenue from Charges"' means the expected revenue from charges and tariff that a licensee or a generating company is permitted to recover pursuant to these regulations;

(li)"Existing Project" means the project declared under commercial operation from a date prior to 21st November 2005;

(lii)"Existing Generating Station" means a generating station, which had a date of commercial operation prior to 31.12,2007;

(liii)"Fees Regulations" means such regulations as may be specified by the Commission under clause (g) of sub-section (1) of section 86 of the Act;

(liv)"Fixed Cost" means ARR or revenue recoverable through tariff reduced by corresponding variable cost for any activity or as a whole of the licensee or a generating station, as the case may be;

(lv)"Force Majeure Event' means, with respect to any party, any event or circumstance which is not within the reasonable control of, or due to an act or omission that party and which, by the exercise of reasonable care and diligence, that party is not able to prevent;

(lvi)"Fuel Cost" means all expenditure related to procurement of fuel that is required for combustion in thermal generating station for generation of electricity only and the associated transportation and handling charges inclusive of fuel quality assurance service cost. fuel delivery assurance cost, fuel quality enrichment cost and any other incidental charges as specified in regulation 5.8 of these regulations;

(lvii)"Generating Company" means any company or body corporate or association or body of individuals, whether incorporated or not, or artificial juridical person, which owns or operates or maintains a generating station and excludes those generating companies covered under clauses (a) and (b) of sub-section (1) of section 79 of the Act or lying outside India or outside the state, except those generating companies whose inter-state supply to any licensee is under the purview of the Commission under sub-section (5) of section 64 of the Act;

(lviii)"Generation Business" means the business of production of electricity from a generating station for the purpose of giving supply to any person or enabling a supply to be so given;

(lix)"Government" or "State Government" means the Government of West Bengal;

(lx)"Gross Calorific Value" or GCV in relation to a thermal power generating station means the heat produced in Kilo Calorie by complete combustion of one Kg of solid fuel, one litre of liquid fuel or one standard cubic meter of gaseous fuel, as the case may be;

(lxi)"Gross Station Heat Rate" means the heat energy input in Kilo Calorie for a generating station required to generate one kWh of electrical energy at generator terminals;

(lxii)"Infirm Power" for these regulations means

(a)electricity generated prior to commercial operation of a unit of a generating station; or

(b)power supplied/received on "as and when available" basis from any generating station/captive generating plant/licensee;

(lxiii)"Installed Capacity" or "IC" means the summation of the nameplate capacities of all the units of the generating station or the capacity of the generating station (reckoned at the generator terminals) as already considered by the Commission in its last tariff order, or as approved by the Commission from time to time.

(lxiv)"Irrigation" to denote a class of consumers means supply of electricity to such consumers for watering or dewatering for the purpose of farming of agricultural produces in his own premises excluding those produces covered by Commercial Plantation:

(lxv)"Licensee" means a person who has been granted licence by the Commission under section 14 of the Act for distribution and / or transmission of electricity and also includes a deemed licensee under the purview of the Commission in pursuance to first to fifth proviso to section 14 of the Act or persons exempted under section 13 of the Act within the State;

(lxvi)"Long-Term Transmission Customer" means transmission system user or intending transmission system user who is or to be long term customer as per open access regulations;

(lxvii)"Maximum Available Capacity"-.

(a)for run-of-river hydro generating station with pondage and storage type or pumped storage hydro-generating stations means the maximum capacity in MW that the generating station can generate with all units running, under the prevailing conditions of water levels and flows available for usage over the peaking hours of next day and for this purpose, the peaking hours shall be as may be scheduled by SLDC, which shall not be less than 3 (three) hours within a 24 (twenty four) hour period for which schedule is drawn;

(b)for a purely run-of-river hydro-generating station means the maximum capacity in MW, the generating station can generate with all units running under the prevailing conditions of water levels and flows available for usage over the next day;

(c)for a thermal generating station means, the maximum capacity in MW, the generating stations can generate with all units running under the fuel availability and equipment availability of the plant over the peaking hours of next day;

(lxviii)"Maximum Continuous Rating" or "MCR" in relation to an unit of a thermal generating station means the maximum continuous output at the generator terminals. guaranteed by the manufacturer at rated parameters or as may be approved by the Commission from time to time, and in relation to a unit or block of a combined cycle thermal 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 specific site conditions or as may be approved by the Commission from time to time;

(lxix)"Monsoon" means July to October of a year;

(lxx)"New Generating Station" means a generating station with a date of synchronization on or after 31.12.2007;

(lxxi)"Non-Tariff Income" means income relating to the core-business other than from tariff, excluding any income from the following activities :

(a)Other business, if applicable;

(b)Auxiliary Services, if applicable;

(c)Wheeling of electricity, if any;

(d)Receipts on account of cross-subsidy surcharge and additional surcharges on charges of wheeling

(e)Income from Unscheduled Interchanges;

(lxxii)"Officer" means an officer of the Commission;

(lxxiii)"Open Access Agreement" means an agreement entered into by an open access customer with transmission licensees, distribution licensees and generators as specified in open access regulations;

(lxxiv)"Open Access Customer" means the person as defined in open access regulations;

(lxxv)"Open Access Regulations" means such regulations specified by the Commission in exercise of the powers conferred by sections 11, 23, 39(2)(d), 40(c), 42(2), 42(3), 42(4), 49, 86(1) read with Section 181 of the Act;

(lxxvi)"Operation and Maintenance Expenses" or "O&M expenses" means the expenses as per regulation 5.7 of these regulations;

(Ixxvii)"Original Project Cost" means the actual expenditure incurred on the project as per the original scope up to cut-off date and as admitted by the Commission;

(lxxviii)"Other Business" means any business engaged in by a transmission licensee referred to in section 41 of the Act or by a distribution licensee referred to in section 51 of the Act for optimum utilization of the assets related to core business of such transmission licensee or for such distribution licensee, as the case may be:

(lxxix)"Plant Load Factor" for a given period, means the total energy generated by a generating station expressed as a percentage of energy corresponding to installed capacity in that period;

(lxxx)"Power Purchase Agreement" or "PPA" means the commercial agreement between a generating company or a licensee with another generating company or licensee, as the case may be, containing the terms and conditions for purchase of electricity by a generating company or a licensee from another generating company or licensee, as the case may be;

(lxxxi)"Previous Year" means four years immediately prior to base year and one, two, three, four in reference to previous year mean first, second, third and fourth years respectively immediately preceding to such base year;

(lxxxii)"Rated Voltage" in relation to a transmission system means the manufacturer's rated design voltage at which the transmission system is designed to operate, or such lower voltage at which the line is charged, for the time being, in consultation with the transmission system

(lxxxiii)"Regulations" means regulations made under the Act;

(lxxxiv)"Research & Development Expenditure" or "R&D Expenditure" means expenditure on the head of pilot project, research in fundamental or applied science, research in technology or engineering, survey or studies on available technology or consumer base or market base, impact assessment on environment and society, audit or survey in relation to safety, occupational health hazards, energy, grid security, and grid protection. etc.

(lxxxv)"Rules" means rules made under the Act;

(Ixxxvi)"Run-of-river hydro-generating station" means a hydro-generating station. which has no upstream pondage;

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

(Ixxxviii)"Salable Energy" means the quantum of energy available for sale (ex-bus) in respect of hydro-generating station after allowing share of free energy, if any, as per agreement or government policy;

(lxxxix)"Salable Primary Energy" means the quantum of primary energy available for sale (ex-bus) after allowing free energy, if any, to the home state;

(xc)"Schedule" means the schedule to these regulations;

(xci)"Scheduled Generation" or "SG"-

(a)for thermal generating station at any time or for any period or time block means schedule of generation in MW ex-bus given by the SLDC;

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;

(b)for hydro generating station means the quantum of energy to be generated at the generating station over the 24 hour period as scheduled by the SLDC and available for sale (Ex-bus);

(xcii)"Season" means a block of four months;

(xciii)"Secretary" means the Secretary of the Commission;

(xciv)"Short Term Supply" means supply for festivals and domestic events including marriage ceremony, etc. for a period not exceeding 35 days at a stretch;

(xcv)"Short Term Supply for Commercial Plantation" means supply of electricity for watering or dewatering of plantations of a tea garden or horticulture or tissue culture or floriculture or herbal/medicinal/bio-diesel farming for a period not exceeding 180 days at a stretch;

(xcvi)"Short Term Irrigation Supply" means supply of electricity for watering or dewatering for the purpose of farming of agricultural produces excluding those produces covered by Commercial Plantation for a period not exceeding 125 days at a stretch;

(xcvii)"Standards of Performance Regulations" or "SOP" means the regulations as specified by the Commission under sub-section (1) of section 57 and sub-section (1) of section 59 of the Act;

(xcviii)"SLDC" means the State Load Despatch Centre established by the Government of West Bengal under sub-section (1) of section 31 of the Act;

(xcix)"State" means the State of West Bengal;

(c)"State Grid" means the same as defined in State Grid Code;

(ci)"State Transmission System" means the state transmission system as defined in state grid code;

(cii)"STU" means WBSETCL or any other Government Company as notified by the Government of West Bengal under sub-section (1) of section 39 of the Act;

(ciii)"Storage type hydro-generating station" means a hydro-generating station associated with large storage capacity to enable variation in generation of electricity according to demand;

(civ)"Summer" means March to June of any calendar year;

(cv)"Synchronization" for the purpose of these regulations means the first commissioning (except test synchronization) of an unit of a generating station for the commencement of trial run prior to date of commercial operation and thereby injecting electricity in the State Grid with full availability of all load bearing equipments and all systems of the generating station subject to specific deviations as specified in regulation 6.15.3 of these regulations and excluding the instances of test synchronization;

(cvi)"Tariff" means a schedule of prices payable by recipient person of electricity for supply of electricity to him or the charges payable by the person for availing specified service of wheeling or transmission of electricity which are determined under section 62 or section 64 of the Act in pursuance to these regulations;

(cvii)"Test Synchronization" means the commissioning of any unit with its full/partial installed capacity and thereby injecting the electricity in the State Grid for the purpose of test operation of such unit;

(cviii)"Transmission Business" means the business of establishing or operating transmission lines by transmission licensee;

(cix)"Transmission Licensee" means a person who has been granted a licence by the Commission under section 14 of the Act including a deemed licensee under the purview of the Commission in pursuance to second, fourth proviso to section 14 of the Act and licensee created in accordance with fifth proviso to section 14 of the Act to transmit electricity;

(cx)"Transmission Loss" means the difference between the energy inputs in the transmission system for transmission of electricity and energy delivered by the transmission system at delivery points including auxiliary and own consumptions of the transmission licensee;

(cxi)"Transmission System" means a transmission line with associated sub-stations or a group of transmission lines inter-connected together along with associated sub-stations and the term includes equipment associated with transmission lines and sub-stations;

(cxii)"Transmission System User" means a person, who has been allotted transmission capacity rights to access an intra-state transmission system pursuant to a bulk power transmission agreement;

(cxiii)"Uncontrollable factor" means those elements of ARR for which expenditure depends on certain external factors and which are not fully controllable by the licensee or generating company;

(cxiv)"Unit" in relation to a thermal power generating station means steam generator, turbine-generator and auxiliaries, or in relation to a combined cycle thermal power generating station, means turbine-generator and auxiliaries;

(cxv)"Useful Heat Value" or "UHV" in relation to fuel means the established heat value of fuel based on which payments are made to the suppliers of fuel. In case of coal, where payments are made in other units, in such cases the corresponding conversion will be done as per the following formula:

UHV = 8900 - 138 x (A+M). where UHV is in Kcal/Kg and A and M stand for ash and moisture content of coal respectively in percentage of coal composition;

(cxvi)"Variable Cost" means the fuel cost and/or power purchase cost portion of ARR or revenue recoverable through tariff for all or any of the activities, as the case may be, of a licensee and/or generating station(s) or generating company, as the case may be;

(cxvii)"WBERC" means the West Bengal Electricity Regulatory Commission;

(cxviii)"WBPDCL" means The West Bengal Power Development Corporation Limited;

(cxix)"WBSEB' mean West Bengal State Electricity Board or its successor distribution licensee(s) along with its generating stations;

(cxx)"WBSEDCL" means the West Bengal State Electricity Distribution Company Limited formed as successor distribution licensee of WBSEB under section 131 of the Act along with its generating stations;

(cxxi)"WBSETCL" means the West Bengal State Electricity Transmission Company Limited formed as successor transmission licensee of WBSEB under section 131 of the Act;

(cxxii)"Winter" means November to February of a year;

(cxxiii)"Year" means a financial year.

1.2.2- Words and expressions used in these regulations and not defined shall have the meanings respectively assigned to them in the Act or the Regulations made thereunder by the Commission.

Chapter - 2 Determination of Tariff

2.1General Principles.-

2.1.1- The Commission shall determine tariff including terms and conditions thereof for all matters for which the Commission has the power under the Act, including the following cases :-

(i)Supply of electricity by a generating company within the state to a distribution licensee within the state except the specific provision permitted under these regulations.

Provided that the Commission may, in case of shortage of supply of electricity, fix the minimum and maximum ceiling of tariff for sale or purchase of electricity in pursuance of an agreement entered into between a generating company and a licensee or between licensees, for a period not exceeding one year;

(ii)Intra-State transmission of electricity within the state for intra-state transmission system;

(iii)Rates and charges for use of intervening transmission facilities, where these cannot be mutually agreed upon by the licensees within the state;

(iv)Wheeling of electricity within the state;

(v)Retail sale of electricity within the state:

Provided that in case of distribution of electricity in the same area by two or more licensees, the Commission may, for promoting competition among licensees, fix only maximum ceiling of tariff for retail sale of electricity :Provided also that where the Commission has allowed open access to certain consumers under section 42, such consumers, notwithstanding the provisions contained in clause (d) of sub-section (1) of section 62 of the Act, may enter into an agreement with any person for supply or purchase of electricity on such terms and conditions (including tariff) as may be agreed upon by them;

2.1.2- Where the Commission has permitted open access to any consumer or a category of consumers under section 42 of the Act, the Commission shall determine only the wheeling charges and surcharge thereon, if any, in pursuance to the proviso to clause (a) of sub-section (1) of section 86 of the Act, and no tariff for such consumer or the category of consumers for wholesale, bulk or retail supply of electricity, as the case may be, shall be determined by the Commission under these regulations for the part corresponding to Open Access mode.

2.1.3- Notwithstanding anything contained in these regulations, the Commission shall adopt the tariff if in pursuance to section 63 of the Act such tariff has been determined through a transparent process of bidding in accordance with the guidelines issued by the Central Government to the extent they are consistent with the Act.

2.1.4- The Commission will regulate electricity purchase and procurement process of distribution licensees including the price at which electricity shall be procured from-

(i)The generating companies or licensees within the state through agreements for distribution and supply of such power within the State and where the tariff for such electricity purchase will be determined under sub-section (1) of section 62 of the Act;

(ii)The generating companies or licensees or from other sources from outside the state through agreements for purchase of power to distribute electricity and make payments therefor in accordance with sub-section (5) of section 64 of the Act.

(iii)The generating companies or licensees or from other sources from outside the state or outside India through agreements for purchase of power for distribution and supply of such power within the state under clause (b) of sub-section (1) of section 86 of the Act but where such supply against purchase is not done under sub-section (5) of section 64 of the Act.

(iv)Any sources by participating in any bidding process through any Power Exchange which is approved by the Commission or CERC in pursuance to section 66 of the Electricity Act, 2003.

2.1.5- While regulating the electricity purchase and procurement process of distribution licensees as mentioned in regulation 2.1.4 for any purchase of power, except through competitive bidding under section 63 of the Act, from any electricity trader or any distribution licensee of states other than West Bengal, the purchase price will be approved by the Commission on the basis of reasonability through:-

(i)Bench marking process with the market driven price when there is any short term procurement of power done either through negotiation or competitive bidding mode which is not covered under the guideline under section 63 of the Act.

(ii)Bench marking process with the price found out from tariff determined under section 62 or 64(5) on normative basis or levelised tariff accepted under investment approval by the Commission or tariff adopted under section 63 of the Act in case of similar type of medium term or long term power procurement.

Such methodology of purchase price determination for the power procurement by the licensee from the electricity trader or distribution licensee of States other than West Bengal will be applicable for procurement both through negotiated route or through any competitive bidding other than the route mentioned in section 63 of the Act.

2.1.6- In case of inter-state supply the purchase price by a distribution licensee will be determined in any of the following ways :

(a)Notwithstanding anything contained in Part X of the Act, the Commission in pursuance of sub-section (5) of section 64 of the Act. upon application made to it by the parties intending to undertake inter-state supply, transmission or wheeling, shall determine the tariff in cases where one of the parties intending to distribute electricity and make payment therefor is under the Commission's jurisdiction.

Provided that the Commission shall determine such tariff having regard to the terms and conditions specified in these regulations for determination of tariff for generation, transmission, supply and wheeling of electricity wholesale, bulk or retail, as the case may be.Provided also that the Commission, while determining tariff upon an application made to it under this regulation, may to the extent considered appropriate also have regard to the terms and conditions of tariff as may be determined by the Appropriate Commission so far as they are consistent with the Act, where any of the parties of such transaction come under the jurisdiction of such Appropriate Commission.

(b)The tariff determined by CERC for any generating station will be accepted by the Commission and no further re-determination will take place.

(c)The tariff adopted in pursuance to regulation 2.1.3 of these regulations.

(d)The price discovered by power exchange in pursuance to regulation 2.1.4 (iv) of these regulations.

(e)The purchase price approved by the Commission in pursuance to regulation 2.1.5 of these regulations.

2.1.7- If any licensee has not applied for determination of tariff for supply and / or transmission and / or wheeling of electricity for any year(s) prior to the coming into force of these regulations, such tariff for that / those year(s) shall be determined under these regulations.

2.1.8- The Commission will not determine the tariff of the part of supply from a generating station to a person who is not under the purview of the Commission.

2.1.9- The tariff / charges determined under these regulations are in addition to other charges which are specified in open access regulations or any other regulations of the Commission.

2.1.10- Any losses incurred by a generating company or a licensee and arising out of sale of electricity for which tariff is not determined under these regulations shall not be allowed to be compensated while determining the tariff or while annual performance review is undertaken under these regulations.

2.1.11- For the purpose of these regulations any procurement of electricity to be considered as long term procurement of electricity or medium term procurement of electricity as per the guidelines issued by the Central Government under section 63 of the Act. For the purpose of these regulations, short term procurement of electricity means the procurement not covered under long term or medium term procurement of electricity.

2.1.12- The tariff determined or adopted for any generating station by CERC or the Commission under section 62(1), 63 and 64(5) of the Act will not be re-determined by the Commission while regulating the purchase and procurement process of the licensee and subject to the above the Commission may determine whether the licensee should enter into PPA or Commission should regulate the procurement process or procurement amount as decided by the Commission. However once the price of procurement of power by any licensee is approved by the Commission under clause (b) of sub-section (1) of section 86 it cannot be re-determined under sub-section (1) of section 62 of the Act or under sub-section (5) of section 64 of the Act.

2.1.13- Any previous orders based on earlier regulations framed under section 61 of the Act cannot be re-opened for re-determination under these regulations.

Provided that if such order is being referred to the Commission by any court of law for re-determination then that matter will be treated under these regulations.Provided further that in such case where such re-determination is to be taken due to order of the Court of Law, the normative parameters, method of calculation and principles of calculation will remain as had been considered in the concerned tariff order and related repealed regulations to the extent it is not affected by the order of the Court of Law.Provided also that, in such case, if re-determination of tariff due to order of Court of Law is to be undertaken by the Commission and the concerned ensuing year for which tariff is to be re-determined is already passed over, then the Commission may ask the licensee or generating company to re-submit the updated expenditures on different heads of uncontrollable ARR item, so that tariff can be re-determined with better accuracy to reduce the impact of FPPCA and APR of ensuing year in future tariff.

2.1.14- Notwithstanding anything to the contrary contained elsewhere in these regulations, if the tariff order of any generating station or any unit of it of a generating company is not determined for any year prior to the 3rd Control Period, then the tariff for such generating station or the unit of it, as the case may be, will be determined under the repealed regulations.

2.1.15- The truing up of the ARR under APR and FPPCA for the year 2009-10 and 2010-11, for which order of APR or FPPCA has not yet been issued by the Commission, will be done under these regulations subject to the conditions that for the fixed cost determination under APR, the normative parameters, method of calculation and principles of calculation will remain as had been considered in the concerned tariff order relevant to the ensuing year for which APR is considered subject to the conditions that "controllable" and/or "uncontrollable" item along with gain sharing and incentive during APR will be considered in accordance with the repealed regulations. However, for fuel cost determination or variable cost determination the fuel surcharge formula termed as FPPCA in Schedule 7A of these regulations will be used on the basis of normative parameters as had been used in the concerned tariff order of the ensuing year for which FPPCA is to be determined and also on the basis of application of regulation 4.8.1 of the repealed regulation.

2.2Guiding Factors for Tariff Determination. -

2.2.1- Without prejudice to the generality of the powers of the Commission, but subject to the guidelines outlined in section 61 of the Act, the Commission shall be guided by the following while determining the tariff-

(i)Only for the purpose of determination of tariff for the generating station and transmission licensee, the principles and methodologies specified by the CERC for determination of the tariff applicable to generating companies and transmission licensees shall be followed so far as they are consistent with the Act;

(ii)The generation, transmission, distribution and supply of electricity are conducted on commercial principles;

(iii)The factors which would encourage competition, efficiency, economical use of the resources, good performance and optimum investments;

(iv)Safeguarding of consumers' interest and at the same time, recovery of the cost of electricity in a reasonable manner;

(v)The principles rewarding efficiency in performance;

(vi)Multi-year tariff principles, as specified in regulation 2.5;

(vii)That the tariff progressively reflects the cost of supply of electricity and also reduces cross-subsidies within three years so that for any class of consumers the average tariff for that class does not go either below 80% of the average cost of supply or above 120% of the average cost of supply;

(viii)The promotion of co-generation and generation of electricity from renewable sources of energy;

(ix)The National Electricity Policy and Tariff Policy so far as they are consistent with the Act and provide rationality with the state specific situations as well as the real time situations.

2.2.2- In addition, the Commission may also keep in view and be guided by the requirements relating to the -

(i)Compliance of environmental standards to reduce the health risks of citizen through less pollution from generation source and different activities of generating companies and licensees;

(ii)Compliance of safety standards;

(iii)Compliance of different statutory requirements of other statutes so far as they are consistent with the Act;

(iv)Compliance of different rules made under the Act so far as they are consistent with the Act;

(v)Compliance of requirement of energy conservation through tariff mechanism to encourage optimum and economic utilization of available electricity and to discourage unnecessary and wasteful use of electricity. Energy conservation also includes demand side management, water conservation, to prevent abuse of electricity usage and to promote usage of energy efficient devices.

(vi)The need of reserve generation capacities to fully meet energy demand and peak demand inclusive of the need arising from non-availability of requisite power due to time over-run of commissioning schedule of power generating stations under construction and consequent to changes in central sector allocations or its principles;

(vii)Performance standards and other norms as may be specified or directed by the Commission including incentives and penalty relating to such standards,

(viii)Development of market relating to electricity;

(ix)Affordability and need of power of different sections of society in the interest of the consumers as well as the sustainability of the licensee;

(x)Requirement and need to insulate the consumers from sudden tariff shocks in a particular year or number of years and to protect both the consumers and the licensee or generating company;

(xi)Requirement and need to have funds and its availability at short notice to meet unexpected emergent circumstances where power supply is affected materially and cannot be met under normal business activities;

(xii)Requirement of the minimum level of support to make electricity affordable to consumers of very poor category;

(xiii)Requirement of adequate payment security arrangements;

(xiv)Requirement of clause (b) of sub-section (3) of section 131 of the Act;

(xv)Requirement to meet the need arising out of other regulations of the Commission;

(xvi)Requirement to meet the Accounting Standards applicable to a Generating Company or a Licensee as per Law.

Provided that while determining the tariff, the Commission may keep in view the existing and future balances available under consumer account, tariff & dividend control account, undistributed rebates, development reserve, contingency reserve, deferred taxation reserve along with its investment and income in accordance with regulation 5.4.1 of these regulations.Provided further that the Commission depending upon the available factors / data / information, or any other material which it may consider appropriate in each case, may. either fix separate rates or by any other method impose extra charges, incentives, penalty etc. on the basic tariff to achieve the purpose of any one or more factors mentioned above to the extent feasible and keeping in view the overall interest of the consumers, licensees / generating company and / or the electrical system as a whole.Provided also that the tariffs of any licensee determined under these regulations for different categories of consumers are the maximum ceilings for supply of electricity at any agreed price to the consumers, only for those areas of supply of the licensee where multiple licensees exist subject to the condition that if for effecting of supply of electricity to any consumer at such lesser price than the above mentioned upper ceiling the licensee incurs any loss, such loss shall not be allowed to be passed on to any other consumers or any other licensee of the Commission.Provided also that in case the obligation of distribution of electricity to all classes of consumers in the same area by two or more distribution licensees has emerged as a result of introduction of the Act, then in order to provide benefits of competition to all sections of consumers through providing a similarly placed and similarly circumstanced framework to all the competing licensees, the Commission shall determine the tariff of different classes of consumers in such a manner that the ratio of the tariff for various categories of consumers and average tariff of each licensee in that area can be maintained in the same level as far as possible.

2.2.3- The Commission at its sole discretion will follow the above principles and suitably apply the same to the extent required in each case. The Commission shall, at its sole discretion, determine the extent to which reliance may be had on any one principle, or more than one principle in any combination in each case having regard to the facts revealed in each such case.

2.2.4. - The financial terms and conditions for determination of tariff for the licencees and generating companies shall be as laid down in various provisions of Schedule - 1 and 3 to Schedule - 8 pertaining to these regulations. In case of overlapping, or in the case of licensees falling under more than one Schedule, or in those cases where none of the Schedules is applicable, the relevant Principles of Schedule - 5 may be followed subject to such modifications, as the Commission may consider appropriate in such a case.

2.2.5- Before incurring any capital expenditure by a licensee or a generating company supplying power to any licensee, prior approval of the Commission shall be taken as per regulations 2.8.1.4 or 2.8.2.3 or 2.8.3 or 2.8.4 of these regulations, as the case may be.

2.2.6- Where information is not available in previous or base year, then the principles of different factors as detailed in Chapter - 3 may be applied for projected tariff for any class of consumers on the basis of best estimate as deemed fit by the Commission with a provision of adjustment of the difference between the actual and the projections for future ensuing year(s) of the control period or subsequent control period, as the case may be.

2.2.7- Any payment on the head of penalty or compensation or fine or penal taxes / duties / cess or disincentive or excess cess / royalty or under any name for violation or non-compliance or contravention of any provision of any statute or order of any statutory body or order of any judicial body subject to dispensation under extenuating circumstances to maintain supply of electricity shall not be considered as an expenditure recoverable through tariff excluding those items to the extent specifically permitted in these regulations. However, if the penalty or fine or penal taxes / duties / cess or disincentive or excess cess/ royalty or any payment under any name imposed on any erstwhile licensee by any order of the Commission or any order passed by any Tribunal/ Court for any previous year is paid by any licensee who has taken over the assets and liabilities of that erstwhile licensee, that may be allowed to be recovered through tariff.

2.2.8- For non-submission or inappropriate submission of information or data as required under these regulations, the Commission may withhold any amount or not allow any expense as considered necessary.

2.3Manner for provision of subsidy by State Government. -

2.3.1- With effect from the date of publication of these regulations, if the state government requires or if, as a consequence of state government's any decision, there is requirement of the grant of any subsidy to any consumer or class of consumers in the tariff determined by the Commission, the state government shall pay in advance the amount to compensate the licensee / person affected by the grant of subsidy in the manner specified in schedule -6 of these regulations.

2.3.2- The amount of subsidy agreed to by the State Government shall be provided in the form of grant by the State Government.

2.3.3- The subsidy shall be passed on to eligible consumers only in proportion to the extent to which the total requirement of the licensee is paid by the State Government. Provided that in case of shortfall in actual release of subsidy, either because of errors in estimation or for any other reason, such shortfall, shall be shown clearly in the consumers' bill and shall be distributed on a pro rata basis among the concerned eligible consumers until such time the shortfall is reduced or eliminated.

Provided further that in case of release of government subsidy for a period at a later stage, the licensee shall pass through such subsidy in proportion to the consumption by the consumer in the above period through electricity bill.

2.4Invitation of Suggestions and Objections or hearing - Notwithstanding anything to the contrary contained elsewhere in these regulations or any other regulations of the Commission. the Commission will undertake hearing or invite suggestions and objections in a manner and at a stage which is only specifically provided in these regulations with following provisions.

(i)Wherever there is invitation of suggestion and objection under these regulations it shall mean that such suggestion and objection shall always be submitted in written form only.

(ii)Whenever suggestions and objections are required to be invited under these regulations it shall be through advertisement in website or/and newspaper in a manner as specified in these regulations for any purpose.

(iii)Hearing wherever provided in these regulations shall always be supported by a written submission which shall be compatible with the oral submission made during hearing. The issue(s) raised in the written submission of any hearing will only be considered as the content ,of hearing in the proceeding by the Commission.

2.5Multi year Tariff (MYT) Framework. -

2.5.1- MYT framework shall be based on the following elements, for calculation of ARR and ERC of each ensuing year and determination of tariff for first ensuing year and amendment of the tariff in the second and onwards ensuing year after due permitted adjustment with the ARR of the ensuing year as determined in the first ensuing year. :

(i)Under the MYT Framework at the commencement of control period every generating company and licensee shalt file a composite application with the projection of ARR and ERC and proposal of tariff including principles of tariff structure for each ensuing year of the control period separately on the basis of projected ARR for the purpose of :

(a)ARR determination for each ensuing year;

(b)tariff determination for the first ensuing year;

(c)amendment of tariff of the first ensuing year or any subsequent ensuing year of the control period for the purpose of fixation of applicable new tariff for any ensuing year after due adjustment of ARR in pursuance to regulation 2.5.3 of that ensuing year as determined under (a) above.

The above filing for the control period shall be made by the generating company / licensee as specified in regulation 2.7.1 & 2.7.2 of these regulations. Such application may consider the ARR of the generating station/unit or other distribution/transmission projects that may be put into commercial operation within the control period and such aggregate revenue requirement shall be considered from the projected date of commercial operation The filing shall be in the form as specified in these regulations, with year wise details for each ensuing year of the control period, duly complying with the principles for determination of ARR as specified in these regulations. For the said control period for all the existing generating stations of a generating company, there shall be one composite application for determination of tariff for each of the generating stations separately showing projected ARR and proposed tariff for each ensuing year. Similarly for determination of transmission tariff, the transmission licensee shall submit a composite application showing projected ARR and proposed tariff along with principles of such tariff structure for each ensuing year separately. Similarly, for determination of tariff / charges of wheeling and retail sale of electricity, the licensee shall submit one composite application showing projected ARR and proposed tariff along with principles of such tariff structure for each ensuing year separately.Provided further that the licensee, part of whose electricity business is regulated by the Commission, shall file the application for determination of tariff according to these regulations for that part only.

(ii)Generating company or licensee's projection of ARR and ERC for each ensuing year during the control period shall be based on reasonable assumptions related to the expected behaviour of the various operational and financial variables subject to operating norms as laid down in Schedule - 9A or Schedule - 9D of these regulations;

(iii)Under the MYT framework against the admitted application of tariff determination for the control period, for first ensuing year of the control period the ARR and tariff will be determined in the tariff order of the first ensuing year. In the tariff order of the first ensuing year of the control period ARR will also be determined for second and onwards ensuing years of the control period which will be subject to adjustment as per regulation 2.5.3 of these regulations for amendment of tariff for the purpose of determination of ERC of that ensuing year on the basis of that adjusted ARR in the tariff order of the relevant ensuing years of the control period in a way as described in regulation 2.5.6.2 (iii).

(iv)ARR of each ensuing year shall be based on the normative operational parameters as laid down in Schedule - 9A or Schedule - 9D in these regulations subject to sharing of gains and incentives at the stage of Annual Performance Review as specified in regulation 2.6 of these regulations for improved performance as provided for in these regulations under Schedule - 9B and Schedule - 10, if any, with the consumers or any other person for whom tariff is determined under these regulations;

Provided that such sharing of gains shall be computed for each normative parameter separately and shall be considered for sharing and shall be independent of actual performance of other operational parameters for which there are norms subject to conditions and limitations as specified in regulation 2.8.6 and in Schedule - 9B of these regulations.

(v)Any generating station or generating unit of any venerating company or licensee, commissioned in intermediate period of an ensuing year of a control period and for which tariff/ARR has not been determined under the tariff order of the first ensuing year of the control period, will be considered for tariff determination for the remaining period of that ensuing year and determination of ARR for the remaining period of that control period on submission of application for tariff determination 120 days before the proposed date of synchronization of the generating station/unit and the Commission may give its effect immediately or subsequently, as may be decided by the Commission.

Provided that such generating station/unit shall go for synchronization with all load bearing equipments available and a I systems on the date of the synchronization and accordingly the status of all equipments of such generating station/unit is to be provided with the application for tariff determination. On the basis of the status of the equipments and other requirements as per regulations, the Commission, at its discretion, will take its decision for admitting such application for tariff determination or otherwise.

2.5.2Contents of MYT Filing. -

2.5.2.1- For ARR determination filing under the MYT framework shall contain the following :

(i)The employee cost, repairs & maintenance costs, administrative & general costs, and fuel cost estimated for the base year, and the actuals for the previous year(s) in complete detail, together with the projection for each item for ensuing year(s) of the control period;

(ii)Detailed scheme/project-wise Capital Investment Plan with a capitalization schedule covering each year of the control period;

(iii)A proposal for appropriate capital structure to meet the capital investment plan with details of cost of financing including interest cost on debt and return on equity;

(iv)The audited data of actual quantum of energy consumed in the own premises of the generating company or licensee in the previous years (as available);

(v)Details of depreciation and capitalization schedule for each year of the control period:

(vi)Details of taxes on income, statutory fees, levies and charges;

(vii)Any other relevant expenditure;

(viii)Plans to contain and reduce the losses in generation, transmission and distribution both short-term and long-term. Where any energy audit has been conducted by any accredited energy auditor or any statutory bodies, broad details and results thereof along with in the recommendations of the energy auditors may be submitted. The method and system of determining the losses and its bifurcation between technical losses and other than technical losses be suitably explained in detail.

(ix)Copy of Audited accounts of last five years under the statute of incorporation along with Auditor's Report and replies of the management;

(x)Copy of the Proforma A to F under Cost Accounting Records (Electricity Industry);

(xi)ERC at the existing tariff including non-tariff income;

(xii)A statement giving full details of subsidies received and receivable, if any, the consumers to whom it is directed and the way in which such subsidy is proposed to be reflected in the proposed tariffs applicable to these consumers:

(xiii)A list of year(s) for which FPPCA and APR application have been submitted and for which FPPCA and APR application are yet to be submitted to the Commission along with reasons for non-submission;

(xiv)Proposed tariff structure or sale price of each of the ensuing years applicable for consumers or any licensee purchasing power from the applicant along with any proposal on terms & conditions of tariff. The rationale of tariff revision proposal and Category and sub-category wise details of consumers along with seasonal energy consumption and time-strata wise energy consumption for TOD system for each sub-category as applicable shall also be submitted;

(xv)Gist of the Tariff Application as specified in Annexure - 7 for publication;

(xvi)In case of differences between the amounts appearing in the audited annual accounts and amounts appearing in the application for determination of tariff under any head, due to adjustments, for any reason whatsoever a reconciliation statement is to be furnished;

(xvii)Perspective plan in accordance with guidelines as specified in Schedule - 2:

(xviii)Copy of the Energy Audit and action plan for efficiency improvement if any; and,

(xix)Any other matter considered appropriate.

2.5.2.2- For filing Tariff application the relevant information is to be furnished in the specified forms annexed to these regulations.

2.5.2.3- While projecting costs on different heads of ARR for the ensuing years of a control period, a licensee or a generating company shall take into consideration the impact of inflation, efficiency improvement programme or any other specific issues that may clearly be established by the licensee/ generating company:

Provided that for projection of fuel cost for the ensuing years, the principles laid down in regulation 5.8.1 shall be followed.

2.5.2.4- For data submission to fulfil the requirement of principles of differentiation and other factors as detailed in Chapter - 3 and Chapter - 4 the data available for previous and base years must be provided where the licensee proposed such differentiation for a class of consumers for whom it is not in existence, and the licensee shall give its projections on the basis of best estimate.

2.5.2.5- Where any element of ARR or ARR as a whole of a licensee is not available with the licensee separately for distribution system, generating station(s), and other activities such as transmission system, electricity trading, etc for a period prior to coming into force of the Act, the licensee may allocate such element of ARR or ARR of the licensee among the activity of distribution system, each generating station and other activities on the basis of any principle approved by the Commission. On receiving prior application with requisite details the Commission will invite suggestions and objections through website and at least four newspapers on that application and on receiving such suggestions and objection shall give appropriate order.

2.5.2.6- The Commission may specify additional information requirements and / or amend the requirements given above for furnishing the details or in the procedure for calculating the expected revenue.

2.5.2.7- If a person holds more than one licence and / or is deemed to be licensee for more than one area of distribution or transmission, he shall submit separate calculation as above in respect of each licence for each area of transmission or distribution. The licensee shall separate the accounts function wise.

2.5.2.8- A licensee having Generating Station(s) shall maintain and submit separate records for the core business and each of the generating stations.

2.5.2.9- Licensee engaged in other business for optimum utilization of their assets related to core business under jurisdiction of the Commission shall maintain separate records for such other business and submit with tariff proposal the proportion of revenue realized from such other business which has utilized these assets, to reduce the transmission / wheeling charges. A declaration / undertaking by the Director/ Secretary/ Partner of the applicant licensee is to be provided with the tariff / APR petition to the effect that all expenditure claimed/ furnished relates only to the licensed transmission / distribution business for which the petition is being furnished and no additional expenditure incurred under any head and by whatever nomenclature called has been included therein.

2.5.2.10- All status/progress reports, plans and schemes which are directed in tariff order are to be submitted along with the application for tariff or Annual Performance Review.

2.5.2.11- Notwithstanding the above, the Commission shall be entitled to require the generating company / licensee to give such other or further information, particulars and documents at any stage of the tariff determination process as the Commission may consider appropriate in a manner as the Commission may find appropriate.

2.5.2.12- The information, report, computation etc. required to be furnished by the licensee or the generating company in the formats contained in these regulations for calculating aggregate revenue requirement to be met from tariff and charges shall include the particulars specified herein. to the extent applicable. Unless otherwise mentioned. calculations submitted shall include specified details in respect of previous year(s), base year and ensuing year(s) as applicable. For previous years, the details to be submitted as per approved tariff rates and audited accounts for each year separately. For base year, it shall be an estimated figure based on the trend of available actuals and projection. For ensuing years such submission shall be a projection on the basis of the actual trend of previous year and estimated trend of base year subject to modification of specific additional input for which supporting documents are to be provided. Different estimated values for the base year of the control period will be determined on the basis of the actual trend available for any period in the base year along with experience gained from the audited accounts of the previous year for the balance period.

2.5.2.13- For the purpose as mentioned in regulations 3.3.1, 3.3.2 & 3,3.3, generating company or the licensee, as the case may be, while submitting tariff application for a Control Period shall provide actual supply from generating station to a licensee or supply from licensee to licensee, as the case may be, in MU for the previous years. They shall provide such values of each season of ensuing years on projection basis and on estimated basis for base year, subject to any specific variation, if any. All such values of actual, estimated and projection for previous years. base year and ensuing year(s) respectively shall be given in each time strata separately for each season according to the time strata as per regulation 3.13.

2.5.3- Allowable Adjustment against already determined ARR of any ensuing year.

(i)Any adjustable amount based on the results of the APR or FPPCA of any or number of previous year(s), as available may be adjusted with the ARR of any ensuing year of a control period;

(ii)In case of ARR determination of any generating unit of a generating station as per regulation 2.5.1 (v), such ARR of the generating unit will be added with the already determined ARR of the generating station or licensee for any ensuing year for which ARR has been determined but tariff is yet to be declared for the ensuing year concerned and such adjustment shall take place in the tariff order or APR order of that ensuing year as required.

(iii)For the purpose of ARR determination where any element of ARR or ARR as a whole of a licensee cannot be ascertained for its distribution system, generating station(s), and other activities such as, trading of electricity, transmission of electricity and other activities separately for any reasons whatsoever while determining the overall ARR of that licensee during ARR determination of different ensuing years of a control period but subsequently such elements of ARR are available through any application of APR of the licensee or through tariff application to the Commission, then the Commission may allocate or reallocate such element of already determined overall ARR between the distribution system or generating station or other activities on the basis of such available information while passing the order of the tariff or APR of any year subject to condition that overall ARR shall not be altered for any ensuing year of the control period for which ARR is already determined in the 1st ensuing year of the control period except due to the permitted alterations as specified in the regulation 2.5.3 of these regulations.

(iv)For the purpose of ARR determination where any amount is admitted but withheld on any ground and not allowed in the ARR of any ensuing year while determining such ARR under any tariff application but subsequently the reasons for such withholding is addressed properly and such amount becomes eligible to be recovered through tariff, then such amount may be adjusted with the ARR of any ensuing year(s) during determination or amendment of tariff for that or those ensuing year(s) or through APR of any year as may be decided by the Commission.

(v)In case any error is found in the determined ARR of any ensuing year in any tariff order or APR due to miscalculation or consideration of improper data or missing of any data, then the Commission may while issuing tariff order for an ensuing year, rectify the error on the basis of any application or suo moto and make necessary adjustment for such rectification in the ARR of any ensuing year or in APR of any year. In such case such rectification shall not be treated as review order.

(vi)Notwithstanding anything to the contrary contained elsewhere in these regulations, in case of changes in fuel price or power purchase cost if it is found that fuel price or power purchase cost considered during ARR determination differs significantly from the prevailing fuel price or power purchase cost during determination of tariff of any ensuing year. the Commission may change the ARR accordingly as deemed fit on that account of fuel price or power purchase cost only by adopting the same principle of computation of fuel cost or power purchase cost as followed during determination of ARR of the concerned ensuing year in the tariff order of the 1st ensuing year of the control period.

(vii)Notwithstanding anything to the contrary contained elsewhere in these regulations, if during tariff order for any ensuing year other than the first ensuing year of a control period, it is found that some elements of the ARR of any ensuing year already determined in the tariff order of the first ensuing year requires re-determination due to order of any appropriate Court of Law or any change in the accounting principles due to change in Accounting Standard as per law, then the Commission may re-determine the said elements with due adjustment in ARR during tariff determination or amendment of tariff for that ensuing year.

(viii)Notwithstanding anything to the contrary contained elsewhere in these regulations, if during determination or amendment of tariff for any ensuing year of the control period it is found that due to change in Income Tax law, cess or any statutory compliances (except for any compensation, penalty or fine adjustment) any adjustment is required with the already determined ARR of the ensuring year as determined in the first ensuing year of the control period then the Commission may accordingly adjust such ARR of the ensuing year concerned.

(ix)Notwithstanding anything to the contrary contained elsewhere in these regulations, if it is found that any payment become payable in the ensuing year for which ARR is under consideration and such payment arises out of any order of APR and/or FPPCA of the Commission of any entity for any ensuing year then such payable amount may be adjusted with the ARR of the concerned year.

(x)In case of increase in employee cost due to wage revision through agreement or Government order or decision of the company or change in statutory provisions or applicable accounting standards over the amount already admitted in the determined ARR of any ensuing year for which tariff is not yet determined, the Commission may, on an application at any time from the generating company / licensee which includes submission of format 1.17(i), admit the amount and adjust the additional amount required for such purpose with already determined ARR for the concerned ensuing year while determining the tariff for that year or through any other order and in that case the generating company/ licensee may consider the ascertained additional amount as revenue for the ensuing year. However, if such increase in employee cost is applicable from any retrospective date covering the period for which tariff has already been determined, then that amount shall also be considered as employee cost for the year as per relevant accounting standard and will be allowed to be recovered through APR or tariff of any ensuing year(s). However, if such admitted amount is found to have adverse impact on tariff in any single year, the Commission may keep such additional amount or a part of it as regulatory asset and pass such amount to be recovered through tariff in such number of years as deemed fit by the Commission. The generating company/ licensee shall submit a copy of the instrument mentioned above, due to which employee cost has increased, along with the application for determination of tariff or application for APR for any ensuing year/ base year or separate application, as the case may be, for allowing such increase in employee cost.

(xi)Notwithstanding anything to the contrary contained elsewhere in these regulations, if during tariff order of any ensuing year it is found from the application of APR of any year of a licensee that in the preceding year(s) energy allowed in the tariff order for sale to consumers and licensee(s) differs significantly from the actuals, then the projected energy for sale to consumers and licensees by that licensee for such ensuing year as shown in the tariff order of the first ensuing year of the control period may be duly adjusted on account of the energy sales figure and consequential energy purchase cost impact in ARR for the ensuing year for which tariff order is to be issued in the proportion equal to the proportion between the actual and projected energy in the last available year for which audited data is available and is also preceding to the ensuing year for which tariff order is to be issued.

(xii)Notwithstanding anything to the contrary contained elsewhere in these regulations or in any other regulations of the Commission, while applying clause (i) to (xi) invitation of suggestions and objections is required separately if the licensees or generating companies in pursuance to regulation 2.11.1 applied for approval under any separate application in between two succeeding APR application. The applicant shall, within 5 (five) working days of an intimation provided to him intimating him of admission of the application in question, publish a notice containing a gist of the application approved by the Commission in at least 4 (four) daily newspapers widely circulated in the area to which the application pertains, at least 1 (one) each of such newspapers being in Bengali and English and also in the website of the licensee inviting suggestions and objections from the members of the public and all stake holders, relating to the said application. For this purpose the licensee or generating company shall submit the gist along with the application. The stakeholders shall be given at least 10 days to submit their suggestions and objections.

(xiii)For non-compliance of any direction of the Commission in the tariff order or order of APR, the Commission may withhold or deduct any amount from the ARR of any ensuing year through the tariff order or order of the APR.

2.5.4Impact of Commencement of Generating Station within a control period of Multiyear Tariff. - (i) If the generating station/unit for whom ARR is being determined under regulation 2.5.1 (v) is owned by a licensee then as a consequence of the ARR determination for such new generating station/unit recovery of such ARR through tariff is required then the Commission may allow recovery of such ARR through an adhoc tariff to be known as Adhoc Generation Cost till next tariff is determined or amended in the second or any ensuing year. Such Adhoc Generation cost will also be subject to FPPCA as per regulation 2.8.7.

(ii)If the generating station/unit for whom ARR is being determined under regulation 2.5.1 (v) is owned by a generating company who is supplying power to a distribution licensee, the Commission may allow the generating company to charge Adhoc Generation Cost for recovery of the determined ARR under regulation 2.5.1 (v) from the recipient of electricity directly for the energy supplied till the composite tariff of the generating station takes place through determination or amendment after including the unit with the existing generating station.

(iii)During APR of the generating company or the distribution licensee the ARR of the generating station or unit as the case may be, for which tariff is determined under regulation 2.5.1 (v) as a part of the generating station and the Adhoc Generation Cost realized shall be accordingly adjusted.

2.5.5Controllable and Uncontrollable Factors - (i) Any variation arising out of all uncontrollable factors during Annual Performance Review using the operating norms, wherever applicable, for determination of allowable normative expenditure on that factor, shall be passed through the tariff in an appropriate manner by the Commission;

(ii)Any variation arising out of controllable factors during Annual Performance Review using operating norms, wherever applicable, for determinations of allowable normative expenditure on that factor, shall be on the account of licensee or generating company, as the case may be subject to other terms and conditions under these regulations;

(iii)For determination of APR or FPPCA in respect of a generating company or a licensee the expenditure on each head of account shall be considered as either controllable or uncontrollable as shown in Table 2.5.5-1

Table 2.5.5-1ARR Item characteristics of Business of Electricity of a Generating Company or a Licensee

ARR Item	"Controllable"/"Uncontrollable" Factor
Fuel Cost subject to efficiency norms as per Schedule-9A,Schedule-9D of these regulation	Uncontrollable
Fuel price	Uncontrollable
Power Purchase Costs including the fuel cost or fuel surchargeinbuilt in such power purchase cost subject to efficiency normsof distribution loss and/or transmission loss as per Schedule-9Aof these regulations.	Uncontrollable
Employee Cost subject to Man / MW ratio adopted by theCommission in Schedule-9A of these regulations for new unitscommissioned after 31.03.2004	Uncontrollable
Employee Cost subject to Man / MW ratio to the extentconsidered by the Commission as per its discretion for unitscommissioned before 31.03.2004	Uncontrollable
Interest rate & Finance Charges rate.	Uncontrollable
Addition or reduction in the Capital loan base on and afterthe 1st day of the concerned year of the APR.	Uncontrollable
Addition or reduction in the Depreciation of asset on andafter 1st day of the base year of the concerned control period	Uncontrollable
Addition or reduction in the equity base on and after the 1stday of the concerned year of the APR.	Uncontrollable
Taxes on Income, Duties, Levies, cess, etc.	Uncontrollable
Non-tariff income as permitted under these regulations	Uncontrollable
Sale volume of electricity	Uncontrollable
Foreign Exchange Rate Variation	Uncontrollable
Unscheduled Interchange	Uncontrollable
Interest on Working Capital as per regulation 5.6.5	Uncontrollable
Insurance premium	Uncontrollable
Effect of rebate / surcharge	Uncontrollable
Income from other business	Uncontrollable
Outsourcing within the period of agreement between thelicensee / generating company and the outsourcing agency(ies)limited to employee cost only*	Uncontrollable
Capital loan base according to the closing balance of the lastdate of the preceding year of the concerned year of the APR	Controllable
Depreciation of assets according to closing balance of lastdate of the year preceding the base year of the concerned controlperiod	Controllable
Repair and Maintenance item for distribution or transmissionsystem	Controllable
Administrative and General Expense for distribution ortransmission system	Controllable
Equity base subject to ceiling as specified in Regulation5.4.2 and according to the closing balance of the last date ofthe preceding year of the concerned year of the APR	Controllable
Man / MW ratio of generating station as adopted by theCommission in pursuance to Schedule-9A or Schedule-9D	Controllable
Man / CKM ratio for transmission licensee as adopted by theCommission in pursuance to Schedule-9A *	Controllable
O&M expenses for generating station	Controllable
Outsourcing within the period of agreement between thelicensee / generating company and the outsourcing agency(ies)where employee cost of such agencies has not been mentioned asvariable cost	Controllable
Any other item not included in above rows	As may be decided by the Commission from time totime
Note:- '*' — will only be applicable from third controlperiod.

2.5.6- Determination of ARR and tariff of any ensuing year under Multi-year tariff frame-work.

2.5.6.1- Procedure for tariff determination under Multiyear Tariff Framework is given in regulation 2.7. While determining ARR, operating norms as specified by the Commission in Schedule-9A or as per Schedule-9D of these regulations are set as target where the performance of the applicant is sought to be improved upon through incentives and disincentives.

2.5.6.2- The tariff and ARR of any ensuing year is to be determined or amended as the case may be as follows :

(i)On the basis of a composite application for determination of separate ARR and tariff for each of the ensuing years within a control period under multi-year tariff framework, ARR shall be determined for each ensuing year of the control period on the basis of projections made and the tariff shall be determined for the first ensuing year of the control period subject to adjustment due to APR and/or FPPCA as specified in clause (ii).

(ii)While determining the revenue recoverable through tariff in the first ensuing year of the control period, the revenue to be recovered or refunded as a result of APR of any previous year or as per clause (iv) of this regulation 2.5.6.2 may be adjusted with the ARR determined for first the ensuing year of the control period under clause (i) to the extent such is permitted by the order in pursuance to regulation 2.6.6. The tariff for the ensuing year shall be determined to recover the above adjusted ARR after taking into consideration the views of the stakeholders on the tariff structure applicable to different class of consumers as submitted against the composite tariff applications for the control period at the beginning of the control period. Such tariff determination for the first ensuing year of the control period is to be issued through tariff order for the first ensuing year mentioning the ARR determined for all the ensuing years of the control period based on the composite tariff application along with the tariff in form of schedule of prices or the charges that will be applicable for different classes of consumers and recipients of electricity in the first ensuing year of the control period after due revocation of tariff which was in vogue prior to issuance of the said tariff order of the first ensuing year under consideration.

(iii)For framing of tariff of the second ensuing year and onwards of control period for determination of the revenue recoverable through tariff, the ARR determined for the said ensuing year under clause (i) will be subject to the following adjustments :

(a)the revenue to be recoverable or refunded arising out of APR of any base year or any ensuing year if such adjustment on such account is permitted by the order in pursuance to regulation 2.6.6.

(b)Adjustment of ARR on account of clause (i) to (xi) and (xiii) of regulation 2,5.3.

(c)Adjustment as per clause (iv) of this regulation 2.5.6.2.

After above adjustment of ARR the Commission shall also make amendment of the tariff which is in vogue from the last tariff order in order to determine the ERC in correspondence to the above adjusted ARR for the concerned ensuing year after taking into consideration the views of the stakeholders on the principle of tariff structure for different class of consumers as submitted against the composite applications for multi-year tariff at the starting of the control period. During amendment of tariff, the Commission shall also consider clause (xi) of regulation 2.5.3 of these regulation for proper adjustment with the energy considered for the ensuing year under consideration in the tariff order of first ensuing year. All such adjustment relevant to the ensuing year under consideration shall be issued through the tariff order of the ensuing year mentioning the adjusted ARR and corresponding tariff along with the reasons of such adjustment for that ensuing year.

(iv)Any variation in expenditure on account of FPPCP, for a previous year or base year or an ensuing year, determined under regulation 2.8.7.1, may further be adjusted, at the discretion of the Commission, with the ARR of any ensuing year of a control period, determined under clause (i) for the purpose of determination of the total revenue recoverable through tariff in that ensuing year of the control period.

2.6Annual Performance Review. -

2.6.1- During the control period for any ensuing year or base year, a generating company or a licensee shall be subjected to an annual performance review covering annual fixed charges, fixed cost, incentives as per schedule-10 and effects of gain sharing on the parameters under schedule-9B which are not covered under the process of FPPCA. The generating company / licensee shall make an application seeking an annual performance review for fixed cost, incentives as per Schedule-10 and effects of gain sharing for the concerned period as per Schedule - 9B for an ensuing year or the base year with statutory audited data and a copy of the audited Annual Accounts for that year by November of the immediate next ensuing year of each such ensuing year or base year, as the case may be. The generating company or licensee shall provide such related information for APR as per the format for tariff application limited to the year under review for the purpose of assessing the reasons and extent of any variation in the performance from the approved projection. A comparative statement showing the different elements of fixed cost as approved in the tariff order of the concerned ensuing year as well as the actual audited figure against such element shall be given.

2.6.2- A generating company or a licensee shall mention in the application for annual performance review, the settlement of disputed amount of energy, in case there has been a dispute, and its final implications, in detail, pertaining to the previous year(s), if any, if such settlement has taken place in the ensuing year or base year under APR. For each previous year, a separate statement shall be given. In case there is no such settlement, the fact that there is an outstanding dispute, along with the quantum of energy in dispute shall also be mentioned specifically. Where a settlement has taken place that fact along with the settled quantum of energy shall be taken into account to compute the incentive afresh, provided an incentive has already been allowed on the basis of the disputed energy. If the incentive already allowed is higher than the freshly computed incentive on the basis of information in the application for APR, such excess amount of incentive allowed shall be adjusted in such manner as may be decided by the Commission.

2.6.3- A licensee may also mention in the application of APR the issues related to revision of the ARR of an ensuing year for which tariff order is going to be issued after taking the impact of the APR in the tariff of the ensuing year. The issues to be mentioned shall be those which are permitted under these regulations for revision in relation to the ensuing year for which tariff order is going to be issued in terms of regulation 2.5.3 and clause (iv) of regulation 2.5.6.2.

2.6.4- The Commission may adjust any arrear related to year before the first control period with the annual aggregate revenue requirement at the annual performance review stage.

2.6.5- During any Annual Performance Review, the Commission shall also determine under the order of the APR, the amount to be adjusted with the ARR of any ensuing year(s) for which tariff order is going to be issued. Determination of such adjustable amounts under APR order shall be based on the following factors :

(i)For Licensee

(a)the difference between x and y i.e. (x-y)

where,x = revenue recovered as per the tariff order and as per the order for any Adhoc Power Purchase Cost/ Adhoc Fuel Cost/ Adhoc Generation Cost / Adhoc Variable Cost / Monthly Fuel Cost / Monthly Variable Cost of the year for which APR is undertaken; andy = the corresponding admissible amount of fixed costs as determined for the year for which APR is undertaken and variable cost as per FPPCA order, if any for the year under APR (While determining the admissible amount of Fixed Cost the Commission shall take into account the actual expenditure/ entitlement of different elements of fixed cost on which the Commission will have prudence check to determine the admitted amount).

(b)the admissible incentives as per Schedule-10 for the year under APR after taking into consideration of the actual performance.

(c)extent of gain sharing as per Schedule-9B for the year under APR for the parameters which are not covered under Fuel and Power Purchase cost determination under FPPCA after taking into consideration of the actual performance.

(ii)For Generating Station of Generating Company but not of a licensee

(a)the difference between the capacity charge recovered under the tariff order or order of Adhoc Generation Cost of the year for which APR is undertaken and the corresponding admissible amount of fixed costs as per APR for the year after taking into account the actual expenditure/entitlement of different elements of fixed cost on which the Commission will have prudence check to determine the admitted amount.

(b)the admissible incentives as per Schedule-10 for the year under APR after taking into consideration of the actual performance.

2.6.6- The Commission may, at its sole discretion, direct to .-

(i)allow whole or part of adjustable amounts determined under APR (which may or may not include the impact of FPPCA) to be adjusted with the ARR of one or more than one ensuing year of a licensee or generating company for which tariff order is yet to be issued:

(ii)allow any specific part or whole of adjustable amounts determined under APR (which may or may not include the impact of FPPCA) of a licensee or generating company to be recovered from purchaser of electricity or consumers through a separate order instead of adjusting with the ARR of any ensuing year under any of the following conditions.

(a)If Commission feels that such adjustment through separate order is required to ensure proper cash flow to the generating company or licensee so that its dependence on Working Capital loan decreases and thereby the future increase in tariff can be reduced.

(b)If Commission feels that such adjustment through separate order is required for the licensee or generating company to enable it for investments as required to meet the need of the future demand in the state.

(c)If Commission feels that such adjustment through separate order is required to overcome any compulsive or emergency situation.

In such case the recovery shall be termed as APR Tariff Adjustment which will be adjusted with the current electricity bill in a manner as will be stipulated in above such order related to APR Tariff adjustment.

(iii)allow, whole or part of any amount that becomes payable by a licensee for purchase of power from another licensee or generating company for any year due to determination of their FPPCA and/or APR. for adjustment with the ARR of the purchaser licensee for one or more than one ensuing year for which tariff order is yet to be issued.

2.6.7- If a generating company or a licensee does not file an application for annual performance review for a base year or an ensuing year within the specified date, the Commission may undertake APR for that base year or ensuing year, as the case may be suo-moto, on the basis of available records. If the Commission, undertakes APR for any base year or ensuing year suo-moto, no subsequent claim from the generating company or licensee regarding APR for that base year or ensuing year shall be entertained in future.

2.6.8- The Commission shall review an application of annual performance review for the elements as mentioned in regulation 2.6.1 in the same manner as done during determination of ARR of the ensuing year under the original tariff application subject to such deviation of allowances as permitted under these regulations and then the deviation arising out of such review from admitted amount in tariff determination stage shall be adjusted with the ARR of ensuing year(s) as decided by the Commission.

Provided that such review can be done in separate manner for any specific head if it is found that there are errors in calculation, missing of any head or any other reasons that are to be found justifiable by the Commission.

2.6.9- The scope of the annual performance review shall be a comparison of the actual performance of the generator / licensee with the approved projection of ARR as given in the tariff order of the first ensuing year of the control period.

2.6.10- Notwithstanding anything to the contrary contained elsewhere in these regulations, the following provisions shall apply during APR of any licensee or generating company for any year :-

(i)No additional cost shall be allowed in APR on any item of controllable factor over the amount permitted in the tariff order except for allowable specific condition based variation as specified in these regulations or specifically mentioned in tariff order.

(ii)The Commission may allow certain additional expenditure through order of APR on any element of controllable item which is included in the working capital base if the rate of inflation is found to be more than 15% with respect to the price of that item at the time of determination of such element of ARR against application for determination of tariff.

(iii)For any uncontrollable factor, the Commission shall apply prudence check and admit such amount under APR according to Commission's discretion. For the uncontrollable items for which the actual expenditure is higher than the amount permitted in the tariff order, the Commission may admit such excess expenditure or a part of it in the APR according to its discretion. In case the actual expenditure is less than the amount admitted in the tariff order, then the actual expenditure will be admitted in APR.

(iv)If the actual expenditure under any sub-head of controllable item of O&M expenses or O&M expenses as a whole. as may be applicable, or on the controllable item of outsourcing is less than 90% of the admitted amount in the tariff order, then the Commission may direct in APR to use such savings below 90% of the projected level by carrying forward such amount for expenses in Repair & Maintenance or human resource skill development programme in future for any generating station or distribution system or transmission system of the licensee or generating company. However, if the concerned generating company or the licensee requests for this carry forward specifically, then the Commission shall allow such carry forward till the period for which such carry forward is requested for or till the end of the concerned control period, whichever is earlier :

Provided that such amount can be carried forward within a control period only after which the accumulated amount on this head for the control period shall be deposited in Development Fund under regulation 5.19 of these regulations or in Power Purchaser Fund under clause (ix) of regulation 5.15.2 of these regulations as per direction of the Commission. Once such excess amount is deposited to the said fund, the concerned licensee or generating company will not have any claim over such amount and it will become a part of the fund for which such fund is created.

2.6.11- Upon completion of annual performance review, the Commission shall pass an order recording :

(i)Any financial loss or gain on account of variation n generation / power purchase cost on account of uncontrollable factors and the mechanism by which the licensee shall pass through such gains or losses.

(ii)The approved aggregate gain or loss to the generator / licensee on account of other uncontrollable factors and the mechanism by which the generator / licensee shall pass through such gains or losses.

(iii)The approved aggregate gain or loss to the generator / licensee on account of controllable factors and the mechanism to share such gains or losses.

(iv)The approved modifications to the forecast for the remainder period of the control period, if any.

2.6.12- While conducting proceeding of APR, Commission shall invite suggestions and objections on the admitted application of APR

(i)for the elements of fixed cost for the year for which APR is to be undertaken;

(ii)on those items for which invitation of suggestions and objections as per clause (xii) of regulation 2.5.3 has not been obtained against any separate application as specified there; and

(iii)where tariff under regulation 2.5.1(v) of these regulations is not being determined for the concerned generating station.

The applicant shall, within 5 (five) working days of an intimation provided to him intimating him of admission of APR application in question, publish a notice containing a gist of the APR application approved by the Commission in at least 4 (four) daily newspapers widely circulated in the area to which the application pertains, at least 1 (one) each of such newspapers being in Bengali and English and also in the website of the licensee inviting suggestions and objections from the members of the public and all stake holders, relating to the APR application. For this purpose the licensee or generating company shall submit the gist along with the application. The stakeholders shall be given at least 21 days to submit their suggestions and objections.Provided that where application is required to be rejected by the Commission, then the applicant of the APR application shall be given a reasonable opportunity of being heard before rejecting his application.

2.7Procedure for determination of tariff under Multiyear Tariff framework. -

2.7.1- A composite application for determination of tariff under the Act for the entire control period shall be submitted 120 days in advance of the effective date of the start of the control period.

Provided that for the third control period, the filing may be made within one month from the date of publication of these regulations.Provided further that for the second ensuing year and onwards for a control period the date of submission of tariff application for the year shall be deemed to be the date of submission of concerned APR application with respect to that ensuing year. However in case of applicability of APR being rejected or the application of APR being not submitted in due time the Commission may duly determine the tariff of the ensuing year without considering the APR.Provided further that the Commission may at any time direct a generating company or a licensee suo-moto to submit a tariff application allowing reasonable time for submission.Provided also that the date of receipt of application for the purpose of this regulation shall be the date of receipt of a complete application in accordance with this regulation.

2.7.2- The said application for determination of tariff under the Act as referred in regulation 2.7.1 of these regulations shall be made in such form and in such manner as laid down in these regulations and accompanied by such fees as specified in Fees Regulations.

2.7.3- The applicant shall, within 5 (five) working days of an intimation provided to him intimating him of admission of tariff application in question, publish a notice containing a gist of the tariff application approved by the Commission in at least 4 (four) daily newspapers widely circulated in the area to which the application pertains, at least 1 (one) each of such newspapers being in Bengali and English and also in the website of the licensee inviting suggestions and objections from the members of the public and all stake holders, relating to the composite tariff application submitted for all the ensuing years of the control period.

Provided that where tariff application is found to be rejected, then the applicant of the tariff application shall be given a reasonable opportunity of being heard before rejecting his application.

2.7.4- On receipt of the suggestions and objections by the Commission in pursuance of regulation 2.7.3, the Commission shall follow the process as specified in regulations 2.5.1 and 2.5.3 of these regulations and bring out the tariff order as per regulation 2.9 of these regulations.

