NOTIFICATION

The 6th November 2024

CHAPTER - 1

PRELIMINARY

SHORT TITLE AND COMMENCEMENT

(1)

These Regulations shall be called “Odisha Electricity Regulatory Commission

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

2024”.

(2)

These Regulations shall be applicable in the State of Odisha.

(3)

The Commission in specifying these Regulations shall be guided by the principles

contained in Sections 61 and 62 of the Act to encourage competition, efficiency,

economical use of resources, good performance and optimum investments.

ODISHA ELECTRICITY REGULATORY COMMISSION

BIDYUT NIYAMAK BHAWAN

PLOT NO. 4, OERC ROAD, SHAILASHREE VIHAR, BHUBANESWAR -751021

TEL. No. 2721048, 2721049

E-MAIL: [email protected] / [email protected]

WEBSITE: www.orierc.org

The Odisha

G a z e t t e

EXTRAORDINARY

PUBLISHED BY AUTHORITY

No. 2144 CUTTACK, WEDNESDAY, NOVEMBER 13, 2024/KARTIKA 22, 1946

No. 1285ʊOERC/RA/GEN. REG./41/2024ʊIn exercise of powers conferred under

section 181 read with Section 61, 62 & 86 of the Electricity Act, 2003 (Act 36 of 2003) and

all other powers enabling it in that behalf, the Odisha Electricity Regulatory Commission

hereby makes the following Regulations, namely:

(4)

These Regulations shall be effective from 01.04.2024 and unless reviewed earlier

or extended by the Commission, shall remain in force till 31.03.2029.

SCOPE AND EXTENT OF APPLICATION

(1)

These Regulations shall be applicable to all existing and future Generating

Stations or unit thereof where tariff is required to be determined by the

Commission under the Act and relevant Regulations & Orders of Odisha

Electricity Regulatory Commission.

(2)

These Regulations shall not be applicable for

(a) Generating station(s) whose tariff has been determined through tariff based

competitive bidding or by Central Electricity Regulatory Commission.

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

determined in accordance with relevant Regulations & Orders of Odisha

Electricity Regulatory Commission.

approved Power Purchase Agreement (PPA) for the period as agreed by

Generating Company and beneficiary(ies).

DEFINITIONS AND INTERPRETATION

(1)

In these Regulations, unless the context otherwise requires-

(a)

“Act” means the Electricity Act, 2003 (36 of 2003);

(b)

“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;

(c)

“Additional Capitalisation”

means the additional capital expenditure

admitted by the Commission after prudence check, in accordance with these

Regulations;

(d)

“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;

(e)

“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 transformer losses within the generating station,

expressed as a percentage of the sum of gross energy generated at the

generator terminals of all the units of the generating station;

Provided that auxiliary energy consumption shall not include energy

consumed for supply of power to housing colony and other facilities at the

generating station and the power consumed for construction works at the

generating station and integrated coal mine;

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 for the purpose of Auxiliary consumption;

(f)

'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 based thermal generating station in

addition to the auxiliary energy consumption under clause (e) of this

Regulation;

(g)

“Auditor” means an auditor appointed by the Generating Company, in

accordance with the provisions of Sections 224, 223B 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;

(h)

“Beneficiary” in relation to a generating station means the person purchasing

electricity generated at such a generating station whose tariff is determined

under these Regulations;

(i)

“Capital Cost” means the capital cost as determined in accordance with

Regulation 15 of these Regulations;

(j)

“Change in Law” means occurrence of any of the following events:

(i)

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

(ii)

adoption, amendment, modification, repeal or re-enactment of any

existing Indian law; or

(iii)

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

(iv)

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.

(v)

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.

(k)

“Commission” means the Odisha Electricity Regulatory Commission referred

to in sub-section (1) of Section 82 of the Act;

(l)

“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;

(m)

“Cut-off Date” means the last day of the calendar month after thirty six (36)

months from the date of commercial operation of the project;

(n)

“Date of Commercial Operation” or “COD” in respect of a thermal

generating station or hydro generating station including pumped storage hydro

generating station shall have the same meaning as defined under Regulation

3(34) of CERC (Indian Electricity Grid Code) Regulations, 2023 as amended

from time to time till the Odisha Grid Code Regulations, 2015 is amended.

(o)

Date of Operation or “OD” 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 Direction of the Generating Company;

(p)

“Day” means a calendar day consisting of 24 hours period starting at 0000

hour;

(q)

“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 or whole of the day, duly taking

into account the availability of fuel or water, and subject to further

qualification in these Regulation;

(r)

“De-capitalisation” for the purpose of the tariff under these Regulations,

means reduction in Gross Fixed Assets of the generating project/ transmission

system as admitted by the Commission corresponding to inter-unit transfer of

assets or the assets taken out from service;

(s)

“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 statutory authority, 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;

Provided that the beneficiary(ies) shall be informed about de-

commissioning at the time of filing of such application by the project

developer to the CEA or any other authorized agency.

(t)

“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;

(u)

“Emission Control System” means a set of equipment or devices required to

be installed in a coal based thermal generating station or unit thereof to meet

the revised emission standards notified from time to time.

(v)

“Energy Sent Out” means the ex-bus energy generated by a generating

station after deducting auxiliary consumption.

(w)

“Existing Project” means the generating station which has been declared

under commercial operation from a date prior to 01.04.2024;

(x)

“Expansion project” shall include any addition of new capacity to the

existing generating station;

(y)

“Expenditure Incurred” means the fund, whether the equity or debt or both,

actually deployed and paid in cash or cash equivalent, for creation or

acquisition of a useful asset and does not include commitments or liabilities

for which no payment has been released;

(z)

‘Extended Life’ means the life of a generating station or unit thereof beyond

the period of useful life or operational life, as may be determined by the

Commission on case to case basis.

(aa)

“Financial Statement” means for each financial year, the following

statements, namely-

(i)

Balance sheet, prepared in accordance with the form contained in Part I

of Schedule III to the Companies Act, 2013 as amended from time to

time;

(ii)

Profit and loss account, complying with the requirements contained in

Part II of Schedule III to the Companies Act, 2013;

(iii)

Cash flow statement, prepared in accordance with the Accounting

Standard on Cash Flow Statement (AS-3) of the Institute of Chartered

Accountants of India;

(iv)

Report of the statutory auditors;

(v)

Cost records prescribed by the Central Government under Section 148 of

the Companies Act, 2013;

Together with notes there to, and such other supporting statements and

information as the Commission may direct from time to time;

Provided further that the Commission may, from time to time, specify

regulatory accounts to be maintained by a local authority under the Act.

(bb) “Financial Year” means a period commencing on 1st April of a calendar year

and ending on 31st March of the subsequent calendar year;

(cc)

“Force Majeure” for the purpose of these Regulations means the event or

circumstance or combination of events or circumstances including those stated

below which partly or fully prevents the Generating Company to complete the

project within the time specified in the Investment Approval or operating the

project, and only if such events or circumstances are not within the control the

Generating Company and could not have been avoided, had the Generating

Company taken reasonable care or complied with prudent utility practices:

(i)

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

(ii)

Any act of war, invasion, armed conflict or act of foreign enemy,

blockade, embargo, revolution, riot, insurrection, terrorist or military

action;

(iii)

Industry wide strikes and labour disturbances having a nationwide

impact in India; or

(iv)

Delay in obtaining statutory approval for the project except where the

delay is attributable to project developer;

(dd) “Fuel Supply Agreement” means the agreement executed between the

Generating Company and the fuel supplier for generation and supply of

electricity to the beneficiaries;

(ee)

“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;

(ff)

“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

including pumped storage hydro generating station means turbine generator

and its auxiliaries;

(gg) “Grid Code” means the OERC (Grid Code) Regulations, 2015 as amended

from time to time or subsequent re-enactment thereof;

(hh) “Gross Calorific Value” or “GCV” in relation to a thermal generating station

means the heat produced in kCal by complete combustion of one kilogram of

solid fuel or one litre of liquid fuel, as the case may be;

(ii)

“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 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 advance

technology for collection, preparation and testing of samples for measurement

of GCV in a fair and transparent manner;

Provided that the measurement of GCV of coal shall be carried out

through sampling by third party to be appointed by the generating companies

in accordance with the guidelines, if any, issued by the Central

Government/Commission;

Provided that GCV of coal ‘as Received’ shall be found out from GCV

of coal on ‘as billed basis’ allowing an adjustment for total moisture as per the

formula given as under:

GCV X (1-TM)

(1-IM)

Where: GCV = Gross Calorific Value of coal on as “billed basis”

TM = Total Moisture

IM = Inherent Moisture

(jj)

“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;

(kk) “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;

(ll)

“Indian Governmental Instrumentality” means the Government of India,

Governments of Odisha and any ministry or department or board or agency

controlled by Government of India or Government of Odisha (where the

project is located) or quasi-judicial authority constituted under the relevant

statutes in India;

(mm) “Infirm Power” means electricity injected into the grid prior to the date of

commercial operation of a unit of the generating station;

(nn) “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;

(oo) “Investment Approval” means approval by the Board of the Generating

Company or any other competent authority conveying administrative sanction

for the project including funding of the project and the timeline for the

implementation of the project;

Provided that the date of Investment Approval shall reckon from the

date of the resolution 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 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.

