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KARNATAKA ELECTRICITY REGULATORY COMMISSION

No. 16, C-1, Millers Tank Bed Area, Vasanth Nagar, Bengaluru, Karnataka 560052

NOTIFICATION

No: KERC/S/2024/61 Date:19.04.2024

Draft Karnataka Electricity Regulatory Commission (Terms and Conditions for

Determination of Generation Tariff) Regulations, 2024.

1. Preamble:

Under Section 181 read with Section 61 and 62 of the Electricity Act, 2003, the Commission

is empowered to specify the terms and conditions for determination of tariff for supplying

power by a generating company to the Distribution Licensees. While specifying the terms

and conditions, the Commission shall be guided by the following:

(a) the principles and methodologies specified by the Central Commission for

determination of the tariff applicable to generating companies and transmission

licensees;

(b) the generation, transmission, distribution and supply of electricity are conducted on

commercial principles;

resources, good performance and optimum investments;

(d) safeguarding of consumers’ interest and at the same time, recovery of the cost of

electricity in a reasonable manner;

(e) the principles rewarding efficiency in performance;

(f) multi-year tariff principles;

(g) that the tariff progressively, reflects the cost of supply of electricity, and also, reduces

cross-subsidies in the manner specified by the Appropriate Commission;

(h) the promotion of co-generation and generation of electricity from renewable

sources of energy;

(i) the National Electricity Policy and tariff policy.

2. CERC has issued regulations specifying the terms and conditions of generation and

transmission tariff vide its Notification dated 15.03.2024. Therefore, in exercise of the power

conferred on it under section 86(1) read with Sections 61 and 62 of the Act, and all the powers

¨sÁUÀ – 3

Part – III

, 25

, 2024(

, 05,

, 1946)

BENGALURU, THURSDAY, 25, APRIL, 2024(VAISHAKHA, 05, SHAKAVARSHA, 1946)

. 234

No. 234

enabling in this behalf, the Commission hereby makes the Draft Regulations, namely

Karnataka Electricity Regulatory Commission (Terms and Conditions for Determination of

Generation Tariff) Regulations, 2024.

3. As required under sub section (3) of section 181 (zi) & (zp) of the Act, and the Electricity

(Procedure for Previous Publication) Rules, 2005, the Commission hereby notifies the Draft

Regulations, for information of the persons and all the stakeholders likely to be affected.

4. Notice is hereby given that the Draft Regulations will be finalized after 30 days from the date

its

publication

the

Official

Gazette,

after

considering

the

comments/suggestions/objections on the draft Regulations submitted by the stakeholders.

Hence, the stakeholders are requested to submit their objections/suggestions/views on the

proposed draft within 30 days from the date of publication of these draft Regulations in the

Official Gazette of Karnataka, to the Secretary of the Commission at the following address:

The Secretary,

Karnataka Electricity Regulatory Commission,

No 16, C-1, Miller Tank Bed Area,

Vasanthanagar,

Bengaluru-560052.

CHAPTER-1

PRELIMINARY

Short title and commencement.

(1)

These Regulations may be called Karnataka Electricity Regulatory Commission

(Terms and Conditions for Determination of Generation Tariff) Regulations, 2024.

(2)

These Regulations shall extend to the whole of the State of Karnataka.

(3)

These Regulations shall come into force from 1st April, 2024 and unless reviewed

earlier or extended by the Commission, shall remain in force up to 31st March,

2029.

Scope and extent of application:

(1) These regulations shall apply in all cases where tariff for a generating station or a unit

thereof achieving commercial operation during the period from 1st April, 2024 up to

31st March, 2029, is required to be determined by the Commission under section 62

of the Act read with section 86 thereof.

Provided that where a project or a part thereof, has been declared to be under

commercial operation before the date of commencement of these Regulations and

whose Tariff has not been finally determined by the Karnataka Electricity Regulatory

Commission till that date, tariff in respect of such generating station or unit thereof:

a) For the period ending 31.03.2014 shall be determined in accordance with the

Karnataka Electricity Regulatory Commission (Terms and Conditions for

Determination of Generation Tariff) Regulations, 2009.

b) For the period ending 31.03.2019 shall be determined in accordance with the

Karnataka Electricity Regulatory Commission (Terms and Conditions for

Determination of Generation Tariff) Regulations 2014.

c) For the period ending 31.03.2024 shall be determined in accordance with the

Karnataka Electricity Regulatory Commission (Terms and Conditions for

Determination of Generation Tariff) Regulations 2019.

(2) These regulations shall not be applicable to;

(a) Generating stations based on renewable sources of energy whose tariff is

determined in accordance with the Karnataka Electricity Regulatory

Commission (Power Procurement from Renewable Sources by Distribution

Licensee) Regulations 2004 as amended from time to time

(b) Generation stations 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.

Definitions. - In these regulations, unless the context otherwise requires: -

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

(2) 'Additional Capital expenditure' means the capital expenditure incurred, or projected

to be incurred after the date of commercial operation of the project by the

generating company in accordance with the provisions of these regulations;

(3) 'Additional Capitalization' means the additional capital expenditure admitted by the

Commission after prudence check, in accordance with these regulations;

(4) 'Admitted capital cost' means the capital cost which has been allowed by the

Commission for servicing through tariff after due prudence check in accordance with

the relevant tariff regulations;

(5) 'Annual Target Quantity' or 'ATQ' in respect of an integrated mine(s) means the

quantity of coal or lignite to be extracted during a year from such integrated mine(s)

corresponding to 85% of the quantity specified in the Mining Plan;

(6) 'Ancillary Service' or 'AS' in relation to power system operation means the service

necessary to support the grid operation in maintaining power quality, reliability and

security of the grid and includes Primary Reserve Ancillary Service, Secondary Reserve

Ancillary Service, Tertiary Reserve Ancillary Service, active power support for load

following, reactive power support, black start and such other services as defined in

the Grid Code;

(7) '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 the

supply of power to the housing colony and other facilities at the generating station and

the power consumed for construction works at the generating station and integrated

mine(s);

Provided further that auxiliary energy consumption for compliance with revised

emission standards, sewage treatment plant and external coal handling plant (jetty

and associated infrastructure) shall be considered separately.

(8) 'Auxiliary energy consumption for emission control system' or 'AUXe' in relation to

a period in the case of coal or lignite based thermal generating station means

the quantum of energy consumed by auxiliary equipment of the emission control

system of the coal or lignite based thermal generating station in addition to the

auxiliary energy consumption under clause (7) of this Regulation;

(9) 'Auditor' means an auditor appointed by a generating company, 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;

(10) 'Beneficiary' in relation to a generating station covered under clauses (a) or (b) of sub-

section 1 of section 79 of the Act, means a distribution licensee who is purchasing

electricity generated at such generating station by entering into a Power Purchase

Agreement either directly or through a trading licensee on payment of capacity

charges and energy charges;

Provided that where the distribution licensee is procuring power through a trading

licensee, the arrangement shall be secured by the trading licensee through back to

back power purchase agreement and power sale agreement.

Provided further that beneficiary shall also include any person who has been

allocated capacity in any inter-State generating station by the Government of India.

(11) 'Capital Cost' means the capital cost as determined in Regulation 19 of these

regulations in respect of generating station, and Regulation 41 of these regulations in

respect of integrated mine(s);

(12) 'Change in Law' means the 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 or treaty

between the Government of India and any other Sovereign Government having

implications for the generating station regulated under these regulations.

(13) 'Commission' means the Karnataka Electricity Regulatory Commission.

(14) '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;

(15) 'Cut-off Date’ shall be the last day of the financial year closing after thirty-six months

from the date of commercial operation of the project, except in case of integrated

mine(s);

(16) 'Date of Commercial Operation' or 'COD' in respect of a thermal generating station or

hydro

generating station shall have the same meaning as defined in the Grid Code, as

amended from time to time:

Provided that Date of Commercial Operation of integrated mine(s) shall have the

same meaning as specified in Regulation 5 of these regulations;

(17) 'Date of Operation' or 'ODe' in respect of an emission control system means the date

of putting the emission control system into use after meeting all applicable technical

and environmental standards, certified through the Management Certificate duly

signed by an authorised person, not below the level of Director of the generating

company;

(18) 'Date of Commencement of Production' in respect of integrated mine(s) means the

date of touching of coal or lignite, as the case may be, as declared by the generating

company;

(19) '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 these

regulations;

(20) 'De-capitalisation' for the purpose of the tariff under these regulations, means a

reduction in Gross Fixed Assets of the project as admitted by the Commission

corresponding to the inter-unit transfer of assets or the assets taken out from service;

(21) 'De-commissioning' means removal from service of a generating station or a unit

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

due to environmental concerns or safety issues or a combination of these factors;

(22) '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;

(23) 'Emission control system' means a set of equipment or devices required to be installed

in a coal or lignite based thermal generating station or unit thereof to meet the revised

emission standards;

(24) 'Existing Project' means the generating station which has been declared under

commercial operation on a date prior to 1.4.2024;

(25) 'Expansion project' shall include any addition of new capacity to the existing

generating station;

(26) 'Expenditure Incurred' means the fund, whether the equity or debt or both, actually

deployed and paid in cash or cash equivalent, for the creation or acquisition of a

useful asset and does not include commitments or liabilities for which no payment has

been released;

(27) 'Extended Life' means the life of a generating station or unit thereof beyond the period

of useful or operational life, as may be determined by the Commission on case to

case basis;

(28) 'Force Majeure' for the purpose of these regulations means the events or

circumstances or

combination of events or circumstances, including those stated below, which prevent

the generating company from completing or operating the project, and only if such

events or circumstances are not within the control of the generating company and

could not have been avoided, had the generating company 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 a 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;

(d)

Delay in obtaining statutory approval for the project except where the delay is

attributable to the project developer;

(29) 'Fuel Supply Agreement' means the agreement executed between the generating

company and the fuel supplier for the generation and supply of electricity to the

beneficiaries;

(30) 'Generating Station' shall have the same meaning as defined under sub-Section 30 of

Section 2 of the Act and, for the purpose of these regulations, shall also include stages

or blocks or units of a generating station;

(31) 'Generating Unit' or '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 or combustion turbine-generator,

associated waste heat recovery boiler, connected steam turbine- generator and

auxiliaries, and in relation to a hydro generating station means turbine-generator and

its auxiliaries;

(32) 'Grid Code' means the Karnataka Electricity Grid Code 2015/Central Electricity

Regulatory Commission (Indian Electricity Grid Code) Regulations, 2023, as amended

from time to time or subsequent re-enactment thereof;

(33) 'Gross Calorific Value' or 'GCV' in relation to a thermal generating station means the

heat produced in kCal by the 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;

(34) 'GCV as Received' means the GCV of coal as measured at the unloading point of the

thermal generating station through collection, preparation and testing of samples

from the loaded wagons, trucks, ropeways, Merry-Go-Round (MGR), belt conveyors

and ships in accordance with the IS 436 (Part-1/ Section 1)- 1964:

Provided that the measurement of coal shall be carried out through sampling by a

third party agency to be appointed by the generating companies in accordance

with the guidelines, if any, issued by the Central Government:

Provided further that samples of coal shall be collected either manually or through

hydraulic augur or through any other method considered suitable, keeping in view

the safety of personnel and equipment:

Provided also that the generating companies may adopt any advanced

technology for the collection, preparation and testing of samples for measurement

of GCV in a fair and transparent manner;

(35) 'Gross Station Heat Rate' or 'SHR' means the heat energy input in kCal required to

generate one kWh of electrical energy at generator terminals of a thermal generating

station;

(36) 'Implementation Agreement' means any agreement or covenant entered into (i)

between the transmission licensee and the generating company or (ii) between the

transmission licensee and developer of the interconnected transmission system for the

execution of generation and transmission projects in a coordinated manner, laying

down the project implementation schedule and mechanism for monitoring the

progress of the projects;

(37) '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 controlled by the Government of India or the Government of State where the

project is located, or quasi-judicial authority constituted under the relevant statutes in

India;

(38) 'Infirm Power' means electricity injected into the grid prior to the date of commercial

operation of a unit of the generating station in accordance with Central Electricity

Regulatory Commission (Indian Electricity Grid Code) Regulations, 2023/ Karnataka

Electricity Grid Code, 2015, as amended from time to time or subsequent re-

enactment thereof;

(39) 'Input Price' means the price of coal or the price of lignite (including transfer price of

lignite in respect of existing lignite mines) sourced from the integrated mines at which

the coal or lignite is transferred to the generating station for the purpose of computing

the energy charges for generation and supply of electricity to the beneficiaries and

determined in accordance with Chapter 9 of these regulations;

(40) '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;

(41) 'Integrated Mine' means the captive mine (allocated for use in one or more

identified generating stations) or basket mine (allocated to a generating company for

use in any of its generating stations) or both being developed by the generating

company or its affiliate for supply of coal or lignite to one or more specified end use

generating stations for generation and sale of electricity to the beneficiaries;

Explanation: Affiliate shall mean a company that is directly controlled and owned by

a generating company having at least twenty six percent (26%) of the voting rights of

the entity.

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

(43) 'Investment Approval' means approval by the Board of the generating company 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 be reckoned from the date of the

resolution of the Board of the generating company where the Board is competent to

accord such approval and from the date of sanction letter of competent authority in

other cases;

Provided further that in respect of the integrated mine(s), funding and timeline for

implementation shall be indicated separately and distinctly in the Investment

Approval;

Provided further that where investment approval includes both the generating station

and the integrated mine(s), the funding and timeline for implementation of the

integrated mine(s) shall be worked out and indicated separately and distinctly in the

Investment Approval.

(44) 'Landed Fuel Cost’ means the total cost of coal (including biomass in case of co firing),

lignite or the gas/naphtha/liquid fuel delivered at the unloading point of the

generating station and shall include the base price or input price, washery charges

wherever applicable, transportation cost (overseas or inland or both) and handling

cost, charges for third party sampling and applicable statutory charges;

(45) 'Loading Point' in respect of integrated mine(s) means the location of railway siding or

silo or the coal handling plant or such other arrangements like a conveyor belt,

whichever is nearest to the mine, for despatch of coal or lignite, as the case may be;

(46) '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;

(47) 'Mine Infrastructure' shall include assets of the integrated mine(s) such as tangible

assets used for mining operations, being civil works, workshops, immovable winning

equipment,

foundations,

embankments,

pavements,

electrical

systems,

communication systems, relief centers, site administrative offices, fixed installations,

handling arrangements, crushing and conveying systems, railway sidings, pits, shafts,

inclines, underground transport systems, hauling systems (except movable equipment

unless the same is embedded in land for permanent beneficial enjoyment thereof),

land demarcated for afforestation and land for rehabilitation and resettlement of

persons affected by mining operations under the relevant law;

(48) 'Mining Plan' or 'Mine Plan' in respect of integrated mine(s) means a plan prepared in

accordance with the Guidelines for Preparation, Formulation, Submission, Processing,

Scrutiny, Approval and Revision of Mining Plan for the coal and lignite block issued by

the Ministry of Coal, Government of India as amended from time to time or provisions

of the Mineral Concession Rules, 1960, as amended from time to time and approved

under clause (b) of sub-section (2) of section 5 of the Mines and Minerals

(Development and Rehabilitation) Act, 1957 by the Central Government or by the

State Government, as the case may be;

(49) 'New Project' means the generating station or unit thereof achieving its commercial

operation on or after 1.4.2024;

(50) 'Non-Pit Head Generating Station' or 'Non-Pit Head Power Plant' means coal and lignite

based generating stations other than Pit Head Generating Stations.

(51) '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, maintenance, repairs and maintenance spares, other

spares of capital nature valuing up to Rs. 10 lakhs, additional capital expenditure of

an individual asset costing less than Rs. 20 lakhs, consumables, insurance and

overheads and fuel other than used for generation of electricity:

Provided that for integrated mine(s), the Operation & Maintenance Expenses shall not

include the mining charge paid to the Mine Developer and Operator, if any, engaged

by the generating company and the mine closure expenses.

(52) 'Original Project Cost' means the capital expenditure incurred by the generating

company, within the original scope of the project up to the cut-off date, and as

admitted by the Commission;

(53) 'Peak Rated Capacity' in respect of integrated mine(s) means the peak rated

capacity of the mine, as specified in the Mining Plan;

(54) 'Pit Head Generating Station' or 'Pit Head Power Plant' means as defined under The

Environment (Protection) Rules, 1986.

(55) '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 auxiliary

energy consumption and auxiliary energy consumption for emission control system as

per these regulations;

(56) 'Plant Load Factor' or '(PLF)' in relation to a thermal generating station or unit thereof

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:

PLF - 10000 x

,^%

Where,

Installed Capacity of the generating station or unit in MW,

SGi

Scheduled Generation in MW for the i^th time block of the

period,

Number of time blocks during the period,

AUXn =

Normative auxiliary energy consumption as a percentage

of gross energy generation; and

AUXen =

Normative auxiliary energy consumption for emission control system as a

percentage

of gross energy generation, wherever applicable.

(57) 'Procedure Regulations' means KERC (General & Conduct of Proceedings)

Regulations, 2000

(58) 'Project' means:

in the case of a thermal generating station, all components of the thermal

generating station and including an integrated coal mine, biomass pellet

handling system, pollution control system, and effluent treatment plan, as may

be required;

ii)

in the case of a hydro generating station, all components of the hydro generating

station including the dam, intake water conductor system, power generating

station, as apportioned to power generation.

(59) 'Prudence Check' means scrutiny of the reasonableness of any cost or expenditure

incurred or proposed to be incurred in accordance with these regulations by the

generating company;

(60) 'Pumped Storage Hydro Generating Station' means a hydro generating station which

generates power through energy stored in the form of water energy, pumped from a

lower elevation reservoir to a higher elevation reservoir;

(61) 'Rated Voltage' means as specified in the Grid Code;

(62) ' Rate of Interest' means the one-year marginal cost of funds based lending rate

(MCLR) of the State Bank of India (SBI) issued from time to time plus 250 basis points;

(63) 'Revised Emission Standards' in respect of thermal generating station means the

revised

norms notified as per Environment (Protection) Amendment Rules, 2015 or any other

Rules as may be notified from time to time;

(64) 'Run-of-River Generating Station' means a hydro generating station which does not

have upstream pondage;

(65) 'Run-of-River Generating Station with Pondage' means a hydro generating station with

sufficient pondage for meeting the diurnal variation of power demand;

(66) 'Scheduled Commercial Operation Date' or 'SCOD' shall mean the date(s) of

commercial operation of a generating station or generating unit thereof as indicated

in the Investment Approval or as agreed in power purchase agreement whichever is

earlier;

(67) '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;

(68) 'Scheduled Generation' or 'Scheduled injection' for a time block or any period means

the schedule of generation or injection in MW or MWh ex-bus, including the schedule

for Ancillary Services given by the concerned Load Despatch Centre in accordance

with the Grid Code;

(69) 'Schedule Drawal' for a time block or any period means the schedule of drawal in MW

or MWh ex-bus, including the schedule for Ancillary Services given by the concerned

Load Despatch Centre;

(70) 'Small Gas Turbine Generating Station' means and includes open cycle gas turbine

combined cycle generating station with gas turbines in the capacity range of 50 MW

or below;

(71) 'Start Date or Zero Date' means the date indicated in the Investment Approval for

commencement of implementation of the project, and where no such date has been

indicated, the date of Investment Approval shall be deemed to be Start Date or Zero

Date;

(72) 'Statutory Charges' means and includes taxes, cess, duties, royalties and other charges

levied through Acts of the Parliament or State Legislatures or by Indian Government

Instrumentality under relevant statutes;

(73) 'Storage Type Generating Station' means a hydro generating station associated with

storage capacity to enable variation of generation of electricity according to

demand;

(74) '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 a

combination of these as its primary source of energy or co-firing of biomass with coal;

(75) 'Trial Run' in relation to the generating station shall have the same meaning as

specified in Regulation 22 of Grid Code;

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

of the Act;

(77) 'Unloading Point' means the point within the premises of the coal or lignite based

thermal generating station where the coal or lignite is unloaded from the rake or truck

or any other mode of transport;

(78) 'Useful Life' in relation to a unit of a generating station, integrated mines, from the date

of commercial operation shall mean the following:

(a)

Coal/Lignite based thermal generating station

25 years

(b)

Gas/Liquid fuel based thermal generating

station

25 years

(c)

Hydro generating station including pumped

storage hydro generating stations

40 years

(d)

Integrated mine(s)

As per the Mining Plan

Provided that in the case of coal/lignite based thermal generating stations and

hydro generating stations, the Operational Life may be 35 years and 50 years,

respectively.

The words and expressions used in these regulations and not defined herein but

defined in the Act or any other regulations of the Commission, shall have the meaning

assigned to them under the Act or any other regulations of the Commission.

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

(1)

'Day' means a calendar day consisting of 24 hours period starting at 0000 hours;

(2)

'kCal' means a unit of heat energy contents in mineral, measured in one kilo

calories or one thousand calories of heat produced at any instantaneous period;

(3)

'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;

(4)

'Quarter' means the period of three months commencing on the first day of April,

July, October and January of each financial year in case of an existing project,

and in case of a new project, in respect of the first quarter, from the date of

commercial operation to the last day of June, September, December or March,

as the case may be;

(5)

'Tonne' means a metric tonne of coal or lignite in respect of integrated mine(s);

(6)

'Year' means a financial year beginning on 1^st April and ending on 31^st March:

Provided that the first year in case of a new project or integrated mine(s) shall

commence from the date of commercial operation and end on the immediately

following 31^st March.