2.7.5- Additional information / particulars / documents as considered appropriate and asked for by the Commission shall also be submitted by a generating company or a licensee, tariff for which is to be determined by the Commission.

2.7.6- During tariff determination different data and quantification will be either as per audited accounts or subject to prudence check from the end of the Commission, if considered necessary. For different data and information including those pertaining to generating stations, generating companies and licensees, the Commission may, at its discretion, rely on and make use of any of the documents published or issued or supplied by Government of India, Central Electricity Authority, Government of West Bengal, different State Governments and different statutory bodies formed under the Electricity Act 2003 or any other statute of the country after giving the generating company or the licensee and the stakeholders an opportunity to express its views on the matter as to which is to be relied on through suggestions and objections as invited through website of the Commission, to be submitted within 7 working days of publication in the website. In case of any discrepancies, or contradiction or inconsistencies in data and information contained in different documents as mentioned above including the information / data submitted by the licensees or the generating companies, the Commission, at its discretion, shall accept those data that will be found by the Commission to be rational or/and reasonable.

2.7.7- Notwithstanding anything contained to the contrary elsewhere in these regulations if during determination of ARR after admitting the tariff application or APR application but prior to bringing out the tariff order if it is found that there is price increase in power purchase cost or generation cost due to direct or indirect impact of increase in price of fuel or railway freight or taxes/ duties/ royalty/ Cess on fuel then the Commission may give the effect of such cost implication after considering the views against suggestions and objections through website of the Commission, to be submitted within 7 (seven) working days of publication in the website.

2.8Determination of Tariff. -

2.8.1- Determination of Generation tariff - The tariff for supply of electricity to a distribution licensee by a generating company from conventional sources of generation within the state including hydro-generating station above 25 MW of installed capacity shall be determined in accordance with Schedule - 1 of these regulations subject to following :

2.8.1.1- Existing generating station

2.8.1.1.1- Where the Commission has, at any time prior to the notification of these regulations, approved a power purchase agreement or arrangement between a generating company and a distribution licensee or has adopted the tariff contained therein for supply of electricity from an existing generating station then the tariff for supply of electricity by the generating company to the distribution licensee shall be in accordance with such power purchase agreement or arrangement for such period as may be so approved or adopted by the Commission.

2.8.1.1.2- Where, as at the date of notification of these regulations, the power purchase agreement or arrangement between a generating company and a distribution licensee for supply of electricity from an existing generating station has not been approved by the Commission or the tariff contained therein has not been adopted by the Commission or where there is no power purchase agreement or arrangement. then the supply of electricity by such generating company to such distribution licensee after the date of notification of these regulations shall be in accordance with a power purchase agreement approved by the Commission in accordance with regulation 7.7 of these regulations.

Provided that the supply of electricity shall be allowed to continue under the present agreement or arrangement, as the case may be, until such time as the Commission approves of such power purchase agreement and shall be discontinued forthwith if the Commission rejects, for reasons recorded in writing, such power purchase agreement.

2.8.1.2- New generating stations

2.8.1.2.1- The tariff determination for the supply of electricity by a generating company to a distribution licensee from a new generating station within the state shall be in accordance with a power purchase agreement approved by the Commission and subject to prior approval of the investment amount of the generating company by the Commission, except if such power purchase agreement has been exempted from requiring such approval in accordance with regulation 7.5 of these regulations.

2.8.1.3- Own generating stations

2.8.1.3.1- Where a distribution licensee also undertakes the business of generation of electricity, the cost at which electricity is supplied by the generation business of the distribution licensee to his core-business shall be determined by the Commission in a similar manner as may be done for a generating station of a generating company.

Provided that the Commission shall follow the operational parameters and other principles as specified in regulations including Schedule - 1, Schedule -7A and Schedule - 7B of these regulations in determining the cost for such supply. Fuel and Power Purchase Cost Adjustment, Monthly Fuel Cost Adjustment (MFCA) and Monthly Variable Cost Adjustment (MVCA).

2.8.1.3.2- The distribution licensee shall maintain separate records for the generation business, business for sale of power to each person other than its consumers of its area of supply, if any, and shall maintain an allocation statement in accordance with the forms specified in these regulations.

2.8.1.3.3-The distribution licensee shall submit the application for determination of tariff for sale of electricity and for wheeling in distribution system simultaneously along with the information required under Schedule -1 of these regulations relating to the generation business. so as to enable the Commission to determine the supply tariff in accordance with the terms and conditions contained in the said Schedule.

2.8.1.4- Investment Approval

2.8.1.4.1- The approval of the Commission for investment for new generating station, commissioned after 31.12.2007 is mandatory, if electricity is received directly by any distribution licensee under the purview of the Commission from such generating station situated within the state or such electricity is purchased under section 64(5) of the Act. Such approval shall be taken before any investment is made in order to minimize investment risk. Any subsequent revision of such investment must also be required to be got approved by the Commission before filing application for determination of tariff. On synchronization or Commercial Operation, as the case may be, a new unit which is an extension of any existing generating station shall also be considered as a new generating station or part of a generating station, as the case may be, under these regulations.

2.8.1.4.2- Such approval shall be sought in two stages. In the first stage, before procurement or placement of order for such project, the concerned generating company or the licensee shall seek in principle' clearance from the Commission through an application along with the following documents.-

(i)Detailed Project Report (DPR) of the project with :-

a. estimated project cost including all relevant details such as estimated cost of different packages/systems, equipments and number of such equipments in each package/system, cost of infrastructure including that of railways and others, civil works, estimated interest during project construction(IDC), land cost, projected fuel quality of fuel inclusive of average grade of coal and UHV of fuel, documents of fuel linkage, the charges for installation, commissioning, testing, erection / construction, consultancy, freight, insurance, transportation, handling, taxes and duties, mandatory initial spares, overheads, contingencies (not above 3% of total costs excluding land cost) etc.;b. targeted values of such operating parameters which have been mentioned in Schedule-9A or as per Schedule 9D and to be asked under performance guarantee from the bidders after considering the conditions of design value of those operating parameters under different operating conditions under normative PLF for a new generating station;c. financial viability analysis of such project alongwith estimated cost/ tariff of generation for the first five years after commercial operation as per these regulations;

(ii)comfort letter or Power Purchase Agreement (PPA) from the concerned person, in case of supply of power from that generating station to a person other than the owner of the generating station;

(iii)all statutory clearances except those which cannot be submitted for sufficient reasons. Such exceptions, however, shall not apply for the terms of reference for the project issued by the Ministry of Environment and Forests (MOEF) of Government of India, chimney height clearance, in principle' clearance of connectivity for power evacuation from appropriate authority, and concurrence of Authority where applicable;

(iv)clearances from State Planning Board and Finance Department of the State Government, in case equity is provided by the Government of West Bengal;

(v)technical specifications for the bid;

(vi)a gist of the application;

On receiving an application along with the required documents, the Commission shall intimate the applicant, within a fortnight from the date of submission of the application, whether the application is admitted or not admitted. In case of non admission of such investment proposal, the Commission shall intimate the applicant, in writing, the reasons for not admitting such application. If the application is admitted, the applicant shall publish the gist of the application, as may be approved by the Commission, in such manner, as may be directed by the Commission, inviting objections, suggestions and comments from the public. After considering all objections, suggestions and comments from the public, the Commission shall give its decision about 'in principle' clearance to the investment proposal for the proposed generating station preferably within 90 days from the date of admitting the application along with specific directions to the applicant, if any, that are to be followed for getting final approval of the investment proposal in the second stage.

2.8.1.4.3- In the second stage, the final approval of investment proposal shall be sought for by the concerned owner of the generating station through an application prior to placement of order(s) after conducting due competitive bidding mentioning the project cost on the basis of the agreed price the supplier(s) and contractor(s) and mentioning the final details of all the parameter as submitted in the first stage for 'in principle' clearance of investment as mentioned in regulation 2.8.1.4.2 of these regulations. Submission of all the statutory clearances and other clearances as per clause (iii) and (iv) of regulation 2.8.1.4.2 is mandatory for obtaining final approval for investment in the second stage. The bidding documents and qualifying criteria of such competitive bidding as mentioned above for each package shall be such that at least two vendors / suppliers/ contractors qualify up to the final stage of bidding. Results of this competitive bidding will not be taken cognizance of by the Commission as one of the grounds for project cost determination unless at least two bidders are in competition up to the final stage.

Provided that in case of two part bidding consisting of evaluation of techno-commercial part as pre-condition prior to opening and evaluation of price bid, if there are only two bidders and one does not submit any supplementary price bid besides the originally submitted price bid as impact of withdrawal of deviation sought at techno-commercial stage or any modification at the evaluation of techno-commercial stage for any valid reasons, the condition of two bidders to be in competition shall be considered to be satisfied. This stipulation is project specific.Provided also that in case of non-fulfilment of participation of two bidders, if the owner of the generation project can establish through supporting documents that inspite of open tendering with sufficient bidding time at least two bidders has not submitted the bid, then the Commission can relax such condition as it deemed fit.

2.8.1.4.4- In the second stage, application for final approval of investment for a new generating station of the concerned generating company or the licensee shall also provide following materials with supporting papers :-

(i)the documents of clearance of fuel linkage with detail thereof or allotment of captive coal mine along with the fuel quality including of grade and UHV of such fuel;

(ii)the performance guarantee on value of different operating parameters as mentioned in Schedule-9A along with margin of deviation of such values under different operating conditions, based on fuel quality according to documents mentioned in clause (i). For a thermal generating station such guaranteed value for different operating parameters also shall include the net base turbine cycle heat rate measurable at the generator terminal after taking the impact of the generator efficiency and at preferable loading of 60%. 70%. 80%, 85%. and 90% with 3% make up on the heat value of fuel and fuel quality, The corresponding boiler efficiency is also to be submitted. For hydro generating station the design performance parameters shall also include auxiliary energy consumption rate and cycle efficiency of pumped storage generating stations. All such information on guaranteed operational parameters shall also include the impact of aging on them during the life period of the plant;

(iii)the expected deviation of guaranteed operating parameters due to variation in fuel quality along with supporting documents and calculations are to be submitted.

2.8.1.4.5- There shall be no 'in principle' clearance or final approval, if any proposed guaranteed operating parameter of the generating station as mentioned in regulation 2.8.1.4.4 of these regulations is inferior to that of any of the equivalent existing coal fired thermal generating stations in the country unless the Commission is duly convinced through proper justifications.

2.8.1.4.6- The second stage application to the Commission for final approval of investment proposal of any generating company must be submitted along with the required power purchase agreement(s) with the licensee(s) under the purview of the Commission. Without such power purchase agreement(s) the application for final approval of investment shall not be admitted by the Commission.

2.8.1.4.7- On receipt of such second stage application along with the required documents the Commission shall intimate the applicant within a fortnight from the date of submission of the application whether the application is admitted or not admitted. In case of non admission of such investment proposal, the Commission shall intimate the applicant, in writing, the reasons for not admitting such application along with necessary directions. On admitting the application, the Commission shall intimate its decision about final approval to the investment proposal, along with 'in principle' clearance to the proposed design value and guaranteed performance value of the operational parameters for the proposed generating station preferably within 30 days from the date of admitting the application along with specific directions to the applicant, if any.

2.8.1.4.8- On completion of the contract agreement with the bidders, the licensee or the generating company shall submit the certified copies of the contract agreement(s) related to the project of the generating station for which investment approval has been sought. Along with this contract agreement separate related documents, if any, that stipulate the performance guarantee on the operating parameters mentioned under Schedule-9A and as detailed under regulation 2.81 .4,4 shall also be submitted. Alongwith such a submission a certified copy of approval of the Board of Directors (Board) of the generating company or licensee and the agenda papers related to such Board's approval shall also be submitted. All such documents shall be submitted within fifteen days from the date of contract agreement or the approval of the Board whichever is earlier.

2.8.1.4.9- Before one year of synchronisation of the said generating station the generating company or the licensee, as the case may be, shall submit all the important applicable design performance parameters such as for thermal generating station auxiliary energy consumption rate, gross station turbine heat rate at generator terminal, turbine heat rate of each unit at generator terminal, boiler efficiency of each unit, generator efficiency of each unit, along with corresponding operational parameters of design coal grade, mainsteam pressure, mainsteam temperature. Such design parameters to be provided by the generating company or the licensee shall be at operating condition of 60% loading. 80% and 100% MCR of the generating stations at 0% make up of the design load and design cooling water temperature/ back pressure. In addition to this, the range of deviation of guaranteed operating parameters due to variation in fuel quality along with supporting documents and calculations are also to be submitted. For hydro generating station the design performance parameters will be for auxiliary consumption ratio and cycle efficiency of pumped storage generating stations. The frequency of planned maintenance of generating station and period required for such planned maintenance as recommended by the manufacturer shall also be submitted. The recommended life periods of major equipments of the generating stations are also to be provided. The generating company or the licensee shall also provide the data/ information on technical standards as specified by Authority. On the basis of such information/data, the Commission shall decide the norms of operating parameters of that generating stations for determination of tariff under these regulations for its first year of operation. Late submission of such data will lead to provisional tariff or generation cost determination on the basis of data submitted at second stage of investment approval with some reduction as a conservative measure in favour of the consumers or purchasers of electricity till all the information are submitted as sought for in this instant regulation. Such withheld amount will not be entitled for any interest in future.

2.8.1.4.10- The performance guarantee test is to be completed within four months from the date of synchronisation. On completion of the performance guarantee test for the generating station, the detailed results alongwith all related documents of such test shall be submitted with the application for next tariff determination or next APR, whichever is earlier, succeeding to completion of such test. Such test result shall clearly mention all the operating parameters that are under performance guarantee along with the prevailing operating conditions of such operating parameters. For non-submission of performance test guarantee result, 15% of the permitted return on the normative maximum equity relevant to that generating station will be kept withheld in the tariff from the year following the abovesaid four months till such report is submitted.

2.8.1.4.11- The above two stage investment approval shall apply to those generating stations / units for which tenders for supply of plants and equipments have been or are to be invited after 15.10.2007.

2.8.1.4.12- Where no prior investment approval has been obtained in terms of these regulations, the applicant shall also submit all the information and documents as sought for under regulation 2.8.1.4 for project cost approval with the application for tariff determination for a new generating station and the Commission shall, on the basis of submitted information approve the project cost to such extent as is found to be reasonable on the basis of information based on regulation 2.7.6 and details worked out by the Commission in respect of equivalent power stations of same vintage in the country.

2.8.1.4.13- Within three years of COD of the last unit of a generating station the generating company or the licensee shall submit a detailed report showing whether the provisions of different penalty(ies) or incentive(s) of contractual conditions are applied or not. The fact of waiver or non-application of penalty or incentive shall be specifically mentioned. Such analysis shall be given against each such provision specifically as stipulated in the contract. Only on submission of such reports, the final project cost of the generating station will be determined. Till submission of such report, the submitted project cost as mentioned in any tariff application will be reduced by at least 5% as per the discretion of the Commission. On submission of such report, the Commission will finally decide the final project cost to be approved for capitalization for the purpose of the tariff determination and such fresh capitalization on the basis of approved project cost will be considered from the date of approval of the project cost.

2.8.1.4.14- The norms of construction period of generating stations are included in Schedule-9C in order to control the capitalization of interest during construction as well as to provide incentive (s).

2.8.1.4.15- Any investment approval under these regulations shall be deemed to include the conditions that ex-bus energy of each unit of the concerned generating station for which such approval is accorded shall be metered for recording both the amount of ex-bus energy and generated energy from the very first day of the synchronization along with real time on-line display and monitoring of such metered information at SLDC.

2.8.2Determination of tariff for transmission, wheeling and retail sale of electricity -

2.8.2.1- The Commission shall determine the tariff for transmission, wheeling and sale of electricity based on an application made by the licensee in accordance with the procedure contained in these regulations.

2.8.2.2- The Commission shall determine the tariff for-

(a)Transmission of electricity, in accordance with the terms and conditions contained in Schedule - 3 of these regulations;

(b)Wheeling of electricity, in accordance with the terms and conditions contained in Schedule - 4 of these regulations;

(c)Retail sale of electricity in accordance with the terms and conditions contained in Schedule - 5 of these regulations.

2.8.2.3- The approval of the Commission for investment in new transmission project commissioned after 31.12.2007 is mandatory. Similarly, the approval of the Commission for distribution project above rupees one hundred and twenty five crore and commissioned after the publication of these regulations is mandatory. Such approval in both cases shall be taken before investment is made in order to minimize their investment risk. Any subsequent revision of such investment must also be required to be got approved by the Commission before filing application for determination of tariff. For the investment approval licensee shall submit an application along with a gist.

Each investment proposal of any distribution licensee shall also take into consideration the duty to be discharged for supplying electricity to any person who has submitted application requesting for such supply in accordance with sub-section (1) of section 43 of the Act. This aspect is to be duly reflected in the investment proposal and in case of any absence of such aspect due justification is to be provided.On receiving an application along with the required documents, the Commission shall intimate the applicant, within a fortnight from the date of submission of the application, whether the application is admitted or not admitted. In case of non admission of such investment proposal, the Commission shall intimate the applicant, in writing, the reasons for not admitting such application. If the application is admitted, the applicant shall publish the gist of the application, as may be approved by the Commission, in such manner, as may be directed by the Commission, inviting objections, suggestions and comments from the public. After considering all objections, suggestions and comments from the public, the Commission shall give its decision regarding investment approval.

2.8.2.4- Any distribution licensees having its electricity business in the State only shall, before committing to bear any type of fixed cost for creation of any new asset relating to any inter-state or intra-state transmission system of any other person, obtain approval of the Commission by giving full techno-economic¬commercial justification of such commitment to the satisfaction of the Commission provided cost of creation of such new assets exceeds Rs. 125 crore.

2.8.2.5- Notwithstanding anything to the contrary contained anywhere else in these regulations. if a distribution licensee proposes purchase / supply of power from a new generating station or any other source, then the impact of such power purchase, as the case may be, on the aggregate revenue requirement of the distribution licensee shall be limited to the extent of such supply I purchase required to meet the demand in the area of supply of the distribution licensee concerned and without taking into consideration of the extent of gain sharing under regulation 5.15.2 at tariff determination stage of the concerned generating station for its first year of operation. However, during APR of the concerned year the extent of gain sharing under regulation 5.15.2 for the said period shall be considered for determination of recoverable revenue through tariff and the tariff shall be determined accordingly.

2.8.2.6- Notwithstanding anything to the contrary contained anywhere in any other regulation of the Commission, the Commission will determine the SLDC charge and Reactive energy charge under the tariff order of the Transmission Licensee which is functioning as STU or through separate order and such charges will be recoverable in a method as may be stipulated in such order or as may be specified in any other regulation of the Commission.

2.8.3Project under Construction. -

2.8.3.1- Notwithstanding anything contained in the regulation 2.8.1.4 and 2.8.2.3, for the projects for which the investment has already been made before 09.02.2007 but not yet commissioned fully. the licensee or generating company concerned shall submit their investment proposal as per latest revised project cost, if any for approval of the Commission. Any subsequent revision of such investment must also be required to be got approved by the Commission before filing application for determination of tariff.

2.8.4Approval of Capital Expenditure of Commissioned Projects, i.e., Utilities Under Commercial Operation. -

2.8.4.1- A licensee or a generating company may undertake capital expenditure in small schemes, which do not fall within the capital expenditure programme approved by the Commission in pursuance of regulations 2.8.1.4, 2.8.2.3 and 2.8.3, provided the aggregate expenditure on such schemes does not exceed Rs. 200 crore during the year concerned. Up to Rs. 200 crore Capital Expenditure for such schemes in a year no approval is required to be taken. However, if such expenditure crosses Rs. 200 crore for such small schemes then prior approval is required to be taken for such Capital Expenditure. Under this provision no proposal for a new generating station will be allowed.

Provided that in case of emergency or emergent circumstances due to its impact on the safety of the assets, life, system or smooth supply or such similar reasons. the licensee or the generating company may incur the necessary expenditure without taking the prior approval of the Commission, but shall intimate the same to the Commission as soon as possible but within 120 days at the maximum from the date of incurring such expenditure along with the circumstances under which it was not possible to take prior approval.Provided further that in case the Commission neither refuses nor gives its consent for incurring of such expenditure within 30 (thirty) days from its filing with all the relevant documents, the licensee / generating company may presume that the Commission has no objection to inclusion of the same for fixing the tariff.Provided also that notwithstanding anything contained above, the above procedure shall not be applicable to the extent the capital expenditure programme, as included in the tariff application, has been approved by the Commission.

2.8.4.2- Investment approval is also mandatory for Renovation and Modernization Programme or Life Extension Programme or Replacement Programme inclusive of retrofitting nature of any generating station. Such approval shall be taken before any investment is made in order to minimize investment risk. Any subsequent revision of such investment must also be required to be got approved by the Commission before filing application for determination of tariff.

2.8.4.2.1- Such approval under regulation 2.8.4.2 shall be sought in two stages. In the first stage, before procurement or placement of order for such project, the concerned generating company or the licensee shall seek in principle' clearance from the Commission through an application alongwith the Detailed Project Report specifically mentioning the following items :-

(a)estimated project cost;

(b)detailed quantification of targets to be achieved through such programme with techno-economic analysis as well as cost benefit analysis of the project;

(c)targeted improvement in the project, if any, with respect to performance norms of the operational parameters as specified in Schedule-9A;

(d)estimated time of completion of such project;

(e)gist of the application;

On receiving an application along with the required documents, the Commission shall intimate the applicant, within a fortnight from the date of submission of the application, whether the application is admitted or not admitted. In case of non admission of such investment proposal, the Commission shall intimate the applicant, in writing, the reasons for not admitting such application. If the application is admitted, the applicant shall publish the gist of the application, as may be approved by the Commission, in such manner, as may be directed by the Commission, inviting suggestions and objections from the public. After considering all suggestions and objections from the public the Commission shall give its decision about provisional 'in principle' clearance to the investment proposal preferably within 60 days from the date of admitting the application along with specific directions to the applicant, if any, that are to be followed for getting final approval of the investment proposal in the second stage.

2.8.4.2.2- In the second stage, the final approval of investment proposal under regulation 2.8.4.2 shall be sought for by the concerned owner of the generating station through an application prior to placement of order(s) after conducting due competitive bidding mentioning the project cost on the basis of the agreed price with the supplier(s) and contractor(s) and mentioning the final details of all the parameter as submitted in the first stage for 'in principle' clearance of investment as mentioned in regulation 2.8.4.2.1 of these regulations. The bidding documents and qualifying criteria of such competitive bidding as mentioned above for each package shall be such that at least two vendors / suppliers/ contractors qualify up to the final stage of bidding. Results of this competitive bidding will not be taken cognizance of by the Commission as one of the grounds for project cost determination unless at least two bidders are in competition up to the final stage;

2.8.4.2.3- On receipt of such second stage application along with the required documents the Commission shall intimate the applicant within a fortnight from the date of submission of the application whether the application is admitted or not admitted. In case of non admission of such investment proposal, the Commission shall intimate the applicant, in writing, the reasons for not admitting such application along with necessary directions. On admitting the application the Commission shall intimate its decision about final approval to the investment proposal along with in principle' clearance to the proposed design value and guaranteed performance value of the operational parameters for proposed generating station preferably within 30 days from the date of admitting the application along with specific directions to the applicant, if any.

Provided also that in case of non-fulfilment of participation of two bidders, if the owner of the generation project can establish through supporting documents that inspite of open tendering with sufficient bidding time at least two bidders has not submitted the bid, then the Commission can relax such condition as it deemed fit.

2.8.4.2.4- On completion of the contract agreement with the bidders, the licensee or the generating company shall submit the certified copies of the contract agreement(s) related to the project for the generating station for which investment approval has been sought. Along with this contract agreement separate related documents, if any, that stipulate the performance guarantee on the operating parameters mentioned under Schedule-9A or as per Schedule-9D and as detailed under regulation 2.8.4.2.2 shall also be submitted. Alongwith such submission the certified copy of the approval of the Board of Directors (Board) of the generating company or the licensee and the agenda papers related to such Board's approval shall also to be submitted. All such documents shall be submitted within fifteen days from the date of contract agreement or the approval of the Board whichever is earlier. On the basis of such documents the Commission shall issue the norms of operating parameter of that generating stations after taking into consideration the views of the stakeholders against invitation of suggestions and objections in regulation 2.8.4.2.1 for determination of tariff under these regulations for first year of operation.

2.8.5Approval of Original Project Cost. -

2.8.5.1- After closing of all contracts the original project cost is to be got approved under regulation 2.8.1.4 or 2.8.2.3 or 2.8.3 or 2.8.4 showing the details of deviations from its investment plan along with reasons of such deviations. The submitted details shall include the audited figures of expenditure on the following heads in the format given in Annexure - 8.

(a)Package-wise equipment supply cost of relevant items under each package mentioning specific order/ LOA/ Contract Agreement against such package.

(b)Above package-wise specific testing, erection and commissioning charges for each package along with details to the extent possible.

(c)Above package-wise specific civil construction cost for each package along with material cost separately for each type of construction material along with quantum.

(d)Consultancy charges against each of the LOA / Order / Contract Agreement mentioned at (a).

(e)Cost of any type of management services if outsourced against each of the LOA / Order I Contract Agreement mentioned at (a) or the Project as a whole.

(f)Specific taxes and duties for each order/ LOA/ Contract Agreement mentioned at (a).

(g)Project specific insurance cost or specific insurance cost for each order! LOA/ Contract Agreement mentioned at (a).

(h)Specific transportation charges for each order/ LOA/ Contract Agreement mentioned at (a).

2.8.5.2- During the project construction period, the incurred capital expenditure and other expenditure under project cost shall also be audited annually according to each package separately with specific reconciliation of supplied items against the said expenditure along with the status of erection and commissioning. Such audit report / certificate is to be submitted to the Commission within the 30th September of the succeeding year, along with a report of actual progress against the scheduled programme in terms of package-wise material supply position, actual status and programme of construction / erection, testing and commissioning programme and status of payment against the schedule of payment along with related conditionality of the schedule of payment for each package.

2.8.5.3- For each package under a project, the contract is to be closed within two years of COD of the last package. For new generation project or distribution project or transmission project or R&M project of generating plant the owner of such project shall disclose the operational status of each equipment of such packages as well as deviation, if any, in specification of such installed equipment from that of the contract agreement/ order, through a third party certification by a reputed engineering firm not involved in the execution of the package from any side. Such report shall also show whether the provision of different penalty(ies) or incentive (s) of contractual conditions were duly applied or not. The fact of waiver or non-application of penalty or incentive shall be specifically mentioned along with the grounds cited by the concerned licensee or generating company for such waiver or non-application of penalties or disincentives. Such analysis shall be given against each such provisions of penalty(ies) or incentive(s) specifically stipulated in the contract. Only on submission of such reports the final project cost of such generation project or distribution project or transmission project will be determined.

2.8.5.4- For new commissioned project after coming into force of these regulations, generating company or licensee shall also submit the applicable Forms P(A) to P(J) of Annexure - 9 for project cost determination.

2.8.6Operating Norms and Standard of Operating Performance. -

2.8.6.1- The operating norms of different operational parameters pertaining to any year on the basis of which the annual revenue requirement of any generating station or licensee will be determined have been laid down in Schedule-9A or as per Schedule-9D of these regulations.

2.8.6.2- If the actual performance of a generating station of a generating company or a licensee in a particular year in respect of any parameter, the operating norm of which has been laid down in Schedule-9A or as per Schedule-9D of these regulations, is better than the norm applicable to that parameter in that year, then such gain shall be shared in the manner and with the persons as specified in Schedule-9B of these regulations.

Provided that such sharing of gain as per Schedule - 9B shall be applicable for a generating station of a generating company or licensee only for that part of the installed capacity which is exclusively dedicated for supply of electricity to any consumer or licensee under the purview of the Commission.

2.8.6.3- If the actual performance of the licensee other than for its embedded generating station(s) in a particular year in respect of any parameter, the operating norm of which has been laid down in Schedule - 9A or as per Schedule - 9D of these regulations, is better than the norm applicable to that parameter in that year, then the gain, if any, originating from such better performance shall be shared in the manner and with the persons as specified in Schedule - 9B of these regulations. Such gain sharing shall be applicable for the portion of the energy which is allowed to be transacted by the licensee in terms of the relevant tariff order of the Commission.

2.8.6.4- In addition to the gains originating from better performance which are to be shared as per regulations 2.8.6.2 and 2.8.6.3, the licensee or the generating company shall also be entitled to incentives for improved performance, if the generating company or the licensee attains or exceeds various standards of operating performance related to different parameters for a year according to principles as specified in Schedule - 10 of these regulations. Such incentives for the parameters mentioned in Schedule - 10 shall be independently measured for each parameter separately and will not be subject to adjustment or disallowance on any score. However, this incentive will only be allowed on claim with supporting information from the licensee or generating company concerned. However ABT compliant generating station for generating company will not be entitled to incentive as per paragraph 1 of Schedule - 10.

Provided that such incentive as per Schedule -10 shall only be applicable for a generating station of a generating company or licensee for that part of installed capacity which is exclusively dedicated through PPA for supply of electricity to any licensee under the purview of the Commission.

2.8.6.5- The sharing of gain and/or entitlement of incentive on each operating parameter as specified in regulations 2.8.6.2 to 2.8.6.4 by and/or to any generating company or licensee against each generating station shall be assessed independently for each operating parameter separately.

2.8.6.6- The sharing of gains and incentives as specified in regulations 2.8.6.2 to 2.8.6.4 shall be computed annually on the basis of audited accounts of the licensee or generating company submitted with the application for Annual Performance Review and/or FPPCA of the year for which incentives and gain sharing are sought for and after Annual Performance Review that amount may be adjusted directly with the ARR of the ensuing year for which tariff is going to be determined or indirectly through APR whose impact is to be adjusted with the said ARR.

2.8.6.7- For any generating company or licensee, availability of installed capacity for any plant may be adjusted downward against enhanced performance of any other plant of the same generating company or the same licensee which may register capacity availability above the target availability of installed capacity, as the case may be, for the purpose of recovery of capacity charge. The plant, the enhanced performance of which will meet the shortfall in availability of any other plant of the same generating company or the same licensee. shall be paid energy charge at the rate applicable to it as per relevant tariff order. If the enhanced amount of availability factor of the plant (Plant-1) which will meet the shortfall in availability of any other plant (Plant-2) be EAV1/0 then the corresponding amount of availability factor EAV2% considered to compensate the shortfall of the Plant-2 will be as follows :

EAV2% =	EAV1 of the concerned period x InstalledCapacity of Plant-1
Installed Capacity of Plant-2

Provided that for any generating company or licensee where fixed charge recovery is based on normative PLF, PLF for any plant may be adjusted downward against enhanced performance of any other plant of the same generating company or the same licensee which may register generation above the target PLF, as the case may be, for the purpose of recovery of capacity charge. The plant, the enhanced performance of which will meet the shortfall of PLF of any other plant of the same generating company or the same licensee, shall be paid energy charge at the rate applicable to it as per relevant tariff order. If the enhanced amount of PLF of the plant (Plant-1) which will meet the short fall in generation of any other plant (Plant-2) be PLF 1% then the corresponding amount of generation (COMP_GEN) in Million Unit considered to compensate the shortfall of the Plant-2 will be as follows :COMP_GEN = PLF1 of the concerned period x Installed Capacity of Plant-1 in MW x Hours of the concerned period x 0.001Provided also that such adjustment shall be done on quarterly basis where for each year the first quarter is from April to June, the second quarter is from July to September, the third quarter is from October to December, the fourth quarter is from January to March. Performance of one quarter of any generating station cannot be used to compensate the performance of any generating stations in any other quarter.

2.8.6.8- All the norms as per Schedule - 9A and gain sharing as per Schedule - 9B are applicable from 01.04.2008 and all new units for which norms are not provided in Schedule-9A shall be subjected to norms after setting of such norms as has been explained in Schedule-9D.

2.8.6.9- In case of any Renovation and Modernisation or Life Extension Programme of any existing generating station, the said norms under Schedule-9A will be modified on the basis of submitted document at the stage of investment approval under regulation 2.8.4 of these regulations. Similarly in case of closing down of any unit of any generating station permanently the norms of the stations will be modified and for this purpose it is the responsibility of the generating station to intimate the Commission of such closing down at least three months prior to such closing down.

2.8.6.10- For the generating stations of any licensee, incentives as per Schedule-10 are applicable subject to the capacity charge recovery and fulfilling of conditions as specified under regulation 6.4.2 of these regulations.

2.8.6.11- For a non-ABT compliant generating station of a licensee the incentives as per Schedule - 10 are applicable. For such plant actual energy generated in excess of ex-bus energy corresponding to target Plant Load Factor after excluding the power sold to person other than distribution licensee under purview of WBERC or own consumption, which is to be computed at ex-bus after considering auxiliary consumption and T&D loss, if any, on such sold energy on the basis of actual or normative whichever is higher shall be entitled for incentive under as per paragraph - 1 of Schedule - 10.

2.8.6.12- The period(s) of shut down arising out of the need for performance guarantee test of any new generating unit shall be excluded from determination of the above mentioned achievement of operating norms under Schedule - 9A or Schedule - 9D of these regulations subject to the condition that such shut-down period(s) shall be considered to be one month or the actual, whichever is less, for consideration of achievement of norms of Schedule - 9A or Schedule - 9D and if such shut-down is undertaken with prior notice to SLDC. However, for incentive or gain sharing computation under Schedule - 10 and Schedule - 9B respectively of these regulations such period will be included for determination of different target performance on the basis of which incentive will be provided.

2.8.7Fuel and Power Purchase Cost Adjustment. -

2.8.7.1- For 2009-10 and for each subsequent ensuing year or base year the fuel and power purchase cost admissible under the process of FPPCA in respect of a generating company or a licensee shall be worked out as per the relevant fuel surcharge formula termed as FPPCA in Schedule - 7A in pursuance to Section 62(4) of the Act, as amended, and that shall also Include the impact of gain-sharing as per schedule - 9B related to the parameters of fuel cost, power purchase cost and transmission and distribution loss. Any variation in expenditure on account of FPPCA arising out of variation of price, purchase volume, mix, heat value and source of purchase of fuel or power purchase etc. as approved in any tariff order or an FPPCA against old power purchase liabilities, arising out of earlier period's purchase of power shall be either adjusted with the ARR of the next earliest available ensuing year during the stage of tariff determination for recovery / refund through tariff or allowed to be recovered from or refunded to the consumers immediately through a separate order of the Commission, as the Commission may decide.

Provided that in case of DVC the fuel surcharge formula in paragraph of Schedule - 7A shall be used for import on power purchase cost only and not the fuel cost of own generation as the variation of Fuel Cost is adjusted separately as per CERC Regulations.

2.8.7.2- A generating company or a licensee shall submit its FPPCA claim for any year within forty five days of the completion of its accounts for that year with necessary statutory audited data and a copy of the statutorily audited Annual Accounts for that year. If a generating company or a licensee does not submit its FPPCA claim for any year within the specified date, the Commission may suo-moto undertake FPPCA for the generating company or licensee for that year on the basis of available records. If the Commission, undertakes FPPCA for any base year or ensuing year suo-moto, no subsequent claim from the generating company or licensee regarding FPPCA for that base year or ensuing year shall be entertained in future.

2.8.7.3- The Commission may, at any time at its discretion, also allow an adhoc fuel cost or adhoc power purchase cost or adhoc variable cost provisionally in any year to a generating company or a licensee suo-moto or on the basis of an application filed by the generating company or licensee for that year arising out of the reasons as mentioned in regulation 5.8.8 subject to adjustment of the same in the FPPCA.

The Commission shall allow in terms of these regulations monthly adjustment of fuel cost or power purchase cost or variable cost which are to be termed as Monthly Fuel Cost Adjustment (MFCA) or Monthly Variable Cost Adjustment (MVCA) to a generating company or to the distribution licensee on the basis of fuel surcharge formula in Schedule - 7B based on normative operational parameters as approved by the Commission by applying regulation 5.8.9 of these regulations subject to reconciliation of the same along with the FPPCA.While allowing such adhoc fuel cost and/or MFCA for a generating station under regulations 5.8.8 and/or 5.8.9 the Commission may also allow to charge the adhoc power purchase cost or adhoc fuel cost or adhoc variable cost or MVCA, as the case may be, on the consumer of a distribution licensee who has been affected as a consequential impact of adhoc fuel cost of the generating station.While determining the adhoc power purchase cost or adhoc fuel cost or adhoc variable cost or MFCA or MVCA under regulations 5.8.8 or 5.8.9 such cost shall also take into account the impact of fuel component cost embedded in the adhoc generation cost, if any, of a generating station.As a consequential impact of giving any Adhoc Generation Cost to the generating station as specified in regulation 2.5.4, the Commission may suo-moto or on application issue separate order of adhoc power purchase cost or adhoc fuel cost or adhoc generation cost or adhoc variable cost under this regulation and/ or regulation 5.8.8 of these regulations for retail tariff of the consumers of the relevant licensee(s) who will be effected by such tariff determination of such generating station and in doing so will not require any application from the licensee in case of suo-moto proceedings by the Commission for implementation of such adhoc power purchase cost or adhoc fuel cost or adhoc generation cost or adhoc variable cost in retail sale. In issuing such order on adhoc power purchase cost or adhoc fuel cost or adhoc generation cost or adhoc variable cost, invitations of suggestions and objections is required only if there is any deviation in the methodology as specified in regulation 5.8.8 of these regulations. In case of invitation of such suggestions and objections, a notice period of seven days is to be provided.Provided that for DVC only adhoc power purchase cost is allowable as fuel cost component of its own generation is under the purview of CERC.Provided also that for DVC only MVCA is applicable where only the power purchase cost and not the fuel cost of own generation will be considered as fuel cost of own generation is under the purview of the CERC.

2.8.7.4- The FPPCA or an adhoc fuel cost or adhoc power purchase cost or adhoc variable cost shall be subject to efficiency norms for the year concerned.

2.8.7.5- While determining FPPCA or adhoc power purchase cost or adhoc fuel cost or ad hoc variable cost under regulation 5.8.8 invitation of suggestions and objections are required only when there is any deviation from the formula laid down in Schedule - 7A.

2.8.7.6- If FPPCA of any earlier year is included in the ARR of any generating company or licensee for a base year or an ensuing year and there is excess or less recovery of that fuel and/or power purchase cost during that base year or ensuing year, such excess or less recovery of cost will be adjusted with the amount arrived at in FPPCA of any years, as may be decided by the Commission.

2.8.7.7- If any recoverable amount, determined by the Commission in APR or FPPCA for a base year or any ensuing year of a generating company or licensee, is adjusted with the ARR of that generating company or licensee for an ensuing year and there is excess or less recovery than the amount so adjusted for any reason whatsoever, such excess or less recovery shall be adjusted in APR of that generating company or licensee for any subsequent ensuing year.

2.8.8Tariff Through Competitive Bidding Route. -

2.8.8.1- Notwithstanding anything to the contrary contained anywhere else in these regulations, the commission shall adopt the tariff for supply of electricity by a generating company to a distribution licensee if such tariff has been determined through transparent process of bidding in accordance with the guidelines issued by the Central Government :

Provided that the owner of the generating station(s) shall apply to the Commission for adoption of such tariff showing the capacity charge and energy charge separately for different years along with all documents starting from tender/bid inviting process to final evaluation stage :Provided further that the bidding documents and qualifying criteria of ouch competitive bidding as mentioned above shall be such that at least two bidders qualify up to the final stage of bidding failing which the results of this competitive bidding will not be taken cognizance of by the Commission :Provided further that the applicant shall provide such information as the Commission may require to satisfy itself that the guidelines issued by the Central Government have been duly followed.Provided also that any special purpose vehicle formed for conducting such competitive bidding as per guidelines of the Central Government shall not have any equity of the participating bidders.

2.8.8.2- The generating station whose tariff has been adopted as a result of competitive bidding in pursuance to regulation 2.8.8.1 of these regulations, shall not be subjected to any APR or any gain sharing as per Schedule 9B or incentive as per Schedule 10 of these regulations.

2.8.9General. -

2.8.9.1- The applicant shall provide, as part of his application to the Commission, in such form as may be stipulated by the Commission from time to time, full details of his calculation of the ARR and ERC from tariff and charges pursuant to the terms of his licence, and thereafter he shall furnish such further information or particulars or documents as me Commission or the secretary or any officer designated for the purpose by the Commission may reasonably require to assess such calculation.

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

2.8.9.2- Upon receipt of a complete application accompanied by all requisite information, particulars and documents including fees in compliance with all the requirements specified in these regulations. the application shall be deemed to be received and the Commission or the secretary or the designated officer shall intimate to the applicant that the application is ready for publication.

2.8.9.3- The applicant shall furnish to the Commission all such books and records (or certified true copies thereof), including the accounting statements, operational and cost data, copy of the application in electronic version comprising of soft copy showing detailed computations in a compact disc or in any other medium as may be required by the Commission for determination of tariff.

2.8.9.4- The procedural aspects pertaining to applications contained in these regulations shall apply, only to such extent as may be required by the Commission having regard to the circumstances of an individual case, to -

(a)An application made by a licensee under the proviso to sub-section (1) of section 36 of the Act;

(b)An application made by a distribution licensee under sub-section (5) of section 64 of the Act.

2.9Tariff Order. -

2.9.1- The Commission shall within 120 (one hundred and twenty) days from receipt of the composite application for the entire control period as specified in these regulations and after considering all suggestions and objections received, issue a tariff order for first year of the control period accepting the application with such modifications or such conditions as may be stipulated in that order.

Provided that in case of tariff application containing particulars of retail sale of electricity and wheeling, the order for retail sale tariff and wheeling tariff shall be issued separately.

2.9.2- Alternatively, an application may be rejected after granting a reasonable opportunity of being heard to the applicant and duly stating the reasons of rejection, recorded in writing if such application is not in accordance with the provisions of the Act and Rules & Regulations made thereunder or the provisions of any other law for the time being in force.

2.9.3- The Commission shall also approve the perspective plan with appropriate modifications as may be considered necessary for the control period.

2.9.4- The Commission shall, within 7 (seven) days of making the tariff order, send a copy of the order to the state government, the authority,. and the concerned applicant. The Commission shall also make available certified copies of order to any person on payment of a cost fixed by the Commission.

2.9.5- If the state government requires the grant of any subsidy to any consumer or class of consumers in the tariff determined by the Commission, the state government shall, notwithstanding any direction which may be given under section 108 of the Act, pay, in advance by a suitable mechanism to be approved by the Commission or a separate account payee cheque / demand draft / banker's cheque in favour of the licensee or such other person to implement the subsidy, the amount to compensate the person affected by the grant of subsidy as a condition for the licensee or any other person concerned to implement the subsidy provided for by the state government.

Provided that no such direction of the state government shall be operative if the payment is not made in the manner decided by the Commission.

2.9.6- The applicant shall within the time specified in the tariff order of the Commission, publish the salient features of tariff or tariffs approved by the Commission in at least 4 (four) dailies of which at least 1 (one) will be in English, and 1 (one) in Bengali having wide circulation in the operational area of licensee and shall put up the approved tariff on its internet website.

Provided that where the applicant is a generating company, the publication shall be in such newspapers as are widely circulated in the area of supply of the distribution licensee to whom the electricity will be supplied in terms of the tariff order and shall also be put up on the internet website of such distribution licensee and the generating company concerned.

2.9.7- The tariff so published shall be in force from the date specified in the said order and shall, unless amended or revoked, continue to be in force for such period as may be specified in the said order.

2.9.8- If in any tariff order there is no express provision, or express direction in respect of any matter that has been covered by an express provision or direction in an earlier tariff order or as per condition of supply of licensee prior to coming into force of the Act or as per any order of Appropriate Government prior to coming into force of the Act. the latter shall be deemed to have a continuing effect, until such provision or direction is altered, modified or discontinued by fresh directions in a subsequent tariff order. However, such change shall be applicable prospectively from a date to be fixed by the Commission.

2.9.9- If in any tariff order there is no express provision, or express direction in respect of any matter that has been covered by an express provision of these regulations, then the provision of such regulation will be considered as part of the tariff order.

2.9.10- If any regulation of the principal Regulations is amended, then the existing tariff order will continue till the next tariff order is issued.

2.9.11- If any principle used in the determination of ARR related to fixed cost for the ensuing years of second or first control period is found to be inconsistent with any subsequent amended regulations, then during APR of that year the same principle adopted in tariff order of the 1st ensuing year of the concerned control period will be followed :

Provided that from the second control period and onwards the capacity charge may be allowed to be recovered on the basis of regulation 6.4.3 of these regulations to the extent as may be decided by the Commission.

2.10Adherence to Tariff Order. -

2.10.1- No reimbursement of fuel and power cost shall be allowed on any excess beyond permissible (a) technical and non-technical loss and (b) self-consumption of electricity under the FPPCA formula mentioned in Schedule -7A of these regulations.

2.10.2- The tariff shall normally be revised from the prospective date unless there is a compelling reason to revise the same from the retrospective date in which case detailed justification will be given in writing by the Commission.

2.10.3- The licensee shall submit periodic returns as may be required by the Commission, containing operational and cost data to enable the Commission to monitor the implementation of its order and reassess the basis on which tariff was approved.

2.10.4- If any licensee or generating company recovers a price or charge exceeding the tariff determined under section 62 of the Act and in accordance with these regulations, the excess amount should be refunded along with interest as determined by the Commission without prejudice to any other liability incurred by such licensee or generating company.

2.11Mitigation of Regulatory Uncertainty and Risk. -

2.11.1- In order to remove any uncertainty in electricity business any licensee or generating company may submit any application to the Commission for getting 'in principle' clearance on any issue and/or for incurring any expenditure for which there is no specific approval mechanism mentioned under these regulations and have an impact on the tariff of the licensee or generating company prospectively :

Provided that in issuing such in principle' clearance, the Commission shall follow such procedure as is deemed necessary.

2.11.2- Notwithstanding anything to the contrary contained anywhere else in these regulations or in any other regulations of the Commission, the distribution licensee may purchase electricity from any other source(s) of 50 MW or below at any price over the stipulated price of procurement as provided in the tariff order, if it is found to be beneficial to the consumers on any of the following ground(s).

(i)If there is shortage in power and such purchase price is less than the rate of UI charges or prices available through power exchange whichever is higher for the relevant time block.

(ii)If the impact of such purchase results in less aggregate revenue requirement for the sale of electricity by the licensee to those for whom the Commission determines the tariff/ price of electricity.

Against each such transaction the licensee shall prepare cost benefit analysis in terms of the above conditionally and preserve those records, so that, if necessary, the Commission may scrutinize such records for validation whenever deemed necessary.

2.11.3- The licensee and generating company shall prepare the annual accounts in such a manner that all its expenditure and income on different heads are mentioned distinctly and separately with necessary notes and description or additional schedule or auditor's certificate from the same auditor of the annual account so that the Commission can take a proper view on each such head while determining the tariff :

Provided that wherever such expenditure and income are not adequately reflected in the annual accounts through distinctly separate notes and description or additional schedule or auditor's certificate from the same auditor of the annual account, as for example, if any expenditure under any head entitled 'others' or 'miscellaneous' or any other terminology which is non-specific, such expenditure may be disallowed by the Commission while determining the ARR.

2.11.4- Notwithstanding anything to the contrary contained anywhere else in these regulations, if any activity of any generating company or licensee which needs governance under any regulation is found to have started prior to coming into force of such regulation, then in such case the generating company or licensee shall bring to the notice of the Commission such fact and the Commission may dispose of such matter in such a way so that the licensee or generating company does not face any loss due to any reason(s) that was needed to be addressed before coming into force of such regulation. However, where any prospective measure can meet the need of such regulation, the Commission may give appropriate direction if deemed necessary.

Chapter - 3 Relevant factors to be considered for determination of tariff

3.1Time-of-the-Day (TOD) Tariff. -

3.1.1- To promote demand side management tariff for consumer may be differentiated by the Commission on the basis of time at which supply is required subject to the condition that the average price of electricity drawn under any such TOD tariff scheme by a consumer in a day shall be less than the non TOD tariff scheme applicable for him, if such drawal is at same level throughout the day.

3.1.2- To enhance optimum utilization of transmission and distribution network, the Commission may differentiate the transmission tariff/ charges or wheeling tariff/ charges or both of any licensee on the basis of the time at which supply is required.

3.1.3- The time strata applicable for determining tariff on the basis of time is as per regulation 3.13.

Provided that the Commission may, considering technology option available in metering system, decide to determine separate time strata for any class of consumers after taking into account other relevant factors as necessary.Provided further that the separate time strata as mentioned in TOD scheme 'B' under Annexure - C2 of these regulations is also applicable to such class of consumers as mentioned in that annexure,

3.2lncentivisation of supply on the basis of time of the day. -

3.2.1- To incentivise the peaking supply capability of thermal generating stations of a generating company to a licensee, the Commission may introduce separate tariff for peak, off-peak and normal period by differentiating on the basis of average tariff subject to the condition that none of the differentiated tariffs will be less than the cost of generation (average tariff minus the sum of the components of reasonable return) which is allowed by the Commission. However, none of such differential tariff shall be higher than 15% of the average tariff. If due to such differentiation, any variation in the generating company's revenue earning exceeds its aggregate revenue requirement, such excess revenue earnings shall be treated as an incentive to the generating company. In case of loss of revenue due to generation not commensurate with the demand pattern, such loss shall not be compensated through tariff.

3.2.2- To incentivise the peaking supply capability by a licensee to another licensee and the reduction of peak and off-peak drawal ratio by the electricity drawing licensee from the supplying licensee, the Commission may introduce separate tariff for peak, off-peak and normal period by differentiating on the basis of average tariff. However, none of such differential tariff shall be higher than 15% of average tariff. If due to such differentiation, any variation in the licensee's revenue earning exceeds its aggregate revenue requirement, such excess revenue earning shall be treated as an incentive to the licensee. in case of loss of revenue due to supply not commensurate with the demand pattern, such loss shall not be compensated through tariff.

3.2.3- The relevant time strata for tariff determination on the basis of time shall be as per regulation 3.13.

3.2.4- The said differentiation of tariff according to regulations 3.2.1 and 3.2.2 shall be based on differentiation of capacity charge for a generating station and annual fixed charge per unit of supply by a licensee.

3.3Differentiation on the basis of the Period of the Year. -

3.3.1- (i) The Commission may introduce separate tariff by differentiating on the basis of average tariff rate, for three seasons of summer, monsoon and winter, of the generating company. However, none of such differential tariff shall be higher than 15% of the average tariff. If due to such differentiation, any variation in the generating company's revenue earning from generating stations exceeds the aggregate revenue requirement, such excess revenue earning shall be treated as an incentive to the generating company. In case of loss of revenue due to generation not commensurate with the demand pattern, such loss shall not be compensated through tariff.

(ii)The Commission may also differentiate the tariff of supplying power from one licensee to another licensee according to the season. If due to such tariff differentiation, any variation in the licensee's revenue earning exceeds its aggregate revenue requirement, such excess revenue earning shall be treated as an incentive to the licensee. In case of loss of revenue due to supply not commensurate with the demand pattern, such loss shall not be compensated through tariff.

(iii)For above stated purpose, the licensee shall provide wheeled energy or transmitted power, as the case may be, for different season separately.

3.3.2- The Commission may differentiate tariff / charges for transmission or wheeling according to the season.

3.3.3- Similarly, the Commission may introduce separate tariff for any class of consumer for the seasons of summer, monsoon and winter for supply of power to consumer. The licensee shall submit season wise and time-strata wise (in case of TOD) actual energy sale in MU for different classes of consumers for each previous year, estimated energy sale in MU for base year and also projected energy sale in MU for each ensuing year in the control period for different seasons and relevant time strata as mentioned in regulation 3.13. For the purpose of season wise energy sales to various classes of consumers, season may be taken on the basis of corresponding billing account months in the billing system.

Provided that such differentiation of tariff on the basis of period of a season shall not be applicable to class of consumers having variable quarterly billing cycle within each class of consumers.

3.4Differentiation on the basis of the geographical area. -

3.4.1- The Commission may differentiate the tariff of licensees for same class of consumers on the basis of Rural / Urban administrative unit of the licensee.

3.4.2- The Commission may differentiate the tariff/ charges on the following basis :

(i)Need to reduce tariff shock to the consumer as decided by the Commission in case of merging of the areas of supplies of more than one licensees under one licensee as per statutory requirement and Commission may from time to time direct the licensees to submit the relevant information.

Provided that the difference of tariff existing between the consumers of two erstwhile licensees under that licensed area will be gradually eliminated among the consumers of the same class of consumers of the area of supply under the merged licence within-a period of not less than five years.

(ii)Geographical area of location of open access source from where any open access customer is getting supply of electricity as open access customer.

(iii)Geographical area of location of open access drawal point of an open access customer.

3.4.3- The Commission may differentiate the tariff of licensees on the basis of any geographical area on any ground that is consistent with the Act.

3.5Differentiation of tariff on the basis of nature of supply - The Commission may differentiate the tariff on the basis of nature of supply, which includes-

(i)Direct Current or Alternate Current

(ii)Reliability level of supply.

(iii)Degree of firm supply requirement by the consumer.

(iv)Predictability of electricity / power usage pattern by the consumer or class of consumer and its impact.

(v)Electricity / power supply requirement in discrete nature for a specific time period out of overall period.

(vi)Requirement of electricity / power supply or wheeling or transmission of electricity / power for a specific time period.

(vii)Nature of open access source from where any consumer gets the supply of electricity as open access customer.

3.6Differentiation on the basis of Consumption of Electricity - The Commission may differentiate the tariff on the basis of consumption of electricity by a consumer in a period in order to enhance the efficient as well as economical use and/ or to avoid wastage of electricity and consequently the resources.

3.7Differentiation on the basis of Demand - The Commission may for any period differentiate the demand charge of any class of consumers, whose demand varies season wise significantly, after giving three months of time for changing meter, incorporating changes in billing software and segregation of load, if any required for the purpose and billing is to be done prospectively.

3.8Treatment of Power Factor. -

3.8.1- The Commission may direct certain class of consumers to maintain power factor at a stipulated level, as may be decided by the Commission, and allow incentive or impose penalty through rebate or surcharge for maintaining power factor above or below the stipulated level, as the case may be.

3.8.2- The power factor rebate or surcharge shall be on energy charge only.

3.8.3- In addition to existing rebate/ surcharge on power factor applicable on the certain classes of consumers, the rebate and surcharge on power factor shall also become applicable for all HT / EHT consumers and the following LT consumers at a rate as will be stipulated in the tariff order from a date as given below or after that date as may be stipulated in the tariff order for the category of consumers as to be stipulated in the tariff order.

Category of Consumers	Date of introduction of rebate /surcharge on Power Factor
HT & EHT	Within 1st April, 2011
LT Industrial	As on 1st April, 2013
LT Public Water Works	As on 1st April, 2013
LT Commercial having Contract Demand 10 KVA and above	As on 1st April, 2014

3.8.4- All distribution licensees shall install power factor controllers for all LT consumers with contract demand of 10 KVA and above except LT industrial and LT public water works consumers and LT commercial consumers having contract demand of 10 KVA and above within 31st March, 2015 in a phased manner.

3.8.5- The following consumers shall install power factor controller / capacitor bank at their own cost in such manner as stipulated by the distribution licensee as per the following programme.

Type of consumer	Target date of completion of installation of power factorcontroller
HT / EHT	31st March, 2011
LT Industrial	31st March, 2013
LT Public water works	31st March, 2013
LT Commercial consumer having contract demand of 10 KVA orabove	31st March, 2014

3.8.6- Where the power factor controller is not commissioned or not put into service properly as reflected from recorded data of different parameters in the meter after the date as specified in regulation 3.8.5 of these regulations, the consumer may be required to pay power factor surcharge in a manner and as per terms and conditions as may be stipulated by the Commission in this regard in the respective tariff order.

3.8.7- The Commission may, if required, reschedule the time frame of regulation 3.8.3, 3.8.4 and 3.8.5 of these regulations through subsequent order(s).

3.9Treatment of Load Factor. -

3.9.1- The Commission may direct certain class of consumers to maintain load factor at a stipulated level, as may be decided by the Commission, and allow incentive or impose penalty through rebate or surcharge for maintaining load factor above or below the stipulated level, as the case may be.

3.9.2- For the purpose of billing, the load factor of a consumer for a billing month shall be determined in accordance with the following formula :

Load Factor (%) =	Energy Consumed in Kwh for the billing periodx 100
(H - ∑Hi)x MD + ∑( Hix RDi)

WhereH = Total Hours in the billing periodMD = Maximum Demand for Load Factor Calculation Recorded maximum demand in the billing period or 85% of the contract demand whichever is higherHi = The duration involved for the incidence of interruption / total shed/ partial restriction on load in supplying power to the consumer by the licensee as specified under regulation 3.9.3 of these regulations.RDi = Restricted load imposed on the consumer corresponding to the incidence or actual drawal during the period of such restriction whichever is higher.

3.9.3- The computation of load factor rebate and surcharge shall exclude that period which is a part of the concerned billing period and when load of the consumer is interrupted/ totally shed / partially restricted because of any fault of the licensee in its system or for non-availability of power with the licensee due to lower supply of electricity from its own generating source or its other suppliers of power or due to imposition of restriction on load by the licensee on drawal of power by its consumer. Such interruption shall also include the interruption caused by the grid failure or automatic under frequency relay tripping or any force majeure event not related to licensee.

3.9.4- For the purpose of load factor calculation as provided in regulation 3.9.2 of these regulations, the following principles shall be followed :

(i)If Maximum Demand (MD) is in KVA, it shall be converted into KW by using the formula : KW = KVA x PF, where PF is the power factor.

(ii)If RD, is in KVA, it shall be converted into KW by using the formula : KW = KVA x PF, where PF is the power factor.

(iii)PF shall be considered as average power factor of the month when 85% or less of the contract demand is recorded maximum demand.

(iv)When maximum demand (MD) represents actual recorded maximum demand, which is higher than 85% of contract demand, PF will be the actual average power factor of the time block corresponding to the period of recording the maximum demand.

(v)For total shedding or interruption, RDi shall be considered as zero.

3.9.5- Load factor rebate for consumer of a licensee will be gradually reduced for load factor below average system load factor of that licensee based on the latest available system load factor of the licensee for a whole year and eliminated within 2013-14 in a manner as will be determined by the Commission.

3.10- The Commission may apply all the above factors from 3.1 to 3.9 or any combination of them for determination of tariff for any class of consumers.

3.11Regulatory Asset. -

3.11.1- If the Commission is satisfied on consideration of the relevant facts and figures that a licensee would not be able to recover fully all the admissible costs at the tariff determined for a particular year(s), for reasons beyond the control of the licensee resulting in abnormal variation(s) in the income or expenses, or both of the licensee for that particular year(s), and the Commission is also satisfied that one time recovery of the entire revenue requirement of the licensee in that particular year(s) for which tariff is being determined, will not be prudent due to tariff shock to the consumers, and also further that the shortfall cannot be met through full or partial utilization of the balance available from any reserve created for such a purpose, the Commission may make appropriate provisions in the tariff order for regulatory assets thereby allowing recovery of the shortfall through future tariffs.

3.11.2- A licensee also may pray to the Commission for creation of a regulatory asset under similar circumstances. The Commission shall satisfy itself about necessity of creation of a regulatory asset on the basis of a prayer from a licensee before issuing any direction for creation of such an asset.

3.11.3- Where the Commission has allowed creation of a regulatory asset, it shall reasonably stipulate the period of amortization and the specific roadmap of release of such regulatory asset along with the date by which such regulatory asset will be extinguished.

3.11.4- From third control period for any licensee or generating company preferably regulatory asset shall not be created through the tariff order of any two subsequent orders except the amount of regulatory asset that is created for the purpose of adjusting during APR with gain from sale of power to the person other than consumers and licensees.

3.12Metering Based Tariff Design and Related Factors: -

3.12.1- The Commission may make TOD or pre-paid metering mandatory within certain time frame for any class of consumers as may be specified by the Commission in due course besides those already covered in Annexure - C2.

3.12.2- No electricity charges shall be recovered from any consumer whose supply has not been made through meter after such date as may be notified by the Commission under sub-section (1) of section 55 of the Act subject to other dispensation as provided in other regulations of the Commission on specific grounds.

3.12.3- The Commission may differentiate tariff or rebate or discount or surcharge or penalty for use of TOD and / or pre-paid meter to provide incentive for efficient use of electricity, ensuring better demand side management and for increased operational efficiency of licensee.

3.12.4- All short-term supply or short-term irrigation supply or short-term supply for commercial plantation or construction supply or emergency supply or common services for industrial estate in LV & MV class of consumers shall be on pre-paid meter basis with activated current limiter and load limiter. In case of technical limitation of pre-paid meter to cater the demand of connected load, multiple pre-paid meters may be used wherever possible.

3.12.5- For power factor measurement by the meter, kWh and kVAh / rkVAh under lagging power factor conditions, can be used by the licensee depending on the availability of such facility in the meter.

3.12.6- The consumer opting for pre-paid meter shall not be required to furnish any security deposit for the energy charge.

3.12.7- No meter rent shall be applicable if the cost of the meter is given by the consumer.

3.13Time Strata for determination of tariff : - Generally, the following time strata are to be considered as normal, peak and off-peak periods :

(i)Time between 06-00 hours and 17-00 hours of the same day shall be treated as the normal period;

(ii)Time between 17-00 hours and 23-00 hours of the same day shall be treated as the peak period;

(iii)Time between 23-00 hours of the same day and 06-00 hours of the following day shall be treated as the off-peak period.

Provided that the Commission may, on consideration of the system peculiarities of any specific licensee or any other relevant factor, determine a different set of time strata for any specific licensee or any specific generating station for the purpose of effecting generation or supply to any particular class of consumers or to all consumers or licensees or any other persons.

3.14Reactive Energy Charge - Commission may decide reactive energy charge from time to time through a separate order which will be applicable on all the entity of the State grid.Chapter - 4 Tariff components and other elements related to consumer

4.1Components of Tariff.-

4.1.1- The charges for the electricity supplied by a Distribution licensee to a consumer shall generally consist of any one or more of the following :

(a)fixed charges;

(b)demand charges;

(c)minimum charges;

(d)energy charges for electricity supplied.

Such charges for electricity may be determined either in the form of a single part tariff or a two part tariff.

4.1.2- Rent for meter or any other equipment(s) provided by the licensee at the premises of a consumer and other charges are non-tariff charges that shall be determined by the Commission. While submitting an application for tariff determination or APR, the licensees shall provide existing meter charges in the Form 2.8 contained in Annex - 2 of these regulations for all classes of consumers inclusive of those mentioned in the Annexure C1 of these regulations and a separate list covering other charges.

4.2.1- Fixed charges, which will be applicable for LV and MV consumers having contract load below 30 KVA and quantified in terms of per KVA/month, shall be based on contract demand.

4.2.2- The recoverable fixed charge from consumer through tariff shall be determined by the Commission through tariff order from time to time and it may be part or full value of the applicable fixed charge in terms of the ceiling of the fixed charge as detailed below. The ceiling of the fixed charge against each KVA of contract demand of a consumer of a licensee for a month shall be FC_UL where

FC_UL =	Annual Fixed Cost in rupees for the licenseefor the ensuing year
(Projectedpeak demand of the licensee in KVA for the ensuing year based onprojected sale of its electricity to its consumers in that year)x 12

Where projected peak demand of the licensee in KVA based on sale of electricity to the consumer in the ensuing year as mentioned in denominator is computed by reducing the projected maximum system peak demand, projected on the basis of past trend, by the amount proportionate to normative average distribution loss of that ensuing year and using power factor as 0.85.

4.2.3- While determining the tariff the Commission may change the Fixed Charges for an ensuing year at a rate not more than 100% of the said charges of the base year or the preceding ensuing year of the control period in the cases where such charges exist. However, for a class of consumers for whom no such fixed charges exist, the Commission can introduce such charges at a rate not higher than that of the highest rate applicable for any other class of consumers.

4.2.4- For fixed charge computation of any consumer, contract demand below 1 KVA shall be treated as 1 KVA.

4.3.1- Demand charge will be applicable to all HV and EHV consumers and also to those LV and MV consumers who have contract load of 30 KVA or above and at a rate as stipulated in the respective tariff order. Demand charge will also come Into force for the following classes of consumers having contract load of below 30 KVA at a rate as stipulated in the respective tariff order as per the following schedule.

Category of Consumers	Earliest Date of introduction of Demand charge
LT Industry	1st April 2015
LT Commercial having Contract Demand 10 KVA and above	1st April 2016
LT Public Water Works	1st April 2016

However, if required the Commission may reschedule the above time frame through subsequent order(s).

4.3.2- The recoverable demand charge from consumer through tariff shall be determined by the Commission through tariff order time to time and it may be part or full value of the applicable demand charge in terms of the ceiling of the demand charge as detailed below. The ceiling of monthly Demand charge against each KVA of contract demand of a consumer of a licensee for a month will be DC_UL where

DC_UL =	Demand/CapacityCharges in rupees to be paid annually as per agreement bylicensee with other licensee or generating company irrespectiveof power drawn or not	+ FC_UL;
(Projectedpeak demand of the licensee in KVA for the ensuing year basedon projected sale of its electricity to its consumers in thatyear) x 12

and FC_UL is as defined in regulation 4.2.2. The denominator of the first term in the above formula is computed in the same method as specified in the regulation 4.2.2.

4.3.3- The demand charge shall be based on the data available from the recording in consumer's meter of average supply in terms of demand for every 15 minutes time block as is applicable under ABT mechanism. In order to meet the need of technological upgradation of the meter the existing system of half hourly recording may continue up to 31st March, 2015.