(pp) “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;

(qq) “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;

(rr)

“Landed Fuel Cost” means the total cost of coal (including biomass in case

of co-firing) 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;

(ss)

“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;

(tt)

“New Project” means the generating station or unit thereof achieving its

commercial operation on or after 01.04.2024;

(uu) “Non-pit head generating station” or “Non-Pit head Plant” means coal

based generating stations other than pit head generating stations.

(vv) “Operation and Maintenance Expenses” or “O&M expenses” means the

expenditure incurred for operation and maintenance of the project, or part

thereof in a financial year 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, security expenses,

overheads and fuel other than used for generation of electricity;

(ww) “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;

(xx) “Pit head Generating Station” or “Pit head Power Plant” means as defined

under the Environment (Protection) Rules, 1986.

(yy) “Plant Availability Factor (PAF)” in relation to a generating station for any

period means the average of the daily declared capacities (DCs) for all the

days during that 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;

(zz)

“Plant Load Factor” or “(PLF)” in relation to thermal generating station or

unit thereof for a given period means the total energy sent out corresponding to

scheduled generation during the period, expressed as a percentage of energy

sent out corresponding to installed capacity in that period and shall be

computed in accordance with the following formula:

Where,

IC = Installed Capacity of the generating station or unit in MW,

SGi

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

N = 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.

(aaa) “Project” means

(i)

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

generating station including the dam, intake water conductor system,

power generating station, as apportioned to power generation;

(ii)

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

generating station including biomass pellet handling system, pollution

control system, effluent treatment plan, as may be required;

Provided that in case of thermal generating stations, it does not include mining

(if it is a pit head project) and dedicated captive coal mine;

(bbb) “Prudence Check” means scrutiny of reasonableness of any cost or

expenditure incurred or proposed to be incurred in accordance with these

Regulations by the Generating Company;

(ccc) “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;

(ddd) “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 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;

(eee) “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;

(fff) “Run-of-River Generating Station” means a hydro generating station which

does not have upstream pondage;

(ggg) “Run of River Generating Station with Pondage” means a hydro generating

station with sufficient pondage for meeting the diurnal variation of power

demand;

(hhh) “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 as the case may be, whichever is earlier;

(iii)

“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;

(jjj)

“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 State Load

Despatch Centre;

(kkk) “State Generating Station” means a generating station whose entire

generation of electricity is dedicated to the State.

(lll)

“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;

(mmm)

“Statutory Charges” means taxes, cess, duties, royalties and other

charges levied through Acts of the Parliament or State Legislatures or by

Indian Governmental Instrumentality under relevant statutes;

(nnn) “Storage Type Generating Station” means a hydro generating station

associated with storage capacity to enable variation of generation of electricity

according to demand;

(ooo) “Tariff Period” means a period of five (5) years from 1^st April 2024 to 31^st

March 2029,

(ppp) Thermal Generating Station’ means a generating station or a unit thereof

that generates electricity using fossil fuels such as coal, lignite, gas, liquid fuel

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

with coal;

(qqq) “Trial Run” in relation to generating station or unit thereof shall have the

same meaning as defined under Regulation 3 (131) of CERC (Indian

Electricity Grid Code) Regulations, 2023 and its amendments from time to

time till the Odisha Grid Code Regulations, 2015 is amended;

(rrr) “Unloading Point” means the point within the premises of the coal based

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

any other mode of transport;

(sss)

“Useful Life” in relation to a unit of a generating station from the date of

Commercial Operation shall mean the following,

(i)

Coal based thermal generating station -

25 years

(ii)

Hydro generating station including pumped

storage hydro generating station -

40 years

(iii)

AC and DC sub-station

25 years

(iv)

Gas Insulated Substation (GIS)

25 years

(v)

Transmission line (including HVAC & HVDC)

35 years

(vi)

Optical Ground Wire (OPGW)

15 years

(vii) IT system, SCADA and Communication system excluding

OPGW

7 years

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

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

respectively.

Provided that the extension of life of the projects beyond the completion

of their useful life shall be decided by the Commission on case to case basis

basing on the submission of the Generator;

(ttt)

“Year” means a financial year commencing from 1st April of a calendar year

and ending on 31st March of subsequent calendar year.

CHAPTER – 2

DATE OF COMMERCIAL OPERATION AND SALE OF INFIRM POWER

DATE OF COMMERCIAL OPERATION

The date of commercial operation of a generating station or until thereof shall be

determined in accordance with the definition under Regulation 3(1)(n) of these

Regulations.

SALE OF INFIRM POWER:

Supply of infirm power shall be in accordance with the CERC (Deviation Settlement

Mechanism and Related matters) Regulations, 2022 as amended from time to time till the

OERC (Deviation Settlement Mechanism & Related Matters) Regulations is notified 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.

CHAPTER – 3

PROCEDURE FOR TARIFF DETERMINATION

TARIFF DETERMINATION

(1)

Notwithstanding anything contained in these Regulations, the Commission shall

at all times have the authority to determine the tariff, including terms and

conditions thereof, of any Generating Company on a Petition filed by the

applicant.

(2)

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

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

unit(s)there of:

(i)

The interim tariff shall be determined for unit(s) till the time tariff cannot

be determined for the whole of the generating station.

(ii)

The tariff shall be determined for the whole of the generating station after

the cut-off date of the last unit in the generating plant or after the capital

cost of the last unit in the generating plant is finalized, whichever is

earlier;

(iii)

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

prior to 01.04.2024, 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 01.04.2024 to 31.03.2029.

(iv)

The Generating Company shall file an application for determination of

supplementary tariff for the emission control system installed in a coal

based thermal generating station in accordance with these Regulations not

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

system.

(3)

Energy charge component of the tariff of generating station getting coal from the

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

integrated mines as determined under OERC (Determination of Input Price of

Coal from Integrated Mine) Regulations, 2024 as amended from time to time.

(4)

In case of multi-purpose hydro schemes, with irrigation, flood control and power

generation, the capital cost chargeable towards power generating stations shall be

considered for determination of tariff.

(5)

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

supplying power to the beneficiaries through a long term power purchase

agreement, the unit(s) 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 shall 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.

(6)

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

for the expanded capacity in accordance with these Regulations;

Provided that the common infrastructure of 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.

(7)

Assets installed for implementation of the revised emission standards shall form

part of the existing generation project and tariff thereof shall be determined

separately in accordance with the application filed under the 3^rd Proviso to

Regulation 8 (1) of these Regulations.

(8)

For the purpose of determination of tariff, the capital cost of the project may be

broken up into units and distinct units forming part of the project, if required;

Provided that where break-up of the capital cost of the project for different

units are not available and in case of on-going projects, the common facilities

shall be apportioned on the basis of the installed capacity of the units.

(9)

The Commission, if need arises, due to insufficiency of data, explanation,

information etc. provided by the petitioner, may issue provisional tariff for the

whole of the generating station or a unit or units of the generating station till such

time final tariff is determined.

APPLICATION FOR DETERMINATION OF TARIFF

(1)

The Generating Company may make an application for determination of tariff of

new generating station or unit thereof in accordance with these Regulations

within 90 days from the actual Date of Commercial Operation:

Provided that the Generating Company shall make an application (as per

formats prescribed by the Commission with necessary information and

explanation) and shall submit an auditor certificate (in case of non-availability of

Auditor Certificate a Management Certificate duly signed by an authorised

person, not below the level of Director of the Company) indicating the estimated

capital expenditure incurred as on the date of commercial operation and projected

additional capital expenditure for respective years of the tariff period 2024-2029.

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

through a specific prayer in its application filed under Regulation 8(1) of these

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

granting interim tariff from the Date of Commercial Operation (COD) 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 30.12.2024 (as per formats prescribed by

the Commission with necessary information and explanation) except OHPC and

OPGC (UNIT-I & II) and shall be based on admitted capital cost including any

additional capitalization already admitted up to 31.03.2024 (either based on actual

or projected additional capital expenditure) and estimated additional capital

expenditure for the respective years of the tariff period 2024-25 to 2028-29 along

with the true up petition for the period 2019-20 and 2020-2024 in accordance

with OERC (Terms and Conditions for Determination of Generation Tariff)

Regulations, 2014 and OERC (Terms and Conditions for Determination of

Generation Tariff) Regulations, 2020 respectively;

Provided further that, in case of emission control system required to be

installed in the existing generating station or unit thereof to meet the revised

emission standards, an application shall be made for determination of

supplementary tariff (capacity charges or energy charge or both) based on the

actual capital expenditure duly certified by the Auditor;

Provided that the application shall have due recommendation from the CEA.

(3)

The Commission, if so desires, can get the capital and / additional capital

expenditure verified by an independent agency appointed by the Commission, the

cost of such verification shall be borne by the Generating Company or as directed

by the Commission;

(4)

The application shall contain details of underlying assumptions for capital cost

and additional capital expenditure incurred/projected to be incurred, wherever

applicable;

(5)

Any additional capital expenditure will be as per Regulation 20-23 & Regulation

25 of these Regulations.

(6)

The tariff filing shall be in such form and in such manner as may be prescribed by

the Commission from time to time.

