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Union of India - Act

Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2014

UNION OF INDIA
India

Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2014

Rule CENTRAL-ELECTRICITY-REGULATORY-COMMISSION-TERMS-AND-CONDITIONS-OF-TARIFF-REGULATIONS-2014 of 2014

Published on 1 April 2014
Commenced on 1 April 2014
[This is the version of this document from 1 April 2014.]
[Note: The original publication document is not available and this content could not be verified.]

Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2014Published vide Notification No.L-1/144/2013/CERC, dated 21, February, 2014Last Updated 19th February, 2019Notification No.L-1/144/2013/CERC. - In exercise of powers conferred under section 178 of the Electricity Act, 2003 (36 of 2003) read with section 61 thereof and all other powers enabling it in this behalf, and after previous publication, the Central Electricity Regulatory Commission hereby makes the following regulations, namely:Chapter - 1 Preliminary

1. Short title and commencement.

(1)These regulations may be called the Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2014.

(2)These regulations shall come into force on 1.4.2014, and unless reviewed earlier or extended by the Commission, shall remain in force for a period of five years from 1.4.2014 to 31.3.2019:Provided that where a project or a part thereof, has been declared under commercial operation before the date of commencement of these regulations and whose tariff has not been finally determined by the Commission till that date, tariff in respect of such project or such part thereof for the period ending 31.3.2014 shall be determined in accordance with the Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2009 as amended from time to time.

2. Scope and extent of application.

(1)These regulations shall apply in all cases where tariff for a generating station or a unit thereof and a transmission system or an element thereof including communication system used for inter-State transmission of electricity is required to be determined by the Commission under section 62 of the Act read with section 79 thereof.

(2)These regulations shall not apply for determination of tariff in case of the following:

(a)Generating stations or inter-State transmission systems whose tariff has been discovered through tariff based competitive bidding in accordance with the guidelines issued by the Central Government and adopted by the Commission under Section 63 of the Act;

(b)Generating stations based on renewable sources of energy whose tariff is determined in accordance with the Central Electricity Regulatory Commission (Terms and Conditions for Tariff determination from Renewable Energy Sources) Regulations, 2012, as amended from time to time or any subsequent enactment thereof.

3. Definitions and Interpretations.

- In these regulations, unless the context otherwise requires-

(1)'Act' means the Electricity Act, 2003 (36 of 2003);

(2)'Additional Capitalisation' means the capital expenditure incurred, or projected to be incurred after the date of commercial operation of the project and admitted by the Commission after prudence check, in accordance with provisions of Regulation 14 of these regulations;

(3)'Auxiliary Energy Consumption' or 'AUX' in relation to a period in case of a generating station means the quantum of energy consumed by auxiliary equipment of the generating station, such as the equipment being used for the purpose of operating plant and machinery including switchyard of the generating station and the transformer losses within the generating station, expressed as a percentage of the sum of gross energy generated at the generator terminals of all the units of the generating station:Provided that auxiliary energy consumption shall not include energy consumed for supply of power to housing colony and other facilities at the generating station and the power consumed for construction works at the generating station;

(4)'Auditor' means an auditor appointed by a generating company or a transmission licensee, as the case may be, in accordance with the provisions of sections 224, 233B and 619 of the Companies Act, 1956 (1 of 1956)], as amended from time to time or Chapter X of the Companies Act, 2013 (18 of 2013) or any other law for the time being in force;

(5)'Bank Rate' means the base rate of interest as specified by the State Bank of India from time to time or any replacement thereof for the time being in effect plus 350 basis points;

(6)'Beneficiary' in relation to a generating station covered under clauses (a) and (b) of sub-section 1 of section 79 of the Act, means a distribution licensee who is purchasing electricity generated at such generating station through a Power Purchase Agreement either directly or through a trading licensee on payment of fixed charges and by scheduling in accordance with the Grid Code:Provided that where the distribution licensee is procuring power through a trading licensee, the arrangement should be secured through back to back power purchase agreement and power sale agreement:Provided further that beneficiary shall also include any person who has allocation in inter State Generating Stations;

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

(8)'Capital Cost' means the capital cost as determined in accordance with Regulation 9 of these regulations;

(9)'Change in Law' means occurrence of any of the following events:

(a)enactment, bringing into effect or promulgation of any new Indian law; or

(b)adoption, amendment, modification, repeal or re-enactment of any existing Indian law; or

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

(d)change by any competent statutory authority in any condition or covenant of any consent or clearances or approval or licence available or obtained for the project; or

(e)coming into force or change in any bilateral or multilateral agreement/treaty between the Government of India and any other Sovereign Government having implication for the generating station or the transmission system regulated under these Regulations.

(10)'Commission' means the Central Electricity Regulatory Commission referred to in sub-section (1) of section 76 of the Act;

(11)'Communication System' includes communication system of Power Grid Corporation of India Ltd. covered under Unified Load Dispatch and Communication (ULD&C) scheme, SCADA, Wide Area Measurement (WAMS), Fibre Optic Communication system, Remote Terminal Unit, Private Automatic Branch Exchange, Radio Communication System and auxiliary power supply system etc. used for managing inter-state transmission of electricity;

(12)'Competitive Bidding' means a transparent process for procurement of equipment, services and works in which bids are invited by the project developer by open advertisement covering the scope and specifications of the equipment, services and works required for the project, and the terms and conditions of the proposed contract as well as the criteria by which bids shall be evaluated, and shall include domestic competitive bidding and international competitive bidding;

(13)'Cut-off Date' means 31st March of the year closing after two years of the year of commercial operation of whole or part of the project, and in case the whole or part of the project is declared under commercial operation in the last quarter of a year, the cutoff date shall be 31st March of the year closing after three years of the year of commercial operation:Provided that the cut-off date may be extended by the Commission if it is proved on the basis of documentary evidence that the capitalisation could not be made within the cut-off date for reasons beyond the control of the project developer;

(14)'Date of Commercial Operation' or 'COD' shall have the same meaning as defined in Regulation 4 of these regulations;

(15)'Declared Capacity' or 'DC' in relation to a generating station means, the capability to deliver ex-bus electricity in MW declared by such generating station in relation to any time-block of the day as defined in the Grid Code or whole of the day, duly taking into account the availability of fuel or water, and subject to further qualification in the relevant regulation;

(16)'De-capitalisation' for the purpose of the tariff under these regulations, means reduction in Gross Fixed Assets of the project corresponding to the removal/deletion of assets as admitted by the Commission;

(17)'De-Commissioning' means removal from service of a generating station or a unit thereof or transmission system including communication system or element thereof, after it is certified by the Central Electricity Authority or any other authorized agency, either on its own or on an application made by the project developer or the beneficiaries or both, that the project cannot be operated due to non performance of the assets on account of technological obsolescence or uneconomic operation or a combination of these factors;

(18)'Design Energy' means the quantum of energy which can be generated in a 90% dependable year with 95% installed capacity of the hydro generating station;

(19)'Day' means a calendar day consisting of 24 hours period starting at 0000 hour;

(20)'Designated ISTS Customers' or 'DICs' shall have the same meaning as defined in Central Electricity Regulatory Commission (Sharing of Inter State Transmission Charges and Losses) Regulations, 2010 as amended from time to time or subsequent reenactment thereof;

(21)'Element' in respect of a transmission system shall mean an asset which has been distinctively defined under the scope of the project in the Investment Approval;

(22)'Existing Project' means a project which has been declared under commercial operation on a date prior to 1.4.2014;

(23)'Expenditure Incurred' means the fund, whether 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;

(24)'Extended Life' means the life of a generating station or unit thereof or transmission system or element thereof beyond the period of useful life, as may be determined by the Commission on case to case basis;

(25)'Force Majeure' for the purpose of these regulations means the event or circumstance or combination of events or circumstances including those stated below which partly or fully prevents the generating company or transmission licensee to complete the project within the time specified in the Investment Approval, and only if such events or circumstances are not within the control the generating company or transmission licensee and could not have been avoided, had the generating company or transmission licensee taken reasonable care or complied with prudent utility practices:

(a)Act of God including lightning, drought, fire and explosion, earthquake, volcanic eruption, landslide, flood, cyclone, typhoon, tornado, geological surprises, or exceptionally adverse weather conditions which are in excess of the statistical measures for the last hundred years; or

(b)Any act of war, invasion, armed conflict or act of foreign enemy, blockade, embargo, revolution, riot, insurrection, terrorist or military action; or

(c)Industry wide strikes and labour disturbances having a nationwide impact in India;

(26)'Generating Unit' in relation to a thermal generating station (other than combined cycle thermal generating station) means steam generator, turbine-generator and auxiliaries, or in relation to a combined cycle thermal generating station, means turbine-generator and auxiliaries; and in relation to a hydro generating station means turbine-generator and its auxiliaries;

(27)'Grid Code' means the Central Electricity Regulatory Commission (Indian Electricity Grid Code) Regulations, 2010 as amended from time to time or subsequent re-enactment thereof;

(28)'Gross Calorific Value' or 'GCV' in relation to a thermal generating station means the heat produced in kCal by complete combustion of one kilogram of solid fuel or one litre of liquid fuel or one standard cubic meter of gaseous fuel, as the case may be;

(29)'Gross Station Heat Rate' or 'GHR' means the heat energy input in kCal required to generate one kWh of electrical energy at generator terminals of a thermal generating station;

(30)'Generating Station' means any station for generating electricity, including any building and plant with step-up transformer, switch-gear, switch yard, cables or other appurtenant equipment, if any, used for that purpose and the site thereof; a site intended to be used for a generating station, and any building used for housing the operating staff of a generating station, and where electricity is generated by water-power, includes penstocks, head and tail works, main and regulating reservoirs, dams and other hydraulic works, but does not in any case include any sub-station;

(31)'Indian Governmental Instrumentality' means the Government of India, Governments of State (where the project is located) and any ministry or department or board or agency or other regulatory or quasi judicial authority controlled by Government of India or Government of State, where the project is located.

(32)'Infirm Power' means electricity injected into the grid prior to the commercial operation of a unit or block of the generating station in accordance with Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-State Transmission and related matters) Regulations, 2009 as amended from time to time;

(33)'Installed Capacity' or 'IC' means the summation of the name plate capacities of all the units of the generating station or the capacity of the generating station reckoned at the generator terminals, as may be approved by the Commission from time to time;

(34)'Implementation Agreement' means the agreement, contract or memorandum of understanding, or any such covenant, entered into (i) between transmission licensee and generating station or (ii) between transmission licensee and developer of the associated transmission system for the execution of project in coordinated manner;

(35)'Inter-State Generating Station' or 'ISGS' has the meaning as assigned in the Grid Code;

(36)'Investment Approval' means approval by the Board of the generating company or the transmission licensee or Cabinet Committee on Economic Affairs (CCEA) or any other competent authority conveying administrative sanction for the project including funding of the project and the timeline for the implementation of the project.Provided that the date of Investment Approval shall reckon from the date of the resolution/minutes of the Board/approval by competent authority.

(37)'Kilowatt-Hour' or 'kWh' means a unit of electrical energy, measured in one kilowatt or one thousand watts of power produced or consumed over a period of one hour;

(38)'Long-Term Transmission Customer' means a person having a long term transmission service agreement with the transmission licensee including deemed transmission licensee for use of inter-State transmission system by paying transmission charges and the term may be used interchangeably with the term Designated ISTS Customers (DICs);

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

(40)'New Project' means the project achieving COD or anticipated to be achieving COD on or after 1.4.2014;

(41)'Normative Annual Plant Availability Factor' or 'NAPAF' in relation to a generating station means the availability factor as specified in Regulation 36 and 37 of these regulations for thermal generating station and hydro generating station respectively;

(42)'Operation and Maintenance Expenses' or 'O&M expenses' means the expenditure incurred for operation and maintenance of the project, or part thereof, and includes the expenditure on manpower, repairs, maintenance spares, consumables, insurance and overheads but excludes fuel expenses and water charges;

(43)'Original Project Cost' means the capital expenditure incurred by the generating company or the transmission licensee, as the case may be, within the original scope of the project up to the cut-off date as admitted by the Commission;

(44)'Plant Availability Factor' or '(PAF)' in relation to a generating station for any period means the average of the daily declared capacities (DCs) for all the days during the period expressed as a percentage of the installed capacity in MW less the normative auxiliary energy consumption;

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

N|-

PLF = 10000 x| ∑SGi/ {N x IC X (100 - AUXn)}%|-

i=1

Where,IC = Installed Capacity of the generating station or unit in MW,SGi = Scheduled Generation in MW for the ith time block of the period,N = Number of time blocks during the period, andAUXn = Normative Auxiliary Energy Consumption as a percentage of gross energy generation;

(46)'Project' means a generating station or a transmission system including communication system, as the case may be, and in case of a hydro generating station includes all components of generating facility such as dam, intake water conductor system, power generating station and generating units of the scheme, as apportioned to power generation and in case of thermal generating stations does not include mining if it is a pit head project and dedicated captive coal mine;

(47)'Procedure Regulations' means the Central Electricity Regulatory Commission (Procedure for making of application for determination of tariff, publication of the application and other related matters) Regulations, 2004, as amended from time to time or any statutory re-enactment thereof;

(48)'Prudence Check' means scrutiny of reasonableness of capital expenditure incurred or proposed to be incurred, financing plan, use of efficient technology, cost and time over-run and such other factors as may be considered appropriate by the Commission for determination of tariff. While carrying out the Prudence Check, the Commission shall look into whether the generating company or transmission licensee has been careful in its judgments and decisions for executing the project or has been careful and vigilant in executing the project;

(49)'Pumped storage hydro generating station' means a hydro station which generates power through energy stored in the form of water energy, pumped from a lower elevation reservoir to a higher elevation reservoir;

(50)'Run-of-River generating station' means a hydro generating station which does not have upstream pondage;

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

(52)'Rated Voltage' means the manufacturer's design voltage at which the transmission system is designed to operate and includes such lower voltage at which any transmission line is charged or for the time being charged, in consultation with long-term transmission customers /DICs;

(53)'Regular Service' means putting into use a transmission system or element thereof after successful trial operation and a certificate to that effect has been issued by the concerned Regional Load Dispatch Centre;

(54)'Scheduled Commercial Operation Date or SCOD' shall mean the date(s) of commercial operation of a generating station or generating unit or block thereof or transmission system or element thereof as indicated in the Investment Approval or as agreed in power purchase agreement or transmission service agreement as the case may be, whichever is earlier;

(55)'Scheduled Energy' means the quantum of energy scheduled by the concerned Load Despatch Centre to be injected into the grid by a generating station for a given time period;

(56)'Scheduled Generation' or 'SG' at any time or for any period or time block means schedule of ex-bus generation in MW or MWh, given by the concerned Load Despatch Centre;Note: - For the open cycle 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. In such an event of reduction of scheduled generation of gas turbine generating station, the corresponding drawal schedule of beneficiaries shall be corrected in proportion to their scheduled drawal with adjustment of transmission losses on post facto basis.

(57)'Sharing Regulations' means Central Electricity Regulatory Commission (Sharing of Transmission Charges and Losses in inter-State Transmission System) Regulations, 2010 as amended from time to time;

(58)'Small gas turbine generating station' means and includes open cycle gas turbine or combined cycle generating station with gas turbines in the capacity range of 50 MW or below;

(59)'Start Date or Zero Date' means the date indicated in the Investment Approval for commencement of implementation of the project and where no date has been indicated, the date of investment approval shall be deemed to be Start Date or Zero Date;

(60)'Storage type generating station' means a hydro generating station associated with large storage capacity to enable variation of generation of electricity according to demand;

(61)'Thermal Generating Station' means a generating station or a unit thereof that generates electricity using fossil fuels such as coal, lignite, gas, liquid fuel or combination of these as its primary source of energy;

(62)'Trial Run' or 'Trial Operation' in relation to transmission system or a generating station shall have the same meaning as specified in Regulation 5 of these regulations;

(63)'Transmission Service Agreement' means the agreement entered into between the transmission licensee and the designated inter-State transmission customers in accordance with the Sharing Regulations and any other agreement between the transmission licensee and the long term transmission customer where the payment of transmission charges are not made through the POC mechanism under Sharing Regulations;

(64)'Transmission Line' shall have the same meaning as defined in sub-section (72) of section 2 of the Act;

(65)'Transmission System' means a line or a group of lines with or without associated sub-station, equipment associated with transmission lines and sub-stations;

(66)'Sub-Station' shall have the same meaning as defined in sub-section (69) of section 2 of the Act;

(67)'Useful life' in relation to a unit of a generating station and transmission system from the COD shall mean the following, namely:

(a)	Coal/Lignite based thermal generating station	25 years
(b)	Gas/Liquid fuel based thermal generating station	25 years
(c)	AC and DC sub-station	25 years
(d)	Gas Insulated Substation (GIS)	25 years
(d)	Hydro generating station including pumped Storage hydrogenerating stations	35 years
(e)	Transmission line (including HVAC & HVDC)	35 years
(f)	Communication system	15 years

Provided that the useful life for AC and DC substations and GIS for which Notice Inviting Tender is floated on or after 01.04.2014 shall be considered as 35 years.Provided further that the extension of life of the projects beyond the completion of their useful life shall be decided by the Commission;

(68)'Year' means a financial year.The words and expressions used in these regulations and not defined herein but defined in the Act or any other regulation of the Commission shall have the meaning assigned to them under the Act or any other regulation of the Commission.Chapter - 2 General

4. Date of Commercial Operation.

- The date of commercial operation of a generating station or unit or block thereof or a transmission system or element thereof shall be determined as under:

(1)Date of commercial operation in case of a generating unit or block of the thermal generating station shall mean the date declared by the generating company after demonstrating the maximum continuous rating (MCR) or the installed capacity (IC) through a successful trial run after notice to the beneficiaries, if any, and in case of the generating station as a whole, the date of commercial operation of the last generating unit or block of the generating station:Provided that

(i)where the beneficiaries have been tied up for purchasing power from the generating station, the trial run shall commence after seven days notice by the generating company to the beneficiaries and scheduling shall commence from 0000 hr after completion of the trial run:

(ii)the generating company shall certify to the effect that the generating station meets the key provisions of the technical standards of Central Electricity Authority (Technical Standards for Construction of Electrical plants and electric lines) Regulations, 2010 and Grid Code:

(iii)the certificate shall be signed by CMD/CEO/MD of the company subsequent to its approval by the Board of Directors in the format enclosed at Appendix VI and a copy of the certificate shall be submitted to the Member Secretary, (concerned Regional Power Committee) and concerned RLDC before declaration of COD:

(2)Date of commercial operation in relation to a generating unit of hydro generating station including pumped storage hydro generating station shall mean the date declared by the generating company from 0000 hour after the scheduling process in accordance with the Grid code is fully implemented, and in relation to the generating station as a whole, the date declared by the generating company after demonstrating peaking capability corresponding to installed capacity of the generating station through a successful trial run:Provided that:

(i)where beneficiaries have been tied up for purchasing power from generating station, scheduling process for a generating unit of the generating station or demonstration of peaking capability corresponding to installed capacity of the generating station through a successful trial run shall commence after seven days notice by the generating company to the beneficiaries and scheduling shall commence from 0000 hr after completion of trial run:

(ii)the generating company shall certify to the effect that the generating station meets key provisions of the technical standards of Central Electricity Authority (Technical Standards for Construction of Electrical plants and electric lines) Regulations, 2010 and Grid code:

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

(v)if a run-of-river hydro generating station or a generating unit thereof is declared under commercial operation during lean inflows period when the water inflow is insufficient for such demonstration of peaking capability, it shall be mandatory for such hydro generating station or generating unit to demonstrate peaking capability equivalent to installed capacity as and when sufficient water inflow is available.

(3)Date of commercial operation in relation to a transmission system shall mean the date declared by the transmission licensee from 0000 hour of which an element of the transmission system is in regular service after successful trial operation for transmitting electricity and communication signal from sending end to receiving end:Provided that:

(i)where the transmission line or substation is dedicated for evacuation of power from a particular generating station, the generating company and transmission licensee shall endeavour to commission the generating station and the transmission system simultaneously as far as practicable and shall ensure the same through appropriate Implementation Agreement in accordance with Regulation 12(2) of these Regulations :

(ii)in case a transmission system or an element thereof is prevented from regular service for reasons not attributable to the transmission licensee or its supplier or its contractors but is on account of the delay in commissioning of the concerned generating station or in commissioning of the upstream or downstream transmission system, the transmission licensee shall approach the Commission through an appropriate application for approval of the date of commercial operation of such transmission system or an element thereof.

(4)Date of commercial operation in relation to a communication system or element thereof shall mean the date declared by the transmission licensee from 0000 hour of which a communication system or element is put into service after completion of site acceptance test including transfer of voice and data to respective control centre as certified by the respective Regional Load Dispatch Centre.

5. Trial Run and Trial Operation.

(1)Trial Run in relation to generating station or unit thereof shall mean the successful running of the generating station or unit thereof at maximum continuous rating or installed capacity for continuous period of 72 hours in case of unit of a thermal generating station or unit thereof and 12 hours in case of a unit of a hydro generating station or unit thereof:Provided that where the beneficiaries have been tied up for purchasing power from the generating station, the trial run shall commence after seven days notice by the generating company to the beneficiaries.

(2)Trial operation in relation to a transmission system or an element thereof shall mean successful charging of the transmission system or an element thereof for 24 hours at continuous flow of power, and communication signal from sending end to receiving end and with requisite metering system, telemetry and protection system in service enclosing certificate to that effect from concerned Regional Load Dispatch Centre.Chapter - 3 Procedure for Tariff Determination

6. Tariff determination.

(1)Tariff in respect of a generating station may be determined for the whole of the generating station or stage or generating unit or block thereof, and tariff in respect of a transmission system may be determined for the whole of the transmission system or transmission line or sub-station or communication system forming part of transmission system:Provided that:

(i)where all the generating units of a stage of a generating station or all elements of a transmission system have been declared under commercial operation prior to 1.4.2014, the generating company or the transmission licensee, as the case may be, shall file consolidated petition in respect of the entire generating station or transmissions system for the purpose of determination of tariff for the period 2014-15 to 2018-19:

(ii)in case of commercial operation of the generating station or transmission system including communication system on or after 1.4.2014, the generating company or transmission licensee shall file a consolidated petition combining all the units of the generating station or file appropriate petition for transmission elements of the transmission system which are likely to be commissioned during next six months from the date of application:

(iii)the tariff of the existing communication system forming part of transmission system shall be as per the methodology followed by the Commission prior to 1.4.2014.

(2)For the purpose of determination of tariff, the capital cost of a project may be broken up into stages, blocks, units, transmission lines and sub-stations, forming part of the project, if required:Provided that where break-up of the capital cost of the project for different stages or units or blocks and for transmission lines or sub-stations is not available and in case of on-going projects, the common facilities shall be apportioned on the basis of the installed capacity of the units, line length and number of bays:Provided further that in relation to multi-purpose hydro schemes, with irrigation, flood control and power components, the capital cost chargeable to the power component of the scheme only shall be considered for determination of tariff.

(3)Where an existing transmission project has been granted licence under section 14 of the Act read with Regulation 6(c) of the Central Electricity Regulatory Commission (Terms and Conditions of grant of Transmission Licence for inter-State Transmission of electricity and related matters) Regulations, 2009, the tariff of such project shall be applicable from the date of grant of transmission licence or from the date as indicated in the transmission licence, as the case may be. In such cases, the applicant shall file petition as per Annexure-I, clearly demarcating the assets which form the part of regulated business of generation and transmission, the value of such assets, source of funding etc. duly certified by an auditor.

(4)In case of multi-purpose hydro generation scheme with irrigation, flood control and power components, the capital cost chargeable to the power component of the scheme only shall be considered for determination of tariff.

(5)Where only a part of the generation capacity of a generating station is tied up for supplying power to the beneficiaries through long term power purchase agreement and the balance part of the generation capacity have not been tied up for supplying power to the beneficiaries, the tariff of the generating station shall be determined with reference to the capital cost of the entire project, but the tariff so determined shall be applicable corresponding to the capacity contracted for supply to the beneficiaries.

7. Application for determination of tariff.

(1)The generating company may make an application for determination of tariff for new generating station or unit thereof in accordance with the Procedure Regulations, in respect of the generating station or generating units thereof within 180 days of the anticipated date of commercial operation.

(2)The transmission licensee may make an application for determination of tariff for new transmission system including communication system or element thereof as the case may be in accordance with the Procedure Regulations, in respect of the transmission system or elements thereof anticipated to be commissioned within 180 days from the date of filing of the petition.

(3)In case of an existing generating station or transmission system including communication system or element thereof, the application shall be made not later than 180 days from the date of notification of these regulations based on admitted capital cost including any additional capital expenditure already admitted up to 31.3.2014 (either based on actual or projected additional capital expenditure) and estimated additional capital expenditure for the respective years of the tariff period 2014-15 to 2018-19.

(4)The generating company or the transmission licensee, as the case may be, shall make an application as per Annexure-I of these regulations, for determination of tariff based on capital expenditure incurred duly certified by the auditors or projected to be incurred up to the date of commercial operation and additional capital expenditure incurred duly certified by the auditors or projected to be incurred during the tariff period of the generating station or the transmission system as the case may be:Provided that the petition shall contain details of underlying assumptions for the projected capital cost and additional capital expenditure, wherever applicable.

(5)If the petition is inadequate in any respect as required under Annexure-I of these regulations, the application shall be returned to the generating company or transmission licensee as the case may be, for resubmission of the petition within one month after rectifying the deficiencies as may be pointed out by the staff of the Commission.

(6)If the information furnished in the petition is in accordance with the regulations and is adequate for carrying out prudence check of the claims made, the Commission shall consider the suggestions and objections, if any, received from the respondents within one month from the date of filing of the petition and any other person including the consumers or consumer associations. The Commission shall issue the tariff order after hearing the petitioner, the respondents and any other person specifically permitted by the Commission.

(7)In case of the new projects, the generating company or the transmission licensee, as the case may be, may be allowed tariff by the Commission based on the projected capital expenditure from the anticipated COD in accordance with Regulation 6 of these regulations:Provided that :

(i)the Commission may grant tariff upto 90% of the annual fixed charges claimed in respect of the transmission system or element thereof based on the management certificate regarding the capital cost for the purpose of inclusion in the POC charges in accordance with the CERC (Sharing of Inter State Transmission charges and losses), Regulation, 2010 as amended from time to time:

(ii)if the date of commercial operation is delayed beyond 180 days from the date of issue of tariff order in terms of clause (6) of this regulation, the tariff granted shall be deemed to have been withdrawn and the generating company or the transmission licensee shall be required to file a fresh application for determination of tariff after the date of commercial operation of the project:

(iii)where the capital cost considered in tariff by the Commission on the basis of projected capital cost as on COD or the projected additional capital expenditure exceeds the actual capital cost incurred on year to year basis by more than 5%, the generating company or the transmission licensee shall refund to the beneficiaries or the long term transmission customers /DICs as the case may be, the excess tariff recovered corresponding to excess capital cost, as approved by the Commission alongwith interest at 1.20 times of the bank rate as prevalent on 1st April of respective year:

(iv)where the capital cost considered in tariff by the Commission on the basis of projected capital cost as on COD or the projected additional capital expenditure falls short of the actual capital cost incurred on year to year basis by more than 5%, the generating company or the transmission licensee shall be entitled to recover from the beneficiaries or the long term transmission customers /DICs as the case may be, the shortfall in tariff corresponding to reduction in capital cost, as approved by the Commission alongwith interest at 0.80 times of bank rate as prevalent on 1st April of respective year.

(8)In case of the existing projects, the generating company or the transmission licensee, as the case may be, may be allowed tariff by the Commission based on the admitted capital cost as on 1.4.2014 and projected additional capital expenditure for the respective years of the tariff period 2014-15 to 2018-19 in accordance with the Regulation 6:Provided that:

(i)the generating company or the transmission licensee, as the case may be, shall continue to bill the beneficiaries or the transmission customers / DICs at the tariff approved by the Commission and applicable as on 31.3.2014 for the period starting from 1.4.2014 till approval of tariff by the Commission in accordance with these regulations:

(ii)where the capital cost considered in tariff by the Commission on the basis of projected capital cost as on COD or the projected additional capital expenditure submitted by the generating company or the transmission licensee, as the case may be, exceeds the actual capital cost incurred on year to year basis by more than 5%, the generating company or the transmission licensee shall refund to the beneficiaries or the long term transmission customers /DICs as the case may be, the excess tariff recovered corresponding to excess capital cost, ,as approved by the Commission alongwith interest at 1.20 times of the bank rate as prevalent on April 1 of respective year:

(iii)where the capital cost considered in tariff by the Commission on the basis of projected capital cost as on COD or the projected additional capital expenditure submitted by the generating company or the transmission licensee, as the case may be, falls short of the actual capital cost incurred on year to year basis by more than 5%, the generating company or the transmission licensee shall be entitled to recover from the beneficiaries or the long term transmission customers /DICs as the case may be, the shortfall in tariff corresponding to reduction in capital cost, as approved by the Commission alongwith interest at 0.80 times of bank rate as prevalent on April 1 of respective year.

8. Truing up.

(1)The Commission shall carry out truing up exercise along with the tariff petition filed for the next tariff period, with respect to the capital expenditure including additional capital expenditure incurred up to 31.3.2019, as admitted by the Commission after prudence check at the time of truing up:Provided that the generating company or the transmission licensee, as the case may be, shall make an application for interim truing up of capital expenditure including additional capital expenditure in FY 2016-17.

(2)The generating station shall carry out truing up of tariff of generating station based on the performance of following Controllable parameters:

(a)Controllable Parameters :

(i)Station Heat Rate;

(ii)Secondary Fuel Oil Consumption;

(iii)Auxiliary Energy Consumption; and

(iv)Re-financing of Loan.

(3)The Commission shall carry out truing up of tariff of generating station based on the performance of following Uncontrollable parameters:

(i)Force Majeure;

(ii)Change in Law; and

(iii)Primary Fuel Cost.

(4)The Transmission Licensee shall carry out truing up of tariff of transmission system based on the controllable parameter of Re-Financing of loans:

(5)The Commission shall carry out truing up of tariff of transmission licensee based on the performance of following Uncontrollable parameters:

(i)Force Majeure; and

(ii)Change in Law.

(6)The financial gains by a generating company or the transmission licensee, as the case may be on account of controllable parameters shall be shared between generating company/transmission licensee and the beneficiaries on monthly basis with annual reconciliation. The financial gains computed as per following formulae in case of generating station on account of operational parameters as shown in Clause 2(a) (i) to (iii) of this Regulation shall be shared in the ratio of 60:40 between generating station and beneficiaries:Net Gain = (ECRN- ECRA) x Scheduled GenerationWhere,ECRN - Normative Energy Charge Rate computed on the basis of norms specified for Station Heat Rate, Auxiliary Consumption and Secondary Fuel Oil Consumption.ECRA - Actual Energy Charge Rate computed on the basis of actual SHR, Auxiliary Consumption and Secondary Fuel Oil Consumption for the month.Provided that in case of financial gains on account of Clause 2 (a)(iv) and Clause 4 of this Regulation shall be shared in accordance with Clause 7 of Regulation 26 of these regulations.

(7)The financial gains and losses by a generating company or the transmission licensee, as the case may be, on account of uncontrollable parameters shall be passed on to beneficiaries of the generating company or to the long term transmission customers/DICs of transmission system, as the case may be.

(8)The generating company or the transmission licensee as the case may be, shall carry out the truing up of grossed up rate of return on equity in accordance with Clause 3 of Regulation 25 of these regulations.

(9)The generating company or the transmission licensee as the case may be, shall make an application, as per Annexure-I to these regulations, for carrying out truing up exercise in respect of the generating station or a unit or block thereof or the transmission system or the transmission lines or sub-stations by 31.10.2019.