(7)

Reference to any Act, Rules, and Regulations shall include amendment or

consolidation or re-enactment thereof.

CHAPTER – 2

DATE OF COMMERCIAL OPERATION

Date of Commercial Operation:

(1) The date of commercial operation of a generating station or unit thereof shall be

determined in accordance with the provisions of the Grid Code.

(2) The date of commercial operation in case of integrated mine(s), shall mean the earliest

of: -

a) the first date of the year succeeding the year in which 25% of the Peak Rated

Capacity as per the Mining Plan is achieved; or

b) the first date of the year succeeding the year in which the value of production

estimated in accordance with Regulation 7 of these regulations, exceeds total

expenditure in that year; or

c) the date of two years from the date of commencement of production:

Provided that on the earliest occurrence of any of the events under sub-clauses (a)

to (c) of Clause (2) of this Regulation, the generating company shall declare the date

of commercial operation of the integrated mine(s) under the relevant sub-clause

with one-week prior intimation to the beneficiaries of the end-use or associated

generating station(s);

Provided further that in case the integrated mine(s) is ready for commercial

operation but is prevented from declaration of the date of commercial operation

for reasons not attributable to the generating company or its suppliers or

contractors or the Mine Developer and Operator, the Commission, on an

application made by the generating company, may approve such other date as

the date of commercial operation as may be considered appropriate after

considering the relevant reasons that prevented the declaration of the date of

commercial operation under any of the sub- clauses of Clause (2) of this Regulation;

Provided also that the generating company seeking the approval of the date of

commercial operation under the preceding proviso shall give prior notice of one

month to the beneficiaries of the end-use or associated generating station(s) of the

integrated mine(s) regarding the date of commercial operation.

Sale of Infirm Power: Supply of infirm power shall be in accordance with the Central

Electricity Regulatory Commission (Deviation Settlement Mechanism and Related

matters) Regulations, 2022, amended from time to time ,till such time a separate

Regulations are issued by the Commission.

Provided that any revenue earned by the generating company from the supply of

infirm power after accounting for the fuel expenses shall be applied in adjusting the

capital cost accordingly.

Supply of Coal or Lignite prior to the Date of Commercial Operation of Integrated Mine:

The input price for the supply of coal or lignite from the integrated mine(s) prior to their

date of commercial operation shall be:

(a) in the case of coal, the estimated price available in the investment approval, or

the notified price of Coal India Limited for the corresponding grade of coal

supplied to the power sector, whichever is lower; and

(b) in the case of lignite, the estimated price available in the investment approval or

the last available pooled lignite price as determined by the Commission for the

transfer price of lignite, whichever is lower:

Provided that any revenue earned from the supply of coal or lignite prior to the date

of commercial operation of the integrated mine(s) shall be applied in adjusting the

capital cost of the said integrated mine(s).

CHAPTER-3

PROCEDURE FOR TARIFF DETERMINATION

Tariff determination

(1) Tariff in respect of a generating station and emission control system, wherever

applicable, may be determined for the whole of the generating station or unit thereof

Provided that:

(i)

In case of commercial operation of all the units of a generating station prior to

1.4.2024, the generating company, shall file a consolidated petition in respect of the

entire generating station for the purpose of determination of tariff for the period from

1.4.2024 to 31.3.2029:

(ii) In case of commercial operation of units of generating station on or after 01.04.2024,

the generating company shall file a consolidated petition, in accordance with the

provisions of the procedure Regulations, combining all the units of the generating

station which are anticipated to achieve commercial operation during the next two

months from the date of application.

(iii) The generating company shall file an application for determination of supplementary

tariff for the emission control system installed in a coal or lignite based thermal

generating station in accordance with these regulations not later than 90 days from

the date of operation of such emission control system.

(2) Where only a part of the generation capacity of a generating station is tied up for

supplying power to the beneficiaries through a long term power purchase agreement,

the units for such part capacity shall be clearly identified and, in such cases, the tariff

shall be determined for such identified capacity. Where the unit(s) corresponding to

such part capacity cannot be identified, the tariff of the generating station may be

determined with reference to the capital cost of the entire project, but the tariff so

determined shall be applicable corresponding to the part capacity contracted for

supply to the beneficiaries.

(3) In case of expansion of the existing generating station, the tariff shall be determined

for the expanded capacity in accordance with these regulations:

Provided that the common infrastructure of the existing generating station, shall be

utilized for the expanded capacity and the benefit of new technology in the

expanded capacity, as determined by the Commission, shall be extended to the

existing capacity.

(4) Assets installed for implementation of the revised emission standards shall form part of

the existing generation project, and the tariff thereof shall be determined separately

in accordance with the application filed under the 5^th proviso to Clause (1) of

Regulation 9 of these Regulations.

(5) Energy charge component of the tariff of the generating station getting coal or lignite

from the integrated mine shall be determined based on the input price of coal or

lignite, as the case may be, from such integrated mines:

Provided that the generating company shall maintain the account of the integrated

mine separately and submit the cost of the integrated mine, in accordance with

these regulations, duly certified by the Auditor.

(6) Tariff of generating station using coal washery rejects developed by Central or State

PSUs or Joint Venture between a Government Company and a company other than

a Government Company shall be determined in accordance with these regulations:

Provided that in case of a Joint Venture between a Government Company and a

Company other than the Government Company, the shareholding of the company

other than the Government Company either directly or through any of its subsidiary

companies or associate companies shall not exceed 26% of the paid up share capital:

Provided further that the energy charge component of the tariff of such generating

station or unit thereof shall be determined based on the fixed cost and the variable

cost of the coal washery project:

Provided also that the Gross Calorific Value of coal rejects shall be measured jointly

by the generating company and the beneficiaries.

(7) In the case of 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 the determination of tariff.

Application for determination of tariff

(1) The generating company may make an application for determination of tariff for a

new generating station or unit thereof in accordance with these Regulations within 90

days from the actual date of commercial operation:

Provided further that the generating company shall submit an Auditor Certificate

and, in case of non-availability of an Auditor Certificate, a Management Certificate

duly signed by an authorised person, not below the level of Director of the company

indicating the estimated capital cost incurred as on the date of commercial

operation and the projected additional capital expenditure for respective years of

the tariff period 2024-29:

Provided that for a new generating station or unit thereof the applicant, through a

specific prayer in its application filed under Regulation 9(1) of these regulations, may

plead for an interim tariff, and the Commission may consider granting interim tariff

from the date of commercial operation after the first hearing of the application and

where such interim tariff of the generating station or unit thereof has been

determined based on Management Certificate, the generating company shall

submit the Auditor Certificate not later than 90 days from the date of Commercial

Operation:

Provided also that the generating company shall file an application for

determination of supplementary tariff for the emission control system installed in coal

or lignite based thermal generating station in accordance with these regulations not

later than 90 days from the date of start of operation of such emission control system.

(2) In case of an existing generating station or unit thereof, the application shall be made

by the generating company by 30.11.2024 , based on admitted capital cost including

additional capital expenditure already admitted and incurred up to 31.3.2024 (either

based on actual or projected additional capital expenditure) and estimated

additional capital expenditure for the respective years of the tariff period 2024-29

along with the true up petition for the period 2019-24 in accordance with the KERC,

Karnataka Electricity Regulatory Commission (Terms and Conditions for Determination

of Generation Tariff) Regulations, 2019.

(3) In case an emission control system is required to be installed in the existing generating

station or unit thereof to meet the revised emission standards, an application shall

be made for the determination of supplementary tariff (capacity charges or energy

charge or both) based on the actual capital expenditure duly certified by the Auditor.

(4) Where the generating company has the arrangement for the supply of coal or lignite

from an integrated mine(s) to one or more of its generating stations, the generating

company shall file a petition for determination of the input price of coal or lignite for

determining the energy charge along with the tariff petitions for one or more

generating stations in accordance with the provision of Chapter 9 of these

regulations:

Provided that a generating company with integrated mine(s) shall file a petition for

determination of the input price of coal or lignite from the integrated mine(s) not later

than 90 days from the date of actual commercial operation of the integrated mine(s)

in accordance with these regulations.

(5) If the information in application and the Forms is inadequate as required under these

regulations, the application shall be returned to the generating company for

resubmission within one month after rectifying the defects as may be pointed out by

the Commission.

(6) Within thirty working days of the receipt of corrected and completed tariff application,

the Commission shall notify the generating company as to whether any additional

information is required by the Commission to assess the generating company's

calculations and to carryout prudence check of the claims made specifying the date

by which such information is to be filed.

(7) If the information furnished as called by the Commission is adequate, the tariff

application filed by the generating company will be treated as a petition after the

Commission decides that all the information and clarification sought have been

produced to the satisfaction of the Commission.

(8) The Commission will thereafter follow, as far as may be practicable, the procedure

specified in Chapter-2 of the KERC (General and Conduct of Proceedings)

Regulations, 2000, for holding hearing on the tariff application and for passing orders

thereon.

10.

Determination of tariff

(1) The generating company for a specific generating station or unit thereof or for an

integrated mine as the case may be, shall file a petition before the Commission as per

Annexure-I to these regulations containing the details of underlying assumptions for

the capital expenditure and additional capital expenditure incurred and projected

to be incurred, wherever applicable.

(2) If the petition is deficient in any respect as required under Annexure-I to these

regulations, the application shall be returned to the generating company for

resubmission of the petition within one month of the date of return of the application

after rectifying the deficiencies as may be pointed out by the staff of the Commission.

(3) If the information furnished in the petition is in accordance with these regulations, the

Commission may consider granting an interim tariff of up to ninety per cent (90%) of

the tariff claimed in the case of a new generating station or unit thereof during the

first hearing of the application for billing purposes till the final tariff is determined by

the Commission:

Provided that in case the final tariff determined by the Commission is lower than the

interim tariff by more than 10%, the generating company shall return the excess

amount recovered from the beneficiaries or long term customers, as the case may

be, with simple interest at 1.20 times of the rate worked out on the basis of 1 year SBI

MCLR plus 100 basis points prevailing as on 1^st April of the financial year in which such

excess recovery was made.

(4) In the case of the existing projects, the generating company, shall continue to bill the

beneficiaries at the capacity charges, as approved by the Commission and

applicable as on 31.3.2024 for the period starting from 1.4.2024 till approval of final

capacity charges by the Commission in accordance with these regulations:

Provided that the billing for energy charges w.e.f. 1.4.2024 shall be as per the

operational norms specified in these regulations.

(5) The Commission shall grant the final tariff in the case of existing and new projects after

considering the replies received from the respondents and suggestions and objections,

if any, received from the general public and any other person permitted by the

Commission, including consumers or consumer associations.

(6) Subject to Sub-Clause (7) below, the difference between the tariff determined in

accordance with clauses (3) and (5) above and clauses (4) and (5) above, shall be

recovered from or refunded to, the beneficiaries or the long term customers, as the

case may be, with simple interest at the rate equal to the 1 year SBI MCLR plus 100 basis

points prevailing as on 1^st April of the respective year of the tariff period, in a maximum

of six equal monthly instalments;

Provided that the bills to recover or refund shall be raised by the generating

company within 45 days from the issuance of the Order.

Provided further that such interest, including that determined as per sub-clause (7)

of this regulation shall be payable till the date of issuance of the Order and no interest

shall be allowed or levied during the period of six-monthly instalments.

Provided further that in case where money is to be refunded and there is a delay in

the raising of bills by the generating company beyond 45 days from the issuance of

the Order, it shall attract a late payment surcharge as applicable in accordance with

these regulations.

(7) Where the capital cost approved by the Commission on the basis of projected

additional capital expenditure exceeds the actual trued up additional capital

expenditure incurred on a year to year basis by more than 10%, the generating

company shall refund to the beneficiaries or the long term customers as the case may

be, the tariff recovered corresponding to the additional capital expenditure not

incurred, as approved by the Commission, along with simple interest at 1.20 times of

the rate worked out on the basis of 1 year SBI MCLR plus 100 basis points as prevalent

on 1^st April of the respective year.

PUBLICATION OF THE PETITION:

The Generating Company shall arrange for publication of the tariff application in the

following manner.

a) The summary of the tariff application, in such format as may be approved by the

Commission, shall be published in two successive issues each of two daily newspapers

in English language and two daily newspapers in Kannada language having wide

circulations in the area of operation of the generating company. The advertisement

shall invite the licensees/ interested persons to file their objections and such

documents as they seek to rely upon, supported by an affidavit, in six copies, within

30 working days of the first advertisement.

b) The generating company shall also indicate in the advertisement that interested

persons may inspect the copies of the petition at specified offices of the generating

company during normal working hours and/or also obtain the salient features of the

petition at such specified place on payment of an amount not exceeding the cost of

photo copying, before the last date fixed for filing of objections.

c) The generating company shall also mention in the advertisement that a full set of the

application together with supporting materials would be made available to any

interested person who may ask for it on payment of an amount, not exceeding the

cost of photocopying.

d) The generating company shall provide, along application to the Commission, the

details in such formats as may be required by the Commission. The generating

company shall necessarily provide unit-wise and station-wise details as envisaged in

the formats to enable the Commission to determine tariff as required.

e) The generating company shall furnish to the Commission all such material, books and

records including the accounting statements, operational cost data as may be

required by the Commission for determination of tariff.

f) The generating company shall host all the details of the petition filed before the

Commission on its website not later than three working days of its acceptance by the

Commission. The generating company shall also host the information on the

observations made by the Commission and the replies submitted to the Commission

thereon, within three working days of submission of replies to the Commission.

11. In-principle approval in specific circumstances: The generating company for a specific

generating station or for an integrated mine undertaking any additional capitalization

on account of change in law events or force majeure conditions may file petition for

in-principle approval for incurring such expenditure after prior notice to the beneficiaries

or the long term customers, as the case may be, along with underlying assumptions,

estimates and justification for such expenditure if the estimated expenditure exceeds

10% of the admitted capital cost of the project or Rs.100 Crore, whichever is lower.

12. Truing up of tariff for the period 2019-24: The tariff of the generating stations, integrated

mines, for the period 2019-24 shall be trued up in accordance with the provisions of

Regulation 13 of the Karnataka Electricity Regulatory Commission (Terms and

Conditions for Determination of Generation Tariff) Regulations, 2019 along with the tariff

petition for the period 2024-29. The capital cost admitted as on 31.3.2024 based on the

truing up shall form the basis of the opening capital cost as on 1.4.2024 for the tariff

determination for the period 2024-29.

13. Truing up of tariff for the period 2024-29: (1) The Commission shall carry out the truing up

exercise for the period 2024-29, along with the tariff petition filed for the next tariff

period, for the following:

the capital expenditure, including additional capital expenditure incurred up to

31.03.2029 as admitted by the Commission after prudence checks at the time of

truing up;

b) the capital expenditure, including additional capital expenditure incurred up to

31.03.2029 on account of Force Majeure and Change in Law as admitted by the

Commission;

the additional capital expenditure incurred up to 31.03.2029 on account of the

Emission Control System as admitted by the Commission.

(2) The input price of coal or lignite from the integrated mine(s) of the generating station(s)

for the tariff period 2024-29 shall be trued up for:

a) The capital expenditure, including additional capital expenditure incurred up to

31.03.2029 as admitted by the Commission after prudence check at the time of

truing up;

b) the capital expenditure, including additional capital expenditure incurred up to

31.03.2029

on account of Force Majeure and Change in Law, as admitted by the Commission.

c) The Operation and Maintenance expenses in accordance with provisions of

Regulation 46 of these Regulations.

(3) The generating company for a specific generating station or for an integrated mine,

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 thereof by 30.11.2029.

(4) The generating company for a specific generating station or for an integrated mine,

may make an application for interim truing up of tariff in the year 2026-27 if the annual

fixed cost increases by more than 20% over the annual fixed cost as determined by

the Commission for the respective years of the tariff period:

Provided that if the actual additional capital expenditure falls short of the projected

additional capital expenditure allowed under provisions of Chapter 7 of these

regulations or reduction of tariff on account of change in the rate of interest on loan

or income tax rate, the generating company shall not be required to file any interim

true up petition for this purpose and shall refund to the beneficiaries, as the case may

be, the excess tariff recovered corresponding to the projected additional capital

expenditure not incurred or on account of change in the rate of interest on loan or

income tax rate, in the same manner as specified in Regulation 10(6) and 10(7) of

these regulations, as the case may be under intimation to the Commission:

Provided further that the generating company shall submit the complete details

along with the calculations of the refunds made to the beneficiaries, as the case may

be, at the time of true up.

(5) After truing up, if the tariff or the input price already recovered exceeds or falls short

of the tariff or the input price approved by the Commission under these regulations,

the generating company shall refund to or recover from, the beneficiaries or the long

term customers, as the case may be, the excess or the shortfall amount, in accordance

with Regulation 10(6) and 10(7) of these regulations as may be applicable.

Provided that in case of input price of coal and lignite, the generating company shall

refund such excess amount or recover the shortfall amount from the beneficiaries

based on scheduled energy.

CHAPTER- 4

TARIFF STRUCTURE

14. Components of Tariff: (1) The tariff for the 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 15 of these regulations)

and energy charge (for recovery of primary and secondary fuel cost and cost of

limestone and any other reagent, where applicable as specified in Regulation 16 of

these regulations).

(2)

The Supplementary tariff consisting of supplementary capacity charges and

supplementary energy charges, on account of the implementation of revised

emission standards in existing generating stations or new generating stations, as

the case may be, shall be determined by the Commission separately.

(3)

The capacity charge and energy charge of a generating station shall be

determined in accordance with the provisions of Chapter 11 of these regulations.

The input price of coal or lignite from the integrated mine, as determined in

accordance with the provisions of Chapter 9 of these regulations, shall form part

of the energy charge of the generating station.

(4)

The tariff for the supply of electricity from a hydro generating station shall comprise

a capacity charge and an energy charge to be derived in the manner specified

in Regulation 65 or 66 of these regulations, as may be applicable, for recovery of

the annual fixed cost consisting of the components referred to in Regulation 15 of

these regulations.

15. Capacity Charges: (1) The capacity charges shall be derived on the basis of annual

fixed costs. The Annual Fixed Cost (AFC) of a generating station 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 with

Regulation 28 of these regulations, shall be recovered separately and shall not be

considered for computation of working capital.

(2) Supplementary Capacity Charges: Supplementary capacity charges shall be derived

on the basis of the Annual Fixed Cost for emission control system (AFCe). The Annual

Fixed Cost for the emission control system shall consist of the components as listed in

Sub-clauses (a) to (e) of Clause

(1) of this Regulation.

16. 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 costs:

(a) Landed Fuel Cost of primary fuel;

(b) Cost of secondary fuel oil consumption; and

Provided that any refund of taxes and duties along with any amount received on

account of

penalties from the fuel supplier shall be adjusted in fuel cost:

Provided further that the supplementary energy charges, if any, on account of

meeting the revised emission standards in case of a thermal generating station shall

be determined separately by the Commission as per Regulation 64 of these

regulations.

Provided also that in case of supply of coal or lignite from the integrated mine(s),

the landed cost of primary fuel shall be based on the input price of coal or lignite,

as the case may be, as computed in accordance with these regulations.

17. Special Provisions for Tariff for Thermal Generating Station which have Completed 25

Years of Operation from Date of Commercial Operation: In respect of a thermal

generating station that has completed 25 years of operation from the date of

commercial operation and the power purchase agreement for supply of electricity to

beneficiaries from such generating station is not extended, the generating company

and the beneficiary may agree on an arrangement, including provisions for target

availability and incentive, where in addition to the energy charge, capacity charges

determined under these regulations shall also be recovered based on scheduled

generation.

CHAPTER – 5

CAPITAL STRUCTURE

18. Debt-Equity Ratio: (1) For new projects, the debt-equity ratio of 70:30 as on date of

commercial operation shall be considered. 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:

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 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 utilized for meeting the capital expenditure of the generating station.

(2) The generating company shall submit the resolution of the Board of the company or

the approval of the competent authority in other cases regarding the infusion of funds

from internal resources in support of the utilization made or proposed to be made to

meet the capital expenditure of the generating station

(3) In the case of the generating station declared under commercial operation prior to

1.4.2024, the debt-equity ratio allowed by the Commission for the determination of

tariff for the period ending 31.3.2024 shall be considered:

Provided that in the case of a generating station which has completed its useful life

as on 1.4.2024 or is completing its useful life during the 2024-29 tariff period, if the

equity actually deployed is more than 30% of the capital cost, equity in excess of

30% shall not be taken into account for tariff computation;

(4) In the case of the generating station declared under commercial operation prior to

1.4.2024, but where debt: equity ratio has not been determined by the Commission

for determination of tariff for the period ending 31.3.2024, the Commission shall

approve the debt: equity ratio in accordance with clause (1) of this Regulation.

(5) Any expenditure incurred or projected to be incurred on or after 1.4.2024 as may be

admitted by the Commission as additional capital expenditure for determination of

tariff, and renovation and modernization expenditure for life extension shall be

serviced in the manner specified in clause (1) of this Regulation.

(6) Any expenditure incurred for the emission control system during the tariff period as may

be admitted by the Commission as additional capital expenditure for determination

of supplementary tariff, shall be serviced in the manner specified in clause (1) of this

Regulation.