(7)

Every application for determination of tariff or for continuation of previously

determined tariff shall be accompanied by a fee as specified by the Commission

for filing of petitions or applications before the Commission, as amended from

time to time.

(8)

The Commission may seek clarification and additional information on the

application and the applicant shall provide clarifications and additional

information within the date stipulated by the Commission.

(9)

True up for any period shall be governed by the provisions of the Regulation

under which the tariff for that year was determined.

TARIFF PETITION

(1)

The Tariff Petition filed by the Generating Company (for their existing generating

station) shall include a forecast of Aggregate Revenue Requirement and expected

revenue from Tariff for each year of the Tariff Period in the manner specified in

these Regulations, and shall be accompanied by applicable fees.

(2)

The forecast of expected revenue from Tariff and charges shall be based on the

estimated quantum of electricity to be generated by each unit / station for each

year of the Tariff Period;

(3)

Based on the forecast of Aggregate Revenue Requirement and expected revenue

from Tariff and charges, the Generating Company shall submit the proposed

Tariff or Fees and Charges for each year of the Tariff Period, to meet the gap, if

any, in the Aggregate Revenue Requirement including unrecovered revenue gaps

of previous years to the extent proposed to be recovered.

(4)

The detail information supporting the forecast including but not limited to details

of past performance, proposed initiatives for achieving efficiency or productivity

gains, technical studies, audited Financial Statements contractual arrangements

and secondary research shall be provided to enable the Commission to assess the

reasonableness of the forecast.

(5)

On receipt of the Petition, the Commission shall either-

(a)

issue an Order approving the Aggregate Revenue Requirement and Tariff

for each financial year, subject to such modifications and conditions as it

may stipulate; or

(b)

reject the Petition for reasons to be recorded in writing, after giving the

Petitioner a reasonable opportunity of being heard.

(6)

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.

(7)

Notwithstanding anything contained above OHPC and OPGC (UNIT-I & II) may

make application (in the Format prescribed by the Commission) by November

30th of every year for determination of tariff in respect of their existing

generating station as a whole or unit(s) thereof.

Provided that the OHPC and OPGC (Unit - I & II) shall make application (in

the prescribed Format) with necessary information and explanations for

determination of tariff based on capital expenditure incurred duly certified by the

auditors up to the date of commercial operation and additional capital expenditure

incurred duly certified by the auditors or projected to be incurred during the

period for which application for determination by tariff is filed of the Generating

Company:

Provided further that application shall contain details of underlying

assumptions for projected capital cost and additional capital expenditure,

wherever applicable.

10.

IN-PRINCIPLE APPROVAL IN SPECIFIC CIRCUMSTANCES:

The Generating Company for a specific generating station 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.

11.

TRUING UP OF TARIFF FOR THE PERIOD 2019-2024

The tariff of the generating stations for the period 2019-20 and 2020-2024 shall be

trued up in accordance with Odisha Electricity Regulatory Commission (Terms and

Conditions for Determination of Generation Tariff) Regulations, 2014 and Odisha

Electricity Regulatory Commission (Terms and Conditions for Determination of

Generation Tariff) Regulations, 2020 respectively along with the tariff petition for the

period 2024-2029. The capital cost admitted as on 31.03.2024 based on the truing up

shall form the basis of the opening capital cost as on 01.04.2024 for the tariff

determination for the period 2024-2029.

12.

TRUING UP OF TARIFF FOR THE PERIOD 2024-2029

(1)

The Commission shall carry out truing up exercise at the end of the Tariff Period

along with the tariff petition filed for the next tariff period, with respect to the

following:

(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 additional capital expenditure incurred up to 31.03.2029 on account of

the Emission Control System as admitted by the Commission.

Provided that the Generating Company, shall make an application, as per the

Format prescribed by the Commission with necessary information and

explanations, for carrying out truing up exercise in respect of the generating

station or a unit thereof:

(2)

The Generating Company, shall submit details of capital expenditure and

additional capital expenditure incurred for the period from 01.04.2024 to

31.03.2029, duly audited and certified by the auditors, for the purpose of truing

up.

Provided that where after the truing up, if the tariff determined is less than the

tariff approved by the Commission under these Regulations, the Generating

Company shall refund the excess amount recovered to the beneficiary(ies) along

with interest at the rate worked out on the basis of one year SBI MCLR plus 100

basis points as prevalent as on 1^st April of the respective year, from the date of

issue of Order by the Commission.

Provided that where after the truing up, if the tariff determined is more than

the tariff approved by the Commission under these Regulations, the Generating

Company shall recover the under-recovered amount from the beneficiary(ies)

along with interest at the rate worked out on the basis of one year SBI MCLR

plus 100 basis points as prevalent as on 1^st April of the respective year, from the

date of issue of the Order by the Commission.

Provided that the amount along with interest at the rates specified in this

Regulation, shall be recovered from the beneficiary(ies) or refunded by the

Generating Company in six (6) equal monthly instalments starting within three

(3) months from the date of issue of the tariff order by the Commission after

completion of the truing up exercise.

(3)

OHPC and OPGC (Unit - I & II) may file an application each year for truing up

of expenses in respect to the capital expenditure and additional capital

expenditure incurred during the previous year(s) for their existing generation

plants/stations for determination of revenue gap/surplus for the ensuing year,

within the time limit as specified in these Regulations.

Provided that the applicant shall submit the information to the Commission, in

such form as may be prescribed by the Commission, together with the Audited

Accounts, extracts of books of account and such other details as the Commission

may require to assess the reasons for and extent of any variation in financial

performance from the approved forecast of Aggregate Revenue Requirement and

expected revenue from tariff and charges.

CHAPTER - 4

TARIFF STRUCTURE

13.

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 14(1) & (2) 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

14(3) 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 6 of these Regulations. The input price of

coal from the integrated mines as determined in accordance with OERC

(Determination of Input Price of Coal from Integrated mine) Regulations, 2024 as

amended from time to time, 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

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

Regulation 45 or 46 of these Regulations, as may be applicable, for recovery of the

annual fixed cost consisting of the components referred to in Regulation 14 of these

Regulations.

14.

ANNUAL FIXED COST, CAPACITY CHARGE & ENERGY CHARGE

(1) Capacity Charges:

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;

(e)

Operation and maintenance expenses;

(f)

Tax on Income

Less:

(g)

Non Tariff Income

Provided that the Special Allowance in lieu of R&M, where opted in accordance

with Regulation 24 of these Regulations, shall be recovered separately and shall not

be considered for computation of working capital.

(2) Supplementary Capacity Charge:

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.

(3) Energy Charge:

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 44 of these Regulations.

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

cost of primary fuel shall be based on the input price of coal as computed in accordance

with OERC (Determination of Input Price of Coal from Integrated mine) Regulations,

2024 as amended from time to time.

(4)

Not withstanding anything mentioned in these Regulations, Capacity Charge

and Energy Charge for OHPC and OPGC (Unit-I & II) will be determined by the

Commission by taking into account the notification(s) issued by the Government of

Odisha from time to time and their PPAs.

CHAPTER – 5

COMPUTATION OF CAPITAL COST & ADDITIONAL CAPITAL EXPENDITURE

AND

CAPITAL STRUCTURE

15.

CAPITAL COST OF THE PROJECT

(1) The Capital Cost of the generating station as determined by the Commission after

prudence check 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 (IDC) 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 (IDC) and Incidental Expenditure During

Construction (IEDC) 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 decapitalization for

respective year of tariff as determined in accordance with these Regulations;

(g) Adjustment of revenue due to 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 upto 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 fulfilment of any conditions for obtaining environment

clearance for the project;

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

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

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

(PAT) scheme of 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 01.04.2024 duly trued up by

excluding liability, if any, as on 01.04.2024;

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

determined in accordance with these Regulations;

Maintenance as admitted 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 Station shall also

include:

(a) Cost of approved Rehabilitation and Resettlement (R&R) plan of the project in

conformity with National R&R Policy and R&R package as approved; and

(b) Cost of the developer’s 10% contribution towards Rajiv Gandhi Grameen

Vidyutikaran Yojana (RGGVY) and Deendayal Upadhyaya Gram Jyoti Yojana

(DDUGJY) project in the affected area.

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 Commission till the date of

acquisition;

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

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 Regulation 20-23 and Regulation 25 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 Regulation 20-25 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 Commission in consultation with Generating Company, 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.

16.

PRUDENCE CHECK OF CAPITAL COST:

The capital cost admitted by the Commission after prudence check shall form the basis

for determination of tariff. The following principles shall be adopted for prudence check

of capital cost of the existing or new projects:

(1) In the case of the thermal generating station, the prudence check may include scrutiny

of the reasonableness of the capital expenditure in the light of capital cost of similar

projects based on past historical data, wherever available, reasonableness of 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 68 and such other

matters as may be considered appropriate by the Commission for determination of

tariff;

(2) Where the power purchase agreement entered into between the Generating Company

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

admitted by the Commission shall take into consideration such ceiling during

prudence check for determination of tariff;

Provided also that the Commission may issue guidelines for vetting of capital cost

of hydro-electric projects by independent agency or expert body and in that event the

capital cost as vetted by such agency or expert may be considered by the Commission

while determining the tariff for the hydro generating station;

Provided also that in case the site of a Hydro Generating Station is awarded to a

developer (not being a State controlled or owned company) by the State Government

by following a transparent process of bidding, any expenditure incurred or committed

to be incurred including the premium payable to the State Government by the project

developer for getting the project site allotted, shall not be included in the capital cost.