4.3.4- While determining the retail tariff applicable to the consumers, the Commission may change the demand charge for an ensuing year at a rate not exceeding 20% of the said charge of the base year or the preceding ensuing year of the control period in the cases where demand charges exist. However, for a class of consumers for whom no such demand charges exist, the Commission can introduce such charges at a rate not higher than the highest rate applicable for any other class of consumers.

4.3.5- Demand Charge shall be levied on the basis of maximum demand, recorded during the month or 85% of the contract demand whichever is higher.

4.3.6- No demand charge shall be payable by any consumer for that period when load of the consumer is interrupted/ totally shed/ partially restricted because of any fault of the licensee or its system or for non-availability of power with the licensee due to lower availability of power from its own generating station and / or its other suppliers of power or imposition of any restriction by the licensee on drawal of power by consumer. However, such exemption from demand charge shall not be available if the interruption is caused by grid failure or automatic under-frequency relay tripping or any force majeure event not related to licensee or due to disconnection of supply for any fault on the part of the consumer. Accordingly, after taking into consideration regulations 4.3.2, 4.3.3, 4.3.4, and 4.3.5, the demand charge in a billing period for a consumer shall be determined in accordance with the following formula :

DC = DCAx	(H - ∑Hi)x MD +∑Hix RDi)
H

WhereDC = Computed Demand Charge applicable to a consumer for billing periodDCA = Applicable rate of demand charge for a consumer.H = Total hours in the billing period.Hi = The duration involved for the incidence of interruption / total shed / partial restriction in supplying power to the consumer which is not to be considered as per this regulation.MD = Maximum Demand considered for levying demand charge as per regulation 4.3.5.RDi = Restricted load imposed on the consumer corresponding to the incidence or actual drawal during the period of such restriction whichever is higher.

4.4- If in a 15 minutes time block a consumer draws power more than the restricted drawal, if any, imposed by a licensee then the consumer will pay additional energy charge at a rate twice the applicable rate for that consumer at that time block. Such additional energy charge shall be payable in addition to the amount that is payable as energy charge for consumption of energy in that particular time block.

4.5- If the supply is disconnected by the distribution licensee at the request of the consumer, the agreement of supply with the consumer shall stand terminated from the date of disconnection. This is, however, without any prejudice to any other compensation if the consumer is entitled to such compensation because of applicability of any other law for the time being in force or the Electricity Act, 2003 or the Regulations made thereunder.

4.6.1- If a consumer, having a captive generating plant, takes stand-by supply of energy from a distribution licensee in respect of the premises where electricity is drawn from its captive generating plant and also sells surplus energy from that captive generating plant to the same distribution licensee, the demand charge of such consumer shall not be more than 50% of the applicable rate of demand charge for such category of consumers subject to the following conditions :-

(i)there shall be firm allocation of surplus capacity of the captive generating plant for sale of energy to the distribution licensee and that shall not be less than 5 MW;

(ii)total surplus generation from that captive generating plant is sold to the distribution licensee(s) within the State;

(iii)tariff of such surplus energy from that captive generating plant to be sold to the distribution licensee(s) shall be determined by the Commission on normative parameters as specified or will be specified in Schedule-9A or Schedule-9D or stipulated in relevant tariff order.

Provided that for the plant whose allocated capacity for such sale of electricity is 25 MW or less, the distribution licensee can decide the price through negotiation subject to the ceiling that such price does not exceed the maximum power purchase cost of that distribution licensee from the sources for which the tariff is determined through regulatory process and is of the same type (such as thermal, hydros etc.).Provided also that for the plant of capacity allocated for such sale below 100 MW but above 25 MW, operating norms will be set by the Commission and purchase price will be determined by the licensee on the basis of such norms through negotiation subject to ceiling that such prices does not exceed the maximum power purchase cost of that distribution licensee from the sources for which the tariff is determined through regulatory process and is of same type (such as thermal, hydros, etc.).Provided further that if such electricity purchased from such captive source is found to be in excess of the need of the power to feed its consumer and other licensee of the State, then the distribution licensee may purchase such power through negotiation only without following the steps specified in earlier provisos.

(iv)a PPA shall be executed by such consumer for sale of such energy from his captive generating plant to the distribution licensee for a period not less than ten years.

4.6.2- A captive generating station shall be allowed to bank its generation with a distribution licensee, if at least 25% of its annual actual generation of such captive generating station is sold to the distribution licensee provided that such distribution licensee agrees to such banking mechanism through PPA and subject to the conditions as specified in clause (i), (ii), (iii) and (iv) of regulation 4.6.1.

Provided that such banked energy can be drawn by the owner of the captive generation at its drawal point in a barter mode in accordance with the terms and conditions as laid down in the PPA.Provided also that for such banking arrangement and subsequent drawal in barter mode of energy from the distribution licensee the Transmission and Distribution losses of energy and wheeling charges for using distribution network of the distribution licensee can be mutually settled by the distribution licensee and the owner of the captive generation in their PPA. so long it is not against the interest of the consumer and after finalization of the PPA the same shall be sent to the Commission for concurrence.

4.6.3- If a generating station operates as a captive generating plant and at the end of the year such plant does not qualify as Captive Generating Plant as per Electricity Rules 2005, or any other rule made under the Act for this purpose, then the user of such generating station is required to pay for the year in twelve equal installments the total cross subsidy charges reduced by the demand charge as paid by the owner in consumer mode in that year for the quantum of energy that is being consumed by the owner. If such value is negative then it will be treated as zero.

4.7- If a consumer consumes power in excess of his contract demand, he shall be liable to pay extra charges as stipulated below.

4.7.1- If the highest demand of any non-TOD consumer recorded in a month exceeds his contract demand, he shall be liable to pay demand charge at the applicable rate for that non-TOD consumer in question. In addition, he will be also liable to pay an additional demand charge at the rate of 60% of the demand charge for the additional demand being the difference between the recorded highest demand and his contract demand. Excess energy drawal corresponding to the aforesaid excess demand shall be billed at the rate of energy charge applicable for such consumer.

4.7.2- In case the highest demand of any consumer under TOD tariff exceeds the contract demand in any month, the demand charge as mentioned in the tariff schedule of the tariff order for any year shall apply on highest demand for that month. In addition, the demand of power in excess of sanctioned contract demand in any period of time shall attract the additional demand charge for the said excess demand for such consumer, and the same shall be calculated according to the following formulae :

(i)In case the highest demand during normal period exceeds the contract demand

ADCED = 0.2 x (Dact - Dcont) x DC

(ii)In case the highest demand during peak period exceeds the contract demand

ADCED = 0.5 x (Dact - Dcont) x DC

(iii)In case the highest demand during off-peak period exceeds the contract demand

When Dact > Dcont and Dact < 1.3 x DcontADCED = 0.01 x (Dact - Dcont) x DC When Dact > 1.3 x Dcont and Dact < 1.5 x DcontADCED = [0.01 X 0.3 x Dcont + 0.1 x (Dact - 1.3 x Dcont)] x DC When Dact > 1.5 x DcontADCED = [0.01 x 0.3 x Dcont + 0.1 X 0.2 x Dcont + 0.2 x(Dact - 1.5 x Dcont)] x DC

(iv)In the formulae (i), (ii) and (iii) mentioned above, the abbreviations have the meanings as given below :

ADCED = Additional Demand Charge for demand of power in excess of sanctioned contract demand during the billing period.Dact = Actual highest demand of power in respective time period.Dcont = Sanctioned Contract Demand of the consumer.DC = Rate of Demand Charge as per the tariff order for the relevant category of consumer.

(v)In case demand of power exceeds sanctioned contract demand in more than one time period, computation of Additional Demand Charge (ADCED) shall be done for each such time period and the highest among such computed additional demand charge for different time periods shall be chargeable.

(vi)Excess energy drawal corresponding to any excess demand shall be billed at the applicable energy charge for such consumer.

4.7.3- In case of application of regulation 4.3.6 in a month the additional demand charge computed as per regulation 4.7.1 or 4.7.2 shall further be adjusted through reducing the amount by a multiplying factor of DC/(MD x DCA) where DC1 DCA and MD are specified in regulation 4.3.6.

4.8- In case of non availability of demand in KVA the said demand shall be converted from KW by considering average power factor of the concerned period or a power factor of 0.85 if the average power factor cannot be calculated because of non-availability of data.

4.9- No consumer shall be made to pay both demand charge and fixed charge simultaneously.

4.10- Notwithstanding anything to the contrary contained anywhere in these regulations, in cases where no consumption of energy has taken place for any reasons whatsoever including disconnection of supply due to fault on the part of the consumer but excluding instances of interruption in supply due to failure on the part of the licensee, the fixed charge or demand charge of a consumer, as the case may be, shall be calculated on the basis of the contract demand.

4.11- When a licensee bills a consumer for consumption of electricity covering only a part of month caused by discontinuance of consumership before the expiry of a full month, the computation of fixed charge or demand charge shall be made for the entire month excepting for such consumers under the short-term supply for whom such billing shall be pro-rata for the number of days for such supply in that particular month.

4.12- Tariffs for consumers having optional TOD-Tariff scheme in LV & MV category with different tariff for different slab of consumption, shall be computed on the basis of the following formula where tariff has not been provided in the concerned tariff order :

RTOD	=	Rx (Cnormal+Cpeakx1.35 +Coff-peakx 0.70
Cnormal	=	Energy consumption during normal period in thebilling period
Total energyconsumption during normal period in the billing period
Cpeak	=	Energy consumption during peak period in thebilling period
Total energyconsumption during billing period
Coff-peak	=	Energy consumption during off-peak period inthe billing period
Total energyconsumption during billing period
R	=	Total energy charge cmuted on the billing ofnormal non-TOD tariff rate in the billing period
Total energyconsumed in the billing period

Normal period, peak period and off peak period shall be such as defined in regulation 3.13.

4.13- For any class of the consumers for whom minimum charge is stipulated in the tariff order, such minimum charge shall be applicable when the sum of the energy charge and fixed charge including rebate/surcharge (except rebate for timely payment) is less than the minimum charge for that billing period.

4.14- The rates of the applicable delayed payment surcharge arising from non-payment of electricity charges as also other charges by a consumer shall be 1.25% per month of delay or pro-rated for part thereof up to 3 months of delay, at 1.5% per month of delay or pro-rated for part thereof for any period beyond 3 months of delay but up to the next 3 months and at 2% per month of delay or pro-rated for part thereof beyond first 6 months of delay. Delay in payment shall be counted from the due date for payment. This delayed payment surcharge is without prejudice to the provisions of disconnection under the Act and the Regulations made thereunder.

4.15- For the purpose of these regulations, the contract demand shall mean the electrical load in horse power (HP) or Kilo Watt (KW) or in Kilo Volt Ampere (KVA) which, in accordance with the signed contract or agreement between the licensee and the consumer, the licensee has committed to deliver and the consumer has right to draw at the delivery point of the consumer at any or all time during the currency of the contract or agreement. For the purpose of these regulations, the contract demand shall also mean any of the following words that might have been incorporated in the agreement between the consumer and the licensee such as contract load or contracted load or sanctioned load or connected aggregate installed capacity or installed capacity. Where the term connected aggregated installed capacity or installed capacity or connected load on contract load or contracted load or contractual load is used in such agreement, in such case the contract demand will be arrived at as per the following formula.

Contract Demand =	Annual Consumption in Unit
Number of days in year x 24

Such contract demand shall be intimated to the consumer for applying revision of contract demand. If no request for such revision is received from the consumer within three months from the date of receipt of such intimation by the consumer, then such calculated contract demand shall be considered as contract demand under the agreement and also for the purpose of these regulations from the date of expiry of 90 (ninety) days of such intimation. However, this revision of contract demand under this regulation shall not be considered for the purpose of counting number of revision in load reduction under SOP.Provided that if it is found subsequently that the above calculated contract demand for any existing consumer differs from the contract demand calculated on the basis of any specific definition under any procedure framed by the licensee under SOP in such case that definition of Contract Demand will become applicable prospectively and no claim for retrospective effect will be allowed.Provided further that where Contract Demand is specifically defined in any agreement of supply or procedures framed by the licensee under SOP, in such case that definition will stand as Contract Demand for new connection effected under that agreement of supply or procedures.Provided also that where any definition of contract demand exists in a procedure framed under SOP regulation, then under any agreement for supply no new definition will be permitted under these regulations from the date of effect of the procedure.

4.16- All statutory levies like Electricity Duty or any other taxes, duties, cess etc. imposed by the State Govt. / Central Govt. or any other competent authority on sale of electricity shall be extra and shall not be a part of the tariff as determined under these regulations.

4.17- For any pre-paid and TOD tariff scheme, other charges shall be the charges applicable to consumers under respective category of non-TOD tariff.

4.18- All billing parameters of a bill shall be construed for a billing period only, which has been specified by the Commission, irrespective of the date on which the meter reading is taken in accordance with any regulation made by the Commission

4.19- In case the contract demand in KW or KVA is not available, it can be converted from KVA considering 0.85 as power factor or vise-versa whenever it is necessary for determination of any issue in relation to tariff or category of consumers.

4.20- In order to remove noise from the system the Commission may introduce rebate and/ or surcharge to any class of consumers through any formula on the basis of any form of measurement of harmonics and applicable from a date which will be stipulated in any tariff order.

4.21- Notwithstanding anything to the contrary contained in these regulations, the fixed charge for a consumer shall not be differentiated according to the period or time of a year.

4.22- The demand charge of any consumer may be differentiated to the extent of such part of demand charge which does not include the fixed charge component within the demand charge as specified in regulation 4.3.2 of these regulations.Chapter - 5 General principles of computing cost and return

5. Capital Cost.

5.1- The Commission shall be guided by the following principles to compute the cost and return.

(i)Investments made prior to the notification of these regulations by the generating company and licensees shall be accepted on the basis of audited accounts, subject to prudence check.

(ii)Wherever Power Purchase Agreement or Agreement for transmission / wheeling provides for a ceiling of capital cost, the capital cost to be considered shall not exceed such ceiling.

(iii)Capital cost for licensee to be considered as below :

(a)The capital expenditure incurred by a licensee or a generating company in any financial year, being a part of a capital building project spanning a number of financial years, shall be, subject to prudence check by the Commission, considered in terms of the instant regulations :

Provided that the aforesaid stipulations shall apply to such capital building projects that have been initiated on, or after these regulations have come into force :Provided also that only such capital expenditures that have resulted in both building and full operationalisation of one or more capital asset(s) which is/are components of the total capital building project referred to above shall qualify to be considered for this purpose.Provided also that investment approval for such capital expenditure is being allowed for the improvement of the norms of the operational parameter, then the norms associated with such parameter shall be revised after the effect of such capital expenditure take place subject to condition that such investment approval shall specifically mention the targeted norms.

(b)For each capital expenditure project, the sum total of annual allowable capital cost from the date of commencement of such project till the date of commissioning shall be the original cost of such project, subject to its approval in accordance with these regulations wherever applicable.

Provided that the Commission may permit reasonable additional costs, which are in the nature of capital expenditure, to be included in the original project cost beyond the date of commissioning upon application for the same made by the licensee or generating company within one year from the date of commissioning.

(c)Where the actual cost incurred on a capital expenditure project exceeds or is likely to exceed the estimate of original project cost, then the licensee or generating company shall apply to the Commission for approval for variation in the estimate of original project cost with supporting documents and proper justification of variation of cost.

(d)Where the actual cost incurred on a capital expenditure project is lower than the approved original project cost, the Commission shall, after due scrutiny, permit the resultant savings in interest on loan capital during the construction period of such project to be dealt with in the manner specified in these regulations. Scrutiny of the original project cost shall be limited to the reasonableness of the capital cost, financing plan, interest during construction stage, use of efficient technology, economic use of resources, need to optimize investment and such other matters for determination of tariff.

(e)Notwithstanding anything contained in these regulations, for any capital expenditure project approved by the authority concerned before notification of these regulations, the actual cost as recorded in the books of account of the licensee or generating company shall be considered as the original cost of project, subject to its approval by the then statutory authority concerned wherever applicable and also subject to prudence check by the Commission,

(f)The amount of any contributions made by users of transmission system or distribution system towards works for access to the intra-State transmission system or distribution system of the licensee or generating company shall be deducted from the original cost for such project for the purpose of calculating the amount of loan capital and equity capital under these regulations.

Provided that for the purpose of depreciation under these regulations, the original project cost before deduction of any such contribution shall be taken into account.

(iv)Prudent accounting practice shall apply, to the extent not inconsistent with these regulations, in determining the original project cost of capital expenditure and / or original cost of fixed assets capitalized.

(v)The resultant Foreign Exchange variations on account of repayment are to be dealt as specified in these regulations.

(vi)The capital cost may include capitalized initial spares as follows :

(a)Up to 2.5% of original capital cost in case of coal based / lignite fired Generating Stations;

(b)Up to 4.0% of original capital cost in case of Gas Turbine / Combined Cycle Generating Stations;

(c)Up to 1.5% of original capital cost in case of Hydro-Generating Stations;

(d)Up to 2.0% of original capital costs for distribution projects;

(e)Up to 1.0% of approved original capital costs for transmission projects;

(vii)Restructuring of capital cost in terms of relative share of equity and loan shall be permitted during the tariff period provided such restructuring is cost effective. Any savings in costs on account of subsequent restructuring shall be dealt with in accordance with these regulations.

(viii)Any new generating station or any project of any licensee which is planned to be implemented and whose tariff is to be determined by WBERC, shall get its investment plan approved by the Commission before the construction starts. The project, which is already under construction on the date of publication of these regulations, shall get its investment plan approved in accordance with regulation 2.8.3 by the Commission prior to filing its tariff application for the project.

(ix)For any new generating station for which tenders for supply of plants and equipments have been invited after 15.10.2007 and whose project cost is not determined / approved under these regulations, the concerned generating station shall submit all the information as required under regulation 2.8.1.4 to the Commission and obtain approval of the Commission before electricity is supplied by that generating station. to the distribution licensee at a tariff determined under section 62 of the Act.

(x)If the tariff of any generation station of a generating company or licensee is adopted under section 63 of the Act and subsequently the generating company or licensee, as the case may be, intends to have the tariff determined for that generating station under section 62 of the Act, then the licensee/generating company shall submit all information as required under regulation 2.8.1.4 to the Commission and obtain the investment approval of the Commission before electricity is supplied by that generating station to the distribution licensee at a tariff determined under section 62 of the Act.

5.2Additional Capitalization. -

5.2.1- The following capital expenditure incurred within the scope of work as approved by the Commission after the date of commissioning and up to the cut off date may be allowed by the Commission for inclusion in the original project cost, subject to prudence check :

(i)Deferred liabilities:

(ii)Procurement of initial capital spares in the original scope of work, subject to ceiling specified in regulation 5.1(vi) of these regulations.

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

(iv)Liabilities on account of change in law, if any.

Provided that original scope of work along with estimates of expenditure shall be submitted along with the next application for determination of tariff.Provided further that a list of the deferred liabilities and works deferred for execution shall be submitted along with the next application for determination of tariff after the date of commercial operation of the generating station.

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

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

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

(iii)Liabilities on account of change in law;

(iv)Any additional works / services which have become necessary for efficient and successful operation of the generating station or licensed business, but not included in the original project cost;

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

(vi)Works related to Pollution Control Measures; and

(vii)Works related to compliance of any statutory requirements.

5.2.3- Any expenditure on minor items / assets like normal tools tackles, personal computers, furniture, air-conditioners, voltage stabilizers, refrigerators, fans, coolers, TV, washing machines, heat-convectors, carpets, mattresses, etc. bought after the cut-off date may not be considered for additional capitalization subject to prudence check by the Commission for determination of tariff. The list of items is illustrative and not exhaustive.

Provided that approval of the Commission under this regulation shall not be required where the aggregate expenditure on such assets in any financial year does not exceed 1`)/0 of total business turnover of that financial year subject to a maximum of Rupees Ten (10) crores.

5.2.4- Prudent accounting principles shall apply, to the extent not inconsistent with these regulations, in determining the original project cost.

5.2.5- The approved capital expenditure of the project shall be considered as the original project cost of such project for the purpose of these regulations.

5.2.6- The amount of capital expenditure at actual shall be considered, subject to the normative debt equity ratio and the completion schedule not exceeding the time approved by the Commission at the time of approval of the investment proposal.

5.2.7- The following considerations shall apply for regulations 5.1 and 5.2 :

(i)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 original scope of work shall be financed in the normative debt equity ratio specified in these regulations;

(ii)Any expenditure incurred on replacement of old assets shall be capitalized subject to satisfaction of the condition in sub-clause (a) of clause (iii) of regulation 5.1 and such capitalization shall be considered after writing off the gross value of the original assets from the original capital cost.

(iii)Any expenditure admitted by the Commission for determination of tariff on account of new works not in the original scope of work shall be financed in the normative debt equity ratio specified in these regulations.

(iv)Any expenditure admitted by the Commission for determination of tariff on renovation and modernization and life extension shall be financed on normative debt equity ratio specified in these regulations after writing off the original amount of the replaced assets.

(v)Any expenditure admitted by the Commission incurred on purchase of other fixed assets shall be assumed to be financed at a normative debt: equity ratio specified in these regulations;

5.2.8- The licensee shall submit the list of capital assets that are to be capitalized in terms of sub-clause (a) of clause (iii) of regulation 5.1 of these regulations showing the capital value of the capitalized assets along with the operational status of full commissioning or quantifiable partial commissioning of those assets clearly.

5.3Revenue / charges during trial stage (prior to COD). -

5.3.1- The actual cost incurred excluding fuel cost during trial up to COD shall be treated as capital cost;

5.3.2- The actual revenue earned from sale of power (infirm power) net of fuel cost shall be treated as reduction in capital cost:

5.3.3- For sale of infirm power Commission shall determine tariff or price of such infirm power on application from owner of the generating station.

5.4Debt-Equity Ratio. -

5.4.1- For the purpose of these regulations, the amount of loan capital and equity capital for existing business shall be calculated as follows :

(i)The amount of loan capital shall be equal to the sum of the outstanding balance of all long-term loans taken to finance the purchase or construction of assets of the generating company or licensee, at the commencement of the financial year for which tariff is being determined, as reflected in the books of account of the generating company or licensee subject to prudence check by the Commission;

(ii)The amount of equity capital at the beginning of any financial year shall be equal to -

(a)Equity capital as at 1st April of that year as determined by the Commission on the basis of approved equity capital as on 1st April of the preceding year; plus

(b)Equity component of approved capital expenditure for the preceding financial year ending 31st March;

(iii)Equity component of approved capital expenditure for the concerned year would be added to the equity capital as on 1st April of that year to arrive at the equity capital at the end of the year.

Explanation - for the purpose of these regulations, equity capital shall be the sum total of paid-up equity capital, preference share capital, fully / compulsorily convertible debentures (or other financial instruments with equivalent characteristics), foreign currency convertible bonds, and share premium amount along with free reserves which have been used for capitalization in the core business along with the embedded generation, if any, inclusive of capitalization through issuing of bonus share. The amount of any grant, revaluation reserve, development reserve, contingency reserve and contributions from customers shall not be included in the equity capital. The amount reflected in the books of account as deferred tax liability or deferred tax asset of the core business shall be added or deducted, as the case may be, from the amount of equity capital. The premium if any raised by the generating company or the licensees while issuing share capital and investment of internal resources created out of its free reserve for the funding of the project, shall be reckoned as paid up capital for the purpose of computing Return on Equity, provided such premium amount and internal resources are actually utilized for meeting the capital expenditure.

5.4.2- For the purpose of determination of tariff on new capital expenditure including expansion of existing business, debt-equity ratio as on the date of commercial operation of generating station and transmission projects, sub-station, distribution lines or capacity expanded after the notification of these regulations shall be 70:30. Where equity employed is more than 30% the amount of equity shall be limited to 30% and the balance amount shall be considered as normative loan capital.

Provided that in case of a generating company or other licensees, where actual equity employed is less than 30%, the actual debt and equity shall be considered for determination of return on equity in tariff computation;Provided further that in case of equity invested in foreign currency, the value of Indian rupees on the date of each such investment of equity shall be considered as respective equity for the purpose of tariff determination under these regulations.Explanation : For the purpose of computation of actual debt equity ratio, the permitted additional capital expenditure incurred after 1st April 2006 is to be considered in aggregate along with actual debt and equity provided to finance such expenditure. For the purpose of the above mentioned computation, equity shall include any project cost or part thereof financed by internal resources subject to ceiling of debt-equity norms indicated above.

5.4.3- Any approved change in the original cost of a project / fixed asset after the date of commissioning shall be assumed to have been financed at the normative debt equity ratio.

5.4.4- The debt and equity amount arrived at in accordance with the instant regulations shall be used for calculating interest on loan, return on equity, advance against depreciation and incentive to transmission licensee.

5.5Loan repayment schedule. -

5.5.1- The repayment schedule for the loan capital shall be in accordance with the loan agreements. In case where low cost loan is found to be cheaper than the existing loan after taking into account all the contents of loan agreements, then the licensee / generating company shall resort to replacing the existing loan through swapping by new loan.

5.5.2- Where, the actual amount of depreciation falls short of actual amount of loan repayment in any financial year allowable under these regulations, such shortfall shall be allowed as an advance against depreciation (AAD) for the difference between the actual amount of such- repayment and the allowable depreciation for such financial year.

Provided that such advance against depreciation shall be restricted to the 1/10th of the principal amount of original approved loans minus the amount of depreciation allowable under these Regulation.Provided also that upon repayment of the entire loan amount, the original cost of the fixed asset shall be reduced by the aggregate of accumulated depreciation and advance against depreciation availed by the generating company or the licensee and the resulting depreciable value shall be spread over the balance useful life of the fixed asset.

5.5.3- During the tenure of loan repayment, where the actual amount of loan repayment in any financial year is less than the amount of depreciation allowable under these regulations, then an interest credit at the rate of weighted average cost of debt for the corresponding year shall be provided on such excess depreciation charged.

5.6Calculation of some elements of Fixed charges. -

5.6.1Return on Equity (ROE). -

5.6.1.1- Return on equity for generating company and transmission licensee shall be computed on the equity capital determined in accordance with these regulations and the applicable rate will be the same as provided for / to be provided for by the Central Electricity Regulatory Commission for generating company and transmission licensee from time to time. Such return on equity shall be calculated on the pre-tax basis and actual income tax liability related to the core business only will be allowed separately on actual payment basis subject to final assessment.

5.6.1.2- Return on equity for a distribution licensee shall be computed on the equity capital determined in accordance with these regulations and applicable rate will be one percent higher than the rate which is applicable as per relevant Regulations of CERC for a generating station of a generating company : Provided that such additional one percent return on equity as specified above for distribution licensee shall be applicable for the equity contribution related to distribution assets only.

5.6.1.3- When a run-of-river hydro-generating station with pondage operates to support the peak demand in a day, the Commission will allow an additional return on equity to such a hydro-generating station, the additionality being 1% more than what has been provided for in this behalf by the CERC for any hydro-generating station.

5.6.1.4- Any of the hydro-generating stations, excluding pumped storage hydro generating station, with allocated installed capacity of 100 MW or above under the purview of the Commission shall be entitled to additional return on equity of 4% more than what has been provided for in this behalf by the CERC for hydro-generating stations for supply of electricity to distribution licensees :

Provided that if such hydro-generating station is not owned by the concerned distribution licensee who is taking the supply, then for entitlement to such additional return on equity there shall be a long term agreement of supply including a PPA covering a period of supply not less than 20 years :Provided also that for such hydro-generating stations regulation 5.6.1.3 shall not be applicable.

5.6.1.5- While computing return on equity for a generating company or a licensee, those equity capital against the tangible assets only shall be considered if such assets are duly recorded in the asset register and have been fully commissioned and are under operation. The equity for any intangible asset will be considered for computation of return on equity if such asset is duly recorded in the asset register and is in use. The equity for receiving any services will be considered for computation of return on equity if such services are actually received and intangible asset concerned for such services is duly recorded in the asset register.

5.6.1.6- In case, any asset of a licensee or a generating company remains inoperative for more than three months at a stretch, resulting in discontinuance of flow of electricity through or from such asset during that period, then the return on equity proportionate to such asset will be fifty percent for the period it remains inoperative and the share will be adjusted with the ARR during determination of ARR or after APR, as the case may be. Similarly, if any asset remains inoperative for a period exceeding six months at a stretch. then the return on equity proportionate to such asset will be nil for the period it remains inoperative and it will be adjusted with the ARR during determination of ARR or after APR, as the case may be.

Provided that tariff determination related to such asset is not done in accordance with availability based tariff determination mechanism :-Provided further that where the actual value of equity corresponding to such inoperative asset is not available and such asset is commissioned prior to coming into force of the Act, the Commission shall determine the deemed value of equity for such asset for tariff determination purposes as follows :

(a)For a generating station the value of equity of the inoperative unit of a generating station for tariff determination purpose only, shall be :-

Eunit = (Etot x lCunit)/∑lCunit x (0.9085)AunitWhere,Eunit = Deemed Equity of inoperative unit under consideration.Etot = Actual Equity against the concerned generating station.Aunit = Age difference of the latest unit and the concerned inoperative unit.lCunit = Installed capacity of the inoperative unit under consideration.∑lCunit = Summation of the installed capacity of the generating station i.e., total installed capacity of the concerned generating stations.

(b)For transmission or distribution system for inoperative transmission or distribution transformers or line, 15% of the value of a comparable asset at present day price level will be considered as the equity value of such inoperative transmission or distribution asset in relation to tariff determination purpose only.

(c)Where project cost of any asset is available, then instead of using the methodology under (a) or (b) above, 30% of such project cost or the ratio in % of actual equity, whichever is less, will be considered for tariff determination purpose only as equity of such project and the equity for inoperative portion will be determined in proportion to the effected installed rated capacity of such inoperative portions to installed rated capacity of the total asset for the purpose of tariff determination only.

(d)For the purpose of determination of age of any unit of a generating station, the available date of any period of synchronization or COD, whichever is later, will be applicable :

Provided also that where actual value of equity for any particular unit of a generating station is available, then the equity for such unit shall be taken on the basis of actual value and for the balance units of the generating station the methodology mentioned under (a) or (b) or (c) shall be applied prudently by considering the balance units of the generating station.

5.6.1.7- Return on equity shall be applicable to that portion of the equity only which is in use under the business operation for which gross aggregate revenue requirement is to be determined and not invested in any security or other business.

5.6.2Depreciation - For the purpose of tariff, depreciation shall be computed in the following manner :

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

(ii)The depreciation shall be calculated annually, based on straight line method at the rates prescribed in the Annexure - A to these regulations.

(iii)The residual value of assets shall be considered as 10% and depreciation shall be allowed up to maximum of 90% of the original cost of the Asset.

(iv)Freehold land is not a depreciable asset and its cost shall be excluded from the capital cost while computing 90% of the historical cost.

(v)The historical cost of the asset shall include additional capitalization.

(vi)Depreciation shall be chargeable from the first year of operation. In case of operation of the asset for part of the year, depreciation shall be charged on pro-rata basis.

(vii)Prudent accounting principles shall apply to the extent not inconsistent with these regulations.

(viii)In case any asset remains inoperative for more than three months continuously in a financial year, the depreciation related to such an asset shall be reduced on proportionate basis for the period it remains inoperative and such reduction shall be adjusted in due course and it will be adjusted with the ARR during determination of ARR or after APR, as the case may be.

Provided that tariff determination related to such asset is not done in accordance with the availability based tariff determination mechanism.Provided further that where actual book value of the asset corresponding to such inoperative asset is not available and such asset is commissioned prior to coming into force of the Act, the Commission will determine the deemed book value for such asset for tariff determination purposes in the following manner :-

(a)For generating station the deemed book value of asset of the inoperative unit of a generating unit for tariff determination purposes only, is

VAunit = (VAtotx lCunit∑/lCunit)x (0.9085)AunitWhere,VAunit Deemed Book Value of inoperative unit under consideration.VAtot Actual Book Value against total power stations concerned.Aunit Age difference of the latest unit and the concerned inoperative unit.ICunit Installed capacity of the inoperative unit under consideration.∑ICunit = Summation of the installed capacity of the generating station i.e. total installed capacity of the concerned generating station.

(b)For inoperative transmission or distribution transformers or line in any transmission or distribution system, 15% of price of a comparable asset in terms of vintage will be considered as deemed book value of such inoperative transmission or distribution asset for tariff determination purposes only :

(c)Where project cost of any asset is available but book value of such asset is not available then instead of methodology under (a) or (b), admissible project cost shall be considered as opening value of such gross fixed asset.

(d)For the purpose of determination of age of any unit of a generating station, the available date of any period of synchronization or COD, whichever is later, will be applicable.

Provided also that where actual value of asset for any particular unit of a generating station is available, then the asset for such unit shall be taken on the basis of actual value and for the balance units of the generating station the methodology depicted under (a) or (b) or (c) shall be applied prudently by considering the balance units of the generating station.

5.6.3Advance Against Depreciation. -

5.6.3.1- In addition to depreciation, the licensee shall be entitled to Advance Against Depreciation, which is the difference between the actual amount of loan repayment, subject to a ceiling specified in Regulations 5.5.2 and allowed depreciation as per schedule for such financial year along with reflection of accumulated depreciation in the book of accounts.

5.6.3.2- The licensee shall be permitted to recover amortization of intangible assets up to such level as may be approved by the Commission.

Explanation - for the purpose of this Regulation, the term "intangible assets" shall mean such pre-operative and promotional expenditure incurred in cash and shown as a debit in the capital account as has fairly arisen in promoting the core business and / or of embedded generation business and shall exclude any amount paid or otherwise accounted as goodwill.

5.6.4Financing cost : -

5.6.4.1- Financing costs will comprise of :-

(i)Interest on and charges relating to loan capital,

(ii)Interest on and charges relating to working capital.

5.6.4.2- Interest on and charges relating to loan capital will be allowed by the Commission as under :-

(i)The generating company or the licensee shall be allowed to recover the interest expenses on all borrowing towards capital works as per terms of such borrowing including the repayment schedule.

(ii)Interest on normative loan capital shall be allowed at weighted average rate of interest on borrowings coming under (i) above.

Provided that such normative capital loan as specified in regulation 5.4.2 is invested in creation of fixed asset to the concerned activity of electricity business of the licensee or generating company.

(iii)The generating company / licensee shall put in every effort to swap the existing loans as long as it results in net benefit to the consumers / beneficiaries after taking into consideration a!! the associated cost inclusive of prepayment of premium for such benefit analysis. The cost associated with such beneficial swapping shall be borne by the consumers / beneficiaries. The generating company / licensee shall not make any profit on account of swapping on loan and interest on loan, except to the extent provided in these regulations.

(iv)The Commission shall also allow all financing charges relating to loan capital viz. front-end fees, bank charges, commitment charges, foreign exchange rate variations in case of loan repayments, guarantee fees, etc.

(v)The interest on borrowings and any other charges thereon for specific capital works-in-progress will not be allowed in the revenue accounts and those need to be charged to the cost of such capital works in progress.

(vi)No interest during construction for any unit of a generating station shall be allowed to be capitalized for the period beyond the scheduled date of commercial operation (COD) as set out in the contract agreement of boiler and/or turbine-generator or the COD as per norms under Schedule-9C, whichever is earlier. However if Commission feels appropriate then it can allow additional capitalization that arises out of force majeure events or extenuating circumstances. No interest during construction for any unit of a generating station whose order for construction has been placed before 15.10.2007 shall be allowed to be capitalized for the period beyond the scheduled date of commercial operation (COD) as set out in the contract agreement of boiler and/or turbine-generator or the COD as per norms under Schedule-9C, whichever is later. For common assets covering more than one unit of the generating station, it will be considered on the basis of proportional allocation to the installed capacity of the unit concerned with reference to the total installed capacity of the project under consideration. Such interest during construction, which has been disallowed to be capitalized, shall also not be allowed to be recovered subsequently through tariff in any form.

Provided that if the Commission is satisfied that the time over run of any project was due to force majeure event including natural calamities or geological surprise in case of hydro generating stations or any reasons beyond the control of the licensee or generating company, the Commission, at its discretion, may allow full or part of such interest to be capitalized.

5.6.5Interest on Working Capital. -

5.6.5.1- The working capital requirement shall be assessed on normative basis @ 18% on summation of annual fixed charge, fuel cost and power purchase cost reduced by the amount of depreciation, deferred revenue expenditure, return on equity and other non cash expenditures such as, the provision for bad-debt, reserve for unforeseen exigencies, special appropriation against any withheld amount of previous year, arrear on account of adjustment due to Annual Performance Review , FPPCA, etc. of a generating company or a licensee, as the case may be. If there is recovery through Monthly Fuel Cost Adjustment or Monthly Variable Cost Adjustment then for working capital requirement the above normative basis shall be 10% instead of 18%.

5.6.5.2- Rate of interest on working capital so assessed on normative basis, shall be equal to the short-term prime lending rate of State Bank of India or adjusted base rate for short term lending as on the 1st April of the year preceding the year for which tariff is proposed to be determined or at the actual rate of borrowing whichever is less.

5.6.5.3- In addition to interest on working capital, the licensee shall be allowed interest on cash security deposit taken by it at the rate in terms of the regulations of the Commission on actual basis.

5.6.5.4- The Commission may allow, if considered necessary, interest on temporary financial accommodation taken by the generating company / licensee from any source to a reasonable extent of unrealized arrears from the consumers / beneficiaries.

5.6.6- For any licensee or a generating company where rental or lease rental charge has been allowed on any of its assets, such asset shall be entitled to depreciation or advance against depreciation to an extent it is reduced by the amount of rental or lease rental charge from the computed depreciation or advance against depreciation in pursuance of these regulations, since the lease and rental charge will be considered separately under these regulations. In case the lease or rental charges is higher than the depreciation or advance against depreciation, such depreciation charge, shall be nil for the asset which is under lease or rental for the period as per the existing agreement of lease or rental. However, if the asset is acquired after the lease, the depreciation for the remaining period may be considered on the basis of book value of the asset as per accounting standard on the date of such acquisition.

5.7Operation and Maintenance Expenses. -

5.7.1- Operation and Maintenance or O & M expenses include the following :

- Repair & Maintenance Expenses (R & M)- Administrative and General Expenses subject to the conditions that for generating station actual expenses may be reduced by Rent and Lease charges where it is required.

5.7.2- Administrative and General Expenses will also include the expenditure to be incurred on account of the following heads, viz.,

(i)Rent and lease charge for asset,

(ii)Legal charges:

(iii)Auditor's expenses, which include auditor's fees, auditor's expenses and payment to auditors in any other capacity or for any work which is necessary to be got done from them and audited.

(iv)Consultancy charges for work which cannot be done in-house or is uneconomical in doing in-house or is essential to be done from outside sources except payment to Auditors:

(v)Other expenses necessary and arising from and ancillary or incidental to the business of electricity except penalty etc. levied under this Act or any other Act;

5.7.3- The Commission shall accept Operation and Maintenance Expenditure subject to prudence check and other specific provision on this respect in these regulations.

5.8Fuel Cost Determination Principle. -

5.8.1- Determination of the Rate of Energy Charge (REC) for thermal generating stations, as well as the projection of fuel cost shall be based on the following considerations :

(i)Useful Heat Value of coal / lignite or gas or liquid fuel based on weighted average of actual amount of fuel consumed annually or to be consumed for the year under consideration. In case of coal for each notified grade, the Commission will take the weighted average of UHV of received coal of that grade as per the last available audited data of the generating company or the licensee, as the case may be, for the purpose of REC or Variable Charge computation during tariff determination stage. However, in order to increase coal procurement efficiency, the UHV considered in tariff determination will not be less than "X" Kilo Calorie / Kilogram.

Where,X = {∑(UHVgm x CLWT g)}/∑CLWT gWhere;UNVgm = Minimum UHV of each notified grade of coal.CLWT g = Corresponding weight of coal actually consumed or to be consumed annually for the year under consideration for the each notified grade.For FPPCA the actual UHV as per audited report will be considered but generally it shall not be less than 'X' Kilo Calorie/ Kilogram as defined above.However, the Commission may allow lesser UHV in certain case if the generating company or licensee is able to prove through document that inspite of its sincere efforts, it is not possible to receive coal of higher UHV in the same grade.

(ii)During tariff determination, the price of each type of fuel for the base year shall be as per the latest declared price of such fuel received from the tariff applicant or from the declared price list of the coal company, subject to modification by the Commission to the extent as decided from the conditions, if any, in fuel purchase agreement between coal company and the licensee or generating company in case of any price revision by the coal supplier after submission of tariff application and if Commission desires so. For the ensuing year the fuel price will be considered after due adjustment on the basis of Compounded Annual Growth Rate in the period covering previous years and base year, subject to application of prudence check wherever required. However, during FPPCA calculation, actual price of fuel will be considered.

(iii)In case where coal price from indigenous source is not on the basis of any notified grade as prevalent for determination of administered price for Coal India Limited (CIL) and its subsidiaries, then maximum admissible price will be arrived at after prudence check on the basis of administered price per heat value for coal of same geographical area of supply from. CIL and its subsidiaries. Maximum admissible price per unit of UHV will be computed as follows :

Pind = (P admin/UHVi) x 1000Where,Pind = Maximum admissible price per UHV of coal from said indigenous sources in Rs./Gcal.P admin = Administered price of coal in Rs./Ton supplied from same geographical area for CIL & subsidiaries corresponding to the notified grade of CIL coal to which UHV of the said indigenous coal belongs.UHVi = UHV of Coal in Kcal/Kg for the i th year to be determined in the following manner :

2007.

-08 UHV1 = L + 0.25 x BW

2008.

-09 UHV2 = L + 0.30 x BW

2009.

-10 UHV3 = L + 0.35 x BW

2010.

-11 UHV4 = L + 0.40 x BW

2011.

-12 UHV5 = L + 0.45 x BW

2012.

-13 UHV6 = L + 0.50 x BWUHV from year 7 onwards, i.e., from 2013-14 shall be equal to UHV6.Where,L = Declared minimum UHV of that notified grade of coal to which UHV from such indigenous source corresponds.BW = Difference between declared maximum UHV and declared minimum UHV of notified grade of coal from the same geographical area for CIL and its subsidiaries.Gcal = 109 x 1 Calorie(iv)Transportation of coal and other charges related to fuel procurement shall be as per the latest declared charges received from the tariff applicant or from the declared price list of the relevant sources providing such transportation and other auxiliary services.(v)During tariff determination, fuel mix of different type of fuel or among different quality of same type of fuel shall be considered as per mixing proportion of last one year, subject to specific deviation, if any, as proposed by the licensee or generating company with proper supporting document and also subject to prudence check.However, during FPPCA calculation, in case where applicant cannot provide actual data of different fuel, fuel mix of different type of fuel or among different quality of same type of fuel, it shall be considered as per mixing proportion of the fuel received in the year for which FPPCA is under calculation.(vi)Demurrage charge of railway rake, being commercial terms and conditions of freight, is also an indicator of efficiency of rake unloading capability of the generating stations. For existing power stations, allowance for the demurrage will gradually be reduced to a target in phased manner within a stipulated period as per regulation 2.8.6 as and when provided under. For new power stations or extension of existing power station commissioned after publication of these regulations it will be zero unless free time provided by railway is reduced by more than 20% from the existing value.(vii)At tariff determination stage, the incidental charges of fuel such as sizing charges, transportation charges to the loading point (not railway freight), underloading/overloading charges, crushing charges and other incidental charges, if any and related taxes and duties shall only be considered on the basis of actual annual average expenses against each unit of fuel for each item related to such supply from each source as will be provided in Form D (2) and Form D (3). However, for FPPCA, it shall be considered on actual basis on the quantum of fuel that has been allowed by the Commission.(viii)In case the price of coal from any indigenous captive coal mine of any licensee or generating company is determined by any statutory body or through any government order, such price will be applicable and in that case the methodology of price determination under clause (iii) will not be applicable.5.8.2- The sourcing of coal besides linkage based allocation policy of the Government of India, such as through e-auction or any other means of auction or any other mechanism from indigenous source shall be allowed by the Commission for consideration of that price for fuel cost determination purpose subject to satisfaction of any of the following conditions.(a)Coal price is less than the administered coal price of same grade available through linkage based allocated coal.(b)It can be established that procurement of such coal will be ultimately beneficial to the consumers of the State and for that purpose prior in principle clearance is obtained from the Commission.(c)In power shortage scenario procurement of coal through such mechanism does not increase the fuel cost, as approved in ARR, by more than 10% provided that allocation of coal through linkage from concerned Ministry of Government of India is not sufficient to harness the total potentiality of available generation capacity and there is sufficient evidence of power shortage which is required to be submitted while claiming such coal price.5.8.3- Any generating company or licensee can procure coal from any other source at a price within the price discovered through e-auction mechanism of Coal India Limited or its subsidiaries or any government company or government/ statutory authority on the date of procurement subject to satisfaction of any of the three conditions as specified in regulation 5.8.2 of these regulations.5.8.4- Any generating company or licensee can procure coal from any source through negotiation for firm supply from dedicated source at a price within the ceiling of the average price discovered through e-auction of Coal India Limited or any government company or government/ statutory authority in the last one year preceding to the year when agreement took place subject to satisfaction of any of the three conditions as specified in regulation 5.8.2 of these regulations.Provided that if such negotiated price exceeds the above specified ceiling then the generating company or licensee shall take prior approval of the Commission through submission of an application justifying its requirement.5.8.5- In case of sourcing coal from overseas through competitive bidding based procurement in a transparent manner, the Commission will adopt the price of such coal subject to prudence check by the Commission and subject to satisfaction of the Commission regarding ensuring of competitiveness in the bidding process and also subject to proof that there is either shortage in required quantity of coal of the desired quality in the country or such procurement will ensure ultimate lower tariff to the consumers of the State.5.8.6- In case of sourcing coal from own coal mines in overseas foreign country, the generating company or licensee shall submit all relevant information in support of the price of the coal inclusive of copies of different deals, agreement, freight, expenditure under different heads etc. On the basis of such documents and available international price on the basis of competitive bidding or available from international market mechanism, the Commission will decide the procurement price of the coal for the purpose of tariff determination under the Act.5.8.7- Notwithstanding anything to the contrary contained elsewhere in these regulations if the price of coal sourcing from foreign country is determined under any regulatory mechanism of that country, then the Commission will adopt such price as a basis for arriving at the landed cost of such coal for tariff determination.5.8.8- In case of any increase in price of fuel or railway freight or taxes/ duties / royalty/ cess on fuel at any time after issue of a tariff order for a year or due to sourcing of coal in terms of regulations 5.8.2 to 5,8.7 in larger quantity than that admitted in the tariff order or due to enhancement in power purchase cost for any justified reason whatsoever, the Commission may in order to reduce tariff rise in future due to accumulation of such entitled expenditure, allow provisionally on the basis of a Fuel Surcharge Formula termed as FPPCA in Schedule - 7A in pursuance to Section 62(4) of the Act an adhoc fuel cost or adhoc power purchase cost or adhoc variable cost as the case may be either suo-moto or on the basis of an application filed by a generating company or a licensee subject to reconciliation of such charges on receiving application for determination of FPPCA for that year. Adhoc variable cost will be applicable when there is increase in both fuel and power purchase cost for a licensee. While determining adhoc fuel cost or adhoc power purchase cost or adhoc variable cost, the fuel surcharge formula termed as FPPCA in Schedule-7A shall be used to determine the enhanced cost on account of fuel and power purchase cost. However while using such fuel surcharge formula termed as FPPCA in Schedule - 7A instead of actual expenses incurred on fuel and power purchase cost, the estimated fuel and power purchase cost for the year shall be computed on the basis of following :(a)The actual latest price of fuel or power purchase cost as far as available for the ensuing year when application for such adhoc fuel cost or adhoc power purchase cost or adhoc variable cost is being made.(b)The energy volume and mix as admitted in the ARR calculation for the concerned ensuing year in the tariff order of the first ensuing year of the concerned control period or the tariff order of that ensuing year, whichever is the latest order.(c)The normative parameters and principles and methodology of computation as considered during ARR determination of the ensuing year concerned along with consideration of Cd and A as nil value for applicability of the fuel surcharge formula termed as FPPCA in Schedule - 7A.(d)In case of non-availability of information for any ensuing year as per (b) and (c) above, for any reason whatsoever, the available information of such requirement as per any latest tariff order of the Commission on the licensees or generating company shall be used.5.8.9- From the 1st April 2011 and onwards Monthly Variable Cost Adjustment (MVCA) shall be recoverable on monthly sale by the licensee from its consumer and purchaser of electricity under the purview of the Commission through applying a Fuel Surcharge Formula for this purpose only as provided in paragraph A of Schedule - 7B in pursuance to Section 62(4) of the Act.Similarly from the 1st April 2011 and onwards Monthly Fuel Cost Adjustment (MFCA) shall be recoverable on the monthly energy sale by the generating company from the purchaser of electricity under the purview of the Commission through applying a Fuel Surcharge formula for this purpose only as provided in paragraph B of Schedule - 7B in pursuance to Section 62(4) of the Act.The licensee or generating company will apply the above Fuel Surcharge Formula of Schedule - 7B directly by them to determine the applicable MVCA or MFCA for recovery from the consumer or purchaser of electricity under the purview of the Commission through their electricity bill subject to annual reconciliation during determination of APR and/or FPPCA as per Schedule - 7A to be done by the Commission.The applicable MVCA or MFCA shall be displayed in the website of the licensee or generating company and such website shall maintain the applicable MVCA or MFCA for last 24 months at any instant of time. Whenever there will be change in MVCA or MFCA the licensee or generating company shall publish such information through two daily newspapers in the area of operation of the license or generating company. While calculating MVCA or MFCA for each month, the licensee or generating company shall prepare a complete work sheet showing the computation of applicable MVCA or MFCA along with the basis of data and supporting documents. Such work sheet shall be prepared by the licensee or generating company so that whenever called for it, it can be submitted to the Commission for verification by the Commission. However, for April '11, May '11 and June '11 such worksheets shall be submitted immediately after the MVCA and MFCA is implemented so that at the initial stage of operationalization of MVCA or MFCA proper regulatory oversight can be applied to streamline the preparation of the details of the worksheet according to which such worksheets are to be maintained in future. Moreover, the copy of monthly worksheet for MVCA and MFCA of each month shall be submitted with application of the FPPCA of that ensuing year for which FPPCA application is being submitted.5.8.10- The applicable MVCA or MFCA shall be computed on the basis of fuel and power purchase cost or fuel cost, as the case may be, of the preceding month of the month for which electricity bills are to be issued.Provided that if the tariff order of any ensuing year is issued after April of any ensuing year then till such tariff order is issued MVCA and MFCA will be computed on the basis of paragraph (d) of the note under paragraph (A) and (B) of Schedule-7B.5.8.11- In case any supplementary bill on power purchase cost or fuel cost of previous year is received such bill shall normally be considered for FPPCA of the concerned ensuing year. However if the order on FPPCA of that ensuing year is already issued by the Commission then such supplementary bill may be considered under the application of FPPCA for any future ensuing year but it shall not be provided in the MVCA or MFCA computation.5.8.12- On the basis of any application or suo-moto Commission may issue order from time to time on MVCA and MFCA for providing any clarification or removal of any difficulties or any other matter as deemed fit by the Commission and such order shall be displayed in the website of the Commission and the licensee and generating company.5.8.13- The recovery against MVCA or MFCA along with the tariff and any Adhoc Power Purchase Cost Adjustment, Adhoc Variable Cost Adjustment or Adhoc Fuel Cost Adjustment will be subject to reconciliation against Admitted Fixed Cost and Variable Cost in APR and FPPCA of the concerned year.5.8.14- Within 21 days from the date on which these regulations will come into force the generating company and distribution licensees under the purview of the Commission shall publish a notice as approved by the Commission regarding introduction of MVCA or MFCA as applicable, such notice shall be published in the website of the licensee and also in at least 4 (four) daily newspapers widely circulated in the area of operations of the applicant, at least 1 (one) each of such newspapers being in Bengali and English.

5.9Employees Cost. -

5.9.1- Employees cost shall also include the share of expenses on account of salaries and wages and staff welfare including Directors remuneration, fees, expenses and other facilities and salaries and wages of corporate office / registered office and shall be shown separately. Employees Cost of own and contracted manpower in regular establishment shall be shown separately.

5.9.2- The cost for maintaining terminal benefit fund for the present and past liability shall be shown separately in a separate sub-head. Such cost will be allowed to the extent it satisfies the following conditions :

(i)The fund is created under any statutory obligation or under any contractual obligation that has got prior approval from the Commission before the contract has taken place or any contractual obligation that has been already admitted by the Commission;

(ii)The fund is audited up-to-date as per the law of the country applicable to the licensee or generating company;

(iii)The cost is not passed through the past tariff at any instant of time. An audited certification in this respect is to be submitted and also this is subject to prudence check by the Commission.

5.9.3- The licensee or generating company shall provide the break up of employee cost in Form 1.17(h) in Annexure-1.

5.9.4- The licensee or generating company shall provide the break up of arrear payment in Form 1.17(i) in Annexure-1 arising out of any wage revision and the period for such arrear is to be mentioned clearly. In case of any wage revision, the licensee or generating company shall also submit the concerned agreement and official order along with the approval of the Board of the generating company or licensee on such wage revision.

5.9.5- Performance incentive based on efficiency of operating parameters of the generating company or licensee which is applicable to the employee, if any, must be shown in a separate head in annual accounts and cannot be included under employee cost or any other head. However, the Commission will not allow such cost for production incentive payment to be recovered through tariff except those components of wage which ensures attendance and compliance with job norms of the employees. If required, a special note is to be inserted in the annual accounts or a certificate from the same auditor who has audited the annual accounts has to be furnished to show separately the expenses on head of performance or production incentive.

5.9.6- The licensee or generating company shall provide the information under regulation 5.9.3 and 5.9.4 for regular employees and contracted manpower in regular establishment separately.

5.9.7- Interest payment to Contributory Provident Fund, General Provident Fund or any statutory retirement benefit fund shall not be considered unless it is explicitly established that inspite of investment of such fund in timely manner there is shortfall in accrued interest to discharge the liability of statutory interest as laid down in concerned laws or there is provision of special dispensation under Section 131 of the Electricity Act 2003.

5.10Bad and Doubtful Debt. -

5.10.1- The Commission may allow such amount of bad debts as actually had been written off in the latest available audited accounts of the generating companies / licensees subject to a ceiling of 0.5% of the annual gross sale value of power at the end of the current year.

Provided that in case of restructuring or merger of entities, the Commission may relax the ceiling for once only as deemed fit and proper.

5.11Reserve for Unforeseen Exigencies. -

5.11.1- The generating companies and the licensees may provide and maintain a reserve for dealing with unforeseen exigencies up to 0.25% of the value of gross fixed assets at the beginning of the year annually and the provision made for the year will be allowed in their Aggregate Revenue Requirement subject to an overall ceiling of 5% of the value of gross fixed assets at the beginning of the year. The existing amount of contingency reserve in the books of accounts of the generating companies / licensees, if any, will be considered while arriving at the overall ceiling as stated herein.

5.11.2- For failure to comply with the provisions of the regulation 5.11.1 and 5.24.1, double the amount allowed under the head reserve for unforeseen exigencies in any tariff order of a year shall be withheld from the re-determined ARR during APR of any year.

5.12Foreign Exchange Rate Variation. -

5.12.1- In case of Foreign Exchange Rate Variation (FERV), the resultant payment due to FERV arising on account of interest payment and repayments of loan, at actual as per loan term, shall be considered subject to regulations 5.12.2 and 5.12.3.

5.12.2- Extra rupee liability towards interest payment and loan repayment corresponding to the actual foreign debt in the relevant year shall be, permissible provided the entire rupee liability directly arises out of foreign exchange rate variation and is not attributable to the generating company / licensee or their suppliers or contractors.

5.12.3- Generating companies / licencees shall be allowed reasonable cost of hedging subject to a ceiling of 1 % of the foreign exchange component to take care of foreign exchange rate variation if it is found beneficial to consumers.

5.13Income Tax. -

5.13.1- Fringe benefit tax, banking cash transaction tax, any other direct tax and tax on income stream of the generating company or the Transmission licensee or the Distribution licensee as the case may be from Core / Licensed business shall be computed as expenses and shall be recovered as pass through from the consumers / beneficiaries. Such taxes of any year shall be passed through tariff subject to submission of assessment order of the concerned year or other valid documents including applicable Auditor's certificate for payment of tax along with the APR or tariff order of any subsequent year. However the amount of minimum alternate tax and self-assessed income tax as deposited for the concerned year will be allowed without the assessment order.

5.13.2- 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 the Income Tax Act 1961 as certified by the Statutory Auditors.

Provided that tax on income from business other than the Core / licensed business shall not constitute a pass through component in tariff and the tax on such income shall be borne by the generating company or the licensee as the case may be.The benefits of any income-tax holiday, credit for unabsorbed losses or unabsorbed depreciation shall be taken into account in calculation of the income-tax liability of the generating station of the generating company or of the licensed business;Provided also that where such benefits cannot be directly attributed to a generating station, they shall be allocated across the generating stations of a generating company in the proportion of the generating station-wise profit before tax.

5.13.3- In case any tax paid against income/ services under other sources or non-tariff income which are considered in ARR, such taxes will also be passed through tariff.

5.14Inclusion in Tariff. -

5.14.1- The licensee and generating company shall be entitled to take into account any statutory fee or charge paid by it under these regulations as expenses in the determination of tariff.

Provided that the expenditure against any statutory provision such as taxes, duties. cess etc. shall only be passed through APR on submission of assessment order or any valid document mentioning the reasons of such payment.

5.14.2- Any expenditure arising out of contravention or non-compliance of any statutory provision under any Act or rules or regulations or non-compliance of any order of judicial body or statutory body shall not be allowed to be passed through tariff and for that purpose, the licensee or the generating company shall specifically mention such expenditure in Form 1.17(j) in Annexure-1 of these regulations along with the relevant order of the authority :

Provided that while submitting application for APR. the licensee or generating company shall submit the details along with the documents of the concerned authorities for any payment made under the head as mentioned under the regulation 2.2,7 and in case no such payment has been made in the concerned year, the applicant has to give a clear declaration for such non-payment in that year in Form 1.17(j) in Annexure-1 of these regulations.

5.14.3- Insurance shall be treated as a separate head for consideration under ARR determination and will be allowed by the Commission if such insurance is done through a transparent process.

5.14.4- The Commission may withhold any amount for non-compliance of its directives or non-submission of information properly as sought for in the regulations.

5.15The principles of sharing of gains or losses between the Generating Companies / licensees and the Consumers:

5.15.1On Capital Account -

(i)Savings in interest during construction on early completion of the project, use of efficient technology, improved financing plan and such other matters - Such savings may be shared equally between the generating companies / licensees and the consumers after a suitable time lag if the Commission so directs. However, in case of delay due to the factors not controllable by generating companies or licensees then the Commission on the merit of the case may approve the additional interest costs attributable to such delay. Otherwise, if Commission disapproves, the additional cost is to be borne by the generating companies or licensees.

(ii)Incentive for completion of hydro-generating stations ahead of schedule In case of commissioning of a hydro-generating station or part thereof ahead of schedule, the Generating Companies or licensees shall become eligible for incentive for an amount equal to pro rata reduction in interest during construction, achieved on commissioning ahead of the schedule. The incentive shall be recovered through tariff in twelve equal monthly instalments during the first year of operation of the Generating station. In case of delay in commissioning, interest during construction for the period of delay shall not be allowed to be capitalized for determination of tariff, unless the delay is on account of natural calamities or geological surprises.

(iii)Any one-time proceeds accruing to the licensee or generating company from carbon trading or green-house emissions reduction programme or environmental pollution reduction programme and which is being invested in creation of new asset in electricity business of the said company or licensee, will be treated as equity invested by the generating company or the licensee itself and ROE as per this regulation shall be applicable to the licensee or generating company, but the said investment amount will be deducted from project cost during computation of depreciation for tariff determination.

(iv)Any one time proceeds accruing to the licensee or generating company from sale of its assets and invested in creation of new asset in electricity business of the company, or licensee, will be treated as equity invested by the generating company or licensee itself and book value of the asset sold will be deducted from the asset valuation. ROE on such equity shall be applicable to the licensee or generating company, but the said investment will be deducted from project cost during computation of depreciation for tariff determination.

(v)Any benefit out of swapping of foreign debt and equity during construction period of a project shall be used totally to reduce the project cost.

5.15.2On Revenue Account -

(i)Savings arising out of swapping of foreign debt and equity - The Commission will allow such swapping only if it proves to be beneficial in terms of cost and the benefits are to be equally shared between the consumers and the power selling licensee as also between power purchasing licensee and generating company or power selling licensee. as the case may be. However, the related cost will also be allowed as an allowable expenditure in determination of tariff.

(ii)Savings arising out of restructuring of capital cost in terms of debt equity ratio during the tariff period - The resultant saving shall be shared between the consumers and the power-selling licensee as also between power purchasing licensee and generating company or power selling licensee, as the case may be, in the ratio of 3 1.

(iii)For better performance than the operating parameters, benefit of gain-sharing will be provided in accordance with the provisions of Schedule 9B between the generating company/distribution licensee and purchaser of electricity for whom tariff/ price of electricity is determined under these regulations.

(iv)Sharing of benefit from selling of power to those other than licensee or any consumer:- Income from selling of power to those other than licensee or any consumer reduced by expenses relating to such activity shall be shared equally between the consumers and the power selling licensee as also between power purchasing licensee and generating company or power selling licensee, as the case may be, within 2015-16 to protect the consumer's interest and encourage optimum investments. In the intervening period, the sharing and utilization of such profit will be decided upon by the Commission, starting in the first control period from retention at a level already approved for the base year of the first control period. However, in case of loss from such activity, such loss shall not be allowed to be adjusted against aggregate revenue requirement.

(v)Sharing of benefit from carbon trading:- Any income by licensee or generating company from carbon trading or greenhouse emissions reduction programme or environmental pollution reduction programme, reduced by expenses relating to such activity, shall be used partially for the benefit of the consumer and licensee purchasing power from them by utilizing 30% of such income to reduce the ARR. However, in case of loss from such trading or programme, such loss shall not be allowed to be adjusted against aggregate revenue requirement.

(vi)Sharing of benefit from income arising to a generating company from supplying power to any person other than a distribution licensee:- Forty percent of the income arising to the generating company for supplying surplus powers to any person other than any distribution licensee shall be utilized after reducing the income by actual cost of fuel for such related generation in case such actual cost of fuel is more than the normative cost of fuel, otherwise by the normative cost, in order to reduce the aggregate revenue requirement related to supply of electricity to

(a)consumers of such distribution licensee(s) purchasing from the said generating company; or

(b)distribution licensee purchasing power from such distribution licensee(s) as mentioned in (a)

Provided the balance 60% is used for investment in electricity business primarily for supplying electricity in West Bengal and in case of investment in generating stations, such station shall supply more than 50% of generated energy within West Bengal to any consumer or licensee under the purview of WBERC.However, in case of loss arising out of such activity, such loss shall not be allowed to be recovered against annual revenue requirement for determination of tariff and / or for sale to the distribution licensee under the purview of WBERC.

(vii)Sharing of income from Auxiliary Services- Where the distribution licensee has derived any extra means of income from auxiliary sendees then an amount equal to 40% of the revenue from such other services after deducting the direct and indirect costs attributed to such auxiliary services shall be deducted from the gross aggregate revenue requirement in calculating the revenue requirement for distribution licensee.

(viii)In respect of the period prior to 31.03.2008, the sharing of any gain out of such income as mentioned in clauses (i) to (vii) during such period shall not be recovered, if such gain is invested by the licensee or the generating company for its business.

(ix)Notwithstanding anything to the contrary contained in clauses (i) to (vii), the Commission may at its discretion in order to avoid future irregular variation in tariff, direct a generating company or a licensee to create a fund to be known as Power Purchaser Fund and credit any or full share of the consumers/power purchaser arising out of any provision contained in clause (i) to (viii) or part thereof to that Power Purchaser Fund. The amount in the Power Purchaser Fund shall be considered as regulatory liability and may be used to control increase in tariff in future.

5.16Incentive :. -

5.16.1- The amount of generation of a thermal generating station used to offset the lower performance of any other generating station as per regulation 2.8.6.7 of these regulations shall not be entitled for consideration of the incentive as per paragraph 1 of Schedule-10.

5.16.2Incentive for energy saving due to demand side management including energy conservation initiatives on demand side - The expenses avoided arising out on energy saving by licensee from demand side management including energy conservation initiatives at demand side programme as approved by the Commission, reduced by expenses relating to such activity, shall be considered as incentive to the licensee in the first year after total completion of such project. From second year onward such incentive will be reduced by 10% for each year till such incentive become nil.

Incentive achieved in such manner shall be in addition to the ARR and shall be passed through any tariff order or APR order.

5.17Income from Unscheduled Interchange(UI) Charges: -

5.17.1- For a generating station of a generating company or a distribution licensee UI charges receivables on actual basis for any previous year or base year or ensuing year shall be considered as income for the period of the previous year or the base year or the ensuing year concerned. Similarly the UI payable on actual basis for any previous year or base year or ensuing year shall be considered as expenditure for the period of the previous year or the base year or the ensuing year concerned.

5.17.2- A generating company shall be allowed to retain the net receivable UI charges for a base year or an ensuing year However for a base year or an ensuing year for a generating company if there is net payable then that shall not be considered as expenses for determination of ARR.