CHAPTER-6

COMPUTATION OF CAPITAL COST

19. Capital Cost:

(l) The Capital cost of the generating station as determined by the Commission after

prudence checks in accordance with these regulations shall form the basis for the

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 and, in the event actual equity is in excess of 30%

on a pari-passu basis, by treating the excess equity over and above 30% of the

funds deployed as a normative loan, or (ii) being equal to the actual amount of

the loan in the event of actual equity being less than 30% of the funds deployed;

loan amount availed during the construction period;

(d) Interest during construction and incidental expenditure during construction as

computed in accordance with these regulations;

(e) Capitalised initial spares subject to the ceiling rates in accordance with these

regulations;

(f)

Expenditure on account of additional capitalization and de-capitalisation

determined in accordance with these regulations;

(g) Adjustment of revenue due to the sale of infirm power in excess of fuel cost prior

to the date of commercial operation as specified under Regulation 6 of these

regulations;

(h) Capital expenditure on account of ash disposal and utilization including handling

and transportation facility;

(i) Capital expenditure incurred towards railway infrastructure and its augmentation

for transportation of coal up to the receiving end of the generating station but does

not include the transportation cost and any other appurtenant cost paid to the

railway;

(j) Capital expenditure on account of biomass handling equipment and facilities, for

co-firing;

(k) Capital expenditure on account of emission control system necessary to meet

the revised emission standards and sewage treatment plant;

(l) Expenditure on account of the fulfilment of any conditions for obtaining

environment clearance for the project;

(m) Expenditure on account of change in law and force majeure events; and

(n) Capital cost incurred or projected to be incurred by a thermal generating station,

on account of implementation of the norms under the Perform, Achieve and Trade

(PAT) scheme of the Government of India shall be considered by the Commission

subject to sharing of benefits accrued under the PAT scheme with the

beneficiaries.

(o) Expenditure required to enable flexible operation of the generating station at lower

loads.

(3)

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

(a) Capital cost admitted by the Commission prior to 1.4.2024 duly trued up by

excluding liability, if any, as on 1.4.2024;

(b) Additional capitalization and de-capitalization for the respective year of tariff as

determined in accordance with these regulations;

by this Commission in accordance with these regulations;

(d) Capital expenditure on account of ash disposal and utilization, including

handling and transportation facility;

(e) Capital

expenditure

incurred

towards

railway

infrastructure

and

its

augmentation for transportation of coal up to the receiving end of generating

station but does not include the transportation cost and any other appurtenant

cost paid to the railway;

(f) Capital cost incurred or projected to be incurred by a thermal generating

station, on account of implementation of the norms under the Perform, Achieve

and Trade (PAT) scheme of the Government of India shall be considered by the

Commission subject to sharing of benefits accrued under the PAT scheme with

the beneficiaries;

(g) Expenditure required to enable flexible operation of the generating station at lower

loads;

(h) Capital expenditure on account of biomass handling equipment and facilities,

for co- firing; and

(i) Expenditure on account of change in law and force majeure events;

(4)

The capital cost in case of existing or new hydro generating stations 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 the Rajiv Gandhi Grameen

Vidyutikaran Yojana (RGGVY) and Deendayal Upadhyaya Gram Jyoti Yojana

(DDUGJY) project in the affected area.

incurred towards developing local infrastructure in the vicinity of the power plant

not exceeding Rs. 10 lakh/MW shall be considered as part of the Capital cost, and

in case the same work is covered under budgetary support provided by the

Government of India, the funding of such works shall be adjusted on receipt of

such funds.

Provided that such funds shall be allowed only if the funds are spent through

Indian Governmental Instrumentality;

(5)

For Projects acquired through NCLT proceedings under the Insolvency and Bankruptcy

Code, 2016, the following shall be considered while approving Capital Costs for the

determination of tariff:

(a) For projects already under operation, historical GFA of the project acquired or

the acquisition cost paid by the generating company, whichever is lower;

(b) For considering the historical GFA for the purpose of Sub-Clause (a) above, the

same shall be the capital cost approved by the appropriate commission till the

date of acquisition;

Provided that in the absence of any prior approved capital cost of an Appropriate

Commission, the Commission shall consider the same on the basis of audited accounts

subject to prudence check;

Provided further, that in case additional capital expenditure is required post

acquisition of an already operational project, the same shall be considered under

the provisions of Chapter 7 of these Regulations;

commercial

operation, the acquisition cost or the actual audited cost incurred till the date of

acquisition, whichever is lower, shall be considered and;

(d) any additional capital expenditure incurred post acquisition of such project up

to the date of commercial operation of the project in line with the investment

approval of the Board of Directors of the generating company shall also be

considered on a case to case basis subject to prudence check.

Provided that post commercial operation, additional capital expenditure shall

be allowed under the provisions of Chapter 7 of these Regulations.

(6)

The following shall be excluded from the capital cost of the existing and new projects:

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

(b) De-capitalised Assets after the date of commercial operation on account of

obsolescence;

another project:

Provided that in case such an asset is recommended for further utilisation by the

Regional Power Committee in consultation with CTU, such asset shall be de-

capitalised from the original project only after its redeployment;

Provided further that unless shifting of an asset from one project to another is of a

permanent nature, there shall be no de-capitalization of the concerned assets.

(d) In the case of hydro generating stations, 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 transparent process;

(e) Proportionate cost of land of the existing generation, which is being used for

generating power from a generating station based on renewable energy as may

be permitted by the Commission; and

(f) Any grant received from the Central or State Government or any statutory body or

authority for the execution of the project that does not carry any liability of

repayment.

20. Prudence Check of Capital Cost: The following principles shall be adopted for

prudence check of capital cost of the existing or new projects:

a. In the case of the thermal generating station the prudence check of capital cost

shall include scrutiny of the capital expenditure, in light of the capital cost of similar

projects based on past historical data, wherever available, reasonableness of the

financing plan, interest during construction, incidental expenditure during

construction, use of efficient technology, cost over-run and time over-run,

procurement of equipment and materials through competitive bidding as given in

Regulation 101 below and such other matters as may be considered appropriate by

the Commission:

Provided that, while carrying out the prudence check, the Commission shall also

examine whether the generating company has been prudent in its judgments and

decisions in the execution of the project.

b. The Commission may, for the purpose of vetting of capital cost of hydro generating

stations, appoint an independent agency or an expert body.

c. Where the power purchase agreement entered into between the generating

company and the beneficiaries provide, for the ceiling of actual capital

expenditure, the Commission shall take into consideration such ceiling for

prudence check.

d. The generating company shall furnish the capital cost for the execution of the

existing and new projects as per Annexure-I to these regulations along with tariff

petition for the purpose of creating a database of benchmark capital cost of various

components.

21. Interest During Construction (IDC) and Incidental Expenditure during Construction

(IEDC)

(1) Interest during construction (IDC) shall be computed considering the actual loan and

normative loan after taking into account the prudent phasing of funds up to actual

COD:

Provided that IDC on a normative loan corresponding to excess equity over 30% of

funds deployed shall be allowed only in cases where the actual infusion of equity on

a pari-passu basis is more than 30% of total funds deployed and shall be computed

on a quarterly basis.

Provided further that in case IDC on normative loan is to be allowed prior to infusion of

actual loan, rate of interest for computing such IDC shall be equal to 1-year SBI MCLR

as prevailing on 1^st April of the respective year.

Provided further that IDC on normative loan, post infusion of actual loan shall be

computed based on Weighted Average Rate of Interest (WAROI) for that respective

quarter.

(2) Incidental expenditure during construction (IEDC) shall be computed from the zero

date, taking into account pre-operative expenses up to actual COD:

Provided that any revenue earned during the construction period up to actual COD

on account of interest on deposits or advances or any other receipts shall be taken

into account for reduction in incidental expenditure during construction.

(3) In case of additional costs on account of IDC and IEDC due to delay in achieving the

COD, the generating company for a specific generating station or for an integrated

mine shall be required to furnish detailed justifications with supporting documents for

such delay, including prudent phasing of funds in the case of IDC and details of IEDC

during the period of delay and liquidated damages recovered or recoverable

corresponding to the delay.

(4) If the delay in achieving the COD is not attributable to the generating company such

additional IDC and IEDC may be allowed after a prudence check, and the liquidated

damages, if any, recovered from the contractor or supplier or agency shall be

adjusted to the capital cost of the generating station

(5) If the delay in achieving the COD is attributable either in entirety or in part to the

generating company or supplier or agency, in such cases, IDC and IEDC due to such

delay may be disallowed after a prudence check, either in entirety or on a pro-rata

basis corresponding to the period of delay not condoned vis-à-vis total

implementation period, and the liquidated damages, if any, recovered from the

contractor or supplier or agency shall be retained by the generating company in the

same proportion of delay not condoned vis-à-vis total implementation period.

[Note: For e.g.: In case a project was scheduled to be completed in 48 months and is

actually completed in 60 months. Out of 12 months of time overrun, if only 6 months

of time overrun is condoned, the allowable IDC and IEDC shall be computed by

considering the total IDC and IEDC incurred for 60 months and allowed in the

proportion of 54 months over 60 month period.]

Provided that in cases where delay in achieving COD is beyond six months from SCOD

on account of delay in obtaining approval of any of the following activities namely, i)

forest clearance, ii) NHAI clearance, or iii) Railways permission, a time overrun

maximum up to 95% shall be allowed after prudence check.

(6) For the purpose of Clauses (4) and (5) of this Regulation, IDC on actual loan and

normative loan shall be considered in accordance with the normative debt-equity

ratio specified under clause (1) of Regulation 18 of these regulations.

22. Controllable and Uncontrollable factors: The following shall be considered as

controllable and uncontrollable factors for deciding time overrun, cost escalation, IDC

and IEDC of the new projects:

a. The "controllable factors" shall include but shall not be limited to the following:

i. Efficiency in the implementation of the new projects not involving an

approved change in scope of such new projects or change in statutory

levies or change in law or force majeure events; and

ii. Delay in execution of the new projects on account of contractor or

supplier or agency of the generating company .

b. The "uncontrollable factors" shall include but shall not be limited to the following:

i. Force Majeure events;

ii. Change in Law; and

iii. Land acquisition except where the delay is attributable to the generating

company

23. Initial Spares: Initial spares shall be capitalised as a percentage of the Plant and

Machinery

cost, subject to the 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 -

hydro generating station

4.0%

Provided that:

Plant and Machinery cost shall be considered as the original project cost excluding

IDC, IEDC, Land Cost and Cost of Civil Works. The generating company for the

purpose of estimating Plant and Machinery Costs, shall submit the break-up of head-

wise IDC and IEDC in its tariff application;

ii.

where the generating station has any transmission equipment forming part of the

generation project, the ceiling norms for initial spares for such equipment shall be as

per the ceiling norms specified for the transmission system under these regulations.

iii.

where the emission control system is installed, the norms of initial spares specified in

this Regulation for coal or lignite based thermal generating stations, as the case may

be, shall apply.

CHAPTER – 7

COMPUTATION OF ADDITIONAL CAPITAL EXPENDITURE

24. Additional Capitalization within the original scope and up to the cut-off date

(1) The additional capital expenditure in respect of a 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:

(a)

Payment made towards admitted liabilities for works executed up to the cut-off

date;

(b)

Works deferred for execution;

(c)

Procurement of initial capital spares within the original scope of work, in

accordance with the provisions of Regulation 23 of these regulations;

(d)

Payment against the award of arbitration or for compliance with the directions

or order of any statutory authority or order or decree of any court of law;

(e)

Change in law or compliance with any existing law which is not provided for in

the original scope of work;

(f)

For uninterrupted and timely development of Hydro projects, expenditure

incurred towards developing local infrastructure in the vicinity of the power

plant not exceeding Rs. 10 lakh/MW shall be considered as part of capital cost

and in case the same work is covered under budgetary support provided by

Government of India, the funding of such works shall be adjusted on receipt of

such funds;

Provided that such expenditure shall be allowed only if the expenditure is

incurred through Indian Governmental Instrumentality; and

(g)

Force Majeure events.

Provided that in case of any replacement of the assets, the additional capitalization

shall be worked out after adjusting the gross fixed assets and cumulative depreciation

of the assets replaced on account of de-capitalization.

(2)

The generating company shall submit 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.

25.

Additional Capitalization within the original scope and after the cut-off date:

The additional capital expenditure incurred or projected to be incurred in respect

of an existing project or a new project on the following counts within the original

scope of work and after the cut-off date may be admitted by the Commission,

subject to prudence check:

(a)

Payment made against award of arbitration or for compliance with the directions

or order of any statutory authority, or order or decree of any court of law;

(b)

Change in law or compliance with any existing law which is not provided for

in the original scope of work;

(c)

Deferred works relating to ash pond or ash handling system or raising of ash

dyke in the original scope of work;

(d)

Payment made towards liability admitted for works within the original scope

executed prior to the cut-off date;

(e)

Force Majeure events;

(f)

Works within original scope executed after the cut-off date and admitted

by the Commission, to the extent of actual payments made; and

In case of replacement of assets deployed under the original scope of the existing

project after the cut-off date, the additional capitalization may be admitted by the

Commission after making necessary adjustments in the gross fixed assets and the

cumulative depreciation, subject to prudence check on the following grounds:

(a)

Assets whose useful life is not commensurate with the useful life of the project

and such assets have been fully depreciated in accordance with the

provisions of these regulations;

(b)

The replacement of the asset or equipment is necessary on account of a

change in law or Force Majeure conditions;

(c)

The replacement of such asset or equipment is necessary on account of

obsolescence of technology; and

(d)

The replacement of such asset or equipment has otherwise been allowed

by the Commission.

(e)

The additional expenditure, excluding recurring expenses covered in O&M

expenses, involved in relation to the renewal of lease of lease hold land on

case to case basis.

Provided that any claim of additional capitalisation with respect to the replacement

of assets under the original scope and on account of obsolescence of technology,

less than Rs. 20 lakhs shall not be considered as part of Capital cost and shall be met

through normative O&M expenses.

26.

Additional Capitalisation beyond the original scope

(1) The capital expenditure, in respect of the existing generating station incurred or

projected to be incurred on the following counts beyond the original scope, may be

admitted by the Commission, subject to prudence check:

(a)

Payment made against award of arbitration or for compliance of order or

directions of any statutory authority, or order or decree of any court of law;

(b)

Change in law or compliance of any existing law;

(c)

Force Majeure events;

(d)

Need for higher security and safety of the plant as advised or directed by

appropriate

Indian

Government

Instrumentality

statutory

authorities

responsible for national or internal security;

(e)

Deferred works relating to ash pond or ash handling system or raising of ash dyke

in addition to the original scope of work, on case to case basis:

Provided also that if any expenditure has been claimed under Renovation

and Modernisation (R&M) or repairs and maintenance under O&M expenses, the

same shall not be claimed under this Regulation;

(f)

Usage of water from the sewage treatment plant in the thermal generating station.

(g) Works required towards biomass handling system to enable biomass co-firing and

towards enabling flexible operation of the generating station as may be required.

(h) Works pertaining to Railway Infrastructure and its augmentation for transportation

of coal up to the receiving end of the generating station (excluding any

transportation cost and any other appurtenant cost paid to railways) that are not

covered under Regulation 24, 25 and 27, but shall result in better fuel management

and can lead to a reduction in operation costs, or shall have other tangible

benefits:

Provided that the generating company shall have to mandatorily seek prior

approval of the Commission before implementing such works based on a

detailed cost-

benefit analysis of such schemes;

(i)

Any additional capital expenditure which has become necessary for efficient

operation of generating station including the works required towards projects

acquired through NCLT process. The claim shall be substantiated with the technical

justification and cost benefit analysis.

(2) Any claim of additional capitalisation less than Rs. 20 lakhs shall not be considered

under Clause (1) of this regulation and shall be met through normative O&M expenses.

(3) In case of de-capitalisation of assets of a generating company, the original cost of

such asset as on the date of de-capitalisation 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 with corresponding adjustments in cumulative depreciation and cumulative

repayment of loan, duly taking into consideration the year in which it was capitalised.

Provided that in cases where an asset forming part of a scheme is de-capitalised and

wherein the historical value of such asset is not available, the value of de-capitalisation

shall be computed by de-escalating the value of the new asset by 5% per year until

the year of capitalisation of the old asset subject to a minimum of 10% of the

replacement cost of the asset.

27.

Additional Capitalisation on account of Renovation and Modernisation

(1)

The generating company intending to undertake renovation and modernization

(R&M) of the generating station or unit thereof for the purpose of extension of life

beyond the originally recognized useful life for the purpose of tariff, shall file a petition

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.

Provided that the generating company making the applications for renovation and

modernization (R&M) shall not be eligible for Special Allowance under Regulation 28

of these regulations;

Provided further that the generating company intending to undertake renovation

and modernization (R&M) shall seek the consent of the beneficiaries for such

renovation and modernization (R&M) and submit the response of the beneficiaries

along with the Petition.

(2)

Where the generating company, as the case may be, makes an application for

approval of its proposal for renovation and modernisation (R&M), approval may be

granted after due consideration of the reasonableness of the proposed cost

estimates, financing plan, schedule of completion, interest during construction, use of

efficient technology, cost-benefit analysis, expected duration of life extension, the

response of the beneficiaries or long term customers, and such other factors as may

be considered relevant by the Commission.

(3)

In the case of gas/ liquid fuel based open/ combined cycle thermal generating

station after 25 years of operation from the date of commercial operation, any

additional capital expenditure which has become necessary for the renovation of

gas turbines/ steam turbines or additional capital expenditure necessary due to

obsolescence or the non-availability of spares for efficient operation of the stations

may be allowed subject to a prudence check:

Provided that any expenditure included in the renovation and modernisation (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 turbines shall be suitably

deducted from the expenditure to be allowed after prudence check.

(4)

After completion of the renovation and modernisation (R&M), the generating

company, as the case may be, shall file a petition for determination of tariff.

Expenditure incurred or projected to be incurred and admitted by the Commission

after a prudence check and after deducting the accumulated depreciation

already recovered from the admitted project cost shall form the basis for the

determination of tariff.

28.

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

(1) In the case of coal-based/ lignite fired thermal generating stations, the generating

company, instead of availing renovation and modernization (R&M), may opt to avail

of a 'special allowance' in accordance with the norms specified in this Regulation, as

compensation for meeting the requirement of expenses towards any additional

capital expenditure covered in Regulations 24, 25, 26 and 27 except for capital

expenditure arising out of change in law, award of arbitration or for compliance of

the directions or order of any statutory authority, or order or decree of any court of

law, and force majeure after completion of 25 years from the date of Commercial

operation of the generating station or a unit thereof and in such an event, an upward

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

thereof for which renovation and modernization has been undertaken and the

expenditure has been admitted by the Commission before the 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;

Provided further that special allowance shall also be available for a generating

station which has availed the Special Allowance during the tariff period 2009-14

or 2014-19 or 2019-24 as applicable from the date of completion of the useful life.

(2) The Special Allowance admissible to a generating station shall be at Rs 10.75 lakh per

MW per year for the tariff period.

(3) In the event of a generating station availing of Special Allowance, the expenditure

incurred upon or utilized from Special Allowance shall be maintained separately by

the generating station, and details of the same shall be made available to the

Commission as and when directed.

(4) The Special Allowance allowed under this Regulation shall be transferred to a

separate fund for utilization towards Renovation & Modernisation and additional

capitalisation as per clause (1) above, and the expenditure incurred or utilized from

the special allowance shall be made available to the Commission as and when

directed.

29.

Additional Capitalization on account of Revised Emission Standards:

(1) A generating company requiring to incur additional capital expenditure in the

existing generating station for compliance with the revised emissions standards

shall share its proposal with the beneficiaries and file a petition for undertaking

such additional capitalization.

(2) The proposal under clause (1) above shall contain details of the proposed

technology as specified by the Central Electricity Authority, scope of the work,

phasing of expenditure, schedule of completion, estimated completion cost

including foreign exchange component, if any, detailed computation of indicative

impact on tariff to the beneficiaries, and any other information considered to be

relevant by the generating company.

(3) Where the generating company makes an application for approval of additional

capital expenditure on account of the implementation of revised emission

standards, the Commission may grant approval after due consideration of the

reasonableness of the cost estimates, financing plan, schedule of completion,

interest during construction, use of efficient technology, cost- benefit analysis, and

such other factors as may be considered relevant by the Commission.

(4) After completion of the implementation of revised emission standards, the

generating company shall file a petition for determination of tariff. Any expenditure

incurred or projected to be incurred and admitted by the Commission after

prudence check based on the reasonableness of the cost and impact on

operational parameters shall form the basis of the determination of tariff.

(5) Un-discharged liability, if any, on account of the emission control system shall be

allowed as additional capital expenditure during the year it is discharged, subject to

prudence check.

CHAPTER-8

COMPUTATION OF ANNUAL FIXED COST

30.

Return on Equity:

(1) Return on equity shall be computed in rupee terms, on the equity base determined in

accordance with Regulation 18 of these regulations.

(2) Return on equity for existing project shall be computed at the base rate of 15.00% for

thermal generating station, and run-of- river hydro generating station and at the

base rate of 15.50% for storage type hydro generating stations, pumped storage

hydro generating stations and run-of- river generating station with pondage;

(3) Return on equity for new project achieving COD on or after 01.04.2024 shall be

computed at the base rate of 15.00% for Thermal generating station and run-of-river

hydro generating station and at the base rate of 15.50% for storage type hydro

generating stations, pumped storage hydro generating stations and run-of-river

generating station with pondage;

Provided that return on equity in respect of additional capitalization beyond the

original scope, including additional capitalization on account of the emission control

system, Change in Law, and Force Majeure shall be computed at the weighted

average rate of interest on actual loan portfolio of he generating station subject to

maximum ceiling of 14%.