17.

INTEREST

DURING

CONSTRUCTION

(IDC)

AND

INCIDENTAL

EXPENDITURE DURING CONSTURCTION (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 upto actual COD:

Provided that any revenue earned during 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 shall be

required to furnish detailed justifications with supporting documents for such

delay including prudent phasing of funds in 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,

IDC and IEDC beyond SCOD may be allowed after prudence check and the

liquidated damages, if any, recovered from the contractor or supplier or agency

shall be adjusted in the capital cost of the generating station.

(5)

If the delay in achieving the COD is attributable either in entirety on in part to the

Generating Company or its contractor or supplier or agency, in such cases, IDC

and IEDC may be disallowed after prudence check either in entirety or on 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 example: 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 months 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 upto 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 as specified in Regulation 26 (1) of these Regulations.

18.

CONTROLLABLE AND UNCONTROLLABLE FACTORS

(1)

The following shall be considered as controllable and uncontrollable factors for

deciding time over-run, cost escalation, IDC and IEDC of the new project:

(a)

The “controllable factors” shall include but shall not be limited to the

following:

(i)

Efficiency in the implementation of the project not involving approved

change in scope of such project, change in statutory levies or change in

law or force majeure events; and

(ii)

Delay in execution of the project 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.

19.

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) Hydro generating stations including pumped storage 4.0%

hydro generating station

(i) Transmission Line

1.0%

(ii) Transmission Sub-station

Green field

4.0%

Brown field

6.0%

(iii)Series Compensation Devices and HVDC Station 4.0%

(iv)Gas Insulated Sub-station (GIS)

Green field

5.0%

Brown field

7.0%

(v) Communication System

3.5%

(vi)Static Synchronous Compensator

6.0%

Provided that:

(i) 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.

20.

ADDITIONAL CAPITALISATION WITHIN ORIGINAL SCOPE AND UPTO

THE CUT-OFF DATE

(1)

The 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 upto the cut-

off date.

(b)

Works deferred for execution;

(c)

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

subject to the provisions under Regulation 19 of these Regulations;

(d)

Payment 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;

(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;

(g)

Force Majeure events; and

(h)

Any additional works/services, which have become necessary for efficient

and successful operation of a generating station but not included in the

original capital cost

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

capitalisation 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 assets forming part of the project but not put to

use, shall not be considered.

(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.

21.

ADDITIONAL CAPITALISATION WITHIN THE ORIGINAL SCOPE AND

AFTER CUT-OFF DATE:

(1)

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 of 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 as part of ash disposal system in the original scope of work;

(d)

Force Majeure events;

(e)

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

the Commission, to the extent of actual payments made;

(2)

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

project after 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)

The 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

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.

22.

ADDITIONAL CAPITALISATION BEYOND THE ORIGINAL SCOPE:

(1)

The capital expenditure, in respect of 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 Governmental Instrumentality or 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

subject to prudence check of efficient utilization of Ash Pond and 100%

utilization of Ash as per MoEF guidelines notified from time to time:

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 sewage treatment plant in 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 20, 21 and 23, 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 or transmission system as the case

may be, 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.

23.

ADDITIONAL CAPITALISATION ON ACCOUNT OF RENOVATION AND

MODERNIZATION

(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 useful life of the generating station or a unit thereof, 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 24 of these Regulations;

(2)

Where the Generating Company, makes an application for approval of its

proposal for Renovation and Modernization (R&M), the approval may be

granted after due consideration of reasonableness of the cost estimates, financing

plan, schedule of completion, interest during construction, use of efficient

technology, cost-benefit analysis, and such other factors as may be considered

relevant by the Commission.

(3)

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

Company 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.

24.

SPECIAL ALLOWANCE FOR COAL BASED THERMAL GENERATING

STATION

In the case of coal-based 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 20, 21, 22 and 23 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;

(1) The Special Allowance admissible to a generating station shall be @ Rs 10.75 lakh

per MW per year for the tariff period.

(2) In the event of a generating station availing 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.

(3) 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.

25.

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 of 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 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 implementation of revised emission standards,

the Commission may grant approval after due consideration of the reasonableness

of the cost estimates, cost derived through competitive bidding, 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 reasonableness of the cost and impact on

operational parameters shall form the basis of 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.

26.

DEBT-EQUITY RATIO

(1)

For new project 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 actual equity deployed is less than 30%, the actual debt

and equity shall be considered for determination of tariff;

Provided further that the equity invested in foreign currency shall be

designated in Indian rupees on the date of each investment;

Provided further that 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 utilised for meeting the capital expenditure of the

generating station.

(2)

The Generating Company shall submit resolution of the Board of the Company

regarding 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 case of the generating station declared under commercial operation prior to

01.04.2024, debt-equity ratio allowed by the Commission for determination of

tariff for the period ending 31.03.2024 shall be considered.

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

life as on 01.04.2024, 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)

Any expenditure incurred or projected to be incurred on or after 01.04.2024 as

may be admitted by the Commission as additional capital expenditure for

determination of tariff, and Renovation and Modernisation expenditure for life

extension, the debt-equity ratio shall be considered in the manner specified in

Clause (1) of this Regulation.

(5)

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.

27.

SPECIAL PROVISIONS

(1)

In respect of a thermal or hydro generating station that has completed the useful

life of the plant or has completed the tenure of the PPA (as applicable), the

Generating Company and the beneficiary shall mutually agree on an

arrangement, where OERC shall continue to determine energy charge, capacity

charges and other charges as specified in these Regulations.

(2)

The beneficiary shall have the first right of refusal and upon its refusal to enter

into an arrangement as above, the Generating Company shall be free to sell the

electricity generated from such station in a manner as it deems fit.

28.

RETURN ON EQUITY

(1)

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

in accordance with Regulations 26 of these Regulations:

(2)

Return on equity shall be computed at the base rate of 14.0% for all thermal

generating stations, at the base rate of 15.5% for run-of-river hydro generating

station and at the base rate of 16.5% for storage type hydro generation station,

pumped storage hydro generating station and run-of-river generating station with

pondage;

Provided that return on equity in case of existing generating stations of OPGC

(Unit - I & II) and existing hydro stations of OHPC shall be as per the provisions

of the PPA.

Provided that return on equity in respect of additional capitalization beyond

the original scope excluding additional capitalization on account of emission

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

rate of one-year marginal cost of lending rate (MCLR) of the State Bank of India

plus 300 basis points as on 1st April of the year, subject to a ceiling of 14%;

Provided further that:

(a)

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 confirmation/report submitted by the

SLDC;

(b)

In case of existing generating station, as and when any of the requirements

under (a) above of this Regulation are found lacking based on the

confirmation/ report submitted by the SLDC, rate of return on equity shall be

reduced by 1.00% for the period for which the deficiency continues;

Provided that if the generator is exempted for FGMO due to its

inherent characteristics with due approval from CERC/CEA, there shall be

no reduction of base rate of RoE.

(c)

In case of a thermal generating station

(i) 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

CERC(Indian Electricity Grid Code) Regulations, 2023 as amended

from time to time, till the Odisha Grid Code Regulations, 2015 is

amended.

(ii) 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%.

29.

TAX ON INCOME

(1)

Income tax of the Generating Company shall be recovered from the beneficiaries.

This will exclude income tax on other income streams (income from non-

generation business).

(2)

The actual assessment of income tax should take into account benefits of tax

holiday and the credit for carry forward losses applicable as per the provisions of

the Income Tax Act 1961 and shall be passed on to the consumers.

30.

INTEREST ON LOAN CAPITAL

(1)

The loans arrived at in the manner indicated in Regulation 26 shall be considered

as gross normative loan for calculation of interest on loan.

(2)

The normative loan outstanding as on 01.04.2024 shall be worked out by

deducting the cumulative repayment as admitted by the Commission up to

31.03.2024 from the gross normative loan.

(3)

The loan repayment for each year of the tariff period 2024-2029 shall be deemed

to be equal to the depreciation allowed for corresponding year/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 upto the date of de-capitalisation of such asset.

(4)

Notwithstanding any moratorium period availed by the Generating Company the

repayment of loan shall be considered from the first year of commercial operation

of the project and shall be equal to the annual depreciation allowed for the year or

part of the year.

(5)

The rate of interest shall be the weighted average rate of interest calculated on the

basis of the actual loan portfolio after providing appropriate accounting

adjustment for interest capitalized at the beginning of each year applicable to the

project;

Provided that if there is no actual loan for a particular year but normative loan

is still outstanding, the last available weighted average rate of interest shall be

considered;

Provided further that if the generating station, does not have actual loan, then

the weighted average rate of interest of the loan portfolio of the Generating

Company as a whole shall be considered.

(6)

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 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 1^st April of the relevant financial year

(7)

The interest on loan shall be calculated on the normative average loan of the

respective years by applying the weighted average rate of interest.

(8)

The changes to the terms and conditions of the loans shall be reflected from the

date of such re-financing.

31.