(10)The generating company or the transmission licensee as the case may be, shall submit for the purpose of truing up, details of actual capital expenditure and additional capital expenditure incurred for the period from 1.4.2014 to 31.3.2019, duly audited and certified by the auditor.

(11)Where after the truing up, the tariff recovered exceeds the tariff approved by the Commission under these regulations, the generating company or the transmission licensee, shall refund to the beneficiaries or the long term transmission customers/DICs, as the case may be, the excess amount so recovered as specified in the Clause 13 of this regulation.

(12)Where after the truing up, the tariff recovered is less than the tariff approved by the Commission under these regulations, the generating company or the transmission licensee shall recover from the beneficiaries or the long term transmission customers/DICs, as the case may be, the under-recovered amount as specified in the Clause 13 of this regulation.

(13)The amount under-recovered or over-recovered, along with simple interest at the rate equal to the bank rate as on 1st April of the respective year, shall be recovered or refunded by the generating company or the transmission licensee, as the case may be, in six equal monthly instalments starting within three months from the date of the tariff order issued by the Commission.Chapter - 4 Computation of Capital Cost and Capital Structure

9. Capital Cost.

(1)The Capital cost as determined by the Commission after prudence check in accordance with this regulation shall form the basis of determination of tariff for existing and new projects.

(2)The Capital Cost of a new project shall include the following:

(a)the expenditure incurred or projected to be incurred up to the date of commercial operation of the project;

(b)Interest during construction and financing charges, on the loans (i) being equal to 70% of the funds deployed, in the event of the actual equity in excess of 30% of the funds deployed, by treating the excess equity as normative loan, or (ii) being equal to the actual amount of loan in the event of the actual equity less than 30% of the funds deployed;

(c)Increase in cost in contract packages as approved by the Commission;

(d)Interest during construction and incidental expenditure during construction as computed in accordance with Regulation 11 of these regulations;

(e)capitalised Initial spares subject to the ceiling rates specified in Regulation 13 of these regulations;

(f)expenditure on account of additional capitalization and de-capitalisation determined in accordance with Regulation 14 of these regulations;

(g)adjustment of revenue due to sale of infirm power in excess of fuel cost prior to the COD as specified under Regulation 18 of these regulations; and

(h)adjustment of any revenue earned by the transmission licensee by using the assets before COD.

(3)The Capital cost of an existing project shall include the following:

(a)the capital cost admitted by the Commission prior to 1.4.2014 duly trued up by excluding liability, if any, as on 1.4.2014;

(b)additional capitalization and de-capitalization for the respective year of tariff as determined in accordance with Regulation 14; and

(c)expenditure on account of renovation and modernisation as admitted by this Commission in accordance with Regulation 15.

(4)The capital cost in case of existing/new hydro generating station shall also include:

(a)cost of approved rehabilitation and resettlement (R&R) plan of the project in conformity with National R&R Policy and R&R package as approved; and

(b)cost of the developer's 10% contribution towards Rajiv Gandhi Grameen Vidyutikaran Yojana (RGGVY) project in the affected area.

(5)The capital cost with respect to thermal generating station, incurred or projected to be incurred on account of the Perform, Achieve and Trade (PAT) scheme of Government of India will be considered by the Commission on case to case basis and shall include:

(a)cost of plan proposed by developer in conformity with norms of PAT Scheme; and

(b)sharing of the benefits accrued on account of PAT Scheme.

(6)The following shall be excluded or removed from the capital cost of the existing and new project:

(a)The assets forming part of the project, but not in use;

(b)Decapitalisation of Asset;

(c)In case of hydro generating station any expenditure incurred or committed to be incurred by a project developer for getting the project site allotted by the State government by following a two stage transparent process of bidding; and

(d)the proportionate cost of land which is being used for generating power from generating station based on renewable energy:

Provided that any grant received from the Central or State Government or any statutory body or authority for the execution of the project which does not carry any liability of repayment shall be excluded from the Capital Cost for the purpose of computation of interest on loan, return on equity and depreciation;

10. Prudence Check of Capital Expenditure.

- The following principles shall be adopted for prudence check of capital cost of the existing or new projects:

(1)In case of the thermal generating station and the transmission system, prudence check of capital cost may be carried out taking into consideration the benchmark norms specified/to be specified by the Commission from time to time:Provided that in cases where benchmark norms have not been specified, prudence check may include scrutiny of the capital expenditure, financing plan, interest during construction, incidental expenditure during construction for its reasonableness, use of efficient technology, cost over-run and time over-run, competitive bidding for procurement and such other matters as may be considered appropriate by the Commission for determination of tariff:Provided further that in cases where benchmark norms have been specified, the generating company or transmission licensee shall submit the reasons for exceeding the capital cost from benchmark norms to the satisfaction of the Commission for allowing cost above benchmark norms.

(2)The Commission may issue new guidelines or revise the existing guidelines for vetting of capital cost of hydro-electric projects by an independent agency or an expert and in that event the capital cost as vetted by such agency or expert may be considered by the Commission while determining the tariff for the hydro generating station.

(3)The Commission may issue new guidelines or revise the existing guidelines for scrutiny and approval of commissioning schedule of the hydro-electric projects in accordance with the tariff policy issued by the Central Government under section 3 of the Act from time to time which shall be considered for prudence check.

(4)Where the power purchase agreement entered into between the generating company and the beneficiaries provides for ceiling of actual capital expenditure, the Commission shall take into consideration such ceiling for determination of tariff for prudence check of capital cost.

11. Interest during construction (IDC), Incidental Expenditure during Construction (IEDC).

- (A) Interest during Construction (IDC): - (1) Interest during construction shall be computed corresponding to the loan from the date of infusion of debt fund, and after taking into account the prudent phasing of funds upto SCOD.

(2)In case of additional costs on account of IDC due to delay in achieving the SCOD, the generating company or the transmission licensee as the case may be, shall be required to furnish detailed justifications with supporting documents for such delay including prudent phasing of funds:Provided that if the delay is not attributable to the generating company or the transmission licensee as the case may be, and is due to uncontrollable factors as specified in Regulation 12 of these regulations, IDC may be allowed after due prudence check:Provided further that only IDC on actual loan may be allowed beyond the SCOD to the extent, the delay is found beyond the control of generating company or the transmission licensee, as the case may be, after due prudence and taking into account prudent phasing of funds.

(B)Incidental Expenditure during Construction (IEDC): - (1) Incidental expenditure during construction shall be computed from the zero date and after taking into account pre-operative expenses upto SCOD:

Provided that any revenue earned during construction period up to SCOD on account of interest on deposits or advances, or any other receipts may be taken into account for reduction in incidental expenditure during construction.

(2)In case of additional costs on account of IEDC due to delay in achieving the SCOD, the generating company or the transmission licensee as the case may be, shall be required to furnish detailed justification with supporting documents for such delay including the details of incidental expenditure during the period of delay and liquidated damages recovered or recoverable corresponding to the delay:Provided that if the delay is not attributable to the generating company or the transmission licensee, as the case may be, and is due to uncontrollable factors as specified in regulation 12, IEDC may be allowed after due prudence check:Provided further that where the delay is attributable to an agency or contractor or supplier engaged by the generating company or the transmission licensee, the liquidated damages recovered from such agency or contractor or supplier shall be taken into account for computation of capital cost.

(3)In case the time over-run beyond SCOD is not admissible after due prudence, the increase of capital cost on account of cost variation corresponding to the period of time over run may be excluded from capitalization irrespective of price variation provisions in the contracts with supplier or contractor of the generating company or the transmission licensee.

12. Controllable and Uncontrollable factors.

- The following shall be considered as controllable and uncontrollable factors leading to cost escalation impacting Contract Prices, IDC and IEDC of the project :

(1)The "controllable factors" shall include but shall not be limited to the following:

(a)Variations in capital expenditure on account of time and/or cost overruns on account of land acquisition issues;

(b)Efficiency in the implementation of the project not involving approved change in scope of such project, change in statutory levies or force majeure events; and

(c)Delay in execution of the project on account of contractor, supplier or agency of the generating company or transmission licensee.

(2)The "uncontrollable factors" shall include but shall not be limited to the following:

(i)Force Majeure events.; and

(ii)Change in law.

Provided that no additional impact of time overrun or cost over-run shall be allowed on account of non-commissioning of the generating station or associated transmission system by SCOD, as the same should be recovered through Implementation Agreement between the generating company and the transmission licensee:Provided further that if the generating station is not commissioned on the SCOD of the associated transmission system, the generating company shall bear the IDC or transmission charges if the transmission system is declared under commercial operation by the Commission in accordance with second proviso of Clause 3 of Regulation 4 of these regulations till the generating station is commissioned:Provided also that if the transmission system is not commissioned on SCOD of the generating station, the transmission licensee shall arrange the evacuation from the generating station at its own arrangement and cost till the associated transmission system is commissioned.

13. Initial Spares.

- Initial spares shall be capitalised as a percentage of the Plant and Machinery cost upto cut-off date, subject to following ceiling norms:

(a)	Coal-based/lignite-fired thermal generating stations	-	4.0%
(b)	Gas Turbine/Combined Cycle thermal generating stations	-	4.0%
(c)	Hydro generating stations including pumped storage hydrogenerating station	-	4.0%
(d)	Transmission system
	(i)	Transmission line	-	1.00%
	(ii)	Transmission Sub-station (Green Field)	-	4.00%
	(iii)	Transmission Sub-station (Brown Field)	-	6.00%
	(iv)	Series Compensation devices and HVDC Station	-	4.00%
	(v)	Gas Insulated Sub-station (GIS)	-	5.00%
	(vi)	Communication system	-	3.5%

Provided that:

(i)where the benchmark norms for initial spares have been published as part of the benchmark norms for capital cost by the Commission, such norms shall apply to the exclusion of the norms specified above:

(ii)where the generating station has any transmission equipment forming part of the generation project, the ceiling norms for initial spares for such equipments shall be as per the ceiling norms specified for transmission system under these regulations:

(iii)once the transmission project is commissioned, the cost of initial spares shall be restricted on the basis of plant and machinery cost corresponding to the transmission project at the time of truing up:

(iv)for the purpose of computing the cost of initial spares, plant and machinery cost shall be considered as project cost as on cut-off date excluding IDC, IEDC, Land Cost and cost of civil works. The transmission licensee shall submit the break up of head wise IDC & IEDC in its tariff application.

14. Additional Capitalisation and De-capitalisation.

(1)The capital expenditure in respect of the new project or an existing project incurred or projected to be incurred, on the following counts within the original scope of work, after the date of commercial operation and up to the cut-off date may be admitted by the Commission, subject to prudence check:

(i)Undischarged liabilities recognized to be payable at a future date;

(ii)Works deferred for execution;

(iii)Procurement of initial capital spares within the original scope of work, in accordance with the provisions of Regulation 13;

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

(v)Change in law or compliance of any existing law:

Provided that the details of works asset wise/work wise included in the original scope of work along with estimates of expenditure, liabilities recognized to be payable at a future date and the works deferred for execution shall be submitted along with the application for determination of tariff.

(2)The capital expenditure incurred or projected to be incurred in respect of the new project on the following counts within the original scope of work after the cut-off date may be admitted by the Commission, subject to prudence check:

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

(ii)Change in law or compliance of any existing law:;

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

(iv)Any liability for works executed prior to the cut-off date, after prudence check of the details of such undischarged liability, total estimated cost of package, reasons for such withholding of payment and release of such payments etc.

(3)The capital expenditure, in respect of existing generating station or the transmission system including communication system, incurred or projected to be incurred on the following counts after the cut-off date, may be admitted by the Commission, subject to prudence check:

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

(ii)Change in law or compliance of any existing law;

(iii)Any expenses to be incurred on account of need for higher security and safety of the plant as advised or directed by appropriate Government Agencies of statutory authorities responsible for national security/internal security;

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

(v)Any liability for works executed prior to the cut-off date, after prudence check of the details of such undischarged liability, total estimated cost of package, reasons for such withholding of payment and release of such payments etc.;

(vi)Any liability for works admitted by the Commission after the cut-off date to the extent of discharge of such liabilities by actual payments;

(vii)Any additional capital expenditure which has become necessary for efficient operation of generating station other than coal/lignite based stations or transmission system as the case may be. The claim shall be substantiated with the technical justification duly supported by the documentary evidence like test results carried out by an independent agency in case of deterioration of assets, report of an independent agency in case of damage caused by natural calamities, obsolescence of technology, up-gradation of capacity for the technical reason such as increase in fault level;

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

(ix)In case of transmission system, any additional expenditure on items such as relays, control and instrumentation, computer system, power line carrier communication, DC batteries, replacement due to obsolesce of technology, replacement of switchyard equipment due to increase of fault level, tower strengthening, communication equipment, emergency restoration system, insulators cleaning infrastructure, replacement of porcelain insulator with polymer insulators, replacement of damaged equipment not covered by insurance and any other expenditure which has become necessary for successful and efficient operation of transmission system; and

(x)Any capital expenditure found justified after prudence check necessitated on account of modifications required or done in fuel receiving system arising due to non-materialisation of coal supply corresponding to full coal linkage in respect of thermal generating station as result of circumstances not within the control of the generating station:

Provided that any expenditure on acquiring the minor items or the assets including tools and tackles, furniture, air-conditioners, voltage stabilizers, refrigerators, coolers, computers, fans, washing machines, heat convectors, mattresses, carpets etc. brought after the cut-off date shall not be considered for additional capitalization for determination of tariff w.e.f. 1.4.2014:Provided further that any capital expenditure other than that of the nature specified above in (i) to (iv) in case of coal/lignite based station shall be met out of compensation allowance:Provided also that if any expenditure has been claimed under Renovation and Modernisation (R&M), repairs and maintenance under (O&M) expenses and Compensation Allowance, same expenditure cannot be claimed under this regulation.

(4)In case of de-capitalisation of assets of a generating company or the transmission licensee, as the case may be, the original cost of such asset as on the date of decapitalisation shall be deducted from the value of gross fixed asset and corresponding loan as well as equity shall be deducted from outstanding loan and the equity respectively in the year such de-capitalisation takes place, duly taking into consideration the year in which it was capitalised.

15. Renovation and Modernisation.

(1)The generating company or the transmission licensee, as the case may be, for meeting the expenditure on renovation and modernization (R&M) for the purpose of extension of life beyond the originally recognised useful life for the purpose of tariff of the generating station or a unit thereof or the transmission system or an element thereof, shall make an application before the Commission for approval of the proposal with a Detailed Project Report giving complete scope, justification, cost-benefit analysis, estimated life extension from a reference date, financial package, phasing of expenditure, schedule of completion, reference price level, estimated completion cost including foreign exchange component, if any, and any other information considered to be relevant by the generating company or the transmission licensee.

(2)Where the generating company or the transmission licensee, as the case may be, makes an application for approval of its proposal for renovation and modernisation, the approval shall be granted after due consideration of reasonableness of the cost estimates, financing plan, schedule of completion, interest during construction, use of efficient technology, cost-benefit analysis, and such other factors as may be considered relevant by the Commission.

(3)In case of gas/ liquid fuel based open/ combined cycle thermal generating station, any expenditure which has become necessary for renovation of gas turbines/steam turbine after 25 years of operation from its COD and an expenditure necessary due to obsolesce or non-availability of spares for efficient operation of the stations shall be allowed :Provided that any expenditure included in the R&M on consumables and cost of components and spares which is generally covered in the O&M expenses during the major overhaul of gas turbine shall be suitably deducted after due prudence from the R&M expenditure to be allowed.

(4)Any expenditure incurred or projected to be incurred and admitted by the Commission after prudence check based on the estimates of renovation and modernization expenditure and life extension, and after deducting the accumulated depreciation already recovered from the original project cost, shall form the basis for determination of tariff.

16. Special Allowance for Coal-based/Lignite fired Thermal Generating station.

(1)In case of coal-based/lignite fired thermal generating station, the generating company, instead of availing R&M may opt to avail a 'special allowance' in accordance with the norms specified in this regulation, as compensation for meeting the requirement of expenses including renovation and modernisation beyond the useful life of the generating station or a unit thereof, and in such an event, revision of the capital cost shall not be allowed and the applicable operational norms shall not be relaxed but the special allowance shall be included in the annual fixed cost:Provided that such option shall not be available for a generating station or unit for which renovation and modernization has been undertaken and the expenditure has been admitted by the Commission before commencement of these regulations, or for a generating station or unit which is in a depleted condition or operating under relaxed operational and performance norms.

(2)The Special Allowance shall be @ Rs. 7.5 lakh/MW/year for the year 2014-15 and thereafter escalated @ 6.35% every year during the tariff period 2014-15 to 2018-19, unit-wise from the next financial year from the respective date of the completion of useful life with reference to the date of commercial operation of the respective unit of generating station:Provided that in respect of a unit in commercial operation for more than 25 years as on 1.4.2014, this allowance shall be admissible from the year 2014-15:Provided further that the special allowance for the generating stations, which, in its discretion, has already availed of a 'special allowance' in accordance with the norms specified in clause (4) of regulations 10 of Central Electricity Regulatory Commission (Terms and Conditions of Tariff Determination) Regulations, 2009, shall be allowed Special Allowance by escalating the special allowance allowed for the year 2013-14 @ 6.35% every year during the tariff period 2014-15 to 2018-19.

(3)In the event of granting special allowance by the Commission, the expenditure incurred or utilized from special allowance shall be maintained separately by the generating station and details of same shall be made available to the Commission as and when directed to furnish details of such expenditure.

17. Compensation Allowance.

(1)In case of coal-based or lignite-fired thermal generating station or a unit thereof, a separate compensation allowance shall be admissible to meet expenses on new assets of capital nature which are not admissible under Regulation 14 of these regulations, and in such an event, revision of the capital cost shall not be allowed on account of compensation allowance but the compensation allowance shall be allowed to be recovered separately.

(2)The Compensation Allowance shall be allowed in the following manner from the year following the year of completion of 10, 15, or 20 years of useful life:

Years of Operation	Compensation Allowance (Rs lakh/MW/year)
0-10	Nil
11-15	0.20
16-20	0.50
21-25	1.00

18. Sale of Infirm Power.

- Supply of infirm power shall be accounted as deviation and shall be paid for from the regional deviation settlement fund accounts in accordance with the Central Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters) Regulations, 2014, as amended from time to time or any subsequent re-enactment thereof:Provided that any revenue earned by the generating company from supply of infirm power after accounting for the fuel expenses shall be applied in adjusting the capital cost accordingly.

19. Debt-Equity Ratio.

(1)For a project declared under commercial operation on or after 1.4.2014, the debt-equity ratio would be considered as 70:30 as on COD. If the equity actually deployed is more than 30% of the capital cost, equity in excess of 30% shall be treated as normative loan:Provided that:

(i)where equity actually deployed is less than 30% of the capital cost, actual equity shall be considered for determination of tariff:

(ii)the equity invested in foreign currency shall be designated in Indian rupees on the date of each investment:

(iii)any grant obtained for the execution of the project shall not be considered as a part of capital structure for the purpose of debt : equity ratio.

Explanation. - The premium, if any, raised by the generating company or the transmission licensee, as the case may be, 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, only if such premium amount and internal resources are actually utilised for meeting the capital expenditure of the generating station or the transmission system.

(2)The generating company or the transmission licensee shall submit the resolution of the Board of the company or approval from Cabinet Committee on Economic Affairs (CCEA) regarding infusion of fund from internal resources in support of the utilization made or proposed to be made to meet the capital expenditure of the generating station or the transmission system including communication system, as the case may be.

(3)In case of the generating station and the transmission system including communication system declared under commercial operation prior to 1.4.2014, debt:equity ratio allowed by the Commission for determination of tariff for the period ending 31.3.2014 shall be considered.

(4)In case of the generating station and the transmission system including communication system declared under commercial operation prior to 1.4.2014, but where debt:equity ratio has not been determined by the Commission for determination of tariff for the period ending 31.3.2014, the Commission shall approve the debt:equity ratio based on actual information provided by the generating company or the transmission licensee as the case may be.

(5)Any expenditure incurred or projected to be incurred on or after 1.4.2014 as may be admitted by the Commission as additional capital expenditure for determination of tariff, and renovation and modernisation expenditure for life extension shall be serviced in the manner specified in clause (1) of this regulation.Chapter - 5 Tariff Structure

20. Components of Tariff.

(1)The tariff for supply of electricity from a thermal generating station shall comprise two parts, namely, capacity charge (for recovery of annual fixed cost consisting of the components as specified in Regulation 21 of these regulations) and energy charge (for recovery of primary and secondary fuel cost and limestone cost where applicable).

(2)The tariff for supply of electricity from a hydro generating station shall comprise capacity charge and energy charge to be derived in the manner specified in Regulation 31 of these regulations, for recovery of annual fixed cost (consisting of the components referred to in regulation 21) through the two charges.

(3)The tariff for transmission of electricity on inter-State transmission system shall comprise transmission charge for recovery of annual fixed cost consisting of the components specified in Regulation 21 of these regulations.

21. Capacity Charges.

- The Capacity charges shall be derived on the basis of annual fixed cost. The annual fixed cost (AFC) of a generating station or a transmission system including communication system shall consist of the following components:

(a)Return on equity;

(b)Interest on loan capital;

(c)Depreciation;

(d)Interest on working capital; and

(e)Operation and maintenance expenses:

Provided that special allowance in lieu of R&M where opted in accordance to Regulation 16 and/or separate compensation allowance in accordance to Regulation 17, wherever applicable shall be recovered separately and shall not be considered for computation of working capital.

22. Energy Charges.

- Energy charges shall be derived on the basis of the landed fuel cost (LFC) of a generating station (excluding hydro) and shall consist of the following cost:

(a)Landed Fuel Cost of primary fuel; and

(b)Cost of secondary fuel oil consumption:

Provided that any refund of taxes and duties along with any amount received on account of penalties from fuel supplier shall have to be adjusted in fuel cost.

23. Landed Fuel Cost for Tariff Determination.

- The landed fuel cost of primary fuel and secondary fuel for tariff determination shall be based on actual weighted average cost of primary fuel and secondary fuel of the three preceding months, and in the absence of landed costs for the three preceding months, latest procurement price of primary fuel and secondary fuel for the generating station, before the start of the tariff period for existing stations and immediately preceding three months in case of new generating stations shall be taken into account.Chapter - 6 Computation of Annual Fixed Cost

24. Return on Equity.

(1)Return on equity shall be computed in rupee terms, on the equity base determined in accordance with regulation 19.

(2)Return on equity shall be computed at the base rate of 15.50% for thermal generating stations, transmission system including communication system and run of the river hydro generating station, and at the base rate of 16.50% for the storage type hydro generating stations including pumped storage hydro generating stations and run of river generating station with pondage:Provided that:

(i)in case of projects commissioned on or after 1st April, 2014, an additional return of 0.50 % shall be allowed, if such projects are completed within the timeline specified in Appendix-I:

(ii)the additional return of 0.5% shall not be admissible if the project is not completed within the timeline specified above for reasons whatsoever:

(iii)additional RoE of 0.50% may be allowed if any element of the transmission project is completed within the specified timeline and it is certified by the Regional Power Committee/National Power Committee that commissioning of the particular element will benefit the system operation in the regional/national grid:

(iv)the rate of return of a new project shall be reduced by 1% for such period as may be decided by the Commission, if the generating station or transmission system is found to be declared under commercial operation without commissioning of any of the Restricted Governor Mode Operation (RGMO)/ Free Governor Mode Operation (FGMO), data telemetry, communication system up to load dispatch centre or protection system:

(v)as and when any of the above requirements are found lacking in a generating station based on the report submitted by the respective RLDC, RoE shall be reduced by 1% for the period for which the deficiency continues:

(vi)additional RoE shall not be admissible for transmission line having length of less than 50 kilometers.

25. Tax on Return on Equity.

(1)The base rate of return on equity as allowed by the Commission under Regulation 24 shall be grossed up with the effective tax rate of the respective financial year. For this purpose, the effective tax rate shall be considered on the basis of actual tax paid in the respect of the financial year in line with the provisions of the relevant Finance Acts by the concerned generating company or the transmission licensee, as the case may be. The actual tax income on other income stream (i.e., income of non generation or non transmission business, as the case may be) shall not be considered for the calculation of "effective tax rate".

(2)Rate of return on equity shall be rounded off to three decimal places and shall be computed as per the formula given below:Rate of pre-tax return on equity = Base rate / (1-t)Where "t" is the effective tax rate in accordance with Clause (1) of this regulation and shall be calculated at the beginning of every financial year based on the estimated profit and tax to be paid estimated in line with the provisions of the relevant Finance Act applicable for that financial year to the company on pro-rata basis by excluding the income of non-generation or non-transmission business, as the case may be, and the corresponding tax thereon. In case of generating company or transmission licensee paying Minimum Alternate Tax (MAT), "t" shall be considered as MAT rate including surcharge and cess.Illustration. - (i) In case of the generating company or the transmission licensee paying Minimum Alternate Tax (MAT) @ 20.96% including surcharge and cess:Rate of return on equity = 15.50/(1-0.2096) = 19.610%

(ii)In case of generating company or the transmission licensee paying normal corporate tax including surcharge and cess:

(a)Estimated Gross Income from generation or transmission business for FY 2014-15 is Rs 1000 crore.

(b)Estimated Advance Tax for the year on above is Rs 240 crore.

(c)Effective Tax Rate for the year 2014-15 = Rs 240 Crore/Rs 1000 Crore = 24%

(d)Rate of return on equity = 15.50/ (1-0.24) = 20.395%

(3)The generating company or the transmission licensee, as the case may be, shall true up the grossed up rate of return on equity at the end of every financial year based on actual tax paid together with any additional tax demand including interest thereon, duly adjusted for any refund of tax including interest received from the income tax authorities pertaining to the tariff period 2014-15 to 2018-19 on actual gross income of any financial year. However, penalty, if any, arising on account of delay in deposit or short deposit of tax amount shall not be claimed by the generating company or the transmission licensee as the case may be. Any under-recovery or over-recovery of grossed up rate on return on equity after truing up, shall be recovered or refunded to beneficiaries or the long term transmission customers/DICs as the case may be on year to year basis.

26. Interest on loan capital.

(1)The loans arrived at in the manner indicated in regulation 19 shall be considered as gross normative loan for calculation of interest on loan.

(2)The normative loan outstanding as on 1.4.2014 shall be worked out by deducting the cumulative repayment as admitted by the Commission up to 31.3.2014 from the gross normative loan.

(3)The repayment for each of the year of the tariff period 2014-19 shall be deemed to be equal to the depreciation allowed for the corresponding year/period. In case of decapitalization of assets, the repayment shall be adjusted by taking into account cumulative repayment on a pro rata basis and the adjustment should not exceed cumulative depreciation recovered upto the date of decapitalisation of such asset.

(4)Notwithstanding any moratorium period availed by the generating company or the transmission licensee, as the case may be, the repayment of loan shall be considered from the first year of commercial operation of the project and shall be equal to the depreciation allowed for the year or part of the year.

(5)The rate of interest shall be the weighted average rate of interest calculated on the basis of the actual loan portfolio after providing appropriate accounting adjustment for interest capitalized:Provided that if there is no actual loan for a particular year but normative loan is still outstanding, the last available weighted average rate of interest shall be considered:Provided further that if the generating station or the transmission system, as the case may be, does not have actual loan, then the weighted average rate of interest of the generating company or the transmission licensee as a whole shall be considered.

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

(7)The generating company or the transmission licensee, as the case may be, shall make every effort to re-finance the loan as long as it results in net savings on interest and in that event the costs associated with such re-financing shall be borne by the beneficiaries and the net savings shall be shared between the beneficiaries and the generating company or the transmission licensee, as the case may be, in the ratio of 2:1.

(8)The changes to the terms and conditions of the loans shall be reflected from the date of such re-financing.

(9)In case of dispute, any of the parties may make an application in accordance with the Central Electricity Regulatory Commission (Conduct of Business) Regulations, 1999, as amended from time to time, including statutory re-enactment thereof for settlement of the dispute:Provided that the beneficiaries or the long term transmission customers /DICs shall not withhold any payment on account of the interest claimed by the generating company or the transmission licensee during the pendency of any dispute arising out of re-financing of loan.

27. Depreciation.

(1)Depreciation shall be computed from the date of commercial operation of a generating station or unit thereof or a transmission system including communication system or element thereof. In case of the tariff of all the units of a generating station or all elements of a transmission system including communication system for which a single tariff needs to be determined, the depreciation shall be computed from the effective date of commercial operation of the generating station or the transmission system taking into consideration the depreciation of individual units or elements thereof.Provided that effective date of commercial operation shall be worked out by considering the actual date of commercial operation and installed capacity of all the units of the generating station or capital cost of all elements of the transmission system, for which single tariff needs to be determined.

(2)The value base for the purpose of depreciation shall be the capital cost of the asset admitted by the Commission. In case of multiple units of a generating station or multiple elements of transmission system, weighted average life for the generating station of the transmission system shall be applied. Depreciation shall be chargeable from the first year of commercial operation. In case of commercial operation of the asset for part of the year, depreciation shall be charged on pro rata basis.

(3)The salvage value of the asset shall be considered as 10% and depreciation shall be allowed up to maximum of 90% of the capital cost of the asset:Provided that in case of hydro generating station, the salvage value shall be as provided in the agreement signed by the developers with the State Government for development of the Plant:Provided further that the capital cost of the assets of the hydro generating station for the purpose of computation of depreciated value shall correspond to the percentage of sale of electricity under long-term power purchase agreement at regulated tariff:Provided also that any depreciation disallowed on account of lower availability of the generating station or generating unit or transmission system as the case may be, shall not be allowed to be recovered at a later stage during the useful life and the extended life.

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

(5)Depreciation shall be calculated annually based on Straight Line Method and at rates specified in Appendix-II to these regulations for the assets of the generating station and transmission system:Provided that the remaining depreciable value as on 31st March of the year closing after a period of 12 years from the effective date of commercial operation of the station shall be spread over the balance useful life of the assets.

(6)In case of the existing projects, the balance depreciable value as on 1.4.2014 shall be worked out by deducting the cumulative depreciation as admitted by the Commission upto 31.3.2014 from the gross depreciable value of the assets.

(7)The generating company or the transmission license, as the case may be, shall submit the details of proposed capital expenditure during the fag end of the project (five years before the useful life) alongwith justification and proposed life extension.The Commission based on prudence check of such submissions shall approve the depreciation on capital expenditure during the fag end of the project.

(8)In case of de-capitalization of assets in respect of generating station or unit thereof or transmission system or element thereof, the cumulative depreciation shall be adjusted by taking into account the depreciation recovered in tariff by the decapitalized asset during its useful services.

28. Interest on Working Capital.

(1)The working capital shall cover:

(a)Coal-based/lignite-fired thermal generating stations

(i)Cost of coal or lignite and limestone towards stock, if applicable, for 15 days for pit-head generating stations and 30 days for non-pit-head generating stations for generation corresponding to the normative annual plant availability factor or the maximum coal/lignite stock storage capacity whichever is lower;

(ii)Cost of coal or lignite and limestone for 30 days for generation corresponding to the normative annual plant availability factor;

(iii)Cost of secondary fuel oil for two months for generation corresponding to the normative annual plant availability factor, and in case of use of more than one secondary fuel oil, cost of fuel oil stock for the main secondary fuel oil;

(iv)Maintenance spares @ 20% of operation and maintenance expenses specified in regulation 29;

(v)Receivables equivalent to two months of capacity charges and energy charges for sale of electricity calculated on the normative annual plant availability factor; and

(vi)Operation and maintenance expenses for one month.

