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Central Electricity RegulatoryCommission (Indian Electricity GridCode) Regulations, 2010Need of Change, Challenges and Experience

Vijay Menghani

Joint Chief (Engg.), CERC

B.E,MBA

[email protected],

[email protected]

Nothing is more terrible than activity

without insight.

Thomas Carlyle
mailto:[email protected]:[email protected]:[email protected]:[email protected]

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CER

C

New Regulatory Initiatives in last oneyear

Revised IEGC. Regulation on Sharing of Transmission Charges and

losses

Renewable tariffs

Regulation on Grant of connectivity, Long-TermAccess and Medium term Access in inter StateTransmission

Regulation on Power market

REC framework Regulation on Real Time congestion Management.

Regulatory Approval of Transmission Scheme.

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CER

C

New Regulatory Initiatives

Approval for Nine High Capacity PowerTransmission corridors

Approval for Wide Area Management System

(WAMs) through PMUs in NR & WR Amendment in UI Regulation

Regulation on Power System Development fund

Fee & charges of RLDCs

Regulation of Power Supply( Draft)

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Philosophy Regulation is "controlling human or societal

behavior by rules or restrictions." Regulationcan take many forms: legal restrictionspromulgated by a government authority,self-regulation by an industry such asthrough a trade association, social regulation(e.g. norms), co-regulation and marketregulation. One can consider regulation asactions of conduct imposing sanctions (such

as a fine). This action ofadministrative law,or implementing regulatory law, may becontrasted with statutory or case law

Regulations can be seen as implementation

artifacts ofpolicystatements.
http://en.wikipedia.org/wiki/Lawhttp://en.wikipedia.org/wiki/Governmenthttp://en.wikipedia.org/wiki/Self-policinghttp://en.wikipedia.org/wiki/Trade_associationhttp://en.wikipedia.org/wiki/Social_controlhttp://en.wikipedia.org/wiki/Norm_(sociology)http://en.wikipedia.org/wiki/Punishmenthttp://en.wikipedia.org/wiki/Fine_(penalty)http://en.wikipedia.org/wiki/Administrative_lawhttp://en.wikipedia.org/wiki/Statutehttp://en.wikipedia.org/wiki/Case_lawhttp://en.wikipedia.org/wiki/Policyhttp://en.wikipedia.org/wiki/Policyhttp://en.wikipedia.org/wiki/Case_lawhttp://en.wikipedia.org/wiki/Statutehttp://en.wikipedia.org/wiki/Administrative_lawhttp://en.wikipedia.org/wiki/Fine_(penalty)http://en.wikipedia.org/wiki/Punishmenthttp://en.wikipedia.org/wiki/Norm_(sociology)http://en.wikipedia.org/wiki/Social_controlhttp://en.wikipedia.org/wiki/Trade_associationhttp://en.wikipedia.org/wiki/Self-policinghttp://en.wikipedia.org/wiki/Governmenthttp://en.wikipedia.org/wiki/Law

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Change Maturity of Regulatory framework in the form of

Removal of difficulty and playing the role offacilitator.

New evolving market structure where multiple playerswith multiple type of contracts pose new challenges.

To make Grid Code coherent with new Regulations ofLTOA and Congestion management

Urgent Need to reduce carbon footprint shift focus toRenewable which with their unpredictable behaviorimpose challenges in integrating them with Grid.

Learning lesson Regulatory decision on Penalty forGrid Indiscipline turned down by Appellate /Court

So we started with amending Grid Code and the reachedthe stage where we had to issue a Revised Grid Code

Draft : 12.2.2010 Public Hearing:15.3.2010

Effective :3.5.2010

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OBJECTIVE

The IEGC brings together a single set of technical andcommercial rules, encompassing all the Utilities connectedto/or using the inter-State transmission system (ISTS) andprovides the following:

Documentation of the principles and procedureswhich define the relationship between the various Users of the

inter-State transmission system (ISTS), National Load DespatchCentre, as well as the Regional and State Load DespatchCenters

Facilitation of the optimal operation of the grid,facilitation of coordinated and optimal maintenance planning ofgeneration and transmission facilities in the grid and facilitation

of development and planning of economic and reliableNational / Regional Grid

Facilitation for functioning of power markets andancillary services by defining a common basis of operation ofthe ISTS, applicable to all the Users of the ISTS.

Facilitation of the development of renewableenergy sources by specifying the technical and commercial

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Focus Focus of this presentation will be to explain

change in Grid Code and its rationale,rather than textbook presentation.

Area of changes

DefinitionsRestricted Governor Mode of Operation

Planning to take care of need of Renewable andOpen Access and congestionNarrowing down frequency band

Control Area Concept

Grid Discipline- Forecasting , Automatic Loadshedding & LegalCommercial Mechanism for Wind & Solar

Reactive Energy Charges

Forced Outage treatment

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WHAT IS GRID CODE

The Indian Electricity Grid Code (IEGC)lays down the rules, guidelines and standardsto be followed by the various persons andparticipants in the system to plan, develop,maintain and operate the power system in themost secure, reliable, economic andefficient manner, while facilitating healthycompetition in the generation and supply ofelectricity.