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 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 that in case of hydro generating stations, the salvage value shall be as

provided in the agreement signed by the developers with the State Government

for development of the generating station;

Provided further that the capital cost of the assets of the hydro generating

station for the purpose of computation of depreciable value shall correspond to

the percentage of sale of electricity under long-term power purchase agreement at

regulated tariff.

Provided also that any depreciation disallowed on account of lower

availability of the generating station or unit, 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 reservoir in case of

hydro generating station shall not be a depreciable asset and its cost shall be

excluded from the capital cost while computing depreciable value of the asset.

(5)

Depreciation for existing project shall be calculated annually based on Straight

Line Method (SLM) and at rates specified in Appendix-A to these Regulations for

the assets of the generating station;

Provided that, the remaining depreciable value as on 31st March of the year

closing after a period of fifteen (15) years from effective date of commercial

operation shall be spread over the balance useful life of the assets;

Provided that for existing Hydro generating plants of OHPC as per the

directions of the High Court of Orissa, depreciation will be calculated at pre-1992

norms notified by Government of India on the book value of the assets or loan

repayment linked to that asset, whichever is higher;

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 A to these

Regulations to reduce front loading of tariff.

Provided further that for existing plants of OPGC (UNIT-I & II), the

applicable depreciation rate for the assets of the generating station shall be as

determined by the Commission from time to time.

(6)

Depreciation for New Projects shall be calculated annually based on the Straight

Line Method (SLM) and at rates specified in Appendix-A to these Regulations

for the assets of the generating station:

Provided that the remaining depreciable value as on 31st March of the year

closing after a period of 15 years from the effective date of commercial operation

of the generating station, 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 A to these

Regulations to reduce front loading of tariff.

(7)

In case of the existing projects, the balance depreciable value as on 01.04.2024

shall be worked out by deducting the cumulative depreciation as admitted by the

Commission upto 31.03.2024 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 (15) 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 (ECS) 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 ECS 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 ECS 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

(SLM) at rates specified in Appendix- A to these Regulations;

Provided that the remaining depreciable value as on 31st March of the year

closing after a period of 12 years from the date of operation of such ECS 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 ECS 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 ECS based on the Straight Line Method (SLM) with a

salvage value of 10% and recovered over ten (10) years or a period mutually

agreed by the Generating Company and the beneficiaries, whichever is higher.

32.

INTEREST ON WORKING CAPITAL

(1)

The working capital shall cover:

(a)

For Coal-based thermal generating stations

(i)

Cost of coal, if applicable, for ten (10) days for pit-head generating

stations and twenty (20) days for non-pit-head generating stations, for

generation corresponding to the Normative Annual Plant Availability

Factor or the maximum coal stock storage capacity, whichever is lower;

(ii) Lime stone towards stock for 15 days corresponding to normative

annual plant availability.

(iii) Advance payment for thirty (30) days towards cost of coal and

limestone for generation corresponding to the Normative Annual Plant

Availability Factor;

(iv) Cost of secondary fuel oil for one month 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

specified in Regulation 34(1) including water charges.

(vi) Receivables equivalent to forty-five (45) days of capacity charges and

energy charges for sale of electricity calculated on the normative annual

plant availability factor; and

(vii) Operation & Maintenance (O&M) expenses and water charges for

one(1) month.

(b)

For Emission Control System (ECS) of coal 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 & Maintenance expenses in respect of the ECS for one

month;

(v) Maintenance spares @20% of operation and maintenance expenses in

respect of ECS;

(c)

For hydro generating stations including pumped storage hydro-electric

generating station

(i)

Receivables equivalent to forty five (45) days of fixed cost;

(ii)

Maintenance spares @ 15% of Operation & Maintenance (O&M)

expenses specified in Regulation 34 (1);

(iii)

Operation and maintenance expenses for one month.

(2)

The cost of fuel in cases covered under Regulation 1(a) of this Regulation shall be

based on the landed fuel cost incurred (taking into account normative transit and

handling losses in terms of Regulation 38 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 and no fuel price escalation shall be provided during the tariff period.

Provided that in case of 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 38 of these

Regulations) and gross calorific value of the fuel as per actual weighted average

for three (3) 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

equal to the one year marginal cost of lending rate (MCLR) of the State Bank of

India issued as on 01.04.2024 or on 1st April of the year during the tariff period

2024-2029 in which the generating station or a unit thereof, is declared under

commercial operation, whichever is later, plus 300 basis points.

Provided that in case of truing-up, the rate of interest on working capital shall

be considered at the one year marginal cost of lending rate (MCLR) of the State

Bank of India issued as on 1st April of each of the financial year during the tariff

period 2024-29, plus 300 basis points.

(4)

Interest on working capital shall be payable on normative basis notwithstanding

that the Generating Company has not taken loan for working capital from any

outside agency.

33.

DE-COMMISSIONING

In case a generating station or unit thereof, after it is certified by CEA 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 realisation 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.

34.

OPERATION AND MAINTENANCE (O&M) EXPENSES

(1)

Thermal Generating station(s)

Normative Operation and Maintenance expenses of thermal Generating station(s)

including security expenses shall be as follows:

(a)

Coal based (including those based on Circulating Fluidised Bed

Combustion (CFBC) technology) generating stations:

Year

(Rs. in Lakh/MW)

200/210/250

MW series

300/330/350

MW series

500 MW

series

600 MW

series

800 MW

series and

above

2024-25

40.92

34.04

27.17

25.78

23.20

2025-26

43.07

35.83

28.60

27.13

24.42

2026-27

45.33

37.71

30.10

28.56

25.70

2027-28

47.71

39.69

31.68

30.06

27.05

2028-29

50.21

41.78

33.34

31.64

28.47

Provided also that O&M 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.

(b)

The Water Charges, 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, subject to actual paid

charges to 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 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 Central Electricity Regulatory

Commission (Terms and Conditions of Tariff) Regulations, 2014 or Special

Allowance or claimed as a part of additional capitalisation or consumption

of stores and spares and renovation and modernization.

Provided that where the date of commercial operation of any additional

unit(s) of a generating station after first four units occurs on or after

01.04.2024, the O&M expenses of such additional unit(s) shall be

admissible at 90% of the operation and maintenance expenses as specified

above;

(c)

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.

(d)

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.

(e)

The operation and maintenance expenses on account of emission control

systems in coal 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 @ 5.25% during the tariff

period ending on 31st March 2029:

Provided that income generated from the sale of gypsum or other by-

products shall be reduced from the operation and maintenance expense

(f)

O&M norms for the existing plants of OPGC (UNIT-I & II) shall be as

determined by the Commission from time to time.

(2)

Hydro generating station:

The following O&M expense norms shall be applicable for hydro generating

stations;

(a) In case of the hydro generating stations including pumped storage hydro

generating stations declared under commercial operation on or after

01.04.2024, Operation & Maintenance expenses shall be fixed at 3.5% of the

original project cost (excluding cost of rehabilitation & resettlement works,

IDC & IEDC) 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 01.04.2024, 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 31.03.2024. 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.

bidding for hydro generating stations shall be allowed separately after

prudence check:

Provided that the generating station shall submit the assessment of the

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 and actual insurance expenses incurred with appropriate

justification.

Provided further that the value of capital spares exceeding Rs. 10 lakhs

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;

(f) O&M norms for the existing plants of OHPC will be as determined by the

Commission from time to time.

35.

NON-TARIFF INCOME

(1)

The amount of Non-Tariff Income of the Generating Company as approved by

the Commission in accordance with Regulation 60 of these Regulations shall be

deducted while determining its Annual Fixed Cost:

Provided that the Generating Company shall submit full details of its forecast

of Non-Tariff Income to the Commission in such form as may be stipulated by

the Commission.

(2)

The Non-Tariff Income shall include:

(a)

Income from rent of land or buildings;

(b)

Income from sale of scrap;

(c)

Income from investments;

(d)

Income from sale of ash/rejected coal;

(e)

Interest income on advances to suppliers/contractors;

(f)

Net Income from supply of electricity by the Generating Company to the

housing colonies of its operating staff and supply of electricity by the

Generating Company for construction works at the generating Station,

after adjusting the expenses incurred for supply of such electricity;

(g)

Income from rental from staff quarters;

(h)

Income from rental from contractors;

(i)

Income from hire charges from contactors and others;

(j)

Income from advertisements;

(k)

Income from sale of tender documents;

(l)

Net-Income from Eco-Tourism Activities;

(m)

Any other Non-Tariff Income.

Provided further that all supply of electricity by the Generating Company to

the housing colonies of its operating staff and for construction works at the

generating Station, shall be metered and billed separately:

Provided also that the tariff for supply of electricity by the Generating

Company to the housing colonies of its operating staff and supply of electricity

by the Generating Company for construction works at the generating Station,

shall be the same as the Tariff approved by the Commission for the supply of

electricity to the respective consumer category by the Distribution Licensee for

that area of supply.

CHAPTER- 6

COMPUTATION OF CAPACITY CHARGE & ENERGY CHARGE

36.

ENERGY CHARGES & SUPPLEMENTARY ENERGY CHARGES

The Energy charges and supplementary energy charge in respect of thermal generating

stations shall comprise 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.

37.