(b)Open-cycle Gas Turbine/Combined Cycle thermal generating stations

(i)Fuel cost for 30 days corresponding to the normative annual plant availability factor, duly taking into account mode of operation of the generating station on gas fuel and liquid fuel;

(ii)Liquid fuel stock for 15 days corresponding to the normative annual plant availability factor, and in case of use of more than one liquid fuel, cost of main liquid fuel duly taking into account mode of operation of the generating stations of gas fuel and liquid fuel;

(iii)Maintenance spares @ 30% of operation and maintenance expenses specified in Regulation 29;

(iv)Receivables equivalent to two months of capacity charge and energy charge for sale of electricity calculated on normative plant availability factor, duly taking into account mode of operation of the generating station on gas fuel and liquid fuel; and

(v)Operation and maintenance expenses for one month.

(c)Hydro generating station including pumped storage hydro electric generating station and transmission system including communication system:

(i)Receivables equivalent to two months of fixed cost;

(ii)Maintenance spares @ 15% of operation and maintenance expenses specified in regulation 29; and

(iii)Operation and maintenance expenses for one month.

(2)The cost of fuel in cases covered under sub-clauses (a) and (b) of clause (1) of this regulation shall be based on the landed cost incurred (taking into account normative transit and handling losses) by the generating company and gross calorific value of the fuel as per actual for the three months preceding the first month for which tariff is to be determined and no fuel price escalation shall be provided during the tariff period.

(3)Rate of interest on working capital shall be on normative basis and shall be considered as the bank rate as on 1.4.2014 or as on 1st April of the year during the tariff period 2014-15 to 2018-19 in which the generating station or a unit thereof or the transmission system including communication system or element thereof, as the case may be, is declared under commercial operation, whichever is later.

(4)Interest on working capital shall be payable on normative basis notwithstanding that the generating company or the transmission licensee has not taken loan for working capital from any outside agency.

29. Operation and Maintenance Expenses.

(1)Normative Operation and Maintenance expenses of thermal generating stations shall be as follows:

(a)Coal based and lignite fired (including those based on Circulating Fluidised Bed Combustion (CFBC) technology) generating stations, other than the generating stations/units referred to in clauses (b) and (d):

(in Rs Lakh/MW)

Year	200/210/250 MW Sets	300/330/350 MW Sets	500 MW Sets	600 MW Sets and above
FY 2014-15	23.90	19.95	16.00	14.40
FY 2015-16	25.40	21.21	17.01	15.31
FY 2016-17	27.00	22.54	18.08	16.27
FY 2017-18	28.70	23.96	19.22	17.30
FY 2018-19	30.51	25.47	20.43	18.38

Provided that the norms shall be multiplied by the following factors for arriving at norms of O&M expenses for additional units in respective unit sizes for the units whose COD occurs on or after 1.4.2014 in the same station:

200/210/250 MW	Additional 5th& 6thunits	0.90
	Additional 7th& more units	0.85
300/330/350 MW	Additional 4th& 5thunits	0.90
	Additional 6th& more units	0.85
500 MW and above	Additional 3rd& 4thunits	0.90
	Additional 5th& above units	0.85

(b)Talcher Thermal Power Station (TPS), Tanda TPS, Badarpur TPS Unit 1 to 3 of NTPC and Chandrapura TPS Unit 1 to 3 and Durgapur TPS Unit 1 of DVC:

(in Rs Lakh/MW)

Year	Talcher TPS	Chandrapura TPS (Units 1 to 3), Tanda TPS,Badarpur TPWS (Unit 1 to 3) , Durgapur TPS (Unit 1)
2014-15	43.16	35.88
2015-16	45.87	38.14
2016-17	48.76	40.54
2017-18	51.83	43.09
2018-19	55.09	45.80

(c)Open Cycle Gas Turbine/Combined Cycle generating stations:

(in Rs Lakh/MW)

Year	Gas Turbine/ Combined Cycle generatingstations other than small gas turbine power generating stations	Small gas turbine power generating stations	Agartala GPS	Advance F Class Machines
2014-15	14.67	33.43	41.32	26.55
2015-16	15.59	35.70	44.14	28.36
2016-17	16.57	38.13	47.14	30.29
2017-18	17.61	40.73	50.35	32.35
2018-19	18.72	43.50	53.78	34.56

(d)Lignite-fired generating stations :

(in Rs Lakh/MW)

Year	125 MW Sets	TPS-I of NLC
2014-15	29.10	38.12
2015-16	30.94	40.52
2016-17	32.88	43.07
2017-18	34.95	45.78
2018-19	37.15	48.66

(e)Generating Stations based on coal rejects :

Year	O&M Expenses (in Rs Lakh/MW)
2014-15	29.10
2015-16	30.94
2016-17	32.88
2017-18	34.95
2018-19	37.15

(2)The Water Charges and capital spares for thermal generating stations shall be allowed separately:Provided that water charges shall be allowed based on water consumption depending upon type of plant, type of cooling water system etc., subject to prudence check. The details regarding the same shall be furnished along with the petition:Provided that the generating station shall submit the details of year wise actual capital spares consumed at the time of truing up with appropriate justification for incurring the same and substantiating that the same is not funded through compensatory allowance or special allowance or claimed as a part of additional capitalisation or consumption of stores and spares and renovation and modernization.

(3)Hydro Generating Station :

(a)Following operations and maintenance expense norms shall be applicable for hydro generating stations which have been operational for three or more years as on 01.04.2014:

(in Rs lakh)

Sr. No.	Name of Station	2014-15	2015-16	2016-17	2017-18	2018-19
A. NHPC
1.	Bairasul	8696.25	9274.03	9890.19	10547.30	11248.06
2.	Loktak	9673.64	10316.36	11001.78	11732.74	12512.26
3.	Salal	14429.58	15388.29	16410.68	17501.01	18663.78
4.	Tanakpur	7101.62	7573.45	8076.63	8613.24	9185.51
5.	Chamera-I	10664.95	11373.53	12129.19	12935.05	13794.46
6.	Uri	7419.40	7912.34	8438.04	8998.66	9596.54
7.	Rangit	4576.46	4880.52	5204.78	5550.58	5919.36
8.	Chamera-II	7256.54	7738.66	8252.82	8801.14	9385.89
9.	Dhauliganga	7181.89	7659.05	8167.92	8710.59	9289.33
10.	Dulhasti	13746.97	14660.32	15634.36	16673.10	17780.86
11.	Teesta-V	8297.32	8848.59	9436.50	10063.46	10732.07
12.	Sewa-II	6157.56	6566.67	7002.96	7468.24	7964.43
D. NHDC
1.	Indira Sagar	8607.73	9179.63	9789.52	10439.94	11133.57
2.	Omkareshwar	4515.31	4815.30	5135.23	5476.42	5840.27
E. NEEPCO
1.	Kopili–I	6132.72	6540.18	6974.71	7438.11	7932.3
2.	Ranganadi	7033.08	7500.36	7998.68	8530.12	9096.86
3.	Doyang	3900.10	4159.22	4435.56	4730.26	5044.54
4.	Khandong	1233.87	1317.89	1405.45	1498.82	1598.41
5.	Kopili-II	321.00	342.33	365.07	389.32	415.19
F. DVC
1.	Panchet	1546.42	1649.17	1758.74	1875.59	2000.20
2.	Tilaiya	698.99	745.43	794.95	847.77	904.10
3.	Maithon	1914.46	2041.66	2177.31	2321.97	2476.24

(b)for hydro generating stations of Satluj Jal Vidyut Nigam Limited (SJVNL) and Tehri Development Corporation Limited (THDC), the O&M expenses shall be approved as per the following methodology:

(i)The operation and maintenance expenses shall be derived on the basis of actual operation and maintenance expenses for the years 2008-09 to 2012-13, based on the audited balance sheets, excluding abnormal operation and maintenance expenses, if any, after prudence check by the Commission.

(ii)The normalised operation and maintenance expenses after prudence check, for the years 2008-09 to 2012-13, shall be escalated at the rate of 6.04% to arrive at the normalized operation and maintenance expenses at the 2012-13 price level respectively and then averaged to arrive at normalized average operation and maintenance expenses for the 2008-09 to 2012-13 at 2012-13 price level. The average normalized operation and maintenance expenses at 2012-13 price level shall be escalated at the rate of 6.04% to arrive at the operation and maintenance expenses for year 2013-14 and thereafter escalated at the rate of 6.64% p.a., to arrive at the O&M expenses for the period FY 2014-15 to FY 2018-19.

(c)In case of the hydro generating stations, which have not been in commercial operation for a period of three years as on 1.4.2014, operation and maintenance expenses shall be fixed at 2% of the original project cost (excluding cost of rehabilitation and resettlement works) for the first year of commercial operation.

Further, in such case, operation and maintenance expenses in first year of commercial operation shall be escalated @6.04% per annum up to the year 2013-14 and then averaged to arrive at the O&M expenses at 2013-14 price level. It shall be thereafter escalated @ 6.64%per annum to arrive at operation and maintenance expenses in respective year of the tariff period.

(d)In case of the hydro generating stations declared under commercial operation on or after 1.4.2014, operation and maintenance expenses shall be fixed at 4% and 2.50% of the original project cost (excluding cost of rehabilitation & resettlement works) for first year of commercial operation for stations less than 200 MW projects and for stations more than 200 MW respectively and shall be subject to annual escalation of 6.64% per annum for the subsequent years.

(3)Transmission system :

(a)The following normative operation and maintenance expenses shall be admissible for the transmission system :

Norms for sub-stations(in Rs Lakh per bay)	2014-15	2015-16	2016-17	2017-18	2018-19
765 kV	84.42	87.22	90.12	93.11	96.20
400 kV	60.30	62.30	64.37	66.51	68.71
220 kV	42.21	43.61	45.06	46.55	48.10
132 kV and below	30.15	31.15	32.18	33.25	34.36
400 kV Gas Insulated Substation	51.54	53.25	55.02	56.84	58.73
Norms for AC and HVDC lines (in Rs Lakh per km)
Single Circuit (Bundled Conductor with six or moresub-conductors)	0.707	0.731	0.755	0.780	0.806
Single Circuit (Bundled Conductor with four subconductors)	0.606	0.627	0.647	0.669	0.691
Single Circuit (Twin & Triple Conductor)	0.404	0.418	0.432	0.446	0.461
Single Circuit (Single Conductor)	0.202	0.209	0.216	0.223	0.230
Double Circuit (Bundled conductor with four or moresub-conductors)	1.062	1.097	1.133	1.171	1.210
Double Circuit (Twin & Triple Conductor)	0.707	0.731	0.755	0.780	0.806
Double Circuit (Single Conductor)	0.303	0.313	0.324	0.334	0.346
Multi Circuit (Bundled conductor with four or moresub-conductors)	1.863	1.925	1.989	2.055	2.123
Multi Circuit (Twin & Triple Conductor)	1.240	1.282	1.324	1.368	1.413
Norms for HVDC Stations
HVDC Back–to-back stations (Rs. Lakh per 500 MW)	578	627	679	736	797
Rihand-Dadri HVDC bipole scheme (Rs. Lakh)	1511	1637	1774	1922	2082
Talcher-Kolar HVDC bipole scheme (Rs. Lakh)	1173	1271	1378	1493	1617
Balia-Bhiwadi HVDC bipole scheme (Rs. Lakh)	1537	1666	1805	1955	2119

Provided that operation and maintenance expenses for new HVDC bi-pole scheme for a particular year shall be allowed pro-rata on the basis of normative rate of operation and maintenance expense for 2000 MW, Talcher-Kolar HVDC bi-pole scheme for the respective year:Provided further that the O&M expenses norms for HVDC bi-pole line shall be considered as Single Circuit quad AC line.

(b)The total allowable operation and maintenance expenses for the transmission system shall be calculated by multiplying the number of bays and kms of line length with the applicable norms for the operation and maintenance expenses per bay and per km respectively.

(c)The operation and maintenance expenses of communication system forming part of inter-state transmission system shall be derived on the basis of the actual O&M expenses for the period of 2008-09 to 2012-13 based on audited accounts excluding abnormal variations if any after prudence check by the Commission. The normalised O&M expenses after prudence check, for the years 2008-09 to 2012-13 shall be escalated at the rate of 3.02% for computing base year expenses for FY 2012-13 and 2013-14 and at the rate of 3.32% for escalation from 2014-15 onwards.

Chapter - 7 Computation of Capacity Charges and Energy Charges

30. Computation and Payment of Capacity Charge and Energy Charge for Thermal Generating Stations.

(1)The fixed cost of a thermal generating station shall be computed on annual basis, based on norms specified under these regulations, and recovered on monthly basis under capacity charge. The total capacity charge payable for a generating station shall be shared by its beneficiaries as per their respective percentage share / allocation in the capacity of the generating station.

(2)The capacity charge payable to a thermal generating station for a calendar month shall be calculated in accordance with the following formulae:CC1 = ((AFC/12) (PAF1 / NAPAF) subject to ceiling of (AFC/12))CC2 = ((AFC/6) (PAF2 / NAPAF) subject to ceiling of (AFC/6)) - CC1CC3 = ((AFC/4) (PAF3 / NAPAF) subject to ceiling of (AFC/4)) - (CC1 + CC2)CC4 = ((AFC/3) (PAF4 / NAPAF) subject to ceiling of (AFC/3)) - (CC1 + CC2 + CC3)CC5 = ((AFC x 5/12) (PAF5 / NAPAF) subject to ceiling of (AFC x 5/12)) - (CC1 + CC2 + CC3 + CC4)CC6 = ((AFC/2) (PAF6 / NAPAF) subject to ceiling of (AFC/2)) - (CC1 + CC2 + CC3 + CC4 + CC5)CC7= ((AFC x 7/12) (PAF7 / NAPAF) subject to ceiling of (AFC x 7/12)) - (CC1 + CC2 + CC3 + CC4 + CC5 + CC6)CC8 = ((AFC x 2/3) (PAF8 / NAPAF) subject to ceiling of (AFC x 2/3)) - (CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7)CC9 = ((AFC x ¾) (PAF9 / NAPAF) subject to ceiling of (AFC x ¾)) - (CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7 + CC8)CC10= ((AFC x 5/6) (PAF10 / NAPAF) subject to ceiling of (AFC x 5/6)) - (CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7 + CC8 + CC9)CC11 = ((AFC x 11/12) (PAF11 / NAPAF) subject to ceiling of (AFC x 11/12)) - (CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7 + CC8 + CC9 + CC10)CC12 = ((AFC) (PAFY / NAPAF) subject to ceiling of (AFC)) - (CC1 + CC2 + CC3 + CC4 + CC5 + CC6 + CC7 + CC8 + CC9 + CC10 + CC11)Provided that in case of generating station or unit thereof or transmission system or an element thereof, as the case may be, under shutdown due to Renovation and Modernisation, the generating company or the transmission licensee shall be allowed to recover part of AFC which shall include O&M expenses and interest on loan only.Where,AFC Annual fixed cost specified for the year, in Rupees.NAPAF = Normative annual plant availability factor in percentage.PAFN = Percent Plant availability factor achieved upto the end of the nth month.PAFY = Percent Plant availability factor achieved during the YearCC1, CC2, CC3, CC4, CC5, CC6, CC7, CC8, CC9, CC10, CC11 and CC12 are the Capacity Charges of 1st, 2nd, 3rd, 4th, 5th, 6th, 7th, 8th, 9th, 10th, 11th and 12th months respectively.

(3)The PAFM upto the end of a particular month and PAFY shall be computed in accordance with the following formula:

N|-

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

i=1

Where,AUX=Normative auxiliary energy consumption in percentage.DCi = Average declared capacity (in ex-bus MW), 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.Note: - DCi and IC shall exclude the capacity of generating units not declared under commercial operation. In case of a change in IC during the concerned period, its average value shall be taken.

(4)Incentive to a generating station or unit thereof shall be payable at a flat rate of 50 paise/kWh for ex-bus scheduled energy corresponding to scheduled generation in excess of ex-bus energy corresponding to Normative Annual Plant Load Factor NAPLF) as specified in regulation 36 (B).

(5)The energy charge shall cover the primary and secondary 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.}

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

(a)For coal based and lignite fired stations

ECR = {(GHR - SFC x CVSF) x LPPF / CVPF+SFC x LPSFi + LC x LPL} 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 percentage.CVPF = (a) Weighted Average Gross calorific value of coal as received, in kCal per kg for coal based stations

(b)Weighted Average Gross calorific value of primary fuel as received, in kCal per kg, per litre or per standard cubic meter, as applicable for lignite, gas and liquid fuel based stations.

(c)In case of blending of fuel from different sources, the weighted average Gross calorific value of primary fuel shall be arrived in proportion to blending ratio.

CVSF = Calorific value of secondary fuel, in kCal per ml.ECR = Energy charge rate, in Rupees per kWh sent out.GHR = Gross station heat rate, in kCal per kWh.LC = Normative limestone consumption in kg per kWh.LPL = Weighted average landed price of limestone in Rupees per kg.LPPF = Weighted average landed price of primary fuel, in Rupees per kg, per litre or per standard cubic metre, as applicable, during the month. (In case of blending of fuel from different sources, the weighted average landed price of primary fuel shall be arrived in proportion to blending ratio)SFC = Normative Specific fuel oil consumption, in ml per kWh.LPSFi = Weighted Average Landed Price of Secondary Fuel in Rs./ml during the month Provided that energy charge rate for a gas/liquid fuel based station shall be adjusted for open cycle operation based on certification of Member Secretary of respective Regional Power Committee for the open cycle operation during the month.

(7)The generating company shall provide to the beneficiaries of the generating station the details of parameters of GCV and price of fuel i.e. domestic coal, imported coal, e-auction coal, lignite, natural gas, RLNG, liquid fuel etc., as per the forms prescribed at Annexure-I to these regulations:Provided that the details of blending ratio of the imported coal with domestic coal, proportion of e-auction coal and the weighted average GCV of the fuels as received shall also be provided separately, along with the bills of the respective month:Provided further that copies of the bills and details of parameters of GCV and price of fuel i.e. domestic coal, imported coal, e-auction coal, lignite, natural gas, RLNG, liquid fuel etc., details of blending ratio of the imported coal with domestic coal, proportion of e-auction coal shall also be displayed on the website of the generating company. The details should be available on its website on monthly basis for a period of three months.

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

Pithead generating stations	:	0.2%
Non-pithead generating stations	:	0.8%

Provided that in case of pit head stations if coal or lignite is procured from sources other than the pit head mines which is transported to the station through rail, transit loss of 0.8% shall be applicable:Provided further that in case of imported coal, the transit and handling losses shall be 0.2%.

(9)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.

(10)In case of part or full use of alternative source of fuel supply by coal based thermal generating stations other than as agreed by the generating company and beneficiaries in their power purchase agreement for supply of contracted power on account of shortage of fuel or optimization of economical operation through blending, the use of alternative source of fuel supply shall be permitted to generating station:Provided that in such case, prior permission from beneficiaries shall not be a precondition, unless otherwise agreed specifically in the power purchase agreement:Provided further that the weighted average price of use of alternative source of fuel shall not exceed 30% of base price of fuel computed as per clause (11) of this regulation:Provided also that where the energy charge rate based on weighted average price of use of fuel including alternative source of fuel exceeds 30% of base energy charge rate as approved by the Commission for that year or energy charge rate based on weighted average price of use of fuel including alternative sources of fuel exceeds 20% of energy charge rate based on based on weighted average fuel price for the previous month, whichever is lower shall be considered and in that event, prior consultation with beneficiary shall be made not later than three days in advance.

(11)The Commission through the specific tariff orders to be issued for each generating station shall approve the energy charge rate at the start of the tariff period. The energy charge so approved shall be the base energy charge rate at the start of the tariff period. The base energy charge rate for subsequent years shall be the energy charge computed after escalating the base energy charge rate approved at the start of the tariff period by escalation rates for payment purposes as notified by the Commission from time to time for under competitive bidding guidelines.

(12)The tariff structure as provided in this regulation may be adopted by the Department of Atomic Energy, Government of India for the nuclear generating stations by specifying annual fixed cost (AFC), normative annual plant availability factor (NAPAF), installed capacity (IC), normative auxiliary power consumption (AUX) and energy charge rate (ECR) for such stations.

31. Computation and Payment of Capacity charge and Energy Charge for Hydro Generating Stations.

(1)The fixed cost of a hydro generating station shall be computed on annual basis, based on norms specified under these regulations, and shall be recovered on monthly basis under capacity charge (inclusive of incentive) and energy charge, which shall be payable by the beneficiaries in proportion to their respective allocation in the saleable capacity of the generating station, i.e., in the capacity excluding the free power to the home State: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.

(2)The capacity charge (inclusive of incentive) payable to a hydro generating station for a calendar month shall be :AFC x 0.5 x NDM / NDY x (PAFM / NAPAF) (in Rupees)Where,AFC = Annual fixed cost specified for the year, in RupeesNAPAF = Normative 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 percentage

(3)The PAFM shall be computed in accordance with the following formula :

N|-

PAFM = 10000 x| ∑DCi/ {N x IC X (100 - 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 nodal load dispatch centre after the day is over.IC = Installed capacity (in MW) of the complete generating stationN = Number of days in the month

(4)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 in Rs. / kWh) x {Scheduled energy (ex-bus) for the month in kWh} x (100 - FEHS) / 100

(5)Energy charge rate (ECR) in Rupees per kWh on ex-power plant basis, for a hydro generating station, shall be determined up to three decimal places based on the following formula, 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 clause (6) below.FEHS = Free energy for home State, in per cent, as defined in Regulation 42.

(6)In case the 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 station, the following treatment shall be applied on a rolling basis on an application filed by the generating company:

(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 clause (5) with the modification that the DE for the year shall be considered as equal to the actual energy generated during the year of the shortfall, till the energy charge shortfall of the previous year has been made up, after which normal ECR shall be applicable:

Provided that in case actual generation form a hydro generating station is less than the design energy for a continuous period of 4 years on account of hydrology factor, the generating station shall approach CEA with relevant hydrology data for revision of design energy of the station.

(b)In case the energy shortfall occurs after ten years from the date of commercial operation of a generating station, the following shall apply.

Explanation. - Suppose the specified annual design energy for the station is DE MWh, and the actual energy generated during the concerned (first) and the following (second) financial years is A1 and A2 MWh respectively, A1 being less than DE. Then, the design energy to be considered in the formula in clause (5) of these regulations for calculating the ECR for the third financial year shall be moderated as (A1 + A2 - DE) MWh, subject to a maximum of DE MWh and a minimum of A1 MWh.

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

(7)In case the energy charge rate (ECR) for a hydro generating station, computed as per clause (5) of this regulation exceeds ninety paise per kWh, and the actual saleable energy in a year exceeds {DE x (100 - AUX) x (100 - FEHS) / 10000} MWh, the Energy charge for the energy in excess of the above shall be billed at ninety 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 ninety paise per kWh after the energy charge shortfall of the previous year has been made up.

(8)In case of the hydro generating stations located in the State of Jammu and Kashmir, any expenditure incurred for payment of water usage charges to the State Water Resources Development Authority, Jammu under Jammu & Kashmir Water Resources (Regulations and Management) Act, 2010 shall be payable by the beneficiaries as additional energy charge in proportion of the supply of power from the generating stations on month to month basis:Provided further that the provisions of this clause shall be subject to the decision of the Hon'ble High Court of Jammu & Kashmir in OWP No. 604/2011 and shall stand modified in accordance with the decision of the High Court.

32. Pumped Storage Hydro Generating Stations.

(1)The fixed cost of a pumped storage hydro generating station shall be computed on annual basis, based on norms specified under these regulations, and recovered on monthly basis as capacity charge. The capacity charge shall be payable by the beneficiaries in proportion to their respective allocation in the saleable capacity of the generating station, i.e, the capacity excluding the free power to the home State: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 be worked out based on the latest estimate of the completion cost for the generating station, for the purpose of determining the capacity charge payment during such period.

(2)The capacity charge payable to a pumped storage hydro generating station for a calendar month shall be:(AFC x NDM / NDY) (in Rupees), if actual Generation during the month is >= 75 % of the Pumping Energy consumed by the station during the month and {(AFC x NDM / NDY) x (Actual Generation during the month during peak hours/ 75% of the Pumping Energy consumed by the station during the month) (in Rupees)}, if actual Generation during the month is < 75 % of the Pumping Energy consumed by the station during the month.Where,AFC = Annual fixed cost specified for the year, in RupeesNDM = Number of days in the monthNDY = Number of days in the yearProvided that there would be adjustment at the end of the year based on actual generation and actual pumping energy consumed by the station during the year.

(3)The energy charge shall be payable by every beneficiary for the total energy scheduled to be supplied to the beneficiary in excess of the design energy plus 75% of the energy utilized in pumping the water from the lower elevation reservoir to the higher elevation reservoir, at a flat rate equal to the average energy charge rate of 20 paise per kWh, excluding free energy, if any, during the calendar month, on ex power plant basis.

(4)Energy charge payable to the generating company for a month shall be:= 0.20 x {Scheduled energy (ex-bus) for the month in kWh - (Design Energy for the month (DEm) + 75% of the energy utilized in pumping the water from the lower elevation reservoir to the higher elevation reservoir of the month)} x (100 - FEHS) / 100.Where,DEm = Design energy for the month specified for the hydro generating station, in MWhFEHS = Free energy for home State, in per cent, as defined in regulation 42, if any.Provided that in case the Scheduled energy in a month is less than the Design Energy for the month plus 75% of the energy utilized in pumping the water from the lower elevation reservoir to the higher elevation reservoir of the month, then the energy charges payable by the beneficiaries shall be zero.

(5)The generating company shall maintain the record of daily inflows of natural water into the upper elevation reservoir and the reservoir levels of upper elevation reservoir and lower elevation reservoir on hourly basis. The generator shall be required to maximize the peak hour supplies with the available water including the natural flow of water. In case it is established that generator is deliberately or otherwise without any valid reason, is not pumping water from lower elevation reservoir to the higher elevation during off-peak period or not generating power to its potential or wasting natural flow of water, the capacity charges of the day shall not be payable by the beneficiary. For this purpose, outages of the unit(s)/station including planned outages and the forced outages up to 15% in a year shall be construed as the valid reason for not pumping water from lower elevation reservoir to the higher elevation during off-peak period or not generating power using energy of pumped water or natural flow of water:Provided that the total capacity charges recovered during the year shall be adjusted on pro-rata basis in the following manner in the event of total machine outages in a year exceeds 15%:

(ACC)adj = (ACC) R x (100-ATO)/85

Where,

(ACC)adj - Adjusted Annual Capacity Charges

(ACC)R - Annual Capacity Charges recovered

ATO - Total Outages in percentage for the year including forced and planned outagesProvided further that the generating station shall be required to declare its machine availability daily on day ahead basis for all the time blocks of the day in line with the scheduling procedure of Grid Code.

(6)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.

33. Computation and Payment of Transmission Charge for Inter-State Transmission System.

(1)The fixed cost of the transmission system or communication system forming part of transmission system shall be computed on annual basis, in accordance with norms contained in 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 in Regulation 43.

(2)The Transmission charge (inclusive of incentive) payable for a calendar month for transmission system or part shall be-For AC system:

(a)For TAFM ≤ 98%

AFC x (NDM/NDY) x (TAFM/98%)

(b)For TAFM: 98%< TAFM < 98.5%

AFC x (NDM/NDY) x (1)

(c)For TAFM: 98.5%< TAFM ≤ 99.75%

AFC x (NDM/NDY) x (TAFM/98.5%)

(d)For TAFM ≥ 99.75%

AFC x (NDM/NDY) x (99.75%/98.5%)For HVDC bi-pole links and HVDC back-to-back Stations:

(a)For TAFM ≤ 95%

AFC x (NDM/NDY) x (TAFM/95%)

(b)For TAFM: 95%< TAFM < 96%

AFC x (NDM/NDY) x (1)

(c)For TAFM: 96%≤ TAFM ≤ 99.75%

AFC x (NDM/NDY) x (TAFM/96%)

(d)For TAFM ≥ 99.75%

AFC x (NDM/NDY) x (99.75%/96%)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 computed in accordance with Appendix III.

(3)The transmission charges shall be calculated separately for part of the transmission system having different NATAF, and aggregated thereafter, according to their sharing by the long term transmission customers/DICs.

34. Deviation Charges.

(1)Variations between actual net injection and scheduled net injection for the generating stations, and variations between actual net drawal and scheduled net drawal for the beneficiaries shall be treated as their respective deviations and charges for such deviations shall be governed by the Central Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters) Regulations, 2014, as amended from time to time or any subsequent re-enactment thereof.

(2)Actual net deviation of every Generating Stations and Beneficiaries shall be metered on its periphery through special energy meters (SEMs) installed by the Central Transmission Utility (CTU), and computed in MWh for each 15-minute time block by the concerned Regional Load Despatch Centre.Chapter - 8 Norms of Operation

35.

(1)Recovery of capacity charge, energy charge, transmission charge and incentive by the generating company and the transmission licensee shall be based on the achievement of the operational norms specified in the regulations 36 to 39.

(2)The Commission may on its own revise the norms of Station Heat Rate specified in Regulation 36 in respect of any of the generating stations for which relaxed norms have been specified.Norms of operation for thermal generating station

36.

The norms of operation as given hereunder shall apply to thermal generating stations:

(A)Normative Annual Plant Availability Factor (NAPAF)

(a)All thermal generating stations, except those covered under clauses (b), (c), (d), & (e) - 85%

Provided that in view of shortage of coal and uncertainty of assured coal supply on sustained basis experienced by the generating stations, the NAPAF for recovery of fixed charges shall be 83% till the same is reviewed.The above provision shall be reviewed based on actual feedback after 3 years from 01.04.2014.

(b)Following Lignite-fired Thermal generating stations of Neyveli Lignite Corporation Ltd:

TPS-I	72%
TPS-II Stage I & II	75%
TPS-I (Expansion)	80%

(c)Following Thermal Generating Stations of DVC:

Bokaro TPS	75%
Chandrapura TPS	75%
Durgapur TPS	74%

(d)Following Gas based Thermal Generating Stations of NEEPCO:

Assam GPS

72%

(e)Lignite fired Generating Stations using Circulatory Fluidized Bed Combustion (CFBC) Technology and Generating stations based on coal rejects :

1. First Three years from COD - 75%

2. For next year after completion of three years of COD - 80%

(B)Normative Annual Plant Load Factor (NAPLF) for Incentive

(a)All thermal generating stations, except those covered under clauses (b), (c) - 85%

(b)Following Lignite-fired Thermal generating stations of Neyveli Lignite Corporation Ltd :

TPS-I	75%
TPS-II Stage I & II	80%
TPS-I (Expansion)	80%

(c)Following Thermal Generating Stations of Damodar Valley Corporation (DVC):

Bokaro TPS	80%
Chandrapura TPS	80%
Durgapur TPS	80%

(C)Gross Station Heat Rate

(a)Existing Thermal Generating Station

(i)Existing Coal-based Thermal Generating Stations, other than those covered under clauses (ii) and (iii) below :

200/210/250 MW Sets	500 MW Sets (Sub-critical)
2450kCal/kWh	2375 kCal/kWh

Note 1 - In respect of 500 MW and above units where the boiler feed pumps are electrically operated, the gross station heat rate shall be 40 kCal/kWh lower than the gross station heat rate specified above.Note 2 - For the generating stations having combination of 200/210/250 MW sets and 500 MW and above sets, the normative gross station heat rate shall be the weighted average gross station heat rate of the combinations.

