Regulatory Framework in Indian Power Sector

Module C5V K Agrawal

ED, NLDC

POSOCO

Contents

Unscheduled Interchange charges and related matters Regulations, 2009

Measures to relieve congestion in real time operation Regulations, 2009

Regulation of Power Supply, Regulation,2010

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UI Regulation

4

Electricity MarketElectricity Market

Supply and Demand to be matched in real time

Control Area: to maintain its interchange schedule with other control areas Control its area load/generation

Unscheduled Interchange The imbalance between scheduled quantum and Actual

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Background

Prior 2002 No mechanism to handle real time energy imbalance Booking of energy drawal at the end of the month .. REA

Real time imbalance settlement ABT Order .. 1999 Frequency linked real time pricing mechanism Facilitates Grid Discipline Promotes Economy exchange/Merit order despatch

Part of IEGC and Tariff Regulation.. Till 2008 Separate UI Regulation

Principle Regulation: Since 1.4.2009 Subsequent amendments since 3.5.2010 and 5.3.2012

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Definitions ‘Generating station’

means a generating station whose tariff is determined by CERC

Beneficiary means the person purchasing electricity generated from the generating station;

Seller means a person, other than a generating station, supplying electricity, through a

transaction scheduled in accordance with the regulations applicable for short term open access, medium term open access and long term access.

Buyer means a person, other than the beneficiary, buying electricity, through a transaction

scheduled in accordance with the regulations applicable for short term open access, medium term open access and long term access

Gaming in relation to these regulations, shall mean an intentional misdeclaration of declared

capacity by any generating Station or seller in order to make an undue commercial gain through Unscheduled Interchange charges.

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A Typical Dispatch

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

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FIRM SHARES IN ISGS

ADVANCE SHORT TERM BILATERAL CONTRACTS

Day Ahead, PX

Sell

BuyBuy

Sell

Forecast

UI

Contingency Real-time

Surpluses/Deficits - Balance supply and demand

Hours

‘00 M

W

Regulation 5( UI charges)

UI Charges payable for Over drawal by buyers and beneficiaries Under injection by sellers and Generating stations

UI Charges receivable for Under drawal by the buyers and beneficiaries Over injection by sellers and Generating stations

Shall be worked out on the average frequency in 15 minutes time block

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Clause 5(1)

Regulation 5 (Contd) Capping for generators

Generators using coal, lignite or gas supplied under APM

Excess of 105% over DC in a time block and excess of 101% of average DC over a day

Capping for buyers/beneficiaries In excess of 10% of under drawals w.r.t schedules or In excess of 250MW which ever is less

Capping for sellers In excess of injection of 20% of schedules Subject to a limit of 105% of the station capacity in a

time block or 101% of the installed capacity over a day

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Regulation 5( contd)

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Clause 5(2) UI Rate: Rs/-0 /kwh : Freq >50.2 Hz UI charges corresponding to grid frequency interval

<50.02 Hz and >=50.0 Hz based on the Median value of the average energy charge of

coal/lignite based generating stations for the six months period of August 2010 to January 2011

UI charges corresponding to grid frequency interval <49.82 Hz and >=49.8 Hz based on Provide sufficient incentive to the generating station

based on coal including imported coal to support the grid after meeting fixed and energy charge.

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Regulation 5( contd)

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Clause 5(2) UI Rate corresponding to grid frequency interval <49.5 Hz based on

highest of the average energy charges of generating stations for the six months period of August 2010 to January 2011

UI price vector Shall be in steps of 0.02 Hz May be reviewed and notified by the Commission

Infirm power injection During the testing prior to COD at UI rate Periodicity not to exceed six months subject to extension with prior permission by

the Commission Subject to ceiling cap rates for the fuels used.

UI over Asynchronous regions Computed based on UI rates prevailing in that region Settled as per the average of the UI charges computed for the two regions.