LANDED FUEL COST OF PRIMARY FUEL:

The landed fuel cost of primary fuel for any month shall consist of 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 transparent process or

as approved by OERC;

Provided further that 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 case of coal-fired 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.

38.

TRANSIT AND HANDLING LOSSES:

For coal, the transit and handling losses shall be as per the following norms:-

Thermal Generating Station

Transit and Handling Loss (%)

Pit head station

0.2%

Non-pit head stations- All Rail route

0.8%

Non-pit

head

multi-modal

transportation (using two or more than

two

mode

of transport

involving

multiple trans-shipments)

Provided further that in case of pit-head stations, if coal 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 station shall apply;

Provided further that in case of imported coal, the transit and handling losses

applicable for pit-head station shall apply.

39.

GROSS CALORIFIC VALUE OF PRIMARY FUEL:

(a)

The gross calorific value for computation of energy charges as per Regulation 44

shall be done in accordance with ‘GCV as received’ basis as per Regulation

3(ii).

(b)

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, liquid fuel etc., as per the Format prescribed by the

Commission.

Provided further that the details of blending ratio of the imported coal with

domestic coal, proportion of e-auction coal and the weighted average GCV of the

primary fuels on “as received” basis used for generation during the period shall

also be provided, along with the bills of the respective month:

40.

LANDED COST OF REAGENT:

(a)

Where specific reagents such as Limestone, Sodium Bi-Carbonate, Urea or

Anhydrous Ammonia are used during operation of emission control system for

meeting revised emission standards, the landed cost of such reagents shall be

determined based on normative consumption and purchase price of the reagent

through competitive bidding, applicable statutory charges and transportation cost.

(b)

The normative consumption of specific reagent for the various technologies

installed for meeting revised emission standards shall be as specified in

Regulation 49(g) of these Regulations.

41.

The computation and payment of capacity charge and energy charge for existing plants

of OPGC (UNIT-I & II) will be as per the provisions of the PPA and the provisions of

these Regulations as determined by the Commission based of the information/ data

submitted by the Generating Company.

42.

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 norms specified under these Regulations, and recovered on monthly

basis under capacity charge. The total capacity charge payable for a generating

station shall be shared by its beneficiaries as per their respective percentage share/

allocation in the capacity of the generating station. The capacity charge shall be

recovered as follows in two parts, viz., Capacity Charge for Peak Hours of the

month and Capacity Charge for Off- Peak Hours of the month:

(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)}] 106 - (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)

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 Hours of n^th Month;

AFC =

Annual Fixed Cost;

PAFMpn = Plant Availability Factor achieved during Peak Hours up to the end of

nth Month;

PAFMopn = Plant Availability Factor achieved during Off-Peak Hours upto the

end of nth Month;

NAPAF = Normative Annual Plant Availability Factor.

Provided that in case of 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 part of

the AFC which shall include O&M expenses and interest on loan only.

(3)

Normative Plant Availability Factor for “Peak” and “Off-Peak” Hours in a month

shall be equivalent to the NAPAF specified in Regulation 49(1)(a) of these

Regulations. The number of hours of "Peak" during a day shall be as mentioned

in the RST Order and "Off-Peak" hours shall be the hours other than peak hours

during a day.

Provided that the Commission may modify the “peak” and “off-peak” hours

from time to time.

Provided that 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 achieved for a Month (PAFM) shall be computed in

accordance with the following formula:

Where,

AUXn=Normative auxiliary energy consumption in percentage;

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 SLDC 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 SLDC, 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 (ß) 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 @ fifty (55) paise/ kWh for ex-bus scheduled energy during

Peak Hours and @ forty (40) 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 Regulation 49 of these Regulations.

(7)

Incentives applicable and payable to the existing plants of OPGC (Unit-I & II)

and OHPC will be as determined by the Commission from time to time.

43.

COMPUTATION AND PAYMENT OF SUPPLEMENTARY CAPACITY

CHARGE FOR COAL 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 to 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 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)

(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+SC

C11)

Where,

SCCn= Supplementary Capacity Charge for the nth Month;

AFCe = Annual Fixed Cost of the emission control system;

PAFMn= Plant Availability Factor achieved up to the end of nth Month;

NAPAF= Normative Annual Plant Availability Factor.

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.

(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 42 of these Regulations. The PAFM shall be worked out in accordance

with Clause (4) of Regulation 42 of these Regulations.

44.

COMPUTATION

AND

PAYMENT

ENERGY

CHARGE

AND

SUPPLEMENTARY ENERGY CHARGE FOR COAL BASED THERMAL

GENERATING STATIONS:

(1) 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}

(2) 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}

(3) 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 thermal generating stations:

ECR = [{(SHR - SFC x CVSF) x LPPF / CVPF} + (SFC x LPSFi) + (LC x

LPL)] x 100/(100 - AUX)

(b)

Supplementary ECR for coal based thermal generating stations:

Supplementary ECR = ('ECR) + [(SRC x LPR / 10)/(100-(AUXn +

AUXen))]

Where,

AUX =Normative auxiliary energy consumption in percentage.

CVPF = Weighted Average Gross calorific value of coal as per Regulation 39

in kCal per kg for coal based stations;

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).

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.

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.

(4) 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.

(5) 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 consumption of biomass

based on blending ratio as specified by Authority or actual consumption of biomass,

whichever is lower.

(6) The Commission, through specific tariff orders to be issued for each generating

station shall approve the energy charge rate for each year of the tariff period. Any

variation in Price and Gross Calorific Value of coal as billed by supplier (after

adjusting for variation during storage) shall be adjusted on month to month basis in

the bills;

Provided, that the Generating Company shall indicate Energy Charge Rates at base

price of primary and secondary fuel approved by the Commission and the adjustments

on account of change in price and gross calorific value of coal for the previous month

separately.

45.

COMPUTATION AND PAYMENT OF CAPACITY CHARGE AND ENERGY

CHARGE FOR HYDRO GENERATING STATIONS OTHER THAN PUMPED

STORAGE HYDRO GENERATING STATIONS

(1)

The fixed cost of a hydro generating station shall be computed on annual basis,

based on norms specified under these Regulations, and recovered on monthly

basis under capacity charge (inclusive of incentive) and energy charge, which

shall be payable by the beneficiaries in proportion to their respective allocation in

the saleable capacity of the generating station, i.e. in the capacity excluding the

free power to the home State;

Provided that during the period between the date of commercial operation of

the first unit of the generating station and the date of commercial operation of the

generating station, the annual fixed cost shall provisionally be worked out based

on the latest estimate of the completion cost for the generating station, for the

purpose of determining the capacity charge and energy charge payment during

such period.

(2)

The capacity charge (inclusive of incentive) payable to a hydro generating station

for a calendar month shall be

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

Where,

AFC =

Annual fixed cost specified for the year, in 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 i^th day of the month which

the station can deliver for at least three (3) hours, as certified by the

SLDC 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 SLDC, 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 ex-bus basis, at the computed energy charge rate. 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 (3) decimal places based

on the following formula, subject to the provisions of Clause (9) 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 percent), if any, as per Note in Regulation

53 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 (4) 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

2020-2024 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 (6) of this Regulation exceeds eighty paise per kWh (80p/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 eighty paise per kWh (80p/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).

(11) The SLDC 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.

(12) The computation and payment of capacity charge and energy charge for existing

plants of OHPC will be as determined by the Commission from time to time.

46.

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

annual basis, based on norms specified under these Regulations, and recovered on

monthly basis as capacity charge. The capacity charge shall be payable by the

beneficiaries in proportion to their respective allocation in the saleable capacity of

the generating station;

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 provisionally 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 the actual generation during the month and during peak hours

by a pumped storage hydro generating station shall be certified by the SLDC.

Provided that there would be adjustment at the end of the year based on

actual generation and actual pumping energy consumed by the station during the

year.

(3)

The energy charge shall be payable by every beneficiary for the total energy

scheduled to be supplied to the beneficiary in excess of the design energy plus

75% of the energy utilized in pumping the water from the lower elevation

reservoir to the higher elevation reservoir, at a flat rate equal to the average

energy charge rate of twenty (20) paise per kWh, 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, subject to the provision below.

Provided further 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 upper elevation

reservoir and lower elevation reservoir on hourly basis. The generator shall be

required to maximize the peak hour supplies with the available water including

the natural flow of water. In case it is established that generator is deliberately or

otherwise without any valid reason, is not pumping water from lower elevation

reservoir to the higher elevation during off-peak period or not generating power

to its potential or wasting natural flow of water, the capacity charges of the day

shall not be payable by the beneficiary. For this purpose, outages of the

unit(s)/station including planned outages and the forced outages up to the 15% in

a year shall be construed as the valid reason for not pumping water from lower

elevation reservoir to the higher elevation during off-peak period or not

generating power using energy of pumped water or natural flow of water;

Provided further that the total capacity charges recovered during the year shall

be adjusted on pro rata basis in the following manner in the event of total

machine outages in a year exceeds 15%:

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

Where,

(ACC) adj – Adjusted Annual capacity Charges

(ACC) R – Annual capacity Charges recovered

ATO - Total Outages in percentage for the year including forced and planned

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 CERC(IEGC) Regulations 2023 as

amended from time to time till OERC (Grid Code) Regulations, 2015 is amended.