(ii)Following Thermal generating stations of NTPC Ltd:

Badarpur TPS	2750kCal/kWh
Talcher TPS	2850kCal/kWh
Tanda TPS	2750kCal/kWh

(iii)Thermal Generating Stations of Damodar Valley Corporation (DVC):

Bokaro TPS	2700kCal/kWh
Chandrapura TPS (Unit 1 to 3)	3100kCal/kWh
Durgapur TPS	2820kCal/kWh

(iv)Lignite-fired Thermal Generating Stations :

For lignite-fired thermal generating stations, except for TPS-I and TPS-II (Stage I & II) of Neyveli Lignite Corporation Ltd, the gross station heat rates specified under sub-clause (i) for coal-based thermal generating stations shall be applied with correction, using multiplying factors as given below:

(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 pro-rated for moisture content between 30-40% and 40-50% depending upon the rated values of multiplying factor for the respective range given under sub-clauses (a) to (c) above.

(v)TPS-I and TPS-II (Stage I & II) of Neyveli Lignite Corporation Ltd :

TPS-I :	4000kCal/kWh
TPS-II :	2900kCal/kWh
TPS-I (Expansion) :	2750kCal/kWh

(vi)Open Cycle Gas Turbine/Combined Cycle generating stations :

Existing generating stations of NTPC Ltd and NEEPCO

Name of generating station	Combined cycle(kCal/kWh)	Open Cycle(kCal/kWh)
Gandhar GPS	2040	2960
Kawas GPS	2050	3010
Anta GPS	2075	3010
Dadri GPS	2000	3010
Auraiya GPS	2100	3045
Faridabad GPS	1975	2900
Kayamkulam GPS	2000	2900
Assam GPS	2500	3440
Agartala GPS	-	3700
Sugen	1850	2685
Ratnagiri	1850	2685

(b)New Thermal Generating Station achieving COD on or after 1.4.2014

(i)Coal-based and lignite-fired Thermal Generating Stations = 1.045 X Design Heat Rate (kCal/kWh)

Where the Design Heat Rate of a generating 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
SHT/RHT (°C)	535/535	537/537	537/565	565/593
Type of BFP	Electrical Driven	Turbine Driven	Turbine Driven	Turbine Driven
Max Turbine Heat Rate (kCal/kWh)	1955	1950	1935	1850
Min. Boiler Efficiency
Sub-Bituminous Indian Coal	0.86	0.86	0.86	0.86
Bituminous Imported Coal	0.89	0.89	0.89	0.89
Max Design Unit Heat Rate (kCal/kWh)
Sub-Bituminous Indian Coal	2273	2267	2250	2151
Bituminous Imported Coal	2197	2191	2174	2078

Provided further that in case pressure and temperature parameters of a unit are different from above ratings, the maximum design unit heat rate of the nearest class shall be taken:Provided also that where unit heat rate has not been guaranteed but turbine cycle heat rate and boiler efficiency are guaranteed separately by the same supplier or different suppliers, the unit design heat rate shall be arrived at by using guaranteed turbine cycle heat rate and boiler efficiency:Provided also that where the boiler efficiency is below 86% for Sub-bituminous Indian coal and 89% for bituminous imported coal, the same shall be considered as 86% and 89% respectively for Sub-bituminous Indian coal and bituminous imported coal for computation of station heat rate:Provided also that maximum turbine cycle heat rate shall be adjusted for type of dry cooling system:Provided also that if one or more generating units were declared under commercial operation prior to 1.4.2014, the heat rate norms for those generating units as well as generating units declared under commercial operation on or after 1.4.2014 shall be lower of the heat rate norms arrived at by above methodology and the norms as per the regulation 36(C)(a)(i):Provided also that in case of lignite-fired generating stations (including stations based on CFBC technology), maximum design heat rates shall be increased using factor for moisture content given in sub-clause (C)(a)(iv) of this regulation:Provided also that for Generating stations based on coal rejects, the Commission will approve the Design Heat Rate on case to case basis.Note: - In respect of generating 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.

(c)Thermal Generating Station having COD on or after 1.4.2009 till 31.03.2014

(i)Coal-based and lignite-fired Thermal Generating Stations = 1.045 X Design Heat Rate (kCal/kWh)

Where the Design Heat Rate of a generating 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 heat rate norms computed as per above shall be limited to the heat rate norms approved during FY 2009-10 to FY 2013-14.

(d)Gas-based / Liquid-based thermal generating unit(s)/ block(s) having COD on or after 01.04.2009.

= 1.05 X Design Heat Rate of the unit/block for Natural Gas and RLNG (kCal/kWh)= 1.071 X Design Heat Rate of the unit/block for Liquid Fuel (kCal/kWh)Where the Design Heat Rate of a unit shall mean the guaranteed heat rate for a unit at 100% MCR and at site ambient conditions; and the Design Heat Rate of a block shall mean the guaranteed heat rate for a block at 100% MCR, site ambient conditions, zero percent make up, design cooling water temperature/back pressure:Provided that the heat rate norms computed as per above shall be limited to the heat rate norms approved during FY 2009-10 to FY 2013-14.

(D)Secondary fuel oil consumption

(a)	Coal-based generating stations other than at (c) below :	0.50 ml/kWh
(b)	(i) Lignite-fired generating stations except stations based onCFBC technology and TPS-I :	2ml/kWh
	(ii) TPS-I :	1.5ml/kWh
	(iii) Lignite-fired generating stations based on CFBCTechnology:	1.00ml/kWh
(c)	Coal-based generating stations of DVC :
	{\|
Mejia TPS Unit – I to IV	1.0 ml/kWh
Bokaro TPS	1.5 ml/kWh
Chandrapur TPS	1.5 ml/kWh
Durgapur TPS	2.4 ml/kWh

|-| (d)| Generating Stations based on Coal Rejects :| 2 ml/kWh|}

(E)Auxiliary Energy Consumption :

(a)Coal-based generating stations except at (b) below:

		With Natural Draft cooling tower or withoutcooling tower
(i) 200 MW series	-	8.5%
(ii) 300/330/350/500 MW and above	-
Steam drivenboiler feed pumps		5.25%
Electricallydriven boiler feed pumps	-	7.75%

Provided further that for thermal generating stations with induced draft cooling towers, the norms shall be further increased by 0.5%:Provided also that Additional Auxiliary Energy Consumption as follows may be allowed for plants with Dry Cooling Systems:

Type of Dry Cooling System	(% of gross generation )
Direct cooling air cooled condensers with mechanical draftfans	1%
Indirect cooling system employing jet condensers with pressurerecovery turbine and natural draft tower	0.5%

(b)Other Coal-based generating stations:

(i)	Talcher Thermal Power Station	:	10.50%
(ii)	Tanda Thermal Power Station	:	12.00%
(iii)	Badarpur Thermal Power Station	:	8.50%
(iv)	Bokaro Thermal Power Station	:	10.25%
(v)	Chandrapur Thermal Power Station	:	9.50%
(vi)	Durgapur Thermal Power Station	:	10.50%

(c)Gas Turbine /Combined Cycle generating stations:

(i)	Combined Cycle	:	2.5%
(ii)	Open Cycle	:	1.0%

(d)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 (E) (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 (E) (a) above.

(ii)Barsingsar Generating station of NLC using CFBC technology: 11.50%

(iii)TPS-I, TPS-I (Expansion) and TPS-II Stage-I&II of Neyveli Lignite Corporation Ltd.:

TPS-I	12.00%
TPS-II	10.00%
TPS-I (Expansion)	8.50%

(iv)Lime stone consumption for lignite-based generating station using CFBC technology:

Barsingsar	: 0.056 kg/kWh
TPS-II (Expansion)	: 0.046 kg/kWh

(e)Generating Stations based on coal rejects : 10%

37. Norms of operation for hydro generating stations.

(1)The following Normative annual plant availability factor (NAPAF) shall apply to hydro generating station:

(a)Storage and Pondage type plants with head variation between Full Reservoir Level (FRL) and Minimum Draw Down Level (MDDL) of up to 8%, and where plant availability is not affected by silt : 90%

(b)In case of storage and pondage type plants with head variation between full reservoir level and minimum draw down level is more than 8% and when plant availability is not affected by silt, the month wise peaking capability as provided by the project authorities in the DPR (approved by CEA or the State Government) shall form basis of fixation of NAPAF.

(c)Pondage type plants where plant availability is significantly affected by silt: 85%.

(d)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.

(2)A further allowance may be made by the Commission in NAPAF determination under special circumstances, e.g. abnormal silt problem or other operating conditions, and known plant limitations.

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

(4)Based on the above, the Normative annual plant availability factor (NAPAF) of the hydro generating stations already in operation shall be as follows :-

Station	Type of Plant	Plant Capacity No. of Units x MW	NAPAF (%)
NHPC
Chamera–1	Pondage	3 x 180	90
Bairasul	Pondage	3 x 60	90
Loktak	Storage	3 x 35	85
Chamera-II	Pondage	3 x 100	90
Chamera–III	Pondage	3 x 77	85
Rangit	Pondage	3 x 20	90
Dhauliganga	Pondage	4 x 70	90
Teesta–V	Pondage	3 x 170	85
Dulhasti	Pondage	3 x 130	90
Salal	ROR	6 x 115	60
Sewa–II	Pondage	3 x 40	85
Uri	ROR	4 x 120	70
Tanakpur	ROR	3 x 31.4	55
Chutak	ROR	4 x 11	50
NimooBazgo	Pondage	3 x 15	65
Teesta Low Dam Project-III	Pondage	4 x 33	85
Uri-II	Pondage	4 x 60	55
NHDC
Indirasagar	Storage	8 x 125	85
Omkareshwar	Pondage	8 x 65	90
THDC
Tehri	Storage	4 x 250	77
Koteshwar	Storage	4x100	67
SJVNL
Nathpa Jhakri	Pondage	6 x 250	90
NEEPCO
KopiliStg–1	Storage	4 x 50	79
Khandong	Storage	2 x 25	69
Kopili Stg.–2	Storage	1 x 25	69
Doyang	Storage	3 x 25	73
Ranganadi	Pondage	3 x 135	85
DVC
Panchet	Storage	2 x 40	80
Tilaiya	Storage	2 x 2	80
Maithon	Storage	3 x 20	80

(5)In case of Pumped storage hydro generating stations, the quantum of electricity required for pumping water from down-stream reservoir to up-stream reservoir shall be arranged by the beneficiaries duly taking into account the transmission and distribution losses etc. up to the bus bar of the generating station. In return, beneficiaries shall be entitled to equivalent energy of 75% of the energy utilized in pumping the water from the lower elevation reservoir to the higher elevation reservoir from the generating station during peak hours and the generating station shall be under obligation to supply such quantum of electricity during peak hours:Provided that in the event of the beneficiaries failing to supply the desired level of energy during off-peak hours, there will be pro-rata reduction in their energy entitlement from the station during peak hours:Provided further that the beneficiaries may assign or surrender their share of capacity in the generating station, in part or in full, or the capacity may be reallocated by the Central Government, and in that event, the owner or assignee of the capacity share shall be responsible for arranging the equivalent energy to the generating station in off-peak hours, and be entitled to corresponding energy during peak hours in the same way as the original beneficiary was entitled.

(6)Auxiliary Energy Consumption (AUX):

(a)Surface hydro generating stations

(i)	with rotating exciters mounted on the generator shaft	:	0.7%
(ii)	with static excitation system	:	1.00%

(b)Underground hydro generating stations

(i)	with rotating exciters mounted on the generator shaft	:	0.9%
(ii)	with static excitation system	:	1.2%

Norms of operation for transmission system

38. Normative Annual Transmission System Availability Factor (NATAF).

- It shall be as under:For recovery of Annual Fixed Charges:

(1)	AC system	:	98%
(2)	HVDC bi-pole links and HVDC back-to-back stations	:	95%

For incentive consideration:

(1)	AC system	:	98.50%
(2)	HVDC bi-pole links and HVDC back-to-back stations	:	96%

Provided that for new HVDC stations, NATAF shall be considered as 95% for first three years of operations for the purpose of incentive:Provided further that no incentive shall be payable for availability beyond 99.75%:Provided also that for AC system, two trippings per year shall be allowed. After two trippings in a year, additional 12 hours outage shall be considered in addition to the actual outage:Provided also that in case of outage of a transmission element affecting evacuation of power from a generating station, outage hour shall be multiplied by a factor of 2.

39. Auxiliary Energy Consumption in the sub-station.

(a)AC System The charges for auxiliary energy consumption in the AC sub-station for the purpose of air-conditioning, lighting and consumption in other equipment shall be borne by the transmission licensee and included in the normative operation and maintenance expenses.

(b)HVDC sub-station For auxiliary energy consumption in HVDC sub-stations, the Central Government may allocate an appropriate share from one or more ISGS. The charges for such power shall be borne by the transmission licensee from the normative operation and maintenance expenses.

Chapter - 9 Scheduling, Accounting and Billing

40. Scheduling.

- The methodology for scheduling and dispatch for the generating station shall be as specified in the Grid Code.

41. Metering and Accounting.

- The provisions of the Grid Code shall be applicable.

42. Billing and Payment of charges.

(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 long term transmission customers/DICs directly to the generating company or the transmission licensee, as the case may be.

(2)Payment of the capacity charge for a thermal generating station shall be shared by the beneficiaries of the generating station as per their percentage shares for the month (inclusive of any allocation out of the unallocated capacity) in the installed capacity of the generating station. Payment of capacity charge and energy charge for a hydro generating station shall be shared by the beneficiaries of the generating station in proportion to their shares (inclusive of any allocation out of the unallocated capacity) in the saleable capacity (to be determined after deducting the capacity corresponding to free energy to home State as per Note 3 herein.Note 1 - Shares / allocations of each beneficiary in the total capacity of Central sector generating stations shall be as determined by the Central Government, inclusive of any allocation made out of the unallocated capacity. The shares shall be applied in percentages of installed capacity and shall normally remain constant during a month. Based on the decision of the Central Government the changes in allocation shall be communicated by the Member-Secretary, Regional Power Committee in advance, at least three days prior to beginning of a calendar month, except in case of an emergency calling for an urgent change in allocations out of unallocated capacity. The total capacity share of a beneficiary would be sum of its capacity share plus allocation out of the unallocated portion. In the absence of any specific allocation of unallocated power by the Central 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 firm share to other States within / outside the region. In such cases, depending upon the technical feasibility of power transfer and specific agreements reached by the generating company with other States within/ outside the region for such transfers, the shares of the beneficiaries may be prospectively re-allocated by the Central Government for a specific period (in complete months) from the beginning of a calendar month. 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 State(s) 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 and its reversion shall be communicated to all concerned by the Member Secretary, Regional Power Committee in advance, at least three days prior to such reallocation or reversion taking effect.Note 3 - FEHS = Free energy for home State, in percent and shall be taken as 13% or actual whichever is less.Provided that in cases where the site of a hydro project is awarded to a developer, by the State Government by following a two stage transparent process of bidding, the 'free energy' shall be taken as 13%, in addition to energy corresponding to 100 units of electricity to be provided free of cost every month to every project affected family for a period of 10 years from the date of commercial operation of the generating station:Provided further that the generating company shall submit detailed quantification of energy corresponding to 100 units of electricity to be provided free of cost every month to every month to every project affected family for a period of 10 years from the date of commercial operation.

43. Sharing of Transmission Charges.

(1)The sharing of transmission charges shall be governed by the Sharing Regulations.

(2)The charges determined in this regulation in relation to communication system forming part of transmission system shall be shared by the beneficiaries or long term transmission customers in accordance with the Sharing Regulations:Provided that charges determined in this regulation in relation to communication system other than central transmission system shall be shared by the beneficiaries in proportion to the capital cost belonging to respective beneficiaries.

44. Rebate.

(1)For payment of bills of the generating company and the transmission licensee through letter of credit on presentation or through NEFT/RTGS within a period of 2 days of presentation of bills by the generating company or the transmission licensee, a rebate of 2% shall be allowed.

(2)Where payments are made on any day after 2 days and within a period of 30 days of presentation of bills by the generating company or the transmission licensee, a rebate of 1% shall be allowed.

45. Late payment surcharge.

- In case the payment of any bill for charges payable under these regulations is delayed by a beneficiary of long term transmission customer/DICs as the case may be, beyond a period of 60 days from the date of billing, a late payment surcharge at the rate of 1.50% per month shall be levied by the generating company or the transmission licensee, as the case may be.Chapter - 10 Miscellaneous Provisions

46. Sharing of CDM Benefits.

- The proceeds of carbon credit from approved CDM project shall be shared in the following manner, namely-

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

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

47. Norms to be ceiling norms.

- Norms specified in these regulations are the ceiling norms and shall not preclude the generating company or the transmission licensee, as the case may be, and the beneficiaries and the long-term transmission customers /DICs from agreeing to the improved norms and in case the improved norms are agreed to, such improved norms shall be applicable for determination of tariff.

48. Deviation from norms.

(1)Tariff for sale of electricity by the generating company or for transmission charges of the transmission licensee, as the case may be, may also be determined in deviation of the norms specified in these regulations subject to the conditions that :

(a)The levelised tariff over the useful life of the project on the basis of the norms in deviation does not exceed the levelised tariff calculated on the basis of the norms specified in these regulations and upon submission of complete workings with assumptions to be provided by the generator or the transmission licensee at the time of filing of the application; and

(b)Any deviation shall come into effect only after approval by the Commission, for which an application shall be made by the generating company or the transmission licensee, as the case may be.

Explanation. - For the purpose of calculating the levelised tariff referred to in sub-clause(a) of clause (1), the discounting factor shall be as notified by the Commission from time to time.

(2)The tariff of the existing generating stations of Neyveli Lignite Corporation Ltd, namely, TPS-I and TPS-II (Stage I & II) and TPS-I (Expansion) and Badarpur TPS of NTPC Ltd., whose tariff for the tariff periods 2004-09 and 2009-14 has been determined by following the Net Fixed Assets approach, shall continue to be determined by adopting Net Fixed Assets approach.

49. Deferred Tax liability with respect to previous tariff period.

- The deferred tax liability before 1.4.2009 shall be recovered from the beneficiaries or the long term transmission customers/DICs as the case may be, as and when the same gets materialised. No claim on account of deferred tax liability arising from 1.4.2009 upto 31.03.2014 shall be made from the beneficiaries or the long term transmission customers/DICs as the case may be.

49A. [ Transmission Majoration Factor. [Inserted by Notification No. L-1/144/2013-CERC, dated 30.1.2019 (w.e.f. 21.2.2014).]

- Transmission Majoration Factor admissible for the transmission projects executed through JV route in terms of Regulation 4.10A of the Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2001 shall be available for a period of 25 years from the date of issue of the transmission licence.]

50. Foreign Exchange Rate Variation.

(1)The generating company or the transmission licensee, as the case may be, may hedge foreign exchange exposure in respect of the interest on foreign currency loan and repayment of foreign loan acquired for the generating station or the transmission system, in part or in full in the discretion of the generating company or the transmission licensee.

(2)As and when the petitioner enters into any hedging based on its approved hedging policy, the petitioner should communicate to the beneficiaries concerned about its hedging decision within thirty days of entering into such hedging transaction(s).

(3)Every generating company and transmission licensee shall recover the cost of hedging of foreign exchange rate variation corresponding to the normative foreign debt, in the relevant year on year-to-year basis as expense in the period in which it arises and extra rupee liability corresponding to such foreign exchange rate variation shall not be allowed against the hedged foreign debt.

(4)To the extent the generating company or the transmission licensee is not able to hedge the foreign exchange exposure, the extra rupee liability towards interest payment and loan repayment corresponding to the normative foreign currency loan in the relevant year shall be permissible provided it is not attributable to the generating company or the transmission licensee or its suppliers or contractors.

(5)Every generating company and the transmission licensee shall recover the cost of hedging and foreign exchange rate variation on year-to-year basis as income or expense in the period in which it arises.

51. Recovery of cost of hedging or Foreign Exchange Rate Variation.

(1)Recovery of cost of hedging or foreign exchange rate variation shall be made directly by the generating company or the transmission licensee, as the case may be, from the beneficiaries or the long term transmission customers /DICs, as the case may be, without making any application before the Commission:Provided that in case of any objections by the beneficiaries or the long term transmission customers /DICs, as the case may be, to the amounts claimed on account of cost of hedging or foreign exchange rate variation, the generating company or the transmission licensee, as the case may be, may make an appropriate application before the Commission for its decision.

52. Application fee and the publication expenses.

- The following fees, charges and expenses shall be reimbursed directly by the beneficiary in the manner specified herein:

(1)The application filing fee and the expenses incurred on publication of notices in the application for approval of tariff, may in the discretion of the Commission, be allowed to be recovered by the generating company or the transmission licensee, as the case may be, directly from the beneficiaries or the long term transmission customers/DICs, as the case may be;

(2)The following fees and charges shall be reimbursed directly by the beneficiaries in proportion of their allocation in the generating stations or by the long term transmission customers /DICs in proportion to their share in the inter-State transmission systems determined in accordance with the Central Electricity Regulatory Commission (Sharing of inter-State Transmission Charges and Losses) Regulations, 2010, as amended from time to time;

(a)Fees and charges paid by the generating companies and inter-State transmission licensees (including deemed inter-State transmission licensee) under the Central Electricity Regulatory Commission (Fees and Charges of Regional Load Despatch Centre and other related matters) Regulations, 2009, as amended from time to time or any subsequent amendment thereof;

(b)Licence fees paid by the inter-State transmission licensees (including the deemed inter-State transmission licensee) in terms of Central Electricity Regulatory Commission (Payment of Fees) Regulations, 2012 or any subsequent amendment or re-enactment thereof;

(c)Licence fees paid by NHPC Ltd to the State Water Resources Development Authority, Jammu in accordance with the provisions of Jammu & Kashmir Water Resources (Regulations and Management) Act, 2010;

(3)The Commission may, for the reasons to be recorded in writing and after hearing the affected parties, allow reimbursement of any fee or expenses, as may be considered necessary.

53. Special Provisions relating to Damodar Valley Corporation.

(1)Subject to clause (2), this regulation shall apply to determination of tariff of the projects owned by Damodar Valley Corporation (DVC).

(2)The following special provisions shall apply for determination of tariff of the projects owned by DVC:

(i)Capital Cost: The expenditure allocated to the object 'power', in terms of sections 32 and 33 of the Damodar Valley Corporation Act, 1948, to the extent of its apportionment to generation and inter-state transmission, shall form the basis of capital cost for the purpose of determination of tariff:

Provided that the capital expenditure incurred on head office, regional offices, administrative and technical centers of DVC, after due prudence check, shall also form part of the capital cost.

(ii)Debt Equity Ratio: The debt equity ratio of all projects of DVC commissioned prior to 01.01.1992 shall be 50:50 and that of the projects commissioned thereafter shall be 70:30.

(iii)Depreciation: The depreciation rate stipulated by the Comptroller and Auditor General of India in terms of section 40 of the Damodar Valley Corporation Act, 1948 shall be applied for computation of depreciation of projects of DVC.

(iv)Funds under section 40 of the Damodar Valley Corporation Act, 1948: The Fund(s) established in terms of section 40 of the Damodar Valley Corporation Act, 1948 shall be considered as items of expenditure to be recovered through tariff.

(3)The provisions in clause (2) of this regulation shall be subject to the decision of the Hon'ble Supreme Court in Civil Appeal No 4289 of 2008 and other related appeals pending in the Hon'ble Court and shall stand modified to the extent they are inconsistent with the decision.

54. Power to Relax.

- The Commission, for reasons to be recorded in writing, may relax any of the provisions of these regulations on its own motion or on an application made before it by an interested person.

55. Power to Remove Difficulty.

- If any difficulty arises in giving effect to the provisions of these regulations, the Commission may, by order, make such provision not inconsistent with the provisions of the Act or provisions of other regulations specified by the Commission, as may appear to be necessary for removing the difficulty in giving effect to the objectives of these regulations.Appendix-ITimeline for completion of Projects(Refer to Regulation 24)

1. The completion time schedule shall be reckoned from the date of investment approval by the Board (of the generating company or the transmission licensee), or the CCEA clearance as the case may be, up to the date of commercial operation of the units or block or element of transmission project as applicable.

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

A. Thermal Power ProjectsCoal/Lignite Power PlantUnit size 200/210/250/300/330 MW and 125 MW CFBC technology

(a)33 months for green field projects. Subsequent units at an interval of 4 months each.

(b)31 months for extension projects. Subsequent units at an interval of 4 months each.

Unit size 250 MW CFBC technology

(a)36 months for green field projects. Subsequent units at an interval of 4 months each.

(b)34 months for extension projects. Subsequent units at an interval of 4 months each.

Unit size 500/600 MW

(a)44 months for green field projects. Subsequent units at an interval of 6 months each.

(b)42 months for extension projects. Subsequent units at an interval of 6 months each.

Unit size 660/800 MW

(a)52 months for green field projects. Subsequent units at an interval of 6 months each.

(b)50 months for extension projects. Subsequent units at an interval of 6 months each.

Combined Cycle Power PlantGas Turbine size upto 100 MW (ISO rating)

(a)26 months for first block of green field projects. Subsequent blocks at an interval of 2 months each.

(b)24 months for first block of extension projects. Subsequent units at an interval of 2 months each.

Gas Turbine size above 100 MW (ISO rating)

(a)30 months for first block of green field projects. Subsequent blocks at an interval of 4 months each.

(b)28 months for first block of extension projects. Subsequent units at an interval of 4 months each.

B. Hydro Electric ProjectsThe qualifying time schedule for hydro electric projects shall be as stated in the original concurrence issued by the Central Electricity Authority under section 8 of the Act.C. Transmission SchemesQualifying time schedules in months

Sr. No.	Transmission Work	Plain Area (months)	Hilly Terrain (months)	Snowbound area/ @very difficult Terrain(months)
a	765 kV S/C Transmission line	36	42	46
b	765 kV D/C Transmission line	40	46	50
c	+/-500 KV HVDC Transmission line	30	36	40
d	400 KV M/C Quad or more sub-conductor Transmission line	40	46	50
e	400 KV M/C Twin/Triple Transmission line	38	44	48
f	400 KV D/C Quad Transmission line	38	44	48
g	400 KV D/C Triple Transmission line	36	42	46
h	400 KV D/C Twin Transmission line	34	40	44
i	400 KV S/C Six or more sub-conductor Transmission line	36	42	46
j	400 KV S/C Twin Transmission line	30	36	40
k	220 KV D/C Twin Transmission line	34	40	44
l	220 KV D/C Transmission line	30	36	40
m	220 KV S/C Transmission line	26	32	36
n	New 220 KV AC Sub-Station	24	27	30
o	New 400 KV AC Sub-Station	30	33	36
p	New 765 kV AC Sub-Station	36	40	$
q	*HVDC bi-pole terminal	42	44	-
r	HVDC back-to-back	32	34	-
@ e.g. Leh, Laddakh
$ No 765 kV sub-station has been planned in difficult terrain
* Includes +800 kV HVDC bi-pole terminal

Notes: - (i) In case a scheme having combination of the above mentioned types of projects, the qualifying time schedule of the activity having maximum time period shall be considered for the scheme as a whole.

(ii)In case a transmission line falls in plain as well as in hilly terrain/snow bound area/very difficult terrain, the composite qualifying time schedule shall be calculated giving proportional weightage to the line length falling in each area.

Appendix-IIDepreciation Schedule

Sr. No.	Asset Particulars	Depreciation Rate(Salvage Value=10%)
		SLM
A	Land under full ownership	0.00%
B	Land under lease
(a)	for investment in the land	3.34%
(b)	For cost of clearing the site	3.34%
(c)	Land for reservoir in case of hydro generating station	3.34%
C	Assets purchased new
a.	P1 & Machinery in generating stations
(i)	Hydro electric	5.28%
(ii)	Steam electric NHRB & waste heat recovery boilers	5.28%
(iii)	Diesel electric and gas plant	5.28%
b.	Cooling towers & circulating water systems	5.28%
c.	Hydraulic works forming part of the Hydro-generating stations
(i)	Dams, Spillways, Weirs, Canals, Reinforced concrete flumes andsiphons	5.28%
(ii)	Reinforced concrete pipelines and surge tanks, steelpipelines, sluice gates, steel surge tanks, hydraulic controlvalves and hydraulic works	5.28%
d.	Building & Civil Engineering works
(i)	Offices and showrooms	3.34%
(ii)	Containing thermo-electric generating plant	3.34%
(iii)	Containing hydro-electric generating plant	3.34%
(iv)	Temporary erections such as wooden structures	100.00%
(v)	Roads other than Kutcha roads	3.34%
(vi)	Others	3.34%
e.	Transformers, Kiosk, sub-station equipment & other fixedapparatus (including plant
(i)	Transformers including foundations having rating of 100 KVAand over	5.28%
(ii)	Others	5.28%
f.	Switchgear including cable connections	5.28%
g.	Lightning arrestor
(i)	Station type	5.28%
(ii)	Pole type	5.28%
(iii)	Synchronous condenser	5.28%
h.	Batteries	5.28%
(i)	Underground cable including joint boxes and disconnected boxes	5.28%
(ii)	Cable duct system	5.28%
i.	Overhead lines including cable support
(i)	Lines on fabricated steel operating at terminal voltageshigher than 66 KV	5.28%
(ii)	Lines on steel supports operating at terminal voltages higherthan 13.2 KV but not exceeding 66 KV	5.28%
(iii)	Lines on steel on reinforced concrete support	5.28%
(iv)	Lines on treated wood support	5.28%
j.	Meters	5.28%
k.	Self propelled vehicles	9.50%
l.	Air Conditioning Plants
(i)	Static	5.28%
(ii)	Portable	9.50%
m.(i)	Office furniture and furnishing	6.33%
(ii)	Office equipment	6.33%
(iii)	Internal wiring including fittings and apparatus	6.33%
(iv)	Street Light fiitings	5.28%
n.	Apparatus let on hire
(i)	Other than motors	9.50%
(ii)	Motors	6.33%
o.	Communication equipment
(i)	Radio and high frequency carrier system	6.33%
(ii)	Telephone lines and telephones	6.33%
p.	I.T. Equipment including software	15.00%
q.	Any other assets not covered above	5.28%

Appendix-IIIProcedure for Calculation of Transmission System Availability Factor for a Month

1. Transmission system availability factor for a calendar month (TAFM) shall be calculated by the respective transmission licensee, got verified by the concerned RLDC and certified by the Member-Secretary, Regional Power Committee of the region concerned, separately for each AC and HVDC transmission system and grouped according to sharing of transmission charges. Transmission System Availability shall be calculated separately for each Regional Transmission System and inter-regional transmission system. For the purpose of calculation of TAFM:

(i)AC transmission lines: Each circuit of AC transmission line shall be considered as one element.

(ii)Inter-Connecting Transformers (ICTs): Each ICT bank (three single phase transformer together) shall form one element.

(iii)Static VAR Compensator (SVC): SVC along with SVC transformer shall form one element. However, 50% credit to inductive and 50% to capacitive rating shall be given.

(iv)Bus Reactors/Switchable line reactors: Each Bus Reactors/Switchable line reactors shall be considered as one element.

(v)HVDC Bi-pole links: Each pole of HVDC link along with associated equipment at both ends shall be considered as one element.

(vi)HVDC back-to-back station: Each block of HVDC back-to-back station shall be considered as one element. If associated AC line (necessary for transfer of interregional power through HVDC back-to-back station) is not available, the HVDC back-to-back station block shall also be considered as unavailable.

2. The Availability of AC and HVDC portion of Transmission system shall be calculated as under:

% TAFM for AC system =| o X AVo + p X AVp + q X AVq + r X AVro + p + q + r| x 100

% TAFM for HVDC system =| s X AVs + t X AVtS + t| x 100

Whereo = Total number of AC lines.AVo = Availability of o number of AC lines.p = Total number of bus reactors/switchable line reactorsAVp = Availability of p number of bus reactors/switchable line reactorsq = Total number of ICTs.AVq = Availability of q number of ICTs.r = Total number of SVCs.AVr = Availability of r number of SVCs.s = Total number of HVDC polesAVs = Availability of s number of HVDC polest = Total number of HVDC back-to-back station blocksAVt = Availability of t number of HVDC back-to-back station blocks

3. The weightage factor for each category of transmission elements shall be as under:

(a)For each circuit of AC line - Surge Impedance Loading for Uncompensated line (SIL) multiplied by ckt-km.