5.17.3- For a distribution licensee the net receivable UI charges for a previous year or base year or an ensuing year, as the case may be, shall be shared equally between the consumers and the distribution licensee from the fourth control period, in the intervening period the extent of such sharing shall be as may be decided by the Commission.

5.18Annual Fixed Charges or Fixed Cost. -

5.18.1- The Annual fixed charges consist of Return on equity, Depreciation, Advance Against Depreciation, Financing Cost, Interest on Working Capital, Operation and Maintenance Expenses, metering charges, Employee Cost, Bad and Doubtful Debt, Reserve for Unforeseen Exigencies, Foreign Exchange Rate Variation, Income Tax, other taxes, water cess, duties, amortization of intangible assets and insurances. The list is illustrative but not exhaustive.

5.19Development Fund. -

5.19.1- The Commission, at its discretion, may allow a generating company or a licensee to make a provision in its annual revenue requirement, not exceeding 5% of its annual fixed charge, for development of its infrastructure directly related to equipment for generating stations or for transmission network or for distribution network for supply of electricity to the licensees or consumers, as the case may be, and to recover the same through tariff.

5.19.2- The amount so allowed for recovery through tariff under regulation 5.19.1 shall be kept in a fund to be known as Development Fund to be created by the generating company or licensees, as the case may be, and utilised exclusively for the purposes mentioned in regulation 5.19.1 of these regulations.

5.19.3- The assets created from the Development Fund shall be maintained under a separate asset register with proper book value under prudent accounting practice along with unique codification of each asset separately.

5.19.4- Accounts of the Development Fund shall be maintained separately, audited by certified Auditor and the Audit Report shall be submitted to the Commission every year.

5.19.5- For the assets created through such "development fund" no return on equity shall be allowed but interest at a rate 2% less than the rate of interest allowed on working capital shall be allowed and the same shall be deposited in the development fund for reinvestment.

5.19.6- The depreciation on such assets created through such Development Fund shall be deposited in the Development Fund for reinvestment.

5.20Income from Other Sources / Non-tariff income. -

5.20.1- Income from other sources or non-tariff income shall be shown against each type of income separately and it shall be clearly mentioned in books of account for each type separately and distinctly.

5.20.2- Income from other sources or non-tariff income shall be allocated to that part of electricity business of a licensee or generating company under which such income has taken place.

Provided that where such segregation is not possible then it will be allocated in proportion to gross aggregate revenue requirement for each part of electricity business.

5.21Research and Development Expenditure. -

5.21.1- The Commission may allow a licensee or a generating company an expenditure on account of Research & Development up to 0.10% of the ARR of the preceding year for the year for which ARR is determined.

5.21.2- Such expenditure on Research & Development will be allowed only when there is prior project-wise approval from the Commission or where the Commission has directed to undertake any such project.

5.21.3- Such project(s), if approved or directed by the Commission, shall be conducted through own in-house resource or through recognized Research Institute(s) under Government of India or State Government or any reputed academic institution or through any reputed consultant provided the selection of the consultant has been done through competitive bidding.

5.21.4- The asset created through such expenditure shall be considered as an asset created through consumer contribution and thus will not be entitled to Return on Equity.

5.22Cost of Outsourcing. -

5.22.1- The licensee or generating company shall show the cost of outsourcing on the following activity separately in a Form 1.17(k) in Annexure-I against each activity of electricity business as shown below :

(i)Generation activity generating station wise.

(ii)Distribution activity.

(iii)Transmission activity.

(iv)Electricity trading activity.

(v)Others, if any, (to be stated clearly).

5.22.2- Against each activity of electricity business as specified in regulation 5.22.1 the outsourcing expenditure is to be shown on different heads distinctly in Form 1.17(k) in Annexure-I which shall also include the following heads :

(a)Repair & maintenance along with details on heads of spares, consumables, services, manpower.

(b)Service (such as security, call centre, office transportation, courier service etc.)

(c)Operational service

(d)Management service

(e)Others, if any, (to be stated clearly).

5.22.3- While showing the cost of outsourcing for the first year the licensee or generating company shall specifically mention the head of account under which such expenditure was previously included along with the actual expenditure on such head for the last three years. On the basis of such information, the Commission shall adjust the requirement of revenue of each element of ARR, irrespective of controllable item or non-controllable item, in APR or tariff order of the year for which outsourcing cost(s) are determined separately.

5.22.4- If any outsourcing is introduced for a new activity, the licensee or generating company, as the case may be, shall mention it clearly. If such activity is in replacement of any existing activity done by its own resource, then it shall also be made clear along with detailing of utilization of such resource in the changed circumstances due to outsourcing. The annual expenditure against such replaced resource for the last three years shall also be made available along with the accounts head under which such expenditure was booked.

5.22.5- Cost of outsourcing shall be considered for ARR determination prospectively subject to prudence check by the Commission.

5.23Insurance Premium. -

5.23.1- Insurance Premium paid by a generating company or licensee after selection of the insurance company through a transparent process shall be adopted by the Commission subject to prudence check for items covered under such insurance only.

5.24.2Investment and other conditions of Reserves and Funds. -

5.24.1- The sum appropriated to the Reserve for Unforeseen Exigencies, Development Fund and Power Purchaser Fund shall be invested separately against each such head prudently in securities authorised under the Indian Trusts Act, 1882 (2 of 1882) or in any financial instruments of Nationalized bank, keeping the risk, rate of return and liquidity factors in view within a period of six months of the close of the year of accounts for which such appropriation is allowed. Such investment will be done in a manner so that about 50% of such investment shall be in long term instruments and balance in short term deposits excluding those specific amounts against which the Commission has issued any specific direction.

5.24.2- The interest accrued from such investment shall be reinvested under the Same reserve / fund or placed under Development I Power Purchaser Fund as may be decided by the Commission in tariff order or order of APR.

5.24.3- The reinvestment from interest shall be maintained separately under separate head and it shall not be treated under any ceiling as specified in regulation 5.11.1 or regulation 5.19.1 of these regulations.

5.24.4- To decide the mode of use of accrued interest, prior approval of the Commission may be taken annually through application of tariff or APR preceding the year in which such interest accrues.

5.24.5- Accrued interest after disbursement shall be invested within a month of receipt of the same unless invested on a cumulative basis.

5.24.6- The aforesaid reserve or fund shall be drawn upon only to meet such charges as the Commission may approve.

5.24.7- For facilitating distinct operation of the above funds and reserves the licensee or generating company shall open separate bank accounts under nationalized/scheduled banks for Power Purchaser Fund, Reserve for Unforeseen Exigencies and Development Fund. The licensee or generating company shall deposit the amount on the head of Reserve for Unforeseen Exigencies and Development Fund on monthly basis from the monthly revenue income in proportion to the amount of such head in the total revenue recoverable through tariff for the year concerned. Any adjustment from these two accounts for a year for over or under deposition shall be done within three months from the date of the issuance of the order of APR of the concerned year. In case of Power Purchaser Fund, the required amount is to be deposited within one month of the concerned order issued or any investment maturity or issue of specific direction from the Commission on any specific amount. All the transactions and investment / reinvestment of the fund or reserve shall be routed through this account only in accordance with these regulations, and specific order of the Commission.

5.24.8- The reserve for unforeseen exigencies or development fund can be utilized for the purpose of providing service directly or indirectly exclusively to the consumers of the State. Similarly, power purchaser fund can be utilized only to control the tariff of the consumers of the State directly or indirectly.

5.24.9- If any generating company create any asset from the development fund or reserve for unforeseen exigencies and subsequently such asset is not used to supply electricity to any licensee of the State due to discontinuance of any PPA then such generating company is required to refund part of such investment to the account of power purchaser fund of the concerned licensee by an amount equal to balance residual amount of depreciated value of such asset under discussion.

5.24.10- The generating company or licensee shall maintain separate accounts of the Power Purchaser Fund, Reserve for Unforeseen Exigencies and Development Fund. It is the duty of the generating company and licensee to get such accounts audited by a certified Auditor, and submit such audit report to the Commission every year.

5.25Treatment of Inoperative asset of Generating Station. -

5.25.1- Notwithstanding anything to the contrary contained anywhere else in these regulations where for a generating station fixed cost recovery is done on the basis of availability, then in case any asset of such generating station of a licensee or a generating company remains inoperative for more than three months due to breakdown or force majeure events resulting in less availability compared to respective normative target of availability for that generating station then shortfall of full capacity charge will be allowed to be recovered partly on the following heads only :-

(i)Employee Cost and interest on capital loan corresponding to such inoperative asset will be allowed while determining the ARR of the generating station or the licensee for recovery to the extent the Commission finds it necessary.

(ii)Depreciation and advance against depreciation corresponding to such inoperative asset will be allowed while, determining the ARR of the generating station or the licensee for recovery to the extent the Commission finds it necessary.

5.25.2- Notwithstanding anything to the contrary contained in these regulations in case any asset of a generating station of a licensee or a generating company, the tariff/ARR of which is not determined on the basis of availability, remains inoperative for more than three months due to breakdown or force majeure events resulting in less actual/ projected generation for generating station compared to respective normative target for that generating station then different element of ARR other than fuel cost corresponding to such inoperative assets will be determined in accordance with the following methodology :-

(i)Employee Cost and interest on capital loan corresponding to such inoperative asset will be allowed while determining the ARR of the generating station or the licensee.

(ii)The return on equity and depreciation shall be determined in pursuance of regulations 5.6.1 and 5.6.2.

(iii)In order to ensure payment of principal of loan only corresponding to such inoperative asset advance against depreciation shall be applicable as per regulation 5.6.3.

(iv)The elements of ARR for a generating station other than those mentioned in regulation 5.25.2(i), 5.25.2(ii) and 5.25.2(iii) of these regulations will be determined in proportion to the actual/ projected generation for such generating stations with respect to normative generation as applicable for that power station.

5.25.3- In case any asset of a generating station of a licensee or generating company, the tariff of which is not determined on the basis of availability, remains inoperative for less than three months the Commission may deduct certain amount but not higher than the amount as per principle laid down in regulation 5.25.2.

5.25.4- Where a part of the asset is required to be treated under this regulation 5.25 for which detailed cost data is not available then Commission can consider principal of proportionate ratio or any other principle by applying due prudence.

5.26Allocation of different elements of ARR - While any element of ARR is required to be allocated among distribution, transmission, generation and trading business of any licensees, then the Commission will follow the allocation in accordance with the following methodology.

5.26.1- The actual amount of expenditure or entitlement on different business as proposed by the licensee or generating company shall be subject to prudence check by the Commission.

5.26.2- Where the licensee or generating company applies for allocation procedure with any reasoning on any element of ARR, the Commission may accept it, if it is found reasonable.

5.26.3- Where the Commission does not agree to any allocation procedure by generating company or licensee or does not have the allocation from generating company or licensee, the Commission will allocate such element of ARR in accordance with any of the following methodologies.

(i)Equity and reserve for unforeseen exigencies on the basis of gross fixed asset,

(ii)Depreciation on the basis of net fixed asset.

(iii)Other elements of ARR on the basis of purpose of such element. For loan, loan repayment and interest, the purpose of the loan shall be mentioned clearly in order to allocate properly its impact on generation, distribution system, transmission system and trading activity separately. Where no such allocation is possible on the basis of purpose, then such allocation will take place on the basis of proportion to gross aggregate revenue requirement for each type of business.

(iv)Any method, other than (i) to (iii) above, found to be reasonable subject to mentioning of such specific reasons.

5.26.4- While adjusting through recovery or refund arising out of APR, such adjustment amount is to be allocated between different businesses of the licensee in accordance with the proportion of the net aggregate revenue determined under APR for each type of business.

5.26.5- While adjusting fuel cost of a generating station under FPPCA of a year with ARR of any subsequent year, such fuel cost adjustment shall be treated under such ARR requirement of such generating station only. Similarly the adjustment for power purchase cost determined in FPPCA of a year with ARR of any subsequent year for a licensee shall be done against distribution activity of such licensee.

Chapter - 6 Availability based tariff framework and approach

6.1Applicability of Availability Based Tariff Order:-

6.1.1- The generating stations of a generating company, will be presently under availability based tariff and also under UI mechanism as shown in Annexure-B. Capacity charge recovery for these generating stations of WBPDCL at present will be based on 100% allocation of the capacity to WBSEDCL till any other decision is taken by the State Government. Thus capacity charge recovery by WBPDCL shall be at present from WBSEDCL only.

The recovery of capacity charges based on availability shall also be applicable for thermal generating stations of those licensees who satisfy the conditions specified in the regulation 6.4.2 of these regulations and will be guided by regulation 6.4.2. The recovery of capacity charges based on availability will also be applicable for hydro generating stations of licensees for station size above 25 MW subject to the conditions laid down in regulation 6.4.2 of these regulations. Capacity charge recovery for the generating stations of any distribution license will be based on 100% allocation of the capacity to the distribution licensee itself which owns the generating stations. The requirement of capacity charge recovery for those generating stations by the distribution licensee shall be considered as integral part of the aggregate revenue requirement of the distribution licensee, the lone beneficiary of those generating stations, on the basis of the normative availability factor of those generating stations as specified in Schedule 9A but the contribution by their generating station in ARR of the distribution licensee will be determined by finding out the ARR required for such generating station in a similar fashion as is being done for a generating company.

6.1.2- As far as unscheduled interchanges (UI) and grid operation issues are concerned in these regulations, the entities concerned are -

(i)All generating stations of West Bengal Power Development Corporation Limited (WBPDCL), or any other generating company under the purview of the Commission and connected to the state grid;

(ii)All distribution licensees under the purview of the Commission and connected to state grid:

(iii)Electricity traders drawing or injecting power in the state grid;

(iv)Deemed licensee(s) under first, third, fourth and fifth proviso to section 14 of the Act with the embedded generation and being a part of state grid, if any, and all other entities including open access customer with open access load exceeding 1 MW connected with network of any licensee Cr person(s) exempted under section 13 or exempted under 8th proviso of section 14 of the Electricity Act, 2003.

Provided that the existing entities prior to having no communication facility with SLDC shall not be considered for unscheduled interchange mechanism.Provided also that in case of generation of electricity from renewable and co-generation source of energy, ABT and scheduled I mismatch UI charges shall be applicable to the extent as specified in the regulations of the Commission on co-generation and generation of electricity from renewable sources of energy

6.1.3- Such entities having no communication facility with SLDC shall ensure setting up the communication system with SLDC within one year from the date of publication of these regulations and shall come under purview of Unschedule Interchange.

6.2Tariff determination. -

6.2.1- Tariff in respect of a generating station under these regulations shall be determined stage-wise, unit-wise or for the whole generating station. The terms and conditions for determination of tariff for generating stations specified in these regulations shall apply in like manner to stages or units, as the case may be, as to generating stations.

6.2.2- Where the tariff is being determined for stage or unit of a generating station, the generating company shall adopt a reasonable basis for allocation of capital cost relating to common facilities and allocation of joint and common costs across all stages or units, as the case may be :

Provided that the generating company shall maintain an allocation statement providing the basis for allocation of such costs and submit such statement to the Commission along with the application for determination of tariff under these regulations.

6.2.3- In relation to multi-purpose project of hydro-generating stations, with irrigation, flood control and power components, the capital cost chargeable to the power component of the project inclusive of statutory obligations for the power components of such project, only shall be considered for determination of tariff.

6.3Power Purchase Agreement (PPA): - Any transaction for sale/ purchase of power among the entities under this multi-year tariff framework is to be done through PPA as detailed in Chapter - 7 of these regulations.

6.4Capacity Charges. -

6.4.1- Capacity charges for thermal generating stations or hydro-generating stations shall be computed as per paragraph 2.3 of Schedule - 1 of this regulation.

6.4.2- The recovery of capacity charges for all the generating stations of the licensees shall be against the normative availability and for ABT compliant generating station of generating company shall be against regulation 6.11 of these regulations for which the schedule of availability for all the 15 minutes time block shall be provided to the SLDC directly by each generating station of a generating company or by the ALDC in respect of a licensee's generating stations for recording and subsequent demonstration of their declared capacity as mentioned in regulation 6.7 of these regulations and for this purpose the licensees/generating companies shall also provide on-line monitoring display arrangement of generation/sent-out of the generating stations along with dedicated voice communication at SLDC to meet the need of regulation 6.7 of these regulations and also paragraph 2 and 5 of Schedule-10 of these regulations for incentives. For generating stations of licensee, the full capacity charge will be recovered at the targeted availability factor as per paragraph C of Schedule - 9A and for performance beyond the targeted availability factor it shall be entitled to no further capacity charge but will be entitled to incentive as per Paragraph - 1 of Schedule - 10 only. While submitting the availability schedule by the ALDC of any licensee for the generating stations of the licensee to the SLDC, ALDC shall also provide the schedule of injection by those generating stations. For subsequent revision in availability schedule and/ or injection schedule for such generating stations of the licensee, the ALDC of the licensee shall follow the methodology as applicable for generating stations of generating companies to submit such revised schedule to the SLDC.

Provided that capacity charge recovery of the generating stations, that have not yet been covered by on-line monitoring display arrangement at SLDC along with dedicated audio communication, shall be done on the basis of normative PLF meant for incentive purpose in paragraph B of Schedule - 9 A or as per Schedule - 9D of these regulations and such generating stations shall not be entitled to any incentive under paragraph 2 and 5 of Schedule - 10 of these regulations.

6.4.3- The availability affected only for the reason of shortage in coal availability from linkage source excluding own captive source shall be separately determined annually in a manner as may be specified in the Balancing and Settlement Code. Such affected quantity of availability shall then be compensated to the maximum extent possible through applying regulation 2.8.6.7. If there is still some quantity of resultant affected availability, derived by reducing the affected quantity of availability through compensation by applying regulation 2.8.6.7, then such resultant affected availability may also be considered to be used further to such extent as the Commission may decide but shall not exceed seventy five percent of the amount of said shortfall in total entitled capacity charge recovery arising out of resultant affected availability. In order to serve such purpose, the coal fired thermal generating stations shall declare capacity for both the situations as mentioned below.

(i)Actual Declared Capacity taking into consideration existing actual shortage in coal supply and this is to be known as declared capacity.

(ii)Notional Declared Capacity considering no shortage notionally in coal supply.

Provided that for the purpose of showing shortage in coal supply during the period of April to July and November to March of a year, the stock in the power plant shall be less than 2 days on the basis of average coal requirement per day and the claim of shortage will be verified by SLDC based on the coal stock related data provided by the generating station on the basis of submitted data as per regulation 6.4.4 of these regulations and daily coal consumptions and receipt to be provided in accordance with State Grid Code.Provided further that for the purpose of showing shortage in coal supply during the period of August to October of a year, the stock in the power plant shall be less than 4 days on the basis of average coal requirement per day and the claim of shortage will be verified by SLDC based on the coal stock related data provided by the generating station on the basis of submitted data as per regulation 6.4.4 of these regulations and daily coal consumptions and receipt to be provided in accordance with State Grid Code.Provided further that in case of any dispute, physical check by the beneficiaries in the presence of SLDC representative will be done in order to verify the stock position. In case of dispute SLDC's decision on coal-stock will be final for the purpose of capacity charge recovery.Provided further that recovery of the Capacity Charge arising out of shortage in coal supply from linkage source will be considered if it is found that the licensee/ generating company has explored all the possibilities of acquiring coal through e-auction or import to compensate such linkage shortage and for procurement of coal through such mechanism the rise in tariff or ARR does not exceed 5% of such value as approved it the last tariff order.Provided further that, if due to restriction in transportation of coal due to any reason beyond the control of the licensee or generating company, there is possibility of delayed supply in coal which requires lowering of generation so that minimum power supply requirement is to be maintained in the grid as required by the SLDC, then that affected amount of availability shall be considered in the overall achieved availability only to attain availability up to target availability in the year for capacity charge recovery subject to submission of a report on such incidence to the Commission within 3 working days of the incident and obtaining the approval from the Commission.Provided further that such part of capacity charge recovery for the portion of resultant affected availability as specified in this regulation shall be done for those coal-fired thermal generating stations, the tariff of which are determined on the basis of availability.Provided also that if after issuing the initial Actual Declared Capacity and Notional Declared Capacity for a day coal stock is increased beyond the stipulated level within the concerned day, then it is the responsibility of the generating station to revise the schedule of Actual Declared Capacity accordingly, failing which the Commission may take decision that may affect the capacity charge recovery for that generating station.

6.4.4- For the purpose of determination of average coal requirement per day, as required under regulation 6.4.3, the annual coal requirement in MT as determined under last tariff order and the number of days in that year shall be considered. In this matter carpet coal shall not be considered for determining 'Coal Stock' in the coal yard of the generating station. SLDC shall initially collect the carpet coal stock position and base stock at the starting of the year. For this purpose the generating station shall also provide the quantity of daily coal consumption and receipt to the SLDC.

6.4.5- Notwithstanding anything contained contrary to this regulation, the extent of resultant affected availability due to shortage in supply of coal as provided in regulation 6.4.3 and used for part of capacity charge recovery commensurate with the resultant affected availability shall not be entitled to earning any incentive.

6.5Unscheduled Interchange (UI) Charges : -

6.5.1- Variation of actual injection or actual drawal with scheduled injection or scheduled drawal respectively shall be accounted for through unscheduled interchange (UI) Charges. UI for a generating station or injecting entity shall be equal to its actual injection minus its scheduled injection. UI for a beneficiary or drawal entity shall be equal to its total actual drawal minus its total scheduled drawal. The quantum of unscheduled interchange shall be inclusive of applicable transmission loss and shall be borne by the entities, who will be liable for paying UI charges at that instant. UI shall be worked out for each 15-minute time block. Charges for all UI transactions shall be based on average frequency of the time block and the rates applicable are as per rate specified by Central Electricity Regulatory Commission. Accounting of UI in case of pumped storage hydroelectric generating stations both in generating and pumping mode shall be on net basis.

6.5.2- The applicable UI mechanism shall be subject to the following conditions :

(i)Any injection up to 105% of the declared capacity by any generating station including captive generating station in any 15 minutes time block and averaging up to 101% of the average declared injection schedule respectively over a day and also averaging up to 101% of the average declared injection schedule during peak period of a day shall not be construed as gaming and such generating station shall be entitled to UI charges for such excess generation above schedule generation.

(ii)For any generation beyond the stipulated limits, the SLDC shall investigate so as to ensure that there is no gaming, and if gaming is found by the SLDC, the corresponding UI charges due to the generating station on account of such extra generation shall be reduced to zero and the amount shall be adjusted in UI account of other beneficiaries in the State grid in the ratio of their capacity share in the generating station. For this purpose extra generation stands for actual generation minus schedule generation.

(iii)If any distribution licensee or any person exempted under section 13 or exempted under 8th proviso of section 14 draws less power than the scheduled drawal inspite of availability of power as per schedule and at the same time having load shedding in his area of supply, then the action will be construed as gaming and no UI charge will be receivable by him. UI charge shall be adjusted in the UI account of beneficiaries. However, if such incidence occurs for any direction by SLDC, then UI charge may be receivable by him, if applicable. In case of any dispute the matter shall be referred to the Commission for decision. For this purpose of this regulation, the load shedding includes load restriction imposed on consumer by the licensee on the ground of shortage of power availability.

Provided in case of non-availability of power as per requisition and to meet the commitment of long term and short term sale of power the shortage can be distributed in some agreed principles between sale of power to consumer by load shedding and sale of power to entities in the State Grid by reduction in supply. However, in the larger interest, any instruction of SLDC shall be binding upon all.

(iv)Any injection in State Grid above the declared injection by any licensee in any 15 minutes time block as a consequence of generation by the embedded generating stations of the licensee up to 105% of the declared injection schedule and averaging up to 101% of the declared injection schedule of the generating station respectively over a day causing consequential underdrawal shall not be construed as gaming. For any injection above the said specified level, the SLDC may investigate so as to ensure that there is no gaming and if gaming is found by the SLDC. the corresponding UI charges due to licensee on account of underdrawal arising out of such extra generation over the schedule shall be reduced to zero and the amount shall be distributed in proportion to UI charges receivable by other entities within the State in those 15 minutes' time block. For this purpose such extra generation shall stand for actual generation minus scheduled generation. However, for this purpose of regulation load restriction or local feeder shedding due to any technical reasons or overloading of transformers shall not be considered as part of gaming.

(v)Any underdrawal at frequency below 50 HZ by any licensee up to 95% of the drawal schedule in any 15 minutes time block and averaging up to 99% of the drawal schedule over a day shall not be construed as gaming. For any drawal by the distribution licensee below the said stipulated level, SLDC may investigate so as to ensure that there is no gaming if such underdrawal below the stipulated level does not cause backing down of any generating station of any generating company or licensee under the purview of the Commission. If gaming is found by SLDC, the corresponding UI charges due to the licensee on account of underdrawal shall be reduced to zero where the underdrawal stands for actual drawal minus scheduled drawal and the amount shall be distributed in proportion to U1 charges recoverable by other entities within the State in these 15 minutes time block. If, such underdrawal below the stipulated level is found to co-exist with load-shedding in the area of supply of the distribution licensee by which such electricity is drawn then the SLDC may, if necessary, revise the concerned schedule and intimate the concerned person(s) immediately and such schedule will be binding on all. For this purpose of regulation load restriction or local feeder shedding due to any technical reasons or overloading of transformers shall not be considered as load shedding.

(vi)Any overdrawal at frequency above 50HZ by any licensee up to 105% of the drawal schedule in any 15 minutes time block and averaging up to 101% of the drawal schedule over a day shall not be construed as gaming. For any drawal by the licensee above the said stipulated level, SLDC may investigate so as to ensure that there is no gaming, and if gaming is found by the SLDC, then the amount of energy drawn by the licensee in excess of the schedule during the period when the frequency is 50 Hz or above but below f Hz will be recoverable at the highest rate of UI charge from the overdrawing licensee and the amount so recovered shall remain in UI fund. At frequency f Hz and above all overdrawal shall be treated at UI rate. For the purpose of these Regulations on the date on which these Regulations will come into force the value of f Hz will be 50.20 Hz. Henceforth Commission may time to time amend the value of f through any order in order to keep parity with inter-state ABT.

Provided that in case of DPL or DPSCL, when applicable, the overdrawal due to outage of the generating station or its units or its load bearing equipments, shall not be construed as gaming for the next three blocks from the block when such outages occur but limited to the extent by which generation is reduced due to the outage.

(vii)Notwithstanding anything to the contrary contained anywhere else in these regulations, in case of less injection by a generating station or a licensee in any 15 minutes time block than its scheduled injection to another licensee the second licensee can generate from its embedded generating stations to any extent over its declared capacity (i.e, declared availability) subject to the restrictions of injection by the second licensee in the State Grid as specified in clause (iv) of regulation 6.5.2 and regulation 6.5.13 of these regulations. In such case the excess energy injected by the second licensee will be entitled for UI charge only.

(viii)In case of certain unforeseen demand fall of a consumer of DPL or DPSCL, when applicable, if there is injection above 105% of the scheduled injection by DPL or DPSCL, then that shall not be construed as gaming if DPL or DPSCL could provide supporting documents. However, such over injection shall be allowed up to next two blocks only from the block when such over injection above 105% has started and by that time schedule has to be revised by the DPL or DPSCL as the case may be.

(ix)Notwithstanding anything contained contrary to any regulation of these regulations for a generating station of installed capacity below 100 MW or a licensee having injection / drawal schedule of less than 100 MW, then deviation up to ± 5 MW shall not be construed as gaming. However, in case of deviation beyond ± 5 MW of the scheduled injection / drawal subject to specific dispensation as provided in proviso of clause (vi), if SLDC finds any gaming then such extra injection shall be reduced to zero where such extra injection stands for actual injection minus scheduled injection.

(x)Whenever any amount of UI charge is not allowed to a licensee or generating company on the ground of gaming then such amount will be distributed in accordance with the following priority.

(a)If UI charge is not distributed as per clause (ii) of this regulation, such amount shall be distributed among the affected entities who are affected by losses of revenue due to such gaming.

(b)Otherwise such amount shall be distributed among the beneficiaries of UI account in proportion to their UI charge recoverable by the other entities excluding the person who has been found to be involved in gaming.

6.5.3- The UI charges receivable or payable by any entity depends on state grid frequency and deviation of actual drawal / injection from schedule drawal / Injection according to following procedure :

(i)For determination of UI charge receivable and payable under this regulation 6.5.3, there are basically two candidates. The first candidate is the injector consisting of the entities who are to inject power in the state grid as per their schedule. The second candidates are drawers consisting of the entities who are to draw power from state grid as per their schedule.

(ii)The candidates for whom UI charge is payable and receivable are given in Schedule - 8.

6.5.4- (i) The price of electricity from captive generating plant having capacity more than 5 MW and connected to State Grid shall be either at UI rates at the time of injection or at a mutually agreed rate as stipulated in power purchase agreement between the captive generating plant and the licensee purchasing such electricity provided that flow of such infirm power does not exceed a period of three months between synchronization and date of Commercial Operation. However, price for firm supply of electricity from such captive generating plant to any licensee in the State Grid shall be as per power purchase agreement. In such case of supply from captive generation deviation from scheduled injection, if any, shall be settled through UI mechanism, or, as per terms and conditions on this account in the agreement between the licensee and the captive generator.

(ii)Any reversal of flow of power for consumption by the consumer having in-situ captive generating plant source during the period, shall be considered as emergency power at a tariff for normal period of TOD scheme for such emergency supply as determined under these regulations irrespective of time of the day for flow of such reversal of flow of power.

(iii)The open access customer shall not indulge in any gaming by deviation from the schedule to enrich himself through UI charges in a premeditated manner.

(iv)Drawal schedule for open access customer in open access customer mode shall be injection schedule minus normative transmission and distribution losses. For operational facilities, open access customer. who also draws simultaneous power in consumer mode shall also provide drawal schedule for consumer mode separately but simultaneously. In case of reduction of actual injection or in case of revised schedule of injection it shall be intimated to SLDC as laid down in state grid code of the Commission for operational requirement.

(v)For computation of UI charges in open access mode and charges for power drawal in consumer mode in the case of an open access customer. the actual injection reduced by normative transmission and distribution losses, shall be treated as the drawal schedule in open access mode. The said computation will be subject to the following conditions :-

(a)For any composite drawal involving both open access mode and consumer modes, the consumption in consumer mode at any instant will always be the total drawal at that instant reduced by the scheduled drawal in open access mode at the same instant.

(b)Any underdrawal in open access customer mode up to 95% of the drawal schedule in any time block of 15 minutes and averaging up to 99% of the drawal schedule over a day shall not be construed as gaming. Failure to fulfil such conditions shall be taken as gaming for the relevant time block. Where gaming is involved, no UI charges shall be receivable by the open access customers, and if any UI amount is found to be receivable through gaming, the same shall be distributed in proportion to UI recoverable by other entities within the State.

(c)Any overdrawal at drawal point with respect to drawal schedule in open access customer mode by an open access customer, will be considered as power supplied by the licensee to the open access customer as a part of supply in consumer mode at an applicable rate in consumer mode or UI rate prevailing at the time of overdrawal whichever is higher. Where such open access customer has an agreement with the licensee for drawal of power in consumer mode also to meet its partial demand or full demand simultaneously with its open access drawal, then also such overdrawal in excess to the drawal schedule of open access mode or consumer mode is to be considered as drawal in consumer mode.

Provided that such applicable rate in consumer mode will also include the additional demand charge, if any, for the excess demand over the sanctioned contract demand. Moreover, drawal of power in excess of sanctioned contract demand shall attract additional energy charge on such excess power drawal at any applicable penal rate if stipulated in the concerned tariff order of the Commission or UI charge whichever is higher.

(d)If the open access customer has no agreement with the licensee of any power drawal through consumer mode, then in such case any overdrawal at drawal point beyond the implemented drawal schedule will be considered as back-up power or stand-by power as agreed between the Open Access customer and the licensee under the commercial agreement for wheeling and applicable price for such back-up power or stand-by power will be in accordance with the commercial agreement for wheeling.

(vi)For open access source outside the state, the schedule / actual injection declared by RLDC concerned to the state shall be taken by SLDC as schedule / actual injection.

6.5.5- Even if no gaming is found under regulations 6.5.2 and 6.5.4 the following procedure needs to be adopted during computation of UI Charge.

Charges for UI in case the injection by a generating station other than the hydro generating station in excess of 105% of the Declared Capacity of the station in a time block or in excess of 101% of the average Declared Capacity over a day shall not exceed the charges for UI corresponding to grid frequency interval of below 50.02 Hz and not below 50.0 Hz.Provided that charges for the UI for the underdrawals by the buyer or the beneficiaries in a time block in excess of 10% of the schedule or 250 MW whichever is less, shall not exceed the cap rate for UI charges as specified by CERC.Provided further that the charges for the Unscheduled Interchange for the injection by the seller in excess of 120% of the schedule subject to a limit of ex-bus generation corresponding to 105% of the Installed capacity of the station in a time block or 101% of the Installed capacity over a day shall not exceed the cap rate for UI charges as specified by CERC.Provided also that the charges for UI for the injection by the seller in excess of ex-bus generation corresponding to 105% of Installed Capacity of the station in a block or 101cY0 of Installed capacity over a day shall not exceed the charges for UI corresponding to grid frequency interval of 'below 50.02 Hz and not below 50.0 Hz'.

6.5.6- The eligible open access customer at the point of drawal will be subject to the UI charges only with reference to their schedule and actual drawal. Rate for UI shall be same as per the applicable rate framed by Central Electricity Regulatory Commission.

6.5.7- In case for open access customer having its injection point and drawal point of open access within the area of supply of same distribution licensee and connected to the network of such distribution licensee, then they will not be treated by these regulations and will be guided by separate open access agreement between -

(i)The licensee and the open access customer in one hand and

(ii)The supplier of electricity at injection point and the open access customer and / or licensee on the other hand.

Open access customer and open access source will be subject to operational control under area load despatch centre concerned.

6.5.8- Power drawn / supplied in radial mode between two entities at a voltage level 33 kV and below shall not be under the purview of UI mechanism. They shall be settled as per mutually agreed principle, method and PPA. However, in case of entities drawing power from generating station, the same shall put both the generating station and the entity under UI mechanism.

6.5.9- In case of shortage of power, the shortage sharing procedure for exchange of power amongst entities shall be as per the provision mutually agreed by the entities in PPA.

6.5.10- While scheduling the injection schedule on the basis of availability of the generating stations of a licensee by ALDC as provided in regulation 6.4.2, ALDC shall also consider the firm allocation of capacity or power provided by the other suppliers (henceforth called as firm supplier) to the licensee with same weightage along with the generating stations of the licensee following the principle of merit order dispatch/supply based on summated amount of energy charge and social cost charge, if available. against each unit of injection for preparation of the injection schedule for the generating stations of the licensee and drawal schedule from its firm suppliers. In absence of separate energy charges the single part tariff will itself be considered as energy charge till two part tariff is introduced.

6.5.11- On submission of such injection schedule of generating station of the licensee and drawal schedule of the licensee prepared as per regulation 6.5.10 of these regulations by ALDC to SLDC, the SLDC shall check those schedules to ensure that there is no deviation from the principles of merit order dispatch/ supply as specified in the regulations 6.5.10 of these regulations and in case of any deviation, shall make appropriate modifications before releasing of injection and drawal schedule for interruption in pursuance to State Grid Code.

6.5.12- The generating stations of the licensees shall not be under Unscheduled Interchange charges though UI charges is applicable on the licensee as a whole entity integrated with embedded generating stations along with provision of payments through UI mechanism that may arise out of gaming by such generating stations as provided in last proviso to this regulation :

Provided that the clause (i) of regulation 6.5.2 of these regulations shall be applicable on such generating stations :Provided further that in case of sudden rise in demand of licensee, subject to conditions as provided in regulation 6.5.13 of these regulations, the licensee shall be allowed to generate over the ceiling specified in clause (i) of regulation 6.5.2 of these regulations to the extent the demand has increased and only after ensuring that its scheduled drawal from all its firm suppliers is maintained :

6.5.13- In case of situations mentioned in clause (vii) of regulation 6.5.2 or second proviso of regulation 6.5.12, the extra supply required to reduce the shortfall between demand and supply shall be allowed to meet up by the generating stations of the licensee and the firm suppliers to the licensee through revising the injection schedule of the generating stations of the licensee and drawal schedule of the licensee for the concerned periods by SLDC in the same principles as laid down in regulation 6.5.10 and regulation 6.5.11 of these regulations :

6.5.14- Notwithstanding anything to the contrary contained anywhere in these regulations in case of violation of clause (vii) of regulation 6.5.2 or second provisos of regulation 6.5.12 of these regulations, such extra energy supplied by the generating stations of the licensee shall be construed as gaming and the corresponding fixed charges of extra sent out energy will be payable by the distribution licensee to the concerned suppliers under the purview of this Commission and who are being deprived due to such gaming either at a rate of fixed charge of such supply by such suppliers where such supply is done against two part tariff or at a rate as provided for single part tariff and such payment would be done in SLDC-Ul-FUND-WBSETCL for onward payment to the suppliers who have been deprived but such payment shall not be recoverable from the consumers on any account. A separate account in the SLDC-UI FUND-WBSETCL shall be maintained for recovery of such fixed charges.

6.5.15- If SLDC comes to a conclusion after observing two consecutive 15 minutes time block or same time blocks of a number of days in a certain pattern at a regular interval or number of days at a stretch, that any licensee or generating company or generating station is involved in gaming then SLDC can suo-moto revise the concerned schedule in a manner which will be beneficial to the State and in the process the loss of income from UI by the licensee or generating company due to such revision of schedule shall not be construed as loss of benefit to the licensee or generating company as because UI is a commercial principle for maintaining grid discipline only.

6.6Procedure for Scheduling : -

6.6.1- The general methodology for scheduling shall be as per the details specified by the Commission in state grid code.

6.7Demonstration of Declared Capacity : -

6.7.1- The generating station under ABT may be required to demonstrate the declared capability of its generation as and when asked by the SLDC. For coal fired thermal generating station such demonstration shall be applicable for both actual declared capacity (normally called as declared capacity) and Notional Declared Capacity as explained in regulation 6.4.3 of these regulations. On a day when there is difference between Actual Declared Capacity and Notional Declared Capacity, SLDC, on the basis of request from any beneficiary or suo-moto shall mandatorily ask for at least one demonstration at a stretch of a duration of 15 minutes time block against Notional Declared Capacity where such demonstration period excludes the ramp-up and ramp down time. In the event the generating station fails to demonstrate any of such declared capacity, the capacity charges due to the generating station shall be reduced as a measure of penalty.

6.7.2- If the captive generating plant / generating station sells a portion of its power to the licensee, then Notional Declared Capacity against total installed capacity is required and the respective proportion for Notional Declared Capacity under sale to licensee will be determined as per ratio of allocation in PPA to the licensee. For such captive generating plant the demonstration is to be given for Notional Declared Capacity against total installed capacity and for that period if there is any surplus generation the licensee will consume such surplus generation. Moreover. for such declaration in such demonstration penalty will be imposed and other measures will be taken proportionately to the extent of its installed capacity which is agreed for allocation for sale to the licensee under PPA.

6.7.3- No separate cost of demonstration, will be allowed for either type of the declared capacity for a unit which is kept idle for want of demand or shortage in coal-supply. This means that, for such demonstration, corresponding capacity charge and fuel cost as determined under normative parameter as provided in tariff order will be applicable.

6.7.4- While giving notice for demonstration of Declared Capacity, to a coal fired thermal generating station SLDC shall clearly mention whether such demonstration is to demonstrate the Actual Declared Capacity or Notional Declared Capacity. In case of demonstration of Notional Declared Capacity, same demonstration will also be treated as the demonstration for Actual Declared Capacity. For generating stations other than coal fired thermal generating stations, demonstration of declared capacity means Actual Declared Capacity only.

6.7.5- During demonstration of Actual Declared Capacity or Notional Declared Capacity the actual injection will be treated as the revised schedule of injection for those 15 minutes time block and the period of ramp-up and ramp-down under which such demonstration takes place in accordance with prior intimation to all entities by SLDC about undertaking of such demonstration. The impact of such additional injection due to such demonstration will be distributed as additional drawal schedule among the purchaser of electricity of that generating station in proportion to their original drawal schedule or as per direction of SLDC where such additional generation can be scheduled for any licensee who has shortage of power or to the licensee (s) who has asked for such demonstration.

6.7.6- The quantum of penalty for the first mis-declaration for any duration/ block in a day shall be the charges corresponding to two days capacity charges. For the second miss-declaration the penalty shall be equivalent to capacity charges for four days and for subsequent miss-declarations, the penalty shall be multiplied in the geometrical progression till the recoverable monthly capacity charge becomes zero in that month. In the mis-declaration where demonstrated capacity against Notional Declared Capacity is less than the corresponding Actual Declared Capacity, then the penalty will be applicable against failure for any one type of declared capacity only. The penalty arising out of mis-declaration shall be recorded by SLDC as specified in the Balancing and Settlement Code and its cumulative amount shall be adjusted with the recoverable revenue through tariff after adjusting the ARR with the amount determined in APR.

6.7.7- In case of no mis-declaration against Actual Declared Capacity/ Declared Capacity in a day, the Actual Declared Capacity/ Declared Capacity for each 15 minutes time block of the day shall be treated as resultant/ achieved actual availability. Similarly in case of no mis-declaration against Notional Declared Capacity in a day, the Notional Declared Capacity for each 15 minutes time block of the day shall be treated as achieved/ resultant notional declared availability, in case of mis-declaration(s), the availability to be determined against Actual Declared Capacity/ Declared Capacity and Notional Declared Capacity of the generating station for the whole day shall be as specified in the Balancing and Settlement Code. In case of mis-declaration against Notional Declared Capacity, following methodology is to be adopted for determination of Actual and Notional availability.

(i)If demonstrated capacity/availability lies between Actual Declared Capacity and Notional Declared Capacity, then during the 15 minutes time block when such demonstration takes place the notional availability will be the demonstrated capacity. Based on such value the notional availability for the whole day will calculated as per the Balancing and Settlement Code.

(ii)If demonstrated capacity/availability lies below the Actual Declared Capacity then during the 15 minutes time block when such demonstration takes place the notional availability as well as actual availability will be the demonstrated capacity. Based on such value the notional availability and actual availability for the whole day will be calculated as per the Balancing and Settlement Code.

6.7.8- When there is no demonstration but at frequency below 50 Hz, If there is failure to inject by the generating station at least to the level of 95% of the schedule of injection for any 15 minutes time block, the actual availability as well as notional availability will be reduced to the actual injection for the concerned 15 minutes time block in order to determine the amount for recovery as capacity charge and that failure shall not be treated as a mis-declaration.

Provided that if during that block the generation is under back down condition as per direction of SLDC, then the actual availability/notional availability will be reduced by the extent equal to the difference of revised schedule due to back down and the actual injection.

6.7.9- In case of dispute, the same shall be referred to the Commission. The operating logbooks of the generating station shall be available for review by the Commission. These books shall keep record of machine operation aid maintenance. For hydro-generating stations, the logbook shall also have records of reservoir level and spill way gate operation.

6.8Deemed Generation for Hydro-Generating Station:- (a) In case of reduced generation of a hydro-generating station due to the reasons not attributable to the generating company or on account of non-availability of transmission / wheeling capacity or on receipt of backing down instructions from the concerned SLDC resulting in spillage of water, the energy charges on account of such spillage shall be payable to the generating company. Apportionment of energy charges for such spillage among the beneficiaries shall be in proportion of their shares in saleable capacity of the generating station.

(b)Energy charges on the above account shall not be admissible if the energy generated by the hydro-generating station during the year is equal to or more than the design energy.

6.9Supply of Information on Demand and Availability : -

6.9.1- Each distribution licensee or any person exempted under section 13 or exempted under 8th proviso of section 14 of the Act must issue a monthly statement of their demand, availability, quantum of load-shedding in MW and quantum of load restriction due to technical interruption in MW along with the affected feeders due to such load-shedding and interruption including time of such load-shedding or interruption and estimated loss in kWh. Copies of such statement shall be sent to the Commission on monthly basis, both in soft and hard copies. Such statement shall commensurate with its other obligation of information supply as per the regulation framed under section 57 and 59 of the Act. Hard copies shall be duly signed in each page of such statement as per the instant clause of these Regulations.

6.10Metering & Accounting : -

6.10.1- Metering arrangements, including installation, testing and maintenance of meters for entities connected to the state transmission system and for such connection with state transmission system only, shall be the responsibility of the STU on payment basis. Collection and transportation of raw data to SLDC shall be the responsibility of individual licensee and generating company. Processing of the data required for accounting of energy exchanges and UI account based on average frequency on 15-minute time block basis shall be done by the SLDC. Initial time synchronization of the meters and further checking and time synchronization, as and when required, shall be done by STU in co-ordination with the licensee and SLDC. A metering committee shall be formed by SLDC with the representative from licensees and STU to decide detailed procedure in this regard. All concerned entities (in whose premises the special energy meters are installed), shall fully cooperate with the SLDC and extend the necessary assistance by taking weekly meter readings and transmitting them to the state load despatch centre. On the basis of processed data of meters along with data relating to declared capacity and schedules etc., the SLDC shalt issue the state level accounts for energy on monthly basis as well as UI charges on weekly basis. UI accounting procedures shall be governed by the Balance and Settlement Code.

6.10.2- Notwithstanding anything contained contrary to any regulation of the Commission, STU / SLDC shall not permit any synchronization of any new unit of any generating station unless ABT compliant meters are installed and commissioned for recording the generation and ex-bus generation amount of such generating station along with proper on-line real time display of such information at SLDC except for the first test synchronization of such unit with explicit prior permission of SLDC.

6.11Capacity Charges of Power Stations : -

6.11.1- The capacity charges shall be computed as detailed out in the following regulations from 6.11.2 to 6.11.8.

6.11.2- The beneficiaries shall have full freedom for negotiating any transaction for utilisation of their capacity shares. In such cases, the beneficiary having allocation in the capacity of the generating station shall be liable for full payment of capacity charges and energy charges (including that for sale of power under the transaction negotiated by him) corresponding to his total allocation and schedule respectively.

6.11.3- If any capacity remains un-requisitioned during day-to-day operation, SLDC shall advise all beneficiaries in the state and the RLDC concerned so that such capacity may be requisitioned through bilateral arrangements either with the concerned generating company or with the beneficiary(ies) concerned under intimation to the RLDC or SLDC depending on the nature of transactions.

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

6.11.4- The fixed cost of a thermal generating station under ABT shall be computed on annual basis, based on norms specified under these regulations, and recovered on monthly basis under capacity charge. The capacity charge payable to a thermal generating station for a calendar month shall be calculated in accordance with the following formula

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

AFC x (NDM / NDY) x (0.5 + 0.5 x PAFM / NAPAF) (in Rupees);Provided that in case the plant availability factor achieved during a financial year (PAFY) is less than 70% the total capacity charge for the year shall be restricted toAFC x (0.5 + 35 / NAPAF) x (PAFY / 70) (in Rupees)

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

AFC x (NDM / NDY) x (PAFM / NAPAF) (in Rupees).Where,AFC = Annual fixed cost specified for the year, in RupeesNAPAF = Normative annual plant availability factor in percentageNDM = Number of days in the monthNDY = Number of days in the yearPAFM = Plant availability factor achieved during the month, in percent :PAFY = Plant availability factor achieved during the year, in percent

(iii)The PAFM and PAFY shall be computed in accordance with the following formula :

PAFM or PAFY =	1000X ∑NDCi/{N x IC C (100x AUX)}%
i = 1

Where,AUX = Normative auxiliary energy consumption in percentageDCi = Average declared capacity (in ex-bus MW), subject to clause (iv) below, for the ith day of the period i.e. the month or the year as the case may be, as certified by the concerned load dispatch centre after the day is over.IC = Installed Capacity (in MW) of the generating stationN = Number of days during the period i.e. the month or the year as the case may be.Note:- DCi and IC shalt exclude the capacity of generating units not declared under commercial operation. In case of a change in IC during the concerned period, its average value shall be taken.

(iv)The DCi shall be equal to the implemented schedule based on actual availability after considering regulation 6.7 of these regulations.

6.11.5- The fixed cost of a hydro generating station shall be computed on annual basis, based on norms specified under these regulations, and recovered on monthly basis under capacity charge and energy charge, which shall be payable by the beneficiaries in proportion to their respective allocation in the saleable capacity of the generating station, that is to say, in the capacity excluding the free power to the home State if any :

Provided that during the period between the date of commercial operation of the first unit of the generating station and the date of commercial operation of the generating station, the annual fixed cost shall provisionally be worked out based on the latest estimate of the completion cost for the generating station, for the purpose of determining the capacity charge and energy charge payment during such period. The capacity charge payable to hydro generating station for a calendar month shall be calculated in accordance with the following formula.

(i)The capacity charge payable to a hydro generating station for a calendar month shall be

AFC x 0.5 x NDM / NDY x (PAFM / NAPAF) (in Rupees).Where,AFC = Annual fixed cost specified for the year, in RupeesNAPAF = Normative annual plant availability factor in percentageNDM = Number of days in the monthNDY = Number of days in the yearPAFM = Plant availability factor achieved during the month, in percent :

(ii)The PAFM shall be computed in accordance with the following formula :

PAFM or PAFY =	1000X ∑NDCi/{N x IC C (100x AUX)}%
i = 1

Where,AUX = Normative auxiliary energy consumption in percentageDCi = Declared capacity (in ex-bus MW) for the ith day of the month which the station can deliver for at least three (3) hours, as certified by the concerned load dispatch centre after the day is over.IC = Installed Capacity (in MW) of the complete generating stationN = Number of days in the month

(iii)In case of any other terms and conditions as applicable under any agreement arising out of inter state water sharing principles then such conditions shall also be considered while determining the capacity charge / fixed cost with prior approval of the Commission of such conditions.

6.11.6- The capacity charge recovery of the generating stations of the licensees under availability based tariff will not be on monthly payment basis in pursuance of regulations 6.11.1, 6.11.4 and/or 6.11.5, as such capacity charge recovery is inbuilt in the recovery of aggregate revenue requirement of the licensee concerned and thus in pursuance of these regulations any adjustment required for variation between normative and actual availability of such generating stations shall be taken due care in Annual Performance Review of the concerned year.

The monthly fixed charge recovery of the licensee as supplier supplying electricity to another licensee against firm allocation of power supply by the supplier licensee to the receiving licensee in two part tariff of fixed/demand charge and energy charge shall be based as per regulation 6.11.4 or 6.11.5 as the case may be.

6.11.7- In case of any hydro pumped storage generating plant the plant availability could not be used for generation, then such availability shall be used for determination of availability of the plant if such non-utilization of availability of the plant is for following reasons.

(i)Non-availability of pumping power.

(ii)Generation is not required due to sufficient power availability to meet the demand of the consumer and other licensee with whom there is PPA for supply of power under the purview of the Commission.

(iii)The pumping energy saved is found to be beneficial to the consumer,

(iv)To maximize availability of power to the consumer.

6.11.8- In case of any hydro-generating station including pumped storage project where the plant availability could not be used due to non-availability of water from the supplier of water or due to annual dependability less than design consideration, then such amount of non-utilised availability shall be considered for availability determination.

Provided that for such cases the availability shall be limited to the ex-bus energy design value for the concerned months.

6.12Energy Charges for Thermal Generating Stations and Pumped Storage Hydro-Generating Station : -

6.12.1- The energy charges shall be paid by the beneficiary(ies) / licensee(s) / pumped storage hydro generating station to the concerned generating company of a generating station in accordance with the charge determined under paragraph 7.0 and paragraph 8.0 of Schedule-1.

6.13Billing and Payment of UI Charges : -

6.13.1- The UI charges shall be paid by the beneficiary(ies), licensee(s), generating station(s) and other entities, on whom said charges are applicable, to the SLDC in accordance with the charge as applicable from the date as per notification of the Commission. The UI rate shall be adjusted to account for the allowable technical losses as defined in open access regulations. Any payment on the head of receivable or payable on UI-charges shall be done through SLDC-Ul-FUND-WBSETCL as specified in Balancing and Settlement Code. SLDC shall also pay to the entities, who are entitled for such payments on UI account, as and when received and distribute on pro-rata basis to the outstanding of all parties. UI charges should not be adjusted with any payable / receivable amount. Licensees / generators / other entities shall pay UI amount payable by them, if any, within one week from the date of receipt of UI bill raised based on UI account issued by SLDC pending finalisation of the dispute, if any. Dispute if any shall be settled with SLDC and licensees / generators and adjusted in next bill. In case the dispute cannot be settled by SLDC, the same shall be referred to the Commission for settlement.

6.14Incentives for Generation : -

6.14.1- The incentive for a generating station of a generating company/ licensee shall be given in accordance with Schedule - 10. However ABT-compliant generating station of a generating company will not be allowed incentive as per paragraph 1 of Schedule - 10.

6.14.2- All the operating parameters meant for capacity charge recovery and/ or incentives in respect of a generating station shall be determined against the specific asset of the generating station for which tariff is determined.

6.14.3- In case of failure to attain scheduled injection by any generating station and in consequences any losses arising out of payment of Ul charges shall not be allowed to be recovered through tariff.

6.14.4- In case of any extra charge or penalty for inability to maintain a certain stipulated ratio of peak and off-peak injection or drawal is being ordered by the Commission, such extra charge or penalty shall be applicable on the basis of ratio as per scheduled injection or scheduled drawal independent of UI charges.

6.14.5- If at the end of a financial year, there is any amount in UI account then 90% of such amount will be used for distributing among the licensee in proportion to the amount of energy required by the licensee for selling the power to its consumer and licensee of the Commission. Such distributed amount shall be kept in the power purchaser fund of the concerned licensee.

6.15Condition of new generating unit prior to COD and consequential impact dealing. -

6.15.1- The test synchronization can continue up to 24 hours at a stretch subject to following conditions :-

(i)Prior to any test synchronization notice is to be provided to the SLDC along with mentioning the maximum possible injection and the duration of such trial operation.

(ii)Prior to first test synchronization PPA between the generating station and purchaser of such electricity is to be submitted to the Commission mandatorily, where prior approval has not been taken yet, for clearance at least six months before such test synchronization except where the generating station and the purchaser are same person.

(iii)Only after receiving of clearance of SLDC on the basis of notice issued under clause (i) above, clearance under clause (ii) above and satisfaction of conditions as specified in regulation 6.10.2, test synchronization can be undertaken.

(iv)The fuel cost of electricity generated under test run shall be considered as a part of project cost and thus not chargeable at all.

(v)The electricity generated under test synchronization shall be deemed to be scheduled among the beneficiaries in proportion to the allocation under PPA or as will be instructed by the generator through written communication in case the beneficiary does not agree to draw such power.

(vi)Between two test synchronization there shall be a gap of at least 24 hours.

6.15.2- The synchronization of an unit of a generating station where tariff is to be determined by the Commission shall be subject to following conditions.

(i)At least 15 days before synchronization the owner of the generating station shall submit to the Commission status of all load bearing equipments, system and facilities along with certification of availability for full operation of these equipments / facilities / system from the manufacturers and / or erection contractor along with validation by the in-charge of the generating station.

(ii)On the basis of documents as above the Commission will provide approval for 'go-ahead' for synchronization.

(iii)Only on the basis of such approval for 'go-ahead' SLDC will allow the generating station to synchronize after getting prior notice from the generating station in accordance with the provisions to the State Grid Code.

(iv)Such unit will be under ABT operation from the Date of Commercial Operation (COD) as specified in these regulations with reference to such date of synchronization against the above synchronization.

(v)For the purpose of tariff determination and ABT operation ninety days from the date of synchronization or the date as declared by the owner of the generating station as COD, whichever is earlier shall be treated as COD.

(vi)The generation between date of synchronization and COD shall be treated as infirm power and chargeable on fuel cost basis.

(vii)The owner of the generating station has filed the tariff application and is being admitted by the Commission as per regulation.

(viii)The condition of regulation 6.10.2 is satisfied.

6.15.3- In case of shortage of power the Commission may allow synchronization of a new generating station with partial availability of all load bearing equipments / facilities / systems subject to following conditions.

(i)Licensee or generating company who owns the generating station cannot ask for any special dispensation in tariff due to partial availability in installed capacity.

(ii)For the purpose of tariff determination and ABT operation ninety days from the date of synchronization with such partial installed capacity or the date as declared by the owner of the generating station as COD, whichever is earlier shall be treated as COD.

(iii)From the date of commercial operation such generating station shall be under ABT operation and no special dispensation will be provided on the ground of lower availability of installed capacity.

(iv)The available installed capacity is at least 60% of the MCR of the generating unit under consideration.

(v)The conditions of regulation 6.10.2 of these regulations are satisfied.

6.16Computation and Payment to Transmission Charge for Intra-State Transmission System. -

6.16.1- The fixed cost of the transmission system shall be computed on annual basis, in accordance with norms as specified under regulation 2.8.6 of these regulations aggregated as appropriate, and recovered on monthly basis as transmission charge from the users, who shall share these charges in the manner specified.

6.16.2- The annual transmission Service Charge (Aggregate Revenue Requirement) recoverable by a transmission licensee shall be computed in accordance with the following equation :

AFC = [Gross ARR - NTI - OI]Where AFC = Annual Fixed CostGross ARR = Gross Aggregate Revenue Requirement of the transmission licensee as specified in these regulations.NTI = Approved level of non-tariff incomeOI = Approved level of income from other business.Annual transmission service charges shall be recovered monthly. However, the short term customers shall pay transmission charges on a daily basis as laid down in the open access regulations.

6.16.3- The transmission charge payable to a transmission licensee for a calendar month shall be calculated in accordance with the following formula.

(i)The transmission charge payable for a calendar month for a transmission system or part thereof shall be AFC x (NDM / NDY) x (TAFM / NATAF)

Where,AFC = Annual fixed cost specified for the year, in RupeesNATAF = Normative annual transmission availability factor, in per centNDM = Number of days in the monthNDY = Number of days in the yearTAFM = Transmission system availability factor for the month in percent.The transmission charges shall be calculated on monthly basis according to transmission service charges to be recovered in each month of a year by the transmission licensee as per allocation done by the Commission against each month in pursuance to the regulation 3.3.2.

(ii)The transmission charges may be calculated separately for part of the transmission system having differing NATAF, if any, and aggregated thereafter, according to their sharing by the beneficiaries. However, it will be the Commission's discretion whether they will determine such transmission charge separately or as a whole with the whole system.

(iii)In case the transmission charge recovered in a year is in excess of the annual fixed cost that excess cost shall be adjusted with the ARR of the next ensuing year through due diligence under APR.

6.16.4- The transmission licensee shall raise the bill for the transmission charge for a month based on its estimate of TAFM. Adjustments, if any, shall be made on the basis of the TAFM within 30 days from the last day of the relevant month.

6.16.5- In case of more than one long term transmission customer of the intra-state transmission system, the transmission service charges leviable on each long-term transmission customer shall be computed as per the following formula :

Transmission charges for transmission system concerned and payable for a month by a long-term transmission customer of that transmission system= {n∑ i=1 [AFCi/12] - TRSC} x CL/SCLWhere AFCi = Annual Fixed Charges for the ith transmission project in the transmission system concerned computed in accordance with regulation 6.16.2 of these regulations.n = Number of projects in the transmission system concerned.TRSC = Total recovery of transmission charges for the month from short-term customers as specified in open access regulations for the transmission system concerned in accordance with the open access regulations.CL = Allotted transmission Capacity of the transmission system concerned to the long-term transmission customer.SCL = Sum of the allotted transmission capacities to all the long-term transmission customers of the transmission system concerned.

6.17Billing and Payment of Charges. -

6.17.1- Bills shall be raised for capacity charge, energy charge and the transmission charge on monthly basis by the generating company and the transmission licensee in accordance with these regulations. and payments shall be made by the beneficiaries or the transmission customers directly to the generating company or the transmission licensee, as the case may be.

6.17.2- Each beneficiary shall pay the capacity charges in proportion to its percentage share in installed capacity for the thermal generating station and for hydro generating station including pumped storage hydro generating station in proportion to its percentage share in total saleable capacity of the generating station.

Note 1:- Allocation of total capacity of state generating stations and share of central sector generation under ABT schedule shall be made by state government from time to time, which also may have an unallocated portion. Such allocation must be intimated by State Government to the SLDC. However, at present all the power generated by WBPDCL and share of central sector generation are considered as fully allocated to WBSEDCL. Allocation of the unallocated portion shall also be made by the State Government from time to time, from the total unallocated capacity and shall be notified by the SLDC in advance at least 24 hours prior to such change in allocation taking effect. The total capacity share of any beneficiary would be the sum of its capacity share plus allocation out of the unallocated portion. In the absence of any specific distribution of unallocated power by the State Government, the unallocated power shall be added to the allocated shares in the same proportion as the allocated shares.Note 2:- The beneficiaries may propose surrendering part of their allocated share to other beneficiaries within the state. In such cases, depending upon the technical feasibility of power transfer and specific agreements reached by the generating company with other beneficiaries within the state for such transfers, the shares of the beneficiaries may be re-allocated by the State Government for a specific period. When such re-allocations are made, the beneficiaries who surrender the share shall not be liable to pay capacity charges for the surrendered share. The capacity charges for the capacity surrendered and reallocated as above shall be paid by the beneficiaries to whom the surrendered capacity is allocated. Except for the period of reallocation of capacity as above, the beneficiaries of the generating station shall continue to pay the full capacity charges as per allocated capacity shares. Any such reallocation shall be notified by the SLDC in advance, at least 24 hours prior to such reallocation taking effect.Note 3:- FEHS = Free energy for Home State, in percent and shall be taken as 12%

6.17.3Rebate -

(i)For payment of bills of the generating company and the transmission licensee through letter of credit on presentation, a rebate of 2% shall be allowed.

(ii)Where payments are made other than through letter of credit within a period of one month of presentation of bills by the generating company or the transmission licensee, a rebate of 1% shall be allowed.

6.17.4Late payment surcharge - In case the payment of any bill for charges payable under these regulations is delayed by a beneficiary beyond a period of 60 days from the date of billing a late payment surcharge at the rate of 1.25% per month on the billed amount or prorated for part thereof shall be levied by the generating company or the transmission licensee for the defaulted period reckoning from the due date.

Chapter - 7 Principles, terms and conditions for purchase and procurement of electricity

7.1Applicability.-

7.1.1- The regulations contained in this Chapter shall apply under section 86(1)(b) only for electricity purchase and procurement by a distribution licensee from a generating company or licensee or electricity trader or from any other source through agreement or arrangement for purchase of power for distribution and supply within the State.

7.2Power procurement guidelines. -

7.2.1- A distribution licensee shall follow the guidelines with respect to procurement of power under any arrangement or agreement.

7.3Power Purchase Agreement and its content. -

7.3.1- Every entity purchasing power from any source must have power purchase agreement covering penalty and rebate for deviation of schedule to take care of AST mode of operation except to the extent provided in these regulations. PPA may also cover month wise power purchase variation pattern, month wise daily drawal of peak and lean ratio, monthly load factor and normal overhauling schedule, power shortage sharing principle, point of sale transaction, etc. Firm and infirm power shall also be treated separately in the PPA. All these parameters shall be commensurate with the capacity charge recovery of the selling entity. Ir case, if any portion of the generation capacity of embedded generating station of any licensee is firmly allocated for other distribution licensee then that allocation must be included in the PPA along with the provision for capacity charge recovery. Similarly, if any portion of the power available with a distribution licensee is kept reserved firmly for supply to another distribution licensee, then the PPA shall include such reservation mechanism and priority in detail along with the terms and conditions.

7.3.2- A generating company or licensee, as the case may be, may agree to any terms and conditions in the power purchase agreement that may vary from the terms and conditions contained in these regulations where the terms and conditions agreed upon will result in a lower total cost of supply of electricity to consumers in the state during the entire duration of the agreement of which such terms and conditions form part or there is any reasonable ground for which the purchase under the agreement can be justified.

Provided that such agreement shall come into effect only with the prior approval of the Commission, except where such approval is not specifically required under the Act or these regulations.

7.4Approval of power purchase agreement / arrangement. -

7.4.1- Every agreement or arrangement for power procurement by a licensee from any other source of supply entered into after 09.02.2007 shall come into effect only with the prior approval of the Commission, subject to the exception vide provisions of regulations 7.5 of these regulations.

Provided that for any power procurement, other than power procurement through any power exchange under the purview of CERC or WBERC, prior approval of the Commission shall be required in accordance with these regulations in respect of any agreement or arrangement for procurement of electricity by the licensee from any source of supply except for the specific conditions for short-term procurement as specified under regulation 7.5.1 to 7.5.5 of these Regulations.Provided further that the prior approval of the Commission shall also be required in accordance with these regulations for any change to an existing arrangement or agreement for power procurement, whether or not the Commission approved such existing arrangement or agreement.

7.4.2- The Commission shall review an application for approval of power purchase agreement / arrangement for a period exceeding one year having regard to the following factors, as appropriate.

(a)Requirement for power procurement;

(b)Adherence to a transparent process of bidding in accordance with guidelines issued by the Central Government;

(c)Adherence to the tariff determined by the Central Electricity Regulatory Commission for the purchase of power from Central generating company;

(d)Adherence to the agreed tariff for purchase of energy from international sources:

(e)Adherence to policy approved by the Commission for purchase of power from captive and non-conventional sources;

(f)Availability (or expected availability) of capacity in the Intra-State transmission system for evacuation and supply of power procured under the agreement / arrangement:

(g)Adherence to Purchase of power from any source, other than those mentioned from (a) to (e) above in pursuance to different provisions of these regulations:

(h)Need to promote co-generation and generation of electricity from renewable sources of energy.