Provided further that;

In case of a new project, the rate of return on equity shall be reduced by 1.00%

for such period as may be decided by the Commission if the generating

station is found to be declared under commercial operation without

commissioning of any of the Free Governor Mode Operation (FGMO), data

telemetry, communication system up to load dispatch centre or protection system

based on the report submitted by the respective SLDC;

ii.

in case of an existing generating station, as and when any of the requirements

under (i) above of this Regulation are found lacking based on the report submitted

by the concerned SLDC, the rate of return on equity shall be reduced by 1.00% for

the period for which the deficiency continues;

iii. in the case of a thermal generating station:

rate of return on equity shall be reduced by 0.25% in case of failure to

achieve the ramp rate as specified under Regulation 45(9) of IEGC

Regulations, 2023.

an additional rate of return on equity of 0.125% shall be allowed for every

incremental ramp rate of 0.50% per minute achieved over and above the

ramp rate specified by Central Electricity Authority, subject to the ceiling of

additional rate of return on equity of 1.00%:

31.

Tax on Return on Equity.

(1) The rate of return on equity as allowed by the Commission under Regulation

30 of these regulations shall be grossed up with the effective tax rate of the

respective financial year. The effective tax rate 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 concerned generating company by

excluding the income of non-generation and the corresponding tax thereon

including deferred tax liability.

Provided that in case a generating company is paying Minimum Alternate Tax

(MAT) under Section 115JB of the Income Tax Act, 1961, the effective tax rate

shall be the MAT rate, including surcharge and cess;

Provided further that in case a generating company has opted for Section

115BAA, the effective tax rate shall be tax rate including surcharge and cess as

specified under Section 115BAA of the Income Tax Act, 1961.

(2)

The 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)

(3)

The generating company, shall true up the effective tax rate for 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 2024-29 on actual gross

income of any financial year. Further, any penalty arising on account of delay in

deposit or short deposit of tax amount shall not be considered while computing the

actual tax paid for the generating company

Provided that in case a generating company is paying Minimum Alternate Tax

(MAT) under Section 115JB, the generating company shall true up the grossed up

rate of return on equity at the end of every financial year with the applicable MAT

rate including surcharge and cess.

Provided that in case a generating company is paying tax under Section 115BAA,

the generating company shall true up the grossed up rate of return on equity at the

end of every financial year with the tax rate including surcharge and cess as

specified under Section 115BAA.

Provided that 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 customers, as the case may be, on a year to year basis.

32. Interest on loan capital:

(1) The loans arrived at in the manner indicated in Regulation 18 of these

regulations shall be considered gross normative loans for the calculation of

interest on loans.

(2) The normative loan outstanding as on 1.4.2024 shall be worked out by

deducting the cumulative repayment as admitted by the Commission up to

31.3.2024 from the gross normative loan.

(3) The repayment for each of the years of the tariff period 2024-29 shall be

deemed to be equal to the depreciation allowed for the corresponding year

or period. In case of de-capitalization 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

up to the date of de-capitalisation of such asset.

(4) Notwithstanding any moratorium period availed of by the generating

company the repayment of the 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 or allocated loan portfolio;

Provided that if there is no actual loan outstanding for a particular year but the

normative loan is still outstanding, the last available weighted average rate of

interest of the loan portfolio for the project shall be considered;

Provided further that if the generating station does not have any actual loan,

then the weighted average rate of interest of the loan portfolio of the generating

company as a whole shall be considered.

Provided that the rate of interest on the loan for the installation of the emission

control system commissioned subsequent to date of commercial operation of the

generating station or unit thereof, shall be the weighted average rate of interest

of the actual loan portfolio of the emission control system, and in the absence of

the actual loan portfolio, the weighted average rate of interest of the generating

company as a whole shall be considered, subject to a ceiling of 14%;

Provided further that if the generating company does not have any actual loan,

then the rate of interest for a loan shall be considered as 1-year MCLR of the

State Bank of India as applicable as on April 01, of the relevant financial year.

(6) The interest on the loan shall be calculated on the normative average loan

of the year by applying the weighted average rate of interest.

(7) The changes to the terms and conditions of the loans shall be reflected from

the date of such re-financing.

33.

Depreciation:

(1) Depreciation shall be computed from the date of commercial operation of a

generating station or unit thereof. In the case of the tariff of all the units of a

generating station 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 taking into consideration the depreciation of individual

units:

Provided that the 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 for which a 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, the weighted average life for the generating station shall be applied.

Depreciation shall be chargeable from the first year of commercial operation. In

the case of commercial operation of the asset for a part of the year, depreciation

shall be charged on a pro rata basis.

(3) The salvage value of the asset shall be considered as 10%, and depreciation shall

be allowed up to the maximum of 90% of the capital cost of the asset:

Provided that the salvage value for IT equipment and software shall be considered

as NIL and 100% value of the assets shall be considered depreciable;

Provided further that in the case of hydro generating stations, the salvage value

shall be as provided in the agreement, if any, signed by the developers with the

State Government for the development of the generating station:

Provided also 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 the 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 unit, as the case may be, shall not be allowed to be

recovered at a later stage during the useful life or the extended life.

(4) Land other than the land held under lease and the land for a reservoir in case of

a hydro generating station shall not be a depreciable asset and its cost shall be

excluded from the capital cost while computing the depreciable value of the

asset.

(5) Depreciation for Existing Projects shall be calculated annually based on the

Straight Line Method and at rates specified in Appendix-I to these regulations for

the assets of the generating station:

Provided that the remaining depreciable value as on 31^st March of the year closing

after a period of 12 years from the effective date of commercial operation of the

generating station , as the case may be, shall be spread over the balance useful

life of the assets.

Provided further that in the case of an existing hydro generating station, the

generating company, with the consent of the beneficiaries, may charge

depreciation at a rate lower than that specified in Appendix I and Appendix II to

these Regulations to reduce front loading of tariff.

(6) Depreciation for New Projects shall be calculated annually based on the Straight

Line Method and at rates specified in Appendix-II to these regulations for the assets

of the generating station:

Provided that the remaining depreciable value as on 31^st March of the year closing

after a period of 15 years from the effective date of commercial operation of the

generating station , as the case may be, shall be spread over the balance useful

life of the assets.

Provided further that in the case of a new hydro generating stations, the generating

company, with the consent of the beneficiaries, may charge depreciation at a rate

lower than that specified in Appendix II to these Regulations to reduce front loading

of tariff.

(7) In the case of the existing projects, the balance depreciable value as on

1.4.2024 shall be worked out by deducting the cumulative depreciation as

admitted to by the Commission up to 31.3.2024 from the gross depreciable value

of the assets.

(8) The generating company shall submit the details of capital expenditure proposed

to be incurred during five years before the completion of useful life along with

proper justification and proposed life extension. The Commission, based on

prudence check of such submissions, shall approve the depreciation by equally

spreading the depreciable value over the balance Operational Life of the

generating station or unit thereof or fifteen years, whichever is lower.

(9) In case of de-capitalization of assets in respect of generating station or unit

thereof the cumulative depreciation shall be adjusted by taking into account the

depreciation recovered in tariff by the de-capitalised asset during its useful

service.

(10) Where the emission control system is implemented within the original scope of the

generating station and the date of commercial operation of the generating

station or unit thereof and the date of operation of the emission control system are

the same, depreciation of the generating station or unit thereof including the

emission control system shall be computed in accordance with Clauses (1) to (9)

of this Regulation.

(11) Depreciation of the emission control system of an existing generating station that

is yet to complete its useful life or a new generating station or unit thereof where

the date of operation of the emission control system is subsequent to the date of

commercial operation of the generating station or unit thereof, shall be

computed annually from the date of operation of such emission control system

based on the straight line method at rates specified in Appendix- I to these

regulations;

Provided that the remaining depreciable value as on 31^st March of the year closing

after a period of 12 years from the date of operation of such emission control system

shall be spread over the balance period of thirteen years or balance operational

life of generating station, whichever is lower;

Provided also that in case the date of operation of the emission control system is after

the 20^th year of commercial operation of the generating station or unit thereof, but

before the completion of the useful life of the generating station, the depreciation

on emission control system (ECS) shall be computed annually from the date of

operation of such ECS based on the straight line method, with a salvage value of

10% and the depreciable value shall be recovered till the operational life of the

generating station.

(12) In case the date of operation of the emission control system is subsequent to the

date of completion of the useful life of generating station commercial operation

of the generating station or unit thereof, depreciation of ECS shall be computed

annually from the date of operation of such emission control system based on the

straight line method, with a salvage value of 10% and recovered over ten years

or a period mutually agreed by the generating company and the beneficiaries,

whichever is higher.

34.

Interest on Working Capital: (1) The working capital shall cover:

(a)

For Coal-based/lignite-fired thermal generating stations:

(i) Cost of coal or lignite, if applicable, for 10 days for pit-head generating

stations and 20 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) Limestone towards stock for 15 days corresponding to the normative annual

plant availability.

(iii) Advance payment for 30 days towards the cost of coal or lignite and

limestone for generation corresponding to the normative annual plant

availability factor;

(iv) 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;

(v) Maintenance spares @ 20% of operation and maintenance expenses,

including water charges and security expenses;

(vi) Receivables equivalent to 45 days of capacity charge and energy charge for

the sale of electricity calculated on the normative annual plant availability

factor; and

(vii) Operation and maintenance expenses, including water charges and security

expenses, for one month.

(b)

For emission control system of coal or lignite based thermal generating stations:

(i)

Cost of limestone or reagent towards stock for 20 days corresponding to the

normative annual plant availability factor;

(ii) Advance payment for 30 days towards the cost of reagent for generation

corresponding to the normative annual plant availability factor;

(iii) Receivables equivalent to 45 days of supplementary capacity charge and

supplementary energy charge for the sale of electricity calculated on the

normative annual plant availability factor;

(iv) Operation and maintenance expenses in respect of the emission control

system for one month;

(v) Maintenance spares @20% of operation and maintenance expenses in

respect of emission control system.

(c)

For Open-cycle Gas Turbine/Combined Cycle thermal generating stations:

(i) Fuel cost for 15 days corresponding to the normative annual plant availability

factor, duly taking into account the 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;

Provided that the above shall only be allowed to generating stations that have

facilities to store liquid fuel.

(iii) Maintenance spares at 30% of operation and maintenance expenses,

including water charges and security expenses;

(iv) Receivables equivalent to 45 days of capacity charge and energy charge for

the sale of electricity calculated on the normative plant availability factor,

duly taking into account the mode of operation of the generating station on

gas fuel and liquid fuel;

(v) Operation and maintenance expenses, including water charges and security

expenses, for one month.

(d)

For Hydro generating station (including Pumped Storage Hydro generating station)

(i)

Receivables equivalent to 45 days of annual fixed cost;

(ii)

Maintenance spares at 15% of operation and maintenance expenses including

security expenses; and

(iii) Operation and maintenance expenses, including security expenses for one

month.

(2) The cost of fuel in cases covered under sub-clauses (a) and (c) of clause (1) of this

Regulation shall be based on the landed fuel cost (taking into account normative

transit and handling losses in terms of Regulation 59 of these regulations) by the

generating station and gross calorific value of the fuel as per actual weighted

average for the preceding financial year in case of each financial year for which tariff

is to be determined:

Provided that in the case of a new generating station, the cost of fuel for the first

financial year shall be considered based on landed fuel cost (taking into account

normative transit and handling losses in terms of Regulation 59 of these regulations)

and gross calorific value of the fuel as per actual weighted average for three

months, as used for infirm power, preceding date of commercial operation for which

tariff is to be determined.

(3) Rate of interest on working capital shall be on a normative basis and shall be

considered at the Rate of Interest as on 1.4.2024 or as on 1^st April of the year during

the tariff period 2024-29 in which the generating station or a unit thereof or the as

the case may be, is declared under commercial operation, whichever is later:

Provided that in case of truing-up, the rate of interest on working capital shall be

considered at Rate of Interest as on 1st April of each of the financial year during the

tariff period 2024-29.

(4) Interest on working capital shall be payable on a normative basis, notwithstanding

that the generating company has not taken a loan for working capital from any

outside agency.

35.

De-Commissioning

1. In case a generating station or unit thereof, after it is certified by CEA or CTU or

any other statutory authority, that any asset cannot be operated or needs to be

replaced on account of environmental concerns or safety issues or system

upgradation or a combination of these factors not attributable to generating

company the unrecovered depreciable value may be allowed to be recovered

on a case-to-case basis after duly adjusting the salvage value or realization value,

whichever is higher, post disposal of such project.

Provided that the manner of recovery, including a number of instalments in

which such unrecovered depreciation will be allowed, shall be specified by the

Commission on a case-to-case basis.

Provided further that no carrying cost shall be allowed on any delay associated

with such recovery.

36.

Operation and Maintenance Expenses:

(1) Thermal Generating Station: Normative Operation and Maintenance expenses of

thermal generating stations shall be as follows:

(1) Coal based and lignite fired (including those based on Circulating Fluidised Bed

Combustion (CFBC) technology) generating stations, other than the generating

stations or units referred to in clauses (2), (4) and (5) of this Regulation:

(in Rs Lakh/MW)

Year

200/210/

250

Series

300/330/

350

Series

500 MW

Series

600 MW

Series

800 MW

Series

and

above

FY 2024-25

40.92

34.04

27.17

25.78

23.20

FY 2025-26

43.07

35.83

28.60

27.13

24.42

FY 2026-27

45.33

37.71

30.10

28.56

25.70

FY 2027-28

47.71

39.69

31.68

30.06

27.05

FY 2028-29

50.21

41.78

33.34

31.64

28.47

Provided also that operation and maintenance expenses of generating station having

a unit size of less than 200 MW not covered above shall be determined on a case-to-case

basis.

(2)

Open Cycle Gas Turbine/Combined Cycle generating stations:

(in Rs Lakh/MW)

Year

Gas Turbine Combined

Cycle generating

stations other than

small gas turbine

power generating

stations

Agartal

a GPS

Small gas

turbine

power

generating

stations and

Tripura Gas

Station

Advance

F Class

Machines

FY 2024-25

18.18

56.48

47.86

32.08

FY 2025-26

19.14

59.44

50.37

33.77

FY 2026-27

20.14

62.57

53.02

35.54

FY 2027-28

21.20

65.85

55.80

37.40

FY 2028-29

22.32

69.31

58.73

39.37

(3)

Lignite-fired generating stations:

(in Rs Lakh/MW)

Year

125 MW Sets

FY 2024-25

38.81

FY 2025-26

40.85

FY 2026-27

42.99

FY 2027-28

45.25

FY 2028-29

47.62

(4)

Generating Stations based on coal rejects:

(in Rs Lakh/MW)

Year

O&M Expenses

FY 2024-25

38.81

FY 2025-26

40.85

FY 2026-27

42.99

FY 2027-28

45.25

FY 2028-29

47.62

(5)

The Water Charges, Security Expenses, Ash Transportation Expenses and Capital

Spares for thermal generating stations shall be allowed separately after prudence

check:

Provided that water charges shall be allowed based on water consumption

depending upon type of plant and type of cooling water system or water

agreement with state govt./utilities, and the norms specified by the Ministry of

Environment, Forest and Climate Change subject to prudence check. The details

regarding the same shall be furnished along with the petition;

Provided further that the generating station shall submit the assessment of the

security requirement and estimated expenses along with the petition seeking the

determination of tariff;

Provided also that the generating station shall submit the details of year-wise actual

capital spares consumed individually costing above Rs. 10 Lakh at the time of truing

up with appropriate justification for incurring the same and substantiating that the

same is not funded through compensatory allowance as per Regulation 17 of

Karnataka

Electricity

Regulatory

Commission (Terms and Conditions for

Determination of generation Tariff) Regulations, 2014 or Special Allowance or

claimed as a part of additional capitalization or consumption of stores and spares

and renovation and modernization.

(6)

Any additional O&M expenses incurred by the generating company due to any

change in law shall be considered at the time of truing up of tariff.

Provided that such impact shall be allowed only in case the overall impact of such

change in law event in a year is more than 5% of normative O&M expenses of the

project allowed for the year.

(7)

In the case of a generating company owned by the Central or State Government,

the impact on account of implementation of wage or pay revision shall be allowed

at the time of truing up of tariff.

(8)

The operation and maintenance expenses on account of emission control systems

in coal or lignite based thermal generating stations shall be 2% of the admitted

capital expenditure (excluding IDC and IEDC) as on its date of operation, which

shall be escalated annually at 5.25% during the tariff period ending on 31^st March

2029:

Provided that income generated from the sale of gypsum or other by-products

shall be reduced from the operation and maintenance expenses.

(2)

Hydro Generating Station:

Following operations and maintenance expense norms shall be applicable for

hydro generating stations which have been operational for three or more years as

on 1.4.2019: Note: The impact in respect of revision of minimum wage, pay revision

and GST, if any, will be considered at the time of determination of tariff.

a) In the case of the hydro generating stations declared under commercial operation

on or after 1.4.2024, operation and maintenance expenses of the first year shall be

fixed at 3.5% and

5.0% of the original project cost (excluding the cost of rehabilitation & resettlement

works, IDC and IEDC) for stations with installed capacity exceeding 200 MW and for

stations with installed capacity less than or equal to 200 MW, respectively and shall

be subject to annual escalation of 5.47% per annum for the subsequent years.

b) In the case of hydro generating stations which have not completed a period of three

years as on 1.4.2024, operation and maintenance expenses for 2024-25 shall be

worked out by applying an escalation rate of 5.47% on the applicable operation

and maintenance expenses as on 31.3.2024. The operation and maintenance

expenses for subsequent years of the tariff period shall be worked out by applying

an escalation rate of 5.47% per annum.

c) The Security Expenses, Capital Spares and Insurance expenses arrived through

competitive bidding for hydro generating stations shall be allowed separately after

prudence check:

Provided that the generating station shall submit the assessment of the security

requirement, capital spares and insurance expenses along with its estimated

expenses, which shall be trued up based on the details of year-wise actual capital

spares consumed, actual insurance and security expenses incurred with

appropriate justification.

Provided further that the value of capital spares exceeding Rs. 10 lakh shall only

be considered for reimbursement at the time of truing up with appropriate

justification for incurring the same and substantiating that the same is not claimed

as a part of additional capitalisation or consumption of stores and spares and

renovation and modernization.

d) Any additional O&M expenses incurred by the generating company due to any

change in law event shall be considered at the time of truing up of tariff.

Provided that such impact shall be allowed only in case the overall impact of such

change in law event in a year is more than 5% of normative O&M expenses of the

project for the year.

e) In the case of a generating company owned by the Central or State Government,

the impact on account of implementation of wage or pay revision shall be allowed

at the time of truing up of tariff;

CHAPTER – 9

COMPUTATION OF INPUT PRICE OF COAL AND LIGNITE FROM INTEGRATED MINE

37.

Input Price of coal and lignite for energy charges:

(1) Where the generating company has the arrangement for supply of coal or lignite

from the integrated mine(s) allocated to it for use in one or more of its generating

stations as end use, the energy charge component of tariff of the generating

station shall be determined based on the input price of coal or lignite, as the case

may be, from such integrated mines in accordance with these regulations.

(2)

The generating company shall, after the date of commercial operation of the

integrated mine(s) till the input price of coal is determined by the Commission

under these regulations, adopt the notified price of Coal India Limited

commensurate with the grade of the coal from the integrated mine(s) or the

estimated price available in the investment approval, whichever is lower, as the

input price of coal for the generating station:

Provided that the difference between the input price of coal determined under

these regulations and the input price of coal so adopted prior to such

determination, the quantity of coal billed shall be adjusted in accordance with

Clause (4) of this Regulation.

(3)

The generating company shall, after the date of commercial operation of the

integrated mine(s), till the input price of lignite is determined by the Commission

under these regulations, fix the input price of lignite for the generating station at

the last available pooled lignite price as determined by the Commission for

transfer price of lignite or the estimated price available in the investment

approval, whichever is lower:

Provided that the difference between the input price of lignite determined under

these regulations and the input price of lignite so fixed prior to such determination, for

the quantity of lignite billed, shall be adjusted in accordance with Clause (4) of this

Regulation.

(4)

In case of excess or short recovery of input price under Clauses (2) or (3) of this

Regulation, the generating company shall refund the excess amount or recover

the shortfall amount, as the case may be, with simple interest at the rate equal

to 1-year SBI MCLR plus 100 basis points prevailing as on 1^st April of the respective

year of the tariff period, in six equal monthly instalments.

Provided that such interest shall be payable till the date of issuance of the Order

and no interest shall be allowed or levied during the period of six-monthly

instalments.

Provided that in case there is a delay in filing the Petition for determination of input

price as per the timelines specified under Regulation 9 of these regulations, no

carrying cost shall be allowed to the generating company or the mining company

for such delay and in such cases the carrying cost at the simple interest rate of 1-

year SBI MCLR plus 100 bps shall be allowed from the date of filing of the Petition.

38.

Input Price of coal or Lignite:

(1) Input price of coal or lignite from the integrated mine(s) shall be determined based

on the following components:

Run of Mine (ROM) Cost; and

II)

Additional charges:

a. crushing charges;

b. transportation charge within the mine up to the washery end or coal

handling plant associated with the integrated mine, as the case may

be;

c. handling charges at mine end;

d. washing charges; and

e. transportation charges beyond the washery end or coal handling plant,

as the case may be, and up to the loading point:

Provided that one or more components of additional charges may be applicable in

the case of the integrated mine(s), based on the scope and nature of the mining

activities;

Provided further that the input price of lignite shall be computed based on Run of Mine

(ROM) based on the technology such as bucket excavator-conveyor or belt-

spreader or its combination and handling charges, if any.