SIL rating for various voltage level and conductor configuration is given in Appendix-IV. However, for the voltage levels and/or conductor configurations not listed in Annexure-I, appropriate SIL based on technical considerations may be used for availability calculation under intimation to long-term transmission customers/DICs.For compensated AC line, Surge Impedance Loading (SIL) shall be as certified by the Regional Power Committee (RPC) Secretariat considering the compensation on the line.For shunt compensated line the reduced value of SIL shall be taken in accordance with the location of the reactor. Similarly in case of the lines with series compensation the higher SIL shall be taken as per the percentage of compensation.

(b)For each HVDC pole - The rated MW capacity x ckt-km

(c)For each ICT bank - The rated MVA capacity

(d)For SVC - The rated MVAR capacity (inductive and capacitive)

(e)For Bus Reactor/switchable line reactors - The rated MVAR capacity.

(f)For HVDC back-to-back station connecting two Regional grids - Rated MW capacity of each block.

4. The availability for each category of transmission elements shall be calculated based on the weightage factor, total hours under consideration and non-available hours for each element of that category. The formulae for calculation of Availability of each category of the transmission elements are as per Appendix-V.

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

(i)Shut down availed for maintenance or construction of elements of another transmission scheme. If the other transmission scheme belongs to the transmission licensee, the Member-Secretary, RPC may restrict the deemed availability period to that considered reasonable by him for the work involved.

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

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

(i)Outage of elements due to acts of God and force majeure events beyond the control of the transmission licensee. However, onus of satisfying the Member Secretary, RPC that element outage was due to aforesaid events and not due to design failure shall rest with the transmission licensee. A reasonable restoration time for the element shall be considered in accordance with Central Electricity Regulatory Commission (Standard of Performance of inter-State transmission licensees) Regulations, 2012 as amended from time to time and any additional time taken by the transmission licensee for restoration of the element beyond the reasonable time shall be treated as outage time attributable to the transmission licensee. Circuits restored through ERS (Emergency Restoration System) shall be considered as available.

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

Appendix-IVSurge Impedance Loading (SIL) of AC Lines

S.No.	Line voltage(kV)	Conductor Configuration	SIL(MW)
1	765	Quad Bersimis	2250
2	400	Quad Bersimis	691
3	400	Twin Moose	515
4	400	Twin AAAC	425
5	400	Quad Zebra	647
6	400	Quad AAAC	646
7	400	Tripple Snowbird	605
8	400	ACKC(500/26)	556
9	400	Twin ACAR	557
10	220	Twin Zebra	175
11	220	Single Zebra	132
12	132	Single Panther	50
13	66	Single Dog	10

Appendix-VFormulae for Calculation of Availability of Each Category of Transmission Elements

AVo (Availability of o no. of AC lines) =	{\|
o o\|-	∑\| Wi (Ti - TNAi)Ti\| /\| ∑\| Wi\|-	i=1 i=1

AVs (Availability of s no. of HVDC pole) =	{\|
s s\|-	∑\| Wj (Tj - TNAj)Tj\| /\| ∑\| Wj\|-	j=1 j=1

AVq (Availability of q no. of ICTs) =	{\|
q q\|-	∑\| Wk (Tk - TNAk)Tk\| /\| ∑\| Wk\|-	k=1 k=1

AVr (Availability of r no. of SVCs) =	{\|
[	{\|
r r\|-	∑\| 0.5WIl (TIl - TNAl)TIl\| +∑\| Wcl (Tcl - Wcl)TCl\|-	l=1 l=1

| ]/[|

r r|-

∑| 0.5WIl| +∑| Wcl|-

l=1 l=1

| ]|}|}

AVp (Availability of p no. of Switched Bus reactors) =	{\|
p p\|-	∑\| Wm (Tm - TNAm)Tm\| /\| ∑\| Wm\|-	m=1 m=1

AVt (Availability of t no. of HVDC Back-to-back Blocks) =	{\|
t t\|-	∑\| Wn (Tn - TNAn)Tn\| /\| ∑\| Wn\|-	n=1 n=1

|}Where

Wi	=	Weightage factor for ithtransmission line
Wj	=	Weightage factor for jthHVDC pole
Wk	=	Weightage factor for kthICT
WIl & WCl	=	Weightage factors for inductive & capacitive operation oflthSVC
Wm	=	Weightage factor for mthbus reactor
Wn	=	Weightage factor for nthHVDC back to back block.
Ti, Tj, Tk, TIl, TCl, Tm & Tn	=	The total hours of ith AC line, jthHVDC pole, kthICT, lthSVC (InductiveOperation), lthSVC (Capacitive Operation), mthSwitched Bus Reactor & nthHVDC back-to-back blockduring the period under consideration (excluding time period foroutages not attributable to transmission licensee for reasonsgiven in Para 6 of the procedure)
TNAi ,TNAj , TNAk TNAIl,TNACl, TNAm, TNAn	=	The non-availability hours (excluding the timeperiod for outages not attributable to transmission licenseetaken as deemed availability as per Para 5 of the procedure) forithAC line, , jthHVDC pole, kthICT, lthSVC (Inductive Operation), lthSVC(Capacitive Operation), mthSwitched Bus Reactor andnthHVDC back-to-back block.

Appendix - VI(For Coal based Generating Stations)It is to certify that the (Name of the Station) has fulfilled all the key provisions as prescribed below in accordance with Regulation 4 of CERC (Terms and Conditions of Tariff), Regulations, 2014.

1. All documents as prescribed in Regulation 3(8) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations - 2010 have been retained at site and are available at site.

2. All requirements as per Regulation 5 of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations - 2010 have been complied.

3. The unit operating capability shall be in conformity to Regulation 7(1), 7(2), 7(3) and 7(4) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations, 2010.

4. All requirements as per Regulation 8 of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations 2010 have been complied for the Steam Generator.

5. All requirements as per Regulation 9(2), 9(4), 9(9), 9(15), 9(16), 9(18) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations 2010 have been complied for the Steam Turbine Generator.

Name:(CMD/CEO/MD)(For Gas based Generating Stations)It is to certify that the (Name of the Station) has fulfilled all the key provisions as prescribed below in accordance with Regulation 4 of CERC (Terms and Conditions of Tariff), Regulations, 2014.

1. All documents as prescribed in Regulation 3(8) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations, 2010 have been retained at site and are available at site.

2. All requirements as per Regulation 5 of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations, 2010 have been complied.

3. The unit operating capability shall be in conformity to Regulation 14 (2), 14(3), 14(4), 14(5) and 14(7) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations, 2010.

4. All requirements as per Regulation 17 and Regulations 9(2), 9(4), 9(9), 9(15), 9(16), 9(18) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations 2010 have been complied for the Steam Turbine.

Name:(CMD/CEO/MD)(For Hydro based Generating Stations)It is to certify that the (Name of the Station) has fulfilled all the key provisions as prescribed below in accordance with Regulation 4 of CERC (Terms and Conditions of Tariff), Regulations, 2014.

1. All documents as prescribed in Regulation 3(8) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations - 2010 have been retained at site and are available at site.

2. All requirements as per Regulation 30(1), 30(2) and 30(5) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations, 2010 have been complied.

3. The unit operating capability shall be in conformity to Regulation 32 (1), 32(3), 32(4), 32(6) and 32(8) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations, 2010.

4. All requirements as per Regulation 33(6), 33(7), 33(8) of the CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations 2010 have been complied for the hydraulic Turbine.

Name:(CMD/CEO/MD)Tariff Filing Forms (Thermal) for Determination of TariffPart-I Annexure-IForm-1Summary SheetName of the Petitioner _________________________Name of the Generating Station : ________________Place (Region/District/State):

Sr. No.	Particulars	Unit	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	2		3	4	5	6	7	8
1.1	Depreciation	Rs Lakh
1.2	Interest on Loan	Rs Lakh
1.3	Return on Equity1	Rs Lakh
1.4	Interest on Working Capital	Rs Lakh
1.5	O & M Expenses	Rs Lakh
1.7	Compensation Allowance (If applicable)	Rs Lakh
1.8	Special allowance (If applicable)	Rs Lakh
	Total	Rs Lakh
2.1	Landed Fuel Cost (Domestic : coal/ gas / RLNG/ liquid)	Rs/Tone
	(%) of Fuel Quantity	(%)
2.2	Landed Fuel Cost (Imported Coal)	Rs/Tone
	(%) of Fuel Quantity	(%)
2.3	Secondary fuel oil cost	Rs/Unit
	Energy Charge Rate ex-bus (Paise/ kWh)2A, 2B, 2C, 2D	Rs/Unit

Note - 1: Details of calculations, considering equity as per regulation, to be furnished.

2A.

: If multifuel is used simultaneously, give 2 in respect of every fuel individually.

2B.

: The rate of energy charge shall be computed for open cycle operation and combined cycle operation separately in case of gas/liquid fuel fired plants.

2C.

: The total energy charge shall be worked out based on ex-bus energy scheduled to be sent out.

2D.

: The Energy Charge rate for the month shall be based on fuel cost(s) and GCV(s) for the month as per Regulation 30 (6).Form-1(I) - Statement showing claimed capital cost:

Sl. No.	Particulars	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)
	Opening Capital Cost
	Add: Addition during the year / period
	Less: Decapitalisation during the year / period
	Less: Reversal during the year / period
	Add: Discharges during the year / period
	Closing Capital Cost
	Average Capital Cost

Form-1(II) - Statement showing Return on Equity:

Sl. No.	Particulars	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)
	Opening Equity
	Add: Increase due to addition during the year / period
	Less: Decrease due to de-capitalisation during the year /period
	Less: Decrease due to reversal during the year / period
	Add: Increase due to discharges during the year / period
	Closing Equity
	Average Equity
	Rate of ROE
	Return on Equity

(Petitioner)Form-2

Plant Characteristics

Name of the Petitioner
Name of the Generating Station
Unit(s)/Block(s)/Parameters	Unit-I	Unit-II	Unit-III	....
Installed Capacity (MW)
Schedule COD as per Investment Approval
Actual COD /Date of Taken Over (as applicable)
Pit Head or Non Pit Head
Name of the Boiler Manufacture
Name of Turbine Generator Manufacture
[Main Steams Pressure at Turbine inlet (kg/Cm2)abs.] [At Turbine MCR condition.]
[Main Steam Temperature at Turbine inlet (°C)] [At Turbine MCR condition.]
[Reheat Steam Pressure at Turbine inlet (kg/Cm2)] [At Turbine MCR condition.]
[Reheat Steam Temperature at Turbine inlet (°C)] [At Turbine MCR condition.]
[Main Steam flow at Turbine inlet under MCR condition (tons/hr)] [with 0% (Nil) make up and design Cooling water temperature]
[Main Steam flow at Turbine inlet under VWO condition (tons/hr)] [with 0% (Nil) make up and design Cooling water temperature]
[Unit Gross electrical output under MCR /Rated condition(MW)] [with 0% (Nil) make up and design Cooling water temperature]
[Unit Gross electrical output under VWO condition (MW)] [with 0% (Nil) make up and design Cooling water temperature]
[Guaranteed Design Gross Turbine Cycle Heat Rate (kCal/kWh)] [at TMCR output based on gross generation, 0% (Nil) makeup and design Cooling water temperature.]
Conditions on which design turbine cycle heat rateguaranteed
% MCR
% Makeup Water Consumption
Design Capacity of Make up Water System
Design Capacity of Inlet Cooling System
Design Cooling Water Temperature (°C)
Back Pressure
Steam flow at super heater outlet under BMCR condition(tons/hr)
Steam Pressure at super heater outlet under BMCR condition)(kg/Cm2)
Steam Temperature at super heater outlet under BMCR condition(°C)
Steam Temperature at Reheater outlet at BMCR condition (°C)
[Design / Guaranteed Boiler Efficiency (%)] [With Performance coal based on Higher Heating Value (HHV) of fuel and at BMCR) out put]
Design Fuel with and without Blending of domestic/importedcoal.
Type of Cooling Tower
[Type of cooling system] [Closed circuit cooling, once through cooling, sea cooling, natural draft cooling, induced draft cooling etc.]
[Type of Boiler Feed Pump] [Motor driven, Steam turbine driven etc.]
[Fuel Details] [Coal or natural gas or Naptha or lignite etc.]
-Primary Fuel
-Secondary Fuel
-Alternate Fuels
[Special Features/Site Specific Features] [Any site specific feature such as Merry-Go-Round, Vicinity to sea, Intake /makeup water systems etc. scrubbers etc. Specify all such features]
[Special Technological Features] [Any Special Technological feature like Advanced class FA technology in Gas Turbines, etc.]
[Environmental Regulation related features] [Environmental Regulation related features like FGD, ESP etc.,]
Any other special features

Note 1: In case of deviation from specified conditions in Regulation, correction curve of manufacturer may also be submitted.Note 2: Heat Balance Diagram has to be submitted along with above information in case of new stations.Note 3: The Terms - MCR, BMCR, HHV, Performance coal, are as defined in CEA Technical Standards for Construction of Electric Plants and Electric Lines Regulations - 2010 notified by the Central Electricity Authority.Note 4: The copy of Certificate shall be submitted in terms of Regulation 4 as per Appendix-VI

(Petitioner)Form-3

Normative parameters considered for tariff computationsName of the Petitioner _______________________Name of the Generating Station ________________Year Ending March

Particulars	Unit	Existing2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
Base Rate of Return on Equity	%
[Effective Tax Rate] [Effective tax rate is to be computed in accordance with Regulation 25 i.e. actual tax (or advance tax)/gross income, where gross income refers the profit before tax.]	%
Target Availability	%
Auxiliary Energy Consumption	%
Gross Station Heat Rate	kCal/kWh
Specific Fuel Oil Consumption	ml/kWh
[Cost of Coal/Lignite for WC] [For Coal based/lignite based generating stations]	in Months
[Cost of Main Secondary Fuel Oil for WC] [For Coal based/lignite based generating stations]	in Months
[Fuel Cost for WC] [For Gas Turbine/Combined Cycle generating stations duly taking into account the mode of operation on gas fuel and liquid fuel]	in Months
[Liquid Fuel Stock for WC] [For Gas Turbine/Combined Cycle generating stations duly taking into account the mode of operation on gas fuel and liquid fuel]	in Months
O & M expenses	Rs lakh / MW
Maintenance Spares for WC	% of O&M
Receivables for WC	in Months
Storage capacity of Primary fuel	MT
SBI Base Rate + 350 basis points as on[_____________] [Mention relevant date]	%
Blending ratio of domestic coal/imported coal

(Petitioner)Form-4

Details of Foreign loans(Details only in respect of loans applicable to the project under petition)Name of the Petitioner _________________________________________Name of the Generating Station __________________________________Exchange Rate at COD or 31.03.2004, whichever is later _______________Exchange Rate as on 31.3.2014 __________________________________

Sl.	Financial Year (Starting from COD)	Year 1
	1	2	3	4	5
		Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount (Rs. Lakh)
	[Currency 1] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of Drawl or at the beginning to the year of theperiod] [In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given]
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	[In case of Hedging] [Furnish details of hedging, in case of more than one hedging during the year or part hedging, details of each hedging are to be given]
1	At the date of hedging
2	Period of hedging
3	Cost of hedging
	[Currency 2] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of Drawl] [In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given]
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	[In case of Hedging] [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]
1	At the date of hedging
2	Period of hedging
3	Cost of hedging
	[Currency 3] [Name of the currency to be mentioned e.g. US$, DM, etc.]& so on
A.1	[At the date of Drawl] [In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given]
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	[In case of Hedging] [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]
1	At the date of hedging
2	Period of hedging
3	Cost of hedging

Year 2	Year 3 and so on
6	7	8	9	10	11	12	13
Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount (Rs. Lakh)	Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount(Rs. Lakh)

Note: Tax (such as withholding tax) details as applicable including change in rates, date from which change effective etc. must be clearly indicated.

(Petitioner)Form-4A

Details of Foreign Equity(Details only in respect of Equity infusion if any applicable to the project under petition)Name of the Petitioner _____________________________Name of the Generating Station ______________________Exchange Rate on date/s of infusion ___________________

Sl.	Financial Year	Year 1
	1	2	3	4	5
		Date	Amount (Foreign Currency)	Exchange Rate	Amount (Rs. Lakh)
	[Currency 1] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3
	[Currency 2] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3
	[Currency 3] [Name of the currency to be mentioned e.g. US$, DM, etc.]& so on
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3

Year 2	Year 3 and so on
6	7	8	9	10	11	12	13
Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount (Rs. Lakh)	Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount(Rs. Lakh)

(Petitioner)Form-5

Abstract of Admitted Capital Cost for the existing ProjectsName of the Company _____________________Name of the Power Station __________________

Last date of order of Commission for the project	Date (DD-MM-YYYY)
Reference of petition no. in which the above order was passed	Petition no.
Following details (whether admitted and /or considered) as onthe last date of the period for which tariff is approved, in theabove order by the Commission:
Capital cost	(Rs. in lakh)*
Amount of un-discharged liabilities included in above (&forming part of admitted capital cost)
Amount of un-discharged liabilities corresponding to aboveadmitted capital cost (but not forming part of admitted capitalcost being allowed on cash basis)
Gross Normative Debt
Cumulative Repayment
Net Normative Debt
Normative Equity
Cumulative Depreciation
Freehold land

(Petitioner)Form-5A

Abstract of Capital Cost Estimates and Schedule of Commissioning for the New ProjectsName of the Petitioner ______________________Name of the Generating Station ______________New ProjectsCapital Cost Estimates

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 on 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,IEDC& FC
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. Lakh)

Capital cost excluding IDC, IEDC, FC, FERV & HedgingCost (Rs. Cr)

IDC, IEDC,FC, FERV & Hedging Cost
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. Lakh)

Total IDC, IEDC, FC, FERV & Hedging Cost(Rs. Lakh)
Rate of taxes & duties considered

Capital cost Including IDC, IEDC, FC, FERV &Hedging Cost
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. Lakh)

Capital cost Including IDC, IEDC& FC (Rs. Lakh)

Schedule of Commissioning
Scheduled COD of Unit-I/Block-I as per Investment Approval
Scheduled COD of Unit-II/Block-II as per Investment Approval
---------------------------
---------------------------
Scheduled COD of last Unit/Block

Note: - 1. Copy of Investment approval letter should be enclosed.

2. Details of Capital Cost are to be furnished as per Form-5B or 5C as applicable.

3. Details of IDC & Financing Charges are to be furnished as per Form-14.

(Petitioner)Form-5B

Break-up of Capital Cost for New Coal/Lignite based projectsName of the Petitioner ________________________Name of the Generating Station _________________(Amount in Rs. Lakh)

Sl. No.	Break Down	As per Original Estimates as per InvestmentApproval	Actual Capital Expenditure as onCOD/anticipated COD	Liabilities/ Provisions	Variation (3-4-5)	Specific Reasons for Variation	Estimated Capital expenditure upto Cut-offdate
Actual Amount
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
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
2.3.15	FGD system, if any
2.3.16	De-salination plant for sea-water intake
2.3.17	External coal handling in Jetty, if any
	Total BOP Mechanical
2.4	BOP Electrical
2.4.1	Switch Yard Package
2.4.2	Transformers Package
2.4.3	Switch gear Package
2.4.4	Cables, Cable facilities & grounding
2.4.5	Lighting
2.4.6	Emergency D.G. set
	Total BOP Electrical
2.5	Control & Instrumentation (C & I) Package
	Total Plant & Equipment excluding taxes & Duties
2.6	Taxes & Duties

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
4.10	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	Total 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 Coat
	Total of IDC, FC,FERV & Hedging Cost
9	Capital cost including IDC, FC, FERV & Hedging Cost

*Provide details of Freehold land and Lease hold land separatelyNote: - 1. In case of cost variation, a detailed note giving reasons of such variation should be submitted clearly indicating whether such cost over-run was beyond the control of the generating company.

2. In case of both time & cost overrun, 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 and cost overrun was beyond the control of the generating company.

3. The implication on cost due to time over run, if any shall be submitted separately giving details of increase in prices in different packages from scheduled COD to Actual COD/anticipated COD, increase in IEDC from scheduled COD to actual COD/anticipated COD and increase of IDC from scheduled COD to actual anticipated COD.

4. Impact on account of each reason for Time over run on Cost of project should be quantified and substantiated with necessary documents and supporting workings.

5. A list of balance work assets/work wise including initial spare on original scope of works along with estimate shall be furnished positively.

(Petitioner)Form-5C

Break-up of Capital Cost for Gas/Liquid fuel based projectsName of the Petitioner _______________________Name of the Generating Station ________________(Amount in Rs. Lakh)

Sl. No.	Break Down	As per Original Estimates as per InvestmentApproval	Actual Capital Expenditure	Liabilities/ Provisions	Variation (3-4-5)	Specific Reasons for Variation*	Actual/Estimated Capital Expenditure uptoCut-off date
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
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	WHRB Island
2.4	BOP Mechanical
2.4.1	Fuel Handling & Storage system
2.4.2	External water supply system
2.4.3	CW system
2.4.4	Cooling Towers
2.4.5	DM water Plant
2.4.6	Clarification plant
2.4.7	Chlorination Plant
2.4.8	Air Condition & Ventilation System
2.4.9	Fire fighting System
2.4.10	HP/LP Piping
	Total BOP Mechanical

2.5	BOP Electrical
2.5.1	Switch Yard Package
2.5.2	Transformers Package
2.5.3	Switch gear Package
2.5.4	Cables, Cable facilities & grounding
2.5.5	Lighting
2.5.6	Emergency D.G. set
	Total BOP Electrical

2.6	Control & Instrumentation (C & I) Package
	Total Plant & Equipment excluding taxes & Duties
2.7	Taxes & Duties

3	Initial Spares

4	Civil Works
4.1	Main plant/Adm. Building
4.2	External Water Supply System
4.3	CW system
4.4	Cooling Towers
4.5	DM water Plant
4.6	Clarification plant
4.7	Fuel handling & Storage system
4.8	Township & Colony
4.9	Temp. construction & enabling works
4.10	Road & Drainage
4.11	Fire fighting System
	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 Coat
	Total of IDC, FC,FERV & Hedging Cost

9	Capital cost including IDC, FC, FERV & Hedging Cost

* Provide details of Freehold land and Lease hold land separatelyNote: - 1. In case of cost variation , a detailed note giving reasons of such variation should be submitted clearly indicating whether such cost over-run was beyond the control of the generating company.

2. In case of time & cost overrun, 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 and cost overrun was beyond the control of the generating company.

3. The implication on cost due to time over run, if any shall be submitted separately giving details of increase in prices in different packages from scheduled COD to Actual COD/anticipated COD, increase in IEDC from scheduled COD to actual COD/anticipated COD and increase of IDC from scheduled COD to actual anticipated COD.

4. Impact on account of each reason for Time over run on Cost of project should be quantified and substantiated with necessary documents and supporting workings.

A list of balance work assets/work wise including initial spare on original scope of works along with estimate shall be furnished positively

(Petitioner)Form-5D

Break-up of Construction/Supply/Service packagesName of the Petitioner ______________________Name of the Generating Station ______________

1	Name/No. of Construction / Supply / Service Package	Package A	Package B	Package C	...	Total Cost of all packages
2	[Scope of works] [The scope of work in any package should be indicated in conformity of Capital cost break-up for the coal/lignite based plants in the Form-5B to the extent possible. In case of Gas/Liquid fuel based projects, break down in the similar manner in the relevant heads as per Form-5C.](in line with head of cost break-ups asapplicable)
3	Whether awarded through ICB/DCB/ Departmentally/ Deposit Work
4	No. of bids received
5	Date of Award
6	Date of Start of work
7	Date of Completion of Work/Expected date of completion of work
8	[Value of Award] [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, the exchange rate and the date e.g. Rs.80 Cr. +US$50m=Rs.390Cr. at US$=Rs62 as on say 01.04.14.]in (Rs. Lakh)
9	Firm or With Escalation in prices
10	Actual capital expenditure till the completion or up to CODwhichever is earlier (Rs.Lakh)
11	Taxes & Duties and IEDC (Rs. Lakh)
12	IDC, FC, FERV & Hedging cost (Rs. Lakh)
13	Sub-total (10+11+12) (Rs. Lakh)

(Petitioner)Form-5E

Details of variables, parameters, optional package etc. for New ProjectName of the Petitioner ______________________Name of the Generating Station _______________

Unit Size
Number of Units
Greenfield/Extension
S. No.	Variables	(Design Operating Range) Values
1	Coal Quality – Calorific Value
2	Ash Content
3	Moisture Content
4	Boiler Efficiency
5	Suspended Particulate Matter
6	Ash Utilization
7	Boiler Configuration
8	Turbine Heat Rate
9	CW Temperature
10	Water Source
11	Distance of Water Source
12	Clarifier
13	Mode of Unloading Oil
14	Coal Unholding Mechanism
15	Type of Fly Ash Disposal and Distance
16	Type of Bottom Ash Disposal and Distance
17	Type of Soil
18	Foundation Type (Chimney)
19	Water Table
20	Seismic and Wind Zone
21	Condensate Cooling Method
22	Desalination/RO Plant
23	Evacuation Voltage Level
24	Type of Coal (Domestic/Imported)
Parameter/Variables	Values
Completion Schedule
Terms of Payment
Performance Guarantee Liability
Basis of Price (Firm/Escalation-Linked)
Equipment Supplier (Country of Origin)
Optional Packages	Yes/No
Desalination Plant/RO Plant
MGR
Railway Siding
Unloading Equipment at Jetty
Rolling Stock/Locomotive
FGD Plant
Length of Transmission Line till Tie Point (in km)

(Petitioner)Form-5E(i)

In case there is cost over runName of the Petitioner ___________________Name of the Generating Station ____________

Sl. No.	Break Down	Original Cost (Rs.Lakh) as approved by the Board of Members	Actual/ EstimatedCost as incurred/to be incurred (Rs. Lakh)	Difference	Reasons forVariation (Please submit supporting computations and documentswherever applicable)	Increase in softcost due to increase in hard cost
		Total Cost	Total Cost	Total Cost
1	Cost of Land & Site Development
1.1	Land*
1.2	Rehabilitation & Resettlement (R&R)
1.3	Preliminary Investigation & Site Development

2	Plant & Equipment
2.1	Steam Generator Island
2.2	Turbine Generator Island
2.3	BOP Mechanical
2.3.1	Fuel Handling & Storage system
2.3.2	External water supply 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	Switch gear Package
2.4.4	Cables, Cable facilities & grounding
2.4.5	Lighting
2.4.6	Emergency D.G. set
	Total BOP Electrical

2.5	Control & Instrumentation (C & I) Package
	Total Plant & Equipment excluding taxes & Duties
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
4.10	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

* Submit details of Freehold and Lease hold land.Note: - Impact on account of each reason for Cost overrun should be quantified and substantiated with necessary documents and supporting workings.

(Petitioner)Form-5E(ii)

In case there is time over runName of the Petitioner ____________________Name of the Generating Station _____________

Sr. No.	Description of Activity / Works / Service	Original Schedule (As per Planning)	Actual Schedule (As per Actual)	Time Over-Run	Reasons for delay	Other Activity affected (Mention Sr. No. ofactivity affected)
Start Date	Completion Date	Actual Start Date	Actual Completion Date	Days
1
2
3
4
5
6
7
8
9
...

1. Delay on account of each reason in case of time overrun should be quantified and substantiated with necessary documents and supporting workings.

2. Indicate the activities on critical path

(Petitioner)Form-5F

In case there is claim of additional RoEName of the Petitioner ____________________Name of the Generating Station _____________

Project	Completion Time as per Investment approval(Months)	Actual Completion time	Qualifying time schedule (as per regulation)
	Start Date	Scheduled COD (Date)	Completion time in Months	Installed Capacity	Start Date	Actual COD (Date)	Actual Completion time in Months	Tested Capacity	Months
Unit 1
Unit 2
Unit 3
Unit 4
....
....

(Petitioner)Form-6

Financial Package upto CODName of the Petitioner ______________________________Name of the Generating Station _______________________[Project Cost as on COD] [Say Rs. 80 Cr. + US$ 200 m or Rs. 1320 Cr. including US$ 200 m at an exchange rate of US$=Rs62] _____________________________[Date of Commercial Operation of the Station] [Provide details on commercial operation as on COD of each Unit] ____________

	Financial Package as Approved	Financial Package as on COD	As Admitted on COD
	[Currency and Amount] [For example : US $ 200m, etc.]	[Currency and Amount] [For example : US $ 200m, etc.]	[Currency and Amount] [For example : US $ 200m, etc.]
1	2	3	4	5	6	7
Loan-I	US $	200m
Loan-II
Loan-III

and so on

Equity-
Foreign
Domestic
Total Equity
Debt : Equity Ratio

(Petitioner)Form-7

Details of project specific loansName of the Petitioner _____________________Name of the Generating Station _____________

Particulars	Package 1	Package 2	Package 3	Package 4	Package 5	Package 6
1	2	3	4	5	6	7
Source of Loan1
Currency2
Amount of Loan sanctioned
Amount of Gross Loan drawn upto 31.03.2014/COD3,4,5,13,15
Interest Type6
Fixed Interest Rate, if applicable
Base Rate, if Floating Interest7
Margin, if Floating Interest8
Are there any Caps/Floor9	Yes/No	Yes/No	Yes/No	Yes/No	Yes/No	Yes/No
If above is yes, specify caps/floor
Moratorium Period10
Moratorium effective from
Repayment Period11
Repayment effective from
Repayment Frequency12
Repayment Instalment13,14
Base Exchange Rate16
Are foreign currency loan hedged?
If above is yes, specify details17

Note: - 1. Source of loan means the agency from whom the loan has been taken such as WB, ADB, WMB, PNB, SBI, ICICI, IFC, PFC etc.

2. Currency refers to currency of loan such as US$, DM, Yen, Indian Rupee etc.

3. Details are to be submitted as on 31.03.2014 for existing assets and as on COD for the remaining assets.

4. Where the loan has been refinanced, details in the Form is to be given for the loan refinanced. However, the details of the original loan is to be given separately in the same form.

5. If the Tariff in the petition is claimed separately for various units, details in the Form is to be given separately for all the units in the same form.

6. Interest type means whether the interest is fixed or floating.

7. Base rate means the base as PLR, LIBOR etc. over which the margin is to be added. Applicable base rate on different dates from the date of drawl may also be enclosed.

8. Margin means the points over and above the floating rate.

9. At times caps/floor are put at which the floating rates are frozen. If such a condition exists, specify the limits.

10. Moratorium period refers to the period during which loan servicing liability is not required.

11. Repayment period means the repayment of loan such as 7 years, 10 years, 25 years etc.

12. Repayment frequency means the interval at which the debt servicing is to be done such as monthly, quarterly, half yearly, annual, etc.

13. Where there is more than one drawal/repayment for a loan, the date & amount of each drawal/repayment may also be given separately

14. If the repayment installment amount and repayment date cannot be worked out from the data furnished above, the repayment schedule to be furnished separately.

15. In case of Foreign loan, date of each drawal& repayment along with exchange rate at that date may be given.

16. Base exchange rate means the exchange rate prevailing as on 31.03.2004 or COD, whichever is later

17. In case of hedging, specify details like type of hedging, period of hedging, cost of hedging, etc.

18. In case of foreign loans, provide details of exchange rate considered on date of each repayment of principal and date of interest payment.