7.4.3- All the PPAs already approved by the Commission shall be deemed to have been approved under these regulations. The PPA which are yet to be approved by the Commission will be considered for approval under these regulations only.

7.4.4- Notwithstanding anything to the contrary contained elsewhere in these regulations no approval is required for the procurement of power through power exchange under the purview of the CERC or the Commission.

7.5PPA on Short-Term Procurement and Its Approval Mechanism. -

7.5.1- Where there has been a shortfall or failure in the supply of electricity from any approved source of supply during the financial year, the licensee may enter into a short-term arrangement or agreement for procurement of power from electricity trader or generating company outside the state under section 86(1)(b) without the prior approval of the Commission where the price for power procured under such arrangement or agreement is discovered through bidding within at least three bidders or procured for meeting the shortage on urgent basis as per regulation 7.5.3.

7.5.2- In pursuance to proviso of Section 62(1)(a) where there has been a shortfall or failure in the supply of electricity from any approved source of supply during the financial year, the licensee may enter into a short-term arrangement or agreement for procurement of power from any generating station or licensee or electricity trader without prior approval if the agreed price in the agreement is less than highest price for power purchase by the licensee that is approved by the Commission in the tariff order for the ensuing year concerned or any previous ensuing year in case the tariff for the concerned ensuing year has not yet been issued.

7.5.3- The licensee may enter into a short-term arrangement or agreement for procurement of power without the prior approval of the Commission and without bidding when faced with emergency conditions that threaten the stability of the distribution system or when directed to do so by the State Load Despatch Centre of West Bengal to prevent grid failure.

7.5.4- Within three months from the date of entering into an agreement or arrangement for short-term power procurement for which prior approval is not required, the distribution licensee shall provide the Commission, full details of such agreement or arrangement. including quantum, tariff calculations, duration, supplier details, method for supplier selection and such other details as the Commission may require with regard to such agreement / arrangement to give the post facto approval.

Provided that where the contract period in the agreement for such short term procurement does not exceed 120 days the post facto approval is also not required.

7.5.5- Notwithstanding anything contrary contained elsewhere in these regulations for short-term procurement, Letter of Award or any order with due terms and conditions shall also be considered as PPA. Power Procurement through exchange will not require any PPA for any transaction.

7.6PPA Under Regulation 2.11.2. -

7.6.1- Notwithstanding anything to the contrary contained anywhere else in these regulations. where the licensee has identified a source from which power can be procured at a tariff that reduces the ultimate average cost of supply to the consumer or ultimately beneficial to the consumer by increasing instant or deferred availability the licensee may enter into procurement agreement or arrangement with such supplier with prior approval of the PPA from the Commission in accordance with regulation 2.11.2 of these regulations. In case, the period of the agreement is over three years, such PPA may be approved subject to the condition that at any time if it is found not to serve the above mentioned purpose then in such case the agreement will be terminated as per order of the Commission or otherwise the tariff for procurement of such power procured is to be determined under this regulatory mechanism for each year.

7.6.2- Where the Commission has reasonable grounds to believe that the arrangement or agreement entered into by the licensee under short term power procurement or under regulation 2.11.2 of these regulations results in increase in average cost of supply to the consumer, the Commission may disallow any increase in the total cost of power procurement (net of additional revenue) over the approved level arising therefrom or any loss incurred by the distribution licensee as a result, from being passed through to consumers as an adjustment in tariffs in the formula for Fuel and Power Purchase Cost Adjustment (FPPCA) as specified in Schedule - 7A.

7.7PPA for existing Entities. -

7.7.1- The power purchase agreement by all the existing entities, as provided in regulation 7.3.1, shall be completed by 31st December, 2011 and submitted to the Commission within a fortnight from the date of completion of the PPA for approval so that it become operative from the date of approval.

7.7.2- In case of existing power purchasing agreement, if the issues mentioned in regulation 7.3.1 above are not covered then that should be covered under supplementary PPA within 31st March, 2012 and submitted to the Commission within a fortnight from the date of completion of the supplementary PPA and the same shall become operative from the date of approval of the PPA by the Commission.

7.7.3- In the absence of power purchase agreement, the decision of the Commission on the above issues shall be binding upon the power purchaser and seller.

7.7.4- Notwithstanding anything to the contrary contained in any provisions anywhere else in these regulations, the tariff for supply of electricity from any licensee to any other licensee after 31st March of 2012 shall not be determined by the Commission unless any power purchase agreement exists between the licensees for the projected period of supply within the concerned control period and has been approved by the Commission.

7.8New PPA. -

7.8.1- The PPA between /among the entities, as provided in regulation 7.3.1 of these regulations, in relation to supply of electricity, shall be submitted to the Commission within a month of completion of such document except for the specific dispensation as made for the cases under these regulations.

7.8.2- New generating station of any generating company and commissioned after 22.05.2009 shall not be allowed to supply electricity to any licensee under the purview of the Commission in line with regulation 7.3.1 of these regulations unless the Commission gives express clearance for supply of electricity on submission of PPA to the Commission.

7.8.3- The PPA for long-term or mid term procurement between any generating company or any electricity trader or any licensee in one hand and any distribution licensee under the purview of the Commission on the other hand and covered by these regulations shall not be operative unless the PPA is approved by the Commission.

7.9PPA And Tariff. -

7.9.1- Notwithstanding anything to the contrary contained in any other provision anywhere else in these regulations, the tariff for supply of electricity from any generating station of a generating company to any licensee shall not be determined by the Commission unless a power purchase agreement exists between the generating company and the licensee for the projected period of supply within the concerned control period and the same has been approved by the Commission.

Chapter - 8 Miscellaneous

8.1- If any tariff applicant fails to submit any information required to be submitted by these regulations the Commission, at its sole discretion, shall apply its best judgement to arrive at its own conclusion regarding such missing information based on prevailing norms and / or other available data, etc. and based on such methods as it may deem fit which shall be recorded through reasoned order.

8.2- Under these regulations Commission can do the following :

(a)The Commission may at its sole discretion fix suitable norms / limits for any or all the items of expenses.

(b)The Commission may, at any time, at its sole discretion, vary, alter, modify, add or amend any provision of these regulations.

8.3- If any difficulty arises in giving effect to any of the provisions of these regulations, the Commission may, on reasons to be recorded in writing, direct any person including a licensee either by a general or a special order, to take suitable action(s) not inconsistent with the provisions of the Act, as may appear to be necessary for removing the difficulty.

8.4- Nothing in these regulations shall be deemed to limit or otherwise affect the inherent power of the Commission to make such orders as may be necessary for meeting the ends of justice or to prevent the abuse of the process of the Commission.Notwithstanding anything contrary contained anywhere in these regulations or any other regulations of the Commission, the Commission may deviate from these regulations with reasoned order in order to meet the ends of justice or to prevent the abuse of the process of the Commission.

8.5Permissible deviation in monthly energy bill recovery and corresponding payment. -

8.5.1- The net amount payable for an energy bill after considering taxes, cess, duties, etc. and adjustment of rebate/surcharges, if any, is to be rounded off to the lower value of nearest rupee or any higher multiple up to ten rupees and the differential amount is to be carried forward for adjustment against next bill on the same principle stated above. However, in case of discontinuance of power purchase agreement or discontinuance as a consumer, the licensee may bill for fractional amount for its dues payable finally.

8.5.2- The licensee shall clearly indicate in the consumer's bill following component of tariff and duty.

(a)the amount payable in terms of tariff determined by the Commission;

(b)the amount of state government subsidy, if any,

(c)fuel and power purchase cost adjustment, if any;

(d)Adhoc Power Purchase Cost and/or Adhoc Fuel Cost and/or Adhoc Generation Cost and/or Adhoc Variable Cost, if any;

(e)APR Tariff Adjustment, if any;

(f)Electricity Duty; and

(g)the net amount payable.

8.5.3- Notwithstanding anything contained in other regulations of the Commission if any consumer paid excess amount than the billed amount as per regulation 8,5.1 of these regulations through any automated mechanized collection system or cheque or draft or pay order then the excess amount will be accepted by the licensee considering that the consumer has consented to such payment, in such case the excess amount will be adjusted against the bill(s) raised during subsequent billing cycle(s).

8.6Period of Operating Norms and Criteria for Incentive. -

8.6.1- All the operating norms and criteria for the purpose of incentives and the basis of measurement of such related performance and all the mode of operationalization of incentives mentioned in these regulations or specified subsequently shall continue to be operative for third control period.

8.6.2- Any generating company or licensee, which achieves any of the operating norms or criteria for incentive in any year of the third control period mentioned in regulation 6.6.1, will get incentives for improved performance for that year only.

8.7Treatment of time barred non-refunded amount on account of excess taxes / duties 1 interest, etc. - Had there been any fund created due to accumulation of time barred non-refunded amount on account of excess taxes / duties / interest, etc, at the end of the financial year, the said amount is to be entirely transferred to power purchaser fund.

8.8Transparency: Wherever the Commission has issued any order in accordance with these Regulations, it shall be deemed to have acted transparently and in a manner envisaged under Section 86(3) of the Act.Provided that the Commission shall maintain all the relevant records related to such order for a period of at least twelve years from the date of issue of the order and which can be accessed by public on demand in accordance with the procedure stipulated by the Commission for such purpose.

8.9Repeal : The West Bengal Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2007 issued under Notification No. 31/WBERC dated 9th February, 2007 published in the Kolkata Gazette. Extraordinary on February 9, 2007, with all amendments are hereby repealed. Notwithstanding such repeal, anything done or any action already taken under the repealed regulations, shall in so far as it is not inconsistent with these regulations, be deemed to have been done or taken under the corresponding provisions of these regulations.

8.10Power to remove difficulties :- If any difficulty arises in giving effect to any order based on these regulations, then the Commission, by subsequent supplementary order, may remove the difficulties keeping consistency with the provisions of the Act and these regulations.

8.11Power to Relax :- In case of creation of any successor company(ies) through transfer scheme in pursuance to section 131 of the Act, the Commission may relax the provisions of any of these regulations as and when required for the concerned control period or its related base year in which such company(ies) is / are created.

8.12Power to change Schedule :- The Commission may from time to time replace the schedule of these regulations through notifications and the replaced schedule shall be treated as a part of these regulations after repealing the schedule, which has been replaced

Schedule 1

[See regulations 1.2.1(ii), 2.2.4, 2.8.1, 2.8.1.3.1, 2.8.1.3.3, 6.4.1, 6.12.1]Principles, terms and conditions for determination of tariff of Conventional Generating Stations

1. Applicability. - 1.1 - The provisions specified in this Schedule - 1 shall apply in determining the Tariff for supply of electricity to a distribution licensee from conventional sources of generation.

1.2- The Commission shall be guided by the terms and conditions contained in this Schedule in determining the tariff for supply of electricity by a generating station of a generating company to a distribution licensee in the following cases :

(a)Where such tariff is pursuant to a power purchase agreement or arrangement entered into subsequent to the date of notification of these regulations; or

(b)Where such tariff is pursuant to a power purchase agreement or arrangement entered into prior to the date of notification of these regulations and the Commission has not previously approved of such agreement / arrangement or adopted the tariff contained therein; or

(c)Where such tariff is pursuant to a power purchase agreement or arrangement which is the subject of a review by the Commission under these regulations;

Provided that where the distribution licensee is engaged in the business of generation of electricity, the principles, terms and conditions to the extent applicable, shall be followed in determining the cost at which electricity is supplied by the generation business of the distribution licensee to his retail supply business.

2. Components of tariff. -

2.1- Tariff for sale of electricity from a thermal power generating station shall comprise of two parts, namely, the recovery of annual capacity charges and energy (variable) charges.

2.2- Tariff for sale of electricity from a hydro-generating station shall comprise of two-parts, namely, recovery of annual capacity charges and energy charges.

2.3- The Annual Capacity Charges and Annual Revenue Recoverable through tariff of a thermal generating station or of a hydro generating station (including pumped storage hydro generating station), as the case may be, shall be computed in the following manner :-Annual Revenue Recoverable through tariff for a year = Aggregate Revenue Required of the concerned ensuing year + Adjustment due to APR of any year(s) + Adjustment due to FPPCA of any year(s), if any.Annual Capacity Charges = Annual Revenue Recoverable through tariff of a year - Fuel Cost of the year.However; for hydro generating station FPPCA and Fuel Cost will not exist.

2.4- The energy (variable) charges, in case of thermal generating station, shall cover fuel cost and / or water pumping cost and shall be computed as specified in these regulations.

3. Capital cost and Additional Capital Cost. -

3.1- The capital cost of the generating company shall be worked out in accordance with the provisions of these regulations.

3.2- Capital cost of hydro generating stations including the complete hydro generating facility covering all components such as dam, intake, water conductor system, power generating stations and generating units of the scheme as apportioned to power generation, shall be determined in accordance with these regulations.

4. Sale of infirm power:. -

4.1- Any revenue earned by the generating company from the sale of infirm power shall be taken as reduction in capital cost as provided in these regulations.

5. SLDC / RLDC / ERPC and Transmission Charges. -

5.1- SLDC / RLDC charges and Transmission charges payable by the licensees as determined by the Commission shall be considered as expenses. SLDC / RLDC / ERPC and Transmission charges paid for the energy sold outside the State shall not be considered as expenses for determining generation tariff.

6.0Other Income. -

6.1- Income except income from sale of electricity and income from UI charges is to be considered as other income to the extent related to generation business inclusive of utilization of its assets within the purview of the Commission.

7. Energy charges for Hydro-Generating Station: -

7.1- The energy charge shall be payable by every beneficiary for the total energy scheduled to be supplied to the beneficiary, excluding free energy, if any, during the calendar month, on ex power plant basis, at the computed energy charge rate. Total Energy charge payable to the generating company for a month shall be :{Energy charge rate (ECR) in Rs./kWh} x {Scheduled energy (ex-bus) for the month in kWh} x (100 - FEHS)/100.FEHS = Free energy for home State, in per cent, as defined in regulation 6.17.2

7.2- Energy charge rate (ECR) in Rupees per kWh on ex-power plant basis, for a hydro generating station, shall be determined up to three decimal places based on the following formula, subject to the provisions of clause (7) :ECR = AFC x 0.5 x 10 / {DE x (100 - AUX) x (100 - FEHS)}Where,DE = Annual design energy specified for the hydro generating station, in MWh, subject to the provision in paragraph 7.3.AUX - Normative auxiliary consumption in %

7.3- In case actual total energy generated by a hydro generating station during a year is less than the design energy for reasons beyond the control of the generating company, the following treatment shall be applied on a rolling basis :

(a)in case the energy shortfall occurs within ten years from the date of commercial operation of a generating station, the ECR for the year following the year of energy shortfall shall be computed based on the formula specified in paragraph 7.2 above with the modification that the DE for the year shall be considered as equal to the actual energy generated during the year of the shortfall, till the energy charge shortfall for the previous year has been made up, after which normal ECR shall be applicable;

(b)in case the energy shortfall occurs after ten years from the date of commercial operation of a generating station, the following shall apply : Suppose the specified annual design energy for the station in DE MWh, and the actual energy generated during the concerned (first) and the following (second) financial years is Al and A2 MWh respectively, Al being less than DE. Then, the design energy to be considered in the formula in paragraph 7.2 above for calculating the ECR for the third financial year shall be moderated as (Al + A2 - DE) MWh, subject to a maximum of DE MWh and a minimum of Al MWh.

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

7.4- In case the energy charge rate (ECR) for a hydro generating station, as computed in paragraph 7.2 above, exceeds eighty paise per kWh, and the actual saleable energy in a year exceeds {DE x (100 - AUX) x (100 - FEI-IS)/ 1000) MWh, the Energy charge for the energy in excess of the above shall be billed at eighty paise per kWh only :Provided that in a year following a year in which total energy generated was less than the design energy for reasons beyond the control of the generating company, the energy charge rate shall be reduced to eighty paise per kWh after the energy charge shortfall of the previous year has been made up.

7.5- The concerned Load Despatch Centre shall finalise the schedules for the hydro generating stations, in consultation with the beneficiaries, for optimal utilization of all the energy declared to be available, which shall be scheduled for all beneficiaries in proportion to their respective allocations in the generating station.

8. Energy Charges for Thermal Generating Stations :

8.1Thermal Generating stations covered under ABT - (i) The energy charge shall cover the primary fuel cost and limestone consumption cost (where applicable), and shall be payable by every beneficiary for the total energy scheduled to be supplied to such beneficiary during the calendar month on ex-power plant basis, at the energy charge rate of the month (with fuel and limestone price adjustment). Total Energy charge payable to the generating company for a month shall be :(Energy charge rate in Rs./kWh) x {Scheduled energy (ex-bus) for the month in kWh.}

(ii)Energy Charge Rate (ECR) in Rupees per kWh on ex-power plant basis shall be determined to three decimal places in accordance with the following formula :

(a)For coal based and lignite fired stations

ECR = {(GHR - SFC x CVSF) x LPPF/CVPF + LC x LPL + SFC x LPSF} x 100 / (100 - AUX)

(b)For gas and liquid fuel based stations

ECR = GHR x LPPF x 100 / {CVPF x (100 - AUX)}Where,AUX = Normative auxiliary energy consumption in percentageCVPF = Average permissible useful heat value of primary fuel as fired, in kCal per kg, per litre or per standard cubic metre, as applicableCVSF = Calorific value of secondary fuel, in kCal per ml.ECR = Energy charge rate, in Rupees per kWh sent out.GHR = Gross station heat rate, in kCal per kWh.LC = Normative limestone consumption in kg per kWh.LPL = Weighted average landed price of limestone in Rupees per kg. or per litre or per standard cubic meter, as applicable, during the period concerned.LPPF = Weighted average landed price of primary fuel, in Rupees per kg., per litre or perstandard cubic metre, as applicable, during the period concern.SFC = Normative Specific secondary fuel oil consumption, in ml per kWh.LPSF = Weighted average landed price of secondary fuel for the concern period.

(iii)The landed cost of fuel for the month shall include price of fuel corresponding to the grade and quality of fuel inclusive of royalty, taxes and duties as applicable. transportation cost by rail/ road or any other means, and, for the purpose of computation of energy charge, and in case of coal/ lignite shall be arrived at after considering normative transit and handling losses as percentage of the quantity of coal or lignite dispatched by the coal or lignite supply company during the month as per applicable norms according to Schedule-9A and Schedule-9D.

(iv)The landed price of limestone shall be taken based on procurement price of limestone for the generating station, inclusive of royalty, taxes and duties as applicable and transportation cost for the month.

8.2Thermal Generating stations other than those covered under ABT - (i) Energy (variable) charges shall cover fuel costs and shall be worked out on the basis of ex-bus energy delivered / sent out from the generating station as per the following formula:Energy charges (Rs) = Rate of energy charges (REC) in Rs./kWh as per latest tariff order x Energy delivered (ex-bus) for the month in kWh.

(ii)The rate of energy charges shall be as per formula mentioned in paragraph 8.1(ii) of this schedule.

8.3Pumped Storage Hydro-Generating Station covered under ABT - (i) Energy (variable) Charges shall cover water pumping costs and shall be worked out on the basis of ex-bus energy scheduled to be sent out including losses (energy which will be available at pumped storage hydro-generating station bus) from the generating station as per the following formula :Energy charges (Rs) = Energy charge rate (ECR) in Rs/kWh as per latest tariff order x Scheduled Energy (ex-bus) for the month in kWh corresponding to scheduled generation.

(ii)Energy Charge Rate (ECR) = Energy charge rate as per normal hydro-generating station as specified in paragraph 7.2 of this schedule plus pumping costs.

Pumping Cost per unit of energy sent out = 100xPC/[100-(Auxn)] Rs. / kWhWhere,PC = Power Purchase Cost for pumping operation to generate one unit of power in generation mode.Auxn = Normative auxiliary energy consumption as percentage of gross generation as per these regulations.

8.4Pumped Storage Hydro-Generating Station other than those covered under ABT - (i) Energy (variable) Charges shall cover water pumping costs and shall be worked out on the basis of ex-bus energy delivered / sent out including losses (energy which will be available at pumped storage hydro-generating station bus) from the generating station as per the following formula :Energy charges (Rs) = Energy charge rate (ECR) in Rs/kWh as per latest tariff order x Energy delivered (ex-bus) for the month in kWh.

(ii)The Energy charge rate shall be as per formula mentioned in paragraph 8.3(ii) of these Schedule.

9. Transmission Charges - The generating company shall be allowed to recover transmission charges payable to it for its dedicated transmission line in accordance with the tariff approved by the Commission in a manner as may be decided by the Commission in line with regulation 6.16 of these regulations.

Schedule 2

[See regulation 2.5.2.1(xvii)]Planning by a licensee or a generating company

1. 0. Content of Perspective Plan. -

1.1- The generating company or licensee shall file a perspective plan for approval of the Commission along with tariff application. The perspective plan shall be for a period of 5 years and shall be submitted with each tariff application and application for annual performance review.

1.2- The content of the perspective plan shall be as follows :

(i)The perspective plan of a distribution licensee for the control period shall, inter alia, contain the forecast for ensuing years on unconstrained peak demand as well as energy demand in the area of supply of the licensee, peak as well as energy demand for other agencies to whom the licensee supplied energy, sales forecast in line with paragraph 3 of schedule-5 of these regulations, power procurement plan and capital investment plan in order to meet the requirements of the guidelines on load forecast as specified in these regulations.

(ii)A separate note of methodology and basis of such projection, as mentioned in (i), shall also be given.

2.0Demand Forecast by Distribution Licensee. -

2.1- The forecast of peak demand and energy demand in the perspective plan must be commensurate with the projected sale figure for ensuing years based on trend analysis. Annual projection of such demand shall be based on monthly demand analysis. Month wise projected demand requirement for both peak and energy shall be based on monthly average of hourly load data. While assessing such demand following points are to be considered;

(i)Standards to be maintained with regard to supply of power, in accordance with the Standards of Performance Regulations;

(ii)Measures proposed to be implemented as regards energy conservation and energy efficiency;

Provided that the peak demand forecast in the perspective plan by any generating company or licensee shall take into account the diversity factor among the entities to whom the supply shall be made and such peak demand shall be considered on growth of the highest co-incident demand among all the entities to whom supply is made and on the basis of input taken from those entities to whom such supply is made.

2.2- Above forecast / estimate contained for the purpose of the procurement plan shall be separately stated for peak, off-peak and normal periods for each of the seasons (Summer, Monsoon and Winter), in terms of quantities of power procured (in millions of units of electricity).Explanation - for the purpose of these regulations, the terms "peak period", "off peak period" and "normal period" shall mean such block of hours during a twenty-four (24) hour period as specified in regulation 3.1.3 in Chapter-3.

3.0Power Procurement Plan by Distribution Licensee. -

3.1- Plan for procurement of power shall be done on the basis of following planning criteria -

(i)To ensure supply for all time to meet the demand as estimated as per paragraph 2.0 inclusive of peak demand through reserving appropriate available generation capacity in long-term. While planning supply side the following parameters shall also be considered;

(a)An estimate of the quantities of electricity supply from the approved sources of generation and power purchase;

(b)The requirement for new sources of power generation and / or procurement, including augmentation of generation capacity and identified new sources of supply, based on above factors;

(ii)In case of shortage, short-term power purchase plan shall be kept available as far as possible;

(iii)Total power purchase plan shall also be made with sufficient margin to take into account future optimistic growth rate;

(iv)The power procurement plan shall be at least cost plan as far as possible after taking into consideration of the factors as mentioned under paragraph 1.2(i), 1.2(ii), 2.1 and 0.1 of these schedule based on available information regarding costs of various sources of supply. Moreover such power procurement plan shall be subject to commercial viability depending on the market condition of the country. The plan for procurement of power including quantities and cost estimates for such procurement shall also consider additional transmission costs, open access and other charges, which may be incidental to such procurement. The Commission shall ensure that power procurement plan submitted by the licensee is consistent with the transmission system plan for the intra-state and inter-state transmission system, taking into account the open access use.

(v)To accommodate the surplus generation of a generating station arising out of the obligations of promoting market development through financing projects with competitive generation costs outside the long-term power purchase framework as envisaged in the national electricity policy for market development.

(vi)The incidental surplus power, if any, arising from consideration of above power procurement plan, may be planned for sale to persons other than consumer through use of open access or trading function or other means in order to pass on the benefit to the consumers in the area of supply of the licensee from any gain of such activity to a reasonable extent, as per these regulations.

(vii)The power purchase plan shall be commensurate with the requirement of other Regulations;

(viii)Where the Commission stipulates a percentage of the total consumption of electricity in the area of a licensee to be purchased from co-generation, non-conventional and renewable sources of energy, the power procurement plan of such licensee shall include the plan for procurement from such sources in accordance with the percentage specified to be specified by the Commission.

4.0Capital Investment Plan by Distribution Licensee. -

4.1- The capital investment plan shall be based on the following :

(i)The proposed capital investment plan for distribution licensee shall also mandatorily show separately the capital investment plan inclusive of annual capital expenditure programme for its distribution network in detail against obligation of universal supply in the area of supply of the licensee in pursuance to the section 43 of the Act. Above investment plan shall show the annual target towards discharge of such obligation of supply along with the schedule of coverage in plans of the whole area of supply of the licensee for the said purpose.

(ii)Similarly, transmission licensees shall also show their capital expenditure programme under the capital investment plan.

(iii)The licensee shall give in detail and transparently to the Commission the status of each project of capital expenditure programme for which investment plan has been approved by the Commission in terms of regulations 2.8.1.4 or 2.8.2.3 or 2.8.3 or 2.8.4.

(iv)The licensee shall also give the details of each project of capital expenditure programme for which the investment plan has been submitted to the Commission but not yet approved in terms of regulations 2.8.1.4 or 2.8.2.3 or 2.8.3 or 2.8.4.

(vi)The approval of Capital investment plan including capital expenditure programme or approval of any modification of it by the Commission is subject to condition that specific project-wise investment approval is to be taken separately under regulations 2.8.1.4, 2.8.2.3. 2.8.2.4, 2.8.3 and 2.8.4 of these regulations.

5.0Infrastructure Plan of Licensee. -

5.1- The perspective plan for distribution licensee and transmission licensee shall also give detail of the emerging load centres and their projected demand along with the sub-stations under construction and planning separately, their commissioning schedule and capacity of the sub-stations. The distribution sub-stations shall also show their respective source of supply related to transmission sub-stations or generating stations directly.

6.0Miscellaneous. -

6.1- The Commission may, if it so deems, suo moto modify the procurement plan of the licensee prepared under these regulations and determine tariff accordingly.

Schedule 3

[See regulations 2.2.4, 2.8.2.2(a)]Principles, terms and conditions for determination of tariff for transmission licensee or for dedicated transmission line

1. Applicability. -

1.1- The regulations contained in this Schedule shall apply in determining tariffs for access to and use of the intra-state transmission system of a transmission licensee pursuant to a Bulk Power transmission Agreement or other arrangement entered into with a transmission system user or any transmission lines whose tariff is required to be determined on or after the date of notification of these regulations.

1.2- The Commission shall be guided by the terms and conditions contained in this Schedule in specifying the rates, charges, terms and conditions for use of intervening transmission facilities pursuant to an application made in this regard by a licensee under the proviso to sub-section (1) of section 36 of the Act.

2. Principle of Tariff Determination. -

2.1- Target availability for recovery of full transformation charge will be on normative basis as per regulation 2.8.6 of these regulations.

2.2Auxiliary Energy Consumption in the sub-station - The charges for auxiliary energy consumption in the AC sub-station for the purpose of air-conditioning, lighting, technical consumption, etc. shall be borne by the transmission licensee as part of its normative losses;

3. Net Annual Revenue Requirement for transmission. -

3.1- The monthly transmission service charges payable by the licensees or the other open access customers shall be based on the capacity allocated to each beneficiary based on average of daily peak demand on annual basis and the annual transmission service charges on the basis of net total capacity utilisation, or on the basis of target availability as determined by the Commission and shall provide for the recovery of the gross aggregate revenue requirement of the transmission licensee for the financial year, as reduced by the amount of non-tariff income and income from other business, as approved by the Commission and comprising the following :Gross Aggregate Revenue Requirement for transmission:

(a)Return on equity;

(b)Income-tax;

(c)Financing cost;

(d)Depreciation, including advance against depreciation, and amortization of intangible assets;

(e)Operation and maintenance expenses:

(ea)taxes and duties;

(f)Employee Cost;

(g)Interest on working capital and deposits from transmission system users;

(h)Insurance premium payable;

(i)Contribution to Reserve for unforeseen Exigencies;

(j)Variation in foreign exchange rate to the extent not recognized as interest;

(k)Other allowances, if any; and

(l)Effect of Rebate/Surcharge.

(m)The contribution to the Development Fund, if any, by the consumers and depreciation and interest on the assets created from the Development Fund.

Net Annual Revenue Requirement for transmission = Gross Aggregate Revenue Requirement for transmission, as above, minus :

(a)Non-tariff income;

(b)Income from other business, to the extent of portion to be passed on to the beneficiaries as decided by the Commission.

(c)Income from transmission system access charges under open access regulations.

3.3.2- The annual transmission service charges of the transmission licensee shall be determined by the Commission on the basis of an application for determination of tariff made by the transmission licensee in accordance with these regulations.

4. Non-tariff Income. -

4.1- Non-tariff income shall include but not limited to :

(a)Reactive energy charges and transmission service charges received from Central Transmission Utility for use of facilities of licensee / STU;

(b)Any general receipts in terms of Act / Regulations / Rules, all other general receipts arising from and ancillary or incidental to the transmission business.

4.2- The amount of non-tariff income relating to the transmission Business as approved by the Commission shall be deducted from the gross aggregate revenue requirement in determining the annual transmission service charges of the transmission licensee.

4.3- The transmission licensee shall submit full details of his estimate of non-tariff income to the Commission in accordance with the form specified in these regulations.

5. Income from other business. -

5.1- Where the transmission licensee has engaged in any other business for optimum utilisation of assets of its core business, an amount equal to two-fifth of the revenues from such other business after deduction of all direct and indirect costs attributed to such other business shall be deducted from the gross aggregate revenue requirement of the transmission licensee.Provided that the transmission licensee shall follow a reasonable basis for allocation of all joint and common costs between the transmission business and the other business and shall submit the allocation statement to the Commission along with his application for determination of tariff.Provided further that where the sum total of the direct and indirect costs of such other business exceed the revenues from such other business or for any other reason, no amount shall be allowed to be added to the aggregate revenue requirement of the transmission licensee on account of such other business.

6. Unbundling Transmission Charges. -

6.1- The state transmission utility shall maintain separate function wise accounts for transmission system and State Load Despatch Center.

6.2- The tariff for the transmission services shall be unbundled to reflect the cost of various activities associated with provision of transmission service once the data as per the above are made available.The components of transmission tariff area. Charges for use of network - This component of transmission service charges / tariff shall be reflecting cost of capital investment in and maintenance and operation of, a transmission system to transfer bulk power to and from different locations. The revenue from this component of transmission tariff will meet the Aggregate Revenue Requirement of transmission entity in respect of owning the transmission asset.b. System Operation Charges - This component of transmission service charges / tariff shall reflect the cost associated with operating the state load despatch center. The cost, among other things, shall include the cost of owning and maintaining state load despatch center, scheduling, real time operation of the grid and the cost for discharging the responsibility under sub-section (2) of section 32 of the Act. This system operation charges shall be charged in addition to SLDC charges to users of such services, based on total energy transacted.

Schedule 4

[See regulations 2.2.4, 2.8.2.2(b)]Principles, terms and conditions for determination of tariff for wheeling of electricity in distribution system.

1. Applicability. -

1.1- This schedule shall apply in determining tariff payable for wheeling of electricity by a user of distribution system who has been allowed open access to the distribution system of a distribution licensee in accordance with the open access regulations.Provided however that the consumers of the distribution licensee shall not be required to pay any tariff under this part for the part of energy he is drawing not as open access customer.

1.2- Every distribution licensee shall maintain separate records for the distribution business and shall prepare and submit an allocation statement in accordance with the format specified in these regulations.

2. Components of tariff. -

2.1- The distribution wheeling charges of the distribution licensee shall provide for the recovery of the gross aggregate revenue requirement relating to the core business of the distribution licensee for the financial year, as reduced by the amount of non-tariff income, expenses incidental to selling and distribution of energy and income from other business and shall comprise the following :Gross Aggregate Revenue Requirement for Distribution Wheeling :

(a)Return on equity;

(b)income-tax;

(c)Financing cost;

(d)Depreciation, including advance against depreciation and amortization of intangible assets;

(e)Operation and maintenance expenses;

(ea)Water cess, taxes and duties;

(f)Employee Cost;

(g)Interest on working capital and deposits from consumers and distribution system users reduced by working capital requirement on account of purchase of power;

(h)Insurance premium payable;

(i)Contribution to reserve for unforeseen exigencies;

(j)Variation in foreign exchange rate to the extent not recognized as interest;

(k)Other allowances, if any; and

(l)Effect of Rebate / Surcharge.

(m)The contribution to the Development Fund, if any, by the consumers and the depreciation and; on the assets created from the Development Fund.

Net Annual Revenue Requirement for Distribution Wheeling = Gross Aggregate Revenue Requirement for distribution wheeling, as above, minus :

(a)Non-tariff income;

(b)Expenses incidental to selling and distribution of energy, viz. billing. collection etc.;

(c)Share of Income from other business, to the extent specified in these regulations;

(d)Income from distribution system access charges under open access regulations in proportion to projected energy sold with respect to the total energy projected for selling and wheeling through distribution licensee's network.

2.2- The distribution wheeling charges of the distribution licensee shall be determined by the Commission on the basis of an application for determination of tariff made by the distribution licensee in accordance with these regulations.

3. Calculation of Net Aggregate Revenue Requirement for Distribution Wheeling. -

3.1- Net Aggregate Revenue Requirement for distribution wheeling is to be calculated in accordance with the procedure specified in these regulations for distribution licensee.

4. Non-Tariff Income. -

4.1- The amount of non-tariff income relating to the distribution business as approved by the Commission shall be deducted from the gross aggregate revenue requirement in determining the distribution wheeling charges of the distribution licensee.

4.2- Distribution licensee shall submit full details of his forecast of non-tariff income to the Commission along with his application for determination of tariff.

5. Income from Other Business. -

5.1- Where the distribution licensee has engaged in any other business for optimum utilisation of assets of its core business, an amount equal to two-fifth of the share of revenues of distribution licensee from such other business after deduction of all direct and indirect costs attributed to such other business shall be deducted from the Gross Aggregate Revenue Requirement including the embedded portion of wheeling in distribution system required to be done for supplying power to all the consumer in determining the distribution wheeling charges of the distribution licensee related to wheeled power through its distribution system.The distribution licensee shall have to follow a reasonable basis for allocation of all joint and common costs between the distribution business and the other business and shall submit the allocation statement to the Commission along with his application for determination of tariff :Provided further that where the sum total of the direct and indirect costs of such other business exceed the revenues from such other business or for any other reason, no amount shall be allowed to be added to the aggregate revenue requirement of the distribution licensee on account of such other business.

6. Allocation of Distribution Wheeling Charges. -

6.1- The Commission shall specify the distribution wheeling charges of the distribution licensee in its order passed under sub-section (3) of section 64 of the Act and shall be on the basis of quantum of energy wheeled including sales to own consumers.

7. Distribution Losses. -

7.1- Distribution loss for open access customers shall be in accordance with open access regulations.

8. Distribution Wheeling Charges. -

8.1- The distribution licensee shall provide open access to any consumer within the area of the supply on payment of distribution wheeling charges, other charges and applicable surcharges. Different type of open access customers for whom different distribution wheeling tariff/ charges will be applicable are according to the type of open access customer as specified in the open access regulations.

8.2- The distribution wheeling charges will represent the charges for the use of distribution systems or associated facilities of a distribution licensee for wheeling of electricity through that facilities and will be derived based on total distribution network cost, total units salable by the licensee to the consumers and total units wheeled for all open access customers in the network and as may be determined on these basis by the Commission from time to time.

8.3- All items of revenue requirement of the distribution licensee excluding generation cost and cost of power purchase as specified in these regulations shall be the cost of distribution licensee for the purpose of wheeling.

8.4- The distribution wheeling charges shall be computed taking into account the projected units sold and wheeled through distribution licensee's network and within the ensuing tariff period.

9. Cross Subsidy Surcharge. -

9.1- Till such time the cross subsidy is eliminated, the open access consumer shall pay cross subsidy surcharge in addition to the distribution wheeling charges in accordance with open access regulations.

9.2- The cross subsidy surcharge collected shall be utilized to meet the current level of cross subsidy.

9.3- Cross subsidy surcharge shall be as per the formula as specified in the open access regulations.

10. Additional Surcharge. -

10.1- When the Commission permits a consumer or class of consumers to receive supply of electricity from a person other than the distribution licensee of his area of supply, such consumer shall pay additional surcharge to meet the fixed charges as specified in the open access regulations.Provided if any consumer of a distribution licensee chooses the supply of electricity for his premises from another distribution licensee empowered to supply the said consumer under the terms of the latter's licence and such supply is effected through the latter's own network only, then the additional surcharge will not be applicable.

10.2- A consumer availing open access and receiving supply of electricity from a person other than a distribution licensee of his area of supply, shall pay the distribution licensee an additional surcharge, in addition to any other charges including wheeling charges and surcharge(s) to meet the fixed cost of such distribution licensee arising out of his obligation to supply, in accordance with sub-section (4) of section 42 of the Electricity Act, 2003.

10.3- The Commission shall fix the amount of additional surcharge through individual orders in a case specific manner keeping in view the amount of fixed cost as has been allowed by the Commission to such distribution licensee towards his distribution business from year to year basis.

10.4- The additional surcharge shall be decided and leviable for such period as the Commission may determine, keeping in view, inter-alia, sales growth.

11. Manners of Recovering Surcharges from open access Customers. - (a) The surcharge(s) to be recovered from open access customers shall be such charge as will be fixed by the Commission from time to time in line with these regulations.

(b)The open access customers within the state who are exclusively availing inter state transmission system shall also pay applicable surcharge (s), to the extent applicable.

(c)The surcharge(s) shall be payable to the concerned distribution licensee of the area of supply where the open access customer's point of drawal of power is situated / located. In case multiple licensees exist within the same area, the surcharge(s) shall be payable to the distribution licensee with whose network the customer point of drawal is connected.

(d)If a generating station operates as a captive generating plant and at the end of the year such plant does not qualify as Captive Generating Plant as per the Electricity Rules 2005 or any other rule made under the Act for this purpose, then the user of such generating station is required to pay cross subsidy surcharge and additional surcharge in the manner as laid down in regulation 4.6.3 of these regulations.

Schedule 5

[See regulation 2.2.4, 2.8.2.2(c), Para 1.2(i) of Schedule-2]Principles, terms and conditions for determination of tariff for retail sale of electricity

1. Applicability. -

1.1- This schedule shall apply for determination of tariff for retail sale of electricity by a distribution licensee to his consumers for the part of energy drawn by the consumer not as open access customer who has got open access under section 42 of the Act.Provided that in case of distribution of electricity in the same area by two or more distribution licensees, the Commission may fix the maximum ceiling of tariff for sale of electricity and may be guided by principles contained in these regulations in fixing such tariff.

2. Net Aggregate Revenue Requirement. -

2.1- The supply tariff of a distribution licensee shall provide for recovery of the gross aggregate revenue requirement of the distribution licensee for the year. as reduced by the amount of non-tariff income, income from wheeling, share of income from other business as per these regulations and receipts on account of cross-subsidy surcharge and additional surcharge, as approved by the Commission and comprising the following :-Gross Aggregate Revenue Requirement-

(a)Return on Equity;

(b)Income-tax;

(c)Financing Cost;

(d)Depreciation, including advance against depreciation and amortization of intangible assets;

(e)Cost of power generation / power purchase;

(f)water-cess, taxes and duties

(g)Transmission charges;

(h)Operation and Maintenance expenses;

(i)Employee cost;

(j)Insurance premium payable;

(k)Contribution to reserve for unforeseen exigencies;

(l)Bad and doubtful debt limited by the ceiling specified in the regulation 5.10.1:

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

(n)Variation in foreign exchange rate to the extent not recognized as Interest;

(o)Permitted incentives_;

(p)Other allocations and expenses considered appropriate by the Commission;

(q)Effects of Rebate and surcharge;

(r)The contribution to the Development Fund, if any by the consumers and the depreciation and the interest on the assets created from the Development Fund.

Net Aggregate Revenue Requirement from sale of electricity = Gross Aggregate Revenue Requirement for retail sale (a to r above) Less (s to y below)

(s)Non-tariff income;

(t)Income from distribution wheeling of electricity;

(u)Receipts on account of cross-subsidy surcharge;

(v)Receipts on account of additional surcharge on charges of wheeling;

(w)Permitted benefits to be passed on to the consumers, if not dealt elsewhere;

(x)Income from distribution system access charges under open access regulations in proportion to projected energy sold with respect to the total energy projected for selling and wheeling through distribution licensee's network:

(y)Share of income from other business to the extent specified in these regulations in paragraph 5.1 of schedule 4.

3. Sales Forecast. -

3.1- The distribution licensee shall formulate the long-term demand forecast.

3.2- The licensee may adopt a suitable methodology like Compounded Annual Growth Rate (CAGR) based on trend analysis or any other appropriate statistical tools to arrive at the category wise sales for the ensuing year. Exceptional circumstances. including shift of consumers to Captive Generation and Open Access, are to be suitably factored in.

3.3- The licensee shall forecast annual demand and sale of electricity for different categories of consumers in his area of supply for ensuing year. Wherever different rates are proposed for different slabs of consumption, forecast for slab-wise consumption shall also be furnished.

3.4- The Commission shall examine the forecast for reasonableness based on growth in number of consumers and consumption of electricity in the previous years and anticipated growth in the next year and any other factor that the Commission may consider relevant and approve sale of electricity to consumers with such modification as deemed fit.

3.5- The forecasts / estimates shall take into account factors such as overall economic growth, consumption growth of electricity-intensive sectors, advent of conservation measures, trends in captive power, impact of loss reduction initiatives, TOD metering, demand side management and improvement in generating station, if any, Plant Load Factors in its own generating stations and other relevant factors.Provided also that where the metered data are not available, the manually logged operational data may be used for the period till the respective meter is installed but not later than the first control period.

3.6- The licensee shall also furnish the details on category wise open access customers and the demand and energy wheeled for them. The details may be furnished separately for the supply within the area of the distribution licensee and to the supply outside the area of supply of the distribution licensee.

3.7- The details of bulk supply of electricity, if any, to electricity traders may also be furnished.

4. Transmission charges. -

4.1- The distribution licensee shall be allowed to recover transmission charges payable to a transmission licensee for access to and use of the intra-State transmission system of such transmission licensee in accordance with the tariff approved by the Commission as per these regulations.

4.2- The distribution licensee shall also be allowed to recover the following expenses, at the approved level :

(a)Charges for use of intervening transmission facilities including intra-state transmission charges payable in accordance with tariff specified by any other Commission;

(b)Wheeling charges paid for use of the distribution system of other distribution licensee;

(c)Charges for access to and use of an inter-state transmission system, in accordance with tariffs specified by the central Commission; and

(d)Fees and charges of the RLDC and SLDC, as may be specified.

5. Non-Tariff Income. -

5.1- The amount of non-tariff income as approved by the Commission shall be deducted from the gross aggregate revenue requirement in calculating the aggregate revenue requirement from retail sale of electricity of the distribution licensee :Provided that the distribution licensee shall submit full details of his forecast of non-tariff income to the Commission along with his application for determination of tariff.

6. Income from distribution wheeling charges. -

6.

1.

- The amount of any income from distribution wheeling charges. calculated in accordance of these regulations and as approved by the Commission, shall be deducted from the gross aggregate revenue requirement in calculating the aggregate revenue requirement from retail sale of electricity of the distribution licensee.

7. Receipts on account of cross-subsidy surcharge and additional surcharge on charges of wheeling. -

7.1- The amount received by the distribution licensee from open access customers within the area of supply of the distribution licensee by way of cross-subsidy surcharge, as approved by the Commission in accordance with the open access regulations shall be deducted from the gross aggregate revenue requirement in calculating the aggregate revenue requirement from retail sale of electricity of such distribution licensee.

7.2- The amount received by the distribution licensee by way of additional surcharge on charges of wheeling, from open access customers, as approved by the Commission in accordance with the open access regulations shall be deducted from the gross aggregate revenue requirement in calculating the revenue requirement from retail sale of electricity of such distribution licensee.

7.3- Separate statement of actual receipt of above surcharge in the previous year has to be submitted along with the tariff petition.

8. Distribution losses. -

8.1- The distribution licensee shall be allowed to retain permissible gain in accordance with Schedule - 9B of these regulations due to reducing distribution loss below the target norms set in Schedule - 9A of these regulations.

8.2- The distribution licensee shall have proper metering arrangements for accurate measurement of transmission loss.

8.3- Appropriate sample study with the approval of the Commission shall be conducted to estimate the consumption in unmetered services so that distribution losses are estimated fairly accurate.

9. SLDC / RLDC / ERPC Charges - SLDC / RLDC / ERPC charges if paid separately in addition to charges for usage of Network (instead of bundled transmission charges) shall be considered as expenses in determination of tariff proportionate to beneficiaries.

10. Determination of tariff - The Commission shall determine the tariff for supply of electricity by the distribution licensee to meet the aggregate revenue requirement after following the procedure mentioned in these regulations.

11. Tariff Income. -

11.1- Income from supply of electricity to consumers shall be assessed based on the tariff applicable to different category of consumers and the quantity of electricity estimated to be sold to them.

12. Class of consumers:. -

12.1- For tariff determination, different classes of consumers may be considered by the licensees, which must include the classes for different licensees as given in Annexure - C1, which is a part of this schedule - 5.

12.2- Licensees' tariff proposal for above class of consumers under 12.1 may further be classified for non-TOD tariff. TOD tariff and Pre-paid tariff separately. The tariff plan for different classes of consumers has been given in Annexure -C2, which is a part of this schedule - 5. The Commission may alter the tariff scheme through separate order as and when required.

12.3- In tariff application, the information shall be filled up in line with regulation 3.3 after taking into account the item 12.1 and 12.2 of this Schedule.

12.4- The licensee intending to propose tariff on the basis of the regulations 3.4, 3.5, 3.6, 3.7, 3.8 and 3.9, shall provide detailed information in the different forms specified in this regulation with due reflection of such proposals.

12.5- Notwithstanding anything.contained in these regulations, any consumer whose partial or full demand is met by supply through open access as open access customer and balance demand in consumer mode, then that consumer shall not have any TOD scheme of tariff in consumer mode and for him the applicable tariff will be tariff scheme under the class of consumers where the open access customer as consumer exists. If the applicable tariff scheme is of TOD-scheme in such case the tariff around 24 hours of a day for such open access customer shall be equal to the rate of normal period of TOD scheme.

12.6- Notwithstanding anything contained in these regulations, any consumer who has in-situ captive generating set shall not have any TOD scheme of tariff in consumer mode and for him the tariff will be the rate of normal period of that TOD scheme of applicable tariff scheme under emergency category and will be applicable for 24 hours of the day.

12.7- The Commission may merge any two or more classes of consumers as and when required through any order.

Schedule 6

[See regulations 2.2.4, 2.3.1]Grant Of Subsidies By State Government

1. Manner for provision of subsidy by State Government -

1.1- The Commission, after determining the tariff for different categories / group of consumers of the licensees on the basis of its aggregate revenue requirement admitted. will communicate to the state government to intimate whether it requires under section 65 of the Act, 2003, to grant any subsidy to any consumer or class of consumers in the tariff determined by the Commission.

1.2- Within 15 (fifteen) days from the date of the receipt of the communication, as stated above, the state government shall intimate the Commission as well to the concerned licensee, the amount of subsidy it agrees to pay, if it decides to pay any subsidy at all, with clear indication of the consumer or class of consumers to be subsidized.

1.3- The amount of subsidy so agreed by the state government is to be paid in advance directly to the licensee in full at the beginning of each financial year or before implementation of any decision for which such grant of subsidy is decided.

1.4- On receiving such subsidy the licensee shall intimate such information of receiving subsidy in detail to the Commission and only after getting approval of the Commission the licensee shall pass on the benefit of subsidy to the eligible consumer/class of consumers in proportion to the extent to which the total realizable revenue in terms of tariff order is paid by the State Government.

1.5- The licensee shall clearly indicate in the consumer / consumers' bill (a) the amount payable in terms of the tariff determined by the Commission; (b) the amount of state government subsidy and (c) the net amount payable.

1.6- If on Annual Performance Review it is found that subsidy received as per paragraph 1.3 and 1 4 was higher than what was actually required the licensee shall take up the matter with the State Government who has provided the subsidy for proper disposal and intimate the Commission about the decision. On the other hand if it is found that the subsidy received was less than what was actually required, the State Government shall make available the balance within one month from the date of order of the Annual Performance Review. Over dues on this score will attract interest on such overdue amount at the rate decided by the Commission and provision of subsidy will be allowed for future only after clearance of such over dues.

7A

[See regulations 2.1.15, 2.2.4, 2.5.3, 2.5.6.2, 2.6.6, 2.6.7, 2.8.1.3.1, 2 8 7.1, 2.8 7.5,2.10.1, 5.8.8, 5.8.8(c), 5.8.9, 7.6.2]Fuel And Power Purchase Cost Adjustment (FPPCA)A. Procedure For Fuel And Power Purchase Cost Adjustment (FPPCA) For Licensees.

(1)Fuel and power purchase cost admitted against energy sold to own consumers and other licensee during adjustment period shall be in terms of the following formula.FPPC (In Rs.) = {FC + (PPC - CDD) + (± A)}Where-

(i)The adjustment period for fuel and power purchase cost will normally be on annual basis, if not otherwise decided by the Commission

(ii)FPPC : Re-determined Fuel and Power Purchase Cost against application of FPPCA.

(iii)FC : Fuel cost of own generation as per normative parameters fixed by the Commission or on actual basis in absence of any norm and UHV range as may be allowed under regulation 5.8. commensurate with actual level of energy sales to own consumers and/or licensee during the adjustment period in accordance with the following methodology.

t = Norms of Transmission and Distribution loss in % considered for sale of power from licensee to licenseed = Norms of distribution loss in %EO = Admitted Energy for own consumption by licenseeESL = Energy sale to other licensee in MUEsC = Energy sale to consumer in MUFuel-Cost = Fuel cost at generation bus of own generating stations = Cost determined on the basis of normative parameters of SHR and oil consumption rate against actual level of energy sent out plus normative auxiliary energy consumptionFCluc = Per unit of Fuel Cost at distribution input= Fuel-Cost ÷ Actual overall energy available at input of the distribution system which includes power purchase from different services.FCAdm_d = Admitted Fuel Cost for sale to licensee= ESL/(1-d x 0.01) x FCIUCFCAdm_c = Admitted Fuel Cost for sale to consumer= ESC+EO/(1-d x 0.01) x FCIUCFC = FCAdm_d + FCAdm_c

(iv)PPC (Rs.) : Total cost incurred including the cost for fuel for power purchase from different sources commensurate with actual level of energy sales during the adjustment period.

(v)CD (Rs.) : Cost disallowable by the Commission as per following methods

Let d = Norms of distribution loss in %t = Norms of Transmission and Distribution loss in % considered for sale of power from licensee to licenseeEg = Actual energy sent out in MU from own generating stationE = excess amount of auxiliary energy consumption in MU Total energy purchased in MUEo = Admitted Energy for own consumption by licenseeESC = Energy sale to consumer in MUESL = Energy sale to other licensee in MUEAdm = Admitted Amount of Energy entitled for purchaseEAdm = ESC + Eo/(1-dx0.01) + ESL/(1-tx0.01) - E - EgEE = Excess energy purchased = Ep - EAdmCD = EE x EPAvgWhen EPAvg = Average cost of power purchase

(vi)A : Adjustment, if any, to be made in the current period to account for any claim due to excess / shortfall in recovery of fuel and power purchase cost in the past adjustment period based on directions / orders of the Commission. (+A) shall be considered as the amount to be recovered from consumer and purchaser of electricity under the purview of the Commission when the licensee has already incurred such expenses. (-A) shall be considered as the amount to be refunded to the consumer and purchaser of electricity under the purview of the Commission because such amount of less expenses has been incurred by the licensee against any prior period adjustment.

(vii)Such re-determined fuel and power purchase cost (FPPC) of the licensee will be further adjusted for gain sharing as per Schedule - 9B for the parameters related to fuel cost to the extent it has impact in the fuel cost.

Note: (i) Such re-determined fuel and power purchase cost (FPPC) including gain sharing under (vii) shall then further be considered in the order of APR along with re-determined fixed cost in APR and incentive and for other parameters, to find out the total revenue entitled to be recovered/ refunded under APR after taking into consideration of the revenue already realized during the period concerned.

(ii)Against FPPC determination by above method any adjustment or recovery or refund shall be done in a manner as determined by the Commission.

B. Formula For Fuel and Power Purchase Cost Adjustment (FPPC) for Generating Stations of Generating Company.Fuel and power purchase cost adjustment against energy sold by generating company to any licensee during adjustment period shall be in terms of the following formula.FPPCA (In Rs.) = {FC + (PPC - CD) + (± A)} - (fc + ppc)Where -

(i)The adjustment period for fuel and power purchase cost will normally be on annual basis, if not otherwise decided by the commission.

(ii)FC (Rs.) : Fuel cost of own generation as per normative parameters fixed by the Commission or on actual basis in absence of any norm and UHV range as may be allowed under regulation 5.8, commensurate with actual level of energy sales by the generating company to the licensee during the adjustment period.

(iii)PPC (Rs.) : Total cost incurred including the cost for fuel for power purchase from different sources commensurate with actual level of pumped energy required by pumped storage hydro-generating station only.

(iv)CD (Rs.) : Cost disallowed by the Commission as having been incurred in breach of its economic generation, or of order I direction of the Commission, if any, or for any other reason considered sufficient by the Commission during the adjustment period and adjusted corresponding to actual level of sales to the licensee.

(v)A (Rs.) Adjustment, if any, to be made in the current period to account for any claim due to excess / shortfall in fuel cost in the past adjustment period based on directions I orders of the Commission. (+A) shall be considered as the amount to be recovered from purchaser of electricity under the purview of the Commission when the generating company has already incurred that expenses. (-A) shall be considered as the amount to be refunded to the purchaser of electricity under the purview of the Commission because such amount of less expenses has been incurred by the generating company against any prior period adjustment.

(vi)fc (Rs.) Fuel cost of own generation for sale to the licensee as allowed by the Commission in the tariff order corresponding to relevant adjustment period,

(vii)ppc (Rs.) : Power purchase cost allowed by the Commission for the relevant adjustment period in the tariff order for pumping energy required by pumped storage hydro-generating station only.

(viii)FPPCA thus determined on normative basis will further be adjusted for gain sharing as per Schedule - 9B for the parameter related to fuel cost only.

Note:- (i) After such re-determination of fuel and power purchase cost adjustment (FPPCA) including gain sharing under (viii) against FPPCA determination by above method any adjustment or recovery or refund shall be done in a manner as determined by the Commission.

7B

[See regulations 2.2.4, 2.8.1.3.1,2.8.7.3, 5.8.9, 5.8.10]Fuel Surcharge Formula for Determination of Monthly Fuel Cost Adjustment (MFCA) and Monthly Variable Cost Adjustment (MVCA)A. Monthly Variable Cost Adjustment (MVCA) for Licensees.- Monthly Variable Cost Adjustment shall be computed as per the following formula.

(a)Value to be taken from tariff order

TL = Normative Transmission loss in %DL = Normative Distribution loss in %esc = Energy sale to consumer and licensee in MU as per tariff orderPPcost = Power purchase cost allowed in the tariff order in Rs.fc = Fuel cost allowed in the tariff order in Rs.PPcost_ex = Power purchase cost/ fuel cost for sale to person other than licensee and consumers as allowed in the tariff order in Rs.

(b)Value to be taken for the month.

The following values shall be taken on monthly basis for the month preceding the month for which MVCA is to be determined.Ulin = Net Power drawal (MU) in UI modeUlout = Net Power exported (MU) in UI modeEp = Total Power purchase (MU) against billEG = Total Sent out from own generation (MU) on normative basis (Excluding normative auxiliary consumption and transformation loss from gross generation)Ex = Energy sold (MU) to person other than licensee and consumersPPcost = Total cost of Power purchase from different sources in Rs.FC = Total fuel cost of own generation as per normative parameters fixed by the Commission in Rs.UI costin = Power purchase cost for Ulin in Rs.

(c)Value to be taken from Order of Adhoc Variable Cost or Adhoc Power Purchase Cost, if any.

Adhoc_Vcost = Adhoc Variable Cost or Adhoc Power Purchase Cost in Rs./kWh

(d)Computation of MVCA

TotENR = Ep + EG + UIinTotENR_Consumer = TOtENR - UIout - ExMVC = Total variable cost incurred for the month preceding the month for which MVCA is to be determined in Rs.= PPcost + FC + UI costinMVCunit = MVC / TotENRMVCconsumer = MVC - MVCunit x (Ulout + Ex)Esc = Energy sale to consumer and licensee for the month preceding the month for which MVCA is to be determined in MU= TotENR_Consumer x (1 - TL x 0.01) x (1 - DL x 0.01)MVCunit_consumer = MVCconsumer/(Esc x 106MVCconsumer = Variable cost as per tariff order in Rs.= PPcost + fc - PPcost_exMVCunit_consumer = mvcconsumer/(esc x 106)MVCA = Monthly variable cost adjustment in Paise / Kwh.= (MVCAunit_consumer - mVCunit_consumer Adhoc_Vcost) x 100 Paise / KwhNote:- (a) The above MVCA shall be calculated on monthly basis for a month based on the normative fuel cost of own generation and power purchase bill received for the month preceding the month for which MVCA is to be determined within the 15th day of the month for which MVCA is to be determined. Determination of own generation cost for the above purpose shall be calculated on monthly basis for a month based on the normative fuel cost for generation based on the fuel related cost payable for the month preceding the month for which MVCA is to be determined within the 15th of the month for which MVCA is to be determined. The fuel related cost means cost of fuel and railway freight, including taxes. duties, cess and royalty and other charges, if any, as applicable on them.

(b)While computing as per above formula the regulation 5.8.11 and 5.8.12 of these regulations shall be duly taken into consideration.

(c)The process of determination of MVCA shall not require any audited data and shall be done by the distribution licensee themselves and shall be recovered on monthly basis subject to final adjustment of FPPCA annually based on Audited Annual Accounts.

(d)Where any tariff order is referred for different parameters of the above formula then such parameters shall be taken from the tariff order on the basis of which the tariff is being charged to the consumer or electricity purchaser under the purview of the Commission. Where the normative parameter related to such tariff order is to be used then it shall be taken from that tariff order or the tariff order of the 1st ensuing year of the control period related to the referred tariff order.

(e)Such MVCA will be applicable to all consumers or purchaser of electricity under the purview of the Commission for each unit of consumption as billed for the month to the consumer or purchaser of electricity.

(f)The MVCA is to be rounded off to nearest integer Paisa in lower side.

[Example : If the computed value of MVCA is 7.92 paisa/ kWh then it will be rounded off to 7 paisa/ kWh only]B. Monthly Fuel Cost Adjustment (MFCA) for Generating Stations of Generating Company - Monthly Fuel Cost Adjustment against energy sold by generating company to any licensee during adjustment period shall be in terms of the following formula :

(a)Value to be taken from tariff order

Auxn = Normative auxiliary consumption (%)Oiln = Normative oil consumption rate (ml/Kwh)SHRn = Normative gross station heat rate of the power station (Kcal/Kwh)TL = Normative Transit & Handling Loss (%)ECT = Average energy cost for sent out energy as per tariff order (Rs/Kwh)

(b)Value to be taken for the month.

The following values shall be taken on monthly basis for the month preceding the month for which MFCA is to be determined.Eg = Sent out energy from the Power Station (MU)Oilprice = Price of Oil (Rs/KL)Oilgcv = GCV of oil (Kcal/lit)CoalUHV = Average permissible Useful Heat Value (UHV) of coal purchased (Kcal/Kg)Coalprice = Average coal price Rs/MT

(c)Value to be taken from Order of Adhoc Fuel Cost, if any.

Adhoc_Fcost = Adhoc Fuel Cost in Rs./kWh

(d)Computation Formula for MFCA

Gn = Normative generation of the power station (MU) = Eg/(1-Auxn x 0.01)oilc = Total Oil cost on normative oil consumption (Rs.) = Gn x Oiln X OilpriceOilHeat = Heat generated from oil consumption (Kcal) = Gn x Oiln x Oilgcv x 103TH = Total Normative heat required for sent out generation (Kcal)= Gn x SHRn x 106FH = Heat required from coal (or primary fuel) (Kcal) = TH - OilHeatCoalcon = Normative coal consumption (MT) = FH / ( CoalUHV x 1000)Coalreq = Normative Coal required (MT) = Coalcon/(1 - TL x 0.01)TCc = Total coal cost on normative coal required (Rs) = Coalreq x CoalpriceECavg = Average energy cost for sent out energy (Rs / Kwh) = TCc+Oilc/Eg x 106MFCA = Monthly fuel cost adjustment for per unit of sent out energy (Paise/ Kwh) = (ECavg - ECT Adhoc_Fcost) x 100 Paise/KwhNote:- (a) The above MFCA shall be calculated on monthly basis for a month based on the normative fuel cost for generation based on fuel related cost payable for the month preceding the month for which MFCA is to be determined within the 15th of the month for which MFCA is to be determined. The fuel related cost means cost of fuel and railway freight, including taxes, duties, cess and royalty and other charges, if any, as applicable on them.

(b)While computing as per above formula the regulation 5.8.11 and 5.8.12 of these regulations shall be duly taken into consideration.

(c)The process of determination of MFCA shall not require any audited data and shall be done by the generating company themselves and shall be recovered on monthly basis subject to final adjustment of FPPCA annually based on Audited Annual Accounts.

(d)Where any tariff order is referred for different parameters of the above formula then such parameters shall be taken from the tariff order on the basis of which the tariff is being charged to the electricity purchaser under the purview of the Commission. Where the normative parameter related to such tariff order is to be used then it shall be taken from that tariff order or the tariff order of the 1st ensuing year of the control period related to the referred tariff order.

(e)Such MFCA will be applicable to all purchaser of electricity for each unit of sale of electricity to them as billed against the month to the purchaser of electricity.

(f)The MFCA is to be rounded off to nearest integer Paisa in lower side.

[Example : If the computed value of MFCA is 7.92 paisa/ kWh then it will be rounded off to 7 paisa/ kWh only]

Schedule 8

[See regulation 2.2.4 and 6.5.3 (ii)]Payable and Receivables under UI charges

1. When average frequency for 15 minutes time block of state grid frequency is f Hz or below, the UI charge payable or receivable by different candidates depends on the following conditions:

(i)When injector injects power more than scheduled injection, it will result into UI charge receivable by that injector;

(ii)When injector injects power less than scheduled injection, it will result into UI charge payable by that injector;

(iii)When drawers draw power more than the scheduled drawal it will result into UI charge payable by that drawer;

(iv)When drawers draw power less than the scheduled drawal it will result into UI charge receivable by that drawer;

Provided this receivable or payable is subject to all the conditions as specified in regulation 6.5.2 of these regulations.

2. For the purpose of this Schedule the f will be considered as specified in regulation 6.5.2.

9A

Operating Norms(See regulations 2.5.1(ii), 2.5.1(iv), 2.5.3, Table 2.5.5-1, 2.5.6.1, 2.8.1.4.2(i)(b), 2.8.1.4.4(ii), 2.8.1.4.8, 2.8.4.2.1(c), 2.8.4.2.4, 2.8.6.1, 2.8.6.2, 2.8.6.3, 2.8.6.8, 2.8.6.9, 2.8.6.12, 4.6.1(iii), 6.1.1, 6.4.2, Para 8.1(iii) of Schedule -1, Para 8.1 of Schedule - 5, Para A3(iii) of Schedule - 9B, Para A of Schedule - 9D, Para B of Schedule - 9D, Para 1 of Schedule - 10, Para 6 of Schedule - 10)A. Recommended Annual Norms of Gross Statsion Heat Rate for Coal Fired Thermal Generating Stations under Operation and under Construction :

Gen. Station / Unit	Recommended Gross Station HeatRate Kcal/Kwh
2011-12	2012-13	2013-14
CESC :	2500	2480	2470
Budge Budge TPS	3 x 250MW
Southern Generating Station	2 x 67.5 MW	2910	2905	2900
Titagarh TPS	4 x 60MW	2920	2915	2910
New Cossipore Generating Station	100 MW	5800	5800	5800
WBPDCL	2500	2485	2470
Bakreshwar TPS	5 x 210MW
Kolaghat TPS	6 x 210MW	2700	2700	2700
Bandel TPS	4 x 60 + 1 x 210MW	2900	2900	2900
4 x 60 MW	3050	3050	3050
1 x 210 MW	2750	2750	2750
Santaldihi TPSSagardighi TPS	1 x 250 MW	2425	2425	2425
2 x 250 MW	2425	2425	2425
2 x 300 MW	2345	2345	2345
Durgapur Projects Power Station	1 x 30 MW	3250	3250	3250
3 x 77 MW + 1 x 100 MW	3100	3100	3100
1 x 300 MW	2345	2345	2345
1 x 30 MW + 3 x 77 MW +1 x 110 MW	3125	3125	3125
1 x 30 MW + 3 x 77 MW +1 x 110 MW + 1 x 300MW	2800	2800	2800
DPSCL	Disergarh TPS (Old Units)	5800	5800	Scheduled For closing by 2012-13
Chinakuri TPS 3 x 10 MW	3750	3746	3746

Note:-- (i) Where the sizes of different units of the same generating station vary, the respective contribution by such units to the gross station heat rate have been shown separately with a view to facilitate modification of norms by the Commission under unusual circumstances like outage of any unit for a period of three months or more at a stretch, or time over-run of new units under construction.