Regulation 6:Declaration, Scheduling & Gaming

Thermal Gen up to 105% of DC in a time block and averaging upto 101% of DC in a

day : not construed as gaming UI admissible for such excess generation

In case of Gaming UI shall be reduced to ‘zero’ UI shall be adjusted to beneficiaries in the ratio of their capacity

share in the station Hydro Generation

Should respond to Grid freq change and inflow fluctuation Should not indulge in gaming and cause grid constraints The difference in actual and schedule energy to be compensated

on 4th days schedule S4=E4+(A1-(E1))

Regulation 7: Limits on UI Volume and consequences

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The overdrawal by beneficiary/buyer <12% of its schedule drawal or 150MW which ever is

lower in any time block at freq < 49.8 Hz and < 3% on daily aggregate basis for all the time blocks

when freq < 49.8 Hz

The under-injection by generator/seller <12% of its schedule injection or 150MW which ever is

lower in any time block at freq < 49.8 Hz < 3% on daily aggregate basis for all the time blocks

when freq < 49.8 Hz

Additional UI Charge Over drawal or Under injection at each time block Applicable at the frequency below 49.7 Hz Methodology as per clause 3(a) Schedule A

Additional UI Charge for generating station using APM Applicable below 49.7 Hz Methodology as per clause 3(b) of Schedule A

Additional UI Charge To be specified as percentage on the Base UI rate /Capped rate

Additional UI Charge on IR Exchange Not applicable

Regulation 7: Limits on UI Volume and consequences

Schedule A: Unscheduled Interchange Charges

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UI rates ( Floor and Ceiling)Time Permissible Frequency

BandCeiling UI Rate (paise/kWh)

Floor UI Rate (paise/kWh)

Slope (paise/kWh for each 0.02 Hz)

1st July 2002 – 31st March 2004

49.0 Hz – 50.5 Hz 420 0 5.6

1st April 2004 – 30th Sept 2004

49.0 Hz – 50.5 Hz 600 0 8

1st October 2004 – 29th April 2007

49.0 Hz – 50.5 Hz 570 0 9

30th April 2007- 6th Jan 2008

49.0 Hz – 50.5 Hz 745 0 6 (50.5-49.8)9 (49.8-49.5)16 (49.5-49.0) 

6th Jan 2008 – 30th March 2009

49.0 Hz – 50.5 Hz 1000 0 8 (50.5-49.8)18 (49.8-49.0) 

1st April 2009 – 3rd May 2010

49.2 Hz – 50.3 Hz 735 0 12 (50.3-49.8)17 (49.8-49.2) 

3rd May 2010 to 16th Sep 2012

49.5 Hz – 50.2 Hz 873 0 15.5(50.2-49.7)47 (49.7-49.5)

17th Sep 2012 to till date

49.7 Hz – 50.2 Hz 900 0 16.5(50.2-50.0)28.5(50.0-49.8)28.12(49.8-49.5)

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UI Rates Infirm Power

Domestic Coal/Lignite/Hydro: ` 1.65/kWh

APM Gas as fuel : ` 2.60/kWh

Imported Coal / RLNG : ` 3.30/kWh

Liquid Fuel : ` 9.00/kWh

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UI Charge receipt side

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Addnl UI Charges

Overdrawal By beneneficiary <49.7 Hz and >= 49.5 Hz : 20% of the UI charge at corresponding

frequency ( 590.63paise /kWh to 1051.88paise /kWh) <49.5 Hz and >=49.2 Hz: 40% of the UI charge corresponding to

frequency of 49.5 Hz i.e 900paise /KWh (1260.63paise /kWh) <49.2 Hz : 100% of the UI charge corresponding to frequency of

49.5 Hz i.e 900paise /KWh (1800 paise /kWh)

Under injection by seller <49.7 Hz and >= 49.5 Hz : 10% of the UI charge at corresponding

frequency ( 590.63paise /kWh to 961.88paise /kWh) <49.5 Hz and >=49.2 Hz: 20% of the UI charge corresponding to

frequency of 49.5 Hz i.e 900paise /KWh (1080paise /kWh) <49.2 Hz : 40 % of the UI charge corresponding to frequency of