19. At the time of truing up rate of interest with relevant reset date (if any) to be furnished separately

20. At the time of truing up provide details of refinancing of loans considered earlier. Details such as date on which refinancing done, amount of refinanced loan, terms and conditions of refinanced loan, financing and other charges incurred for refinancing, etc.

(Petitioner)Form-8

Details of Allocation of corporate loans to various projectsName of the Petitioner __________________Name of the Generating Station ___________

Particulars	Package 1	Package 2	Package 3	Package 4	Package 5	Remarks
1	2	3	4	5	6	7
Source of Loan1
Currency2
Amount of Loan sanctioned
Amount of Gross Loan drawn upto 31.03.2014/COD3,4,5,13,15
Interest Type6
Fixed Interest Rate, if applicable
Base Rate, if Floating Interest7
Margin, if Floating Interest8
Are there any Caps/Floor9	Yes/No	Yes/No	Yes/No	Yes/No	Yes/No
If above is yes, specify caps/floor
Moratorium Period10
Moratorium effective from
Repayment Period11
Repayment effective from
Repayment Frequency12
Repayment Instalment13,14
Base Exchange Rate16
Are foreign currency loan hedged?
If above is yes, specify details17

	Distribution of loan packages to various projects
Name of the Projects						Total
Project 1
Project 2
Project 3 and so on

Note: - 1. Source of loan means the agency from whom the loan has been taken such as WB, ADB, WMB, PNB, SBI, ICICI, IFC, PFC etc.

2. Currency refers to currency of loan such as US$, DM, Yen, Indian Rupee etc.

3. Details are to be submitted as on 31.03.2014 for existing assets and as on COD for the remaining assets.

4. Where the loan has been refinanced, details in the Form is to be given for the loan refinanced. However, the details of the original loan is to be given separately in the same form.

5. If the Tariff in the petition is claimed separately for various units, details in the Form is to be given separately for all the units in the same form.

6. Interest type means whether the interest is fixed or floating.

7. Base rate means the base as PLR, LIBOR etc. over which the margin is to be added. Applicable base rate on different dates from the date of drawl may also be enclosed.

8. Margin means the points over and above the floating rate.

9. At times caps/floor are put at which the floating rates are frozen. If such a condition exists, specify the limits.

10. Moratorium period refers to the period during which loan servicing liability is not required.

11. Repayment period means the repayment of loan such as 7 years, 10 years, 25 years etc.

12. Repayment frequency means the interval at which the debt servicing is to be done such as monthly, quarterly, half yearly, annual, etc.

13. Where there is more than one drawal/repayment for a loan, the date & amount of each drawal/repayment may also be given separately

14. If the repayment installment amount and repayment date cannot be worked out from the data furnished above, the repayment schedule to be furnished separately.

15. In case of Foreign loan, date of each drawal& repayment along with exchange rate at that date may be given.

16. Base exchange rate means the exchange rate prevailing as on 31.03.2004 or COD, whichever is later

17. In case of hedging, specify details like type of hedging, period of hedging, cost of hedging, etc.

18. In case of foreign loans, provide details of exchange rate considered on date of each repayment of principal and date of interest payment.

19. At the time of truing up rate of interest with relevant reset date (if any) to be furnished separately

20. At the time of truing up provide details of refinancing of loans considered earlier. Details such as date on which refinancing done, amount of refinanced loan, terms and conditions of refinanced loan, financing and other charges incurred for refinancing etc.

(Petitioner)Form-9A

Year wise Statement of Additional Capitalisation after CODName of the Petitioner _______________________Name of the Generating Station _______________COD _____________________________________For Financial Year __________________________

Sl. No.	Head of Work / Equipment	ACE Claimed (Actual / Projected)	Regulations under which claimed	Justification	Admitted Cost by the Commission, if any
Accrual basis	Un-discharged Liability included in col. 3	Cash basis	IDC included in col. 3
(1)	(2)	(3)	(4)	(5=3-4)	(6)	(7)	(8)	(9)

1. In case the project has been completed and cost has already been admitted under any tariff notification(s) in the past, fill column 10 giving the cost as admitted for the purpose of tariff notification already issued by (Name of the authority) (Enclose copy of the tariff Order)

2. The above information needs to be furnished separately for each year / period of tariff period 2014-19.

3. In case of de-capitalisation of assets separate details to be furnished at column 1, 2, 3 and 4. Further, the original book value and year of capitalisation of such asset to be furnished at column 8. Where de-caps are on estimated basis the same to be shown separately.

4. Where any asset is rendered unserviceable the same shall be treated as de-capitalised during that year and original value of such asset to be shown at col. 3. And impaired value if any, year of its capitalisation to be mentioned at column 8.

5. Justification against each asset of capitalization should be specific to regulations under which claim has been made and the necessity of capitalization of that particular asset.

Note: - 1. Fill the form in chronological order year wise along with detailed justification clearly bringing 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. e.g. Rotor - 50 Crs. Initial spares- 5 Crs.

(Petitioner)Form-9B

Statement of Additional Capitalisation during fag end of useful life of the ProjectName of the Petitioner _______________________Name of the Generating Station _______________COD ______________________________________

Sl. No.	Year	Work / Equipment added during last five yearsof useful life of each Unit/ Station	ACE Claimed (Actual / Projected)	Regulations under which claimed	Justification	Impact on life extension
Accrual basis	Un-discharged Liability included in col. 4	Cash basis	IDC included in col. 4
(1)	(2)	(3)	(4)	(5)	(6=4-5)	(7)	(8)	(9)	(10)

Note: - 1. Cost Benefit analysis for capital additions done should be submitted along with petition for approval of such schemes.

2. Justification for additional capital expenditure claim for each asset should be relevant to regulations under which claim has been made and the necessity of capitalization of the asset.

(Petitioner)Form-9B(i)

Details of Assets De-capitalized during the periodName of the Petitioner __________________Name of the Generating Station ___________

Region

State

District

Sr. No.	Name of the Asset	Nature of de-capitlization (whether claimedunder exclusion or as additional capital expenditure)	Original Value of the Asset Capitalised	Year Put to use	Depreciation recovered till date ofde-capitalization
1	2	3	4	5	6
1
2
3
4
5

Note: Year wise detail need to be submitted.Form-9CStatement showing reconciliation of ACE claimed with the capital additions as per booksName of the Petitioner ___________________Name of the Generating Station ___________COD __________________________________

Sl. No.	Particulars	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)
	Closing Gross Block
	Less: Opening Gross Block
	Total Additions as per books
	Less: Additions pertaining to other Stages (give Stage wisebreakup)
	Net Additions pertaining to instant project/Unit/Stage
	Less: Exclusions (items not allowable / not claimed)
	Net Additional Capital Expenditure Claimed

Note: Reason for exclusion of any expenditure shall be given in Clear terms

(Petitioner)Form-9D

Statement showing items/assets/works claimed under Exclusions:Name of the Petitioner ___________________Name of the Generating Station ___________COD __________________________________

Sl. No.	Head of Work /Equipment	ACE Claimed underExclusion	Justification
Accrual basis	Un-discharged Liability included in col. 3	Cash basis	IDC included in col. 3
(1)	(2)	(3)	(4)	(5=3-4)	(6)	(7)

Note: - 1. Exclusions claimed on assets not allowed in Tariff should be supported by the specific reference of Commission Order date, Petition No., amount disallowed, etc..

2. For inter unit transfer, nature of transfer i.e. temporary or permanent should be mentioned. It is to be certified that exclusion sought in receiving station only and not in sending station or in both the station.

(Petitioner)Form-9E

Name of the Petitioner __________________Name of the Generating Station __________Statement of Capital cost(To be given for relevant dates and year wise)(Amount in Rs. Lakh)

Sl. No.	Particulars	As on relevant date.
A	a) Opening Gross Block Amount as per books
	b) Amount of capital liabilities in A(a) above
	c) Amount of IDC in A(a) above
	d) Amount of FC in A(a) above
	e) Amount of FERV in A(a) above
	f) Amount of Hedging Cost in A(a) above
	g) Amount of IEDC in A(a) above

B	a) Addition in Gross Block Amount during the period (Directpurchases)
	b) Amount of capital liabilities in B(a) above
	c) Amount of IDC in B(a) above
	d) Amount of FC in B(a) above
	e) Amount of FERV in B(a) above
	f) Amount of Hedging Cost in B(a) above
	g) Amount of IEDC in B(a) above

C	a) Addition in Gross Block Amount during the period(Transferred from CWIP)
	b) Amount of capital liabilities in C(a) above
	c) Amount of IDC in C(a) above
	d) Amount of FC in C(a) above
	e) Amount of FERV in C(a) above
	f) Amount of Hedging Cost in C(a) above
	g) Amount of IEDC in C(a) above

D	a) Deletion in Gross Block Amount during the period
	b) Amount of capital liabilities in D(a) above
	c) Amount of IDC in D(a) above
	d) Amount of FC in D(a) above
	e) Amount of FERV in D(a) above
	f) Amount of Hedging Cost in D(a) above
	g) Amount of IEDC in D(a) above

E	a) Closing Gross Block Amount as per books
	b) Amount of capital liabilities in E(a) above
	c) Amount of IDC in E(a) above
	d) Amount of FC in E(a) above
	e) Amount of FERV in E(a) above
	f) Amount of Hedging Cost in E(a) above
	g) Amount of IEDC in E(a) above

Note: - 1.Relevant date/s means date of COD of unit/s/station and financial year start date and end date.

(Petitioner)Form-9F

Name of the Petitioner ___________________Name of the Generating Station ___________Statement of Capital Woks in Progress(To be given for relevant dates and year wise)(Amount in Rs. Lakh)

Sl. No.	Particulars	As on relevant date.
A	a) Opening CWIP as per books
	b) Amount of capital liabilities in A(a) above
	c) Amount of IDC in A(a) above
	d) Amount of FC in A(a) above
	e) Amount of FERV in A(a) above
	f) Amount of Hedging Cost in A(a) above
	g) Amount of IEDC in A(a) above

B	a) Addition in CWIP during the period
	b) Amount of capital liabilities in B(a) above
	c) Amount of IDC in B(a) above
	d) Amount of FC in B(a) above
	e) Amount of FERV in B(a) above
	f) Amount of Hedging Cost in B(a) above
	g) Amount of IEDC in B(a) above

C	a) Transferred to Gross Block Amount during the period
	b) Amount of capital liabilities in C(a) above
	c) Amount of IDC in C(a) above
	d) Amount of FC in C(a) above
	e) Amount of FERV in C(a) above
	f) Amount of Hedging Cost in C(a) above
	g) Amount of IEDC in C(a) above

D	a) Deletion in CWIP during the period
	b) Amount of capital liabilities in D(a) above
	c) Amount of IDC in D(a) above
	d) Amount of FC in D(a) above
	e) Amount of FERV in D(a) above
	f) Amount of Hedging Cost in D(a) above
	g) Amount of IEDC in D(a) above

E	a) Closing CWIP as per books
	b) Amount of capital liabilities in E(a) above
	c) Amount of IDC in E(a) above
	d) Amount of FC in E(a) above
	e) Amount of FERV in E(a) above
	f) Amount of Hedging Cost in E(a) above
	g) Amount of IEDC in E(a) above

Note: - 1.Relevant date/s means date of COD of unit/s/station and financial year start date and end date.

(Petitioner)Form-10

Financing of Additional CapitalisationName of the Petitioner ________________________Name of the Generating Station ________________Date of Commercial Operation _________________(Amount in Rs Lakh)

	Actual	Admitted
[Financial Year (Starting from COD)] [Year 1 refers to Financial Year of COD and Year 2, Year 3 etc. are the subsequent financial years respectively.]	Year 1	Year 2	Year 3	Year 4	Year 5 & So on	Year 1	Year 2	Year 3	Year 4	Year 5 & So on
1	2	3	4	5	6	7	8	9	10	11

Amount capitalised in Work/ Equipment

Financing Details
Loan-1
Loan-2
Loan-3 and so on
[Total Loan] [Loan details for meeting the additional capitalisation requirement should be given as per Form-7 or 8 whichever is relevant.]

Equity
Internal Resources
Others (Pl. specify)

Total

(Petitioner)Form-11

Calculation of DepreciationName of the Petitioner ______________________Name of the Generating Station _______________(Amount in Rs Lakh)

Sl. no.	[Name of the Assets] [Name of the Assets should conform to the description of the assets mentioned in Depreciation Schedule appended to the Notification.]	Gross Block as on 31.03.2014 or as on COD,whichever is later and subsequently for each year thereafter upto31.3.19	Depreciation Rates as per CERC's DepreciationRate Schedule	Depreciation Amount for each year up to31.03.19
	1	2	3	4= Col.2 X Col.3
1	Land*
2	Building
3	and so on
4
5
6
7
8
9
10
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
	TOTAL
	Weighted Average Rate of
	Depreciation (%)

* Provide details of Freehold land and Lease hold land separately

(Petitioner)Form-12

Statement of DepreciationName of the Petitioner _____________________Name of the Generating Station _____________(Amount in Rs Lakh)

Sl. No.	Particulars	2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
	Opening Capital Cost
	Closing Capital Cost
	Average Capital Cost
	Freehold land
	Rate of depreciation
	Depreciable value
	Balance useful life at the beginning of the period
	Remaining depreciable value
	Depreciation (for the period)
	Depreciation (annualised)
	Less: Cumulative depreciation adjustment on account ofun-discharged liabilities deducted as on 01.04.2009/ Station COD
	Less: Cumulative depreciation adjustment on account ofde-capitalisation
	Net Cumulative depreciation at the end of the period

1. In case of details of FERV and AAD, give information for the applicable period.

(Petitioner)Form-13

[Calculation of Weighted Average Rate of Interest on Actual Loans] [In case of Foreign Loans, the calculations in Indian Rupees is to be furnished. However, the calculations in Original currency is also to be furnished separately in the same form.]Name of the Petitioner _____________________Name of the Generating Station _____________(Amount in Rs. Lakh)

Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
Loan-1
Gross loan - Opening
Cumulative repayments of Loans upto 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 upto 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 upto 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 upto 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

(Petitioner)Form-13A

Calculation of Interest on Normative LoanName of the Petitioner ____________________Name of the Generating Station _____________(Amount in Rs Lakh)

Sl. No.	Particulars	2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
	Gross Normative loan – Opening
	Cumulative repayment of Normative loan upto previous year
	Net Normative loan – Opening
	Add: Increase due to addition during the year / period
	Less: Decrease due to de-capitalisation during the year /period
	Less: Decrease due to reversal during the year / period
	Add: Increase due to discharges during the year / period
	Net Normative loan - Closing
	Average Normative loan
	Weighted average rate of interest
	Interest on Loan

(Petitioner)Form-13B

Calculation of Interest on Working CapitalName of the Petitioner _____________________Name of the Generating Station ______________(Amount in Rs Lakh)

Sl. No.	Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	2	3	4	5	6	7	8
1	[Cost of Coal/Lignite] [For Coal based/Lignite based generating stations]
2	[Cost of Main Secondary Fuel Oil] [For Coal based/Lignite based generating stations]
3	[Fuel Cost] [For Gas Turbine/Combined Cycle generating stations duly taking into account the annual mode of operation (last available) on gas fuel and liquid fuel]
4	[Liquid Fuel Stock] [For Gas Turbine/Combined Cycle generating stations duly taking into account the annual mode of operation (last available) on gas fuel and liquid fuel]
5	O & M Expenses
6	Maintenance Spares
7	Receivables
8	Total Working Capital
9	Rate of Interest
10	Interest on Working Capital

(Petitioner)Form-13C

Other Income as on CODName of the Petitioner ___________________Name of the Generating Station ____________(Amount in Rs. Lakh)

Sl. No.	Parameters	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	Interest on Loans and advance
2	Interest received on deposits
3	Income from Investment
4	Income from sale of scrap
5	Rebate for timely payment
6	Surcharge on late payment from beneficiaries
7	Rent from residential building
8	Misc. receipts (Please Specify Details)
...	...
...	...(add)

(Petitioner)Form-13D

Incidental Expenditure during Construction up to Scheduled COD and up to Actual/anticipated CODName of the Petitioner ____________________Name of the Generating Station _____________(Amount in Rs. Lakh)

Sl. No.	Parameters	As on Scheduled COD	As on actual COD/ anticipated COD
A	Head of Expenses:
1	Employees' Benefits Expenses
2	Finance Costs
3	Water Charges
4	Communication Expenses
5	Power Charges
6	Other Office and Administrative Expenses
7	Others (Please Specify Details)
8	Other Pre-Operating Expenses
...	.....
...	.....
B	Total Expenses
	Less: Income from sale of tenders
	Less: Income from guest house
	Less: Income recovered from Contractors
	Less: Interest on Deposits
	.....

(Petitioner)Form-13E

Expenditure under different packages up to Scheduled COD and up to Actual/anticipated CODName of the Petitioner _____________________Name of the Generating Station _____________(Amount in Rs. Lakh)

Sl. No.	Parameters	As on Scheduled COD	As on actual/ anticipated COD
1	Package 1
2	Package 2
3	Package 3
4	-------------------------------
5	-------------------------------
6

(Petitioner)Form-14

Draw Down Schedule for Calculation of IDC & Financing ChargesName of the Petitioner ____________________Name of the Generating Station ____________

Sl. No.	Draw Down	Quarter 1	Quarter 2	Quarter n (COD)
Particulars	Quantum in Foreign currency	Exchange Rate on draw down date	Amount in Indian Rupee (Rs Lakh)	Quantum in Foreign currency	Exchange Rate on draw down date	Amount in Indian Rupee (Rs Lakh)	Quantum in Foreign currency	Exchange Rate on draw down date	Amount in Indian Rupee (Rs Lakh)
1	Loans
1.1	Foreign Loans

1.1.1	[Foreign Loan] [Drawal of debt and equity shall be on paripassu basis quarter wise to meet the commissioning schedule. Drawal of higher equity in the beginning is permissible]
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.1.2	[Foreign Loan] [Applicable interest rates including reset dates used for above computation may be furnished separately]
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.1.3	[Foreign Loan] [In case of multi unit project details of capitalization ratio used to be furnished.]
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.1.4	- -
	- -
	- -


1.1	Total Foreign Loans
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.2	Indian Loans

1.2.1	[Indian Loan] [Drawal of debt and equity shall be on paripassu basis quarter wise to meet the commissioning schedule. Drawal of higher equity in the beginning is permissible]
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1.2.2	[Indian Loan] [Applicable interest rates including reset dates used for above computation may be furnished separately]
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1.2.3	[Indian Loan] [In case of multi unit project details of capitalization ratio used to be furnished.]
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1.2.4	--	--	--	--	--	--	--	--	--	--
	--	--	--	--	--	--	--	--	--	--
	--	--	--	--	--	--	--	--	--	--

1.2	Total Indian Loans
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1	Total of Loans drawn
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

2	Equity

2.1	Foreign equity drawn

2.2	Indian equity drawn

	Total equity deployed

(Petitioner)Form-14A

Actual cash expenditureName of the Petitioner ____________________Name of the Generating Station _____________(Amount in Rs. Lakh)

Particulars	Quarter-I	Quarter-II	Quarter-III	Quarter-n (COD)
Expenditure towards Gross Block
Add: Expenditure towards CWIP
Add: Capital Advances, if any
Less: Un-discharged liabilities (included above)
Add/Less: Others
Payment to contractors / suppliers towards capital assets
Cumulative payments

Note: If there is variation between payment and fund deployment justification need to be furnished

(Petitioner)Form-15

[Details/Information to be Submitted in respect of Fuel for Computation of Energy Charges] [Similar details to be furnished for natural gas/liquid fuel for CCGT station and secondary fuel oil for coal/lignite based thermal plants with appropriate units.]Name of the Petitioner _______________________Name of the Generating Station _______________

S. No.	Month	Unit	For preceding	For preceding	For preceding
3rd Month (from COD or from 1.4.2014 as thecase may be)	2nd Month (from COD or from 1.4.2014 as thecase may be)	1st Month (from COD or from 1.4.2014 as thecase may be)
Domestic	Imported	Domestic	Imported	Domestic	Imported
1	Quantity of Coal/ Lignite supplied by Coal/ Lignite Company	(MMT)
2	Adjustment (+/ -) in quantity supplied made by Coal/ LigniteCompany	(MMT)
3	Coal supplied by Coal/ Lignite Company (1+2)	(MMT)
4	Normative Transit & Handling Losses (For coal/ Lignitebased Projects)	(MMT)
5	Net coal / Lignite Supplied (3-4)	(MMT)
6	Amount charged by the Coal / Lignite Company	(Rs.)
7	Adjustment (+/ -) in amount charged made by Coal/ LigniteCompany	(Rs.)
8	Total amount	(Rs.)
9	Transportation charges by rail/ ship/ road transport	(Rs.)
10	Adjustment (+/ -) in amount charged made by Railways/Transport Company	(Rs.)
11	Demurrage Charges, if any	(Rs.)
12	Cost of diesel in transporting coal through MGR system, ifapplicable	(Rs.)
13	Total Transportation Charges (9+/ -10-11+12)	(Rs.)
14	Total amount Charged for coal/ lignite supplied includingTransportation (8+13)	(Rs.)
15	Landed cost of coal/ Lignite	Rs./ MT
16	Blending Ratio (Domestic/ Imported)
17	Weighted average cost of coal/ Lignite for preceding threemonths	Rs./ MT
18	GCV of Domestic Coal as per bill of Coal Company
19	GCV of Imported Coal as per bill Coal Company
20	Weighted average GCV of coal/ Lignite as Billed	(kCal/ Kg)
21	GCV of Domestic Coal as received at Station
22	GCV of Imported Coal as received at Station
23	Weighted average GCV of coal/ Lignite as Received

Note: - 1. As billed and as received GCV, quantity of coal, and price should be submitted as certified by statutory auditor.

(Petitioner)Form-16

Details/Information to be Submitted in respect of Limestone for Computation of Energy Charge RateName of the Petitioner ____________________Name of the Generating Station ____________

Sl. No.	Month	Unit	For preceding	For preceding	For preceding
3rd Month (from COD or from 1.4.2014 as thecase may be)	2nd Month (from COD or from 1.4.2014 as thecase may be)	1st Month (from COD or from 1.4.2014 as thecase may be)
1	Quantity of Limestone supplied by Limestone supply Company	(MMT)
2	Adjustment (+/-) in quantity supplied made by Limestone supplyCompany	(MMT)
3	Limestone supplied by Limestone supply Company(1+2)	(MMT)
4	Net Limestone Supplied (3-4)	(MMT)
5	Amount charged by the Limestone supply Company	(Rs.)
6	Adjustment (+/-) in amount charged made by Limestone supplyCompany	(Rs.)
7	Total amount Charged (6+7)	(Rs.)
8	Transportation charges by rail/ship/road transport	(Rs.)
9	Adjustment (+/-) in amount charged made by Railways/TransportCompany	(Rs.)
10	Demurrage Charges, if any	(Rs.)
11	Total Transportation Charges (8+/-9-10)	(Rs.)
12	Total amount Charged for Limestone supplied includingTransportation (7+11)	(Rs.)

(Petitioner)Form-17

Details/Information to be Submitted in respect of Capital SparesName of the Petitioner ______________________Name of the Generating Station ______________

Sl. No.	Details of Capital Spares and Expenses	Claimed as a part of additional Capitalisation	Funded through compensatory allowance	Funded through Special allowance (IfApplicable)	Claimed as a part of stores and spares
Name of spare	Amount
1
2
3
4
5
6
7
8
9
10
11
12

Form-18Liability Flow StatementName of the Petitioner ____________________Name of the Generating Station _____________

Party	Asset / Work	Year of actual capitalisation	Original Liability	Liability as on 31.03.2014	Discharges (Yearwise)	Reversal (Yearwise)

(Petitioner)Tariff Filing Forms (Hydro)

For Determination of TariffPart-II Annexure-IForm-1Summary SheetName of the Petitioner: ____________________Name of the Generating Station: ____________Place (Region/District/State):(Rs. lakh)

S. No.	Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	2	3	4	5	6	7	8
1.1	Depreciation
1.2	Interest on Loan
1.3	[Return on Equity] [Details of calculations, considering equity as per regulation, to be furnished.]
1.4	Interest on Working Capital
1.5	O & M Expenses
	Total

Form-1(I) - Statement showing claimed capital cost:

Sl. No.	Particulars	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)
	Opening Capital Cost
	Add: Addition during the year / period
	Less: Decapitalisation during the year / period
	Less: Reversal during the year / period
	Add: Discharges during the year / period
	Closing Capital Cost
	Average Capital Cost

Form-1(II) - Statement showing Return on Equity:(Rs. in Lakh)

Sl. No.	Particulars	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)
	Opening Equity
	Add: Increase due to addition during the year / period
	Less: Decrease due to de-capitalisation during the year /period
	Less: Decrease due to reversal during the year / period
	Add: Increase due to discharges during the year / period
	Closing Equity
	Average Equity
	Rate of ROE
	Return on Equity

(Petitioner)Form-2

Details of COD, Type of hydro station, Normative Annual Plant Availability Factor (NAPAF) & Other normative parameters considered for tariff calculationName of the Petitioner: ____________________Name of the Generating Station: ____________Year Ending March

	Particulars	Unit	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
	(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
1	Installed Capacity	MW
2	Free power to home state	%
3	Date of commercial operation (actual/anticipated)
	Unit-1
	Unit-2
	Unit-3
4	Type of Station
	a) Surface/underground
	b) Purely ROR/ Pondage/Storage
	c) Peaking/non-peaking
	d) No. of hours of peaking
	e) Overload capacity(MW) & period
5	Type of excitation
	a) Rotating exciters on generator
	b) Static excitation
6	[Design Energy (Annual)] [Month wise 10-day Design energy figures to be given separately with the petition.]	GWh
7	Auxiliary Consumption including Transformation losses	%
8	Normative Plant Availability Factor (NAPAF)

9.1	Maintenance Spares for WC	% of O&M
9.2	Receivables for WC	in Months
9.3	Base Rate of Return on Equity	%
9.4	[Tax Rate] [Tax rate applicable to the company for the year FY 2013-14 should also be furnished.]	%
9.5	[Effective Tax Rate] [Effective tax rate is to be computed in accordance with Regulation 25 i.e. actual tax (or advance tax)/gross income, where gross income refers the profit before tax.]
9.6	SBI Base Rate + 350 basis points as on[______________] [Mention relevant date]	%

(Petitioner)Form-3

Salient Features of Hydroelectric ProjectName of the Petitioner: ____________________Name of the Generating Station: ____________

1. Location
State/Distt.
River
2. Diversion Tunnel
Size, shape
Length (M)
3. Dam
Type
Maximum dam height (M)
4. Spillway
Type
Crest level of spillway (M)
5. Reservoir
Full Reservoir Level (FRL) (M)
Minimum Draw Down Level (MDDL) (M)
Live storage (MCM)
6. De-silting Chamber
Type
Number and Size
Particle size to be removed (mm)
7. Head Race Tunnel
Size and type
Length (M)
Design discharge (Cumecs)
8. Surge Shaft
Type
Diameter (M)
Height (M)
9. Penstock/Pressure shafts
Type
Diameter & Length (M)
10. Power House
Installed capacity (No of units x MW)
Type of turbine
Rated Head (M)
Rated Discharge (Cumecs)
Head at Full Reservoir Level (M)
Head at Minimum Draw down Level (M)
MW Capability at FRL
MW Capability at MDDL
11. Tail Race Tunnel/Channel
Diameter (M) , shape
Length (M)
Minimum tail water level (M)
12. Switchyard
Type of Switch gear
No. of generator bays
No. of Bus coupler bays
No. of line bays

Note: - Specify limitation on generation during specific time period(s) on account of restrictions on water use due to irrigation, drinking water, industrial, environmental considerations etc.

(Petitioner)Form-4

Details of Foreign loans(Details only in respect of loans applicable to the project under petition)Name of the Petitioner: ____________________Name of the Generating Station: ____________Exchange Rate at COD ____________________Exchange Rate as on 31.3.2014 _____________

Sl.	Financial Year (Starting from COD)	Year 1
	1	2	3	4	5
		Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount (Rs. Lakh)
	[Currency 1] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of Drawl] [In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given]
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	[In case of Hedging] [Furnish details of hedging, in case of more than one hedging during the year or part hedging, details of each hedging are to be given]
1	At the date of hedging
2	Period of hedging
3	Cost of hedging
	[Currency 2] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of Drawl] [In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given]
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	[In case of Hedging] [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]
1	At the date of hedging
2	Period of hedging
3	Cost of hedging
	[Currency 3] [Name of the currency to be mentioned e.g. US$, DM, etc.]& so on
A.1	[At the date of Drawl] [In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given]
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	[In case of Hedging] [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]
1	At the date of hedging
2	Period of hedging
3	Cost of hedging

Year 2	Year 3 and so on
6	7	8	9	10	11	12	13
Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount (Rs. Lakh)	Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount(Rs. Lakh)

Note: Tax (such as withholding tax) details as applicable including change in rates, date from which change effective etc. must be clearly indicated.

(Petitioner)Form-4A

Details of Foreign Equity(Details only in respect of Equity infusion if any applicable to the project under petition)Name of the Petitioner: ____________________Name of the Generating Station: ____________Exchange Rate on date/s of infusion _________

Sl.	Financial Year	Year 1
	1	2	3	4	5
		Date	Amount (Foreign Currency)	Exchange Rate	Amount (Rs. Lakh)
	[Currency 1] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3
	[Currency 2] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3
	[Currency 3] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3
	[Currency 4] [Name of the currency to be mentioned e.g. US$, DM, etc.]& so on
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3

Year 2	Year 3 and so on
6	7	8	9	10	11	12	13
Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount (Rs. Lakh)	Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount(Rs. Lakh)

(Petitioner)Form-5

Abstract of Admitted Capital Cost for the existing ProjectsName of the Petitioner: ____________________Name of the Generating Station: ____________

	Capital Cost as admitted by CERC

a)	Capital cost admitted as on________________
	(Give reference of the relevant CERC Order with Petition No. &Date)

b)	Foreign Component, if any (In Million US $ or the relevantCurrency)

c)	Foreign Exchange rate considered for the admitted Capital cost(Rs Lakh)

d)	Total Foreign Component (Rs. Lakh)

e)	Domestic Component (Rs. Lakh.)

f)	Hedging cost, if any, considered for the admitted Capital cost(Rs Lakh)

	Total Capital cost admitted (Rs. Lakh) (d+e+f)

(Petitioner)Form-5A

Abstract of Capital Cost Estimates and Schedule of Commissioning for the New ProjectsName of the Petitioner: ____________________Name of the Generating Station: ____________New ProjectsCapital Cost Estimates

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 on 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,IEDC& FC
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. Lakh)

Capital cost excluding IDC, IEDC, FC, FERV & HedgingCost (Rs. Lakh)

IDC, IEDC,FC, FERV & Hedging Cost
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. Lakh)

Total IDC, IEDC, FC, FERV & Hedging Cost(Rs. Lakh)
Rate of taxes & duties considered

Capital cost Including IDC, IEDC, FC, FERV &Hedging Cost
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. Lakh)

Capital cost Including IDC, IEDC& FC (Rs. Lakh)

Schedule of Commissioningas per investment approval
Scheduled COD of Unit-I
Scheduled COD of Unit-II
---------------------------
---------------------------
Scheduled COD of last Unit/Station

Note: - 1. Copy of approval letter should be enclosed

2. Details of Capital Cost are to be furnished as per FORM-5B or 5C as applicable

3. Details of IDC & Financing Charges are to be furnished as per FORM-14.

(Petitioner)Form-5B

Break-up of Capital Cost for New Hydro Power Generating StationName of the Petitioner: ____________________Name of the Generating Station: ____________(Amount in Rs Lakh)

Sl. No.	Break Down	Original Cost as approved by Authority/Investment Approval	Actual Capital Expenditure as on actual/anticipated COD	Liabilities/ Provisions	Variation	Reasons for Variation
(1)	(2)	(3)	(4)	(5)	(6=3-4-5)	(7)
1.0	Infrastructure Works
1.1	Preliminary including Development
1.2	Land*
1.3	R&R expenditure 1.4 Buildings
1.5	Township
1.6	Maintenance
1.7	Tools & Plants
1.8	Communication
1.9	Environment & Ecology
1.10	Losses on stock
1.11	Receipt & Recoveries
1.12	Total (Infrastructure works)

2.0	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)

3.0	Hydro Mechanical equipments

4.0	Plant & Equipment
4.1	Initial spares of Plant & Equipment
4.2	Total (Plant & Equipment)

5.0	Taxes and Duties
5.1	Custom Duty
5.2	Other taxes & Duties
5.3	Total Taxes & Duties

6.0	Construction & Pre-commissioning expenses
6.1	Erection, testing & commissioning
6.2	Construction Insurance
6.3	Site supervision
6.4	Total (Const. & Pre-commissioning)

7.0	Overheads
7.1	Establishment
7.2	Design & Engineering
7.3	Audit & Accounts
7.4	Contingency
7.5	Rehabilitation & Resettlement
7.6	Total (Overheads)

8.0	Capital Cost without IDC, FC, FERV & Hedging Cost

9.0	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

10.0	Capital cost including IDC, FC, FERV & Hedging Cost

* Provide details of Freehold Land, Leasehold Land and Land under reservoir separatelyNote: - 1. In case of cost variation, a detailed note giving reasons of such variation should be submitted clearly indicating whether such cost over-run was beyond the control of the generating company.