(2) Statutory Charges, as applicable, shall be allowed.

39.

Run of Mine (ROM) Cost:

(1) Run of Mine Cost of coal in case of integrated mine(s) allocated through an

auction route under the Coal Mines (Special Provisions) Act, 2015 shall be worked out

as under:

ROM Cost = (Quoted Price of coal) + (Fixed Reserve Price)

Where,

(i)

The Quoted Price of coal is the Final Price Offer of coal in respect of the

concerned coal block or mine, along with subsequent escalation, if any,

as provided in the Coal Mine Development and Production Agreement:

Provided that additional premium, if any, quoted by the generating

company during auction shall not be considered in the Run of Mine Cost;

(ii)

Fixed Reserve Price is the fixed reserve price per tonne along with

subsequent escalation, if any, as provided in the Coal Mine

Development and Production Agreement: and

(iii)

Capital cost under Regulation 41 and additional capital expenditure

under

Regulation 42 shall not be admissible for the purpose of ROM cost in

respect of integrated mine(s) allocated through the auction route.

(2) Run of Mine Cost of coal in case of integrated mine allocated through allotment route

under Coal Mines (Special Provisions) Act, 2015 shall be worked out as under:

ROM Cost = [(Annual Extraction Cost / (ATQ or Actual production

whichever is higher) + Mining Charge] + (Fixed Reserve Price).

Where,

(i)

Annual Extraction Cost is the cost of extraction of coal as computed

in accordance with Regulation 43 of these regulations;

(ii)

Mining Charge is the charge per tonne of coal paid by the generating

company to the Mine Developer and Operator engaged by the

generating company for mining, wherever applicable; and

(iii)

Fixed Reserve Price is the fixed reserve price per tonne along with

subsequent escalation, if any, as provided in the Coal Mine

Development and Production Agreement.

(3) Run of Mine Cost of lignite in case of integrated mine(s) for lignite shall be worked out as

under:

ROM Cost = [(Annual Extraction Cost / (ATQ or Actual production

whichever is higher) + (Mining Charge)]

Where,

(i)

Annual Extraction Cost is the cost of extraction of lignite as

computed in accordance with Regulation 43 of these regulations; and

(ii)

Mining Charge is the charge per tonne of lignite paid by the generating

company to the Mine Developer and Operator engaged by the

generating company for mining, wherever applicable.

(4) The generating company shall adhere to the Mining Plan for the extraction of coal or

lignite on an annual basis and shall submit a certificate to that effect from the Coal

Controller or the competent authority:

Provided that deviations from the Mining Plan shall be considered only if such

deviations have been approved by the Coal Controller or the revised Mining Plan

has been approved by the competent authority.

(5) Run of Mine Cost of coal and lignite shall be worked out in terms of Rupees per tonne.

40.

Additional Charges:

(1) Where crushing or transportation or handling or washing are undertaken by the

generating company without engaging the Mine Developer and Operator or an

agency other than the Mine Developer and Operator, additional charges shall be

worked out as under:

(i) Crushing Charges = Annual Crushing Cost/Quantity;

(ii) Transportation Charges= Annual Transportation Cost/Quantity:

Provided that separate transportation charges, as applicable, shall be

considered from the mine up to the washery end or coal handling plant

associated with the integrated mine(s) and beyond the washery end or

coal handling plant associated with the integrated mine(s) and up to the

loading point, as the case may be;

(iii) Handling charges = Annual Handling Cost/ Quantity; and

(iv) Washing Charges = Annual Washing Cost/Quantity.

Where,

(a)

Annual Crushing Cost, Annual Transportation Cost, Annual Handling

Cost and Annual Washing Cost shall be worked out on the basis of

the following components, for which the generating company shall

submit the capital cost separately:

(i)

Depreciation;

(ii)

Interest on Working Capital;

(iii)

Interest on Loan;

(iv)

Return on Equity;

(v)

Operation and Maintenance Expenses, excluding mining charge;

(vi)

Statutory charges, if applicable.

(b)

Quantity shall be the quantity of coal or lignite in a tonne crushed or

transported or handled or washed, as the case may be, during the

year duly certified by the Auditor.

(2) Where crushing, transportation, handling, or washing are within the scope of the Mine

Developer and Operator engaged by the generating company, no additional

charges shall be admitted, as the same shall be recovered through the Mining Charge

of the Mine Developer and Operator.

(3) Where crushing, transportation, handling, or washing are undertaken by the generating

company by engaging an agency other than the Mine Developer and Operator, the

annual charges of such agencies shall be considered as part of the Operation and

Maintenance Expenses, provided that the charges have been discovered through a

transparent, competitive bidding process.

(4) The crushing charges, transportation charges, handling charges, and washing charges

shall be admitted by the Commission after a prudence check, considering charges

of Coal India Limited or similarly placed coal mines or any other reference charges.

(5) The crushing charges, transportation charges, handling charges, and washing charges

shall be worked out in terms of Rupees per tonne.

41.

Capital Cost:

(1) The expenditure incurred, including IDC and IEDC, duly certified by the Auditor, for

the development of the integrated mine(s) up to the date of commercial operation

shall be considered for arriving at the capital cost.

(2) Capital expenditure incurred shall be admitted by the Commission after a prudence

check.

(3) Capital expenditure incurred on infrastructure for crushing, transportation, handling,

washing and other mining activities required for mining operations shall be arrived

at separately in accordance with these regulations:

Provided that where crushing, transportation, handling or washing are undertaken

by the generating company, the expenditure incurred on infrastructures of these

components shall be capitalized;

Provided further that where mine development and operation, with or without any

component of crushing, transportation, handling or washing, are undertaken by

the generating company by engaging the Mine Developer and Operator or an

agency other than the Mine Developer and Operator, the capital expenditure

incurred by the Mine Developer and Operator or such agency shall not be

capitalised by the generating company and shall not be considered for the

determination of input price.

(4) The capital expenditure shall be determined by considering, but not limited to,

the Mining

Plan, detailed project report, mine closure plan, cost audit report and such other

details as deemed fit by the Commission.

(5) In the case of integrated mine(s) which have declared the date of commercial

operation prior to 1.4.2024, the capital expenditure allowed by the Commission for the

period ending 31.3.2024 shall form the basis for the computation of input price.

42.

Additional Capital Expenditure:

(1) The expenditure, in respect of the integrated mine(s), incurred or projected to be

incurred after the date of commercial operation and up to the date of achieving

the Peak Rated Capacity may be admitted by the Commission, subject to a

prudence check and shall be capitalized in the respective year of the tariff period

as additional capital expenditure corresponding to the Annual Target Quantity of

the year as specified in the Mining Plan or actual extraction in that year, whichever

is higher, on following counts:

(a)

expenditure incurred on activities as per the Mining Plan;

(b)

expenditure for works deferred for execution and un-discharged

liabilities recognized for works executed prior to the date of

commercial operation;

(c)

expenditure for works required to be carried out for complying with

directions or orders of any statutory authorities;

(d)

liabilities arising out of compliance with the order or decree of any

court of law or award of arbitration;

(e)

expenditure for procurement and development of land as per the

Mining Plan;

(f)

expenditure for procurement of additional heavy earth moving

machineries for replacement, on completion of their useful life; and

(g)

liabilities due to Change in Law or Force Majeure event;

Provided that in case of replacement of any assets, the additional capitalization

shall be worked out after adjusting the gross fixed assets and cumulative

depreciation of the assets replaced on account of de-capitalization;

Provided further that the generating company shall prepare guidelines for

procurement and replacement of heavy mining equipment such as Heavy Earth

Moving Machineries and share the same with the beneficiaries and submit it to

the Commission along with its petition.

(2) The expenditure, in respect of the integrated mine(s), incurred or projected to be

incurred after the date of achieving the Peak Rated Capacity may be admitted by

the Commission subject to a prudence check, and shall be capitalized as Additional

Capital Expenditure, corresponding to the Annual Target Quantity of the respective

years as specified in the Mining Plan, on following counts:

(a)

expenditure incurred on activities, if any, as per the Mining Plan;

(b)

expenditure for works required to be carried out for complying with

directions or orders of any statutory authority;

(c)

liabilities arising out of compliance with an order or decree of any

court of law or award of arbitration;

(d)

expenditure for procurement and development of land as per the

Mining Plan; and

(e)

liabilities due to Change in Law or Force Majeure events;

Provided that in case of replacement of any assets, the additional capitalization

shall be worked out after adjusting the gross fixed assets, cumulative depreciation

and cumulative repayment of loan of the assets replaced on account of de-

capitalization.

(3) The expenditure on the following counts shall not be considered as additional capital

expenditure for the purpose of these regulations:

expenditure incurred but not capitalized as the assets have not

been put in service (capital work in progress);

mine closure expenses;

expenditure on works not covered under the Mining Plan, unless

covered under sub-clause (g) of Clause (1) or sub-clause (e) of Clause

(2) of this Regulation;

expenditure on replacement due to obsolescence of assets on

account of completion of the useful life or due to obsolescence of

technology if the original cost of such assets has not been de-

capitalised from the gross fixed assets.

43.

Annual Extraction Cost: The Annual Extraction Cost of integrated mine(s) shall consist

of the following components:

(i) Depreciation;

(ii) Interest on Loan;

(iii) Return on Equity;

(iv) Operation and Maintenance Expenses, excluding mining charge;

(v) Interest on Working Capital;

(vi) Mine closure expenses, if not included in mining charge; and

(vii) Statutory charges, if applicable.

44.

Capital Structure, Return on Equity and Interest on Loan:

(1) For integrated mine(s), the debt-equity ratio as on the date of commercial

operation and as on the date of achieving Peak Rated Capacity shall be

considered in the manner as specified under Clause (1) of Regulation 18 of these

regulations:

Provided that for integrated mine(s) in respect of lignite with the date of

commercial operation prior to 1.4.2024, the debt-equity ratio allowed by the

Commission for the period ending 31.3.2024 shall form the basis for computation

of input price.

(2) For integrated mine(s), the debt-equity ratio for additional capital expenditure

admitted by the Commission under these regulations shall be considered in the

manner specified under Clause (1) of this Regulation.

(3) Return on equity shall be computed in rupee terms on the equity base arrived

under Clause (1) of this Regulation at the base rate of 14%.

(4) The base rate of return on equity as per Clause (3) of this Regulation shall be

grossed up with the effective tax rate computed in the manner specified under

Regulation 31 of these regulations.

(5) Interest on loan, including normative loan, if any, determined under Clause (1) of this

Regulation, shall be arrived at by considering the weighted average rate of interest

calculated on the basis of the actual loan portfolio, in accordance with Clauses

(2) to (7) of Regulation 32 of these regulations.

45.

Depreciation:

(1) Depreciation in respect of integrated mine(s) shall be computed from the date of

commercial operation by applying the Straight Line Method:

Provided that depreciation methodology allowed in respect of integrated

mine(s) of lignite which have been declared under commercial operation on

or before 31.3.2024, shall continue to apply for determination of input price of

lignite.

(2) The value base for the purpose of depreciation shall be the capital cost of the asset

admitted by the Commission:

Provided that,

freehold land or assets purchased from grant shall not be

considered as depreciable assets, and their cost shall be excluded

from the capital cost while computing the depreciable value of the

assets;

ii)

where the allotment of freehold land is conditional and is required to

be returned, the cost of such land shall be part of the value base for

the purpose of depreciation, subject to a prudence check by the

Commission; and

iii)

leasehold land shall be amortized over the lease period or remaining

life of the integrated mine(s), whichever is lower.

(3) The salvage value of an asset shall be considered as 5% of the capital cost of the

asset: Provided that the salvage value shall be:

zero for IT equipment and software;

ii)

zero or as agreed by the generating company with the State

Government for land; and

iii)

as notified by the Ministry of Corporate Affairs under the Companies

Act, 2013 for specialized mining equipment.

(4) Depreciation in respect of integrated mine(s) shall be arrived at annually by

applying depreciation rates or on the basis of expected useful life specified in

Appendix III of these regulations:

Provided that specialized mining equipment shall be depreciated as per the

useful life and depreciation rate as notified by the Ministry of Corporate Affairs

under the Companies Act, 2013.

46.

Operation and Maintenance Expenses:

(1) The Operation and Maintenance Expenses in respect of integrated mine(s) shall be

allowed as under:

(a) The Operation and Maintenance expenses in respect of integrated mine(s)

of coal, for the tariff period ending on 31^st March 2029 shall be allowed based

on the projected Operation and Maintenance Expenses for each year of the

tariff period subject to prudence check by the Commission;

Provided that the Operation and Maintenance expenses allowed under this

clause shall be trued up based on actual expenses for the tariff period ending

on 31^st March 2029.

(b) The Operation and Maintenance expenses for the tariff period ending on 31^st

March 2029 in respect of the integrated mine(s) of lignite commissioned on

or before 31^st March 2024 shall be worked out based on the Operation and

Maintenance expenses as admitted by the Commission during 2023-24 and

escalated at the rate of 5.25 % per annum;

31^st March 2029 in respect of the integrated mine(s) of lignite commissioned

after 31^st March 2024 shall be allowed based on the projected Operation and

Maintenance Expenses for each year of the tariff period, subject to

prudence check by the Commission;

Provided that the Operation and Maintenance expenses allowed under this

clause shall be trued up based on actual expenses for the tariff period ending

on 31^st March 2029.

(2) Where the development and operation of the integrated mine(s) is undertaken

by the generating company by engaging the Mine Developer and Operator, the

Mining Charge of such Mine Developer and Operator shall not be included in

Operation and Maintenance Expenses under Clause (1) of this Regulation;

(3) Where an agency other than Mine Developer and Operator is engaged by the

generating company, through a transparent competitive bidding process, for

crushing or transportation or handling or washing or any combination thereof,

the annual charges of such agency shall be considered as part of Operation

and Maintenance Expenses under clause (1) of this Regulation, subject to a

prudence check by the Commission.

47.

Interest on Working Capital:

(1) The working capital of the integrated mine(s) of coal shall cover:

(i) Input cost of coal stock for 7 days of production corresponding to the Annual

Target Quantity for the relevant year;

(ii) Consumption of stores and spares, including explosives, lubricants and fuel

@ 15% of operation and maintenance expenses, excluding mining charge

of the Mine Developer and Operator and annual charges of the agency

other than the Mine Developer and Operator, engaged by the generating

company; and

(iii) Operation and maintenance expenses for one month, excluding the mining

charge of the Mine Developer and Operator and annual charges of the

agency other than the Mine Developer and Operator engaged by the

generating company.

(2) The working capital of the integrated mine(s) of lignite shall cover: -

(i) Input cost of lignite stock for 7 days of production corresponding to the

Annual Target Quantity for the year;

(ii) Consumption of stores and spare including explosives, lubricants and fuel

@20%

of Operation and Maintenance expenses, excluding Mining Charge of the

Mine Developer and Operator and annual charges of the agency other

than the Mine Developer or Operator engaged by the generating

company; and

(iii) Operation and Maintenance expenses for one month, excluding the Mining

Charge of the Mine Developer and Operator and annual charges of the

agency other than the Mine Developer and Operator, engaged by the

generating company.

(3) The rate and payment of interest on working capital shall be determined in

accordance with Clauses (3) and (4) of Regulation 34 of these regulations.

48.

Mine Closure Expenses:

(1) Where the mine closure is undertaken by the generating company, the amount

deposited in the Escrow account as per the Mining Plan, after adjusting interest earned,

if any, on the said deposits shall be admitted as Mine Closure Expenses:

Provided that,

the amount deposited in the Escrow account as per the Mining Plan prior to

the Date of Commercial Operation of the integrated mine(s) shall be

indicated separately and shall be recovered over the useful life of the

integrated mine(s) in the form of annuity linked to the borrowing rate;

the amount deposited in the Escrow account as per the Mining Plan or any

expenditure incurred towards mine closure shall be excluded from the

capital cost for computing input price;

where the expenditure incurred towards mine closure falls short of or is in

excess of the reimbursement received from the Escrow account during the

tariff period 2024- 29, the shortfall or excess shall be carried forward to

the subsequent years for

adjustments.

(2) The amount towards mine closure shall be deposited in the Escrow account as

per the Mining Plan and shall be recovered as part of the input price irrespective

of the expenditure incurred towards mine closure during any of the years of the

tariff period.

(3) Where mine closure is within the scope of the Mine Developer and Operator

engaged by the generating company and mine closure expenses are part of

the Mining Charge of the Mine Developer and Operator, the mine closure

expenses shall be met out of the Mining Charge, and no mine closure expenses

shall be admissible to the generating company separately:

Provided that,

the amount deposited in the Escrow account by the Mine Developer and

Operator or by the generating company and any amount received from

the Escrow Account against expenditure incurred towards mine closure

shall not be considered for computing input price; and

the difference between the borrowing cost, arrived at by considering the

weighted average rate of interest calculated on the basis of the actual

loan portfolio in accordance with the methodology specified in

Regulation 32 of these regulations, and the amount deposited in the

Escrow account and the interest received from Escrow account in a year

shall be adjusted in the input price of coal or lignite of the respective year,

as part of mine closure expenses, on case to case basis;

(4) Where the mine closure is within the scope of the Mine Developer and Operator

engaged by the generating company only for a part of useful life of the

integrated mine(s)and the generating company undertakes the mine closure for

the balance useful life, the treatment of mine closure during the period

undertaken by the generating company shall be in accordance with Clause (1)

of this Regulation and mine closure during the period undertaken by the Mine

Developer and Operator shall be in accordance with Clause (3) of this Regulation:

Provided that the treatment of mine closure at the end of the useful life of the

integrated mine(s) shall be decided by the Commission on a case-to-case basis.

(5) The mine closure expenses worked out in accordance with this Regulation shall

not be applicable in case of the integrated mine(s) allocated through an auction

route under the Coal Mines (Special Provisions) Act, 2015.

49.

Determination of Input Price:

(1) The input price of coal or lignite shall be determined as under:

Input Price = [ROM Cost + Additional charges]

(2) The credit arising on account of adjustment due to shortfall in overburden

removal, GCV Adjustment and Non- tariff Income, if any, shall be dealt with

separately in the manner specified in these regulations.

(3) Statutory Charges, as applicable, shall be allowed.

50.

Recovery of Input Charges:

(1) The input charges of coal or lignite shall be recovered as under:

Input Charges = [Input Price x Quantity of coal or lignite supplied] + Statutory

charges, as applicable;

Provided that where the energy charge rate based on the input price of coal from

integrated mine(s) exceeds 20% of the energy charge rate based on the notified

price of Coal India Limited for the commensurate grade of coal in a month, prior

consent of the beneficiary(ies) shall be required to be obtained by the generating

company;

Provided further that where such consents of beneficiaries are not available, the

input price of coal from such integrated mine(s) shall be so fixed that the energy

charge rate based on the input price of coal from integrated mine(s) does not

exceed by more than 20% of the energy charge rate based on the notified price

of Coal India Limited for the commensurate grade of coal in a month;

Provided also that the energy charge rate based on the input price of coal does

not lead to a higher energy charge rate throughout the tenure of the power

purchase agreement than that which would have been obtained as per terms

and conditions of the existing power purchase agreement.

(2) The generating company shall work out the comparative energy charge rate

based on the input price of coal and notified price of Coal India Limited for the

commensurate grade of coal for every month from the date of commercial

operation of integrated mine(s) and share the same with beneficiaries.

51.

Adjustment on account of Shortfall of Overburden Removal (OB Adjustment):

1. The generating company shall remove overburden as specified in the Mining

Plan.

2. In case of a shortfall of overburden removal during a year, the generating

company shall be allowed to adjust such shortfall against excess of overburden

removal, if any, during the subsequent three years.

3. In case of excess of overburden removal during a year, the generating company

shall be allowed to carry forward such excess for adjustment against the shortfall,

if any, during the subsequent three years.

4. Where the shortfall of overburden removal of any year is not made good by the

generating company in accordance with Clause (2) of this Regulation, the

adjustment on account of the shortfall of overburden removal (OB Adjustment)

for that year shall be worked out as under:

OB Adjustment = [Factor of adjustment for shortfall of overburden removal

during the year] x [Mining Charge during the year +

Operation and Maintenance expenses during the year]

Where,

Factor of adjustment for the shortfall of overburden removal during the

year shall be computed as under:

[(Actual quantity of coal or lignite extracted during the year x

Annual Stripping Ratio as per Mining Plan) - (Actual quantity of

overburden removed during the year/ Annual Stripping Ratio as

per Mining Plan)]/ (Annual Target Quantity);

ii)

Annual Stripping ratio is the ratio of the volume of overburden to be

removed for one unit of coal or lignite as specified in the Mining Plan.

iii)

Mining Charge is the charge per tonne of coal or lignite paid by the

generating company to the Mine Developer and Operator engaged

by the generating company for mining, wherever applicable.

iv)

Mining Charge and Operation and Maintenance expenses shall be in

terms of Rupees per tonne corresponding to the Annual Target

Quantity.

5. The provisions of this Regulation regarding adjustment on account of shortfall of

overburden removal shall not be applicable in case of the integrated mine(s)

allocated through an auction route under the Coal Mines (Special Provisions)

Act, 2015.

52.

Adjustment on account of shortfall in GCV (GCV Adjustment):

(1) In case the weighted average GCV of coal extracted from the integrated mine(s)

in a year is higher than the declared GCV of coal for such mine(s), no GCV adjustment

shall be allowed.