49.5 Hz i.e 900paise /KWh (1260.63 paise /kWh)

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Under injection by Generators using fuel under APM <49.7 Hz and >= 49.5 Hz : 10% of the capped UI rate of 421.50

paise/kWh (463.65 paise/kWh) <49.5 Hz and >=49.2 Hz: 20% of the capped UI rate of 421.50

paise/kWh (505.8 paise/kWh) <49.2 Hz : 20% of the capped UI rate of 421.50 paise/kWh (505.8

paise/kWh) (590.1 paise /kWh)

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Addnl UI Charges

UI Charges ( payment side)

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UI Accounting

RPC shall issue, to all constituents, by Tuesday, for seven day period ending on the penultimate Sunday mid-night.

“Regional Unscheduled interchange pool account fund” to be maintained by RLDC

Commission may by order direct any other entity to operate and maintain the respective “Regional Unscheduled Interchange Pool Account Funds”:

Separate books of accounts shall be maintained for the principal component and interest component of Unscheduled Interchange charges and Additional Unscheduled Interchange charges by the respective Regional Power Committees.

Payment appropriation sequence

All payments received in the “Regional Unscheduled Interchange Pool Account Fund” of each region shall be appropriated in the following sequence:

First towards any cost or expense or other charges incurred on recovery of UI charges

Next towards over dues or penal interest, if applicable Next towards normal interest Lastly, towards UI and additional UI charges.

Any additional UI charge collected from a regional entity shall be retained in the “Regional Unscheduled Interchange Pool Account Fund” of the concerned region where the regional entity is located.”

Inter-regional UI should have highest priorityMention of normal interest not understood

Schedule of UI payment and security

UI payment : high priority Within 10 days of issuance of accounts by RPC Delayed payment of interest @0.04 % per day of delay :

in case payment is made beyond 12 days of issuance of sttement

RLDC to pay within two days of receipt of UI amount in pool fund

Measures to Relieve Congestion in real time

28

CongestionCongestion

The condition when actual flow in a transmission system exceeds the available transfer capacity

What is Congestion charge

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That the congestion charge is a tool to relieve congestion through commercial signals.

When it is imposed

When demand for transmission capacity exceeds the Available Transfer Capability limits.

This could happen due to following reasons:

Severe high demand conditions towards one region forcing most of the power to rush towards that.

Severe load crash conditions in a region resulting into large export of power from that region to other regions.

Skewed load generation pattern between two regions which could be combination of first two factors.

Widely prevailing market factors forcing the cheaper generation in one region trying to replace the costlier generation in the other.

Background

Concept of Congestion Charge Introduced in 2007 vide CERC order date 7th Nov’2007 Applicable for constituents in the Northern Region Congestion charge of 300 Paise /kWh over and above UI for

deviation from schedules

Regulations Draft Regulation : 9th Jan ‘2009 Final Regulation: 22nd Dec’2009 Order dated : 8th Jan’2010 seeking comments Final Order : 17th March ’2010 Detailed procedures : 11th June 2010

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Chapter I: Definition

“Available Transfer Capability (ATC)” means the transfer capability of the inter-control area transmission system

available for scheduling commercial transactions (through long term access, medium term open access and short term open access) in a specific direction, taking into account the network security. Mathematically ATC is the Total Transfer Capability less Transmission Reliability Margin.

“Congestion” means a situation where the demand for transmission capacity exceeds

the Available Transmission Capability; “Congestion charge”

means the supplementary charge kicked in on one or more Regional entities in one or more Regions for transmission of power from one Region to another or from one State to another within a Region when the deviations from the schedule cause the net drawal of power in the inter-regional or intra-regional transmission links to go beyond the Total Transfer Capability limit;

POSOCO 31

Chapter I: Definition….