2. In case of both time & cost overrun, 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 and cost overrun was beyond the control of the generating company.

3. The implication on cost due to time over run, if any shall be submitted separately giving details of increase in prices in different packages from scheduled COD to Actual COD/anticipated COD, increase in IEDC from scheduled COD to actual COD/anticipated COD and increase of IDC from scheduled COD to actual anticipated COD.

4. Impact on account of each reason for Time over run on Cost of project should be quantified and substantiated with necessary documents and supporting workings.

5. A list of balance work assets/work wise including initial spare on original scope of works along with estimate shall be furnished positively.

(Petitioner)Form-5C

Break-up of Capital Cost for Plant & Equipment (New Projects)Name of the Petitioner: ____________________Name of the Generating Station: ____________(Amount in Rs Lakh)

Sl. No.	Break Down	Original Cost as approved byAuthority/Investment Approval (1)	Cost on Actual/anticipated COD (1)	Variation	Reasons for Variation*
Total Cost	Total Cost
(1)	(2)			(3)	(4)
1.0	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)

2.0	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
2.10	Diesel generating sets
2.11	Total (Auxiliary Elect. Equipment)

3.0	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
3.10	Workshop machines & equipment
3.11	Total (Auxiliary equipt. & services for PS)

4.0	Switchyard package

5.0	Initial spares for all above equipments
6.0	Total Cost (Plant & Equipment) excluding IDC, FC, FERV& Hedging Cost

7.0	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

8.0	Total Cost (Plant & Equipment) including IDC, FC, FERV& Hedging Cost

Note: - 1. In case of cost variation, a detailed note giving reasons of such variation should be submitted clearly indicating whether such cost overrun was beyond the control of the generating company.

(Petitioner)Form-5D

Break-up of Construction/Supply/Service packagesName of the Petitioner: ____________________Name of the Generating Station: ____________

1	Name/No. of Construction / Supply / Service Package	Package A	Package B	Package C	...	Total Cost of all packages
2	[Scope of works] [The scope of work in any package should be indicated in conformity of Capital cost break-up for the coal/lignite based plants in the Form-5B to the extent possible. In case of Gas/Liquid fuel based projects, break down in the similar manner in the relevant heads as per Form-5C.](in line with head of cost break-ups asapplicable)
3	Whether awarded through ICB/DCB/ Departmentally/ Deposit Work
4	No. of bids received
5	Date of Award
6	Date of Start of work
7	Date of Completion of Work/Expected date of completion of work
8	[Value of Award] [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, the exchange rate and the date e.g. Rs.80 Cr. +US$50m=Rs.390Cr. at US$=Rs62 as on say 01.04.14.]in (Rs. Lakh)
9	Firm or With Escalation in prices
10	Actual capital expenditure till the completion or up to CODwhichever is earlier (Rs.Lakh)
11	Taxes & Duties and IEDC (Rs. Lakh)
12	IDC, FC, FERV & Hedging cost (Rs. Lakh)
13	Sub-total (10+11+12) (Rs. Lakh)

(Petitioner)Form-5E(i)

In case there is cost over runName of the Petitioner ______________________Name of the Generating Station _______________

Sl. No.	Break Down	Original Cost (Rs.Lakh) as approved by the Board of Members	Actual/ EstimatedCost as incurred/to be incurred (Rs. Lakh)	Difference	Reasons forVariation (Please submit supporting computations and documentswherever applicable)	Increase in softcost due to increase in hard cost
		Total Cost	Total Cost	Total Cost
1	Cost of Land & Site Development
1.1	Land*
1.2	Rehabilitation & Resettlement (R&R)
1.3	Preliminary Investigation & Site Development

2	Plant & Equipment
2.1	Steam Generator Island
2.2	Turbine Generator Island
2.3	BOP Mechanical
2.3.1	Fuel Handling & Storage system
2.3.2	External water supply 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	Switch gear Package
2.4.4	Cables, Cable facilities & grounding
2.4.5	Lighting
2.4.6	Emergency D.G. set
	Total BOP Electrical

2.5	Control & Instrumentation (C & I) Package
	Total Plant & Equipment excluding taxes & Duties
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
4.10	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

* Submit details of Freehold and Lease hold landNote: - Impact on account of each reason for Cost overrun should be quantified and substantiated with necessary documents and supporting workings.

(Petitioner)Form-5E(ii)

In case there is time over runName of the Petitioner: ____________________Name of the Generating Station: ____________

Sr. No.	Description of Activity / Works / Service	Original Schedule (As per Planning)	Actual Schedule (As per Actual)	Time Over-Run	Reasons for delay	Other Activity affected (Mention Sr. No. ofactivity affected)
Start Date	Completion Date	Actual Start Date	Actual Completion Date	Days
1
2
3
4
5
6
7
8
9
...

1. Delay on account of each reason in case of time overrun should be quantified and substantiated with necessary documents and supporting workings.

2. Indicates the activities on critical path.

(Petitioner)Form-5F

In case there is claim of additional RoEName of the Petitioner: ____________________Name of the Generating Station: ____________

Project	Completion Time as per Investment approval(Months)	Actual Completion time	Qualifying time schedule (as per regulation)
	Start Date	Scheduled COD (Date)	Completion time in Months	Installed Capacity	Start Date	Actual COD (Date)	Actual Completion time in Months	Tested Capacity	Months
Unit 1
Unit 2
Unit 3
Unit 4
....
....

Note: Necessary documentary evidence in support of actual completion time to be submitted in accordance with Regulation 5(1).

(Petitioner)Form-6

Financial Package upto CODName of the Petitioner ______________________________Name of the Generating Station _______________________[Project Cost as on COD] [Say Rs. 80 Cr. + US$ 200 m or Rs. 1320 Cr. including US$ 200 m at an exchange rate of US$=Rs62] _____________________________[Date of Commercial Operation of the Station] [Date of Commercial Operation means Commercial Operation of the last unit] ____________

	Financial Package as Approved	Financial Package as on COD	As Admitted on COD
	[Currency and Amount] [For example : US $ 200m, etc.]	[Currency and Amount] [For example : US $ 200m, etc.]	[Currency and Amount] [For example : US $ 200m, etc.]
1	2	3	4	5	6	7
Loan-I	US $	200m
Loan-II
Loan-III

and so on

Equity-
Foreign
Domestic
Total Equity
Debt : Equity Ratio

(Petitioner)Form-7

Details of Project Specific LoansName of the Petitioner: ____________________Name of the Generating Station: ____________

Particulars	Package 1	Package 2	Package 3	Package 4	Package 5	Package 6
1	2	3	4	5	6	7
Source of Loan1
Currency2
Amount of Loan sanctioned
Amount of Gross Loan drawn upto 31.03.2014/COD3,4,5,13,15
Interest Type6
Fixed Interest Rate, if applicable
Base Rate, if Floating Interest7
Margin, if Floating Interest8
Are there any Caps/Floor9	Yes/No	Yes/No	Yes/No	Yes/No	Yes/No	Yes/No
If above is yes, specify caps/floor
Moratorium Period10
Moratorium effective from
Repayment Period11
Repayment effective from
Repayment Frequency12
Repayment Instalment13,14
Base Exchange Rate16
Are foreign currency loan hedged?
If above is yes, specify details17

Note: - 1. Source of loan means the agency from whom the loan has been taken such as WB, ADB, WMB, PNB, SBI, ICICI, IFC, PFC etc.

2. Currency refers to currency of loan such as US$, DM, Yen, Indian Rupee etc.

3. Details are to be submitted as on 31.03.2014 for existing assets and as on COD for the remaining assets.

4. Where the loan has been refinanced, details in the Form is to be given for the loan refinanced. However, the details of the original loan is to be given separately in the same form.

5. If the Tariff in the petition is claimed separately for various units, details in the Form is to be given separately for all the units in the same form.

6. Interest type means whether the interest is fixed or floating.

7. Base rate means the base as PLR, LIBOR etc. over which the margin is to be added. Documentary evidence for applicable base rate on different dates from the date of drawl may also be enclosed.

8. Margin means the points over and above the floating rate.

9. At times caps/floor are put at which the floating rates are frozen. If such a condition exists, specify the limits.

10. Moratorium period refers to the period during which loan servicing liability is not required.

11. Repayment period means the repayment of loan such as 7 years, 10 years, 25 years etc.

12. Repayment frequency means the interval at which the debt servicing is to be done such as monthly, quarterly, half yearly, annual, etc.

13. Where there is more than one drawal/repayment for a loan, the date & amount of each drawal/repayment may also be given separately

14. If the repayment installment amount and repayment date cannot be worked out from the data furnished above, the repayment schedule to be furnished separately.

15. In case of Foreign loan, date of each drawal & repayment along with exchange rate at that date may be given with documentary evidence.

16. Base exchange rate means the exchange rate prevailing as on 31.03.2014 for existing assets and as on COD for the remaining assets.

17. In case of hedging, specify details like type of hedging, period of hedging, cost of hedging, etc.

18. In case of foreign loans, provide details of exchange rate considered on date of each repayment of principal and date of interest payment.

19. At the time of truing up rate of interest with relevant reset date (if any) to be furnished separately

20. At the time of truing up provide details of refinancing of loans considered earlier. Details such as date on which refinancing done, amount of refinanced loan, terms and conditions of refinanced loan, financing and other charges incurred for refinancing etc.

21. Call or put option, if any exercised by the generating company for refinancing of loan

22. Copy of loan agreement

(Petitioner)Form-8

Details of Allocation of corporate loans to various projectsName of the Petitioner: ____________________Name of the Generating Station: ____________

Particulars	Package 1	Package 2	Package 3	Package 4	Package 5	Remarks
1	2	3	4	5	6	7
Source of Loan1
Currency2
Amount of Loan sanctioned
Amount of Gross Loan drawn upto 31.03.2014/COD3,4,5,13,15
Interest Type6
Fixed Interest Rate, if applicable
Base Rate, if Floating Interest7
Margin, if Floating Interest8
Are there any Caps/Floor9	Yes/No	Yes/No	Yes/No	Yes/No	Yes/No
If above is yes, specify caps/floor
Moratorium Period10
Moratorium effective from
Repayment Period11
Repayment effective from
Repayment Frequency12
Repayment Instalment13,14
Base Exchange Rate16
Are foreign currency loan hedged?
If above is yes, specify details17

	Distribution of loan packages to various projects
Name of the Projects						Total
Project 1
Project 2
Project 3 and so on

Note: - 1. Source of loan means the agency from whom the loan has been taken such as WB, ADB, WMB, PNB, SBI, ICICI, IFC, PFC etc.

2. Currency refers to currency of loan such as US$, DM, Yen, Indian Rupee etc.

3. Details are to be submitted as on 31.03.2014 for existing assets and as on COD for the remaining assets.

4. Where the loan has been refinanced, details in the Form is to be given for the loan refinanced. However, the details of the original loan is to be given separately in the same form.

5. If the Tariff in the petition is claimed separately for various units, details in the Form is to be given separately for all the units in the same form.

6. Interest type means whether the interest is fixed or floating.

7. Base rate means the base as PLR, LIBOR etc. over which the margin is to be added. Documentary evidence for applicable base rate on different dates from the date of drawl may also be enclosed.

8. Margin means the points over and above the floating rate.

9. At times caps/floor are put at which the floating rates are frozen. If such a condition exists, specify the limits.

10. Moratorium period refers to the period during which loan servicing liability is not required.

11. Repayment period means the repayment of loan such as 7 years, 10 years, 25 years etc.

12. Repayment frequency means the interval at which the debt servicing is to be done such as monthly, quarterly, half yearly, annual, etc.

13. Where there is more than one drawal/repayment for a loan, the date & amount of each drawal/repayment may also be given separately

14. If the repayment installment amount and repayment date cannot be worked out from the data furnished above, the repayment schedule to be furnished separately.

15. In case of Foreign loan, date of each drawal & repayment along with exchange rate at that date may be given with documentary evidence.

16. Base exchange rate means the exchange rate prevailing as on 31.03.2014 for existing assets and as on COD for the remaining assets.

17. In case of hedging, specify details like type of hedging, period of hedging, cost of hedging, etc.

18. In case of foreign loans, provide details of exchange rate considered on date of each repayment of principal and date of interest payment.

19. At the time of truing up rate of interest with relevant reset date (if any) to be furnished separately

20. At the time of truing up provide details of refinancing of loans considered earlier. Details such as date on which refinancing done, amount of refinanced loan, terms and conditions of refinanced loan, financing and other charges incurred for refinancing etc.

21. Call or put option, if any exercised by the generating company for refinancing of loan

22. Copy of loan agreement

(Petitioner)Form-9A

Sl. No.	Head of Work / Equipment	ACE Claimed (Actual / Projected)	Regulations under which claimed	Justification	Admitted Cost by the Commission, if any
Accrual basis	Un-discharged Liability included in col. 3	Cash basis	IDC included in col. 3
(1)	(2)	(3)	(4)	(5=3-4)	(6)	(7)	(8)	(9)

1. In case the project has been completed and cost has already been admitted under any tariff notification(s) in the past, fill column 10 giving the cost as admitted for the purpose of tariff notification already issued by (Name of the authority) (Enclose copy of the tariff Order)

2. The above information needs to be furnished separately for each year / period of tariff period 2014-19.

3. In case of de-capitalisation of assets separate details to be furnished at column 1, 2, 3 and 4. Further, the original book value and year of capitalisation of such asset to be furnished at column 8. Where de-caps are on estimated basis the same to be shown separately.

4. Where any asset is rendered unserviceable the same shall be treated as de-capitalised during that year and original value of such asset to be shown at col. 3. And impaired value if any, year of its capitalisation to be mentioned at column 8.

5. Justification against each asset of capitalization should be specific to regulations under which claim has been made and the necessity of capitalization of that particular asset.

Note: - 1. Fill the form in chronological order year wise along with detailed justification clearly bringing 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. e.g. Rotor - 50 Crs. Initial spares- 5 Crs.

(Petitioner)Form-9B

Statement of Additional Capitalisation during fag end of the ProjectName of the Petitioner _______________________Name of the Generating Station _______________COD ______________________________________

Sr. No.	Year	Work/ Equipment added during last five yearsof useful life of each Unit/ Station	Amount capitalised / Proposed to becapitalised (Rs Lakh)	Justification for capitalisation proposed	Impact on life extension
1	2	3	4	5	6
1
2
3
4
5

Note: - 1. Cost Benefit analysis for capital additions done should be submitted along with petition for approval of such schemes

2. Justification for additional capital expenditure claim for each asset should be relevant to regulation under which claim and the necessity of capitalization of the asset

(Petitioner)Form-9B(i)

Details of Assets De-capitalized during the periodName of the Petitioner __________________Name of the Generating Station ___________

Region

State

District

Sr. No.	Name of the Asset	Nature of de-capitlization (whether claimedunder exclusion or as additional capital expenditure)	Original Value of the Asset Capitalised	Year Put to use	Depreciation recovered till date ofde-capitalization
1	2	3	4	5	6
1
2
3
4
5

Sl. No.	Particulars	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)
	Closing Gross Block
	Less: Opening Gross Block
	Total Additions as per books
	Less: Additions pertaining to other Stages (give Stage wisebreakup)
	Net Additions pertaining to instant project/Unit/Stage
	Less: Exclusions (items not allowable / not claimed)
	Net Additional Capital Expenditure Claimed

Note: Reason for exclusion of any expenditure shall be given in Clear terms

(Petitioner)Form-9D

Statement showing items/assets/works claimed under Exclusions:Name of the Petitioner ___________________Name of the Generating Station ___________COD __________________________________

Sl. No.	Head of Work /Equipment	ACE Claimed underExclusion	Justification
Accrual basis	Un-discharged Liability included in col. 3	Cash basis	IDC included in col. 3
(1)	(2)	(3)	(4)	(5=3-4)	(6)	(7)

Note: - 1. Exclusions claimed on assets not allowed in Tariff should be supported by the specific reference of Commission Order date, Petition No., amount disallowed, etc..

2. For inter unit transfer, nature of transfer i.e. temporary or permanent should be mentioned. It is to be certified that exclusion sought in receiving station only and not in sending station or in both the station.

(Petitioner)Form-9E

Name of the Petitioner: ____________________Name of the Generating Station: ____________Statement of Capital cost(To be given for relevant dates and year wise)(Amount in Rs. Lakh)

Sl. No.	Particulars	As on relevant date.
A	a) Opening Gross Block Amount as per books
	b) Amount of capital liabilities in A(a) above
	c) Amount of IDC in A(a) above
	d) Amount of FC in A(a) above
	e) Amount of FERV in A(a) above
	f) Amount of Hedging Cost in A(a) above
	g) Amount of IEDC in A(a) above

B	a) Addition in Gross Block Amount during the period (Directpurchases)
	b) Amount of capital liabilities in B(a) above
	c) Amount of IDC in B(a) above
	d) Amount of FC in B(a) above
	e) Amount of FERV in B(a) above
	f) Amount of Hedging Cost in B(a) above
	g) Amount of IEDC in B(a) above

C	a) Addition in Gross Block Amount during the period(Transferred from CWIP)
	b) Amount of capital liabilities in C(a) above
	c) Amount of IDC in C(a) above
	d) Amount of FC in C(a) above
	e) Amount of FERV in C(a) above
	f) Amount of Hedging Cost in C(a) above
	g) Amount of IEDC in C(a) above

D	a) Deletion in Gross Block Amount during the period
	b) Amount of capital liabilities in D(a) above
	c) Amount of IDC in D(a) above
	d) Amount of FC in D(a) above
	e) Amount of FERV in D(a) above
	f) Amount of Hedging Cost in D(a) above
	g) Amount of IEDC in D(a) above

E	a) Closing Gross Block Amount as per books
	b) Amount of capital liabilities in E(a) above
	c) Amount of IDC in E(a) above
	d) Amount of FC in E(a) above
	e) Amount of FERV in E(a) above
	f) Amount of Hedging Cost in E(a) above
	g) Amount of IEDC in E(a) above

Note: - 1. Relevant date/s means date of COD of unit/s/station and financial year start date and end date

(Petitioner)Form-9F

Name of the Petitioner: ____________________Name of the Generating Station: ____________Statement of Capital Woks in Progress(To be given for relevant dates and year wise)(Amount in Rs. Lakh)

Sl. No.	Particulars	As on relevant date.
A	a) Opening CWIP as per books
	b) Amount of capital liabilities in A(a) above
	c) Amount of IDC in A(a) above
	d) Amount of FC in A(a) above
	e) Amount of FERV in A(a) above
	f) Amount of Hedging Cost in A(a) above
	g) Amount of IEDC in A(a) above

B	a) Addition in CWIP during the period
	b) Amount of capital liabilities in B(a) above
	c) Amount of IDC in B(a) above
	d) Amount of FC in B(a) above
	e) Amount of FERV in B(a) above
	f) Amount of Hedging Cost in B(a) above
	g) Amount of IEDC in B(a) above

C	a) Transferred to Gross Block Amount during the period
	b) Amount of capital liabilities in C(a) above
	c) Amount of IDC in C(a) above
	d) Amount of FC in C(a) above
	e) Amount of FERV in C(a) above
	f) Amount of Hedging Cost in C(a) above
	g) Amount of IEDC in C(a) above

D	a) Deletion in CWIP during the period
	b) Amount of capital liabilities in D(a) above
	c) Amount of IDC in D(a) above
	d) Amount of FC in D(a) above
	e) Amount of FERV in D(a) above
	f) Amount of Hedging Cost in D(a) above
	g) Amount of IEDC in D(a) above

E	a) Closing CWIP as per books
	b) Amount of capital liabilities in E(a) above
	c) Amount of IDC in E(a) above
	d) Amount of FC in E(a) above
	e) Amount of FERV in E(a) above
	f) Amount of Hedging Cost in E(a) above
	g) Amount of IEDC in E(a) above

Note: - 1. Relevant date/s means date of COD of unit/s/station and financial year start date and end date

(Petitioner)Form-10

Financing of Additional CapitalisationName of the Petitioner ________________________Name of the Generating Station ________________Date of Commercial Operation _________________(Amount in Rs Lakh)

	Actual	Admitted
[Financial Year (Starting from COD)] [Year 1 refers to Financial Year of COD and Year 2, Year 3 etc. are the subsequent financial years respectively.]	Year 1	Year 2	Year 3	Year 4	Year 5 & So on	Year 1	Year 2	Year 3	Year 4	Year 5 & So on
1	2	3	4	5	6	7	8	9	10	11

Amount capitalised in Work/ Equipment

Financing Details
Loan-1
Loan-2
Loan-3 and so on
[Total Loan] [Loan details for meeting the additional capitalisation requirement should be given as per Form-7 or 8 whichever is relevant.]

Equity
Internal Resources
Others (Pl. specify)

Total

(Petitioner)Form-11

Calculation of DepreciationName of the Petitioner: ____________________Name of the Generating Station: ____________(Amount in Rs Lakh)

Sl. no.	[Name of the Assets] [Name of the Assets should conform to the description of the assets mentioned in Depreciation Schedule appended to the Notification.]	Gross Block as on 31.03.2014 or as on COD,whichever is later and subsequently for each year thereafter upto31.3.19	Depreciation Rates as per CERC's DepreciationRate Schedule	Depreciation Amount for each year up to31.03.19
	1	2	3	4= Col.2 X Col.3
1	Land*
2	Building
3	and so on
4
5
6
7
8
9
10
11
12
13
	TOTAL
	Weighted Average Rate of
	Depreciation (%)

* Provide details of Freehold Land, Leasehold Land and Land under reservoir separately

(Petitioner)Form-12

Statement of DepreciationName of the Petitioner: ____________________Name of the Generating Station: ____________(Amount in Rs. Lakh)

Sl. No.	Particulars	2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
	Opening Capital Cost
	Closing Capital Cost
	Average Capital Cost
	Freehold land
	Rate of depreciation
	Depreciable value
	Balance useful life at the beginning of the period
	Remaining depreciable value
	Depreciation (for the period)
	Depreciation (annualised)
	Cumulative depreciation at the end of the period
	Less: Cumulative depreciation adjustment on account ofun-discharged liabilities deducted as on 01.04.2009/ Station COD, whichever is later
	Less: Cumulative depreciation adjustment on account ofde-capitalisation
	Net Cumulative depreciation at the end of the period

1. In case of details of FERV and AAD, give information for the applicable period.

(Petitioner)Form-13

Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
Loan-1
Gross loan - Opening
Cumulative repayments of Loans upto 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 upto 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 upto 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 upto 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

Note: - 1. In case of Foreign Loans, the calculations in Indian Rupees is to be furnished. However, the calculation in Original currency is also to be furnished separately in the same form.

(Petitioner)Form-13A

Calculation of Interest on Normative LoanName of the Petitioner ____________________Name of the Generating Station _____________(Amount in Rs Lakh)

Sl. No.	Particulars	2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
	Gross Normative loan – Opening
	Cumulative repayment of Normative loan upto previous year
	Net Normative loan – Opening
	Add: Increase due to addition during the year / period
	Less: Decrease due to de-capitalisation during the year /period
	Less: Decrease due to reversal during the year / period
	Add: Increase due to discharges during the year / period
	Net Normative loan - Closing
	Average Normative loan
	Weighted average rate of interest
	Interest on Loan

(Petitioner)Form-13B

Calculation of Interest on Working CapitalName of the Petitioner: ____________________Name of the Generating Station: ____________(Amount in Rs Lakh)

Sl. No.	Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	2	3	4	5	6	7	8
1	O & M Expenses
2	Maintenance Spares
3	Receivables
4	Total Working Capital
5	Rate of Interest
6	Interest on Working Capital

(Petitioner)Form-13C

Other Income as on actual/anticipated CODName of the Petitioner ___________________Name of the Generating Station ____________(Amount in Rs. Lakh)

Sl. No.	Parameters	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	Interest on Loans and advance
2	Interest received on deposits
3	Income from Investment
4	Income from sale of scrap
5	Rebate for timely payment
6	Surcharge on late payment from beneficiaries
7	Rent from residential building
8	Misc. receipts (Please Specify Details)
...	...
...	...(add)

(Petitioner)Form-13D

Incidental Expenditure during ConstructionName of the Petitioner: ____________________Name of the Generating Station _____________(Amount in Rs. Lakh)

Sl. No.	Parameters	Upto Scheduled COD	Upto actual COD/ anticipated COD
A	Expenses:
1	Employees' Benefits Expenses
2	Finance Costs
3	Water Charges
4	Communication Expenses
5	Power Charges
6	Other Office and Administrative Expenses
7	Others (Please Specify Details)
8	Other Pre-Operating Expenses
...	.....
...	.....
B	Total Expenses
	Less: Income from sale of tenders
	Less: Income from guest house
	Less: Income recovered from Contractors
	Less: Interest on Deposits
	.....

(Petitioner)Form-14

Draw Down Schedule for Calculation of IDC & Financing ChargesName of the Petitioner: ____________________Name of the Generating Station: ____________

Sl. No.	Draw Down	Quarter 1	Quarter 2	Quarter n (COD)
Particulars	Quantum in Foreign currency	Exchange Rate on draw down date	Amount in Indian Rupee (Rs Lakh)	Quantum in Foreign currency	Exchange Rate on draw down date	Amount in Indian Rupee (Rs Lakh)	Quantum in Foreign currency	Exchange Rate on draw down date	Amount in Indian Rupee (Rs Lakh)
1	Loans
1.1	Foreign Loans

1.1.1	[Foreign Loan] [Drawal of debt and equity shall be on paripassu basis quarter wise to meet the commissioning schedule. Drawal of higher equity in the beginning is permissible]
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.1.2	[Foreign Loan] [Applicable interest rates including reset dates used for above computation may be furnished separately]
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.1.3	[Foreign Loan] [In case of multi unit project details of capitalization ratio used to be furnished.]
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.1.4	- -
	- -
	- -


1.1	Total Foreign Loans
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.2	Indian Loans

1.2.1	[Indian Loan] [Drawal of debt and equity shall be on paripassu basis quarter wise to meet the commissioning schedule. Drawal of higher equity in the beginning is permissible]
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1.2.2	[Indian Loan] [Applicable interest rates including reset dates used for above computation may be furnished separately]
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1.2.3	[Indian Loan] [In case of multi unit project details of capitalization ratio used to be furnished.]
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1.2.4	--	--	--	--	--	--	--	--	--	--
	--	--	--	--	--	--	--	--	--	--
	--	--	--	--	--	--	--	--	--	--

1.2	Total Indian Loans
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1	Total of Loans drawn
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

2	Equity

2.1	Foreign equity drawn

2.2	Indian equity drawn

	Total equity deployed

Note: - Detailed calculation of IDC (Actual drawl and repayment dates and amount, rates of interest, etc.) should be furnished.

(Petitioner)Form-14A

Actual cash expenditureName of the Petitioner: ____________________Name of the Generating Station: ____________(Amount in Rs. Lakh)

	Quarter-I	Quarter-II	Quarter-III	Quarter-n (COD)
Payment to contractors/suppliers
% of fund deployment

Note: - If there is variation between payment and fund deployment justification need to be furnished

(Petitioner)Form-15A

Design energy and peaking capability (month wise)- ROR with Pondage/Storage type new stationsName of the Petitioner: ____________________Name of the Generating Station: ____________

Generating Company..................

Name of Hydro-electric Generating Station :.........

Installed Capacity: No of units X .MW=

Month		Design Energy* (MUs)	Designed Peaking Capability (MW)*

April	I
	II
	III
May	I
	II
	III
June	I
	II
	III
July	I
	II
	III
August	I
	II
	III
September	I
	II
	III
October	I
	II
	III
November	I
	II
	III
December	I
	II
	III
January	I
	II
	III
February	I
	II
	III
March	I
	II
	III
Total

*As per DPR/TEC of CEA dated..................Note : - Specify the number of peaking hours for which station has been designed.

(Petitioner)Form-15B

Design energy and MW Continuous (month wise)- ROR type stationsName of the Petitioner: ____________________Name of the Generating Station: ____________

Generating Company..................

Name of Hydro-electric Generating Station :.........

Installed Capacity: No of units X .MW=

Month		Design Energy* (MUs)	MW continuous*

April	I
	II
	III
May	I
	II
	III
June	I
	II
	III
July	I
	II
	III
August	I
	II
	III
September	I
	II
	III
October	I
	II
	III
November	I
	II
	III
December	I
	II
	III
January	I
	II
	III
February	I
	II
	III
March	I
	II
	III
Total

*As per DPR/TEC of CEA dated..................

(Petitioner)Form-16

Liability Flow StatementName of the Petitioner: ____________________Name of the Generating Station: ____________

Party	Asset / Work	Year of actual capitalisation	Original Liability	Liability as on 31.03.2014	Discharges (Yearwise)	Reversal (Yearwise)

(Petitioner)Tariff Filing Forms (Transmission & Communication System)

For Determination of TariffPart-III Annexure-IForm-1Summary Sheet

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

Sr. No.	Particulars	Form No.	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	2		3	4	5	6	7	8
1.1	Depreciation
1.2	Interest on Loan
1.3	[Return on Equity] [Details of calculations, considering equity as per regulation, to be furnished (As per Form 8).]
1.4	Interest on Working Capital
1.5	O & M Expenses
	Total

(Petitioner)Form-2

Details of Transmission Lines & Substations & Communication System

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

Transmission 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.	Line length km	Date of Commercial operation	Covered in the present petition
Yes/No	If No, petition No.
1
2
3
4
-
-
-

Substations:

S.No.	Name of Sub-station	Type of Substation Conventional (Greenfield/Brownfield)/ GIS/ HVDC terminal/ HVDC Back to Back	Voltage level kV	No. of transformers/ Reactors/ SVC etc. (withcapacity)	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
-
-

Communication System:

S. No.	Name of Communication System	Type of Communication System –Communication System under ULDC/ SCADA/ WAMS/ Fibre OpticCommunication System/ RTU/ PABX etc	Technical Particulars	Number/ length	Date of Commercial operation	Covered in the present petition
Yes/No	If No, petition No.
1
2
3
4
-

(Petitioner)Form-3

Normative parameters considered for tariff computations

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

Year Ending March

Particulars	Unit	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
Base Rate of Return on Equity	%
Tax Rate	%
[Effective tax rate] [To be supported by necessary documents and calculations. Effective tax rate is to be computed in accordance with Regulation 25 i.e. actual tax (or estimated tax)/gross income, where gross income refers the profit before tax.]	%
Target Availability	%
Normative O&M per km	Rs. Lakh
Normative O&M per bay	Rs. Lakh
Spares for WC as % of O&M	%
Receivables in Months for WC	Months
Bank Rate as on[______________] [Mention relevant date]	%

(Petitioner)Form-4

Abstract of admitted parameters for the existing transmission assets/elements under project.