(ii)The gross station heat rate of any coal fired thermal generating station shall always be computed on the basis of generating station as a whole without any special consideration being given to the possible impact of any individual unit on the plant except when there is an outage of any unit over three months or more at a stretch, or there is a time overrun of a new proposed unit.

(iii)During stabilization period of new units, additional gross station heat rate on the basis of actual generation will be applicable, subject to a ceiling of 50 Kcal/Kwh.

(iv)New Cossipore Generating Station shall be operated last in the merit order.

B. Recommended Annual Norms of Plant Load Factor (PLF) of Coal Fired Thermal Generating Stations under Operation and under Construction for incentive :

Generating Station	PLF NORM IN %
2011-2012	2012-2013	2013 -2014
WBPDCL
Bakreshwar TPS	5x210 MW	80	80	80
Kolaghat TPS	6x210MW	73	73	73
Bandel	4x60 MW	62	65	65
1x210MVV	71	72	73
4x60 MW+1x210MW	66	68	69
Santaldih TPS	½ x250 MW	80	80	80
Sagardighi TPS	2x300 MW	80	80	80
CESC
Budge Budge TPS	2/3x250 MW	80	80	80
Southern Generating Station	2x67.5 MW	80	80	80
Titagarh Generating Station	4x60 MW	80	80	80
New Cossipore	100 MW	80	80	80
DPL	1x30 MW	20	20	20
3x77 MW	72	72	72
1x110 MW	64	64	64
1x300 MW	80	80	80
1x30 MW+3x77 MW+1x110 MW	66	66	66
1x30 MW+3x77 MVV+1 x110+1 x300 MW	72	72	72
DPSCL	Chinakuri TPS 3x10 MW	80	80	80
Dishergarh TPS (Old Units)	48	48	48
For BTPS, PLF is to be considered on the basis ofde-rated units

Note:-- (i) The norms of PLF of those coal fired thermal generating stations that have units of different sizes, such as DPL and Bandel TPS are the weighted averages of the unit load factors based on the weightage of installed capacity of individual units, subject to the rounding off to the nearest whole number.

(ii)The generations from DPL 30 MW unit have been considered at a reduced level in view of a near certitude, of the closure of these units in the future.

(iii)If there is a time over run in commissioning of a new unit of an existing coal fired thermal generating station, then the normative PLF of the generating station as a whole shall be freshly determined in the tariff order or APR of the concerned year on the weighted pro-rata basis of the unit load factor of each unit based on weightage of installed capacities considered for the units under considerations and COD of the new units.

(iv)DPL shall run 30 MW unit only to meet evening peak shortages, or during any other high shortage scenario or in order to meet any emergency. Any losses incurred under any head caused by generation in contravention of the above stipulations shall disqualify to be a pass through in tariff or FPPCA. Any loss of generation due to lower priority of running 30 MW unit as mentioned above will be duly taken care of by reducing the target generation, target availability along with necessary adjustment in target oil consumption, station heat rate, auxiliary energy consumption and / or 0 & M expenses during Annual Performance Review based on the actual generation of 30 MW unit. However these stipulations shall not apply if specific and prior approval of the Commission is obtained for running the 30 MW unit during any extra-ordinary but non peak, or non shortage or non emergency periods.

(v)The generation from 30 MW unit of DPL will not be considered for incentive under paragraph-1 of schedule-10.

(vi)The PLF of any coal fired thermal generating station, shall always be computed on the basis of generating station as a whole without any special consideration being given to the possible impact of any individual unit on the plant.

C. Recommended Annual Norms of Target Plant Availability Factor for Coal Fired Thermal Generating Stations under Operation and under Construction :

Generating Stations	Recommended Target Availabilityin %
2011-12	2012-13	2013-14
CESC :
Budge Budge TPS	3x250 MW	85	85	85
Southern Generating Station	2x67.5 MW	85	85	85
Titagarh TPS	4x60MW	85	85	85
New Cossipore Generating Station	100 MW	50	50	50
WBPDCLBakreshwar TPS	5x210 MW	85	85	85
Kolaghat TPS	6x210MW	78	78	78
Bandel TPS	4x60 MW	67	70	70
1x210MW	76	77	78
4x60 MW+1x210 MW	71	73	74
Santaldihi TPS	½x250 MW	85	85	85
Sagardighi TPS	2x300 MW	85	85	85
DPL	1x30 MW	25	25	25
3x77 MW	77	77	77
1x110 MW	69	69	69
1x300 MW	85	85	85
3x77 MW+1x100 MW	74	74	74
1x30 MW+3 x77 MW+ 1x 110 MW	70	70	70
3x77 MW+1x110 MW+1x300 MW	79	79	79
1x30 MW+3x77 MW+1x 110 MW+1x300 MW	75	75	75
DPSCLTPS	Disergarh (Old Units)	48	48	Scheduled for closing by 2012-13
Chinakuri TPS 3x10 MW	82	82	82

Note:-- (i) For the purpose of determination of the norms of overall plant availability factor of the concerned generating station, the norms of availability factor of each unit has been taken to be of 85% for the new units of the existing generating stations such as Budge Budge Unit 3 and Bakreshwar Unit 4 and 5.

(ii)The norms of plant availability factor of those coal fired generating stations that have units of different sixes, such as DPL and Bandel TPS are the weighted averages of the availability factor of the units, based on the weightage of installed capacities of each unit subject to the rounding off to the nearest whole number.

(iii)If there is a time over run in commissioning of a new unit of an existing coal fired thermal generating station, than the normative plant availability factor of the generating station as a whole shall be freshly determined in the tariff order or APR of the concerned year on the weightage pro-rate of the availability factor of each unit under considerations and COD of the new units.

(iv)The availability of any coal fired thermal generating station, shall always be computed on the basis of generating station as a whole without any special consideration being given to the possible impact of any individual unit on the plant.

D. Recommended Annual Norms of Auxiliary Energy Consumption (AEC) on generation basis for Coal Fired Thermal Generating Stations under Operation and under Construction:

Generating Stations	Recommended Auxiliary EnergyConsumption (AEC) in %
2011-12	2012-13	2013-14
CESC :
Budge Budge TPS	3x250 MW	9.00	9.00	9.00
Southern Generating Station	2x67.5 MW	9.00	9.00	9.00
Titagarh TPS	4x60MW	9.00	9.00	9.00
New Cossipore Generating Station	100 MW	10.00	10.00	10.00
WBPDCL
Bakreshwar TPS	5x210 MW	9.00	9.00	9.00
Kolaghat TPS	6x210MW	9.80	9.70	9.60
Bandel TPS	4x60 MW	10.60	10.50	10.4
1x210MW	9.70	9.50	9.4
4x60 MW+1x210 MW	10.15	10.05	9.95
Santaldihi TPS	½x250 MW	9.00	9.00	9.00
Sagardighi TPS	2x300 MW	9.00	9.00	9.00
DPL	1x30 MW	10.10	10.00	10.00
3x77 MW	10.00	10.00	10.00
1x110 MW	10.00	10.00	10.00
1x300 MW	8.50	8.50	8.50
1x30 MW+3 x77 MW+ 1x 110 MW	10.05	10.00	10.00
1x30 MW+3x77 MW+1x 110 MW+1x300 MW	9.35	9.35	9.35
DPSCL	Disergarh (Old Units)	10.85	10.80	Scheduled for closing by 2012-13
Chinakuri TPS 3x10 MW	10.00	10.00	10.00

Note:-(i) The norms of auxiliary energy consumption rate of those coal fired generating stations that have units of different sizes, such as DPL, Bandel TPS and Santaldihi TPS, are the weighted averages of the norms of auxiliary energy consumption rates of different units, based on the weightage of normative generation for incentive of each individual units, subject to the rounding off to two decimal places in multiples of 0.05 on higher side.

(ii)If there is a time over run in commissioning of a new unit of an existing coal fired thermal generating station, then the normative auxiliary consumption of that generating station as a whole shall be freshly determined in the tariff order or APR of the concerned year on the weighted pro-rata of auxiliary energy consumption rate of each unit based on the weightage of normative generations of the units under considerations and COD of the new units.

E. Recommended Annual Norms of Oil Consumption on generation basis for Pulverized Coal Fired Thermal Generating Stations under Operation and under Construction :

Generating Stations	Recommended oil consumption(ml/kWh)
2011-12	2012-13	2013-14
WBPDCL
Kolaghat TPS	6x210 MW	2.00	2.00	2.00
Bandel TPS	4x60 MW	3.50	3.00	2.50
1x210 MW	2.00	2.00	2.00
4x60+1x210 MW	2.75	2.50	2.25
Santaldihi TPS	1/2x250 MW	1.00	1.00	1.00
Bakreshwar TPS	5x210 MW	1.30	1.30	1.30
Sagardighi TPS	2x300 MW	1.00	1.00	1.00
CESC
Budge Budge TPS	3x250 MW	1.30	1.30	1.30
Southern Generating Station	2x67.5 MW	2.20	2.15	2.10
Titagarh TPS	4x60 MW	2.20	2.15	2.10
DPL	3x77 MW	2.40	2.30	2.20
1x30 MW	5.00	4.75	4.50
1x110 MW	3.25	3.00	2.75
1x300 MW	1.00	1.00	1.00
1x30+3 x77+1 x100 MW	3.05	2.90	2.70
1x30+3x77+1x110+1x300 MW	22.0	2.10	2.00

Note:-- (i) The norms of oil consumption rate of those coal fired thermal generating stations that have units of different sizes. such as DPL. Bandel TPS and Santaldihi TPS, are the weighted averages of the norms of oil consumption rates of different units based on the weightage of normative generation of the individual units for incentive, subject to the rounding off to nearest two decimal as multiples of 0.05 preferably on higher sides except few cases, for smoothening of trajectory.

(ii)If there is a time over run in commissioning of a new unit of an existing coal fired thermal generating station, then the normative oil consumption rate of that generating station as a whole shall be freshly determined in the tariff order or APR of the concerned year on the weighted pro-rata of oil consumption rate of each unit based on normative generations of the units under considerations and COD of the new units.

(iii)During the stabilization period of new units, additional oil consumption on the basis of actual generation but subject to a ceiling rate of 3.5 ml/KWh will be allowable.

F. Recommended Annual Norms of Transit and Handling Losses of coal for Coal Fired Thermal Generating Stations under Operation and under Construction :

Coal Fired Generating Stations	Recommended Transit &Handling Loss (%)
2011-12	2012-13	2013-14
Generating Stations of CESC	0.75	0.75	0.75
WBDPCL
Bakreshwar	0.50	0.50	0.50
Kolaghat	0.80	0.80	0.80
Bandel	0.80	0.80	0.80
Santaldihi	0.80	0.80	0.80
Sagardighi	0.80	0.80	0.80
DPL	0.50	0.50	0.50
Generating Stations of DPSCL	0.3	0.3	0.3

G. Recommended Annual Norms of Operation and Maintenance (O&M) Expenses for a Coal Fired Thermal Generating Stations under Operation and under Construction :

Generating Station	Computed O&M Expenses in Rs. Lakh / MW
2011-12	2012-13	2013-14
Budge Budge TPS : 3 x 250 MW	10.39	10.7	11.02
Bakreshwar TPS : 5 x 210 MW	8.43	8.85	9.29
Kolaghat TPS : 6 x 210 MW	10.67	11.1	11.54
Bandel TPS : 4 x 60 MW + 210 MW	11.48	12.05	12.65
Santaldih TPS : 1 x 250 MW	11.48	12.05	12.65
Santaldih TPS : 2 x 250 MW	7.09	7.44	7.81
DPL : 2 x 30 MW + 3 x 77 MW + 110 MW	14.77	15.07	15.22
DPL : 1 x 300 MW	6.03	6.33	6.65
Sagardighi TPS : 2 x 300 MW	6.03	6.33	6.65
Southern Generating Station : 2 x 67.5 MW	12.29	12.66	13.04
Titagarh TPS : 4 x 60 MW	12.08	12.44	12.81
New Cossipore TPS 100 MW	15.6	16.38	17.2
Chinakuri TPS : 3 x 10 MW	11.7	12.29	12.9
Disergarh TPS : (Old Units)	15.31	16.08	Scheduled for closing by 2012-13

Note:-- (i) The above O&M expenses are against the provisions of regulation 5.7;

(ii)The above O&M expenditure is exclusive of lease rental charges which have been covered separately by regulation 5.6.6 of the instant regulations.

H. Recommended Annual Man! MW Ratio for determination of Employee Cost for Coal Fired Thermal Generating Stations under Operation and under Construction

Generating Station	Recommended MAN / MW Ratio
2011-12	2012-13	2013-14
Budge Budge TPS : 3x250 MW	1.58	1.58	1.58
Bakreshwar TPS 5x210 MW	1.58	1.55	1.55
Kolaghat TPS 6x210 MW	2.00	2.00	2.00
Bandel TPS : 4x60 MW+210 MW	3.50	3.50	3.50
Santaldih TPS : 1x250 MW	1.40	1.40	1.40
Santaldih TPS : Combined	2.45	2.45	2.45
DPL 1x30 MW+3x77 MW+110 MW	3.50	3.50	3.50
DPL 7th Unit	1.20	1.20	1.20
Sagardighi TPS 2x300 MW	1.35	1.35	1.35
Southern Generating Station : 2x67.5 MW	3.50	3.50	3.50
Titagarh TPS : 4x60 MW	3.00	3.75	3.75
New Cossipore TPS : 100 MW	7.40	7.25	7.25
Chinakuri TPS : 3x10 MW	6.43	6.33	6.23
Disergarh TPS (Old Units)	16.00	15.5	Scheduled for closing by 2012-13

Note:-- (i) The above Man/ MW ratio for different plants has considered all regular employees of own establishment as also all contracted manpower in the regular establishment, irrespective of whether the latter has been contracted directly or indirectly.

(ii)This Man/MW ratio in the above table is only for the purpose of determination of the cost of employees.

(iii)The tariff application of a licensee having its own generation activity shall, show its manpower engaged in generating station(s) and manpower engaged in business other than generation separately.

(iv)In case of operation of any of the activities of a licensee through a contract, the cost allowed for the contract shall be subject to a ceiling arrived at on the basis of said manpower and the average cost per employee in the licensees regular establishment for the same category of employees.

(v)Due to de-commissioning of old unit(s) of any existing generating station, the expenditure of the surplus man power will be allowed in the tariff after considering the due adjustment of such manpower to any new unit(s) of any generating station or any other part of the business by the generating company or licensees.

I. Stabilisation Period : In relation to a unit, stabilization period shall be reckoned commencing from the date of commercial operation of that unit as follows :

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

(b)Gas Turbine/Combined cycle generating stations - 90 days

J. Norms of Distribution Losses for Different Distribution Licensees :

Norms of Distribution Loss in Percentage ofDistribution Licensees
Distribution Licensee	2011-12	2012-13	2013-14
WBSEDCL	17.75	17.5	17.5
CESC	14.60	14.45	14.3
DPL	5.5	5.3	5.2
DPSCL	5.25	5.25	5.25
DVC	2.4	2.3	2.2

Note:- If any licensee owns and runs any generating station located outside its area of supply and transmits any energy generated by such a generating station to its area of supply through a dedicated transmission line, the transmission loss associated with such transmission shall be determined by the Commission separately and the same shall not governed by the distribution loss shown in the above table. In case the licensee sources electricity using its EHV system through any transmission system in the areas beyond the area of supply of the licensee, the Commission shall also determine the loss associated with the EHV system separately and the same shall not be governed by the distribution loss shown in the above table.K. Norms for Transmission Loss for Transmission Licensees :

Transmission Licensee	Transmission Loss In Percentage
2011-12	2012-13	2013-14
WBSETCL	3.60	3.50	3.40
Note:-The norms oftransmission loss in the intra-state transmission system of DVCwill be laid down by the Commission in due course on conclusionof different legal proceedings.

L. Norms for Availability of Transmission System :

Part of Transmission System	Availability of Transmission System inPercentage for WBSETCL
2011-12	2012-13	2013-14
Transmission Line	99.00	99.00	99.00
Sub-Station	97.00	97.00	97.00

M. Norms of Plant Availability Factor Hydro Generating Station for Incentive Purpose :

Norms of Availability Factor
Sl. No.	Type of Hydro Generating Station	Norms of Availability Factor
(i)	Purely run of the river	90%
(ii)	Pondage/storage type run of the river	85%
(iii)	Pumped Storage Type	95%
(iv)	Jaldhaka HEP	85%

Note:- For WBSEDCL Rammam HEP Stage-II, is to be considered as purely run of the river scheme.N. Norms of Auxiliary Energy Consumption of Hydro Generating Stations (including transformation loss) :

Norms of Auxiliary Energy Consumption inPercentage for Existing Hydro Generating Stations
Hydro Generating Station	2011-12	2012-13	2013-14
Rammam Stage-II	1.0	1.0	1.0
Jaldhaka	1.0	1.0	1.0
Purulia Pumped Storage Project	1.2	1.2	1.2
Small Hydro Generating Stations	1.2	1.1	1.0

Note:- Small hydro generating stations mean all existing and future hydro generating stations having capacities of 25 MW or less and under the purview of the Commission, but are not specifically covered by the above table.O. Norms of Pumping Energy for Pumped Storage Hydro Generating Stations : The norms of pumping energy is as per cycling efficiency in % defined as ratio of generation energy to pumping energy where such generation is done due to such quantum of water that has been pumped by the said pumping energy. The norms for such cycle efficiency will be treated as 74%.P. Norms of O&M Expenses of Hydro Generating Stations :

Normative O&M Cost for Hydro GeneratingStations in Rupees Lakh/ Mw only
Name of Plant	Years
	2011-12	2012-13	2013-14
Jaldhaka HEP	8.77	9.12	9.48
Rammam HEP	4.16	4.33	4.5
Small Hydros	2.87	3.02	3.17
Purulia Pumped Storage Project	3.94	4.09	4.26

Q. Recommended Annual Man/ MW Ratio for determination of Employee Cost for Hydro Generating Stations under Operation and under Construction :

Normative Man-Power for Hydro GeneratingStations in Number of Persons per Mw of Installed GenerationCapacity
Name of Plant	Years
	2011-12	2012-13	2013-14
Jaldhaka HEP	7.30	7.10	6.90
Rammam HEP	5.15	4.95	4.75
Small Hydros	10.05	9.90	9.75
Purulia Pumped Storage Project	0.225	0.225	0.225

Note:- (i) The above Man / MW ratio for different generating stations has considered all regular employees of own establishment as also all contracted manpower in the regular establishment, irrespective of whether the latter have been contracted directly or indirectly.

(ii)This Man/MW ratio in the above table is only for the purpose of determination of the cost of employees.

(iii)The tariff application of a licensee having its own hydro generation activity shall, show its manpower engaged in hydro generating station(s) and manpower engaged in business other than generation separately.

R. Recommended norms for Man Power per CKM of Transmission line for determination of Employee Cost for Transmission Licensee's Transmission Business :

Transmission Licensee	No. of Man Power per Ckm of Transmission Lines
WBSETCL	0.35

S. All norms for new Generating Stations : The new generating station not covered under this Schedule 9A shall be covered by the principles laid down in Schedule - 9D.

9B

Gain Sharing(See regulations 2.5.1(iv), 2.6.1, 2.6.5, 2.8.6.2, 2.8.6.3, 2.8.6.8, 2.8.6.12, 2.8.7.1, 2.8.8.2, 5.15.2(iii), Para 8.1 of Schedule-5, Para A.(vii) of Schedule-7A, Para B.(viii) of Schedule-7A)Principle of Gain Sharing Between Electricity Supplier and Purchaser for Performance Better than Operating NormsA. Gain Sharing for Coal Fired Thermal Power Stations - Any gain of a licensee or a generating company operating coal fired thermal generating station(s), that arises from performance of the generating station which is better than the operating norms for that generating station, shall be computed by the difference between the actual performance on the one hand, and the relevant normative values on the Other, expressed in monetary terms, and such gains shall be shared between the supplier of electricity and the purchaser of the same.A1. Gain Sharing For Better Oil Consumption Rate : When gains in a pulverized coal fired thermal generating station accrue from actual performance in respect of oil consumption in a year being better than the norms in this behalf. the gains shall be shared between that generating station on the one hand, and the distribution licensee on the other, the latter being the purchaser of electricity from that generating station. Where the distribution licensee itself is the owner of the generating station, the performance of which in respect of oil consumption betters the norms, the resultant gains shall be shared between the distribution licensee on the one hand and the purchaser(s) of the electricity from that distribution licensee on the other, i.e., consumers or other licensees as the case may be. The gains shall be shared in the manner shown in the following table.

Sl. No.	Criteria	Sharing of Gain (G) Between Generating Stationand Purchaser of Electricity for Following Category of GeneratingStation
		Category A	Category B	Category C
1	(OILn-0.25 ml/Kwhr) OIL < OILn	60%: 40%	55%: 45%	50%: 50%
2	(OILn-0 50 ml/Kwhr) < OIL < (OILn-0.25ml/Kwhr	65%: 35%	60% : 40%	55% : 45%
2	(OILn-0.75 ml/Kwhr) < OIL <(OILn-0.50 ml/Kwhr)	70%: 30%	65% : 35%	60% : 40%
4	(OILn-1.0 ml/Kwhr) < OIL<(OILn-0.75 ml/Kwhr)	74% 26%	70%: 30%	65%: 35%
5	(OILn-1,25 ml/Kwhr) < OIL<(OILn-1. 0 ml/Kwhr)	Not Applicable	74%: 26%	70%: 30%
6	(OILn-1.50 mliKwhr) < OIL<(OILn-1.25 ml/Kwhr)	Not Applicable	77% : 23%	74% : 26%
7	OIL < (OILn-1.5 ml/Kwhr)	Not Applicable	80%: 20%	77% 23%

Where OILn = Norms for oil consumption rate in ml/Kwhr for the year under consideration;OIL = The actual oil consumption in ml/ Kwhr for the year underconsideration; andG = Total generation in million unit x (OILn - OIL) in ml/Kwhr x price of oil in Rs/KL when OILn > OIL; orG = 0 when OILn < OILCategory A = The generating station whose OILn < 1Category B = The generating station whose OILn > 1 and OILn < 2Category C = The generating station whose OILn > 2Note:- If the gain accruing to a generating station belonging to any criteria group (indicated by a serial number against each criteria group) is found to be less than the gain accruing at lower criteria group (indicated by a lesser serial number against that criteria group), then it is the latter gain that shall be considered for the generating station. This shall hold good irrespective of the categories to which the generating stations in question may belong to Also, if the gain accruing to any generating station belonging to category A is found to be less than the gains accruing at same criteria group in category B or Category C, then it is the latter gain that shall be considered for former generating station. This shall hold good irrespective of the criteria groups (indicated by the serial number against each criteria group) to which the generating stations in question may belong to. The same principle shall apply mutatis mutandis for a generating stations belonging to categories B and C categories respectively.A2. Gain Sharing For Better Auxiliary Consumption : When gains in a coal fire thermal generating station accrue from actual performance in respect of auxiliary energy consumption in a year being better than the norms in this behalf, the gains shall be shared between the generating station on the one hand and the distribution licensee on the other, the latter being the purchaser of electricity from the generating station. Where the distribution licensee itself is the owner of the generating station, the performance of which in respect of auxiliary consumption betters the norms, the resultant gains shall be shared between the distribution licensee on the one hand and the purchaser(s) of electricity from that distribution licensee on the other, i.e., consumers or other licensee(s) as the case may be. The gains shall be shared in the manner shown in the following table.

Auxiliary Energy Consumption for Coal FiredThermal Generating Station with Cooling Tower and ElectricallyDriven Pumps
Sl.No.	Criteria	Sharing of Gain (G) Between Generating Stationand Purchaser of Electricity for Following Category of GeneratingStation
		Category A	Category B	Category C
1	(Auxn- 0.5%) < Aux < Auxn	70% 30%	60% : 40%	50% : 50%
2	(Auxn- 0.75%) < Aux <(Auxn- 0.5%)	75% 25%	70% : 30%	60% : 40%
3	( Auxn- 1.0%) < Aux <(Auxn- 0.75%)	80% 20%	75% : 25%	70% : 30%
4	( Auxn- 1.5%) <. Aux <( Auxn- 1.0%)	85% : 15%	80% : 20%	75% : 25%
5	Aux < ( Auxn- 1.5%)	88% : 12%	85% : 15%	80% : 20%
Category A = The generating station whose Auxn< 9%Category B = The generating station whose Auxn> 9% and Auxn< 10%Category C = Thegenerating station whose Auxn> 10%Note: This table will be applicable for unit below 200MW set and alsofor generating set of 200MW and above with cooling tower andelectrically driven boiler feed pump.

Auxiliary Energy Consumption for Coal FiredThermal Generating Station of capacity of 200MW and above withElectrically Driven Pumps but without cooling Tower
Sl.No.	Criteria	Sharing of Gain (G) Between Generating Stationand Purchaser of Electricity
		Category A	Category B	Category C
1	(Auxn- 0.5%) < Aux < Auxn	70% 30%	60% : 40%	50% : 50%
2	(Auxn- 0.75%) < Aux <(Auxn- 0.5%)	75% 25%	70% : 30%	60% : 40%
3	( Auxn- 1.0%) < Aux <(Auxn- 0.75%)	80% 20%	75% : 25%	70% : 30%
4	( Auxn- 1.5%) <. Aux <( Auxn- 1.0%)	85% : 15%	80% : 20%	75% : 25%
5	Aux < ( Auxn- 1.5%)	88% : 12%	85% : 15%	80% : 20%
Category A = The generating station whose Auxn< 8.5%Category B = The generating station whoseAuxn> 8.5% and Auxn<9.5%Category C = The generating station whose Auxn>9.5%

Where Auxn (in %) = norms for auxiliary consumptions for a generating stations for the year under considerations;Aux (in %) = actual auxiliary consumption by the generating station for the year under consideration; andG = Excess Units sent out from generating station due to improved performance over the norms x (Energy Cost per unit in rupees of the generating station + annual capacity charge per unit in rupees of the generating station when generation is achieved as per norms or above)Note:- (i) If the gain accruing to a generating station belonging to any criteria group (indicated by a serial number against each criteria group) is found to be less than the gain accruing at lower criteria group (indicated by a lesser serial number against that criteria group), then it is the latter gain that shall be considered for the generating station. This shall hold good irrespective of the categories to which the generating stations in question may belong to. Also, if the gain accruing to any generating station belonging to category A is found to be less than the gains accruing at same criteria group in category B or Category C, then it is the latter gain that shall be considered for former generating station. This shall hold good irrespective of the criteria groups (indicated by the serial number against each criteria group) to which the generating stations in question may belong to. The same principle shall apply mutatis mutandis for a generating stations belonging to categories B and C categories respectively.

(ii)When auxiliary energy consumption rate is higher than the applicable norms then G = 0.

A3. Gain Sharing For Better Gross Station Heat Rate : When the gains in a coal fired thermal generating station accrue from actual performance in respect of gross station heat rate in a year being better than the norms in this behalf, the gains shall be shared between the generating station on one hand and the distribution licensee on the other hand, the latter being the purchaser of electricity from that generating station. Where the distribution licensee itself is the owner of the generating station, the performance of which in respect of gross station heat rate betters the norms, the resultant gains shall be shared between the distribution licensee on the one hand and the purchased(s) of electricity from that distribution licensee on the other, i.e., consumers or other licensee(s) as the case may be. The gains shall be shared in the manner shown in the following table :

Sl. No.	Criteria	Sharing of Gain (G) BetweenGenerating Station and Purchaser of Electricity for FollowingCategory of Generating Stations
Category A	Category B	Category C
1	SHRnx 0.99 < SHR< SHRn	70% , 30%	60% 40%	50% : 50%
2	SHRnx 0.98 SHR < SHRnx0.99	75% : 25%	70% : 30%	60% : 40%
3	SHRnx 0.97 SHR < SHRnx0.98	80% : 20%	75% : 25%	70% : 30%
4	SHRnx 0.96 < SHR< SHRnx 0.97	85% : 15%	81% : 19%	76% : 24%
5	SHR < SHRnx 0.96	88% : 12%	86% : 14%	80% : 20%

WhereCategory A = The generating station whose SHRn < 1.05 x DCategory B = The generating station whose SHRn < 1.10 x D and SHRn > 1.05 x DCategory C = The generating station whose SHRn > 1.10 x DD = Design Gross Station Heat Rate;SHRn = Gross Station Heat Rate in Kcal/Kwhr as per norms for the year under consideration;SHR = Actual Gross Station Heat Rate in Kcal/Kwhr in the year under consideration; andG = Fuel cost saving in Rs. for overall actual generation when such generation is equal to or better than the norms.Note :- i. If the gain accruing to any generating station belonging to any criteria group (indicated by the serial number against each criteria group) is found to be less than the gain accruing at a lower criteria group (indicated by a lesser serial number against that criteria group), then it is the latter gain that shall be considered for the aforesaid first generating station. This shall hold good irrespective of the categories to which the generating stations in question may belong to.ii. In case of non-availability of design heat rates of all the units of a coal fired thermal generating station or in case of availability of design heat rates of only some of the units of such a generating station or in case of non-acceptance by the Commission of the design heat rate(s) submitted by the owner of such generating station, the generating station in question shall be considered as category C thermal generating stations.iii. The design station heat rate of any coal fired thermal generating stations under construction as on 15.10.2007 and not considered specifically in the Schedule-9A or the same for any similar coal fired thermal generating stations to be constructed thereafter, shall not be considered at a value higher than the station heat rate to be found in an equivalent coal fired thermal generating station existing and functioning at that time.iv. For the purpose of these regulations the design gross station heat rate (D) for different units of thermal generating stations are as follows :

Gen. Station / Unit	Design Gross station Heat Rate in Kcal / KWhr
CESC :
Budge Budge TPS Unit 1 & 2	2261
Budge Budge TPS Unit 3	2220.1
Southern Generating Station Unit 1 & 2	2707
Titagarh Generating Station Unit 1 to 4	2659
New Cossipore Generating Station 100 MW	2920
WBPDCL
Bakreswar Thermal Power Station Unit 1 to Unit 3	2257.6
Bakreswar Thermal Power Station Unit 4 to Unit 5	2257.6
Kolaghat Thermal Power Station Unit 1 to Unit 6	2386.57
Bandel Thermal Power Station Unit 1 to 4	2603.14
Bandel Thermal Power Station Unit 5	2386.57
Santaldihi Thermal Power Station Unit 1 to 4	2298
Santaldihi Thermal Power Station Unit 5	2220.1
Sagardighi Thermal Power Station Unit 1 & 2	2160
Durgapur Project Limited
DPL Unit 1 TO6	Not Available
DPL UNIT 7	2160
DPSCL
Disergarh TPS 12.2 MW	Not Available
Chinakuri Unit 1 to 3	Not Available

Above design value of gross station heat rate is at the generator terminal end. Where the design gross station heat rate of thermal power station has different design heat rate for different units or cluster of units then the value of design gross station heat rate (ID) of that thermal generating stations will be computed on the basis of weighted average of the normative generation.B. Gain Sharing for Hydro Generating Stations The gains accruing to a hydro generating station due to its performance being better than the norms in any year, may be retained by that station.C. Gain Sharing for Distribution Licensee The gains accruing to a distribution licensee due to its performance in distribution loss being better than the norms of distribution loss in any year, may be retained by that distribution licensee subject to gain sharing applicable separately for fuel cost of own generation as specified in paragraph A of Schedule-7A during FPPC determination.D. Some Restrictions on Gain Sharing In case of availability of a generating station of either a generating company or a licensee falls below the availability norm, then the total gains meant to be passed on to consumers, which shall represent the sum of the sharable gains under paragraph A to paragraph D, shall be used first to compensate the deficit in fixed charge recovery of the concerned generating station by the generating company or the licensee as the case may be, and only thereafter the balance if any shall be passed on to consumers. In such an event, the computation shall be generating station specific.

9C

(See regulation 2.8.1.4.14, 5.6.4.2(vi). Para 7(a) of Schedule-10, Para 10 of Schedule-10)Norms For Construction Period

1. Coal Fired Thermal Power Stations

Sl. No.	Type of Coal fired Generating Stations	Norms of Duration of Construction in months
1	Below 500 MW	42
2	Above or more than 500 MW	54
3	Project whose order is placed before 1.1.2007	45

The above norms of duration of construction are applicable only to the first units of any coal fired thermal generating stations. For subsequent units the norms of COD period shall be considered at a gap of six months for each additional unit.Illustration :- If there is project of coal fired thermal generating station consisting of three units of 250 MW set, the norms of COD from the zero date for the first unit shall be 42 months, the same for the second unit shall be 48 months and the same for the third unit shall be 54 months.

2. Hydro Power Stations - As per contract agreement.

3. Duration Of Construction - Duration of construction of a generating station shall be the period between zero date of the project and COD where zero date is the date of placement of order of boiler or turbine whichever is earlier.

9D

(See regulations 2.5.1(ii), 2.5.1(iv), 2.5.6.1, Table 2.5.5-1, 2.8.1.4.2(i)(b), 2.8.4.2.4, 2.8.6.1, 2.8.6.2, 2.8.6.8, 2.8.6.12, 4.6.1(iii) Para 8.1 (iii) of Schedule-1, Para S of Schedule-9A)A. Norms of operation for New Thermal Generating Station not covered under Schedule - 9A

(1)Gross Station Heat Rate (GSHR):

(a)Coal-based and lignite-fired Thermal Generating Stations

GSHR = 1.065 x Design Heat Rate (kCal/kWh)Where the Design Heat Rate of a unit means the unit heat rate guaranteed by the supplier at conditions of 100% MCR, zero percent make up, design coal and design cooling water temperature/back pressure.Provided that the design heat rate shall not exceed the following maximum design unit heat rates depending upon the pressure and temperature ratings of the units :

Pressure Rating (Kg/cm2)	150	170	170	247	247
SHT / RHT (0C)	535/535	537/537	537/565	537/565	565/593
Type of BFP	Electrical Driven	Turbine Driven	Turbine Driven	Turbine Driven	Turbine Driven
Max Turbine Cycle Heat rate (kCal/kWh)	1955	1950	1935	1900	1850
Min. Boiler Efficiency
Sub-Bituminous Indian Coal	0.85	0.85	0.85	0.85	0.85
Bituminous Imported Coal	0.89	0.89	0.89	0.89	0.89
Max Design Unit Heat rate (kCal/kWh)
Sub-Bituminous Indian Coal	2300	2294	2276	2235	2176
Bituminous Imported Coal	2197	2191	2174	2135	2079

Provided further that in case pressure and temperature parameters of a unit are different from above ratings, the maximum design unit heat rate of the nearest class shall be taken :Provided also that where unit heat rate has not been guaranteed but turbine cycle heat rate and boiler efficiency are guaranteed separately by the same supplier or different suppliers, the unit design heat rate shall be arrived at by using guaranteed turbine cycle heat rate and boiler efficiency.Provided also in case there is one or more units declared under commercial operation under Schedule-9A and there are some units declared under commercial operation under this schedule then the norms of heat rate for power station shall be on weighted average basis.Provided also that in case of lignite-fired generating station (including stations based on CFBC technology), maximum design heat rates shall be increased using factor for moisture content given as follows.

(a)For lignite having 50% moisture : 1.10

(b)For lignite having 40% moisture : 1.07

(c)For lignite having 30% moisture : 1.04

(d)For other values of moisture content, multiplying factor shall be prorated for moisture content between 30-40% and 40-50% depending upon the rated values of multiplying factor for the respective range given under (a) to (c) above.

Provided further that in case of any thermal generating stations the following additional unit heat rate is to be given again the condition as mentioned below :

(i)In respect of units where the boiler feed pumps are electrically operated, the maximum design unit heat rate shall be 40 kCal/kWh lower than the maximum design unit heat rate specified above with turbine driven BFP.

(ii)During stabilization period of new units, additional gross station heat rate on the basis of actual generation will be applicable, subject to a ceiling of 50 Kcal/Kwh.

(b)Gas-based / Liquid-based thermal generating unit(s) / block(s)

GSHR = 1.05 x Design Heat Rate of the unit/block for Natural Gas and RLNG (kCal/kWh) GSHR = 1.071 x Design Heat Rate of the unit/block for Liquid Fuel (kCal/kWh)Where the Design Heat Rate of a unit shall mean the guaranteed heat rate for a unit at 100% MCR and at site ambient conditions and the Design Heat Rate of a block shall mean the guaranteed heat rate for a block at 100% MCR, site ambient conditions, zero percent make up, design cooling water temperature/ back pressure.The gross station heat rate of any coal fired thermal generating station shall always be computed on the basis of generating station as a whole without any special consideration being given to the possible impact of any individual unit on the plant except when there is an outage of any unit over three months or more at a stretch, or there is a time overrun of a new proposed unit.

(2)Secondary fuel oil consumption

(a)Coal-based generating stations Other than at (c) below : 1.0 ml/kWh

(b)Lignite-fired generating stations not based on CFBC Technology : 2.0 ml/kWh

(c)Lignite-fired generating stations based on CFBC Technology : 1.25 ml/kWh

(3)Auxiliary Energy Consumption

(a)Coal-based generation stations :

		With Natural Draft cooling tower or without cooling tower
(i)	Less than 200 MW	10.00%
(ii)	200 MW series	8.50%
(iii)	500 MW & above	6.00%
(iv)	Steam driven boiler feed pumps	8.50%

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

(b)Gas Turbine/Combined Cycle generating stations :

(i)Combined cycle 3.0%

(ii)Open cycle 1.0%

(c)Lignite-fired thermal generating stations :

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

The auxiliary energy consumption norms shall be 0.5 percentage point more than the auxiliary energy consumption norms of coal-based generating stations at (a) above.Provided that for the lignite fired stations using CFBC technology. the auxiliary energy consumption norms shall be 1.5 percentage point more than the auxiliary energy consumption norms of coal-based generating stations at (a) above.

(4)Plant load Factor (PLF) - The normative PLF of a new coal fired thermal generating stations as a whole or part of it or of an already existing coal fired thermal generating stations due to addition of any new unit, not covered in Schedule-9A, shall be as may be determined by the Commission subject to the condition that the minimum PLF to be considered for determination of eligibility of incentives, shall be 80% for non-ABT complaint station and subject to other conditions under these regulations.The PLF of any coal fired thermal generating station, shall always be computed on the basis of generating station as a whole without any special consideration being given to the possible impact of any individual unit on the plant.

(5)Plant Availability Factor (PAF) - The normative plant availability factor of a new coal fired thermal generating stations as a whole or part of it or of an already existing coal fired thermal generating stations due to addition of any new unit, not covered in Schedule-9A, shall be as may be determined by the Commission, subject to the condition that the availability factor to be considered for recovery of capacity charges, shall not be less than 85% and subject to other conditions under these regulations.The availability of any coal fired thermal generating station, shall always be computed on the basis of generating station as a whole without any special consideration being given to the possible impact of any individual unit on the plant.

(6)Transit and Handling Losses - The normative transit and handling losses of a new coal fired thermal generating stations not covered in Schedule-9A, shall be determined by the Commission subject to a ceiling of 0.80% for non pithead generating stations and 0.20% for pit head generating stations.

(7)Operation and Maintenance (O&M) Expenses - The normative O&M expenses of a new coal fired thermal generating stations as a whole or part of it or of an already existing coal fired thermal generating stations due to addition of any new unit, which is/are not covered in Schedule-9A, the normative O&M expenses shall be as may be determined by the Commission, on consideration of facts and figures submitted to it, subject to a ceiling that may be provided for Sagardighi Thermal Power Station for that relevant year and also subject to other conditions under these regulations.

(8)Man/MW ratio - The normative Man/MW ratio of a new coal fired thermal generating stations as a whole or part of it or of an already existing coal fired thermal generating stations due to addition of any new unit, which is/are not covered in Schedule-9A, the normative Man / MW ratio shall be determined by the Commission on consideration of facts and figures submitted to it subject to a ceiling of 1.3 for units with a installed capacity of 200 MW or above subject to other conditions under these regulations.

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

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

(b)Gas Turbine/ Combined cycle generating stations - 90 days

B. Norms of operation for hydro generating stations not covered under Schedule 9A - The norms of operation as given hereunder shall apply to hydro generating station :

(1)Normative annual plant availability factor (NAPAF) for hydro generating stations :

(a)Normative annual plant availability factor (NAPAF) for hydro generating stations shall be determined by the Commission as per the following criteria :

Storage and Pondage type plants with head variation between Full Reservoir Level (FRL) and Minimum Draw Down Level (MDDL) of up to 8%, and where plant availability is not affected by silt : 90%. Storage and Pondage type plants with head variation between FRL and MDDL of more than 8%, where plant availability is not affected by silt : Plant-specific allowance to be provided in NAPAF for reduction in MW output capability as reservoir level falls over the months. As a general guideline the allowance on this account in terms of a multiplying factor may be worked out from the projection of annual average of net head, applying the formula :(Average head/ Rated head) + 0.02 Alternatively in case of a difficulty in making such projection, the multiplying factor may be determined as :(Head at MDDL/ Rated head) x 0.5 + 0.52 Pondage type plants where plant availability is significantly affected by silt : 85%.Run-of-river type plants : NAPAF to be determined plant-wise, based on 10 day design energy data, moderated by past experience where available/ relevant.

(b)A further allowance may be made by the Commission in NAFPA determination under special circumstances, E.G. abnormal silt problem or other operating conditions, and known plant limitations.

(c)In case of a new hydro electric project the developer shall have the option of approaching the Commission in advance for fixation of NAPAF based on the principles enumerated in sub-clauses (1), (2) and (3) of this regulations.

(2)Auxiliary Energy Consumption (AUX) :

Maximum Ceiling Of Norms Of All Future HydroGenerating Station
Type of hydro generating stations	Norms of auxiliary consumption in % of energygenerated
Surface generating station with rotating exciters mounted onthe generator shaft	0.7
Surface generating station with static excitation system	1.0
Underground generating station with rotating exciters mountedon the generator shaft	0.9
Underground generating station with static excitation system	1.2

C. The normative Man-MW ratio of a new hydro generating station as a whole or part of it or of an already existing hydro generating station due to addition of any new unit, which is/are not covered in Schedule-9A, the normative Man/MW ratio shall be determined by the Commission on consideration of facts and figures submitted to it subject to other conditions under these regulations.D. The normative O&M expenses of a new coal fired thermal generating stations as a whole or part of it or of an already existing coal fired thermal generating stations due to addition of any new unit, which is/are not covered in Schedule-9A, the normative O&M expenses shall be as may be determined by the Commission, on consideration of facts and figures submitted to it, subject to a ceiling that may be provided for Sagardighi Thermal Power Station for that relevant year and also subject to other conditions under these regulations.E. Norms of operation for transmission systemNormative Annual Transmission System Availability Factor (NATAF) shall be as under :

(1)	AC system	98%
(2)	HVDC bi-pole links	92%
(3)	HVDC back-to-back Stations	95%

Schedule 10

Incentives for Improved Performance(See regulations 2.5.1(iv), 2.6.1, 2.6.5, 2.8.6.4, 2.8.6.10, 2.8.6.11, 2.8.6.12, 2.8.8.2, 5.16.1, 6.4.2, 6.14.1)

1. Incentive for Generation Higher than Annual Norms - For generation by thermal generating stations in a year higher than annual norms of PLF as provided in paragraph B of Schedule 9A of these regulations the incentive will be given for ex-bus scheduled energy corresponding to implemented scheduled generation in excess of ex-bus energy corresponding to annual norms of generation (PLF) and auxiliary consumptions at the following rate :

PLF Achieved Range	Incentive rate in excess of Ex-bus energycorresponding to PLF achieved (in paisa / kWh)
	Category A	Category B	Category C	Category D
X % < PLF Achieved < (X+1)%	10	20	25	30
(X+1)% < PLF Achieved < (X+2)%	11	21	26	31
(X+2)% < PLF Achieved < (X+3)%	12	22	27	32
(X+3)% < PLF Achieved < (X+4)%	13	23	28	33
(X+4)% < PLF Achieved < (X+5)%	14	24	29	34
(X+5)% < PLF Achieved < (X+6)%	15	25	30	35
(X+6)% < PLF Achieved < (X+7)%	16	26	31	36
(X+7)% < PLF Achieved < (X+8)%	17	27	32	37
(X+8)% < PLF Achieved < (X+9)%	18	28	33	38
(X+9)% < PLF Achieved < (X+10)%	19	29	34	39
PLF Achieved > X+10%	20	30	35	40
Where,X = Value of target PLF of the generating station in%.Category A = Operating Age of Generating Station < 10YearsCategory B = Operating Age of Generating Station < 20Years and > 10 YearsCategory C = Operating Age ofGenerating Station < 25 Years and > 20 YearsCategory D= Operating Age of Generating Station > 25 Years

From third control period, this incentive will not be applicable for any ABT compliant generating station of any generating company.Note - (i) The above incentive shall not apply for Disergarh Thermal Power Station of DPSC Ltd. and New Cossipore Thermal Power Station of CESC Ltd. Further, generation from 30 MW unit of DPL shall not be considered for the above incentive.

(ii)The old units of Bandel TPS, the capacities of which have been derated, shall be treated as Category C generating stations.

(iii)Notwithstanding any other method of computing PLF anywhere in the instant regulations, computation of actual PLF achieved for the purpose of PLF related incentives, shall be done on the basis of generation achieved in % with respect to generation at MCR, i.e, by adding actual implemented ex bus scheduled injection with normative auxiliary consumption.

(iv)Notwithstanding anything to the contrary contained anywhere else in any other provisions under these regulations, any generating company can enter into any agreement with the purchaser of electricity for separate type of incentive due to annual generation over the normative PLF subject to following conditions :

(a)Such incentive will not be an element that can be passed through tariff

(b)In such event the above incentive under paragraph 1 of Schedule 10 of these Regulations will not be applicable

2. Incentive on Reliability of Generation Schedule - Incentive on annual basis for actual achievement by any generating station with respect to initial schedule of injection as provided by SLDC on day a head shall be provided on the basis of following principle.

Sl. No.	Criteria	Incentive on ex-bus generation
1	RI_GENSCHD = 100%	3.0 paisa/Kwhr
2	99% <RI_GENSCHD < 100%	1.5 paisa/Kwhr
3	98% < RI_GENSCHD < 99%	0.7 paisa/Kwhr
4	97% < RI_GENSCHD < 98%	0.3 paisa/Kwhr
5	96% < RI_GENSCHD < 97%	0.1 paisa/Kwhr
6	RI_GENSCHD < 96%	0.0 paisa/Kwhr

In the above table RI_GENSCHD is Reliability Index of Generation Injection Schedule and defined by the following formula :

GENSCHD =| No. of blocks where actual injection achieved with respect to initial injection schedule x 100No. of block in the year

However, if actual injection is less than the scheduled injection in order to assist the grid due to frequency at 50 HZ or above or as per specific instruction of SLDC then such actual injection is to be considered of achieving scheduled injection.

3. Incentive for Less Oil Consumption than the Norms - Incentive with respect to oil consumption by pulverized coal fired thermal generating stations shall be available when the actual annual oil consumption is less than the normative value, and the same would be determined on application of the criteria given below.

Criteria for Incentive	Incentive in Paisa/Unit of Generation
0.5 ml/ Kwhr < X < 0.75 ml/ Kwhr	0.25 Paisa
0.75 ml/ Kwhr < X < 1.0 ml/ Kwhr	0.30 Paisa
1.0 ml/ Kwhr < X < 1.50 ml/ Kwhr	0.40 Paisa
1.5 ml/ Kwhr < X < 2.0 ml/ Kwhr	0.45 Paisa
2.0 ml/ Kwhr < X < 2.5 ml/ Kwhr	0.60 Paisa
X > 2.5 ml/ Kwhr	0.75 Paisa
Where X = Norms of oil consumption rate in ml/Kwhr —Actual oil consumption rate in ml/Kwhr

4. Incentive for Better Gross Station Heat Rate than the Norms - Incentive with respect to gross station heat rate (SHR) of a coal fired thermal generating stations shall be available when the actual gross station heat rate for a year achieved by the generating station shall be within the criteria as provided in the table below :

Operating age of the Generating Station	Criteria for Incentive	Incentive in paisa/kWh Generation (Gross)
Up to 10 Yrs.	SHR < (DSHR x 1.02)	0.25 Paisa/kWh
> 10 Yrs but < 20 Yrs	SHR < (DSHR x 1.02)	0.50 Paisa / kWh
	(DSHR x 1.02) < SHR < (DSHR x 1.03)	0.25 Paisa / kWh
> 20 Yrs. but < 25 Yrs.	SHR < (DSHR x 1.03)	0.75 Paisa/kWh
	(DSHR x 1.03) < SHR < (DSHR x 1.04)	0.50 Paisa/kWh
> 25 Yrs.	SHR < (DSHR x 1.04)	1.00 Paisa/kWh
DSHR = Design Station Heat Rate

However where the generating stations as a whole or any part of it having undergone Life Extension Programme(s) through renovation and modernization programme. the operating age shall be considered separately. Unit no. 1 to 5 of DPL having undergone such Life Extension Programme(s), shall be put in the age group of 1r1 to 20 years individually for the purpose of this incentive only as well as to avoid any further categorization and shall be considered as of 12 years age on 2008-09 . Further Unit 6 and Unit 7 of DPL Shall be treated individually for the purpose of availability of incentive on gross station heat rate as the COD of these two units are temporarily widely spaced from each other.

5. Incentive for Sustainable Evening Generation - Incentive for actual achievement with respect to annual Average Evening Generation (AEG) during the evening hours of one year shall be provided on the basis of the following criteria.

Operating age of the generating station	Eligibility Criteria	Incentive Amount
First 5 yrs.	AEG > 98% of MCR	1 paisa per unit of extra generation over the eligibilitycriteria from 5 pm to 8pm
6th to 10th yrs	AEG >97% of MCR	1.5 paisa per unit of extra generation over the eligibilitycriteria from 5 pm to 8pm
11th to 15th yrs	AEG >96% of MCR	3.0 paisa per unit of extra generation over the eligibilitycriteria from 5 pm to 8pm
16th to 20th yrs	AEG > 95% of MCR	5.0 paisa per unit of extra generation over the eligibilitycriteria from 5 pm to 8pm
20th to 25th yrs	AEG > 94% of MCR	7.0 paisa per unit of extra generation over the eligibilitycriteria from 5 pm to 8pm
Above 25 yrs	AEG > 92% of MCR	10.0 paisa per unit of extra generation over the eligibilitycriteria from 5 pm to 8pm

Note:-(i) For the purpose of calculation of AEG, the number of days in the concerned year shall be reduced by the number of days required for planned maintenance, if any, which however shall be subject to ceiling of 30 days.

(ii)The claim of average peak generation is to be authenticated by the SLDC. The maximum generation for which the incentive is applicable should be limited to the MCR capacity.

(iii)Similarly the generating stations or part of it having undergone life extension programme (LEP) through renovation and modernization programme such as DPL shall also be considered in the age of 12 years in 2008-09 for the corresponding part which has undergone such renovation and modernization. The eligibility criteria for incentive on sustainable evening generation by the generating station which has undergone LEP as mentioned will be determined by the weighted average of the eligibility criteria of the part as mentioned and the balance part of the generating station on the basis of the MCR of those parts after taking the age of the balance part as a separate generating station in accordance with paragraph 9 of this instant Schedule. The said determined eligibility criteria will be applied on such type of generating stations as a whole for determination of their incentive on the sustainable evening generation.

(iv)However the said incentive for AEG shall not be applicable for Disergarh Thermal Power Station of DPSC and New Cossipore Thermal Power Station of CESC.

(v)Notwithstanding, anything to the contrary contained anywhere in these regulations for the purpose of computation of annual Average Evening Generation for this incentive calculation shall be based on implemented scheduled generation determined by adding actual implemented ex bus scheduled injection with normative auxiliary consumption for the applicable total hours of evening as defined in the table above for the year concerned subject to conditions as laid down in paragraphs (i), to (iv) above.

6. Incentive for Generation by Hydro-Generating Station - (a) Incentive shall be payable in case of all the hydro-generating stations, including in case of new generating stations in the first year of operation and any pumped storage hydro generating station, when the availability factor exceeds the norms as provided in Schedule 9A and incentive shall accrue up to a maximum availability factor index of 100%.

(b)Incentive shall be payable to the generating company or licensee in accordance with the following formula :

Incentive = 0.65 x Annual Capacity Charge x (CIA - CIN)/100(If incentive is negative, it shall be set to zero.)Where, CIA is the availability factor achieved and CIN is the normative availability factor provided in Schedule -9A or as per Schedule - 9D.

(c)The incentives on account of availability factor and payment for secondary energy shall be payable on yearly basis along with APR.

(d)Total incentive payment calculated on annual basis as provided in paragraphs (a), (b) and (c) above shall be shared by the beneficiaries who are purchasing power from that stations based on the saleable allocated capacity.

7. Incentive for Early Commissioning of Hydro-Generating Station - (a) In case of commissioning of a hydro-generating station or part thereof ahead of schedule, as set out in the final approval in pursuance to regulation 2.8.1.4.7 or as mentioned in the Schedule-9C or as mentioned in techno-economic clearance of the Authority if any, whichever is earlier, the generating station shall become eligible for incentive for an amount equal to pro rata reduction in interest during construction, achieved on commissioning ahead of the schedule. The incentive shall be recovered through tariff in twelve equal monthly instalments during the first year of operation of the generating station provided in case of ownership of such generating station by any generating company there shall be power purchase agreement for supplying power from this generating station to Distribution Licensee for at least 15 year.

(b)Total incentive payment calculated on annual basis as above paragraph (a) shall be shared by the beneficiaries who are purchasing power from that stations based on the saleable allocated capacity.

8. Incentive for Transmission Licensee - Incentive = Annual Transmission Charges x (Annual Availability achieved -Target Availability) / Target Availability.

Where, Annual transmission charges shall correspond to intra-state assets and/or for a particular inter-state asset, as the case may be.Provided that no incentive shall be payable below the availability of 99.75% for AC transmission line and substation system and 98.5% for HVDC system.

9. Operating Age Determination of Generating Stations - For incentive computation from paragraph 1 to 5 wherever operating age determination of the generating station is required, the operating age of the generating station will be the weighted average of the age of all units from their COD based on weightage of normative annual generation of each unit. The operating age of the unit will be calculated as on 1st October of the year for which incentive will be given.

10. Incentive for Early Cod With Full Load Operation by Coal Fired Thermal Generating Station - If the actual COD with full load operation and all load bearing equipments is achieved earlier than both the COD as stipulated in the agreement and in Schedule-9C, 75% of the saved interest during construction shall be allowed as incentive in such number of monthly instalments over first four year of operation of the generating station as may be stipulated by the Commission in the tariff order.

Annexure - A[See Regulation 5.6.2(ii)]Depreciation Schedule

Description of Assets	Useful life (Years)	Rate Calculated (w.r.t 90%)
1	2	3
A. Land owned under full title	Infinity	-
B. Land held under lease
(a) For investment in the land	The period of lease or the period remainingun-expired on the assignment of the lease
(b) For cost of clearing the site	The period of lease remaining un-expired at thedate of clearing the site
C. Assets Purchased New :
(a) Plant and machinery ingenerating stations including plant foundations
(i) Hydro-electric	35	2.57
(ii) Steam electric NHRS &Waste Heat Recovery Boilers / Plants	25	3.60
(iii) Diesel-electric and gasplant	15	6.00
(b) Cooling towers and circulatingwater systems	25	3.60
(c) Hydraulic Works forming Partof Hydro-electric system including :
(i) Dams, Spillways, weirs,canals, reinforced concrete Flumes and siphons	50	1.80
(ii) Reinforced concrete pipelinesand surge tanks, steel pipelines, sluice gates, steel surge(tanks), hydraulic control valves and other hydraulic works	35	2.57
(d) Building & civilengineering works of a permanent character, not mentioned above
(i) Offices & showrooms	50	1.80
(ii) Containing thermo-electricgenerating plant	25	3.60
(iii) Containing hydro-electricgenerating plant	35	2.57
(iv) Temporary erection such aswooden structures	5	18.00
(v) Roads other than kutcha roads	50	1.80
(vi) Others	50	1.80
(e) Transformers, transformer (Kiosk),sub-station equipment & other fixed apparatus (includingplant foundations)
(i) Transformers (includingfoundations) having a rating of 100 kilo volt amperes and over	25	3.60
(ii) Others	25	3.60
(f) Switchgear including cableconnections	25	3.60
(g) Lightning arrestors
(i) Station type	25	3.60
(ii) Pole type	15	6.00
(iii) synchronous condenser	35	2.57
(h) Batteries	5	18.00
(i) Underground Cable includingjoint boxes and disconnected boxes	35	2.57
(ii) Cable duct system	50	1.80
(i) Overhead lines includingsupports :
(i) Lines on fabricated steeloperating at nominal voltages higher than 66 kV	35	2.57
(ii) Lines on steel supportsoperating at nominal voltages higher than 13.2 kilovolts but notexceeding 66 kilovolts	25	3.60
(iii) Lines on steel or reinforcedconcrete supports	25	3.60
(iv) Lines on treated woodsupports	25	3.60
(j) Meters	15	6.00
(k) self propelled vehicles	5	18.00
(l) Air conditioning plants:
(i) Static	15	6.00
(ii) Portable	5	18.00
(m) Office Furniture andEquipments:
(i) Office Furniture and fittings	15	6.00
(ii) Office equipments	15	6.00
(iii) Electronic Office Equipments	15	6.00
(iv) Internal wiring includingfittings and apparatus	15	6.00
(v) Street light fittings	15	6.00
(n) Apparatus let on hire
(i) Other than motors	5	18.00
(ii) Motors	15	6.00
(o) Communication equipment:
(i) Radio and high frequencycarrier system	15	6.00
(ii) Telephone lines andtelephones	15	6.00
(p) Assets purchased second andand assets not otherwise provided for in the Schedule	Such reasonable period as the Commissiondetermines in each case having regard to the nature, age andcondition of the assets at the time of its acquisition by theGenerating Company / Licensee

Explanatory Note:-

(1)For this purpose all motor vehicles including dumper, dozer, etc. should include self-propelled vehicles.

(2)The above rates of depreciation will be applicable for determination of tariff as well as for accounting purpose.Annexure - B(See Regulation 6.1.1)Power Stations under Availability Based TariffI. All generating stations of West Bengal Power Development Corporation Limited (WBPDCL) viz.,

1. Kolaghat Thermal Power Station,

2. Bakreswar Thermal Power Station,

3. Bandel Thermal Power Station,

4. Santaldih Thermal Power Station,

5. Sagardighi Thermal Power Station

II. All other forthcoming generating stations(s) above 50MW of any generating company synchronized with the State Grid subsequently.Annexure - C1[See Regulation 2.7.2, 4.1.2 and Paragraph 12.1 of Schedule-5]Different Classes of Consumers

Class of Consumers	WBSEDCL	CESC LTD.	DPSC LTD.	DPL	DVC
A. LV & MV Consumers :
(i) Domestic (Rural)	Applicable	Not Applicable	Applicable	Applicable	Applicable
(ii) Domestic (Urban)	Applicable	Applicable	Applicable	Applicable	Applicable
(iii) Commercial (Rural)	Applicable	Not Applicable	Applicable	Applicable	Applicable
(iv) Commercial (Urban)	Applicable	Applicable	Applicable	Applicable	Applicable
(v) Irrigation	Applicable	Not Applicable	Applicable	Applicable	Applicable
(vi) Commercial Plantation.	Applicable	Not Applicable	Applicable	Applicable	Applicable
(vii) Short Term Irrigation Supply	Applicable	Not Applicable	Applicable	Applicable	Applicable
(viii) Short Term supply for Commercial Plantation	Applicable	Not Applicable	Applicable	Applicable	Applicable
(ix) Short-term supply	Applicable	Applicable	Applicable	Applicable	Applicable
(x) Public Utility / Specified Institutions /Public Bodies, as applicable.
(a) In Municipal area	Applicable	Applicable	Applicable	Applicable	Applicable
(b)In Non-Municipal area	Applicable	Applicable	Applicable	Applicable	Applicable
(xi) Cottage Industry / Artisan / Weavers / Smallproduction oriented establishment not run by electricity asmotive power	Applicable	Applicable	Applicable	Applicable	Applicable
(xii) Poultry, Duckery, Horticulture, Tissueculture Floriculture, Herbal - Medicinal - Bio-diesel PlantFarming, Food Processing Unit	Applicable	Applicable	Applicable	Applicable	Applicable
(xiii) Public Water Works & Sewerage System	Applicable	Applicable	Applicable	Applicable	Applicable
(xiv) Industries
(a) Rural	Applicable	Not Applicable	Applicable	Applicable	Applicable
(b) Urban	Applicable	Applicable	Applicable	Applicable	Applicable
(xv) Street Lighting	Applicable	Applicable	Applicable	Applicable	Applicable
(xvi) Private Educational Institutions &Hospitals	Applicable	Applicable	Applicable	Applicable	Applicable
(xvii) Emergency	Applicable	Applicable	Applicable	Applicable	Applicable
(xviii) Construction Power	Applicable	Applicable	Applicable	Applicable	Applicable
(xix) Bulk supply at single point, inter-alia, toCo-operative Group Housing Society for providing power to itsmembers or person, for providing power to its employee's in asingle premises	Applicable	Applicable	Applicable	Applicable	Applicable
(xx) Common Services of Industrial Estate	Applicable	Applicable	Applicable	Applicable	Applicable
(xxi) Sports Complex	Applicable	Applicable	Applicable	Applicable	Applicable
(xxii) Cold Storage or dairy with chilling plant	Applicable	Applicable	Applicable	Applicable	Applicable
B. HV & EHV Consumer
(i) Public Utility	Applicable	Applicable	Applicable	Applicable	Applicable
(ii) Industries	Applicable	Applicable	Applicable	Applicable	Applicable
(iii) Irrigation	Applicable	Not Applicable	Applicable	Applicable	Applicable
(iv) Commercial Plantation	Applicable	Not applicable	Applicable	Applicable	Applicable
(v) Short Term Irrigation Supply	Applicable	Not applicable	Applicable	Applicable	Applicable
(vi) Short Term supply for Commercial Plantation	Applicable	Not applicable	Applicable	Applicable	Applicable
(vii) Commercial	Applicable	Applicable	Applicable	Applicable	Applicable
(viii) Domestic	Applicable	Applicable	Applicable	Applicable	Applicable
(ix) Public Water Works & Sewerage	Applicable	Applicable	Applicable	Applicable	Applicable
(x) Sports Complex	Applicable	Applicable	Applicable	Applicable	Applicable
(xi) Cold Storage or dairy with chilling plant	Applicable	Applicable	Applicable	Applicable	Applicable
(xii) Emergency Supply	Applicable	Applicable	Applicable	Applicable	Applicable
(xiii) Construction Power	Applicable	Applicable	Applicable	Applicable	Applicable
(xiv) Bulk supply at single point, inter-alia toCo-operative Group Housing Society for providing power to itsmembers or person, for providing power to its employees in asingle premises	Applicable	Applicable	Applicable	Applicable	Applicable
(xv) Common Services to Industrial Estate	Applicable	Applicable	Applicable	Applicable	Applicable
(xvi) Traction load for transport system	Applicable	Applicable	Applicable	Applicable	Applicable
(xvii) Short-term supply	Applicable	Applicable	Applicable	Applicable	Applicable

Note to Annexure - C1 :

(i)Sub-section (1) of section 43 of the Act shall be applicable to all licensees irrespective of any provisions to the contrary contained in any law or document or in licence.

(ii)Traction load included traction connection for railways, metro rail, tramways and any other man-transit system.

(iii)Public bodies means State and Central Government establishments for whom public bodies tariffs are applicable under existing tariff structure as per the order of the Commission for 2006-2007.

(iv)Common Services of Industrial Estates includes Street Lighting, Estate Office Establishment, Water Service, Effluent Treatment, Pump House for Sewerage and Storm Water Drainage under the authority of the Industrial Estate.

(v)Specified Institutions means such class of consumers who are falling under the following categories :

(a)All non-profit making educational and research institutions including public libraries, owned or aided by the State / Central Government;

(b)All State / Central Government hospitals; and

(c)Charitable dispensaries, maternity homes, hospitals, old age homes and social welfare establishments owned and run by either State Government or Central Government or by any charitable organisation either public or private.

In order to be treated as Specified Institutions, such classes of consumers are to satisfy the following conditions :

(a)The electricity supply at their premises shall be either at 230 V single phase or 400 V three phase.

(b)The educational and research institutions aided by the State / Central Government shall furnish necessary documents to indicate that they have been receiving from the State / Central Government such aid, which must be at least 50% of their total annual income for the last three years consecutively.