“Control area” means an electrical system bounded by interconnections (tie

lines), metering and telemetry, where it controls its generation and/or load to maintain its interchange schedule with other control areas whenever required to do so and contributes to frequency regulation of the synchronously operating system;

“Credible contingency” means the likely-to-happen contingency, which would affect the

Total Transfer Capability of the inter-control area transmission system;

“Regional entity” means such persons whose metering and energy accounting is

done at the regional level;

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Chapter I: Definition….

“Transmission Reliability Margin (TRM)” means the amount of margin kept in the total transfer capability

necessary to ensure that the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions;

“Total Transfer Capability (TTC)” means the amount of electric power that can be transferred reliably

over the inter-control area transmission system under a given set of operating conditions considering the effect of occurrence of the worst credible contingency.

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Calculation of TTC, ATC and TRM SLDCs shall assess the TTC,TRM&ATC on its iner-state transmission

corridor considering the meshed intra-state corridors for export/import of power with ISTS. This figure along with data would be forwarded to respective RLDCs

Regional Load Despatch Centres shall assess TTC, ATC and TRM of individual control areas within the Region, if required, and the same would be put on the website of respective RLDC, along with the details of basis of calculations, including assumptions if any, three months in advance. The specific constraints indicated by the study would also be put on the website

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Chapter II Measures to Relieve Congestion

The National Load Despatch Centre shall asses the TTC, ATC and TRM of inter-regional links / Corridors in consultation with RLDCs, for three months in advance.

TTC, ATC, and TRM along with the details of basis of calculations, including assumptions if any, shall be put up on the website of NLDC and RLDC at least three months in advance. The specific constraints indicated by the study would also be put on the website.

Provided further that National Load Despatch Centre (NLDC) and/or concerned Regional Load Despatch Centre (RLDC) , may revise the TTC , ATC and TRM due to change in system conditions, which includes change in network topology or change in anticipated active or reactive generation or load, on account of outage or otherwise, of one or more generators or transmission lines, at any of the nodes in the study.

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Calculation of TTC…contd…

Power System modelling

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EHV transmission network shall be normally modelled down to 220 kV level with exceptions for

generating units connected at 132 kV and for North Eastern Region, it shall be modelled down to

132 kV.

Normally all generating units greater than 50 MW and connected at 132kV and above shall be

modelled. Smaller generating units (particularly hydro units) may be lumped for study purposes. Load shall be generally lumped Load shall be generally lumped at 220 kV or 132 kV, as the

case may be. Actual system data wherever available shall be used for power system modelling. In cases where data is not available, standard data as given in the CEA Manual on Transmission Planning Criteria shall be considered

Separate base cases calculating the export and import capability corresponding to both peak and off- peak load and generation with the likely scenario during the time frame for which transfer capability is to be assessed shall be used in the Simulation Studies for calculation of TTC and TRM of the required transmission corridors.

Detailed procedure

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Assessment of TTC/ATC/TRM

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Methodology In harmony with the detailed procedure of the Central Transmission Utility (CTU) prepared

reliable system operation and to facilitate non discriminatory open access in transmission as per CERC regulations on Open Access and Power Markets.

Simulation Studies based on a representative scenario

Power System model

Regional Network EHV Network upto 220kV 132 kV Network for NE Region Unit size of 50 MW and above Load modelling

State Network May consider lower voltage network also

Separate Base case Peak /Off –Peak Load Export/Import Capability

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Input Data Base case preparation

Network Topology Unity Availability Coal Fired Thermal Despatch Gas /Nuclear Despatch Hydro Despatch Reactive Power capability of Units Nodal MW/MVAR Demand Operating Limits for Transmission Line

90% of MCR for ICTs Emergency limit 110% of normal operating limit

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TTC Assessment Increasing Demand at the importing area Increasing generation at the exporting area Till Credible Contingency

Credible Contingency Outage of single Transmission element (N-1) in the transmission

corridor/connected system. Outage of largest unit in the importing area

Base case Transmission loading within normal operating limits Voltage within operating limits of IEGC