(2) In case the weighted average GCV of coal extracted from the integrated mine(s) in a

year is lower than the declared GCV of coal of such mine(s), the GCV adjustment in that

year shall be worked out as under:

(a) Where the integrated mine(s) are allocated through an auction route under

the Coal Mines (Special Provisions) Act, 2015:

GCV Adjustment = (Quoted Price of coal + Fixed Reserve Price) X

[(Declared GCV of coal - Weighted Average GCV of

coal extracted in the year)/(Declared GCV of coal)]

Where,

Quoted Price of coal is the Final Price Offer of coal in respect of the

concerned coal Block or Mine, along with subsequent escalation, if

any, as provided in the Coal Mine Development and Production

Agreement:

Provided that additional premium, if any, quoted by the

generating company in the auction shall not be considered; and

ii)

Declared GCV of coal shall be the GCV of coal as specified or quoted

in the auction.

(b) Where the integrated mine(s) are allocated through an allotment route

under the Coal Mines (Special Provisions) Act, 2015:

GCV Adjustment = [(Annual Extraction Cost/ATQ) + (Mining Charge)] X

[(Declared GCV of coal – Weighted Average GCV of coal

extracted in the year)/(Declared GCV of coal)]

Where,

Annual Extraction Cost is the cost of extraction of coal as computed in

accordance with Regulation 43 of these regulations;

ii)

Mining Charge is the charge per tonne of coal paid by the generating

company to the Mine Developer and Operator engaged by the

generating company for mining, wherever applicable; and

iii)

Declared GCV of coal shall be the average GCV as per the Mining

Plan or as approved by the Coal Controller.

53.

Adjustment on account of Non-tariff income (NTI Adjustment):

(1) Adjustment on account of non-tariff income (NTI Adjustment) for any year, such as

income from sale of washery rejects in case of integrated mine of coal and profit,

if any, from supply of coal to the Coal India Limited or merchant sale of coal as

allowed under the Coal Mines (Special Provisions) Act, 2015 shall be worked out

as under:

NTI Adjustment = (2/3) x (Total Non-tariff income during the year)/(Actual quantity

of coal or lignite extracted during the year)

(2) The adjustment on account of non-tariff income worked out in accordance with

this Regulation shall not be applicable in case of the integrated mine(s) allocated

through an auction route under the Coal Mines (Special Provisions) Act, 2015.

Provided that in case the actual extraction is less than ATQ, no NTI adjustment

shall be made till the total cost of extraction is recovered.

54.

Credit Adjustment Note:

(1) The credit arising on account of OB Adjustment, GCV Adjustment, and NTI

Adjustment shall be dealt with through a Credit Adjustment Note for any year.

(2) The Credit Adjustment Note shall be issued in favour of the specified end use

generating stations on account of OB Adjustment, GCV Adjustment or NTI

Adjustment, as the case may be, for that year as under:

(i) OB Adjustment for the year X Quantity of coal or lignite supplied in that year;

(ii) GCV Adjustment for the year X Quantity of coal or lignite supplied in that

year; and

(iii) NTI Adjustment in the year X Quantity of coal or lignite supplied in that year.

(3) The amount in the Credit Adjustment Note shall be adjusted against the charges

of coal or lignite supplied after the date of issue of the Credit Adjustment Note.

The integrated mine(s) shall prepare an annual reconciliation statement of such

adjustment and furnish the same to all the end use plants and also publish the

same on its website.

55.

Quality Measurement: The quality of coal or lignite supplied from the integrated

mine(s) shall be measured at the loading point through third party sampling as per the

guidelines and procedure specified by the Ministry of Coal, Government of India and

records of such measurement of quality of coal shall be made available to the

beneficiaries on demand.

56.

Special Provision: Provisions of Chapters 5 to 8 of these regulations shall not be

applicable in case of integrated mine(s), except to the extent specifically provided for

or referred to in Chapter- 9:

Provided that the financial parameters required for determination of input price of

coal or lignite from integrated mine(s), if not specifically provided for or referred to

in Chapter-9, shall be considered as per provisions of these regulations as

applicable to the coal or lignite based generating stations.

CHAPTER – 10

COMPONENTS OF ENERGY CHARGE

57.

Energy Charges and Supplementary Energy Charges: The energy charge and

Supplementary Energy Charges in respect of the thermal generating Stations shall

comprise the landed cost of primary fuel, secondary fuel oil consumption and

reagents on account of the implementation of the revised emission standards.

58.

Landed Fuel Cost of Primary Fuel: The landed fuel cost of primary fuel for any month shall

consist of the base price or input price of fuel corresponding to the grade and quality

of fuel and shall be inclusive of statutory charges as applicable, washery charges,

transportation cost by rail or road or any other means and loading, unloading and

handling charges:

Provided that procurement of fuel at a price other than Government notified prices

may be considered if it is based on competitive bidding through a transparent

process;

Provided further that the landed fuel cost of primary fuel shall be worked out based

on the actual bill paid by the generating company, including any adjustment on

account of quantity and quality;

Provided also that in the case of coal-fired or lignite based thermal generating

station, the Gross Calorific Value shall be measured by third party sampling, and

the expenses towards the third party sampling facility shall be reimbursed by the

beneficiaries.

59.

Transit and Handling Losses: For coal and lignite, the transit and handling losses shall

be as per the following norms: -

Thermal Generating

Station

Transit and Handling

Loss(%)

Pit

head

0.20%

Non-pit head – All

0.80%

Rail route

Non-pit head

multi- modal

transportation

(using two or

more than two

mode of transport

involving multiple

trans-

shipments)

1.00%

Provided that in the 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 and handling losses applicable for non-pit head stations shall apply;

Provided further that in case of imported coal, the transit and handling losses

applicable for pit-head station shall apply.

60.

Gross Calorific Value of Primary Fuel:

(1) The gross calorific value for computation of energy charges as per Regulation 64

of these regulations shall be done in accordance with 'GCV as Received’;

(2) The measurement of GCV of domestic coal shall be done based on third party

sampling through an agency to be appointed by the generating company in

accordance with the guidelines, if any, issued by the Central Government and

the generating company shall ensure recovery of compensation as per Fuel

Supply Agreement(s) and pass on the benefits of the same to the beneficiaries

of the generating station:

Provided that in the absence of third party sampling, computation of the energy

charges as per Regulation 64 of these Regulations shall be done in accordance

with 'GCV as Billed’;

(3) In the case of an integrated coal mine, the GCV of coal received at the end use

generating station shall be adjusted by 15 kCal/Kg from the GCV measured at

the mine end for every 100 km distance beyond 200 Km, or actual whichever is

lower, subject to the condition that such an adjustment in aggregate shall not

exceed 300 kCal/kg.

Provided further that the Commission after carrying out a detailed study may

rationalise the mechanism for arriving at the gross calorific value of domestic coal

at the generating station by considering the various factors impacting the

calorific value throughout entire value chain from the delivery of coal to

receiving at the generating station.

(4) No loss in calorific value between ‘GCV as billed’ and ‘GCV as received' shall be

admissible for generating stations procuring coal through import.

(5) The generating company shall provide to the beneficiaries of the generating

station the details in respect 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 Form

15 prescribed at Annexure-I (Part I) to these regulations:

Provided that the additional details of the weighted average GCV of the primary

fuel on a received basis used for generation during the period, the blending ratio

of the imported coal with domestic coal, and the proportion of e-auction coal

shall be provided, along with the bills of the respective month;

Provided further copies of the bills and details of parameters of GCV and price

of fuel such as domestic coal, imported coal, e-auction coal, lignite, natural gas,

RLNG, liquid fuel, details of blending ratio of the imported coal with domestic

coal, the proportion of e-auction coal shall also be displayed on the website of

the generating company.

61.

Landed Cost of Reagent:

(1) Where specific reagents such as Limestone, Sodium Bi- Carbonate, Urea or

Anhydrous Ammonia are used during the operation of an emission control system

for meeting revised emission standards, the landed cost of such reagents shall be

determined based on the normative consumption and the purchase price of the

reagent through competitive bidding, applicable statutory charges and

transportation cost.

(2) The normative consumption of specific reagents for the various technologies

installed for meeting revised emission standards shall be as specified in Regulation

70 of these regulations.

CHAPTER – 11

COMPUTATION OF CAPACITY CHARGES AND ENERGY CHARGES

62.

Computation and Payment of Capacity Charge for Thermal Generating Stations:

1. The fixed cost of a thermal generating station shall be computed on annual

basis based on the norms specified under these regulations and recovered on

a 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 or allocation in the capacity of the generating station. The

capacity charge shall be recovered in two parts, viz., Capacity Charge for Peak

Hours of the month and Capacity Charge for Off- Peak Hours of the month as

follows:

2. The Capacity Charge payable to a thermal generating station for a calendar

month shall be calculated in accordance with the following formulae:

Capacity Charge for the Month (CCn) =

Capacity Charge for Peak Hours of the Month (CCpn) +

Capacity Charge for Off-Peak Hours of the Month (CCopn)

Where,

CCp1= [(0.20 x AFC) x (1/12) x (PAFMp1/NAPAF) subject to ceiling of {(0.20 x AFC) x

(1/12)}]

CCp2= [(0.20 x AFC) x (1/6) x ( PAFMp2/NAPAF) subject to ceiling of {(0.20 x AFC) x

(1/6)}]

– CCp1

CCp3= [(0.20 x AFC) x (1/4) x (PAFMp3/NAPAF) subject to ceiling of {(0.20 x AFC) x

(1/4)}]

- (CCp1+ CCp2)

CCp4= [(0.20 x AFC) x (1/3) x (PAFMp4/NAPAF) subject to ceiling of {(0.20 x AFC) x

(1/3)}]

- (CCp1+ CCp2+CCp3)

CCp5= [(0.20 x AFC) x (5/12) x (PAFMp5/NAPAF) subject to ceiling of {(0.20 x AFC) x

(5/12)}]

- (CCp1+ CCp2+CCp3+CCp4)

CCp6= [(0.20 x AFC) x (1/2) x (PAFMp6/NAPAF) subject to ceiling of {(0.20 x AFC) x

(1/2)}] -

(CCp1+ CCp2+CCp3+CCp4+CCp5)

CCp7= [(0.20 x AFC) x (7/12) x (PAFMp7/NAPAF) subject to ceiling of {(0.20 x AFC) x

(7/12)}]

- (CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6)

CCp8= [(0.20 x AFC) x (2/3) x (PAFMp8/NAPAF) subject to ceiling of {(0.20 x AFC) x

(2/3)}] -

(CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6 +CCp7)

CCp9= [(0.20 x AFC) x (3/4) x (PAFMp9/NAPAF) subject to ceiling of {(0.20 x AFC) x

(3/4)}] -

(CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6+CCp7+CCp8)

CCp10= [(0.20 x AFC) x (5/6) x (PAFMp10/NAPAF) subject to ceiling of {(0.20 x AFC) x

(5/6)}]

- (CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6 +CCp7 +CCp8 +CCp9)

CCp11= [(0.20 x AFC) x (11/12) x (PAFMp12/NAPAF) subject to ceiling of {(0.20 x

AFC) x (11/12)}] - (CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6

+CCp7+CCp8+CCp9+CCp10)

CCp12= [(0.20 x AFC) x (PAFMp12/NAPAF) subject to ceiling of (0.20 x AFC)] - (CCp1+

CCp2+ CCp3+CCp4+CCp5+CCp6 +CCp7+CCp8+CCp9+CCp10+CCp11)

CCop1= (0.80 x AFC) x (1/12) x (PAFMop1/NAPAF) subject to ceiling of {(0.80 x AFC) x

(1/12)}

CCop2= [(0.80 x AFC) x (1/6) x (PAFMop2/NAPAF) subject to ceiling of {(0.80 x AFC) x

(1/6)}]

– CCop1

CCop3= [(0.80 x AFC) x (1/4) x (PAFMop3/NAPAF) subject to ceiling of {(0.80 x AFC) x

(1/4)}]

- (CCop1+ CCop2)

CCop4= [(0.80 x AFC) x (1/3) x (PAFMop4/NAPAF) subject to ceiling of {(0.80 x AFC) x

(1/3)}]

- (CCop1+ CCop2+CCop3)

CCop5= [(0.80 x AFC) x (5/12) x (PAFMop5/NAPAF) subject to ceiling of {(0.80 x

AFC) x

(5/12)}] – (CCop1+ CCop2+CCop3+CCop4)

CCop6= [(0.80 x AFC) x (1/2) x (PAFMop6/NAPAF) subject to ceiling of {(0.80 x AFC) x

(1/2)}]

– (CCop1+ CCop2+CCop3+CCop4+CCop5)

CCop7= [(0.80 x AFC) x (7/12) x (PAFMop7/NAPAF) subject to ceiling of {(0.80 x

AFC) x

(7/12)}] - ((CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6)

CCop8= [(0.80 x AFC) x (2/3) x (PAFMop8/NAPAF) subject to ceiling of {(0.80 x AFC) x

(2/3)}]

- (CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6+CCop7)

CCop9= [(0.80 x AFC) x (3/4) x (PAFMop9/NAPAF) subject to ceiling of {(0.80 x AFC) x

(3/4)}]

- (CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6+CCop7+CCop8)

CCop10= [(0.80 x AFC) x (5/6) x (PAFMop10/NAPAF) subject to ceiling of {(0.80 x AFC) x

(5/6)}]

- (CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6+CCop7+CCop8 +CCop9)

CCop11= [(0.80 x AFC) x (11/12) x (PAFMop12/NAPAF) subject to ceiling of {(0.80 x

AFC) x (11/12)}] - (CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6

+CCop7+CCop8+CCop9+CCop10)

CCop12= [(0.80 x AFC) x (PAFMop12/NAPAF) subject to ceiling of (0.80 x AFC)] -

(CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6+CCop7+CCop8

+CCop9+CCop10+CCop11)

Provided that in case generating station or unit thereof is under shutdown due to

Renovation and Modernisation or installation of emission control system, as the case

may be, the generating company shall be allowed to recover O&M expenses and

interest on loan only.

Where,

CCm=

Capacity Charge for the Month;

CCP=

Capacity Charge for the Peak Hours of the Month;

CCop=

Capacity Charge for the Off-Peak Hours of the Month;

CCpn=

Capacity Charge for the Peak Hours of n^th Month;

CCopn=Capacity Charge for the Off-Peak of n^th Month;

AFC =

Annual Fixed Cost;

PAFMpn= Plant Availability Factor achieved during Peak Hours up to the end of n^th

Month;

PAFMopn= Plant Availability Factor achieved during Off-Peak Hours up to the end of n^th Month;

NAPAF= Normative Annual Plant Availability Factor.

3. Normative Plant Availability Factor for "Peak" and "Off-Peak" Hours in a

month shall be equivalent to the NAPAF specified in Clause (A) of

Regulation 70 of these regulations. The number of hours of "Peak" and "Off-

Peak" periods during a day shall be four and twenty, respectively. The

hours of Peak and Off-Peak periods during a day shall be declared by the

concerned RLDC at least a week in advance.

Provided that RLDC, after duly considering the comments of the concerned

stakeholders, shall declare Peak Hours in such a way as to coincide with the majority of

the Peak Hours of the region to the maximum extent possible:

Provided further that in respect of a generating station having beneficiaries across

different regions, the Peak Hours shall correspond to Peak Hours of the region in which

the majority of its beneficiaries, in terms of percentage of allocation of share, are

located.

The shortfall in recovery of Capacity Charge for cumulative Off-Peak Hours derived

based on NAPAF shall be allowed to be off-set by over-achievement of PAF, if any, and

consequent notional over-recovery of Capacity Charge for cumulative Peak Hours.

Provided that the shortfall in recovery of Capacity Charge for cumulative Peak Hours

derived based on NAPAF, shall not be allowed to be off-set by over-achievement of

PAF, if any, and consequent notional over-recovery of Capacity Charge for cumulative

Off-Peak Hours.

4. The Plant Availability Factor for a Month ('PAFM') shall be computed in

accordance with the following formula:

𝑛

𝐷𝐶𝑖

𝑃𝐴𝐹𝑀 = 10000 𝑥 ∑ [𝑁 𝑥 𝐼𝐶 𝑥 (100 − 𝐴𝑈𝑋𝑛 − 𝐴𝑈𝑋𝑒𝑛)] %

𝑖=1

Where,

AUXn = Normative auxiliary energy consumption as a percentage of gross energy

generation;

AUXen= Normative auxiliary energy consumption for emission control system as a

percentage of gross energy generation, wherever applicable;

DCi = Average declared capacity (in ex-bus MW), for the i^th day of the period i.e. the

month or the year, as the case may be, as certified by the concerned load dispatch

centre after the day is over;

IC = Installed Capacity (in MW) of the generating

station; n = Number of days during the period;

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.

5. In addition to the AFC entitlement as computed above, the thermal generating

station shall be allowed an incentive of up to 1.00% of AFC approved for a given

year, which shall be billed monthly as per the following.

Incentive = (1.00% x ß x CCy)/12

Where,

ß = Average Monthly Frequency Response Performance for that generating

station, as certified by RPCs, which shall be computed by considering primary

response as per the methodology prescribed by the NLDC with approval of

the Commission, and ß shall range between 0 to 1.

Provided that the incentive shall be payable only if the Beta value is higher than

0.30.

CCy= Capacity Charges for the Year.

6. In addition to the capacity charge, an incentive shall be payable to a

generating station or unit thereof @ 75 paise/ kWh for ex-bus scheduled

energy during Peak Hours and @ 55 paise/ kWh for ex-bus scheduled

energy during Off-Peak Hours corresponding to scheduled generation in

excess of ex-bus energy corresponding to Normative Annual Plant Load

Factor (NAPLF) achieved on a cumulative basis, as specified in Clause (B)

of Regulation 70 of these regulations.

63.

Computation and Payment of Supplementary Capacity Charge for Coal or Lignite

based Thermal Generating Stations:

(1) The fixed cost of the emission control system shall be computed on an annual basis

based on the norms specified under these regulations and recovered on a monthly

basis under a supplementary capacity charge. The total supplementary capacity

charge is payable for a generating station shall be shared by its beneficiaries as per

their respective percentage share or allocation in the capacity of the generating

station.

(2) The Supplementary Capacity Charge payable to a coal or lignite generating station

for a calendar month shall be calculated in accordance with the following formulae:

SCC1= (AFCe) x (1/12) x (PAFM1/NAPAF) subject to ceiling of {(AFCe) x (1/12)}

SCC2= [(AFCe) x (1/6) x (PAFM2/NAPAF) subject to ceiling of {(AFCe) x (1/6)}] – SCC1

SCC3= [(AFCe) x (1/4) x (PAFM3/NAPAF) subject to ceiling of {(AFCe) x (1/4)}] -

(SCC1+SCC2)

SCC4= [(AFCe) x (1/3) x (PAFM4/NAPAF) subject to ceiling of {(AFCe) x (1/3)}] -

(SCC1+ SCC2 + SCC3)

SCC5= [(AFCe) x (5/12) x (PAFM5/NAPAF) subject to ceiling of {(AFCe) x (5/12)}] -

(SCC1+ SCC2+SCC3+SCC4)

SCC6= [(AFCe) x (1/2) x (PAFM6/NAPAF) subject to ceiling of {(AFCe) x (1/2)}] -

(SCC1+ SCC2+SCC3+SCC4+SCC5)

SCC7= [(AFCe) x (7/12) x (PAFM7/NAPAF) subject to ceiling of {(AFCe) x (7/12)}] -

(SCC1+SCC2+ SCC3+SCC4+SCC5+SCC6)

SCC8= [(AFCe) x (2/3) x (PAFM8/NAPAF) subject to ceiling of {(AFCe) x (2/3)}] - (SCC1+

SCC2+ SCC3+SCC4+SCC5+SCC6 +SCC7)

SCC9= [(AFCe) x (3/4) x (PAFM9/NAPAF) subject to ceiling of {(AFCe) x (3/4)}] -

(SCC1+ SCC2+ SCC3+SCC4+SCC5+SCC6+SCC7+SCC8)

SCC10= [(AFCe) x (5/6) x (PAFM10/NAPAF) subject to ceiling of {(AFCe) x (5/6)}] -

(SCC1+ SCC2+ SCC3+SCC4+SCC5+SCC6 +SCC7 +SCC8 +SCC9)

SCC11= [(AFCe) x (11/12) x (PAFM11/NAPAF) subject to ceiling of {(AFCe) x

(11/12)}] -

(SCC1+ SCC2+ SCC3+SCC4+SCC5+SCC6 +SCC7+SCC8+SCC9+SCC10)

SCC12= [(AFCe) x (PAFM12/NAPAF) subject to ceiling of (AFCe)] - (SCC1+ SCC2+

SCC3+SCC4+SCC5+SCC6 +SCC7+SCC8+SCC9+SCC10+SCC11)

Provided that in case of the generating station or unit thereof under shutdown due

to Renovation and Modernisation, the generating company shall be allowed to

recover O&M expenses and interest on the loan in respect of the emission control

system only.

Where,

SCCn= Supplementary Capacity Charge for the n^th Month;

AFCe = Annual Fixed Cost of the emission control system;

PAFMn= Plant Availability Factor achieved up to the end of n^th

Month; NAPAF= Normative Annual Plant Availability Factor.