(6)

The SLDC 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.

47.

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 OERC (Deviation

Settlement Mechanism & Related Matters) Regulations is notified by the

Commission.

(2)

Actual net deviation of every Generating Stations and Beneficiaries 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 or any duration of time block, as amended from time to time, by the

State Load Despatch Centre.

CHAPTER – 7

NORMS OF OPERATION

48.

RECOVERY OF TARIFF & 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 Regulations 49 to

50 of this Chapter.

(2)

The Commission may on its own revise the norms of Station Heat Rate specified

in Regulation 49(1)(c) of this Chapter in respect of any of the generating stations

for which relaxed norms have been specified.

49.

NORMS OF OPERATIONS FOR THERMAL POWER GENERATING

STATIONS

(1)

The norms of operation as given hereunder shall apply to coal based thermal

generating station:

(a)

Normative Annual Plant Availability Factor (NAPAF)

(i)

The Normative Annual Plant Availability Factor for all thermal

generating stations, except those covered under (ii) & (iii) below is

85%.

(ii)

The Normative Annual Plant Availability Factor for existing

Thermal Generating Stations of OPGC (UNIT-I & II) will be as

determined by the Commission from time to time.

(iii)

The Normative Annual Plant Availability Factor for all thermal

generating stations which have completed 30 years from COD is

83%.

(b)

Normative Annual Plant Load Factor (NAPLF) for Incentive

(i)

NAPLF for all thermal generating stations except those covered

under (ii) & (iii) below is 85%.

(ii)

The Normative Annual Plant Load Factor for existing Thermal

Generating Stations of OPGC (UNIT-I & II) will be as determined

by the Commission from time to time.

(iii)

The Normative Annual Plant Load Factor for all thermal generating

stations which have completed 30 years from COD is 83%.

(c)

Gross Station Heat Rate

(i)

The Gross Station Heat Rate for all existing coal based thermal

generating stations, except those covered under (ii) below is

200-300 MW Sets

500 MW Sets (Sub-critical)

2415 kCal/kWh

2375 kCal/kWh

Note 1

In respect of 500 MW and above units where the boiler feed pumps are

electrically operated, the gross station heat rate shall be 40 kCal/kWh

lower than the gross station heat rate specified above.

Note 2

For the generating stations having combination of 200/210/250 MW sets

and 500 MW and above sets, the normative gross station heat rate shall be

the weighted average gross station heat rate of the combinations.

Note 3

The Gross Station Heat Rate above is exclusive of the compensation

specified as per CERC (IEGC) Regulations, 2023 as amended from time

to time till OERC (GRID Code) Regulations, 2015, is amended. The

Generating Company shall, based on the unit loading factor, consider the

compensation in addition to the normative gross heat rate above.

(ii)

The Gross Station Heat Rate for existing Thermal Generating

Stations of OPGC (UNIT-I & II) Ltd will be as determined by the

Commission from time to time

(iii)

The Gross Station Heat Rate for all coal based thermal generating

stations achieving COD on or after 01.04.2014, is to be calculated

based on the following formula:

For 200 – 300 MW set = 1.05 X Design Heat Rate (kCal/kWh)

For 500 MW sets & above = 1.045 x Design Heat Rate (kCal/kWh)

Where the Design Heat Rate of a unit means the unit heat rate guaranteed by

the supplier at conditions of 100% MCR, zero percent make up, design coal

and design cooling water temperature/back pressure.

Provided that 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:

Column

Pressure

Rating

(Kg/cm2)

150

170

247

260

270

SHT/RHT

(⁰C)

535/535

537/537

537/565

565/593

593/593

600/600

Type of

BFP

Electrical

Driven

Turbine

driven

Turbine

driven

Turbine

driven

Turbine

driven

Turbine

driven

Turbine

driven

Turbine

driven

Max

Turbine

Cycle Heat

rate

(kCal/kWh)

1955

1950

1935

1900

1850

1814

1810

1790

Min. Boiler Efficiency (%)

Sub-

Bituminous

Indian Coal

(%)

86.5

Bituminous

Imported

Coal (%)

89.5

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 pressure and temperature parameters of a unit

are different from above ratings, the maximum design unit heat rate of the

nearest class shall be taken;

Provided also that where 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 unit design heat rate shall be arrived at

by using guaranteed turbine cycle heat rate and boiler efficiency;

Provided also that where the boiler efficiency is 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 case of coal based generating station, if one or more

units were declared under commercial operation prior to 01.04.2024, the heat

rate norms for those units as well as units declared under commercial operation

on or after 01.04.2024 shall be lowest of the heat rate norms considered by the

Commission during tariff period 2020-24 or those arrived at by above

methodology or the norms as per the Regulation 49(1)(c)(i) of this Regulation;

Note: In respect of units where the boiler feed pumps are electrically operated,

the maximum design unit heat rate shall be 40 kCal/kWh lower than the

maximum design unit heat rate specified above with turbine driven Boiler

Feed Pump.

(d)

Secondary fuel oil consumption

(i)

The secondary fuel oil consumption for all existing coal based

thermal generating stations with wall (front/rear/sides/fixed boilers)

who have achieved CoD before 01.04.2014 except as mentioned (iii)

below is 1 ml/kWh.

(ii)

The Secondary fuel oil consumption for all coal based thermal

generating stations, who have achieved CoD on or after 01.04.2014

is 0.50 ml/kWh.

(iii)

The Secondary fuel oil consumption for existing Thermal Generating

Stations of OPGC (Unit - I & II) Ltd. will be as determined by the

Commission from time to time.

(e)

Auxiliary Energy Consumption

(i)

The Auxiliary Energy Consumption for all coal based thermal

generating stations is

Sl. No.

Generating Station

With Natural Draft

cooling tower or

without cooling tower

(i)

200 MW – 300 MW series

8.5%

(ii)

500 MW & above series

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 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 on case to case basis.

(ii)

The

Auxiliary Energy Consumption for existing Thermal

Generating Stations of OPGC (Unit - I & II) Ltd will be as

determined by the Commission from time to time.

(f)

Norms of Auxiliary energy consumption for the emission control

system (AUXen) of thermal generating stations:

Name of Technology

AUXen

(as % of gross

generation)

(1)

For reduction of emission of

Sulphur dioxide:

a) Wet Limestone based FGD system

(without Gas to Gas heater)

1.0%

b) Lime Spray Dryer or Semi dry

FGD System

1.0%

c) Dry Sorbent

Injection

System

(using Sodium bicarbonate)

NIL

d) For CFBC Power plant (furnace

injection)

NIL

e) 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

b) 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.

(g)

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 = Weighted Average Gross calorific value of coal in kCal per kg

for coal based thermal generating stations computed in accordance

with Regulation 39 of these Regulations;

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;

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 = 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.

50.

NORMS OF OPERATION FOR HYDRO GENERATING STATION

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

(a)

Normative annual plant availability factor (NAPAF) for hydro generating

stations:

(i)

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%;

(ii)

Storage and Pondage type plants with head variation between FRL

and MDDL of more than 8%, where plant availability is not affected

by silt: the month wise peaking capability as provided by the project

authorities in the DPR (approved by CEA or the State Government)

shall form basis of fixation of NAPAF;

(iii)

Pondage type plants where plant availability is significantly affected

by silt - 85%;

(iv)

Run-of-river type plants: NAPAF to be determined plant-wise,

based on 10-day design energy data, moderated by past experience

where available/relevant.

(b)

A further allowance may be made by the Commission in NAPAF

determination under special circumstances, e.g. abnormal silt problem or

other operating conditions, and known plant limitations.

(c)

The Normative Annual Plant Availability Factor (NAPAF) for existing

Hydro Generating Stations of OHPC Ltd will be as determined by the

Commission from time to time.

(d)

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.

(e)

Auxiliary Energy Consumption (AEC) for Hydro generating stations:

Type of Hydro Generating Station

AEC

Installed

Capacity above

200MW

Installed

Capacity upto

200MW

Surface hydro generating stations

Rotating Excitation System

(Mounted on generator shaft)

0.7%

Static Excitation System

1.0%

1.2%

Underground

hydro

generating

stations

Rotating Excitation System

(Mounted on generator shaft)

0.9%

Static Excitation System

1.2%

1.3%

CHAPTER – 8

SCHEDULING, ACCOUNTING AND BILLING

51.

SCHEDULING

The methodology for scheduling and dispatch for the generating station shall be as

specified in the Grid Code.

52.

METERING AND ACCOUNTING

The provisions of the Grid Code shall be applicable for the purpose of metering and

accounting.

53.

BILLING AND PAYMENT OF CHARGES

(1)

Bills shall be raised by the Generating Company for capacity charge, energy

charge and Incentive on monthly basis and payments shall be made by the

beneficiaries directly to the Generating Company, subject to adjustments at the

end of the year.

(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.

(3)

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 herein).

Note:

Free energy for home State, in percent and shall be taken as notified by the

Commission from time to time

54.