To be declared three months in advance Regular review in the event of outages/ system condition change

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TTC may be limited by Violation of grid voltage operating range or Violation of transmission element operating limit in the base case

or Violation of emergency limit in the contingency case

TRM To ensure that the interconnected transmission network is secure

under a reasonable range of uncertainties in system conditions. Forecasting uncertainties Size of largest unit size in the control area Single largest anticipated infeed in the control area

The TTC: to be available at the website of RLDCs and NLDC

Revisions in case of change in system conditions

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Applicability of Congestion charge

Congestion Charge To be applied as a commercial measure to relieve

congestion Payable by Regional entities causing congestion in the

inter/intra regional link Receivable by Regional entities relieving congestion

Applicable to any regional entity/entities Detail procedure by NLDC Congestion charge

Payable by overdrawing entity over and above UI charges payable

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Applicability of Congestion Charge

Frequency below 50 Hz in a importing control area For over drawal /under injection

Frequency above 50 Hz in a exporting control area For under drawal / over injection

May be applicable for intra regional corridor also Congestion Charge rate

` 5,45 /kWh as per commission order dated

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Declaration of Congestion

Real Time display at SLDCs/RLDC/NLDC

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A corridor shall be considered congested Grid voltage in the important nodes downstream/

upstream of the corridor is beyond the operating range specified in the IEGC and/or

The real-time power flow along a corridor exceeds the ATC for that corridor for continuously one time block of 15-minute and/ or

One or more transmission lines in the corridor are loaded beyond the operating limit

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Warning Notice

Violation of ATC or Security Criteria for continuously for two blocks NLDC to issue warning notice to concerned RLDC Shall be on website of NLDC

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Non Applicability of Congestion Charge

In case of scheduled power flow Forced outage of Transmission element Open Access Transaction be curtailed as per priority as

per regulation Revision of TTC/ATC/TRM

In case congestion is due to Violation of Grid Voltage operating range One or more lines loaded beyond operating limits TTC/ATC/TRM shall be revised

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Application of Congestion Charge

Persistent Congestion For more than two block( not counting the block when warning was

issued) NLDC/RLDCs to issue notice for application of congestion charge To be informed to all concerned .. Make available at websites

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Applicability of Congestion Charge.

Congestion Charge shall be applicable to Regional entities as per the CERC (Measures to relieve congestion in real time operation) Regulations and orders on rate of congestion charge as applicable from time to time.

To relieve congestion in the real time, a congestion charge shall be applied as a commercial measure. The congestion charge will be payable by a Regional entity or entities causing congestion in the inter-regional link or intra-regional link and receivable by a Regional entity or entities relieving congestion.

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Applicability….contd

Congestion charge may be imposed on any Regional entity or entities in any Region or Regions for causing congestion and paid to any Regional entity or entities in any Region or Regions for relieving congestion as per the detailed procedure under these regulations formulated by NLDC and approved by the Commission.

The congestion charge shall be payable by the overdrawing regional entity in addition to the Unscheduled Interchange charges which would be payable as per Central Electricity Regulatory Commission (Unscheduled Interchange charges and related Matters) Regulations, amended time to time

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Applicability….contd

Congestion charges may also become applicable for an intra-regional corridor of one region, if the congestion is attributable to other regional entities of other region.

Congestion charge shall be applicable only after two time blocks from the time of issuing the notice, not counting the time block in which notice is issued.

Congestion charge shall be withdrawn after the power flow on the affected transmission link/ corridor has come down to the ATC and remains at this level for one time block. NLDC/ RLDC shall communicate to all concerned Regional entities telephonically or through fax message/ e-mail and through postings on website and making available the same on the common screen available at NLDC/ RLDCs/ SLDCs for lifting of congestion charge

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When, in the opinion of the National/Regional Load Despatch Centre, flow of electricity on an interregional /intra-regional corridor/ link used for transfer of electricity has crossed the ATC of such corridor/link, the NLDC/RLDC shall issue a warning notice to the defaulting entities.