(3) Normative Plant Availability Factor for a month for the purpose of Supplementary

Capacity Charge shall be considered in the manner specified in Clause (3) of

Regulation 62 of these regulations. The PAFM shall be worked out in accordance with

Clause (4) of Regulation 62 of these regulations.

64.

Computation and Payment of Energy Charge for Thermal Generating Stations and

Supplementary Energy Charge for Coal or Lignite based Thermal Generating Stations:

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 an ex-power plant basis, at the energy charge

rate of the month (with fuel and limestone price adjustment). The total Energy

charge payable to the generating company for a month shall be:

Energy Charges = (Energy charge rate in Rs./kWh) x {Scheduled energy (ex bus)

for the month in kWh}

The supplementary energy charge on account of the emission control system

shall cover the differential energy charges due to auxiliary energy consumption

and cost of reagent consumption and shall be payable by every beneficiary for

the total energy scheduled to be supplied to such beneficiary during the

calendar month on an ex-power plant basis, at the supplementary energy

charge rate of the month. The total supplementary energy charge payable to

the generating company for a month shall be:

Supplementary Energy Charges = (Supplementary energy charge rate in Rs./kWh)

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

Energy charge rate (ECR) and Supplementary Energy charge rate in Rupees

per kWh on ex- power plant basis shall be determined to three decimal places

in accordance with the following formulae:

(a)

ECR for coal based and lignite fired stations:

ECR = [{(SHR - SFC x CVSF) x LPPF / CVPF} + (SFC x LPSFi) + (LC x LPL)] x 100/(100 -

AUX)

(b)

Supplementary ECR for coal and lignite based thermal generating

stations: Supplementary ECR = (ECR) + [(SRC x LPR / 10)/(100-(AUXn +

AUXen))]

(c)

For gas and liquid fuel based stations:

ECR = SHR 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 considering GCV as per

Regulation 60, in kCal per kg for coal based stations less 85 Kcal/Kg on account of

variation during storage at generating station;

(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;

(d) In the case of blending of fuel from different sources, the weighted average Gross

calorific value of the primary fuel shall be arrived at in proportion to the blending

ratio:

CVSF = Calorific value of secondary fuel, in kCal per

ml; ECR = Energy charge rate, in Rupees per kWh sent

out; SHR = Gross station heat rate, in kCal per kWh;

LC = Normative limestone consumption in kg per kWh;

LPL = Weighted average landed cost of limestone in Rupees per kg;

LPPF = Weighted average landed fuel cost 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 fuel cost of primary

fuel shall be arrived in proportion to the blending ratio);

SFC = Normative Specific fuel oil consumption, in ml per kWh;

LPSFi = Weighted Average Landed Fuel Cost of Secondary Fuel in Rs./ml during the

month;

(ECR) = Difference between ECR with revised auxiliary energy consumption with

emission control system equivalent to (AUXn + AUXen) and ECR with normative

auxiliary energy consumption as specified in these regulations;

SRC = Specific reagent consumption on account of revised emission standards (in

g/kWh); LPR = Weighted average landed price of reagent for the emission control

system (in Rs./kg).

Note:Quantity of primary fuel required for generation of one kWh of electricity at generator

terminals in kg or litre or standard cubic metre, as the case may be, and shall be computed

on the basis of normative Gross Station Heat Rate (less heat contributed by secondary fuel

oil for coal/lignite based Generating Stations) and gross calorific value of coal/lignite or gas

or liquid fuel as billed by supplier less:

(a) Actual loss in calorific value of coal between “as billed by supplier” and “as received at

generating station”, subject to the maximum loss in calorific value of 300 kcal/kg; and

(b) actual stacking loss subject to the maximum stacking loss of 85 kcal/kg for pithead

stations and 120 kcal/kg for non-pithead stations;

Provided that the energy charge rate for a gas or liquid fuel based station shall be adjusted

for open cycle operation based on certification of the Member Secretary of the respective

Regional Power Committee during the month.

In case of part or full use of an 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 the supply of contracted power on account of a

shortage of fuel or optimization of economical operation through blending, the use of an

alternative source of fuel supply shall be permitted to generating station:

Provided that the weighted average price of alternative source of fuel shall not exceed

30% of base price of fuel computed as per clause (5) of this Regulation and in such case,

prior permission from beneficiaries shall not be a pre-condition, unless otherwise agreed

specifically in the power purchase agreement:

Provided further that where the energy charge rate based on weighted average price of fuel

upon use

of alternative source of fuel supply exceeds 30% of base energy charge rate as approved

by the Commission for that year or exceeds 20% of energy charge rate for the previous

month, whichever is lower shall be considered and, in that event, prior consultation with

beneficiary shall be made at least three days in advance.

Notwithstanding anything contained in clause 3 of this Regulation, the

Commission after considering the shortage of fuel, may vary through separate

Order(s), the blending ratio and the requirement of beneficiary consent thereof,

towards use of alternative source of fuel..

Where biomass fuel is used for blending with coal, the landed cost of biomass

fuel shall be worked out based on the delivered cost of biomass at the unloading

point of the generating station, inclusive of taxes and duties as applicable. The

energy charge rate of the blended fuel shall be worked out considering the

consumption of biomass based on the blending ratio as specified by the Authority

or the actual consumption of biomass, whichever is lower.

The Commission, through 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 rate so approved shall be the base energy charge rate for the

first year 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 by escalation rates for payment purposes as notified by the Commission from

time to time under competitive bidding guidelines.

The tariff structure as provided in Regulation 63 and Regulation 64 of these

regulations 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 energy consumption (AUX) and energy charge rate (ECR) for

such stations.

65.

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 an annual basis,

based on norms specified under these regulations, and shall be recovered on a

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 Rupees

NAPAF = Normative plant availability factor in percentage

NDM= Number of days in the month

NDY= Number of days in the year

PAFM= plant availability factor achieved during the month, in percentage

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

Where

AUX = Normative auxiliary energy consumption in percentage

DCi = Declared capacity (in ex-bus MW) for the ith day of the month, which the

station can deliver for at least three (3) hours, as certified by the nodal load

dispatch centre after the day is over.

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

station N = Number of days in the month

4. In addition to the AFC entitlement as computed above, the hydro generating station

shall be allowed an incentive of up to 3% of the Capacity Charge approved for a

given year which shall be billed monthly as per the following.

Incentive = (3% x ß x CCy)/12

Where,

ß = Average Monthly Frequency Response Performance for that generating

station, as certified by RPCs, which shall be computed by considering primary

response as per the methodology prescribed by the NLDC with approval of

the Commission and beta shall range between 0 to 1.

Provided that incentive shall be payable only if Beta value is higher than 0.30.

CCy= Capacity Charges for the Year.

5. 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 the ex-bus basis, at the computed energy charge rate. The total

energy charge payable to the generating company for a month shall be:

Energy Charges = (Energy charge rate in Rs. / kWh) x {Scheduled energy (ex-bus) for the

month in kWh} x (100 – FEHS) / 100

6. 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 (8) of this Regulation:

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 (7) below.

FEHS = Free energy for home State, in per cent, as mentioned in EXPLANATION-III under

Regulation 76 of these regulations.

7. In case the saleable scheduled energy (ex-bus) of a hydro generating station during

a year is less than the saleable design energy (ex-bus) for reasons beyond the control

of the generating station, the generating station may directly recover the shortfall in

energy charges in six equal interest-free monthly instalments after adjusting for DSM

Energy in the immediately following year and shall be subject to truing up at the end

of the tariff period.

Provided that in case actual generation from a hydro generating station is less

than the design energy for a continuous period of four years on account of hydrology

factor, the generating

station shall approach the Central Electricity Authority with relevant hydrology data for

revision of design energy of the station.

8. Any shortfall in the energy charges on account of saleable scheduled energy (ex-bus)

being less than the saleable design energy (ex-bus) during the tariff period 2019-24,

which was beyond the control of the generating station and which could not be

recovered during the said tariff period shall be recovered in accordance with clause

(7) of this Regulation.

9. In case the energy charge rate (ECR) for a hydro generating station, computed as

per clause (5) of this Regulation exceeds one hundred and thirty 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 one

hundred and thirty paise per kWh only.

10. In addition to the above, an incentive shall be payable to a ROR Hydro generating

station @ 50 paise/ kWh corresponding to the saleable scheduled energy during peak

hours of the day in excess of average saleable scheduled energy during the day (24

hours).

66.

Computation and Payment of Capacity Charge and Energy Charge for Pumped

Storage Hydro Generating Stations:

(1)

The fixed cost of a pumped storage hydro generating station shall be computed on

an annual basis, based on norms specified under these regulations, and recovered on a

monthly basis as a 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;

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

Rupees NDM = Number of days in the month

NDY = Number of days in the year

Provided that there would be adjustments 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, 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)}/ 100.

Where,

DEm = Design energy for the month specified for the hydro generating station, in

MWh 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.

Provided that if the energy for the pumping of water from lower reservoir to upper

reservoir is arranged by the generating company, the charges for the pumping energy till

the ex-Bus of the generating station shall be payable by the beneficiaries in proportion to

their respective allocation in the saleable capacity of the generating station.

(5)

The generating company shall maintain the record of daily inflows of natural water

into the upper elevation reservoir and the reservoir levels of the upper elevation reservoir

and lower elevation reservoir on an 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 the generator is deliberately or otherwise, without any valid reason, not

pumping water from a lower elevation reservoir to a higher elevation during off-peak

periods or not generating power to its potential or wasting the 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 forced outages up to 15% in

a year, shall be construed as the valid reason for not pumping water from the lower

elevation reservoir to the higher elevation during an off-peak period or not generating

power using the energy of pumped water or natural flow of water:

Provided that the total capacity charges recovered during the year shall be adjusted

on a pro-rata basis in the following manner in the event of total machine outages in a

year exceeding 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 outages

Provided 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.

67.

Deviation Charges:

(1) Variations between actual net injection and scheduled net injection for the generating

stations, and variations between actual net drawl and scheduled net drawl 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, 2022, as amended from time to time, till such

time a separate Regulations are issued by the commission.

(2) The actual net deviation of every generating station and Beneficiary shall be metered

on its periphery through special energy meters (SEMs) installed by the State Transmission

Utility (STU), and computed in MWh for each 15-minute time block by the concerned State

Load Despatch Centre.

CHAPTER - 12

NORMS OF OPERATION

68.

Recovery of Tariff and Incentive: (1) Recovery of capacity charge, energy charge,

supplementary capacity charge, supplementary energy charge and incentive by the

generating company shall be based on the achievement of the operational norms

specified in the Regulation 69 to Regulation 71 of these regulations.

(2) The Commission may on its own revise the norms of Station Heat Rate specified in

Regulation 69(C ) of these regulations in respect of any of the generating stations for

which relaxed norms have been specified.

69.

Norms of operation for thermal generating station

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

(A)

Normative Annual Plant Availability Factor (NAPAF)

(a)

85% for all thermal generating stations, except those covered under clauses (b), (c),

(d) and (e);

(b)

83% for coal and lignite based generating stations completing 30 years from COD

as on 31.03.2024;

(c)

Lignite fired generating stations using Circulatory Fluidized Bed Combustion (CFBC)

Technology and generating stations based on coal rejects:

First Three years from the date of commercial operation – 68.50%

After completion of three years of the date of commercial operation - 75%

(B)

Normative Annual Plant Load Factor (NAPLF) for Incentive:

(a)

85% for all thermal generating stations, except for those covered under

clause (b) below

(b)

83% for coal and lignite based generating stations completing 30 years from

COD as on 31.03.2024

(C)

Gross Station Heat Rate:

(a)

Existing Thermal Generating Stations achieving COD before 1.4.2009

(i)

For Coal-based Thermal generating stations other than those covered under

clause (ii) below:

Name of the Station

Proposed heat rate for 2024-29

210 MW each of RTPS

Units 1 to 7

2430 kcal/kwh or actuals, whichever is lower.

250 MW RTPS Unit 8

2273 kcal/kwh or actuals, whichever is lower.

500 MW, BTPS Unit-1

2390 kcal/kwh or actuals, whichever is lower.

500 MW, BTPS Unit-2

2267 kcal/kwh or actuals, whichever is lower.

700 MW, BTPS Unit-3

2176.65 kcal/kwh or actuals, whichever is

lower.

1600 MW YTPS 1&2

2151 kcal/kwh or actuals, whichever is lower.

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 and above 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.

Note 3

The normative gross station heat rate above is exclusive of the compensation specified as

per the Grid Code. The generating company shall, based on the unit loading factor,

consider the compensation in addition to the normative gross heat rate above.

Note 4

The gross station heat rate for the unit capacity of less than 200 MW sets, shall be dealt

with on a case-to-case basis.

(b)

Thermal Generating Stations achieving COD on or after 1.4.2009:

(i) For Coal-based and lignite-fired Thermal Generating Stations:

For 200-300 MW Sets.

1.05 X Design Heat Rate (kCal/kWh)

For 500 MW Sets and above:

1.045 X Design Heat Rate (kCal/kWh)

Where the Design Heat Rate of a generating unit means the unit heat rate

guaranteed by the supplier at conditions of 100% MCR, zero per cent make up,

design coal and design cooling water temperature/back pressure.

Provided that depending upon the pressure and temperature ratings of

the units, the maximum design turbine cycle heat rate and minimum design boiler

efficiency shall be as per the table below:

Pressure Rating (Kg/cm2)

150

170

SHT/RHT (⁰C)

535/535

537/53

537/565

Type of BFP

Electrical

Driven

Turbine

Driven

Turbine

Driven

Max

Turbine

Heat

Rate

(kCal/kWh)

1955

1950

1935

Min. Boiler Efficiency

Sub-Bituminous Indian Coal (%)

Bituminous Imported Coal (%)

Pressure Rating

(Kg/cm2)

247

260

270

SHT/RHT (⁰C)

537/56

565/593

593/593

600/600

Type of BFP

Turbine

Driven

Turbine

Driven

Turbine

Driven

Turbine

Driven

Turbine

Driven

Max Turbine

Heat Rate

(kCal/kWh)

1900

1850

1814

1810

1790

Min. Boiler Efficiency (%)

Sub-Bituminous

Indian Coal (%)

86.00

86.50

Bituminous

Imported Coal (%)

89.00

89.50

* For Lignite fired thermal generating station, the minimum boiler efficiency shall be

76% (for pulverised) and 80% (for fluidised bed) based boilers.

In case designed turbine cycle heat rate and boiler efficiency are better than these

values, the same shall be considered for calculation of design unit heat rate.

Provided further that in case the pressure and temperature parameters of a unit are

different from the above ratings, the maximum design heat rate of the unit of the nearest

class shall be taken:

Provided also that where the heat rate of the unit has not been guaranteed but turbine

cycle heat rate and boiler efficiency are guaranteed separately by the same supplier or

different suppliers, the design heat rate of the unit shall be arrived at by using guaranteed

turbine cycle heat rate and boiler efficiency:

Provided also that where the boiler efficiency is lower than 86% for Sub- bituminous Indian

coal and 89% for bituminous imported coal, the same shall be considered as 86% and 89%

for Sub- bituminous Indian coal and bituminous imported coal, respectively, for

computation of station heat rate:

Provided units based on a dry cooling system, the maximum turbine cycle heat rate shall

be considered as per the actual design or 6% higher than the values given in the table

above, whichever is lower;

Provided also that in the case of coal based generating station, if one or more generating

units were declared under commercial operation prior to 1.4.2024, the heat rate norms for

those generating units as well as generating units declared under commercial operation on

or after 1.4.2024 shall be lowest of the heat rate norms considered by the Commission

during tariff period 2019-24 or those arrived at by above methodology or the norms as per

the sub-clause (C)(a)(i) of this Regulation:

Provided also that for Generating stations based on coal rejects, the Commission shall

approve the Station Heat Rate on a case-to-case basis.

Note: In respect of generating units where the boiler feed pumps are electrically operated,

the maximum design heat rate of the unit shall be 40 kCal/kWh lower than the maximum

design heat rate of the unit specified above with turbine driven Boiler Feed Pump.

(c)

For Gas-based/ Liquid based Thermal Generating Unit(s)/ Block(s) having COD on

or after 1.4.2009:

For Natural Gas and RLNG= 1.050 X Design Heat Rate of the unit/block

(kCal/kWh) For Liquid Fuel=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 per cent

make up, design cooling water temperature/back pressure.

(d)

The Gross Station Heat Rate norms as specified in sub-clauses (a) and (b) of this

clause, in respect of the coal and lignite based generating stations or units thereof (except

for the generating stations or units thereof for which relaxed norms have been specified)

and commissioned till 31.3.2024 (before 2009 and after 2009) shall remain applicable for

such generating stations or units thereof for the remaining operational life of the respective

generating stations or units thereof.

(D)

Secondary Fuel Oil Consumption:

(a) For Coal-based generating stations: 0.50 ml/kWh

(b) For Coal-based generating stations with wall (front/rear/sides) fired boilers: 1.00

ml/kWh

(d) For Generating Stations based on Coal Rejects: 2.0 ml/kWh

(E)

Auxiliary Energy Consumption:

(a) For Coal-based generating stations below:

S. No.

Generating Station

With Natural Draft cooling tower

or without cooling tower

(i)

200-300 MW series

8.50%

(ii)

300/ 330/ 350/ 500 MW and above

Steam driven boiler feed pumps

5.25%

Electrically driven boiler feed pumps

8.00%

(iii)

600 MW and above

Steam driven boiler feed pumps

5.25%

Electrically driven boiler feed pumps

8.00%

Provided that for thermal generating stations with induced draft cooling towers

and where ball and tube-type coal mill is used, the norms shall be further increased

by 0.5% and 0.8%, respectively:

Provided further that Additional Auxiliary Energy Consumption as follows

shall be allowed for plants with Dry Cooling Systems:

Type of Dry Cooling System

(% of gross

generation)

Direct cooling air cooled condensers with

mechanical draft fans

1.0%

Indirect cooling system employing jet condensers

with pressure recovery turbine and natural draft

tower

0.5%

Note: The auxiliary energy consumption for the unit capacity of less than 200 MW sets

shall be dealt with on a case-to-case basis.

(b)

For Gas Turbine /Combined Cycle generating stations:

(i)

Combined Cycle

2.75%

(ii)

Open Cycle

1.00%

Provided that where the gas based generating station is using electric motor

driven Gas Booster Compressor, the Auxiliary Energy Consumption in case of Combined

Cycle mode shall be 3.30% (including the impact of air-cooled condensers for Steam

Turbine Generators):

Provided further that an additional Auxiliary Energy Consumption of 0.35% shall

be allowed for Combined Cycle Generating Stations having direct cooling air cooled

condensers with mechanical draft fans.

(c)

For Lignite-fired thermal generating stations:

(i)

For all generating stations with 200 MW sets and above:

The auxiliary energy consumption norms shall be 0.5 percentage points 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 points more than the auxiliary energy

consumption norms of coal-based generating stations at (E) (a) above.

(d)

For Generating Stations based on coal rejects: 10%

(e) Norms of Auxiliary energy consumption for the emission control system (AUXen) of

thermal generating stations:

Name of Technology

AUXen (as % of

grossgeneration

)

(1) For reduction of emission of Sulphur dioxide:

Wet Limestone based FGD system

(without Gas to Gas heater )

1.0%

Lime Spray Dryer or Semi dry FGD System

1.0%

Dry Sorbent Injection System (using

Sodium bicarbonate)

NIL

For CFBC Power plant (furnace injection)

NIL

Sea water based FGD system (without

Gas

to Gas heater)

1.00%

(2) For reduction of emission of oxide of nitrogen:

Selective Non-Catalytic

Reduction system

NIL

Selective Catalytic Reduction

system

0.2%

Provided that where the technology is installed with a "Gas to Gas" heater, AUXen

specified above shall be increased by 0.20% of gross generation.

(F)

Norms for consumption of reagent:

(1) The normative consumption of specific reagents for various technologies for the

reduction of emission of sulphur dioxide shall be as under:

(a) For Wet Limestone based Flue Gas De-sulphurisation (FGD) system: The specific

limestone consumption (g/kWh) shall be worked out by following the formula:

[K x Normative heat rate (kcal/kWh) x Sulphur content of coal (%)/CVPF in kCal/Kg] x

[85/LP]g/kWh

Where,

GCV = (a) Weighted Average Gross calorific value of coal in kCal per kg for coal based

thermal generating stations computed in accordance with Regulation 60 of these

regulations;

(b)

Weighted Average Gross calorific value of lignite as received, in kCal per kg, as

applicable for lignite based thermal generating stations:

Provided that the value of K shall be equivalent to (35.2 x Design SO2 Removal

Efficiency/96%) to comply with the SO2 emission norm of 100/200 mg/Nm³ or (26.8 x Design

SO2 Removal Efficiency/73%) for units to comply with the SO2 emission norm of 600

mg/Nm³;

Provided further that the limestone purity shall not be less than 85%.

(b) For Lime Spray Dryer or Semi-dry Flue Gas Desulphurisation (FGD) system: The specific

lime consumption shall be worked out based on minimum purity of lime (LP) as at 90% or

more by applying formula [ 6 x90/LP] g/kWh;

(c)

For Dry Sorbent Injection System (using sodium bicarbonate): The specific

consumption of sodium bicarbonate shall be 12 g per kWh at 100% purity.