RECOVERY OF STATUTORY CHARGES:

The Generating Company shall recover the statutory charges imposed by the State and

Central Government such as electricity duty, water cess & charges by considering

normative parameters specified in these Regulations. In case of the electricity duty is

applied on the auxiliary energy consumption, such amount of electricity duty shall

apply on normative auxiliary energy consumption of the generating station (excluding

colony consumption) and apportioned to each of the beneficiaries in proportion to their

schedule dispatch during the month.

55.

LATE PAYMENT SURCHARGE (LPS)

In case the payment of any bill for charges payable under these Regulations is delayed

by a beneficiary beyond a period of forty five (45) days from the date of receipt of the

bill, a late payment surcharge at the rate of 1.25% per month 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.

56.

REBATE

(1)

For payment of the bill(s) of the Generating Company through Letter of Credit on

presentation or through National Electronic Funds Transfer (NEFT)/ Real Time

Gross Settlement (RTGS) within a period of 2 working days of presentation of

bills by the Generating Company, a rebate of 2% shall be allowed.

(2)

Where payments are made on any day after two (2) working days and within a

period of five (5) working days of presentation of bills by the Generating

Company, a rebate of 1.5% shall be allowed.

(3)

Where payments are made on any day after five (5) working days and within a

period of thirty (30) days of presentation of bills by the Generating Company, a

rebate of 1% shall be allowed.

CHAPTER – 9

SHARING OF BENEFITS

57.

SHARING OF GAINS DUE TO VARIATION IN NORMS

(1)

The Generating Company shall workout gains based on the actual performance of

applicable Controllable parameters as under:

(i)

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 Generating Company and the beneficiaries on

annual basis. The financial gains computed as per the following formulae in case

of generating station 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 50:50 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, Auxiliary Energy Consumption and Secondary Fuel Oil

Consumption for the month.

Provided that in 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 following formulae provided the

saleable scheduled generation is more than the saleable design energy and shall

be shared in the ratio of 50:50 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]

58.

SHARING OF SAVING IN INTEREST DUE TO RE-FINANCING OR

RESTRUCTURING OF LOAN:

(1)

The Generating Company shall make every effort to re-finance the loan as long

as it results in net savings on interest and in that event the costs associated with

such refinancing shall be borne by the beneficiaries and the net savings shall be

shared between the beneficiaries and the Generating Company, in the ratio of

50:50.

(2)

In case of dispute, any of the parties may make an application in accordance with

the Odisha Electricity Regulatory Commission (Conduct of Business)

Regulations, 2004 as amended from time to time, for settlement of the dispute:

Provided that the beneficiaries 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 loan

59.

Sharing of net gains of Generating Company with the beneficiary (ies) due to supply of

power from alternate source shall be in the ratio of 50:50. In case of existing plants of

OPGC (UNIT-I & II) and OHPC sharing of net gains will be as determined by the

commission based on prudence check considering the information/ data submitted by

the Generating Company.

60.

SHARING OF NON-TARIFF INCOME

The details of Non-Tariff income in case of generating station as listed in Regulation

35(2) shall be furnished by the Generating Company at the time of Tariff filling. The

net Non-Tariff Income excluding Income from Investments shall be shared between

the beneficiaries and the Generating Company, in the ratio 50:50.

61.

SHARING OF CLEAN DEVELOPMENT MECHANISM (CDM) BENEFITS

The proceeds of carbon credit from approved emission reduction project under CDM

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

(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 – 10

MISCELLANEOUS PROVISIONS

62.

OPERATIONAL NORMS TO BE CEILING NORMS

Norms of operation specified in these Regulations are the ceiling norms and shall not

preclude the Generating Company and the beneficiaries from agreeing to the improved

norms of operation and in case the improved norms are agreed to, such improved

norms shall be applicable for determination of tariff.

63.

DEVIATION FROM CEILING TARIFF

(1)

The tariff determined in these Regulations shall be a ceiling tariff. The

Generating Company and the beneficiaries 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.

(5)

The Generating Company and the beneficiaries of a generating station shall be

required to approach the Commission for charging 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 as per Regulation 12 of these

regulations.

64.

HEDGING OF FOREIGN EXCHANGE RATE VARIATION

(1)

The Generating Company may hedge foreign exchange exposure in respect of the

interest on foreign currency loan and repayment of foreign currency loan taken

for the generating station, in part or full at the discretion of the Generating

Company.

(2)

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

year-to-year basis as expense in the period in which it arises and extra rupee

liability corresponding to such foreign exchange rate variation shall not be

allowed against the hedged foreign debt.

(3)

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.

65.

RECOVERY OF COST OF HEDGING FOREIGN EXCHANGE RATE

VARIATION

(1)

Every Generating Company shall recover the cost of hedging and foreign

exchange rate variation on year-to-year basis as income or expense in the period

in which it arises

(2)

Recovery of cost of hedging and foreign exchange rate variation shall be made

directly by the Generating Company, from the beneficiaries, without making any

application before the Commission:

Provided that in case of any objections by the beneficiaries to the amounts

claimed on account of cost of hedging or foreign exchange rate variation, the

Generating Company, may make an appropriate application before the

Commission for its decision.

66.

APPLICATION FEE AND THE PUBLICATION EXPENSES

The application filing fee and the expenses incurred on publication of notices in the

application for approval of tariff, may in the discretion of the Commission, be allowed

to be recovered by the Generating Company, directly from the beneficiaries.

67.

REIMBURSEMENT OF FEES, CHARGES AND EXPENSES

(1)

Fees and charges paid by the generating companies under the prevailing

Regulation/ Notification on Fees for filing of petitions or applications before the

Commission, as amended from time to time, shall be reimbursed directly by the

beneficiaries in proportion of their allocation in the generating stations.

(2)

The Generating Company shall be entitled to recover the fees and charges as

mentioned in this Regulation which have been paid till the notification of these

Regulations.

(3)

The Commission may for the reasons to be recorded in writing and after hearing

the affected parties, allow reimbursement of any fee or expenses as may be

considered necessary.

68.

PUBLIC PROCUREMENT THROUGH COMPETITIVE BIDDING:

The Generating Company for a specific generating station 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.

69.

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.

70.

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.

71.

POWER TO GIVE DIRECTIONS OR ISSUE OF SUO-MOTO ORDERS

The Commission may, from time to time, issue such directions and orders, as

considered appropriate, for effective implementation of these Regulations.

72.

POWER TO AMEND

The Commission, for reasons to be recorded in writing, may at any time vary, alter or

modify any of the provisions of these Regulations by an amendment.

73.

INTERPRETATION

If a question arises relating to the interpretation of any provision of these Regulations,

the decision of the Commission shall be final.

By Order of the Commission

Dr. PRIYABRATA PATNAIK

SECRETARY

Appendix-A Depreciation Schedule

Sl.

No.

Asset Particulars

Depreciation

Rate: SLM

(Salvage

value =10%)

[for Existing

Projects]

Depreciation

Rate: SLM

(Salvage

value =10%)

[for New

Projects]

A. Land under full ownership

B. Land under lease

for investment in the land

3.34%

For cost of clearing the site

3.34%

Land for reservoir in case of hydro generating

station

3.34%

C. Assets purchased new

Pl & Machinery in generating stations

(i) Hydro electric

5.28%

4.22%

(ii) Steam electric NHRB & waste heat recovery

boilers

5.28%

4.22%

(iii)

Diesel electric and gas plant

5.28%

4.22%

Cooling towers & circulating water systems

5.28%

4.22%

Hydraulic works forming part of the Hydro-

generating stations

(i) Dams, Spillways, Weirs, Canals, Reinforced

concrete flumes and syphons

5.28%

4.22%

(ii) Reinforced concrete pipelines and surge tanks,

steel pipelines, sluice gates, steel surge tanks,

hydraulic control valves and hydraulic works

5.28%

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, Kiosk, sub-station equipment &

other fixed apparatus (including plant)

(i) Transformers including foundations having

rating of 100 KVA and over

5.28%

4.22%

(ii) Others

5.28%

4.22%

Switchgear including cable connections

5.28%

4.22%

g Lightning arrestor

4.22%

(i) Station type

5.28%

4.22%

(ii) Pole type

5.28%

4.22%

h Synchronous condenser

5.28%

4.22%

i Batteries

9.5%

Underground cable including joint boxes and

disconnected boxes

5.28%

4.22%

Cable Duct system

5.28%

4.22%

Overhead lines including cable support

(i)

Lines on fabricated steel operating at terminal

voltages higher than 66 KV

5.28%

4.22%

(ii) Lines on steel supports operating at terminal

voltages higher than 13.2 KV but not

exceeding 66 KV

5.28%

4.22%

(iii)

Lines on steel on reinforced concrete support

5.28%

4.22%

(iv) Lines on treated wood support

5.28%

4.22%

m Meters

5.28%

4.22%

Self propelled vehicles

9.50%

Air Conditioning Plants

(i) Static

5.28 %

4.22%

(ii) Portable

9.50%

p(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 %

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 %

(ii) Telephone lines and telephones

15 %

(iii)

Fibre Optic/OPGW

6.33%

I.T. equipments including software, UNMS,

URTDSM, EMS, Cyber security system,

REMC, WAMS, SCADA system

15.00%

Any other assets not covered above

5.28%

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.

Printed and Published by the Director, Directorate of Printing, Stationery and Publication, Odisha, Cuttack-10

Ex. Gaz. 1384—173+30