If the flow of electricity on the inter-regional /intra-regional corridor/ link exceeds the TTC, the NLDC/RLDC may, after notice through fax/voice message and through posting on its website and the common screen available on the Energy Management System, which is common to NLDC, RLDC and SLDCs, decide to apply congestion charge on the defaulting entities from a particular time-block in accordance with regulation 4:

Provided that notice of at least two clear time blocks shall be given by the Regional Load Despatch Centre before congestion charge becomes applicable, not counting the time block in which the notice is issued.

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Notice for Applicability

Notice for Withdrawal

When in the opinion of the National / Regional Load Despatch Centre, flow of electricity on the affected transmission link /corridor has come down to the ATC, it may, after notice through fax/voice message and through posting on its website and the common screen available on the Energy Management System, withdraw congestion charge from a particular time-block:

Provided that notice of one time block shall be given by the Regional Load Despatch Centre before congestion charge is withdrawn, not counting the time block in which the notice is issued.

Chapter III: Congestion charge account

As per CERC’s order (dated 8th Jan’2010) congestion charge is fixed at Rs.5.45/kwh, in accordance with the then existing UI rates.

Rationale Congestion charge shall be equal to the difference of maximum UI rate and UI at

50.0Hz,ie Rs.7.35- Rs.1.92=Rs.5.43 This is because the maximum UI rate is equal to the energy charge of

liquid fuel, so any over drawing state at frequency just below 50Hz. through a congestion corridor shall be encouraged to utilize own liquid generation rather than over drawing through a congested corridor, with a price more than liquid fuel variable cost.

Congestion Charge Account.. contd

Each Regional Load Despatch Centre shall maintain a separate bank account called “Congestion Charge Account” wherein all money received on account of congestion charge shall be credited. The amount standing to the credit of Congestion Charge Account, if any, shall be transferred to a Fund at regular intervals as per methodology notified by the Commission.

Congestion charge account shall presently be maintained and operated by the Regional Load Despatch Centre in the same manner as the account for Unscheduled Interchange Charges.

Provided that Congestion Charge Account may be maintained by any other entity as the Commission may direct by notification from time to time.

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Chapter IV: Payment and Utilisation

Statement of Congestion Charge.

The statement of payment and disbursal of congestion charge shall be issued by the Regional Power Committee Secretariat on weekly basis along with statement for Unscheduled Interchange charge. A monthly report on the collected and disbursed congestion charges shall be given to the Commission by Regional Load Despatch Centres.

Payment to Congestion Charge Account. The Regional Entity liable to pay congestion charge shall deposit the

amount in Congestion Charge Account within 10 days of issue of statement by the Regional Power Committee Secretariat: Provided that when payment of congestion charge is delayed beyond two days from due date, that is to say, beyond twelve days of the issue of statement by the Regional Power Committee Secretariat, the Regional entity responsible for delay in depositing congestion charge amount shall be liable to pay interest at the rate of 0.04% per day.

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Release of Congestion Charge Amount. The Regional Load Despatch Centre shall, within three working days of

receipt of congestion charge payment, release the amount payable to the Regional Entity entitled to receive congestion charge, along with interest, if any, on account of delay in payment of congestion charge.

12. Utilisation of Congestion Charge. The undisbursed amount of congestion charge collected from the

constituents in the account mentioned in Regulation 8 shall be utilized, with the prior approval of the Commission, to relieve congestion including but not limited to carrying out specific system studies to optimize the utilization of the inter-regional links, installation of special protection schemes, installation of shunt capacitors, etc. in accordance with the procedure notified under Regulation 8 . Provided that the Regional Load Despatch Centres/any other entity entrusted with maintenance and operation of the funds shall submit report to the Commission on a six monthly basis, furnishing details of undisbursed amount and utilisation thereof.