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

	Asset-1	Asset-2	Asset-3 and so on	Total Gross Block as on 31.03.2014
Name of the Assets
DOCO
Petition Number
Tariff order date
Particulars	Capital Expenditure admitted as on 31.03.2014	Capital Expenditure admitted as on 31.03.2014	Capital Expenditure admitted as on 31.03.2014
Apportioned approved Cost/Revised cost estimates, if any(with reference and date of approval)

Freehold Land
Leasehold Land
Building & Other Civil Works
Transmission Line
Sub-Station Equipments
PLCC
Total
Notional Loan
Notional Equity
Total

Debt-Equity Ratio
Debt
Equity
Total
Cumulative amount of Depreciation
Cumulative Repayment of Loan
[Initial Spares] [Initial spares claimed for existing whose cut off date falls in current tariff period.]

Details of remaining assets of the project yet to be commissioned needs to be included in Form-5B

(Petitioner)Form-4A

Statement of Capital cost(To be given for relevant dates and year wise)

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

		[As on relevant date.] [Relevant date/s means date of COD of transmission element/s or Communication system and financial year start date and end date]
A	a) Opening Gross Block Amount as per books
	b) Amount of capital liabilities in A(a) above
	c) Amount of (i) IDC (ii) FC (iii) FERV & (iv) Hedgingcost included in A(a) above	(i)...(ii)…(iii)...(iv)...
	d) Amount of IEDC (excluding IDC, FC, FERV & Hedging cost)included in A(a) above
B	a) Addition in Gross Block Amount during the period
	b) Amount of capital liabilities in B(a) above
	c) Amount of (i) IDC (ii) FC (iii) FERV & (iv) Hedgingcost included in B(a) above	(i)...(ii)…(iii)...(iv)...
	d) Amount of IEDC (excluding IDC, FC, FERV & Hedging cost)included in B(a) above
C	a) Closing Gross Block Amount as per books
	b) Amount of capital liabilities in C(a) above
	c) Amount of (i) IDC (ii) FC (iii) FERV & (iv) Hedgingcost included in C(a) above	(i)...(ii)…(iii)...(iv)...
	d) Amount of IEDC (excluding IDC, FC, FERV & Hedging cost)included in C(a) above

(Petitioner)Form-4B

Statement of Capital Works in Progress(To be given for relevant dates and year wise)

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

		[As on relevant date.] [Relevant date/s means date of COD of transmission element/s and financial year start date and end date]
A	a) Opening CWIP Amount as per books
	b) Amount of capital liabilities in a above
	c) Amount of (i) IDC (ii) FC (iii) FERV & (iv) Hedgingcost included in (a) above	(i)...(ii)...(iii)...(iv)...
B	a) Addition/Adjustment in CWIP Amount during the period
	b) Amount of capital liabilities in a above
	c) Amount of (i) IDC (ii) FC (iii) FERV & (iv) Hedgingcost included in (a) above	(i)...(ii)...(iii)...(iv)...
C	a) Capitalization/Transfer to Fixed asset of CWIP Amountduring the period
	b) Amount of capital liabilities in a above
	c) Amount of (i) IDC (ii) FC (iii) FERV & (iv) Hedgingcost included in (a) above	(i)...(ii)...(iii)...(iv)...
D	a) Closing CWIP Amount as per books
	b) Amount of capital liabilities in a above
	c) Amount of (i) IDC (ii) FC (iii) FERV & (iv) Hedgingcost in a above	(i)...(ii)...(iii)...(iv)...

(Petitioner)Form-4C

Abstract of Capital Cost Estimates and Schedule of Commissioning for the New Project/Element

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

New ProjectsCapital Cost Estimates

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 on End of ______ Qtr. of the year _________	As on Scheduled COD of the transmission system/ transmission element/ Communication System

Foreign Exchange rate considered for the Capital costestimates
Capital Cost excluding IDC,IEDC& FC
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. Lakh)

Capital cost excluding IDC, IEDC, FC, FERV & HedgingCost (Rs. Cr)

IDC, IEDC,FC, FERV & Hedging Cost
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. Lakh)

Total IDC, IEDC, FC, FERV & Hedging Cost(Rs. Lakh)
Rate of taxes & duties considered

Capital cost Including IDC, IEDC, FC, FERV &Hedging Cost
Foreign Component, if any (In Million US $ or the relevantCurrency)
Domestic Component (Rs. Lakh)

Capital cost Including IDC, IEDC& FC (Rs. Lakh)

Schedule of Commissioning
COD of transmission system 1 /transmission element 1/Communication System 1
COD of transmission system 1/ transmission element 2/ Communication System 2
---------------------------
---------------------------
COD of last transmission system /transmission element / Communication System

Note: - 1. Copy of approval letter by the Board duly certified by the Company secretary should be enclosed

2. Details of Capital Cost are to be furnished as per FORM-5 or 5A as applicable

3. Details of IDC & Financing Charges are to be furnished as per FORM-12(B).

(Petitioner)Form-5

Element wise Break-up of Project/Asset/Element Cost for Transmission System or Communication System

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

Sl. No.	Particulars	Cost in Rs. Lakh	Liabilities/ Provisions	Variation	Reasons for Variation	Admitted Cost
As per Original Estimates	Actual Capital Expenditure as on COD
Quantity	Rate	Estimated Amount	Quantity	Rate	Actual Amount
(1)	(2)	3)	(4)	(5)	(6=3-4-5)	(7)	(8)
A	TRANSMISSION LINE
1.0	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

2.0	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
	Total Transmission Lines material

3.0	Taxes and Duties
3.1	Custom Duty
3.2	Other Taxes & Duties
	Total Taxes & Duties

	Total- Transmission lines

B.	SUBSTATIONS
4.0	Preliminary works & land
4.1	Design & Engineering
4.2	Land
4.3	Site preparation
	Total Preliminary works & land

5.0	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
	Total Civil Works

6.0	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
6.10	Grounding System
6.11	Structure for switchyard
	Total Substation Equipments
7.00	Spares

8.0	Taxes and Duties
8.1	Custom Duty
8.2	Other Taxes & Duties
8.3	Total Taxes & Duties
	Total (Sub-station)

C	Communication System
9.1	Preliminary Works
9.2	Communication System equipment’s
9.3	Taxes and Duties
	Total (Communication System)

10.0	Construction and pre-commissioning expenses
10.1	Site supervision & site administration .etc.
10.2	Tools and Plants
10.3	construction Insurance
	Total Construction and pre commissioning expenses

11.0	Overheads
11.1	Establishment
11.2	Audit & Accounts
11.3	Contingency
	Total Overheads
12.0	Cost of Plant & Machinery

13.0	Capital Cost including Plant & Machinery
13.1	Interest During Construction (IDC)
13.2	Financing Charges (FC)
13.3	Foreign Exchange Rate Variation (FERV)
13.4	Hedging Cost
	Total of IDC, FC, FERV & Hedging Cost

14.0	Capital cost including IDC, FC, FERV & Hedging Cost

Note: - 1. In case of cost variation, a detailed note giving reasons of such variation should be submitted clearly indicating whether such cost over-run was beyond the control of the transmission licensee.

2. Separate details of free hold/lease hold land should be submitted.

(Petitioner)Form-5A

Break-up of Construction/Supply/Service Packages

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

Sr. No.

Name/ No. of Const-ruction/ supply/ servicepackage

[Scope of works] [The scope of work in any package should be indicated in conformity of cost break-up in Form-5B to the extent possible.](in line with head of costbreak-ups as applicable)

Whether awarded through ICB/ DCB/Depart-mentally/ Deposit Work, etc.

No. of bids received

Date of Award

Date of Start of work

Date of Completion of Work

[Value of Award] [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, the exchange rate and the date e.g. Rs. 800 Lakh. + US$ 5m=Rs. 3900 Lakh. at US$=Rs62 as on say 01.04.14.]in (Rs. Lakh).

Firm or With Escalation in prices

Actual expenditure till the completion or upto COD whichever is earlier (Rs. Lakh)

Taxes & Duties and IEDC (Rs. Lakh)

IDC, FC, FERV & Hedging cost (Rs. Lakh)

Sub-Total (Rs. Lakh)

(Petitioner)Form-5B

Details of elementwise cost of the project

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________

Transmission Lines:

S. No.	Name of line	Apportioned approved cost (Rs. Lakh)	Revised cost estimates, if applicable (Rs.Lakh)	Completed Cost (Rs. Lakh)	Covered in the present petition
Yes/No	If No, petition No.
1
2
3
4
-
-
-

Substations:

S. No.	Name of Sub-station	Apportioned approved cost (Rs. Lakh)	Revised cost estimates, if applicable (Rs.Lakh)	Completed Cost (Rs. Lakh)	Covered in the present petition
Yes/No	If No, petition No.
1
2
3
4
-
-
-

Communication System:

S. No.	Name of Communication System	Apportioned approved cost (Rs. Lakh)	Revised cost estimates, if applicable (Rs.Lakh)	Completed Cost (Rs. Lakh)	Covered in the present petition
Yes/No	If No, petition No.
1
2
3
4
-
-
-

(Petitioner)Form-6

Financial Package upto COD

Name of the Petitioner:	______________________________
Name of the Transmission Element/ Communication system:	______________________________
[Project/Element Cost as on COD] [Say Rs. 800 Lakh. + US$ 5m=Rs. 3900 Lakh including US$ 5 m at an exchange rate of US$=Rs62]:	______________________________
Date of Commercial Operation of the[Transmission Element] [For example: US $ 5m, etc.]or Communication System	______________________________

	Financial Package as Approved	Financial Package as on COD	As Admitted on COD
	[Currency and Amount] [In case of foreign loans exchange rate considered on date of commercial operation.]	[Currency and Amount] [In case of foreign loans exchange rate considered on date of commercial operation.]	[Currency and Amount] [In case of foreign loans exchange rate considered on date of commercial operation.]
1	2	3	4	5	6	7
Loan-I	US $	m
Loan-II
Loan-III
and so on
Total Loans
Equity-
Foreign
Domestic
Total Equity
Debt : Equity Ratio
Total Cost
	Debt	Equity	Total
Add cap for Year-1
Add cap for Year-2

Add cap for Year-1	Actual	Normative
Debt
Equity
Total
Add cap for Year-2	Actual	Normative
Debt
Equity
Total
Total Capital Cost with add cap.

(Petitioner)Form-7

Statement of Additional Capitalisation after COD

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________
COD	______________________________

Sr. No.	Year	Work/ Equipment proposed to be added after CODupto Cut off Date/ beyond Cut-off Date	Amount capitalized/ Proposed to be capitalized(Rs Lakh)	Justification	Regulations under which covered	[Admitted Cost] (Rs Lakh)
(1)	(2)	(3)	(4)	(5)	(6)	(7)
1
2
3
4
5

1. In case the project has been completed and any tariff notification(s) has already been issued in the past, fill column 7 giving the cost as admitted for the purpose of tariff notification already issued by (Name of the authority) (Enclose copy of the tariff Order).

Note: - • Fill the form in chronological order year wise along with detailed justification clearly bringing out the necessity and the benefits accruing to the beneficiaries.• In case initial spares are purchased along with any equipment, then the cost of such spares should be indicated separately.• In case of de-capitalisation of assets separate details to be furnished. Further, the original book value and year of capitalisation of such asset to be furnished. Where de-caps are on estimated basis the same to be shown separately.

(Petitioner)Form-7A

Financing of Additional Capitalisation

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

	Actual/Projected	Admitted
Financial Year (Starting from COD)	Year 1	Year 2	Year 3	Year 4	Year 5 & So on	Year 1	Year 2	Year 3	Year 4	Year 5 & So on
1	2	3	4	5	6	7	8	9	10	11

Amount capitalised in Work/Equipment

Financing Details
Loan-1
Loan-2
Loan-3 and so on
Total Loan

Equity
Internal Resources
Others

Total

Note: - 1. Year 1 refers to Financial Year of COD in case of new elements. For existing elements it is from 2014-15 and Year 2, Year 3 etc. are the subsequent financial years respectively.

2. Loan details for meeting the additional capitalisation requirement should be given as per FORM-9 or 9(A) whichever is relevant.

(Petitioner)Form-7B

Statement of Additional Capitalisation during [fag end] [Five years before the completion of useful life.] of the Project

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________
COD	______________________________

Sr. No.	Year	Work/ Equipment added five years before theuseful life	Amount capitalised/ Proposed to be capitalized(Rs Lakh)	Justification for capitalisation proposed	Impact on life extension
1	2	3	4	5	6
1
2
3
4
5

Note: - • Cost Benefit analysis for capital additions done should be submitted along with petition for approval of such schemes

(Petitioner)Form-8

Calculation of Return on Equity

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

S. No.	Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	2	3	4	5	6	7	8
1.1	Equity as on COD/Admitted equity
1.2	Notional Equity for Add Cap
1.3	Total Equity
1.4	[Return on Equity] [To be calculated on average equity during the year.]
	Total

(Petitioner)Form-8A

Details of Foreign Equity(Details only in respect of Equity infusion if any applicable to the Asset/Element under petition)

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System:	______________________________
Exchange Rate on date/s of Infusion:	______________________________

Sl.	Financial Year	Year 1
	1	2	3	4	5
		Date	Amount (Foreign Currency)	Exchange Rate	Amount (Rs. Lakh)
	[Currency 1] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3
	[Currency 2] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3
	[Currency 3] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3
	[Currency 4] [Name of the currency to be mentioned e.g. US$, DM, etc.]& so on
A.1	[At the date of infusion] [In case of equity infusion more than once during the year, Exchange rate at the date of each infusion to be given]
2
3

Year 2	Year 3 and so on
6	7	8	9	10	11	12	13
Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount (Rs. Lakh)	Date	Amount (Foreign Currency)	Relevant Exchange Rate	Amount(Rs. Lakh)

(Petitioner)Form-8B

Details of additional RoE

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

Project/ Element	Completion Time as per Investment approval	Actual Completion time	Qualifying time schedule (as per regulation)(in months)
Start Date	Scheduled COD (Date)	Months	Start Date	Actual COD (Date)	Months
1
2
3
4
...
...

(Petitioner)Form-9

Details of Allocation of corporate loans to various transmission elements

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

Particulars	Package 1	Package 2	Package 3	Package 4	Package 5	Remarks
1	2	3	4	5	6	7
Source of Loan1
Currency2
Amount of Loan sanctioned
Amount of Gross Loan drawn upto 31.03.2014/COD3,4,5,13,15
Interest Type6
Fixed Interest Rate, if applicable
Base Rate, if Floating Interest7
Margin, if Floating Interest8
Are there any Caps/Floor9	Yes/No	Yes/No	Yes/No	Yes/No	Yes/No
If above is yes, specify caps/floor
Moratorium Period10
Moratorium effective from
Repayment Period11
Repayment effective from
Repayment Frequency12
Repayment Instalment13,14
Base Exchange Rate16
Are foreign currency loan hedged?
If above is yes, specify details17

	Distribution of loan packages to various transmission elements/ Communication system
Name of the Projects						Total
Transmission element 1/ Communication system 1
Transmission element 2/ Communication system 2
Transmission element 3/ Communication system 3 and so on

Note: - 1. Source of loan means the agency from whom the loan has been taken such as WB, ADB, WMB, PNB, SBI, ICICI, IFC, PFC etc.

2. Currency refers to currency of loan such as US$, DM, Yen, Indian Rupee etc.

3. Details are to be submitted as on 31.03.2014 for existing assets and as on COD for the remaining assets.

4. Where the loan has been refinanced, details in the Form is to be given for the loan refinanced. However, the details of the original loan is to be given separately in the same form.

5. If the Tariff in the petition is claimed separately for various transmission elements/ Communication system, details in the Form is to be given separately for all the transmission elements/ Communication system in the same form.

6. Interest type means whether the interest is fixed or floating.

7. Base rate means the base as PLR, LIBOR etc. over which the margin is to be added. Applicable base rate on different dates from the date of drawl may also be enclosed.

8. Margin means the points over and above the floating rate.

9. At times caps/floor are put at which the floating rates are frozen. If such a condition exists, specify the limits.

10. Moratorium period refers to the period during which loan servicing liability is not required.

11. Repayment period means the repayment of loan such as 7 years, 10 years, 25 years etc.

12. Repayment frequency means the interval at which the debt servicing is to be done such as monthly, quarterly, half yearly, annual, etc.

13. Where there is more than one drawal/repayment for a loan, the date & amount of each drawal/repayment may also be given separately

14. If the repayment installment amount and repayment date cannot be worked out from the data furnished above, the repayment schedule to be furnished separately.

15. In case of Foreign loan, date of each drawal & repayment of principal and interest along with exchange rate at that date may be given.

16. Base exchange rate means the exchange rate as on 31.03.2004 or as on COD whichever is later.

17. In case of hedging, specify details like type of hedging, period of hedging, cost of hedging, etc.

18. At the time of truing up rate of interest with relevant reset date (if any) to be furnished separately

19. At the time of truing up provide details of refinancing of loans considered earlier. Details such as date on which refinancing done, amount of refinanced loan, terms and conditions of refinanced loan, financing and other charges incurred for refinancing etc.

(Petitioner)Form-9A

Details of Project Specific Loans

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

Particulars	Package 1	Package 2	Package 3	Package 4	Package 5	Package 6
1	2	3	4	5	6	7
Source of Loan1
Currency2
Amount of Loan sanctioned
Amount of Gross Loan drawn upto 31.03.2014/COD3,4,5,13,15
Interest Type6
Fixed Interest Rate, if applicable
Base Rate, if Floating Interest7
Margin, if Floating Interest8
Are there any Caps/Floor9	Yes/No	Yes/No	Yes/No	Yes/No	Yes/No	Yes/No
If above is yes, specify caps/floor
Moratorium Period10
Moratorium effective from
Repayment Period11
Repayment effective from
Repayment Frequency12
Repayment Instalment13,14
Base Exchange Rate16
Are foreign currency loan hedged?
If above is yes, specify details17

Note: - 1. Source of loan means the agency from whom the loan has been taken such as WB, ADB, WMB, PNB, SBI, ICICI, IFC, PFC etc.

2. Currency refers to currency of loan such as US$, DM, Yen, Indian Rupee etc.

3. Details are to be submitted as on 31.03.2014 for existing assets and as on COD for the remaining assets.

4. Where the loan has been refinanced, details in the Form is to be given for the loan refinanced. However, the details of the original loan is to be given separately in the same form.

5. If the Tariff in the petition is claimed separately for various transmission system/transmission elements/ Communication system, details in the Form is to be given separately for all the transmission system/transmission element/ Communication system in the same form.

6. Interest type means whether the interest is fixed or floating.

7. Base rate means the base as PLR, LIBOR etc. over which the margin is to be added. Applicable base rate on different dates from the date of drawl may also be enclosed.

8. Margin means the points over and above the floating rate.

9. At times caps/floor are put at which the floating rates are frozen. If such a condition exists, specify the limits.

10. Moratorium period refers to the period during which loan servicing liability is not required.

11. Repayment period means the repayment of loan such as 7 years, 10 years, 25 years etc.

12. Repayment frequency means the interval at which the debt servicing is to be done such as monthly, quarterly, half yearly, annual, etc.

13. Where there is more than one drawal/repayment for a loan, the date & amount of each drawal/repayment may also be given separately

14. If the repayment installment amount and repayment date cannot be worked out from the data furnished above, the repayment schedule to be furnished separately.

15. In case of Foreign loan, date of each drawal & repayment of principal and interest along with exchange rate at that date may be given.

16. Base exchange rate means the exchange rate as on 31.03.2004 or as on COD whichever is later.

17. In case of hedging, specify details like type of hedging, period of hedging, cost of hedging, etc.

18. At the time of truing up rate of interest with relevant reset date (if any) to be furnished separately

19. At the time of truing up provide details of refinancing of loans considered earlier. Details such as date on which refinancing done, amount of refinanced loan, terms and conditions of refinanced loan, financing and other charges incurred for refinancing etc.

(Petitioner)Form-9B

Details of Foreign loans(Details only in respect of loans applicable to the Asset/Element under Petition)

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________
Exchange Rate at COD/31.03.2004 whichever is later	______________________________

Sl.	Financial Year (Starting from COD)	Year 1	Year 2 and so on
	1	2	3	4	5	6	7	8	9
		Date	Amount (Foreign Currency)	[Exchange Rate] [Exchange rate at COD/31.03.2004 whichever is later.]	Amount (Rs. Lakh)	Date	Amount (Foreign Currency)	[Exchange Rate] [Exchange rate at COD/31.03.2004 whichever is later.]	Amount (Rs. Lakh)
	[Currency 1] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of Drawl] [In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given]
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	[In case of Hedging] [Furnish details of hedging, in case of more than one hedging during the year or part hedging, details of each hedging are to be given.]
1	At the date of hedging
2	Period of hedging
3	Cost of hedging
	[Currency 2] [Name of the currency to be mentioned e.g. US$, DM, etc.]
A.1	[At the date of Drawl] [In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given]
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year Sl.
B	[In case of Hedging] [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.]
1	At the date of hedging
2	Period of hedging
3	Cost of hedging
	[Currency 3] [Name of the currency to be mentioned e.g. US$, DM, etc.]& so on
A.1	[At the date of Drawl] [In case of more than one drawl during the year, Exchange rate at the date of each drawl to be given]
2	Scheduled repayment date of principal
3	Scheduled payment date of interest
4	At the end of Financial year
B	[In case of Hedging] [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.]
1	At the date of hedging
2	Period of hedging
3	Cost of hedging

Note - In case of refinancing similar details with supporting documents to be furnishedForm-9C[Calculation of Weighted Average Rate of Interest on Actual Loans] [In case of Foreign Loans, the calculations in Indian Rupees is to be furnished as per Form 9(D). However, the calculation in original currency is also to be furnished separately in the same form.]

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
Loan-1
Gross loan - Opening
Cumulative repayments of Loans upto 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 repayment effective from (date to be indicated)

Loan-2
Gross loan - Opening
Cumulative repayments of Loans upto 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 repayment effective from (date to be indicated)

Loan-3 and so on
Gross loan - Opening
Cumulative repayments of Loans upto 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 repayment effective from (date to be indicated)

Total Loan
Gross loan - Opening
Cumulative repayments of Loans upto 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

Note: - 1. In case of already commissioned combined assets the details may be provided asset wise as well as combined.

2. Details of Financing Charges.

(Petitioner)Form-9D

Loans in Foreign Currency

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
Foreign Loan-1 (USD in Lakh) Exchange rate
Gross loan - Opening
Cumulative repayments of Loans upto 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 repayment effective from (date to be indicated)

Foreign Loan-2 (USD in Lakh) Exchange rate
Gross loan - Opening
Cumulative repayments of Loans upto 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 repayment effective from (date to be indicated)

Foreign Loan-3 (USD in Lakh) Exchange rate
.....
.....

(Petitioner)Form-9E

Calculation of Interest on Normative Loan

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

Sl. No.	Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
	Gross Normative loan – Opening
	Cumulative repayment of Normative loan upto previous year
	Net Normative loan – Opening
	Increase/Decrease due to ACE/de-capitalization during the Year
	Repayments of Normative Loan during the year
	Net Normative loan - Closing
	Average Normative loan
	Weighted average rate of interest of actual Loans
	Interest on Normative Loan

Note: - 1. At the time of true-up net savings as a result of refinancing of loans may be provided along with adjustments of sharing.

(Petitioner)Form-10

Calculation of Depreciation Rate

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

Sl. no.	[Name of the Assets] [Name of the Assets should conform to the description of the assets mentioned in Depreciation Schedule appended to the Notification.]	Gross Block as on 31.03.2014 or as on COD,whichever is later and subsequently for each year thereafter upto31.3.19	Depreciation Rates as per CERC's DepreciationRate Schedule	Depreciation Amount for each year up to31.03.19
	1	2	3	4= Col.2 X Col.3
1	Land
2	Building
3	and so on
4
5
6
7
8
9
10
18
19
20
21
22
23
24
25
	TOTAL
	Weighted Average Rate of Depreciation (%)

(Petitioner)Form-10A

Statement of Depreciation

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

Sl. No.	Particulars	2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)
1	Opening Capital Cost
2	Closing Capital Cost
3	Average Capital Cost
4	Freehold land
5	Rate of depreciation
6	Depreciable value
7	Balance useful life at the beginning of the period
8	Remaining depreciable value
9	Depreciation (for the period)
10	Depreciation (annualised)
11	Cumulative depreciation at the end of the period
12	Less: Cumulative depreciation adjustment on account ofde-capitalisation
13	Net Cumulative depreciation at the end of the period

1. In case of details of FERV and AAD, give information for the applicable period.

(Petitioner)Form-10B

Statement of De-capitalisation

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________
COD	______________________________

Sr. No.	Year of De-capitalisation	Work/ Equipment proposed to be De-capitalised	Year of capitalisation of asset/ equipmentbeing decapitalised	Original Book Value of the asset beingdecapitalised	Debt Equity ratio at the time ofcapitalisation	Cumulative Depreciation corresponding todecapitalisation	Cumulative Repayment of Loan corresponding todecapitalisation	Justification
(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)	(9)
1
2
3
4
5

(Petitioner)Form-11

Calculation of Interest on Working Capital

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

Sl. No.	Particulars	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	2	3	4	5	6	7	8
1	O & M Expenses
2	Maintenance Spares
3	Receivables
4	Total Working Capital
5	Rate of Interest
6	Interest on Working Capital

(Petitioner)Form-12

Details of time over run

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project/element:	______________________________

S.No	Description of Activity/ Works/ Service	Original Schedule (As per Planning)	Actual Schedule (As per Actual)	Time Over-Run	Agency responsible and whether such time overrun was beyond the control of the Transmission Licensee	Reasons for delay	Other Activity affected (Mention Sr No ofactivity affected)
Start Date	Completion Date	Start Date	Completion Date	Months
1
2
3
4
5
6
7
8
9
...	.....

1. Delay on account of each reason in case of time overrun should be quantified and substantiated with necessary documents and supporting workings.

(Petitioner)Form-12A

Incidental Expenditure during Construction

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________
Date of Commercial Operation	______________________________

(Amount in Rs. Lakh)

Sl. No.	Parameters	Year-1	Year-2	Year-3	Year-4	Year-5
A	Expenses:
1	Employees' Remuneration & Benefits
2	Finance Costs
3	Water Charges
4	Communication Expenses
5	Power Charges
6	Other Office and Administrative Expenses
7	Others (Please Specify Details)
8	Other pre-Operating Expenses
	....
B	Total Expenses
	Less: Income from sale of tenders
	Less: Income from guest house
	Less: Income recovered from Contractors
	Less: Interest on Deposits
	....

Note: IEDC should be duly reconciled with the corresponding figures of Auditor's Certificate.

(Petitioner)Form-12B

Draw Down Schedule for Calculation of IDC & Financing Charges

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

Sl. No.	Draw Down	Quarter 1	Quarter 2	Quarter n (COD)
Particulars	Quantum in Foreign currency	Exchange Rate on draw down date	Amount in Indian Rupee (Rs Lakh)	Quantum in Foreign currency	Exchange Rate on draw down date	Amount in Indian Rupee (Rs Lakh)	Quantum in Foreign currency	Exchange Rate on draw down date	Amount in Indian Rupee (Rs Lakh)
1	Loans
1.1	Foreign Loans

1.1.1	[Foreign Loan] [Drawal of debt and equity shall be on pari-passu basis quarter wise to meet the commissioning schedule. Drawal of higher equity in the beginning is permissible]
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.1.2	[Foreign Loan] [Applicable interest rates including reset dates used for above computation may be furnished separately]
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.1.3	[Foreign Loan] [In case of multi unit project details of capitalization ratio used to be furnished.]
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.1.4	- -
	- -
	- -


1.1	Total Foreign Loans
	Draw down Amount
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

1.2	Indian Loans

1.2.1	[Indian Loan] [Drawal of debt and equity shall be on paripassu basis quarter wise to meet the commissioning schedule. Drawal of higher equity in the beginning is permissible]
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1.2.2	[Indian Loan] [Applicable interest rates including reset dates used for above computation may be furnished separately]
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1.2.3	[Indian Loan] [In case of multi unit project details of capitalization ratio used to be furnished.]
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1.2.4	--	--	--	--	--	--	--	--	--	--
	--	--	--	--	--	--	--	--	--	--
	--	--	--	--	--	--	--	--	--	--

1.2	Total Indian Loans
	Draw down Amount	--	--	--	--	--	--	--	--	--
	IDC	--	--	--	--	--	--	--	--	--
	Financing charges	--	--	--	--	--	--	--	--	--

1	Total of Loans drawn
	IDC
	Financing charges
	Foreign Exchange Rate Variation
	Hedging Cost

2	Equity

2.1	Foreign equity drawn

2.2	Indian equity drawn

	Total equity deployed

(Petitioner)Form-13

Breakup of Initial Spares

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

Particulars	Plant & Machinery Cost (excluding IDC andIEDC) Upto DOCO	IDC	IEDC	Year wise additional Capital expenditure up tocut off date	Total Cost	Initial spares claimed
Year-1	Year-2	Year-3	Amount	%
Transmission Line
Transmission Substation (Green Field/ Brown Field)
PLCC
Series Compensation devices
HVDC Station
Gas Insulated Substation
Communication System

Note: - 1. Details to be furnished as per Regulation 13.

2. Corresponding figures of initial spares included in each transmission system may be provided separately.

(Petitioner)Form-14

Other Income as on COD

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

Sl. No.	Parameters	Existing 2013-14	2014-15	2015-16	2016-17	2017-18	2018-19
1	Interest on Loans and advances
2	Income from sale of scrap
3	Misc. receipts (Please Specify Details)
...	...
...	...
...	...(add)

(Petitioner)Form-15

Actual cash expenditure

Name of the Petitioner:	______________________________
Name of the Region:	______________________________
Name of the Project:	______________________________
Name of the Transmission Element or Communication System	______________________________

(Amount in Rs. Lakh)

	Quarter-I	Quarter-II	Quarter-III	Quarter-n (COD)
Payment to contractors/suppliers
% of fund deployment

Note: - If there is variation between payment and fund deployment justification need to be furnished

(Petitioner)

AVo (Availability of o no. of AC lines) =	{\|
o o\|-	∑\| Wi (Ti - TNAi)Ti\| /\| ∑\| Wi\|-	i=1 i=1

AVs (Availability of s no. of HVDC pole) =	{\|
s s\|-	∑\| Wj (Tj - TNAj)Tj\| /\| ∑\| Wj\|-	j=1 j=1

AVq (Availability of q no. of ICTs) =	{\|
q q\|-	∑\| Wk (Tk - TNAk)Tk\| /\| ∑\| Wk\|-	k=1 k=1

AVp (Availability of p no. of Switched Bus reactors) =	{\|
p p\|-	∑\| Wm (Tm - TNAm)Tm\| /\| ∑\| Wm\|-	m=1 m=1

AVt (Availability of t no. of HVDC Back-to-back Blocks) =	{\|
t t\|-	∑\| Wn (Tn - TNAn)Tn\| /\| ∑\| Wn\|-	n=1 n=1

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