(c)The educational and research institutions aided by State / Central Government and the hospitals, maternity homes, charitable dispensaries, old age homes and social welfare establishments owned and run by -Charitable Organisations" shall be required to submit their audited accounts of the last three years.

(d)All consumers shall be required to furnish an undertaking stating that the power supply to their institutions / organisations shall be used and shall continue to be used exclusively for the purpose for which the supply has been proposed to be taken.

(e)Libraries owned by the State Government shall be eligible to be treated as the Specified Institutions, if their applications are duly recommended by the Director of Libraries / District Library Officer concerned.

(f)Libraries receiving grants from State Government for a continuous period of at least three years shall also qualify to be treated as Specified Institutions subject to submission of their audited accounts of the last three years along with a certificate from the Director of Libraries / District Library Officer concerned about their eligibility.

Provided that the quantum of grant received from the State Government must be at least 50% of their total annual income for the last three years consecutively.In addition, the following conditions are also required to be complied with for becoming eligible for treating to be a Specified Institution.

(a)Certificate from concerned Corporation / Municipality / Panchayat regarding clearance of dues, if applicable, should be furnished by the consumer.

(b)The licensees may satisfy itself about the veracity of the claim of the consumer.

Provided that the status of Specified Institution shall not be allowed to any class of consumer(s) who is I are defaulter in regard to payment of electricity bills. Further, such status shall stand automatically withdrawn if it defaults in payment of electricity bills during the period for which such status of Specified Institution has been allowed.The aforesaid status shall be given effect prospectively from the date on which the licensee takes decision for such status and that date should not be more than three months from the date on which the applicant-institution has complied with all formalities.

(vi)Public utility in HV / EHV means Government Hospital and Government Research / Educational Institutions and its tariff shall be applicable on prospective basis only following the tariff order as and when issued under these regulations.

(vii)In view of introduction of new categories, if parameters related to any of the sub-categories mentioned above are not directly assessable for measurement, licensee shall put in place system for measurement and segregation of load within three months from the date of notification of these regulations and billing under such new categories shall be done prospectively and data may accordingly be furnished.

(viii)For CESC, class of consumers for A(i), A(iii), A(v), A(vi), A(vii), A(viii), B(iii), B(iv), B(v), B(vi) are not applicable considering present area of supply. These categories may be applicable as and when its area of supply changes.

(ix)Short-term supply includes events, festivals and marriage ceremony. For such short-term supply, the fixed / demand charge shall be the fixed / demand charge under non-TOD tariff applicable to that particular category of consumer to which the applicant seeking such supply belongs. Such short-term supply shall not have any load factor rebate and power factor rebate. However, other charges for such short-term supply shall be the same as are applicable to that particular category of consumer to which the applicant seeking such short-term supply belongs. For such short-term supply, consumer shall apply to the licensee at least 10 days in advance for LV and MV consumers and at least 20 days in advance for HV consumer. For EHV category, there shall be no short-term supply.

(x)Domestic consumer having monthly consumption of 25 units in case of monthly billing or having quarterly consumption of 75 units in case of the quarterly billing and contract demand not more than 0.3 KW shall be treated as Life Line Domestic Consumer.

Annexure - C2[See Regulations 2.7.2, 3.1.3, 3.12.1 and Paragraph 12.2 of Schedule - 5]Tariff Scheme for Different Classes of Consumers

Class of Consumers	Applicable Tariff Scheme	Optional Tariff Scheme	TOD Scheme
A.LV & MV Consumers :
(i) Domestic (Rural)	Normal	Prepaid
(ii) Domestic (Urban)	Normal	Prepaid
(iii) Commercial (Rural)	Normal	Normal TOD & Prepaid - TOD	A
(iv) Commercial (Urban)	Normal	Normal TOD & Prepaid - TOD	A
(v) Irrigation	Normal -TOD	Prepaid - TOD	A
(vi) Commercial Plantation.	Prepaid - TOD		A
(vii) Short Term Irrigation Supply	Prepaid - TOD		A
(viii) Short Term supply for Commercial Plantation	Prepaid -TOD		A
(ix) Short Term Supply	Prepaid - TOD		A
(x) Public Utility / Specified Institutions / Public Bodies,as applicable.
(a) In Municipal area	Normal	Prepaid/Prepaid-TOD	B
(b) In Non-Municipal area	Normal	Prepaid /Prepaid - TOD	B
(xi) Cottage Industry / Artisan / Weavers / Small productionoriented establishment not run by electricity as motive power	Normal	Prepaid - TOD	A
(xii) Poultry, Duckery, Horticulture, Tissue culture,Floriculture, Herbal - Medicinal - Bio-diesel Plant Farming, FoodProcessing Unit	Normal	Prepaid - TOD	A
(xiii) Public Water Works & Sewerage System	Normal	Prepaid - TOD	B
(xiv) Industries
(a) Rural(b) Urban	Normal	Normal - TOD	A
(xv) Street Lighting	Normal	-	-
(xvi) Private Educational Institutions & Hospitals	Normal	Normal - TOD	B
(xvii) Emergency	Pre-paid — TOD	-	A
(xviii) Construction Power Supply	Prepaid — TOD	-	B
(xix) Bulk Supply at single point to Co-operative GroupHousing Society for providing power to its members or person forproviding power to its employees in a single premises	Normal	Normal — TOD	A
(xx) Sports Complex	Normal	-
(xxi) Cold Storage or dairy with chilling plant	Normal	Normal — TOD	A
(xxii) Common Services of Industrial Estate	Prepaid — TOD	-	B
B.HV & EHV Consumer:
(i) Public Utility	Normal	Normal — TOD	B
(ii) Industries	Normal	Normal — TOD	A
(iii) Irrigation	Normal — TOD	-	A
(iv) Commercial Plantation	Normal — TOD	-	A
(v) Short Term Irrigation Supply	Normal — TOD	-	A
(vi) Short Term supply for Commercial Plantation	Normal — TOD	-	A
(vii) Commercial	Normal	Normal — TOD	A
(viii) Domestic	Normal	Normal — TOD	A
(ix) Public Water Works & Sewerage	Normal	Normal — TOD	B
(x) Sports Complex	Normal	-
(xi) Cold Storage or dairy with chilling plant	Normal	Normal — TOD	A
(xii) Emergency Supply	Normal — TOD	-	A
(xiii) Construction Power Supply	Normal — TOD	-	B
(xiv) Bulk Supply at single point to Co-operative GroupHousing Society for providing power to its members or person forproviding power to its employees in a single premises	Normal	Normal — TOD	A
(xv) Common Services of Industrial Estate	Normal — TOD	-	B
(xvi)Traction load for transport system	Normal	-	A
(xvii) Short-term supply	Normal — TOD	-	A

Note:- (i) 'Normal' tariff scheme means the tariff which is to be paid on the basis of the bill raised, after consumption of electricity in a billing cycle, as per regulations framed under section 50 of the Act and such tariff will not be differentiated on the basis of time of the day;

(ii)'Normal - TOD' tariff means the tariff which is to be paid on the basis of the bill raised, after consumption of electricity in a billing cycle, as per regulations framed under section 50 of the Act and such tariff will be differentiated on the basis of time of the day;

(iii)'Prepaid' tariff scheme means the scheme under which advance payment is to be made for use of certain quantity of electricity and such tariff will not be differentiated on the basis of time of the day;

(iv)Prepaid - TOD' tariff scheme means the scheme under which advance payment is to be made for use of certain quantity of electricity and such tariff will be differentiated on the basis of time of the day,

(v)Any consumer whose partial demand is met by supply through open access as open access customer shall be guided by the paragraph 12.5 of schedule - 5.

(vi)Optional Scheme of normal tariff scheme under emergency category will only be applicable for consumers having in-situ captive sources in pursuance of para 12.6 of schedule - 5. No other consumer will be entitled to this option of normal tariff.

(vii)Pre-paid meter in applicable tariff scheme will be based on pre-denominated pre-paid facility only where vending machine infrastructure is not available.

(viii)Optional tariff scheme for pre-paid meter will be available only in those areas where the vending machine for such pre-paid meter is available. However, where vending machine is not available pre-denominated pre-paid facility shall be made available to the consumer.

(ix)In case of pre-denominated prepaid facility, if there is any balance on pre-denominated facility arising out of any validity condition of such facility or because of discontinuance of consumer-ship, such amount shall be refunded to the consumer.

(x)Notwithstanding anything to the contrary contained in any other regulation of the Commission, in case of non availability of pre-paid meter, the consumer applying under applicable tariff scheme or under optional tariff scheme shall be provided with the non pre-paid meter but for such consumer the tariff shall be at the rate of pre-paid tariff scheme on the basis of post consumption payment basis as applicable for that class of consumers. If such pre-paid meter scheme is of TOD type then the non-prepaid meter with TOD - scheme will be first preferred and only on non availability of non pre-paid meter with TOD-scheme normal meter may be used when tariff will be the rate of normal hours of the pre-paid TOD-Scheme. This arrangement may be continued up to two years from the date of application for such pre-paid meter by the said consumer so that by that time the consumer shall have to be provided with the pre-paid meter. On completion of the specified two years if such pre-paid meter is not installed at the premises of the consumer then the distribution licensee will not be able to raise any bill in respect of the consumer till such time the pre-paid meter is installed and any losses incurred by the distribution licensee after the said two years on this account shall not be allowed to be recovered through tariff.

(xi)Optional tariff scheme is meant for existing consumers only. Once option for optional tariff scheme is exercised the subsequent reversion to applicable tariff scheme is not permissible.

(xii)All new connections to the consumers under HV & EHV category, for whom optional TOD scheme exists, shall be under TOD scheme compulsorily except the class of consumers namely Domestic or Commercial or Sports Complex or Traction or Bulk Supply at single point to Co-operative Group Housing Society for providing power to its members or person for providing power to its employees in a single premises, for whom the TOD scheme shall remain optional.

(xiii)For commissioning of any generating station, except own generating station of a distribution licensee, the tariff for commissioning power shall be equal to the tariff of industrial class of consumer at the applicable voltage. However such supply shall not have load factor rebate, power rebate and high voltage supply rebate.

(xiv)The TOD Scheme as mentioned in the table is defined as follows:-

TOD Scheme	Normal Period	Peak Period	Off-peak Period
A	06.00 hrs. to 17.00 hrs.	17.00 hrs. to 23.00 hrs.	23.00 hrs. to 06.00 hrs.
B	06.00 hrs. to 17.00 hrs. and 20.00 hrs. to 23.00 hrs.	17.00 hrs. to 20.00 hrs.	23.00 hrs. to 06.00 hrs.

Note:- Considering the actual system peculiarities of any specific licensee, the Commission may decide to determine separate time strata for any class of consumers.

(xv)An applicant for short term supplies through pre-paid meter shall have to comply with all necessary formalities for obtaining supply including payment in accordance with the Regulations made by the Commission subject to the conditions that he shall provide space for installing weather-proof, safe and secure terminal services apparatus to protect sophisticated meter; and

(xvi)If the word rural or urban within the bracket of any particular class of consumers is not mentioned in the tariff order by the Commission under these regulations, then it will be presumed that same tariff is applicable for both the classes of consumers or the particular class of consumers, for whom that tariff is applicable as per Annexure C1.

List of Forms contained in Annex 1[See Regulation 2.7.2]

Form No.	Description
Form 1.1	Availability of Plant (Plant Availability Factor) - Annually
Form 1.1(a)	Availability of Unit (Unitwise Availability Factor) - Annually(Stationwise)
Form 1.2	Plant Load Factor - Annually
Form 1.2(a)	Unit wise Plant Load Factor - Annually (Stationwise)
Form 1.3	Gross Energy available at Generator's Terminal for stabilisedcommercial operation (Stationwise)
Form 1.4(a)	Auxiliary Consumption for stabilised commercial operation(Stationwise)
Form 1.4(b)	Pumping Energy for Pumped Storage Project
Form 1.5	Net Energy Sent out for stabilised commercial operation(Stationwise)
Form 1.6(a)	Energy Purchase (Sourcewise)
Form 1.6(b)	Monthwise nondrawal of power from different sources ofpurchase due to low demand inspite of having availabilities atpurchaser side
Form 1.6(c)	Monthwise Generation Loss at different GeneratingStation
Form 1.7	T&D Loss %
Form 1.8	Aggregate Technical & Commercial (AT&C) Loss
Form 1.9	Energy Balance
Form 1.9(a)	Energy received for Wheeling
Form 1.9(b)	Energy sold to persons other than licensees or any consumers
Form 1.9(c)	Energy sold to other licensees
Form 1.9(d)	Energy wheeled at delivery point
Form 1.10(a)	Quantum of Purchase of Power and rate thereof (Sourcewisevis-a-vis Stationwise)
Form 1.10(b)	Power Purchase Cost Analysis (Sourcewise vis-a-visStationwise)
Form 1.11	Cost of Fuel (Stationwise)
Form 1.12	Expenditure - Cost of Energy from own Generation - Stationwise
Form 1.13	Expenditure - Transmission of Energy
Form 1.14	Average System Demand for Transmission Systems
Form 1.15	Expenditure - Distribution of Energy
Form 1.16	Expenditure - Sale of Energy
Form 1.17	Other expenses - Centrally maintained
Form 1.17(a)	Interest on temporary accommodation
Form 1.17(b)	Interest on working capital
Form 1.17(c)	Other finance charges
Form 1.17(d)	Foreign Exchange Rate Variation (FERV) - Yearwise
Form 1.17(e)	Advance Against Depreciation (AAD)
Form 1.17(f)	Insurance premium payable
Form 1.17(g)	Interest credit
Form 1.17(h)	Break-up of Employee Cost
Form 1.17(i)	Details of Arrear against wage revision
Form 1.17(j)	Statement of penalty / fine / cess etc.
Form 1.17(k)	Cost of outsourcing
Form 1.18	Original Cost of Fixed Assets
Form 1.18(a)	Original Cost of work-in-progress
Form 1.18(b)	Intangible Assets
Form 1.18(c)(i)	Investments
Form 1.18(c)(ii)	Income from Investments
Form 1.19(a)	Capital Expenditure for the year
Form 1.19(b)	Overall Capital Expenditure Programme
Form 1.19(c)	Project Specifications
Form 1.20(a)	Equity Base
Form 1.20(b)	Normative Debt (Equity Part converted to Debt)
Form 1.21	Special Allocation
Form 1.22	Return on Equity
Form 1.23	Permitted Incentive
Form 1.24	Benefits passed on to Consumers
Form 1.25	Receipts from Sale of Energy
Form 1.26	Income other than Sale of Energy
Form 1.27	Wheeling Charge
Form 1.28	Statement Showing Status of FPPCA Claim
Form A	Planned Repairs and Maintenance/ forced outage/ major repairsfor generation plants (Stationwise-vis-a-vis yearwise)
Form B	Details of Depreciation chargeable to revenue account for theyear (Yearwise)
Form C	Statement of Loans and Calculation of Interest thereon for theyear (Yearwise)
Form D(1)	Details of Fuel Consumption for the year (Stationwisevis-à-vis Yearwise)
Form D(2)	Breakup of Transportation and other cost of coal (Sourcewise)
Form D(3)	Cost of Primary Fuel (Yearwise)
Form E(A)	Summarized Revenue Requirement - Part-A
Form E(B)	Summarized Revenue Requirement - Part-B
Form E(T)	Summarized Revenue Requirement (Transmission)

Annex 1Form 1.1 : Availability of Plant (Plant Availability Factor) - Annually in %

Station	Previous Year	Base Year	Ensuing Year
	Four	Three	Two	One		One	Two	Three	Four	Five	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected	Projected
Station 1Station 2 and so on

Note:-(i) For any Plant, Plant Availability Factor shall be considered for stabilised operation only i.e. without taking into account the in-firm power generation or generation during stabilisation period.

(ii)Reasons for variations over the years are to be given in a note.

ApplicantAnnex 1Form 1.1(a) : Availability of Unit (Unitwise Availability Factor) - Annually (stationwise) in %

Station	Previous Year	Base Year	Ensuing Year
	Four	Three	Two	One		One	Two	Three	Four	Five	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected	Projected
Unit 1Unit 2 and so on

Note:- (i) in-firm power generation or generation during stabilisation period.

(ii)Reasons for variations over the years are to be given in a note.

ApplicantAnnex 1Form 1.2 Plant Load Factor - Annually in %

Station	Previous Year	Base Year	Ensuing Year
	Four	Three	Two	One		One	Two	Three	Four	Five	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected	Projected
Station 1Station 2 and so on

Note:-(i) For any Plant, PLF shall he considered for stabilised operation only i.e. without taking into account the in-firm power generation or generation during stabilisation period.

(ii)Reasons for variations over the years are to be given in a note.

ApplicantAnnex 1Form 1.2(a) Unitwise Plant Load Factor - Annually (Stationwise) in %Name of the Station :

Station	Previous Year	Base Year	Ensuing Year
	Four	Three	Two	One		One	Two	Three	Four	Five	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected	Projected
Unit 1Unit 2 and so on

Note:- (i) For any Unit, unitwise PLF shall be considered for stabilised operation only i.e. without taking into account the in-firm power generation or generation during stabilisation period.

(ii)Reasons for variations over the years are to be given in a note.

ApplicantAnnex 1Form 1.3 Gross Energy available at Generators Terminal for Stabilised Commercial Operation (Stationwise)Name of the Station :Capacity : (MW) MU

Season/Time of the day	Actual Gross Generation inPrevious Years (MU)	Estimated Gross Generation inBase Year (MU)	Project Gross Generation inEnsuing Years (M U)
Four	Three	Two	One	One	Two	Three	Four	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1. SummerNormal Peak Off-peak
Total Summer
2. MonsoonNormal Peak Off-peak
Total Monsoon
3. WinterNormal Peak Off-peak
Total Winter
Grand Total :

Note:- 1. For the first Control Period and any year at second and third control period, if actual time stratawise data is not available for the previous years and base year then on the basis of average hourly load of that month, the time stratawise generation for the month can be obtained. Such derived data for the previous year and base year may be used for the projections for the ensuing year.

2. When New Unit comes into commercial operation, generation before Commercial Operation Date and generation during stabilisation period are to be shown separately in a similar format. For existing stabilised units, Gross Energy generated during stabilised Commercial Operation period is only to be submitted.

3. Actual Generation means energy actually generated irrespective of schedule.

ApplicantAnnex 1Form 1.4(a) Auxiliary Consumption for stabilised Commercial Operation (Stationwise)Name of the Station :Capacity : (MW) MU

Season	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1. Summer2. Monsoon3. Winter
Grand total:

Note:-1. For different season, Auxiliary Energy shall be calculated on the basis of actual annual auxiliary consumption rate for previous year, estimated annual auxiliary consumption rate for base year and projected annual auxiliary consumption rate for the ensuing years.

2. When New Unit comes into commercial operation, generation before Commercial Operation Date and generation during stabilisation period are to be shown separately in a similar format. For existing stabilised units, Gross Energy generated during stabilised commercial operation period only is to be submitted.

3. For Hydro-generating station including Pumped Storage Plant, Transformation Losses shall be included in the auxiliary energy consumption.

ApplicantAnnex 1Form 1.4(b) Pumping Energy for Pumped Storage ProjectName of the Station :Capacity:(MW) MU

Season/Time of the day	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1. SummerNormalPeakOff-peak
Total Summer :
2. MonsoonNormalPeakOff-peak
Total Monsoon :
3. WinterNormalPeakOff-peak
Total Winter :
Grand Total :

Note:- 1. Pumping Energy for each unit of Generation as per design is to be provided with supporting documents.

2. Pumping Energy shall be measured at bus bar of the generating station.

ApplicantAnnex 1Form 1.5 Net Energy Sent Out for Stabilised Commercial Operation (Stationwise)Name of the Station :Capacity:(MW) MU

Season/Time of the day	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1. SummerNormalPeakOff-peak
Total Summer :
2. MonsoonNormalPeakOff-peak
Total Monsoon :
3. WinterNormalPeakOff-peak
Total Winter :
Grand Total :

Note:- 1. Time stratawise Net sent out unit is to be obtained after deducting Auxiliary consumption applying the overall annual auxiliary consumption rate on the gross energy available at generators terminal of the respective time strata.

2. When New Unit comes into commercial operation, generation before Commercial Operation Date and generation during stabilisation period are to be shown separately in a similar format. For existing stabilised units, Gross Energy generated during stabilised commercial Operation period is only to be submitted.

ApplicantAnnex 1Form 1.6(a) : Energy Purchase (Sourcewise)Name of the Source : MU

Season/Time of the day	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1. SummerNormalPeakOff-peak
Total Summer :
2. MonsoonNormalPeakOff-peak
Total Monsoon :
3. WinterNormalPeakOff-peak
Total Winter :
Grand Total :
Less Grid Loss, ifany
Net Purchase

Note:- 1. For the First Control Period and any year of second or third control period, if actual time stratawise data is not available for the previous years and base year then on the basis of average hourly load of purchased energy of that month, the time stratawise purchase for the month can be obtained. Such derived data for the previous year and base year may be used for the projections for the ensuing year.

2. Each source is to be furnished in a separate sheet with an aggregate consolidated sheet for all sources.

3. Energy related to UI mechanism shall not be reflected in Energy purchase.

ApplicantAnnex 1Form 1.6(b) : Month wise Non-drawal of power from different sources of purchase due to low demand inspite of having availabilities at purchaser side

Month	Source 1	Source 2	Source 3
April
May
June
July
August
September
October
November
December
January
February
March

Total

Source means WBPDCL, NTPC etc.Form 1.6(c) : Monthwise Generation Loss at different generating station

Month	Non-drawal by concern distributionlicensee due to low demand	Bad Coal	Poor Coal Stock	Forced Outage	Planned Outage	Transmission Restriction	Generation restriction for partialequipment availability	Non-drawal by other thandistribution licensee against schedule drawal
April
May
June
July
August
September
October
November
December
January
February
March

Total

1. Statement is to be furnished sourcewise separately.

2. Depending on type of generating station, relevant column may be filled up with due editing on reading and for additional reasons, if any on account of generation loss, additional column may be separately provided.

3. Depending on the type of the generating station, the reasons for monthly generation losses may be submitted by using additional columns for separate reasoning.

ApplicantAnnex 1Form 1.7 : T&D Loss%

Ref.

Particulars

Unit

Derivation

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Generation [Form 1.3]

Auxiliary Consumption [Form 1.4]

Transformation Loss

Units delivered to system from generation(including infirm power, if any) [Form 1.5]

C=A-B1-B2

Quantum of infirm power included in 1

Energy Purchased [Form 1.6]

Energy Received for Wheeling [Form 1.9a]

Overall Gross Energy in System

F = C+D+E

Units Sold to persons other than licensees or anyconsumers [Form 1.9b]

Additional Units allowed by Commission for Salesto persons other than licensees or any consumers

Units sold/ used for pumping energy of PumpedStorage Project at Bus bar [Form 1.4(b)]

Additional Units allowed by Commission againstPumping Energy for pumping loss

Units sold to other licensees [Form 19c]

Additional Units allowed by Commission for Salesto other licensees

Net UI [Actual drawal]

Total Energy goes out of System

(G = G1+G3+G4+G5+G6+G7)

Net Energy in System

H=F-G

Units sold to consumers

Units wheeled [Form 1.9d]

Additional Units allowed for wheeling

Units utilised in own premises includingconstruction power

Quantum of construction power included in 21

Overall Utilisation

M=sum(I:L)

Unutilised Units

N = H-M

System Loss

0 = N* 100/ H

Note:- Actual Generation means units actually generated irrespective of schedules. Purchase and sales to persons other than licensees or any consumers shall not include the energy under UI mechanism.ApplicantAnnex 1Form 1.8 : Aggregate Technical & Commercial (ATC) Loss

Particulars

Unit

Derivation

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Units supplied to System [Item H ofForm 1.7]

Units utilised [Item M of Form 1.7]

Unutilised Units [Item N of Form 1.7]

C=A-B

T&D Loss % [Item of Form 1.7]

D=(Cx100)/A

Realized Units in corresponding period

AT&C Loss in Units

F=A-E

ATC Loss

G=(F/A)x100

Note:- Reasons for shortfall in Collection Efficiency and actions taken for improvement of the same is to be furnished.ApplicantAnnex 1Form 1.9 : Energy Balance

Ref.

Particulars

Unit

Derivation

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Energy Input

Generation [Form 1.3]

Auxiliary Consumption

Transformation Loss

Units delivered to system from generation(including infirm power, if any) [Form 1.5]

4=1-2-3

Energy Purchased [Form 1.6]

Energy received for Wheeling [Form 1.9a]

Gross Energy Input

7=sum(4:6)

Units sold to persons other than licensees or anyconsumers [Form 1.9b)

Additional Units allowed by Commission for Salesto persons other than licensees or any consumers

Units sold/used for pumping energy of PumpedStorage Project at bus bar [Form 1.4(b)]

Additional Units allowed by Commission againstPumping Energy for pumping loss

Units sold to other licensees [Form 19c]

Additional units allowed by the commissionagainst sale to licensee

Net UI [Actual drawal]

Total Energy Goes out of System

15=8+10+11+12+13+14

Energy Input for own system

7-5

Energy Utilisation [Form 1.7]

Units sold to consumers

Units wheeled [Form 1.9 d]

Additional units allowed for wheeling

Units utilised in own premises includingconstruction power

Unutilised Units

Total Energy

sum (a:e)

Note:- Actual Generation means units actually generated irrespective of schedules.ApplicantForm 1.9(a) : Energy received for WheelingAnnex 1Mu

Ref	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
		Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1.2.etc.

ApplicantAnnex 1Form 1.9(b) : Energy sold to person other than licensees or any consumersMU

Ref.	Season 1 Time of the day	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
	1. SummerNormalPeakOff-peak
	Total Summer :
	2. MonsoonNormalPeakOff-peak
	Total Monsoon
	3. WinterNormalPeakOff-peak
	Total Winter :
	Grand Total :

1. Energy are to be measured at Power Station Bus for Generating Company and for Distribution Licensees from pool energy inclusive of T&D Loss.

2. Energy sold to any person other than licensee or any consumer shall be shown separately for each such person.

ApplicantAnnex 1Form 1.9(c) : Energy sold to other licensees

Ref.	Season 1 Time of the day	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
	1. SummerNormalPeakOff-peak
	Total Summer :
	2. MonsoonNormalPeakOff-peak
	Total Monsoon
	3. WinterNormalPeakOff-peak
	Total Winter :
	Grand Total :

1. Energy sold to other licensee shall be shown separately for each licensee.

ApplicantAnnex 1Form 1.9(d) : Energy wheeled at Delivery PointMU

Ref	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
12etc.

ApplicantAnnex 1Form 1.10(a) : Quantum of Purchase of Power and Rate thereof (Sourcewise vis-a-vis Stationwise)

Particulars

Unit

Derivation

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Detailsof Import DrawalA. InfirmB. FirmB1: Summer:

Normal

B1N

Peak

B1P

Off-peak

B1OP

TotalFirm in Summer: (B1)

B2:Monsoon:

Normal

B2N

Peak

B2P

Off-peak

B2OP

TotalFirm in Summer: (B2)

B3:Winter

Normal

B3N

Peak

B3P

Off-Peak

B3OP

TotalFirm in Winter:(B3)

Total Firm:(B)

B=B1-B2+B3

ChargeableUnits

A+B

ApplicableRates

A. Infirm

Paise/Unit

B.Firm

FixedCharges

Rs.Lakhs/

Month

EnergyCharges

B1:Summer:

Normal

Paise/Unit

Peak

Paise/Unit

Off-Peak

Paise/Unit

B2:Monsoon

Normal

Paise/Unit

Peak

Paise/Unit

Off-Peak

Paise/Unit

B3:Winter

Normal

Paise/Unit

Peak

Paise/Unit

Off-Peak

Paise/Unit

C. Fuel and Power Purchase CostAdjustment

Paise/Unit

Note:-(1) Source of energy purchased, purchase rate, quantum of energy purchased, escalation / rebate adjustment clause in the purchase rate, if any, may be given along with all the relevant details. Whether there is any dispute on purchase rate and if yes, the details thereof may be submitted.

(2)Whether any power purchase agreements (PPA), if required, have been entered into which will be in force during the period for which the tariff has been proposed. Copies of such PPAs are to be enclosed.

(3)Whether the competent authority has approved the purchase rates as per the Act and if not, details thereof.

(4)Whether any procurement is made from co-generation / renewable sources of energy. If yes, details thereof may be submitted.ApplicantAnnex 1Form 1.10(b) : Power Purchase Cost Analysis (Sourcewise vis-à-vis Stationwise)

Particulars

Unit

Derivation from form 1.10(a)

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Details of power purchase cost

Rs. Lakhs

A. infirm

Rs. Lakhs

O=A*C

B.firm

Fixed charges:

Rs. Lakhs

P=D*12

Energy Charges:

B1:Summer

Normal

Rs. Lakhs

O=B1N*E

Peak

Rs. Lakhs

R=B1P*F

Off-peak

Rs. Lakhs

S=B1OP*G

Toalfirm in summer:(B1)

Rs. Lakhs

T=O+R+S

B2:Monsoon

Normal

Rs. Lakhs

U=B2N*H

Peak

Rs. Lakhs

V=B2P*I

Off-peak

Rs. Lakhs

W=B2OP*J

Totalfirm in monsoon:(B2)

Rs. Lakhs

X=U+V+W

B3: Winter

Normal

Rs. Lakhs

Y=B3N*K

Peak

Rs. Lakhs

Z=B3Pl

OFF-Peak

Rs. Lakhs

AA=B30P*M

Totalfirm in winter:(B3)

Rs. Lakhs

AB=Y+Z+AA

Total firm:Energy charges

Rs. Lakhs

AC=T+X+AB

Total firm: fixed+energy charges

Rs. Lakhs

AD=AC+P

Total charges: firm+infirm

Rs. Lakhs

AE=O+AD

Fuel andpower purchase cost adjustment

Rs. Lakhs

AF=B*N

Transmissioncharge

Rs. Lakhs

SLDCCharge

Rs. Lakhs

Others(Tobe specified)

Rs. Lakhs

Less:Incentive/Rabate for timely payment etc.

Rs. Lakhs

Overallcost

Rs. Lakhs

AK = Sum(Ae:AI) - AJ

* Rate of Energy Charge in Paise/Unit shall be calculated on annual basis considering both variable and fixed cost and quantum of energy.

(1)Source of energy purchased, purchase rate, quantum of energy purchased, escalation / rebate adjustment clause in the purchase rate, if any, may be given along with all the relevant details. Whether there is any dispute on purchase rate and if yes, the details thereof may be submitted.

(3)Whether the competent authority has approved the purchase rates as per the Act and if not, details thereof.

(4)Whether any procurement is made from co-generation / renewable sources of energy. If yes, details thereof may be submitted.ApplicantAnnex 1Form 1.11 : Cost of Fuel (Stationwise)

Sl.

Station

Unit

Derivation

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Gross Generation

Anxilliary consumption

Sent-out Energy

3=1-2

Station Heat Rate

kCal/kwh generated

Total Heat Required

GCal

5=1*4

Specific Oil Consumption

ml/kwh

Oil Consumption

7=6x1

Heat Value of Oil

kCal/litre

Heat from Oil

GCal

9=7x8

10.

Heat from Coal

GCal/kg

10=5-9

11.

Heat Value of Coal

kCal/kg

12.

Coal Consumption

Tonne

12=10/11

13.

Coal requirement considering TransitLoss

Tonne

14.

Average Price of Oil

Rs./KL

15.

Average Price of Coal

Rs/Tonne

16.

Cost of Oil

Rs. Lakhs

16=7x14

17.

Cost of Coal

Rs. Lakhs

17=13x15

18.

Total Fuel Cost

Rs. Lakhs

18=16+17

Notes:- 1. Where any Norm has been specified by the Commission for any parameter, calculation is to be based on such parameters only.

2. Main sources of fuel supply and break up of fuel prices (Gradewise) to be submitted as per specified format.

3. The normative values of various parameters like station heat rate and secondary fuel consumption etc. adopted, if any, may also be submitted.

4. Cost of Fuel in aggregate for all the stations are to be submitted in a separate sheet.

ApplicantAnnex 1Form 1.12 : Expenditure - Cost of Energy from own Generation - StationwiseRs. Lakhs

Ref.

Particulars

Previous Year

Base Year

Ensuing Year

Basis for estimation for ensuingyear

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

(i)

Cost of energy from ownGeneration – allstationsExcludes expense shown under any other head

As per Form B

Fuel costcoaloil

(ii)

Coal & Ash handling charges

(iii)

Demmurage for Transportation of fuel

(iv)

Water charges

(v)

Consumption of stores & spares

(vi)

Repairs & Maintenance (excluding Salaries etc& stores)

BuildingPlant & MachineriesOthers

(vii)

Employee costsSalaries &WagesBonusContribution to fundsWelfare Expensive

(viii)

Depreciation

(ix)

Travelling Expenses

(x)

Vehicles Maintenance

(xi)

Telephone Expenses

(xii)

Security Charges

(xiii)

Other management & Administrative Expenses

(xiv)

Expenses due to penalty, fines etc.

Overall (1.12)

Note:- 1. Expenses specifically attributable to generating stations and chargable to Revenue account have to be shown as such above and others to be included under centrally maintained expenses. These details are to be shown station-wise.

2. O&M charges of all the plants including that of CHP and ASH Handling Plant and other auxiliary services are to be shown under a Repairs and Maintenance of Plant and Machinery.

3. Under Employee Cost, cost of own and contracted manpower in regular establishments are to be shown separately. The corresponding number of manpower to the said cost for both own and contracted manpower in regular establishments are to be shown separately in two separate rows.

4. For the purpose of item (iii) data for previous year(s) and base year have to be submitted for the year for which tariff is being determined under these regulations.

Annex 1Form 1.13: Expenditure - Transmission of energyRs. Lakhs

Ref.

Particulars

Previous Year

Base Year

Ensuing Year

Basis for estimation for ensuingyear

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Expenses on Distribution of energy excludesexpenses shown under any other head

As per Form B

(i)

Consumption of stores & Spares

(ii)

Repair & Maintenance (Salaries etc &stores)BuildingTransmission &DistributionAssetsOthers

(iii)

Employee costsSalaries &WagesBonusContribution to fundsWelfare expenses

(iv)

Depreciation

(v)

Travelling Expenses

(vi)

Vehicles Maintenance

(vii)

Telephone Expenses

(viii)

Security Charges

(ix)

Other management & Administrative Expenses

(x)

Expenses due to penalty, fines etc.

(xi)

Others (Specify)

Overall (1.13) (Transmission)

Note:- 1. Expenses specially attributable to transmission activities and chargeable to revenue account are to be shown above and others are considered under centrally maintained expenses.

2. Under employee cost, cost of own and contracted manpower in regular establishments are to be shown separately.

Annex 1Form 1.14 : Average System Demand for Transmission SystemMW

Season/Time of the day	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
	Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1.Summer2.Monsoon3. Winter
Grand total:

Note:- 1. Average System Demand means average of the daily peak for the concerned period.ApplicantAnnex 1Form 1.15 : Expenditure - Distribution of EnergyRs. Lakhs

Ref.

Particulars

Previous Year

Base Year

Ensuing Year

Basis for estimation for ensuingyear

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Expenses on Distribution of energy excludesexpenses shown under any other head

As per Form B

(i)

Consumption of stores & Spares

(ii)

Repair & Maintenance (Salaries etc &stores)BuildingTransmission &DistributionAssetsOthers

(iii)

Employee costsSalaries &WagesBonusContribution to fundsWelfare expenses

(iv)

Depreciation

(v)

Travelling Expenses

(vi)

Vehicles Maintenance

(vii)

Telephone Expenses

(viii)

Security Charges

(ix)

Other management & Administrative Expenses

(x)

Expenses due to penalty, fines etc.

(xi)

Others (Specify)

Overall (1.15)

Note:- 1. Under Employee Cost, cost of own and contracted manpower in regular establishment are to be shown separately.ApplicantAnnex 1Form 1.16: Expenditure - Sale of energy.Rs. Lakhs

Ref.

Particulars

Previous Year

Base Year

Ensuing Year

Basis for estimation for ensuingyear

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Expenses on Distribution ofEnergy Excluding Expenses shown under any other head

As per Form B

(i)

Consumption of stores & Spares

(ii)

Repair & Maintenance (excluding Salaries etc& stores)

(iii)

Employee costsSalaries &WagesBonusContribution to fundsWelfare expenses

(iv)

Depreciation

(v)

Travelling Expenses

(vi)

Vehicles Maintenance

(vii)

Telephone Expenses

(viii)

(ix)

Computer Maintenance Expenses

(x)

Stamps & Courier Charges

(xi)

Other management & AdministrativeExpenses

(xii)

Expenses due to penalty, fines etc.

(xiii)

Others (Specify)

Overall (1.13) (Transmission)

1. Under Employee Cost, cost of own and contracted manpower in regular establishments are to be shown separately.

ApplicantAnnex 1Form 1.17: other expenses - Centrally maintainedRs. Lakhs

Ref.

Particulars

Previous Year

Base Year

Ensuing Year

Basis for estimation for ensuingyear

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

(a)

Rent, Rates & Taxes(Otherthan taxes on income & profits)

As per Form B

(b)

Interest

(i)

Interest on capitalexpenditure, loans & Public Deposits

(ii)

Interest on temporaryAccommodation [Form 1.17a]

(iii)

Interest on working capital[Form 1.17b]

(iv)

Interest on Security Depositat rates specified by the Commission calculated on average basis

(v)

Interest on advance fromconsumers.

(vi)

Other finance charges [Form1.17c]

(vii)

Lease Rental

(viii)

Delayed Payment Surcharge

(c)

Bad Debts (see regulation5.10.1)

(d)

Legal charge

(e)

Consultancy fees,charge and expenses

(f)

Auditors fees

(g)

Depreciation

(h)

Advance against depreciation[Form 1.17e]

(i)

Foreign Exchange ratevariation on loanrepayments[Form 1.17d]

(j)

Other expenses

(k)

Insurance Premium Payable[Form 1.17f]

(l)

Employee costs & Directorsfees & expenses

(i)

Salaries & Wages

(ii)

Bonus

(iii)

Contribution to Funds

(iv)

Welfare Expenses

(v)

Directors fees & expenses

(vi)

Other(Specify) if any

(m)

Repair & Maintenance(Excluding salaries etc & Stores)

(n)

Impact of Service Tax onrepair & maintenance

(o)

Travelling Expenses

(p)

Postage

(q)

Security

(r)

Intangible assets written off

(s)

Telephone, telex, etc

(t)

Vehicle Running &Maintenance

(u)

General Establishment charges

(v)

Terminal Benefits

(w)

Taxes on income/profit

(x)

Others to be specified, if any

Overall (1.17)

Notes : 1. Expenditure chargeable to Revenue Account are only to be submitted.

2. If Expenses are taken at Gross basis, the total amount allocated/proposed to be allocated to Capital Account should be shown as deductions.

ApplicantAnnex 1Form 1.17(a):Interest om temporary Accommodation.Rs. Lakhs

Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
OpeningBalanceRepaymentsfor the yearClosingBalanceInterest on Temporary Accommodation
Total

Annex 1Form 1.17(b): Interest on working CapitalRs. Lakhs

Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
A. Gross SalesB1. Less:DepreciationB2. Less: DeferredRevenue ExpenditureB3. Less: Return onEquityB. Total deductions:(sum B1 : B3)C. Allowable GrossSales for Working CapitalD. Allowable WorkingCapital @ 18% on CE. Interest at State Bank Short Term PLR rate orat actual rate of borrowing, whichever is less
F. Interest on Working Capital

Annex 1Form 1.17(c): other Finance chargeRs. Lakhs

Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
GuranteeCommissionFront EndfeesBankchargesPublicDeposit an Advance against electricity billL/COpening chargesFees andExpenses for RestructuringCost ofhedgingOthers (Specify)
Overall

ApplicantAnnex 1Form 1.17(d): Foreign Exchange Rate Variation (FERV) - YearwiseRs. Lakhs

For the Ensuing Year	Amount of Loan Repayable in ForeignCurrency	Actual/Estimated Rate of Repayment	Original Rate of Drawal	FERV for the year
Loan 1Loan 2 and so on	(1)	(2)	(3)	4=1x(2-3)

Overall

Annex 1Form 1.17(e) : Advance against Depreciation (AAD)Rs. Lakhs

Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1. Total allowablerepayment of loan during the year2. 1/10th oforiginal loan amount net of disallowed loans if any3. Maximumpermissible amount of loan repayment restricted to 1/10th oforiginal admitted loan4. Depreciation asper Form B5. Allowable advance against depreciation (3-4)

ApplicantAnnex 1Form 1.17(f): Insurance premium PayableRs. Lakhs

Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
Overall

Annex 1Form 1.17(g) Interest CreditRs. Lakhs

Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1. Depreciation as per Form B2. Repayment as per Form C3. Excess Fund created (1-2, if 1>2)4. Weighted average rate of interestof existing loan5. Interest credit
Overall

Note:- Interest Credit will be allowed during the period of Loan repayment onlyApplicantAnnex 1Form 1.17(h) Break-up of Employee Cost

Category	Sl. No.	Particulars	Own Employees	Employees on Contract in RegularEstablishment
A		Expenditure
1	Salary and Wages
a. Basic Pay
b. Dearness Allowances
c. Other Allowances
2	Statutory Retirement Benefit
a. Gratuity
b. Company's contribution to PF
c. Company's contribution to Pension Scheme
3	Statutory Bonus and Ex-Gratia
4	LTC
5	Leave Encashment
6	Workmen and staff welfare expenditure
7	Others, if any
B	Contribution for shortfall in interest of PFFund, if any
C	Production / Performance incentive toEmployees
D	Number of Personnel
Note:- (i) In serial no. 7 of CategoryA under the head "Others", specific head to bementioned. Incentive to employees related toperformance/production shall not be included under any head,except C.(ii) This form is to be filled for eachensuing year separately.(iii) This form shall be filled upseparately for each area of electricity business as specified inregulation 5.9.3 of these regulations.

ApplicantAnnex 1Form 1.17(i) Details of arrear against wage revision

Category	Sl. No.	Particulars	Arrear Annual Expenditure for theyear concerned
A		Expenditure
1	Salary and Wages
a. Basic Pay
b. Dearness Allowances
c. Other Allowances
2	Statutory Retirement Benefit
a. Gratuity
b. Company's contribution to PF
c. Company's contribution to Pension Scheme
3	Statutory Bonus and Ex-gratia
4	LTC
5	Leave Encashment
6	Workmen and staff welfare expenditure
7	Others, if any
B	Contribution for shortfall in interest of PFFund, if any
C	Production / Performance incentive toEmployees
D	Number of Personnel
Note:- (i) In the above submittedformat production incentive shall not be included under any headas mentioned above. Specific head to be mentioned. Incentive toemployees related to performance/production shall not be includedunder any head , except C.(ii) This form is to be filledfor each ensuing year separately.(iii) This form shall befilled up separately for each area of electricity business asspecified in regulation 5.9.4 of these regulations.

ApplicantAnnex 1Form 1.17(j) Statement of penalty I fine / cess etc.

Name of Statute	Type of Payment	Amount	Reasons	Remedial measures
Environmental (Prevention) Act, 1986
Income Tax Act. 1961
Electricity Act, 2003
Others
Note:- (i) This form is to be filled for each ensuing yearseparately(ii) This form shall be filled up separately foreach area of electricity business as specified in regulation5.14.2 of these regulations

Form 1.17(k) Cost of Outsourcing

Heads	Cost	Scope of work and service to beprovided *
(a) Administration & General Expenses—Call Centre—Security Services— Office Transportation—Courier Services— Retail Outlet Services—Pre-paid Vending Machine Services— Revenue Collection/Billing Services(b) Repair & Maintenance Expenses—Services*—Spares— Consumables— Manpower(c) Operational Services(d) ManagementServices(e) Others

* In case of Service it is to be mentioned that whether spares and consumables are to be provided, what service to be provided and how much manpower to be provided.Note:- This form shall be filled up separately for each area of electricity business as specified in regulation 5.22.1.ApplicantAnnex 1Form 1.18 : Original Cost of Fixed Assets

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
(1)(2)(3)(4)(5)(6)	Generation AssetsState wiseStation1Station 2 and so onTotalTransmissionAsstesDistribution AssetsMeeterial AssetsOtherAssetsLess: Contribution from consumers including advancefrom themTotal (1+2+3+4+5-6)

Notes:- (1) Generation assets will include assets up to Station Bus bar. Transmission assets will be from Station Bus bar to EHT/HT sub-station. Distribution assets will be assets up a CD to metering point of sales excluding cost of meters.

(2)Approval of capital expenditure is to be obtained from the Commission for the ensuing year (whether included in fixed assets or capital work-in-progress) where such capital (7),expenditure on assets individually or in aggregate exceeds the limits specified in Regulation 2.8.2.3 and 2.8.4.1.

(3)The original value of the assets, if any, retired or not available for use is not to be included . Figures for ensuing year, current year and previous year of the assets so retired/likely to be retired/ not available for use are to be submitted.

(4)Period during which the units of the operational power stations were scheduled to be under planned repairs and maintenance or were under major repairs other than the above, re a' as contained in Form-A may be submitted.

(5)In case the cost of any assets has been revalued, or purchased on revalued cost basis, the &tails thereof, along with the year of revaluation are to be submitted.

(6)Foreign exchange variation charged/adjusted, if any, is to be separately indicated.

(7)Figures for capital expenditure for projects under construction are to be separately indicated.

(8)Original cost of the asset at the beginning of the year and addition/retirements during the year are to be separately shown for the previous year, current year and the ensuing year.

(9)Overall amount of expenditure is to be limited to the amount approved by the Commission.

(10)Any expenditure on replacement arising out of renovation and modernisation or extention of like of old fixed assets is to be dealt as specified in the regulation 5.2_7 (iv)ApplicantAnnex 1Form 1.18(a) : Original Cost of Works in ProgressRs. Lakhs

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
(1)(2)(3)(4)	Opening BalanceAdditional Capital Expenditure for the yearAmount transferred to Fixed AssetsClosing Balance
	Total

Notes:- 1. Expenditure on Works in Progress for Plan and Non-Plan outplay should be given separately

2. Expenditure on Work in Progress should be provided itemwise

3. Expenditure on Work in Progress should include Interest during construction

4. Unusual delay of expenditure booked under Works in Progress, but not transferred to the Fixed Assets are to be separately indicated and justified in the form of a note

5. Overall Expenditure should not exceed the amount approved by the Commission

ApplicantForm 1.18(b): Intangible Assets

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1	Cumulative Opening Balance (Gross)

2	Cost incurred during the year

3	Gross Intangible Asset at the end of the year (1+ 2)

4	Cumulative Amount written off at the beginning ofthe year

5	Amount written off during the year
6	Cumulative amount written off at the end of theyear (4 + 5)

7	Cumulative Closing Balance (Gross) (3 - 6)

	Total

Annex 1Form 1.18(c)(i) Investments

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected

	Total

Form 1.18(c)(ii) : Income from InvestmentsRs. Lakhs

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected

	Total

Annex 1Form 1.19(a) : Capital Expenditure for the yearRs. Lakhs

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals or Admitted by theCommission	Actuals or Admitted by theCommission	Actuals or Admitted by theCommission	Actuals or Admitted by theCommission	Estimated	Projected	Projected	Projected	Projected	Projected
A(1)	General Capital ExpenditureGeneration CapitalExpenditureStation wiseStation 1Station 2 and so
	Overall Generation Capital Expenditure
(2)	Transmission Capital Expenditure
(3)	Distribution Capital Expenditure
A	Overall General Capital Expenditure (1+2+3)
B	Special Projects as per Note 2 of Form 1.18
	Generation
	Transmission
	Distribution
	Overall Special Projects
	Capital Expenditure (A+B)

Notes:- 1. To be specified separately for the previous year, current year and the ensuing year.

2. Plan and Non-Plan expenditure are to be shown separately.

3. Expenditure should include Interest during construction.

4. Overall amount of expenditure should be limited to the amount admitted by the Commission.

5. This format shall be submitted with perspective plan in pursuance to Schedule - 2.

ApplicantAnnex 1Form 1.19(b) : Overall Capital Expenditure ProgrammeRs. Lakhs

Ref.

Particulars

Original Project Cost (at latestapproved)

Cumulative Expenditure

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Expenditure to be spilled beyondControl period

Actuals

As approved by the Commission

Actuals

Estimated

Projected

A(a)(b)(c)

Capital Expenditure Plan for the exis ingon-going Projects

StationwiseGeneration CapitalExpenditureTransmission CapitalExpenditureDistribution Capital Expenditure

Overall Capital Expenditure Plan for existingon-going Projects

B(a)(b)(c)

Capital Expenditure Projects completed in thelast previous year(s) or to be completed in the Base year

ProjectwiseGeneration CapitalExpenditureTransmission CapitalExpenditureDistribution Capital Expenditure

Overall Capital Expenditure Projects completed inthe last previous year(s) or to be completed in the Base year

C(a)(b)(c)

Capital Expenditure Programme for new projectsfor which Investment Plan submitted for approval of theCommission

ProjectwiseGeneration CapitalExpenditureTransmission CapitalExpenditureDistribution Capital Expenditure

Expenditure Programme for new projects for whichInvestment Plan submitted for approval of the Commission

Overall Capital Expenditure (A + B + C)

Notes:- 1. To be specified separately for the previous year(s), base year and the ensuing year(s)

2. Plan and Non-Plan expenditure are to be shown separately

3. Expenditure should include Interest during construction but to be indicated separately

4. For the Base year and ensuing year(s) which has already passed related to a control period, the actual expenditure is to be provided.

5. This format shall be submitted with perspective plan in pursuance to Schedule - 2

ApplicantAnnex 1Form 1.19(c) : Project Specifications

Ref.

Name of the Project with briefdescription

As approved in investment Plan

Latest approved revision

Target set upto last previous year

Target achieved uoto last previousyear

Cumulative Expenditure upto lastprevious year

Cumulative Expenditure opto lastpreviews Year

Reason for variation

Estimated Target dale of completion

Estimated Project Cost

Base Year

Ensuing Year

Expenditure to be spilled beyondControl period

One

Two

Three

Four

Five

Target date of completion

Original Project Cost

Target date of completion

Original Project Cost

Actuals

As approved by the Commission

Projected

Actuals/Estimated

Projectwise

(a)

Generation Capital Expenditure

(b)

Transmission Capital Expenditure

(c)

Distribution Capital Expenditure

Overall CapitalExpenditure (a + b +c)

Notes:

1. Plan and Non-Plan expenditure are to be shown separately

2. Expenditure should include Interest during construction but to be indicated separately

3. The reasons for time over run and consequential cost over run are to be specifically mentioned. In the event of actual expenditure is more than the approved expenditure then separate approval is to be obtained from the commission as per these regulations.

4. For the Base year and ensuing year(s) which has already passed related to a control period, the actual expenditure is to be provided.

5.

This format shall be submitted with perspective plan in pursuance to Schedule - 2.ApplicantAnnex 1Form 1.20(a) Equity BaseRs. Lakhs

Sl. No.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1	Actual equity base at the beginning of the year
2	Admissible equity base at the beginning of theyear
3	Actual addition/deletion to equity base duringthe year
4	Actual Equity Base at the end of the year (1+3)
5	Net Addition to theoriginal cost of fixed assetsduring the year (vide submission in form 1.18)
6	Less: Asset created in terms of regulation5.15.1(iv), if any
7	Net addition to the original cost of fixed assetsduring the year other than assets created in terms of regulation5.15.1 (iv)
8	Normative addition to equity base (30% of 7)
9	Addition to equity base considered for the year(lower of 3 and 8)
10	Add: Asset created in terms of regulation5.15.1(iv)
11	Addition in equity base during the year for thepurpose of computation of return (9+10)
12	Admissible equity base at the closing of the year(2+11)
13	13 Average admissible equity base for allowingreturns (2+12)/2

ApplicantAnnex 1Form. 1.20(b): Normative Debt (Equity part converted to debt)Rs. Lakhs

Sl. No.

Particulars

Derivative

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Opening gross normative debt

Less: Cumulative repayment of normative debt upto previous year

Opening net normative debt

a = A1-A2

Actual addition to debt for the year

Additional to the fixed assets during the year

Normative debt

d = 70%

Normative addition to debt for the year

e = cxd

Addition to debt for the year to be considered toARR

f = higher of b and e

Addition gross normative debt during the year

G1 = f-b

Repayment of normative debt during the year

Net additional gross normative debt during theyear

g = G1xG2

Closing balance of net normative debt(i.e.closing gross normative debt (B1)over cumulative repayment ofnormative debt up to the end of the year (B2)

h = a+g

Average balance of net normative debt

i = a+h/2

Weighted average rate of interest

J in %

Allowable interest on normative debt

k = i x j

Closing gross normative debt

B1 = A1xG1

Cumulative repayment of normative debt up to theend of the year

B2 = A2+G2

Annex 1Form 1.21: Special Allocations.Rs. Lakhs

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
(A)(B)	Special AllocationsAppropriation toReserve for unforeseen exigenciesOthers, if any, to be specified
Total (A+B)

Note:- For the purpose of this form, appropriation to reserve for unforeseen exigencies shall be taken as per regulation 5.11.ApplicantAnnex 1Form 1.22: Return on equityRs. Lakhs

Ref.

Particulars

Basis

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

(1)(2)(3)

Averageequity Base (a)Rate ofreturn (b)Return on equity (c)

Form 1.20(a)%c=a*b*0.01

Note:- Return on equity shall have to be determined as per Regulation 5.6.1.ApplicantAnnexForm 1.23 : Permitted IncentiveRs. Lakhs

Ref.

Particulars

Basis

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

(1)abcdef

Incentive for GenerationSent Out UnitsTargetPLFUnits to be sent out at target PLFAdditional Units, if>0Incentive Rate for additional generationIncentivefor additional generation

d=a-c in MUPaise/ kWhf = dxe

(2)(i)(ii)(iii)(iv)(v)(vi)

Incentive for Hydropower generatingstations.Capacity Index achievedNormative CapacityIndexExcess capacity index achieved over target, if>0Annualfixed chargesIncentive for additional capacityindexachieved

(3)(i)(ii)(iii)(iv)(v)

Incentive for TransmissionAnnualAvailabilityTarget AvailabilityExcess availability overtarget, if >0EquityIncentive for additionalavailability

(iii) = (i-ii)Form 1.20a(v)=(iv)x(iii)

Notes:- Availability and Generation of all Generating stations qualifying for such incentives are to be furnished separately.Availability under Transmission shall be Availability of Transmission System.Transmission Incentive is applicable to Transmission Licensee onlyApplicantAnnex 1Form 1.24: Benefits passed on to consumersRs. Lakhs

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
(1)	Share of savings arising out of swapping offoreign debt and equity
(2)	Share of savings arising out of restructuring ofcapital cost in terms of debt equity ratio during the tariffperiod
(3)	Sharing of excess profit over clear profit
(4)	Sharing of benefit from selling of power to thoseother than licensee or any consumer
(5)	Sharing of benefit from carbon trading
(6)	Sharing of benefit from income arising to agenerating company from supplying power to any person other thanlicensee
(7)	Any other (Specify)

Notes:- 1. Licensee/Generating Company is to furnish particulars in accordance with the Regulation 5.15.2 as applicable.

2. Only details with respect to Revenue Account are to be furnished here.

3. For the purpose of this form base year and previous year(s) data have to be submitted for the year for which tariff is being determined under these regulations.

ApplicantForm 1.25: Receipts from sale of EnergyRs. Lakhs

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
	Receipts from Sale of Energy

Notes:- actual estimates are to be furnished for previous year(s) and base year. Ending year figure should correspond with annexure 2.ApplicantAnnex 1Form 1.26: income other than sale of EnergyRs. Lakhs

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
A.	Income derived from
(i)	Rental of meters and other apparatus hired out
(ii)	Sale and repair of lamp and other apparatus
(iii)	Transfer fees (Service connection fees)
(iv)	Income from investment and bank balances
(v)	Surcharge for late payments
(vi)	Income from job at consumer premises
(vii)	Transmission/Wheeling charges
(viii)	Reactive energy Section 42
(ix)	Surcharge under section 42
(x)	Additional surcharge under Section 42
(xi)	Other Business income to the extent to be passedon consumer
(xii)	Income from Auxiliary Services
(xiii)	Other General receipts arising from and ancillaryor incidental to the business of electricity
	Sub-Total (i to xiii)
B.	Net receivable UI Charge for the previous year

*Income from all investment is to be shown except those made out of profit and/or any equity issue exclusively meant for non-core business excluding embedded generation of licensee.Note:- Licensees to exclude charges from own consumers under Transmission/Wheeling charges.Income from investment and bank balance shall not include the interest accrued from reserves and funds covered under regulation 5.24 of these regulations.Income from any investment made out of any portion of equity not covered under regulation 5.6.1.7 and also not covered as normative loan capital as per regulation 5.4.2 shall be excluded provided such amount are separately and specifically reflected in certificates or valid documents from the same auditor who has audited the annual account.ApplicantAnnex 1Form 1.27: wheeling Charge

Ref.

Particulars

Unit

Previous Year

Base Year

Ensuing Year

Four

Three

Two

One

Two

Three

Four

Five

Actuals

Estimated

Projected

Wheeling Charge

Rs. Lakhs

Employee Cost

Other Administrative & Generalcharges

Rent, Rates & Taxes

Legal charges

Auditor Fees

Repairs & Maintenance incl.Consumables

Interest

Foreign Exchange Rate Variation

Other Financing Charges

Interest on Security Deposits

Lease Rental

Depreciation

Advance against depreciation

Intangible Asset Write Off

Reserve for unforeseen exigencies

Bad Debt

Tax

Normative Return

Permitted Incentives

Special Allocations

Others if any to be specified

Gross total expenses (sum 1: 21)

Less: Income other than sale ofenergy(educed by Receipt from Wheeling Charges)

Less: Interest credit on Depreciation

Less: Net receivable UI Charges forthe previous year

Less: Others, if any, to be specified

Gross Deductions (sum 23:26)

Net Charges (22-27)

Units sold to own consumers

Units received for wheeling [Form 1.9a]

Overall Units (a+b)

Wheeling charge rate (A/B)

P/kWh

Sales to consumer and Units wheeled should correspond to the dataForm 1.28: Statement showing status of FPPCA claim

Sl #	FPPCA claim application submittedbut order is yet to be issued by the commission	FPPCA claim application is yet to beapplied
Related Year	Date of submission	Related Year	Expected date of submission	Reasons of delay against regulation2.8.72

Form-A: Planned repairs and maintenance/forced outage/major repairs for generation plants(Station-wise vis-a-vis yearwise)Name of the Station :For the year:

Unit No.	Outage	Nature(Planned)/forced	Duration in Hrs.	Summary Details	Next periods as per schedule ofplanned maintenance	Period of last majormaintenance(scheduled)	Period of last majormaintenance(actual)	Remarks
From	to

ApplicantForm-B : Details of Depreciation chargeable to revenue account for the year (Yearwise)

Particulars

Opening Balance of Original Cost of Assets

Additions of Original Cost of Assets during theyear put into use

Assets fully depreciated

Assets to be depreciated during the year

Value of Assets classified into different rates

Other rates, if any

Land- FH

Total

Retirements of Original Cost of Assets during theyear

Closing Balance of Original Cost of Assets

A. Generating Assets

Cost

Depreciation for the year

B. Transmission

Assets

Cost

Depreciation for the year

C. Distribution Assets

Cost

Depreciation for the year

D Metering Assets

Cost

Depreciation for the year

E Other Assets

Cost

Depreciation for the year

Overall

Note:- Opening Balance of Assets should match with Form 1.18ApplicantAnnex 1Form-C: Statement of loans and calculation of interest thereon for the year (yearwise)

Sl. No.	Sources of Loans	Original Amount of loan	Outstanding Balance at the beginningof the year	Normalrate of interest(%)	Penalrate of interest if any(%)	Rebate (if any) for prompt payment	Repayment due Amount/ Date	Fresh Drawal if any Amount/ Date	Interest paid /payable	Balance at the close of the year	Remarks, if any
Normal	Penal	Rabate	Total
1	2	3	4	5	6	7	8	9	10	11	12	13	14	15
112	Actual LoansA.On Capital AccountsB. On Revenue AccountsOverall ActualNormative loanOverallLess: Interest to be capitalised

Notes:- (1) The statement should be consolidated for all the loans taken separately for Capital Accounts and Revenue Accounts.

(2)Loans bearing different interest rates and terms should not be clubbed even if from same sources.

(3)Loans with variable rate of interest should be clearly identified with the mention of base date rates.

(4)In case of foreign currency loans, the exchange rates adopted at opening balance, closing balance and repayments should be mentioned. The base rate of exchange on the date of drawal of capital loan should be indicated.

(5)If loan is taken from a group company or subsidiary etc., same should be justified.

(6)Any rate of interest which is above PLR should be fully justified along with necessity of the loan.

(7)The details of fresh drawal of loan may be enclosed along with detail justifications, purpose and supporting cash flow which necessitated the drawal of loan along with investments made or proposed and average bank balances.

(8)Any default in loan repayment of loan may also be suitably explained along with relevant details.

(9)Rebate for prompt payment etc. or penalty for delayed /non-payment to be disclosed separately.ApplicantAnnex 1Form-D (1):Detail of fuel consumption for the year (Stationwise vis-a-vis yearwise)Name of the Station :Year :

Source/Name of the Coalfields	Gradewise coal consumption in MT	Overall
A	B	C	D	E	E	Washeries
Source 1
Source 2 & so on

Note:- 1. Overall figure for each row must add up to 100%.

2. Different Grades of washeries Coal is to be separately furnished.

3.

Import of coal is also to be shown as a separate source.

4.

Source means coal supply from individual coal supply from individual coal suppliers such as ECL, BCCL, CCL, MCL etc, washeries, captive mines importing companies etc.

5. Format is to be filled up properly improper filling of this format may result in a conservative assessment of cost by the commission during tariff determination.

Form-D(2): Break-up of transportation and other cost of coal (Sourcewise):Name of the station:

Element of cost	Rs
Railway freight inclusive of related other charges
Road bills
Toll and other incidental charges related to transportation
Demmurage charge
Others related to transportation
Total:

1. Format is to be filled up properly Improperly filling of this format may result in a consecutive assessment of cost by the Commission during tariff determination.

ApplicantAnnex 1Form-D(3) : Cost of Primary Fuel (yearwise)Name of the Source (Coal Suppliers) :Rs ./ TonnekCal/ Kg

Grade

Basic

Royalty

R.E. CESS

Stowing Excise

P.W. & RD CESS

P.E. CESS

AMBH

Applicable Tax

Total

Average Incidental Charges

Gross Total

Heat Value

'A'

'B' and so on

Note:- Average incidental Charges means transportation charges to the loading point (not railway freight), underloading/overloading charges, any other incidental charges, if any, and related taxes and duties considered on the basis of average expenses for each item related to such supply from each sources.Agency-wise details from major sources have to be provided separately.Basic Rates should include applicable sizing charges.Heat Value should conform to the Declared range by the Supplier.Charges should exclude transportation costs.Wherever applicable, notified Price Schedule have to be enclosed.Separate statement is to be furnished for Previous years, Base Year andProjected Years.Statement is to be furnished sourcewise.Format is to be filled UP properly. Improper filling of this format may result in a conservative assessment of cost by the Commission during tariff determination.Annex 1Form E(A): Summarised Revenue Requirement-Part-AMU

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
1.	Generation [including infirm power, if any) [Form1.3]
2.	Auxiliary Consumption [Form 1.4]
3.	Transformation loss
4.	Units delivered to system from generation(including infirm power, if any) [Form 1.5] (1-2-3)
5.	Energy Purchased [Form 1.6 (a)]
6.	Energy Received for Wheeling [Form 1 9a]
7.	Overall Gross Energy in System (4+5+6)
8.	Units sold to persons other than licensees or anyconsumers [Form 1.9b]
9.	Units sold/used for pumping energy or pumpedstorage project at bus bar [Form 1.4(b)]
10.	Additional Units allowed by Commission againstpumping energy for pumping loss
11.	Total units sold/used for pumping energy orpumped storage project (9+10)
12.	Units sold to other licensees [Form 1.9c]
13.	Additional units allowed by the commissionagainst sale to other licensee
14.	Total units sold to other licensee (12+13)
15.	Net UI (Actual drawal)
16.	Total Energy goes out of system (8 + 11 + 14 +15)
17.	Net Energy in System (7 - 16)
18.	Units sold to consumers
19.	Units wheeled [Form 1.9d]
20.	Additional units allowed for wheeling
21.	Units utilised in own premises includingconstruction power
22.	Overall Utilisation (18+19+20+21)
23.	Unutilised Units (17-22)
24.	T&D Loss %

Form E(B): Summarised Revenue Requirement - Part-BRs. Lakhs Annex 1

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
B.
1.	Fuel
2.	Power Purchase
3.	Employee Cost
	(a) Salaries
	(b) Others (specify)
4.	Other Administrative & General Charges
5.	Coal & Ash Handling
6.	Rent, Rates & Taxes
7.	Legal Charges
8.	Auditors Fees
9.	Repairs & Maintenance incl. Consumables
10.	(a) Interest
	(b) Foreign Exchange Rate Variation
	(c) Other Financing Charges
	(d) Interest on Security Deposits
	(e) Lease Rental
11.	(a) Depreciation
	(b) Advance against depreciation
12.	Intangible Asset Write Off
13.	Water Cess
14.	Bad Debt (see regulation 5.10.1)
15.	Tax
16.	Reserve for unforeseen exigencies
17.	Demmurage
18.	Others if any to be specified
19.	Total Expenditure (sum of 1 : 18)
20.	Normative Return
21.	Permitted Incentives
22.	Permitted Return (20+21)
23.	Special Allocations [Form 1.21]
24.	Gross Revenue Required (19+22+23)
25.	(a) Less : Income other than sale of energy [Form1.26]
26.	(b) Less . Benefits passed on to Consumers [Form1.24]
27.	(c) Less : Interest credit on Depreciation
28.	(d) Less : Expenses attributable to persons otherthan licensees or any consumers
29.	(e) UI charges Receivable at the end of theprevious year
30.	Total Deductions from Gross Revenue Requirements:(25:29)
31.	Aggregate Revenue Required (24-30)
32.	Subsidy received / receivable, if any
33.	Revenue from sale of Energy (Actual estimate)
34.	Average cost of Supply (Paise / Unit)
Note:-Transmission Companies are to furnish Form E(T) instead of FormE. For the item (17) under particulars, data for previous year(s)and base year have to be submitted for the year for which tariffis being determined under these regulations.* Whereactuals are not available, estimated figures are to be furnished.