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13. Dispute Redressal Mechanism. All disputes arising under these regulations shall be decided by the

Commission based on an application made by the person aggrieved in accordance with Central Electricity Regulatory Commission (Conduct of Business) Regulations, 1999 or any re-enactment thereof.

14. Power to Relax. The Commission may by order, for reasons to be recorded in

writing and after giving an opportunity of hearing to the parties likely to be affected, relax any of the provisions of these regulations on its own motion or on an application made before it by an interested person.

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Issuues & concerns Congestion in the transmission network is being experienced even

though the frequency is operating in normal band and/or frequently hovering around the nominal value of 50 Hz.

Imposition of congestion charge linked with the system frequency i.e. “At frequency below 50 Hz, congestion charge would be levied for over-drawal in the importing control area and at frequencies above 50 Hz., congestion charge would be levied for under-drawal in the exporting control area”,

it is observed that in a large grid many a times the action either only upstream or downstream of congested corridor is not enough to quickly decongest the network and efforts from the utilities on both the sides are equally important.

Congestion charge may be applied on entities both upstream as well as downstream of congested corridor irrespective of frequency. Accordingly Clause 6.2 of the detailed procedure require a review

Power Supply Regulation

62

Chapter I : GeneralChapter I : GeneralDefinitions"Defaulting entity"

means a beneficiary having outstanding dues of a generating company or a transmission licensee or not maintaining the required Letter of Credit or any other agreed Payment Security Mechanism in terms of the Agreement;

“Default Trigger Date” means the date from which the default in payment or default in

maintaining Letter of Credit or any other agreed Payment Security Mechanism has been established.

Explanation I:- In case of non payment of dues, this date shall be the next working day after completion of the 60 days period from the date of service of the bill by the generating company or the transmission licensee as the case may be.

Explanation II:- In case of non maintenance of the required Letter of Credit or any other agreed Payment Security Mechanism, the Default Trigger Date shall be third working day after the payment security mechanism, as per the Agreement, ceases to exist.;

Definitions … contd

Regulating entity" means the generating company or the transmission licensee,

as the case may be, within the jurisdiction of the Commission, which notifies the Regional Load Despatch Centre or the State Load Despatch Centre, to regulate the power supply of the defaulting entity.

  “Regulated Entity”

means the defaulting entity whose power supply is regulated in accordance with these Regulations;

04/21/23 POSOCO 63

"

Scope and Applicability

These Regulations shall be applicable to the generating station and the transmission system where there is a specific provision in the Agreement between the Beneficiaries and Generating Company or the Transmission Licensee as the case may be, for regulation of power supply in case of non-payment of outstanding dues or non maintenance of Letter of Credit or any other agreed Payment Security Mechanism.

04/21/23 POSOCO 64

Chapter II Procedures for Regulation

Notice for regulation after default trigger date Reduction of drawal schedule in case of

Generating Co. Withdrawal of open access/access to Inter

State Transmission System in the case of the transmission licensee.

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Case I : Regulating Entity is a generator Amount of outstanding dues or the duration of non-maintenance of

payment security mechanism Source(s) of power from which reduction/diversion is to be made. Quantum and duration of reduction in drawl schedule Whether reduction of drawl schedule of Defaulting Entity is likely to

cause reduction in generation or the excess power available consequent to regulation is to be sold to any other entity, whether directly or through trader; and

In case of diversion of power, the particulars of the person to whom power is to be diverted and the price agreed to be charged from such person, if determined in advance.

 

04/21/23 POSOCO 66

Case II : Regulating Entity is a Transmission Licensee Amount of outstanding dues or the duration of non-

maintenance of payment security mechanism Quantum and duration of denial of medium-term open

access and/or long-term access. Transmission line or the transmission corridor on which

medium-term open access and / or long-term access to the defaulting Entity is to be restricted

Source of power, preferably the cheapest power station in that corridor from which schedule is to be restricted