(d)

For CFBC Technology (furnace injection) based generating station: The specific

limestone consumption for CFBC based generating station (furnace injection) shall be

computed with the following formula:

[62.9 x S x SHR/ CVPF] x[85/LP]

Where

S = Sulphur content in

percentage, LP = Limestone Purity

in percentage,

SHR = Gross station heat rate, in kCal per kWh,

CVPF = (a) Weighted Average Gross calorific value of lignite as received, in kCal

per kg as applicable for lignite based thermal generating stations;

(e)

For Sea Water based Flue Gas Desulphurisation (FGD) system: The reagent used

in sea water based Flue Gas Desulphurisation (FGD) system shall be NIL

(2)

The normative consumption of specific reagent for various technologies for the

reduction of emission of oxide of nitrogen shall be as below:

(a) For Selective Non-Catalytic Reduction (SNCR) System: The specific urea

consumption of the SNCR system shall be 1.2 g per kWh at 100% purity of urea.

(b) For Selective Catalytic Reduction (SCR) System: The specific ammonia

consumption of the SCR system shall be 0.6 g per kWh at 100% purity of ammonia.

70.

Norms of Operation for Hydro Generating Stations:

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

(A)

Normative Annual Plant Availability Factor (NAPAF): (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 the 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 the basis of

fixation of NAPAF;

(c)

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

Run-of-river generating stations: 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.

(B)

In the case of pumped storage hydro generating stations, the quantum of electricity

required for pumping water from the down-stream reservoir to the up-stream reservoir shall

be arranged by the beneficiaries duly taking into account the transmission and distribution

losses up to the bus bar of the generating station. In return, beneficiaries shall be entitled

to an 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 a 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.

(C)

Auxiliary Energy Consumption (AEC):

Type of Station

AEC

Installed

Capacity

above 200 MW

Installed

Capacity upto

200 MW

Surface

Rotating Excitation

0.7%

Static

1.0%

1.2%

Underground

Type of Station

AEC

Installed

Capacity

above 200 MW

Installed

Capacity upto

200 MW

Rotating Excitation

0.9%

Static

1.2%

1.3%

* AEC for Tuirial HPS = 4%

CHAPTER - 13

SCHEDULING, ACCOUNTING AND BILLING

71.

Scheduling: The methodology for scheduling and dispatch for the generating station

shall be as specified in the Grid Code.

72.

Metering and Accounting: For metering and accounting, the provisions of the Grid

Code shall be applicable.

73.

Billing and Payment of charges: (1) Bills shall be raised for capacity charge and energy

charge by the generating company on a monthly basis in accordance with these

regulations, and payments shall be made by the beneficiaries or the long term

customers directly to the generating company

EXPLANATION-I: The physical copy of the Bill in Original at the office of the Authorised

Person of the beneficiary or long term customer, as the case may be, or the scanned

copy of the Original Bill through the official email ID of the Authorised Signatory of

the Generating Company shall be recognized as a valid mode of presentation of

Bill:

EXPLANATION-II: Authorized Signatory or Signatories (official designation only) shall

be notified in advance by the Managing Director or Chief Executive Officer of the

Company, and any change in the list of Authorised Signatories for the purpose shall be

communicated in the same manner.

(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.

EXPLANATION-I: Shares or 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 for 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 the beginning of a calendar month, except in case of an

emergency call for an urgent change in allocations out of unallocated capacity. The total

capacity share of a beneficiary would be the sum of its capacity share plus allocation out

of the unallocated portion.

EXPLANATION-II: The beneficiaries may propose surrendering part of their allocated firm

share to other States within or 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 or outside the region for such transfers, the shares of the

beneficiaries may be 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.

EXPLANATION-III: FEHS = Free energy for home State, in per cent 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 an 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 a 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.

74.

Recovery of Statutory Charges: The generating company shall recover the statutory

charges imposed by the State and Central Government, such as electricity duty and

water cess, by considering normative parameters specified in these regulations. In case

the electricity duty is applied to the auxiliary energy consumption, such amount of

electricity duty shall apply to the normative auxiliary energy consumption of the

generating station (excluding colony consumption) and apportioned to each of the

beneficiaries in proportion to their scheduled dispatch during the month.

75.

Rebate: (1) For payment of bills of the generating company through letter of credit on

presentation or through National Electronic Fund Transfer (NEFT) or Real Time Gross

Settlement (RTGS) payment mode within a period of 5 days of presentation of bills by

the generating company, a rebate of 1.50% shall be allowed.

Provided that in case a different Rebate mechanism is provided in the PPA, the same

shall be governed by the provisions of the PPA.

Explanation: In case of computation of '5 days', the number of days shall be

counted

consecutively without considering any holiday. However, in case the last day or day is

an official holiday, the 5^th day for the purpose of Rebate shall be construed as the

immediate succeeding working day (as per the official State Government's calendar,

where the Office of the Authorised Signatory or Representative of the Beneficiary, for the

purpose of receipt or acknowledgement of Bill is situated).

(2) Where payments are made on any day after 5 days and within a period of 30 days

of presentation of bills by the generating company, a rebate of 1% shall be allowed.

76.

Late payment surcharge: (1) In case the payment of any bill for charges payable under

these regulations is delayed by a beneficiary or long term customer as the case may be,

beyond a period of 45 days from the date of presentation of bills, a late payment surcharge

as specified in the Ministry of Power – Electricity (Late Payment Surcharge and Related

Matters) Rules, 2022 as amended from time to time shall be levied by the generating

company

Provided that in case a different LPS mechanism is provided in the PPA, the same

shall be governed by the provisions of the PPA.

(2) Unless otherwise agreed by the parties, the charges payable by a beneficiary or long

term customer shall be first adjusted towards a late payment surcharge on the outstanding

charges and, thereafter, towards monthly charges billed by the generating company

starting from the longest overdue bill.

CHAPTER – 14

SHARING OF BENEFITS

77.

Sharing of gains due to variation in norms: (1) The generating company shall work out gains

based on the actual performance of applicable Controllable parameters as under:

Station Heat Rate;

ii)

Secondary Fuel Oil Consumption; and

iii) Auxiliary Energy Consumption.

(2) The financial gains by the generating company on account of controllable parameters

shall be shared between the generating company and the beneficiaries or long term

customers, as the case may be on an annual basis. The financial gains computed as per

the following formulae in the case of generating stations other than hydro generating

stations on account of operational parameters as shown in Clause (1) of this Regulation shall

be shared in the ratio of 1:1 between the generating stations and beneficiaries.

Net Gain = (ECRN- ECRA) X Scheduled

Generation Where,

ECRN = Normative Energy Charge Rate computed on the basis of norms specified

for Station Heat Rate, Auxiliary Energy Consumption and Secondary Fuel Oil

consumption.

ECRA = Actual Energy Charge Rate computed on the basis of actual Station Heat

Rate, actual Auxiliary Energy Consumption and actual Secondary Fuel Oil

Consumption.

Provided that in the case of hydro generating stations, the net gain on account

of Actual

Auxiliary Energy Consumption being less than the Normative Auxiliary Energy Consumption

shall be computed as per the following formulae provided the saleable scheduled

generation is more than the saleable design energy and shall be shared in the ratio of 1:1

between generating station and beneficiaries:

(i)

When saleable scheduled generation is more than saleable design energy on the

basis of normative auxiliary energy consumption and less than or equal to

saleable design energy on the basis of actual auxiliary energy consumption:

Net gain (Million Rupees) = [(Saleable Scheduled generation in

MUs) - (Saleable Design energy on the basis of normative auxiliary energy

consumption in MUs)] x [1.30 or ECR, whichever is lower]

(ii) When saleable scheduled generation is more than saleable design energy on the

basis of actual auxiliary energy consumption:

Net gain (Million Rupees) = {Saleable Scheduled generation in MUs-

[(Saleable Scheduled Generation in MUs x (100 - normative AEC in %)/(100

actual AEC in %)]}x [1.30 or ECR, whichever is lower]

78.

Sharing of savings in interest due to re-financing or restructuring of loan :(1) If re- financing

or restructuring of loan by the generating company results in net savings on interest after

accounting for cost associated with such refinancing or restructuring, the same shall be

shared between the generating company and the beneficiaries, as the case may be, in

the ratio of 1:1.

(2) In case of dispute, any of the parties may make an application in accordance with

the Central Electricity Regulatory Commission (Conduct of Business) Regulations, 2023 for

settlement of the

dispute:

Provided that the beneficiaries or the long term customers shall not withhold any

payment on account of the interest claimed by the generating company during the

pendency of any dispute arising out of re-financing of the loan.

72.

Sharing of net gains referred to in Regulation 48(3)(e) and Regulation 49(1)(l) of Grid

Code, unless specifically provided in the rules or the guidelines issued by the Central

Government, shall be in the ratio of 1:1.

79.

Sharing of Non-Tariff Income: The non-tariff net income in case of generating station from

rent of land or buildings, eco-tourism, sale of scrap, and advertisements shall be shared

between the generating company and the beneficiaries or the long term customers, as

the case may be, in the ratio of 1:1.

80.

Sharing of Clean Development Mechanism Benefits: The proceeds of carbon credit from

approved emission reduction projects under the Clean Development Mechanism shall be

shared in the following manner:

(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, 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%, where after the proceeds shall

be shared in equal proportion, by the generating company and the beneficiaries.

CHAPTER 15

MISCELLANEOUS PROVISIONS

81.

Operational Norms to be ceiling norms: Operational norms specified in these regulations

are the ceiling norms and shall not preclude the generating company and the beneficiaries

and the long-term customers 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.

82.

Deviation from ceiling tariff: (1) The tariff determined in these regulations shall be a ceiling

tariff. The generating company and the beneficiaries or the long-term customer, as the

case may be, may mutually agree to charge a lower tariff.

(2) The generating company may opt to charge a lower tariff for a period not

exceeding the validity of these regulations on agreeing to deviation from

operational parameters, reduction in operation and maintenance expenses,

reduced return on equity and incentive specified in these regulations.

(3) If the generating company opts to charge a lower tariff for a period not exceeding

the validity of these regulations on account of lower depreciation based on the

requirement of repayment in such case, the unrecovered depreciation on account

of reduction of depreciation by the generating company during useful life shall be

allowed to be recovered after the useful life in these regulations.

(4) The deviation from the ceiling tariff specified by the Commission, shall come into

effect from the date agreed to by the generating company and the beneficiaries

or the long-term customer, as the case may be.

(5) The generating company and the beneficiaries of a generating station shall be

required to approach the Commission for charging a lower tariff in accordance with

clauses (1) to (3) above. The details of the accounts and the tariff actually charged

under clauses (1) to (3) shall be submitted at the time of true up.

(6) Where a generating company and its beneficiaries have mutually agreed to charge

a lower tariff in respect of a particular generating station in terms of Clauses (1) to

(3) of this Regulation, the said agreed tariff shall not be revised upwards at the time

of truing up based on the capital cost and additional capital expenditures in

accordance with these regulations:

Provided that where the trued up tariff is lower than the agreed tariff, the

generating company shall charge such trued-up tariff only:

Provided further that the difference between the agreed tariff and the trued-up

tariff shall be settled between the parties in accordance with Regulations 10(7) and 10(8)

of these regulations.

83.

Deferred Tax liability with respect to the previous tariff period: Deferred tax liabilities for the

period up to 31^st March 2009, whenever they materialize, shall be recoverable directly by

the generating companies from the then beneficiaries or long term customers, as the case

may be. Deferred tax liabilities for the period arising from 1.4.2009 to 31.3.2024, if any, shall

not be recoverable from the beneficiaries or the long term customers, as the case may be.

84.

Hedging of Foreign Exchange Rate Variation: (1) The generating company

may hedge foreign exchange exposure in respect of the interest and repayment of foreign

currency loan taken for the generating station, in part or in full at their discretion.

(2)

If the petitioner enters into hedging arrangement(s) based on its approved hedging

policy, the petitioner shall communicate to the beneficiaries concerned, of entering into

such arrangement(s) within thirty days.

(3)

Every generating company shall recover the cost of hedging of foreign exchange

rate variation corresponding to the normative foreign debt, in the relevant year on a 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 foreign

debt.

(4)

To the extent the generating company 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 its suppliers or

contractors.

85.

Award of Arbitration: In cases where there is a liability with respect to capital works on

account of award of arbitration having principal amount along with interest payment, the

principal amount actually paid shall be capitalised.

Provided that any interest amount associated with the arbitration award and

actually paid shall be recovered in instalments along with carrying cost at the rate

specified under Regulation 10(6) and 10(7) of these Regulations.

Provided further that such number of instalments shall be decided by the

Commission on a case-to-case basis depending upon the amount to be reimbursed.

86.

Recovery of the cost of hedging or Foreign Exchange Rate Variation (FERV):

(1)

Every generating company shall recover the cost of hedging and foreign exchange

rate variation on a year-to-year basis as income or expense in the period in which it arises.

(2)

Recovery of the cost of hedging or foreign exchange rate variation shall be made

directly by the generating company from the beneficiaries or the long term customers, 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

customers, as the case may be, to the amounts claimed on account of the cost of hedging

or foreign exchange rate variation, the generating company may make an appropriate

application before the Commission for its decision.

87.

Application fee and 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 at the discretion of the Commission, be

allowed to be recovered by the generating company directly from the beneficiaries

(2) The fees and charges shall be reimbursed directly by the beneficiaries in proportion

to their allocation in the generating stations

(3) Fees and charges paid by the generating companies under the Karnataka

Electricity Regulatory Commission (Fees) Regulations, 2016, as amended from time

to time or any subsequent amendment thereof.

88.

Public Procurement through Competitive Bidding: The generating company for a specific

generating station or for an integrated mine shall procure equipment, work and services

through a transparent process of competitive bidding.

Provided that under certain exceptional circumstances, equipment, works and

services may be procured through other methods, as provided under general financial

rules issued by the Government of India and applicable from time to time.

89.

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.

90.

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.

91.

Issue of Suo-Moto orders and practice directions: The Commission may, from time to time,

issue orders and practice directions in regard to the effective implementation of these

regulations and matters incidental or ancillary thereto as the Commission may consider

appropriate.

Secretary

for Karnataka Electricity Regulatory Commission

Appendix I

Depreciation Schedule

Sr.

No.

Asset Particulars

Depreciation

Rate (Salvage

Value=10%)

SLM

Land under full ownership

0.00%

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%

Assets purchased new

Plant & 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%

Cooling towers & circulating water systems

5.28%

Hydraulic works forming part of the Hydro-

generating stations

(i)

Dams, Spillways, Weirs, Canals, Reinforced

concrete flumes and siphons

5.28%

(ii)

Reinforced concrete pipelines and surge tanks,

steel pipelines, sluice gates, steel surge tanks,

hydraulic control valves and hydraulic works

5.28%

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%

Transformers, Kiosks, sub-station equipment &

other fixed apparatus (including plant)

(i)

Transformers, including foundations having a rating

of 100 KVA and over

5.28%

(ii)

Others

5.28%

Switchgear including cable connections

5.28%

Lightning arrestor

(i)

Station type

5.28%

(ii)

Pole type

5.28%

(iii)

Synchronous condenser

5.28%

Sr. No.

Asset Particulars

Depreciation

Rate (Salvage

Value=10%)

SLM

Batteries

9.50%

(i)

Underground cable, including joint boxes and

disconnected boxes

5.28%

(ii)

Cable duct system

5.28%

Overhead lines, including cable support

(i)

Lines on fabricated steel operating at terminal

voltages higher than 66 KV

5.28%

(ii)

Lines on steel supports operating at terminal

voltages higher than

13.2 KV but not exceeding 66 KV

5.28%

(iii)

Lines on steel on reinforced concrete support

5.28%

(iv)

Lines on treated wood support

5.28%

Meters

5.28%

Self propelled vehicles

9.50%

Air Conditioning Plants

(i)

Static

5.28%

(ii)

Portable

9.50%

m(i)

Office furniture and furnishing

6.33%

(ii)

Office equipment

6.33%

(iii)

Internal wiring, including fittings and apparatus

6.33%

(iv)

Street Light fittings

5.28%

Apparatus let on hire

(i)

Other than motors

9.50%

(ii)

Motors

6.33%

Communication equipment

(i)

Radio and high frequency carrier system

15.00%

(ii)

Telephone lines and telephones

15.00%

(iii)

Fibre Optic/OPGW

6.33%

I. T Equipment including software, UNMS, URTDSM,

EMS, Cyber Security System, REMC, WAMS, SCADA

15.00%

System

Any other assets not covered above

5.28%

Note: Where the life of the particular asset is less than the useful life of the project, the

useful life of such particular asset shall be considered as per the provisions of the

Companies Act, 2013 and subsequent amendment thereto.

Appendix II

Depreciation Schedule for New Projects

Sr.

No.

Asset Particulars

Depreciation

Rate (Salvage

Value=10%)

SLM

Land under full ownership

0.00%

Land under lease

(a)

for investment in the land

3.34%

(b)

For the cost of clearing the site

3.34%

Land for reservoir in case of hydro generating

station

3.34%

Assets purchased new

Plant & Machinery in generating stations

(i)

Hydro electric

4.22%

(ii)

Steam electric NHRB & waste heat recovery boilers

4.22%

(iii)

Diesel electric and gas plant

4.22%

Cooling towers & circulating water systems

4.22%

Hydraulic works forming part of the Hydro-

generating stations

(i)

Dams, Spillways, Weirs, Canals, Reinforced

concrete flumes and siphons

4.22%

(ii)

Reinforced concrete pipelines and surge tanks,

steel pipelines, sluice gates, steel surge tanks,

hydraulic control valves and hydraulic works

4.22%

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%

Transformers, Kiosks, sub-station equipment &

other fixed apparatus (including plant)

(i)

Transformers, including foundations having a rating

of 100 KVA and over

4.22%

(ii)

Others

4.22%

Switchgear, including cable connections

4.22%

Lightning arrestor

(i)

Station type

4.22%

(ii)

Pole type

4.22%

(iii)

Synchronous condenser

4.22%

Sr. No.

Asset Particulars

Depreciation

Rate (Salvage

Value=10%)

SLM

Batteries

9.50%

(i)

Underground cable, including joint boxes and

disconnected boxes

4.22%

(ii)

Cable duct system

4.22%

Overhead lines, including cable support

(i)

Lines on fabricated steel operating at terminal

voltages higher than 66 KV

4.22%

(ii)

Lines on steel supports operating at terminal

voltages higher than

13.2 KV but not exceeding 66 KV

4.22%

(iii)

Lines on steel on reinforced concrete support

4.22%

(iv)

Lines on treated wood support

4.22%

Meters

4.22%

Self propelled vehicles

9.50%

Air Conditioning Plants

(i)

Static

4.22%

(ii)

Portable

9.50%

m.(i)

Office furniture and furnishing

6.33%

(ii)

Office equipment

6.33%

(iii)

Internal wiring, including fittings and apparatus

6.33%

(iv)

Street Light fittings

4.22%

Apparatus let on hire

(i)

Other than motors

9.50%

(ii)

Motors

6.33%

Communication equipment

(i)

Radio and high frequency carrier system

15.00%

(ii)

Telephone lines and telephones

15.00%

(iii)

Fibre Optic/OPGW

6.33%

I. T Equipment including software UNMS,

URTDSM, EMS, Cyber Security System, REMC,

WAMS, SCADA system

15.00%

Any other assets not covered above

4.22%

Note: Where the life of the particular asset is less than the useful life of the project, the useful

life of such particular asset shall be considered as per the provisions of the Companies Act,

2013 and subsequent amendment thereto.

142

Appendix III

Depreciation Schedule for Integrated Mine

DEPRECIATION SCHEDULE FOR INTEGRATED MINE

Sr No

Asset Particulars

Life in Years

Land Freehold@

999

Land Leasehold

&&&

Temporary erections

HEMM^$

Roads, bridges, culverts, helipads

Main Plant Buildings

Machinery other than HEMM

Water Supply, Drainage and sewerage

Furniture and Fixtures

Office equipment/s other than computers

Hospital equipment(s)

EDP, WP machines, SATCOM & communication

equipment

Electrical installations

Self propelled vehicles

Computers, Software

6.33

Laboratory & workshop equipment

Mine Development Expenses and Evaluation and

Exploration ^#

20 or life of mine, whicheveris

lower

Evaluation and Exploration^#

20 or life of mine, whicheveris

lower

Others not covered above

Salvage Value shall be other than 5% for the following assets -

a. IT Equipment, software Zero (0)

b. Zero or as agreed with the state Government in case of land

c. For specialized mining equipment as specified by the Ministry of Corporate

affairs Mine Development expenses, Evaluation and Exploration Zero (0)

Petitioner to submit if the Freehold Land is attached with any conditions for return. If yes

submit the conditions and period after which the land is to be returned. In such a case,

the land shall be

depreciable based on such details.

&&&

To be filled by petitioner, least of lease agreement/mine life/right to use period

List of individual HEMM with the cost of each HEMM be provided separately

In a generic sense Mine Development Expenditure is the expenditure incurred to bring

the mine n into usable condition after ensuring the economic viability and decision is

taken by the Mine Owner to develop the mine. While filling under this head, details to the

extent feasible are to be given separately. Evaluation and exploration expenditure is

generally the expenditure incurred associated with finding the mineral by carrying out

topographical, geological, geochemical and geophysical studies, exploratory drilling,

trenching, sampling, expenditure for activities in relation to evaluation of technical

feasibility and commercial viability, acquisition of rights to explore etc. While filling under

this head, details to the extent feasible are to be given separately.

[

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R.N.I. No. KARBIL/2001/47147 POSTAL REGN. No. RNP/KA/BGS/2202/2017-19

Licensed to post without prepayment WPP No. 297

THAMMAIAH

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Date: 2024.04.29 17:04:21 +05'30'