Form E(T):Summarised Revenue Requirement (Transmission)

Ref.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
A.
1.	Energy Input [Form 1.7]
2.	Energy Transmitted [Form 1.7
3.	Allocated Transmission capcacity
4.	Actual Transmission Loss % [Form 1.7]
B.	Rs. InLakhs
1.	Employee Cost
	(a) Salaries
	(b)Others (specify)
2.	Other Administrative & General Charges
3.	Rent, Rates & Taxes
4.	Legal Charges
5.	Auditors Fees
6.	Repairs & Maintenance incl. Consumables
7.	(a) Interest
	(b) Foreign Exchange Rate Variation
	(c) Other Financing Charges
	(d) Interest on Transmission Users' SecurityDeposits
	(e) Lease Rental
8.	(a) Depreciation
	(b) Advance against depreciation
9.	Bad Debt [see regulation 5.10.1]
10.	Intangible Asset Write Off
11.	Tax
12.	Others if any to be specified
13.	Total Expenditure (sum of 1:12)
14.	Normative Return
15.	Permitted Incentives
16.	Permitted Return (14+15)
17.	Special Allocations [Form 1.21]
18.	Gross Revenue Required (13+16+17)
19.	(a) Less i Income other than revenue fromtransmission of energy [Form 1.26]
	(b) Less Benefits passed on to Transmission Users
	(c) Less Interest credit on Depreciation and anyothers
	(d) Less : Others if any to be specified
20.	Revenue Required (18-19)
21.	Subsidy received / receivable, if any
22.	Revenue from Transmission of Energy (Actualestimate)
23.	Transmission charge (Rs./ MW)
Note:- TransmissionLicensees are to furnish Form E(T) instead of Form E.* Where actuals arenot available, estimated figures are to be furnished.

List of Forms contained in Annex 2 [See Regulation 2.7.2]

Form No.	Description
Form 2.1	Annual Sales
Form2.1 (a)	Seasonal Sales for Summer
Form2.1(b)	Seasonal Sales for Winter
Form2.1(c)	Seasonal Sales for Monsoon
Form 2.2	Consumer details for Ensuing year (Yearwise)
Form 2.3	Annual Revenue at Current Rates (Yearwise for ensuing years)
Form 2.3(a)	Seasonal Revenue at Current Rates for Summer (Yearwiseforensuing years)
Form 2.3(b)	Seasonal Revenue at Current Rates for Monsoon (Yearwise forensuing years)
Form 2.3(c)	Seasonal Revenue at Current Rates for Winter (Yearwise forensuing years)
Form 2.4	Low & Medium Voltage Supplies - Existing Rates
Form 2.5	High Voltage Supplies - Existing Tariff Structure
Form 2.6	Details of Existing Rates
Form 2.7	Impact on Fixed Charges, Interruption Benefits, Rebates andSurcharges, Minimum Charges etc.on Revenue at Existing Tariff(Yearwise for ensuing years)
Form 2.7.1	Details of Annual Power Factor Rebate / Surcharge on Revenueat existing tariff (Yearwise for ensuing years)
Form 2.7.2	Details of Annual Load Factor Rebate / Surcharge on Revenue atexisting tariff (Yearwise for ensuing years)
Form 2.7.3	Details of Annual TOD benefits at existing tariff (Yearwisefor ensuing years)
Form 2. 8	Meter Rental (Existing)
Form 2.9	Existing broad financial terms of supply

Form 2.1: Annual Sales

Classes of Consumers (As applicable as perAnnexure - C1)	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
LV & MV Consumers:






OVERALL LV & MV:
HV & EHV Consumers:




OVERALL HV & EHV:

Overall

1. For all categories, details are to be provided for relevant tariff sub-categories as existing, as applicable.

2. Total of Form 2.1 (a), 2.1 (b) & 2.1 (c) must correspond to the figures in Form 2.1.

3. For any classes of consumers which do not exist in any of the previous year and base year but now exist in a reclassified category shall be properly indicated mentioning its identification in the previous category.

4. Time-strata wise data for previous years and base year for each class of consumers are to be provided for the class of consumers for whom TOD tariff is applicable now and have consumptions.

ApplicantForm 2.1(a): Seasonal Sales for Summer

Classes of Consumers (As applicable as perAnnexure - C1)	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
LV & MV Consumers:






OVERALL LV & MV:
HV & EHV Consumers:




OVERALL HV & EHV:

Overall

1. For all categories, details are to be provided for relevant tariff sub-categories as existing, as applicable.

2. Total of Form 2.1 (a), 2.1 (b) & 2.1 (c) must correspond to the figures in Form 2.1.

3. For any classes of consumers which do not exist in any of the previous year and base year but now exist in a reclassified category shall be properly indicated mentioning its identification in the previous category.

4. Time-strata wise data for previous years and base year for each class of consumers are to be provided for the class of consumers for whom TOD tariff is applicable now and have consumptions.

Form 2.1(b): Seasonal Sale for Monsoon

Classes of Consumers(As applicable as per Annexure - C1)	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
LV &MV Consumers:






OVERALLLV & MV:
HV &EHV Consumers:




OVERALLHV & EHV:

Overall

1. For all categories, details are to be provided for relevant tariff sub-categories as existing, as applicable.

2. Total of Form 2.1 (a), 2.1 (b) & 2.1 (c) must correspond to the figures in Form 2.1.

3. For any classes of consumers which do not exist in any of the previous year and base year but now exist in a reclassified category shall be properly indicated mentioning its identification in the previous category.

4. Time-strata wise data for previous years and base year for each class of consumers are to be provided for the class of consumers for whom TOD tariff is applicable now and have consumptions.

Form 2.1: Seasonal Sale for Winter

Classes of Consumers (As applicable as perAnnexure - C1)	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	One	Two	Three	Four	Five
Actuals	Actuals	Actuals	Actuals	Estimated	Projected	Projected	Projected	Projected	Projected
LV & MV Consumers:






OVERALL LV & MV:
HV & EHV Consumers:




OVERALL HV & EHV:

Overall

1. For all categories, details are to be provided for relevant tariff sub-categories as existing, as applicable.

2. Total of Form 2.1 (a), 2.1 (b) & 2.1 (c) must correspond to the figures in Form 2.1.

3. For any classes of consumers which do not exist in any of the previous year and base year but now exist in a reclassified category shall be properly indicated mentioning its identification in the previous category.

4. Time-strata wise data for previous years and base year for each class of consumers are to be provided for the class of consumers for whom TOD tariff is applicable now and have consumptions.

Form. 2.2: Consumer details for ensuing year (year-wise)

Classes of Coinsumers (As applicable as perAnnexure — C1)	Catetory / Sub category-wise	Consumer number	Slab-wise MU	Billing cycle characteristic(Monthly/Quaterly/Variable Quaterly)
Sale	('000)
LV & MV Consumers:





OVERALL LV & MV:
HV & EHV Consumers:




OVERALL HV & EHV

OVERALL

(i)For all cateories, details are to be provided for relevent tariff sub-categories as existing.

(ii)Slab-wise Units are to be provided for category/sub-category where income-tax or follow on tariff structure exists.

(iii)Number of consumers must corrspond to the numder in form 2.1.

(iv)variable Quanterly cycle means the periods of quaeterly billing cycle is ranging from cosumer to customer within same class of comsumers.

Applicant.Form 2.3 Statement showing annual revenue at current rates(Yearwise for ensuing year)

		Current Rates
Classes of Consumers(As applicable as perAnnexure—C1)	Annual Sales Volume	Gross Revenue	FPPCA etc.if any	Subsidy from External Sources, if any	Gross Revenue for full year	Rebates & other charges	Net Revenue for full year
	MU	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs
LV & MV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable









Minimum Charge
Overall LV & MV Consumers
HV & EHV Consumers
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable










Overall HV & EHV Consumers:
Overall (A)
Break-up of rebates etc. reducing revenue
Power Factor Rebate
Load Factor Rebate
Rebate for supply at high voltage
Specified Rebates
Timely payment Rebate
Minimum Charge
Excess Drawal Charges
Overall effects of rebates etc reducing revenue (B)
Total Revenue from sale of electricity (A+B)

1. In case of unmetered supply, rates are to the multiplied with estimated usage.

2. Meter Rental and late payment surchange are not to be included here but in Annexure 1, Form 1.26.

3. Duties and taxes, if any, are not to be included herein.

4. Consumer details are to be provided Subcategories, slabwise and time stratawise in applicable cases.

5. Total of Form 2.3(a), 2.3(b) & 2.3(c) must be summated to the figures in Form 2.3.

Form 2.3(a) Statement Showing Annual Revenue At Current Rates (Yearwise for ensuing years)

		Current Rates		Full year Revenue		Current Rates	Full year Revenue
Classes of Consumers (As applicable as perAnnexure—C1)	Annual Sales Volume	Gross Revenue	FPPCA etc. if any	Subsidy from External Sources, if any	[Gross Rate Basis]	Rebates & other charges	Net Rate	[Net Rate Basis]
	MU	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Paise/ Unit	Rs. Lakhs
[1]	[2]	[3a]	[3b]	[3c]	[4]	[5]	[6]	[7=8/2]]	[8=4-6]
LV & MV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable









Minimum Charge
Overall LV & MV Consumers
HV & EHV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable










Overall HV & EHV Consumers:
Overall (A)
Break-up of rebates etc. reducing revenue
Power Factor Rebate
Load Factor Rebate
Rebate for supply at high voltage
Specified Rebates
Timely payment Rebate
Minimum Charge
Excess Drawal Charges
Overall effects of rebates etc reducing revenue (B)
Total Revenue from sale of electricity (A+B)

1. In case of unmetered supply, rates are to be multiplied with estimated usage.

2. Meter Rental and Late payment surcharge are not to be included here but in Annexure 1, Form 1.26.

3. Duties and taxes, if any, are not to be included herein.

4. Consuner details are to be provided Subcategorieswise, slabwise and time stratawise in applicable cases.

5. Total of Form 2.3(a), 2.3(b) & 2.3(c) must be summated to the figures in Form 2.3.

ApplicantForm 2.3(b): Statement showing seasonal revenue at current rates for monsoon(yearwise for ensuing years)

		Current Rates		Full year Revenue	Current Rates	Full Year Revenue
Classes of Consumers (As applicable as perAnnexure—C1)	Annual Sales Volume	Gross Revenue	FPPCA etc. if any	Subsidy from External Sources, if any	[Gross Rate Basis]	Rebates & other charges	Net Rate	[Net Rate Basis]
	MU	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Paise/Unit	Rs. Lakhs
[1]	[2]	[3a]	[3b]	[3c]	[4]	[5]	[6]	[7=8/2]	[8=4-6]
LV & MV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable









Minimum Charge
Overall LV & MV Consumers :
HV & EHV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable










Overall HV & EHV Consumers:
Overall (A)
Break-up of rebates etc. reducing revenue
Power Factor Rebate
Load Factor Rebate
Rebate for supply at high voltage
Specified Rebates
Timely payment Rebate
Minimum Charge
Excess Drawal Charges
Overall effects of rebates etc reducing revenue (B)
Total Revenue from sale of electricity (A+B)

1. In case of unmetered supply, rates are to be multiplied with estimated usage.

2. Meter Rental and Late payment surcharge are not to be included here but in Annexure 1, Form 1.26.

3. Duties and taxes, if any, are not to be included herein.

4. Consumer details are to be provided Subcategorieswise, slabwise and time stratawise in applicable cases.

5. Total of Form 2.3(a), 2.3(b) & 2.3(c) must be summated to the figures in Form 2.3. Applicant

Form 2.3(c) : Statement Showing Seasonal Revenue At Current Rates For Winter (Yearwise for ensuing years)

		Current Rates			Full year Revenue		Current Rates	Full Year Revenue
Classes of Consumers (As applicable as perAnnexure—C1)	Annual Sales Volume	Gross Revenue	FPPCA etc. if any	Subsidy from External Sources, if any	[Gross Rate Basis]	Rebates & other charges	Net Rate	[Net Rate Basis]
	MU	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Paise/Unit	Rs. Lakhs
[1]	[2]	[3a]	[3b]	[3c]	[4]	[5]	[6]	[7=8/2]	[8=4-6]
LV & MV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable









Minimum Charge
Overall LV & MV Consumers:
HV & EHV Consumers
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable










Overall HV & EHV Consumers:
Overall (A)
Break-up of rebates etc. reducing revenue
Power Factor Rebate
Load Factor Rebate
Rebate for supply at high voltage
Specified Rebates
Timely payment Rebate
Minimum Charge
Excess Drawal Charges
Overall effects of rebates etc reducing revenue (B)
Total Revenue from sale of electricity (A+B)

1. In case of unmetered supply, rates are to be multiplied with est mated usage.

2. Meter Rental and Late payment surcharge are not to be included here but in Annexure 1, Form 1.26.

3. Duties and taxes, if any, are not to be included herein.

4. Consumer details are to be provided Subcategorieswise, slabwise and time stratawise in applicable cases.

5. Total of Form 2.3(a), 2.3(b) & 2.3(c) must be summated to the figures in Form 2.3.

Form 2.4: Low and Medium Voltage Supplies- Existing Tariff Structure

Classes of Consumers (As applicable as perAnnexure—C1)	Subcategory / Slabwise / Time stratawise	Gross Rate (p/k Wh)
Summer	Monsoon	Winter
LV & MV Consumers

Form 2.5: High & Extra volatge supplies - Existing Tariff Structure

Classes of Consumers(As applicable as per Annexure—C1)	Subcategory /Slabwise /Time stratawise	Gross Rate (p/k Wh)
Summer	Monsoon	Winter
LV & MV Consumers

Form 2.6: Category-wise Details of Existing Rates

Classes of Consumers	Item	Unit	Applicable gross rates
Summer	Monsoon	Winter
Applicable as perAnnexure Cl	Demand Charge	Rs./ KVA or Rs./ kW
Demand Charge	Paise/Unit
Energy charge	Paise/Unit
Summated Revenue Against Demand Charge	Rs.
Average monthly Load Factor
Average monthly Power Factor

Details in this form are to be provided for all tariff categories falling under two-part tariff structure or are subject to load/power factor penalty/rebates.Categorywise details for all classes of consumers like Domestic, Commercial, Industrial etc. are to be given separately.Form 2.7: Impact Of Fixed Charges, Interruption Benefits Rabates And Surcharge Minimum Charges Etc On Revenue At Existing Tariff (Yearwise For Ensuing Year)

Classes of Consumers (As applicable as perAnnexure - C1)	Fixed Charges	Interruption Benefit	Power Factor Rebate	Power Factor Surcharge	Load Factor Rebate	Load Factor Surcharge	High Voltage Supply Rebate	Rebate for others (specify)	Minimum Charge	Excess Drawal Charges








Overall

Form 2.7.1 : Detail of Annual Power Factor Rebate/Surcharge on Revenue at existing tariff (Yearwise for ensuing years)

Applicable Classes of Consumers	Average Power factor	Projected Sales	Applicable Rates	Impact	%, Gross Energy Charges
		MU	Paise/Unit	Rs. Lakhs

Note:- Details are to be furnished for all existing power factor slots for applicable categories.Form 2.7.2: Detail of annual load factor rebate/surcharge on revenue at existing tarriff(Yearwise for ensuing years)

Applicable Classes of Consumers	Average Power factor	Projected Sales	Applicable Rates	Impact	%, Gross Energy Charges
		MU	Paise/Unit	Rs. Lakhs

Note:- Details are to be furnished for all existing power factor slots for applicable categories.Form 2.7.3: Detail of annual TOD benefit at existing tarriff (yearwise for ensuing years)

Time Period		Normal	Peak	Off-peak	Overall
Projected Sales (A)	MU
Time Periodwise share of sales (B)	%
Time of the Day Tariff (C)	Paise/Unit
Normal tariff (D)	Paise/Unit
Difference in Rates (E=C-D)	Paise/Unit
Difference in Amounts (F=PA)	Rs.Lakhs

Form 2.8: Meter Rental(Existing)

Classes of Consumers(As applicable as perannexure-C1)	Phase	Particulars	Type of meters
			Electro-maechinical	electronic	TOD	Pre-paid	Any other (Specify)
	Single
		Rental (Rs./month)
		Number of consumers
		Number of meters
		Rental(Rs. Lakhs)
	Three
		Rental(Rs./month)
		Number of consumers
		Number of meters
		Rental(Rs. Lakhs)

Note:- 1: Particulars are to be provided for applicable categories

2. In the first control period and the first year of the next control periods, number of meters and rental amount in Rupees May not be furnished if data are not available. However, Utilities are to design MIS in this period so as to provide data asper this format subsequently, if not available now.

Form 2.9 : Existing Broad Financial Terms of SupplyExisting broad terms are to be given in this form. This may include but not limited to, the following :

1. Timely Payment Rebate

2. Billing Demand

3. Load Factor Rebate/Surcharge

4. Power factor Penalty/Surcharge

5. Other specified Rebates/Surcharges not covered in earlier Forms

6. Minimum charges

7. Excess Drawal Charges

8. Meter Rental as per Form 2.8

9. Others to be specified, if any, separately

All details are to be furnished for all applicable classes of consumersApplicantAnnex 3List of Forms contained in Annex 3[See Regulation 2.7.2 ]

Form No.	Description
Form 3.1	Annual Revenue at Proposed Rates (Yearwise for ensuing years)
Form 3.1(a)	Seasonal Revenue at Proposed Rates for Summer (Yearwise forensuing years)
Form 3.1(b)	Seasonal Revenue at Proposed Rates for Monsoon (Yearwise forensuing years)
Form 3.1(c)	Seasonal Revenue at Proposed Rates for Winter (Yearwise forensuing years)
Form 3.2	Low & Medium Voltage Supplies - Proposed Tariff Structurefor ensuing years (Yearwise)
Form 3.3	High Voltage Supplies - Proposed Tariff Structure for ensuingyears (Yearwise)
Form 3.4	Details of Proposed Rates for ensuing years (yearwise)
Form 3.5	Impact on Fixed Charges, Interruption Benefits, Rebates andSurcharges, Minimum Charges etc. on Revenue at Proposed Tariff(Yearwise for ensuing years)
Form 3.5.1	Details of Annual Power Factor Rebate / Surcharge on Revenueat Proposed Tariff (Yearwise for ensuing years)
Form 3.5.2	Details of Annual Load Factor Rebate / Surcharge on Revenue atProposed Tariff (Yearwise for ensuing years)
Form 3.5.3	Details of Annual TOD benefits at Proposed Tariff (Yearwisefor ensuing years)
Form 3.6	Meter Rental (Proposed)
Form 3.7	Proposed Broad Financial Terms of Supply

Form 3.1 : Statement Showing Annual Revenue At Proposed Rates (Yearwise for ensuing years) Annex 3

		Proposed Rates
Classes of Consumers (As applicable as perAnnexure—C1)	Annual Sales Volume	Gross Revenue	FPPCA etc. if any	Subsidy from External Sources, if any	Gross Revenue for full year	Rebates & other charges	Net Revenue for full year
	MU	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs	Rs.Lakhs
LV & MV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable









Minimum Charge
Overall LV & MV Consumers
HV & EHV Consumers
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable










Overall HV & EHV Consumers:
Overall (A)
Break-up of rebates etc. reducing revenue
Power Factor Rebate
Load Factor Rebate
Rebate for supply at high voltage
Specified Rebates
Timely payment Rebate
Minimum Charge
Excess Drawal Charges
Overall effects of rebates etc reducing revenue (B)
Total Revenue from sale of electricity (A+B)

1. In case of unmetered supply, rates are to be multiplied with estimated usage.

2. Meter Rental and Late payment surcharge are not to be included here but in Annexure 1, Form 1.26.

3. Duties and taxes, if any, are not to be included herein.

4. Consumer details are to be provided Subcategorieswise, slabwise and time stratawise in applicable cases.

5. Total of Form 3.1(a), 3.1(b) & 3.1(c) must be summated to the figures in Form 3.1.

Form 3.1(a):Statement showing seasonal revenue at proposed rates for summer(Yearwise for ensuing year)

		Proposed Rates			Full year Revenue		Proposed Rates	Full Year Revenue
Classes of Consumers (As applicable as perAnnexure—C1)	Annual Sales Volume	Gross Revenue	FPPCA etc. if any	Subsidy from External Sources, if any	[Gross Rate Basis]	Rebates & other charges	Net Rate	[Net Rate Basis]
	MU	Paise/Unit	Paise/Unit	Paise/Unit	Rs. Lakhs	Paise/ Unit	Rs. Lakhs	Paise/Unit	Rs. Lakhs
(1)	(2)	(3a)	(3b)	(3c)	(4)	(5)	(6)	(7=8/2)	(8=4-6)
LV & MV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable









Minimum Charge
Overall LV & MV Consumers :
HV & EHV Consumers
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable










Overall HV & EHV Consumers:
Overall (A)
Break-up of rebates etc. reducing revenue
Power Factor Rebate
Load Factor Rebate
Rebate for supply at high voltage
Specified Rebates
Timely payment Rebate
Minimum Charge
Excess Drawal Charges
Overall effects of rebates etc reducing revenue (B)
Total Revenue from sale of electricity (A+B)

1. In case of unmetered supply, rates are to be multiplied with estimated usage.

2. Meter Rental and Late payment surcharge are not to be included here but in Annexure 1, Form 1.26.

3. Duties and taxes, if any, are not to be included herein.

4. Consumer details are to be provided Subcategorieswise, slabwise and time stratawise in applicable cases.

5. Total of Form 3.1(a), 3.1(b) & 3.1(c) must be summated to the figures in Form 3.1.

Form 3.1(b): Statement showing seasonal revenue at proposed rates for monsoon (Yearwise for ensuing year)

		Proposed Rates			Full year Revenue		Proposed Rates	Full Year Revenue
Classes of Consumers (As applicable as perAnnexure—C1)	Annual Sales Volume	Gross Revenue	FPPCA etc. if any	Subsidy from External Sources, if any	[Gross Rate Basis]	Rebates & other charges	Net Rate	[Net Rate Basis]
	MU	Paise/Unit	Paise/Unit	Paise/Unit	Rs. Lakhs	Paise/ Unit	Rs. Lakhs	Paise/Unit	Rs. Lakhs
(1)	(2)	(3a)	(3b)	(3c)	(4)	(5)	(6)	(7=8/2)	(8=4-6)
LV & MV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable









Minimum Charge
Overall LV & MV Consumers :
HV & EHV Consumers
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable










Overall HV & EHV Consumers:
Overall (A)
Break-up of rebates etc. reducing revenue
Power Factor Rebate
Load Factor Rebate
Rebate for supply at high voltage
Specified Rebates
Timely payment Rebate
Minimum Charge
Excess Drawal Charges
Overall effects of rebates etc reducing revenue (B)
Total Revenue from sale of electricity (A+B)

1. In case of unmetered supply, rates are to be multiplied with estimated usage.

2. Meter Rental and Late payment surcharge are not to be included here but in Annexure 1, Form 1.26.

3. Duties and taxes, if any, are not to be included herein.

4. Consumer details are to be provided Subcategorieswise, slabwise and time stratawise in applicable cases.

5. Total of Form 3.1(a), 3.1(b) & 3.1(c) must be summated to the figures in Form 3.1.

Form 3.1(c): Statement showing seasonal revenue at proposed rates for winter(Yearwise for ensuing year)

		Proposed Rates			Full year Revenue		Proposed Rates	Full Year Revenue
Classes of Consumers (As applicable as perAnnexure—C1)	Annual Sales Volume	Gross Revenue	FPPCA etc. if any	Subsidy from External Sources, if any	[Gross Rate Basis]	Rebates & other charges	Net Rate	[Net Rate Basis]
	MU	Paise/Unit	Paise/Unit	Paise/Unit	Rs. Lakhs	Paise/ Unit	Rs. Lakhs	Paise/Unit	Rs. Lakhs
(1)	(2)	(3a)	(3b)	(3c)	(4)	(5)	(6)	(7=8/2)	(8=4-6)
LV & MV Consumers :
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable









Minimum Charge
Overall LV & MV Consumers :
HV & EHV Consumers
	Subcategorywise vis-a-vis Slabwise vis-a-vis timestratawise, where applicable










Overall HV & EHV Consumers:
Overall (A)
Break-up of rebates etc. reducing revenue
Power Factor Rebate
Load Factor Rebate
Rebate for supply at high voltage
Specified Rebates
Timely payment Rebate
Minimum Charge
Excess Drawal Charges
Overall effects of rebates etc reducing revenue (B)
Total Revenue from sale of electricity (A+B)

1. In case of unmetered supply, rates are to be multiplied with estimated usage.

2. Meter Rental and Late payment surcharge are not to be included here but in Annexure 1, Form 1.26.

3. Duties and taxes, if any, are not to be included herein.

4. Consumer details are to be provided Subcategorieswise, slabwise and time stratawise in applicable cases.

5. Total of Form 3.1(a), 3.1(b) & 3.1(c) must be summated to the figures in Form 3.1.

Form 3.2: Low and medium voltage supplies - Propsed tarriff structure for ensuing year.

Classes of Consumers(As applicable as per Annexure—C1)	Subcategory / Slabwise / Time stratawise	Gross Rate(p/kWh)
Summer	Monsoon	Winter
Lv & MV Consumers

Form 3.3: High Voltage Supplies - Proposed Tariff Structure for ensuing Year(Year-wise)

Classes of Consumers(As applicable as per Annexure—C1)	Subcategory / Slabwise / Time stratawise	Gross Rate(p/kWh)
Summer	Monsoon	Winter
Lv & MV Consumers :

Form 3.4: Category-Wise details of proposed Rates for ensuing Years(Yearswise)

Classes of Consumers	Item	Unit	Applicable gross rates
Summer	Monsoon	Winter
Applicable as perAnnexure Cl	Demand Charge	Rs./ KVA or Rs./ kW
Demand Charge	Paise/Unit
Energy charge	Paise/Unit
Summated Revenue against Demand Charge	Rs.
Average monthly Load Factor
Average monthly Power Factor

Details in this form are to be provided for all tariff categories falling under two part tariff structure or are subject to load/power factor panelty/rebates.categorywise details for all classes of consumers like domestic commericial industrial etc to be given separatelyForm 3.5: Impact of fixed charges interuption benefits, rebates amd surcharge minimun charges etc on revenue at proposed tariff(Yearwise for ensuing years)

Classes of Consumers (As applicable as perAnnexure - C1)	Fixed Charges	Interruption Benefit	Power Factor Rebate	Power Factor Surcharge	Load Factor Rebate	Load Factor Surcharge	High Voltage Supply Rebate	Rebate for others (specify)	Minimum Charge	Excess Drawal Charges

Form 3.5.1: Detail of annual power Factor reabtes/surcharge on revenue at proposed tariff(Yearwise for ensuing years)

Applicable Classes of Consumers	Average Power factor	Projected Sales	Applicable Rates	Impact	%, Gross Energy Charges
		MU	Paise/Unit	Rs. Lakhs

Note:- Details are to be furnished for all existing power factor slots for applicable categories.Form 3.5.2: Detail of Annual Power Factor Rebate/Surcharge on Revenue at proposed Tariff (Yearwise for ensuing years)Year :

Applicable Classes of Consumers	Average Power factor	Projected Sales	Applicable Rates	Impact	%, Gross Energy Charges
		MU	Paise/Unit	Rs. Lakhs

Note:- Details are to be Furnished for existing power factor slots for applicable categories.Form 3.5.3: Details of annual TOD Benefit at existing tariff(Yearwise for ensuing years)

Time Period		Normal	Peak	Off-Peak	Overall
Projected sales(A)	MU
Time periodwise share of sales(B)	%
Time of the Day Tariff(C)	Paisa/Unit
Normal tariff(D)	Paisa/Unit
Difference in rate(E=C-D)	Paisa/Unit
Difference in Amounts (F=E*A)	Rs. Lakhs

Form 3.6: Meter Rental(Proposed)

Category of consumers	Phase	Particulars	Type of Meters
			Electro-mechanical	Electronic	TOD	Pre-paid	Any other (specify)
	Single
		Rental(Rs./Month)
		Number of consumers
		Number of meters
		rental(Rs. Lakh)
	Three
		Rental (Rs./month)
		Number of consumers
		Number of meters
		Rental (Rs. Lakh)

Note:-1. Particulars are to be provided for applicable categories.

2. In the first control period and the first year of the next control period, Number of meters and Rental amount in Rupees may not be furnished if data are not available. However, Utilities are to design MIS in this period so as to provide data as per this format subsequently, if not available now.

Form 3.7 Proposed Broad Financial Terms of Supply (Year-wise)Proposed broad terms are to be given in this form. This may include but not limited to, the following :

1. Timely Payment Rebate

2. Billing Demand

3. Load Factor Rebate/Surcharge

4. Power factor Penalty/Surcharge

5. Other board terms not covered in earlier Forms

6. Minimum charges

7. Excess Drawal Charges

8. Meter Rental as per Form 3.6

9. Others to be specified, if any, separately

All details are to be furnished for all applicable tarrif categories.ApplicantAnnex 4List of Forms contained in Annexure 4[See Regulation 2.7.2 ]

Form No.	Description
Form 4( )	Input to EHT system
Form 4(ii)	Delivery to 33 & 11 KV systems from EHT system
Form 4(iii)	EHT Sales
Form 4(iv)	Losses at EHT system
Form 4(v)	Energy delivered into 33 kV distribution System
Form 4(vi)	HT sales at 33 KV
Form 4(vii)	Energy delivered from 33/20 11 KV Substations into 20 KV / 11KV 16 KV & LT system
Form 4(viii)	Energy delivered into 11 KV Distribution System
Form 4(ix)	HT Direct Sales at 20 KV / 11 KV 16 KV & 3.3 KV
Form 4(x)	Energy sold in the LT system
Form 4(xi)	Energy Losses - 33 KV and below

Form 4(i): Input to the EHT System (400 kv, 132 kv and 66kv)

(a)Own Generating Stations

SI.No	Source of Supply	Energy Delivered into the Grid System	MU
1	Thermal
2	Hydel
3	Mini-Hydro
4	Diesel
5	Gas
6	Wind
7	Renewable
8	Co-generation
Etc.

(b)Energy Purchase - sources within the State

SI.No
1
2
3
4
Etc.

(c)Energy Purchase - sources outside the State

SI.No
1
2
3
4
Etc.

(D)Others

SI.No
1
2
3
4
Etc.


Total

Form 4(ii) : Delivery to 33 & 11 kV Distribution System from EHT System (400 kV, 220 kV, 132 kV and 66 kV)MU

		Energy Received atall EHT S/Ss( 132/33 KV)existing in the Unit Area	Total Energy delivered into
SI.No.	Unit Area	Energy deliveredinto 33 kVDistribution System	Energy deliveredinto 11 kVDistribution System	33 & 11 kV Distribution System
		(a)	(b)	(a) + (b)
1
2
3
4
Etc
	Total

ApplicantForm. 4(iii): EHT Sales at 220kv, 66kv voltages

Sl. No.	Supply Voltage	No of consumers	Total Units Recorded by HT Meters


1	220kv
2	132kv
3	66kv

	Total

Form 4(iv): Losses (400 kV, 220 kV, 132 kV & 66 kV)Loss CalculationMU


(a)(b)(c)	Total Energy delivered toSystem — 4(i)Own Generating Stations — 4(i)Energy Purchase - sources within the State — 4(i)Energy Purchase - sources outside the State — 4(i)Others.— 4(i)Total Energy delivered to System —4(i)Delivered to Distribution System — 4(ii) &4(iii)Energy received at all EHT S/Ss at 33 kV —4(11)Energy received at all EHT S/Ss at 11 kV —4(11)HT Consumption at 220, 132, 66 kV — 4(iii)Delivered to Distribution System — 4(ii) &4(iii)Losses :220 kV, 132 kV, 66 kV System Losses %(a-b) / a X 100

ApplicantAnnex 4Form 4(v) : Energy Delivered into 33 kV Distribution System at the Inter-connection Points of the EHT System & other sources of GenerationMU

SI. No.	Name of the Unit Area	Energy Delivered into 33 KV Distribution System	Total Energy
		From all EHT S/Ss Existing	Other Sources of Input in the Unit Area	Delivered into
		in the Unit Area (a) .	(b)	the Unit Area
		Gross	Substation Consumption/ Export, if any	Net	Own Generation	Purchase Generation	Renewable/ Co - Generation	Others	Sub-total	(a+b)


1.
2.
3.
4.
Etc.

	Total

Form 4(vi): HT Sales at 33 kv

Sl. No.	Name of the Unit Area	Number of consumers	Total Units Recorded by 33KV HT meters













	Total HT Sales at 33KV

Annex 4Form 4(vii) : Energy delivered from 33/20/11/6 kV Substations into 20 kV, 11 kV & kV System (including LT System)MU

SI. No.	Name of the Unit Area	Energy delivered at HT from all the 33/20/11/6 kvSubstation existing in the Unit Area.












	Total

Annex 4Form 4(viii) : Energy Delivered into 11 kV Distribution System at the Inter-connection Points of the EHT System & other sources of GenerationMU

SI. No.	Name of the Unit Area	Energy Delivered into 33 KV Distribution System	Total Energy
		From all EHT S/Ss Existing	Other Sources of Input in the Unit Area	Delivered into
		in the Unit Area (a)	(b)	the Unit Area
		Gross	Substation Consumption/ Export, if any	Net	Own Generation	Purchase Generation	Renewable/ Co Generation	Others	Sub-total	(a+b)


1.
2.
3.
4.
Etc.

	Total

Annex 4Form 4(ix): HT Direct Sales at 20 kv, 11kv, 6kv& 3.3 Kv

Sl. No	Name of the Unit Area	Number of Consumers	Total Units Recorded by HT Meters













	Total

Annex 4Form 4(X): Energy Sold in the LT System

Sl. No.	Name of the Unit Area	Domestic	Commercial	Industrial	Public	Irrigation &	Others	others	others	Total
					Lighting	Agriculture	(to be specified)	(to be specified)	(to be specified)











	Total

Annex 4Form. 4(xi): Losses at 33 kv and below

1.	Losses in 33 kV System and Connected Equipment
	(i)	Total Energy delivered into 33 kV Distribution System from EHTS/Ss and other Generating Stations - 4(v)	A
	(ii)	Energy sold by HT direct sales at 33 kV - 4(vi)	B
	(iii)	Energy Delivered into 11 kV and LT System from 33/11 kV S/Ss -4(vii)	C
		Losses	A-(B+c)
		% Losses	1008{A-(B+c)}/A

2.	Losses in 11 kVand LT System and Connected Equipment
	(i)	Energy delivered into 11 kV and LT Distribution System from33/11 kV S/Ss - 4(vii)	C
	(ii)	Energy delivered into 11 kV Distribution System and EHT S/Ssand other Gen. Stn. - 4(viii)	D
		Total Energy delivered into 11 kV and LT Distribution System	C+D
	(iii)	Energy sold by HT direct sales at 11 kV - 4(x)	E
	(iv)	Energy sold in the LT System - 4(x)	F
		Total Sales	E+F
		Losses	{(C+D)-(F+F)}
		%Losses	{(c+d)-(E+F)}*100/(C+D)

Annex 5List of forms contained in annex 5[See Regulation 2.7.2]

Form No.	Description
Form 5( )	Voltage Fluctuation
Form 5(ii)	Frequency excursion
Form 5(iii)	Abstract of Outages due to tripping of HT Feeders
Form 5(iv)	Failure of Transformers (Nos.)
Form 5(v)	Major System Disturbance (Grid Disturbance)
Form 5(vi)	Electrical Accidents
Form 5(vii)	Release of Customer Bills
Form 5(viii)	Release of Service Connections
Form 5(ix)	Status of Metering
Form 5(x)	Status of Demand

Annex 5Form 5(i) Voltage Fluctuation

	Period	First six months	Last six months	First six months	Corrective Measures Proposed
of previous year	of previous year	of current year
Percentage of time	Percentage of time	Percentage of time
hen Voltage was	when Voltage was	when Voltage was
	At 33kV side	Below	Above	Below	Above	Below	Above
	of Transformer	(9%)	(6%)	(9%)	(9%)	(6%)	(9%)	(6%)
	(take off point
	of 33kV bus)
	At EHT bus	Below	Above	Below	Above	Below	Above
		12.5%	10%	12.5%	10%	12.5%	10%

Annex 5Form 5(ii): Frequency excursion

Period	First six months of previous year percentage oftime when system frequency was	Last six months of previous year percentage oftime when system frequency was	First six moths of current year percentage oftime when system fraquency was	Corrective measures proposed to maintain systemfraquency within limits
	Below 48.5 C/s	Above 51.5 C/S	Below 48.5 C/S	Above 51.5 C/S	Below 48.5 C/S	Above 51.5 C/S

Annex 5Form 5(iii): Abstract of outages of HT Feeders

	System	First six months of the Previous year	First six months of the previous year	First six months of the current year	Remedial Measures
		No of outages	Duration of outages	Average Interruption per Feeder	No of outages	Duration of outages	Average Interruption per Feeder	No of outages	Duration of outages	Average Interruption per Feeder
			(Hours.)	(Hours.)		(Hours.)	(Hours.)		(Hours.)	(Hours.)

a.	All 33kv outgoing feeders

b.	All 6kv/11kv outgoing feeders

c	Power Transformer

i)	High voltage side

ii)	Low voltage

Annex 5Form 5(iv) : FAILURE OF TRANSFORMERS (NOS)

SI. No.	Period	First six months of previous year	Last six months of previous year	First six months of current year
Items	No. of Failures	Total No. Installed	% Failure	No. of Failures	Total No. Installed	% Failure	No. of Failures	Total No. Installed	% Failure
1	EHT Transformers
	i) Auto
	ii) Power
2	Power Transformers (HT)
3	Distribution Transformers

Annex 5Form 5(v) Major System Disturbance (Grid Disturbance)

SI.No.	Period	First six months of the previous year	Last six months of the previous year	First six months of the current year
1	No. of occurrences
2	Total duration of Interruption
3	Estimated unserved energy due to such interruptions Example
	Load Prior to tha disturbance x No. of Hours of Interruption
4	No. of occasions when system was isolated from the Region Griddue to system disturbance affecting power supply in the system
5	No. of occasions when system remained stable after beingisolated from Grid due to system disturbance
6	Remedial Measures to prevent Grid system disturbance

Annex 5Form 5(vi) . Electrical Accidents

Period

First six months of previous year

Last six months of previous year

First six months of current year

Corrective Measures Proposed to avoid accidents

No. of Accidents

Items

Fatal

Non-Fatal

Fatal

Non-Fatal

Fatal

Non-Fatal

Human

Animal

Human

Animal

Human

Animal

Human

Animal

Human

Animal

Human

Animal

(a)EHT

(b)HV/LV

Annex 5Form 5(vii) : Release Of Customer Bills

Period	First six months of previous year	Last six months of previous year	First six months of current year	Actions proposed to be taken for prompt releaseof customer bills
No. of customer bills served within 30 days ofbilling period	No. of customer bills served within 30 days ofbilling period	No. of customer bills served within 30 days ofbilling period	No. of customer bills served within 30 days ofbilling period	No. of customer bills served within 30 days ofbilling period	No. of customer bills served within 30 days ofbilling period

Annex 5Form 5 (viii) : Release Of Service Connection

Period	Category	First six months of previous year	Last six months of previous year	First six months of current year	Actions proposed to be taken for providingservice connection in time
SL . No.	No. of service connections provided within 30days of valid requisitions for power supply	No. of service connections provided within 30days of valid requisitions for power supply	No. of service connections provided within 30days of valid requisitions for power supply	No. of service connections provided within 30days of valid requisitions for power supply	No. of service connections provided within 30days of valid requisitions for power supply	No. of service connections provided within 30days of valid requisitions for power supply

Form 5(ix) : Status of Metering

Sl. No.

1. .................................(Name of applicant) has made an application before the West Bengal Electricity Regulatory Commission (Commission) for determination of Tariff, Aggregate Revenue Requirement and Expected Revenue from Charges of all the ensuing years of the control period consisting............ years from..................(year) to..................(year) and the application has been admitted by the Commission on...................(date).

2. The gist of the tariff application is as follows :

(i)Tariff proposed to be made effective from the billing month of April of every ensuing year.

(ii)Details of proposed tariff (only applicable portion to be filled up).

(A)For Generating Company: (p/kWh)

(Separate figures to be given for each generating station)

Name of the Generating Station	Tariff for the Base Year	Tariff for the control period......... (year) to…..... (year)
1styear	2ndyear	3rdyear	4thyear	5thyear
Year to be indicated	Year to be indicated	Year to be indicated	Year to be indicated	Year to be indicated

(B)For Transmission Licensee: (p/kWh)

	Tariff for the Base Year	Tariff for the control period..........(year)to..........(year)
1st year	2nd year	3rd year	4th year	5th year
Year to be indicated	Year to be indicated	Year to be indicated	Year to be indicated	Year to be indicated
Rate for Long Term Customer (Rs/MW/month)
Rate for Short Term Customer (Rs/MW/day)
Rate payable by Short Term Customer in case of uncongestedtransmission network (in % sort term customer)
(a) up to 6 hours in a day in one block
(b) More than 6 hour and up to 12 hours in a day in one block
(c) More than 12 hours and up to 24 hours in a day in oneblock

(C)For Distribution Licensee (p/kWh)

	Tariff for the Base Year	Tariff for the control period........(year)to...........(year)
		1st year	2nd year	3rd year	4th year	5th year
		Year to be indicated	Year to be indicated	Year to be indicated	Year to be indicated	Year to be indicated
Average cost of supply

(iii)Projected Revenue at current tariff, Projected Aggregate Revenue Requirement and Expected Revenue from Charges at proposed tariff for the ensuing years of the control period are as follows:

(Rs. in Lakh)

	Tariff for the Base Year	Tariff for the control period.........(year)to.........(year)
1st year	2nd year	3rd year	4th year	5th year
Year to be indicated	Year to be indicated	Year to be indicated	Year to be indicated	Year to be indicated
Projected revenue at Current Tariff
Projected Aggregate Revenue Requirement
Expected Revenue from Charges at Proposed Tariff
Range of percentage of increase/ decrease sought in theapplication for each of the ensuing year compared to the baseyear.

(iv)Major reasons for increase/decrease in tariff proposed.

(v)Major factors not considered in the above increase/decrease sought, if any

(vi)Details of major changes proposed regarding applicable terms and conditions.

(vii)Any important issue.

3. Application submitted by...........(Name of applicant) may be inspected at the office of the Commission and............(other address, if any) by..........(date) and certified copies of the application or part thereof may be obtained from the office of the Commission by........(date)

4. The application made for determination of Tariff has been posted on the website of the applicant at.............(name of the web site).

5. The suggestions, objections and comments, if any, on the proposals contained in the application may be submitted at the office of the Commission at........by..........(date).

Note:- Dates will be filled up by the CommissionPlace :Date :Name and designation of the signatory submitting the proposalAnnexure - 8(See regulation 2.8.5.1)

(1)Name of the Project :

(2)Name of the Package :

(3)Reference No. & Date of Letter of Award / Letter of Interest / OrderRupees in Lakh

Item	Particulars	Amount
a	Equipment Supply Cost
b	Civil Cost
c	Erection Testing & Commissioning Cost
d	Consultancy Charges - Against the Package
e	Management Services (Outsourced if any)
f	Taxes and duties separately for item no.	a
	c
	d
	e
g	Transportation Charges for item no.	a
		b
h	Insurance Charges separately against item no. where applicable	a
	b
	c
	d
	e
i	Other cost

Note:- 1. Against item no. (a) bill of material and their cost against each material/ equipment in Indian Rupees is to be provided as separate enclosure.

2. Against item no. (b) quantity of major construction material item wise along with their quantum and prices in Indian Rupees is to be provided in separate enclosure.

3. If necessary, the Commission may ask for detail breakup on any head, as and when required.

4. 'Other Cost' shall be mentioned specifically.

List of Forms contained in Annexure 9[See Regulation 2.7.2 ]

Form No.	Description
Form P(A)	Details of Foreign Loans (Thermal/Hydro/Transmission/Distribution
Form P(B)	Abstract of Capital Cost Estimates and Schedule of commissionfor the New Projects (Thermal)
Form P(C)	Abstract of Admitted Capital Cost for the existing Projects(Thermal/Hydro/Transmission/Distribution)
Form P(D1)	Break-up of Capital Cost (Thermal)
Form P(D2)	Break-up of Capital cost for Hydro Power Generating Station
Form P(D3)	Element wise Break-up of Project Cost for Transmission
Form P(D4)	Break-up of Capital cost for Plant & Equipment (Hydro)
Form P(E)	Break-up of Construction/Supply/Service packages(Hydra/Transmission)
Form P(F)	Financial Package up to COD (Thermal/Hydro Transmission)
Form P(G)	Statement of Additional Capitalization after COD(Thermal/Hydro/ Transmission)
Form P(H)	Financing of Additional Capitalization (Thermal/Hydro/Transmission)
Form P(I)	Calculation of Weighted Average Rate of Interest on ActualLoans
Form P(J)	Details of Transmission / Distribution Lines &Sub-stations

Annexure 9Form P(A) : Details of Foreign loans (Thermal/Hydro/Transmission/Distribution) Name of the Generating Station/Transmission Project/Distribution ProjectExchange Rate atCOD Amount in Lakhs

Sl.	Particulars	Previous Year	Base Year	Ensuing Year
Four	Three	Two	One	Year One....2....3......4.....5 so on
Actuals	Actuals	Actuals	Actuals	Estimated	Date	Amount (Foreign Currency)	Exchange Rate	Amount (Rs.)
	Currency 11
A.1	At the date of Drawl 2
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	In case of Hedging3
1	At the date of hedging
2	Period of hedging
3	Cost of hedging

	Currency21
A.1	At the date of Drawl 2
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	In case of Hedging 3
1	At the date of hedging
2	Period of hedging
3	Cost of hedging

	Currency 31& so on
A.1	At the date of Drawl 2
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	In case of Hedging 3
1	At the date of hedging
2	Period of hedging
3	Cost of hedging

1. Name of the currency to be mentioned e.g. US $, DM, etc. etc.

2. In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given.

3. Furnish details of hedging, in case of more than one hedging during the year or part hedging, details of each hedging are to be given.

4. Tax (such as withholding tax) details as applicable including change in rates, date from which change effective etc. must be clearly indicated.

ApplicantAnnexure 9Form P(B) : Abstract of Capital Cost Estimates and Schedule of Commissioning for the New projects (Thermal)Name of the Generating Station:New Projects Capital Cost Estimates (Rs. in Lakh)

Board of Director/ Agency approving the Capital costestimates:
Date of approval of the Capital cost estimates:
	Present Day Cost	Completed Cost
Price level of approved estimates	As of End of.....Qtr. of the year	As on Scheduled COD of the Station
Foreign Exchange rate considered for the Capital costestimates
Capital Cost excluding IDC & FC
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. in lakh)
Capital cost excluding IDC, FC, FERV & Hedging Cost (Rs. in lakh)
IDC, FC, FERV & Hedging Cost
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. in lakh)
Total IDC, FC. FERV & Hedging Cost (Rs. in lakh)s
Rate of taxes & duties considered
Capital cost Including IDC, FC, FERV &Hedging Cost
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. in lakh)
Capital cost Including IDC & FC (Rs. in lakh)
Schedule of Commissioning
COD of Unit-I/Block-I
COD of Unit-II/Block-II
COD of last Unit/Block

Note:- 1. Copy of approval letter should be enclosed.

2. Details of Capital cost are to be furnished as per FORM-P(D1) or P(D2) or P(D3) as applicable.

3. Details of IDC & Financing Charges are to be furnished.

ApplicantAnnexure 9Form P(C) : Abstract of Admitted Capital Cost for the existing Projects (Thermal/Hydro/Transmission/Distribution)Name of the Generating Station/Transmission Project/ Distribution Project:_______________(Rs. in Lakh)

Capital Cost as admitted by WBERC

Capital cost admitted as on
(Give reference of the relevant WBERC Order with Petition No.& Date)
Foreign Component, if any (In Million US $ or the relevantCurrency)

Domestic Component (Rs. in lakh)

Foreign Exchange rate considered for the admitted Capital cost
Hedging cost, if any, considered for the admitted Capital cost

Total Capital cost admitted (Rs. in lakh)

ApplicantAnnexure 9Form P(D1) : Break-up of Capital Cost (Thermal)Name of the Generating Station: (Rs. in Lakh)

Sl. No.	Break Down	As per original Estimates	Actual capital expenditure	Liabilities/ provisions	Variation (3-4-5)	Reasons for Variation
#	(2)	(3)	(4)	(5)	(6)	(7)
1	Cost of Land & Site Development
1.1	Land
1.2	Rehabilitation & Resettlement (R&R)
1.3	Preliminary Investigation & Site development
	Total Land & Site Development
2	Plant & Equipment
2.1	Steam Generator Island
2.2	Turbine Generator Island
2.3	BOP Mechanical
2.3.1	External water supply system
2.3.2	CW system
2.3.3	DM water Plant
2.3.4	Clarification plant
2.3.5	Chlorination Plant
2.3.6	Fuel Handling & Storage system
2.3.7	Ash Handling System
2.3.8	Coal Handling Plant
2.3.9	Rolling Stock and Locomotives
2.3.10	MGR
2.3.11	Air Compressor System
2.3.12	Air Condition & Ventilation System
2.3.13	Fire fighting System
2.3.14	HP/LP Piping
	Total BOP Mechanical
2.4	BOP Electrical
2.4.1	Switch Yard Package
2.4.2	Transformers Package
2.4.3	Switchgear Package
2.4.4	Cables, Cable facilities & grounding
2.4.5	Lighting
2.4.6	Emergency D.G set
	Total BOP Electrical

2.5	C&l Package
	Total Plant & Equipment excluding taxes & Duties
2.6	Taxes and Duties
2.6.1	Custom Duty
2.6.2	Other Taxes & Duties
	Total Taxes & Duties
	Total Plant & Equipment
3	Initial spares
4	Civil Works
4.1	Main plant/Adm. Building
4.2	CW system
4.3	Cooling Towers
4.4	DM water Plant
4.5	Clarification plant
4.6	Chlorination Plant
4.7	Fuel Handling & Storage system
4.8	Coal Handling Plant
4.9	MGR & Marshalling Yard
4.1	Ash Handling System
4.11	Ash disposal area development
4.12	Fire fighting System
4.13	Township & Colony
4.14	Temp, construction & enabling works
4.15	Road & Drainage
	Total Civil works
5	Construction & Pre-Commissioning Expenses
5.1	Erection Testing and commissioning
5.2	Site supervision
5.3	Operator's Training
5.4	Construction Insurance
5.5	Tools & Plant
5.6	Start up fuel
	Total Construction & Pre-Commissioning Expenses
6	Overheads
6.1	Establishment
6.2	Design & Engineering
6.3	Audit & Accounts
6.4	Contingency
	Total Overheads
7	Capital cost excluding IDC & FC
8	IDC, FC, FERV & Hedging Cost
8.1	Interest During Construction (IDC)
8.2	Financing Charges (FC)
8.3	Foreign Exchange Rate Variation (FERV)
8.4	Hedging Cost
	Total of IDC, FC, FERV & Hedging Cost
9	Capital cost including IDC, FC, FERV & Hedging Cost

Note:- 1. In case of time & Cost over run, a detailed note giving reasons of such time and cost over run should be submitted clearly bringing out the agency responsible and whether such time & cost over run was beyond the control of the generating company.ApplicantAnnexure 9Form P(D2) : Break-up of Capital Cost for hydro power generating station (Hydro)Name of the Generating Station: _________________(Rs. in Lakhs)

Sl. No.	Head of works	Original cost as approved by Authority	Actual capital expenditure as on COD	Liabilities / provisions	Variation (3-4-5)	Reasons for Variation	Admitted cost
1	(2)	(3)	(4)	(5)	(6)	(7)	(8)
1	Infrastructure Works
1.1	Preliminary including Development
1.2	Land
1.3	Buildings
1.4	Township
1.5	Maintenance
1.6	Tools & Plants
1.7	Communication
1.8	Environment & Ecology
1.9	Losses on stock
1.10	Receipt & Recoveries
1.11	Total (Infrastructure works)
2	Major Civil Works
2.1	Dam, Intake & Desilting Chambers
2.2	HRT, TRT, Surge Shaft & Pressure shafts
2.3	Power Plant civil works
2.4	Other civil works (to be specified)
2.5	Total (Major Civil Works)
3	Hydro Mechanical equipments
4	Plant & Equipment
4.1	Initial spares of Plant & Equipment
4.2	Total (Plant & Equipment)
5	Taxes and Duties
5.1	Custom Duty
5.2	Other taxes & Duties
5.3	Total Taxes & Duties
6	Construction & Pre-commissioning expenses
6.1	Erection, testing & commissioning
6.2	Construction Insurance
6.3	Site supervision
6.4	Total (Const. & Pre-commissioning)
7	Overheads
7.1	Establishment
7.2	Design & Engineering
7.3	Audit & Accounts
7.4	Contingency
7.5	Rehabilitation & Resettlement
7.6	Total (Overheads)
8	Capital Cost without IDC, FC, FERV & Hedging Cost
9	IDC, FC, FERV & Hedging Cost
9.1	Interest During Construction (IDC)
9.2	Financing Charges (FC)
9.3	Foreign Exchange Rate Variation (FERV)
9.4	Hedging Cost
9.5	Total of IDC, FC, FERV & Hedging Cost
10	Capital cost including IDC, FC, FERV & Hedging Cost

Note:- 1. In case of time & Cost over run, a detailed note givving reasons of such time and cost over run should be submitted clearly bringing out the agency responsible and whether such time & cost over run was beyond the control of the generating company.ApplicantAnnexure 9Form P(D3) : Element wise Break-up of Project Cost for TransmissionName of the Transmission Licensee:Name of Region:Name of the Project:Name of the Transmission Element:

Sl. No.	Break Down	Cost in Rs. in lakh	Variation	Reasons for Variation	Admitted cost
		As per original Estimates	As on COD	Liabilities / Provisions
1	(2)	(3)	(4)	(5)	(6) =(3-4-5)	(7)	(8)
A	Transmission Line
1	Preliminary works
1.1	Design & Engineering
1.2	Preliminary investigation, Right of way, forest clearance,PTCC, general civil works etc.
1.3	Total Preliminary works
2	Transmission Lines material
2.1	Towers Steel
2.2	Conductor
2.3	Earth Wire
2.4	Insulators
2.5	Hardware Fittings
2.6	Conductor & Earth wire accessories
2.7	Spares
2.8	Erection, Stringing & Civil works including foundation
2.9	Total Transmission Lines material
3	Taxes and Duties
3.1	Custom Duty
3.2	Other Taxes & Duties
3.3	Total Taxes & Duties
3.4	Total—Transmission lines
B.	Substations
4	Preliminary works & land
4.1	Design & Engineering
4.2	Land
4.3	Site preparation
4.4	Total Preliminary works & land
5	Civil Works
5.1	Control Room & Office Building including HVAC
5.2	Township & Colony
5.3	Roads and Drainage
5.4	Foundation for structures
5.5	Misc. civil works
5.6	Total Civil Works
6	Substation Equipments
6.1	Switchgear (CT,PT, Circuit Breaker, Isolator etc)
6.2	Transformers
6.3	Compensating Equipment (Reactor, SVCs etc)
6.4	Control, Relay & Protection Panel
6.5	PLCC
6.6	HVDC package
6.7	Bus Bars/ conductors/ Insulators
6.8	Outdoor lighting
6.9	Emergency D.G Set
6.1	Grounding System
6.11	Structure for switchyard
6.12	Total Substation Equipments
7	Spares
8	Taxes and Duties
8.1	Custom Duty
8.2	Other Taxes & Duties
8.3	Total Taxes & Duties
	Total (Sub-station)

9	Construction and pre-commissioning expenses
9.1	Site supervision & site admn. etc.
9.2	Tools and Plants
9.3	Construction Insurance
9.4	Total Construction and pre-commissioning expenses
10	Overheads
10.1	Establishment
10.2	Audit & Accounts
10.3	Contingency
10.4	Total Overheads
11	Project cost without Total Cost (Plant & Equipment)
12	Total Cost (Plant & Equipment)
12.1	Interest During Construction (IDC)
12.2	Financing Charges (FC)
12.3	Foreign Exchange Rate Variation (FERV)
12.4	Hedging Cost
12.5	Total of IDC, FC, FERV & Hedging Cost
13	Capital cost including IDC, FC, FERV & Hedging Cost

1. In case of time & Cost over run, a detailed note giving reasons of such time and cost over run should be submitted clearly bringing out the agency responsible and whether such time & cost over run was beyond the control of the generating company.

ApplicantAnnexure 9Form P(D4) : Break up of Capital Cost for Plant & Equipment (Hydro)Name of Generating Station:______________ (Rs. in Lakh)

Sl. No.	Head of Works	Original cost as approved by Commission	Cost on COD	Variation	Reasons for Variation	Admitted cost
#	(2)	(3)	(4)	(5)	(6)	(7)
1	Generator, turbine & Accessories
1.1	Generator package
1.2	Turbine package
1.3	Unit control Board
1.4	C&I package
1.5	Bus Duct of GT connection
1.6	Total (Generator, turbine & Accessories)
2	Auxiliary Electrical Equipment
2.1	Step up transformer
2.2	Unit Auxiliary Transformer
2.3	Local supply transformer
2.4	Station transformer
2.5	SCADA
2.6	Switchgear, Batteries, DC dist Board
2.7	Telecommunication equipment
2.8	Illumination of Dam, PH and Switchyard
2.9	Cables & cable facilities, grounding
2.1	Diesel generating sets
2.11	Total (Auxiliary Elect. Equipment)
3	Auxiliary equipment & services for power station
3.1	EOT crane
3.2	Other cranes
3.3	Electric lifts & elevators
3.4	Cooling water system
3.5	Drainage & dewatering system
3.6	Fire fighting equipment
3.7	Air conditioning, ventilation and heating
3.8	Water supply system
3.9	Oil handling equipment
3.1	Workshop machines & equipment
3.11	Total (Auxiliary equipment & services for PS)
4	Switchyard package
5	Initial spares for all above equipments
6	Total Cost (Plant & Equipment) excluding IDC, FC, FERV & Hedging Cost
7	IDC, FC, FERV & Hedging Cost
7.1	Interest During Construction (IDC)
7.2	Financing Charges (FC)
7.3	Foreign Exchange Rate Variation (FERV)
7.4	Hedging Cost
7.5	Total of IDC, FC, FERV & Hedging Cost
8	Total Cost (Plant & Equipment) including IDC, FC, FERV &Hedging Cost

Annexure 9Form P(E) : Break-up of Construction/Supply/Service packages (Hydro/Transmission)Name of the Generating Station/Transmission System :(Rs. in Lakh)

Sl. No.	Name/ No. of Construction/ Supply / Service Package	Scope of works (in line with head of cost breakups as applicable)	Whether awarded through ICB/DCB/ Departmentally/Deposit Work	No. of bids received	Date of Award	Date of Start of work	Date of Completionof Work	Value of Award 1	Firm or With Escalation in prices	Actual expenditure till the completion or up to COD whichever is earlier	Taxes & Duties and IEDC	IDC, FC, FERV & Hedging cost	Total (11 + 12+ 13)
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)	(9)	(10)	(11)	(12)	(13)	(14)

1. If there is any package, which need to be shown in Indian Rupee and foreign currency(ies), the same should be shown separately along with the currency and the exchange rate.

ApplicantAnnexure 9Form P(F) : Financial Package up to COD (Thermal/Hydro/Transmission)Name of the Generating Station/Transmission SystemProject Cost as on CODDate of Commercial Operation(Rs. in lakhs)

Particulars	Financial Package as Approved	Financial Package as on COD	As Admitted on COD
Currency and Amount	Currency and Amount	Currency and Amount
(1)	(2)	(3)	(4)	(5)	(6)	(7)
Loan-I
Loan-II
Loan-III
and so on

Equity
Foreign
Domestic
Total Equity
Debt : Equity Ratio

ApplicantAnnexure 9Form P(G): Statement of Additional Capitalization after COD (Thermal/Hydro/Transmission)Name of the Generating Station/Transmission System : _______________Date of Commercial Operation:_______________ (Rs. in Lakh)

Sl. No.	Head of Work /Equipment	Actual / projected additional expenditure claimed	Regulations under which claimed	Justification
		Ensuing Year 2011-12	Ensuing Year 2012-13	Ensuing Year 2013-14	Spill beyond 2013-14
1
2
3
4
5

Note:- 1 Fill the form in chronological order year wise along with detailed justification clearly bring out the necessity and the benefits accruing to the beneficiaries.

2. In case initial spares are purchased along with any equipment, then the cost of such spares should be indicated separately.

ApplicantAnnexure 9Form P(H): Financing of Additional Capitalization (Thermal/Hydro/Transmission)Name of the Generating Station/Transmission System: _______________Date of Commercial Operation : _______________Amount in Rs. Lakhs

Financial Year (Starting from COD)	Actual up to 2009-2010	Base Year	Ensuing Year	Spill beyond 2013-14
2011-12	2012-13	2013-14
(1)	(2)	(3)	(4)	(5)	(6)	(7)
Amount capitalized in Work / Equipment
Financing Details
Loan-1
Loan-2
Loan-3 and so on
Total Loan
Equity
Internal Resources
Others
Total

1Year. 1 refers to Financial Year of COD and Year 2; Year 3 etc. are the subsequent financial years respectively.

ApplicantAnnexure 9Form P(I) : Calculation of Weighted Average Rate of Interest on Actual Loans1Rs. in Lakh

Financial Year (Starting from COD)	Actual up to 2009- 2010	Base Year	Ensuing Year	Spill beyond 2013-14
2011-12	2012-13	2013-14
(1)	(2)	(3)	(4)	(5)	(6)	(7)
Loan-1
Gross loan - Opening
Cumulative repayments of Loans up to previous year
Net loan - Opening
Add: Drawal(s) during the Year
Less: Repayment (s) of Loans during the year
Net loan - Closing
Average Net Loan
Rate of Interest on Loan on annual basis
Interest on loan
Loan-2
Gross loan - Opening
Cumulative repayments of Loans up to previous year
Net loan - Opening
Add: Drawal(s) during the Year
Less: Repayment (s) of Loans during the year
Net loan - Closing
Average Net Loan
Rate of Interest on Loan on annual basis
Interest on loan
Loan-3 and so on
Gross loan - Opening
Cumulative repayments of Loans up to previous year
Net loan - Opening
Add: Drawal(s) during the Year
Less: Repayment (s) of Loans during the year
Net loan - Closing
Average Net Loan
Rate of Interest on Loan on annual basis
Interest on loan
Total Loan
Gross loan - Opening
Cumulative repayments of Loans up to previous year
Net loan - Opening
Add: Drawal(s) during the Year
Less: Repayment (s) of Loans during the year
Net loan - Closing
Average Net Loan
Interest on loan
Weighted average Rate of Interest on Loans

1In. case of Foreign Loans, the calculations in Indian Rupees is to be furnished. However, the calculations in Original currency are also to be furnished separately in the same form.

ApplicantAnnexure 9Form P(J) : Details of Transmission / Distribution Lines & SubstationsName of ProjectName of the Transmission / Distribution Element :Transmission / Distribution lines

S. No.	Name of line	Type of line AC/HVDC	S/C or D/C	No. of Sub-Conductors	Voltage level kV	Line length Ckt.Km.	Date of Commercial operation	Covered in the present petition
								Yes/No	If No. petition No.
1
2
3
4
-
-
-

Annexure 9Form P(J) : Details of Transmission / Distribution Lines & Substations

S.No.	Name of Sub-station	Type of Substation Conventional/ GIS/HVDC terminal/HVDC Back to Back	Voltage level kV	No. of transformers/Reactors/SVC etc. (with capacity)	No. of Bays	Date of Commercial operation	Covered in the present petition
					765 KV	400 KV	220 KV	132 KV & Below	.Yes / No	If No, petition No
1
2
3
4
-
-
-

ApplicantBy Order of the CommissionK. L. Biswas,Secretary of the Commission.Place KolkataDate : 25.04.2011

Sl. No.	Month - Year	Average of Daily Peak Demand (inclusive of loadshedding)	Average of Daily Peak Demand met	Shortfall	Reasons
MW	MW	MW
1	2	(1) - (2)

Legal Document View

Unlock Advanced Research with PRISMAI

State of West Bengal - Act