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Copy of Notice and Request for preparation of implementation plan RLDC/SLDC in whose control area the Regulating entity

is located Other concerned RLDCs/SLDCs/RPCs

At least Three(3) Days in Advance for commencement

Regulating entity to indemnify, defend and save Concerned RLDC/SLDC and hold them harmless from

damages, losses, claims and actions, etc………

04/21/23 POSOCO 68

RLDC/SLDC in whose control area the defaulting entity is situated within 3days thereafter Shall prepare the implementation plan Inform all concerned

Regulating entity Regulated Entity SLDCs RLDCs RPCs

Post in its website RLDC/SLDC

May defer the implementation due to system condition Shall inform within three days of receipt of notice alongwith expected date

of commencement. Implementation to commence from the fourth day of the notice.

04/21/23 POSOCO 69

Regulating Entity may withdraw /postpone its notice of regulation of power supply with at least 2 days advance intimation.

Regulating Entity shall communicate the time and date of withdrawal of regulation of power supply in view that the regulation of power supply has to be withdrawn immediately after the outstanding dues are recovered.

During the period of regulation of power supply, the Regulated Entity shall restrict its drawal to the revised schedule given by the Load Despatch Centre and the deviations, if any, from the drawal schedule shall be subjected UI charges

04/21/23 POSOCO 70

The RLDC or SLDC, To consider Grid Security, and may temporarily suspend implementation of the plan

The concerned RLDC shall keep Member-Secretary, Regional Power Committee of the

region informed of the implementation of the regulation of power supply.

Default in making payment to both Generating Company and Transmission Licensee, the regulation shall be implemented concurrently.

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Chapter III Regulation by Generating Cos

Generating Company maySell the power

Rendered surplus due to regulation of power supply, to any person, including any of the existing beneficiaries, subject to grid security, as ascertained by the concerned RLDC.

Quantum/duration and rate of sale to be informed to MS. RPC

Reduce generationLiability to pay Capacity Charge

Remain with the Regulated Entity unless specified in the Agreement

In case of Diversion Open Access shall be governed as per CERC Regulations

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Amount received through sale proceeds Adjustment of the outstanding dues after deduction of energy

charges, trading margin, other incidental expenses Remaining amount if any shall be passed on to Regulated Entity

Hydro Gen Station May inject power in UI if buyer is not arranged Loss of Energy due to spillage shall be made good from sale of

powe/UI earned

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Chapter IV Regulation by Transmission Licensee

On the request of a Transmission Licensee for Regulating the power supply, the RLDC may, under intimation to the concerned generating company, curtail the medium-term open access or long-term access of the allocated power or power supply contracted by the Defaulting Entity, on account of regulation according to the notice served under Regulation 4 of these regulations, preferably from the cheapest generating station in that corridor

The Regulating Transmission Licensee may decide the quantum and duration of denial of open access/ access in consultation with any of the concerned generating companies who have a contract to sell power to the Regulated Entity and the concerned RLDC

The Transmission Licensee can propose the quantum and duration of regulation of power supply based on an estimated price, indications of which can be taken from the Power Exchange Uniform MCP and the prevailing price of electricity sold through traders directly.

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The generating company, as a result of reduction of open access shall be entitled to sell the power rendered surplus due to regulation of power supply, to any person including any of the existing beneficiaries, during the regulation of power supply. The revenue received on account of sale of this power shall be utilised in following sequence: a) to pay the energy charges and any incidental expenses,

including trading margin if power is sold through a trader, of the generating company

b) to pay the outstanding dues of the transmission licensee. c) any remaining amount to be passed on to Regulated Entity.

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In case of such reduction of drawl schedule, the liability of payment of capacity charges for its original share in the generating station shall remain with the Regulated Entity

Through Hydro Stations Same as Gen cos

Oustanding to Both Gen Cos and Tr Licensee The payments received from sale of power, after adjustment of energy

charges and incidental expenses of the Generating Company shall be shared by the Generating Company and the Transmission Licensee in proportion to their outstanding dues, till the dues are neutralised and the balance amount, if any, shall be passed on to the Regulated Entity.

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Thank You

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