This is published by CERC under section 79(1) h-to specify Grid Code having regard to GridStandards.

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History

Came into force w.e.f. 3.5.2010.

Superseded the Indian ElectricityGrid Code (IEGC) , 2006 which

came into effect from 1.4.2006.Last Amendment on 30.3.2009

The first IEGC came into effect

w.e.f. 1.1.2000.

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CONTENTS

Part - 1 General

Part - 2 Role of various organizations andtheir linkages

Part - 3 Planning Code for Inter - StateTransmission

Part - 4 Connection Code

Part - 5 Operating Code

Part - 6 Scheduling and Despatch Code

Part - 7 Miscellaneous

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SCOPE

All parties that connect with and/orutilize the Inter State transmissionSystem (ISTS) are required to abide by

the principles and procedures definedin the IEGC in so far as they apply tothat party.

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Part - 2: Role of various

organizationsand theirOrganisational linkages

Defines the roles of National Load DespatchCentre (NLDC), Regional Load Despatch Centre

(RLDC), Regional Power Committee (RPC),Central Transmission Utility (CTU), CentralElectricity Authority (CEA) etc. which areinvolved for implementation of the IEGC.

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Part - 3 Planning Code for Inter -State Transmission

This Part comprises various aspects ofPlanning relating to Inter-State transmissionsystems.

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Part - 4 Connection Code

Specifies to comply with CEA(Technical Standards for connectivityto the Grid) Regulations, 2007 whichgives the minimum technical anddesign criteria and CERC (Grant ofConnectivity, Long-term Access,Medium-term Open Access andShort-term Open access in inter-state

Transmission and related matters)Regulations,2 009.

Also specifies Responsibilities for

safety, Cyber Security and scheduleof assets.

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Part - 5 Operating CodeSpecifies the operational rules and proceduresto maintain secure, efficient, and reliable gridoperation.

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Part - 6 Scheduling andDespatch Code

Demarcates responsibilities between variousregional entities, SLDC, RLDC and NLDC inscheduling and despatch

Procedure for scheduling and despatch

procedure. Reactive power and voltage control

mechanism.

Complementary Commercial Mechanisms (in

the Annexure1).

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IMPORTANT DEFINITIONS- New andModified

Ancillary Services means in relation topower system (or grid) operation, theservices necessary to support the powersystem (or grid) operation in maintaining

power quality, reliability and security of thegrid, eg. active power support for loadfollowing, reactive power support, blackstart, etc;

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Available Transfer Capability (ATC) meansthe transfer capability of the inter-controlarea transmission system available forscheduling commercial transactions

(through long term access, medium termopen access and short term open access) ina specific direction, taking into account thenetwork security. Mathematically ATC is the

Total Transfer Capability less TransmissionReliability Margin;

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Transmission Reliability Margin (TRM) meansthe amount of margin kept in the totaltransfer capability necessary to ensure thatthe interconnected transmission network is

secure under a reasonable range ofuncertainties in system conditions;

ATC=TTC-TRM

Congestion means a situation where the

demand for transmission capacity exceedsthe Available Transfer Capability;

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Connectivity means the state of gettingconnected to the inter-State transmissionsystem by a generating station, including acaptive generating plant, a bulk consumer or

an inter-State transmission licensee; Connection Agreement means an

Agreement between CTU, inter-statetransmission licensee other than CTU (if any)

and any person setting out the termsrelating to a connection to and/or use of theInter State Transmission System;

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Long term Access means the right to usethe inter-State transmission system for aperiod exceeding 12 years but not exceeding25 years;

Medium-term Open Access means the rightto use the inter- State transmission systemfor a period exceeding 3 months but notexceeding 3 years;

Short-term Open Access means open accessfor a period up to one (1) month at one time;

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SOME IMPORTANT DEFINITIONS

Control Area means an electrical systembounded by interconnections (tie lines),metering and telemetry which controls itsgeneration and/or load to maintain its

interchange schedule with other controlareas whenever required to do so andcontributes to frequency regulation of thesynchronously operating system;

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Demand response means reduction inelectricity usage by end customers fromtheir normal consumption pattern, manuallyor automatically, in response to high UI

charges being incurred by the State due tooverdrawal by the State at low frequency, orin response to congestion charges beingincurred by the State for creatingtransmission congestion, or for alleviating a

system contingency, for which suchconsumers could be given a financialincentive or lower tariff;

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Governor Droop means in relation to theoperation of the governor of a GeneratingUnit, the percentage drop in systemfrequency which would cause the Generating

Unit under restricted/free governor action tochange its output from zero to full load;

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User means a person such as a GeneratingCompany including Captive Generating Plantor Transmission Licensee ( other than theCentral Transmission Utility and State

Transmission utility) or Distribution Licenseeor Bulk Consumer, whose electrical plant isconnected to the ISTS at a voltage level33kV and above;

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Part-1

Compliance Oversight (Earlier Non-Compliance)

Role of RPC and RLDC reversed based on pastexperience and legal cases.

Earlier RPC was assigned task of reporting toCommission cases of Grid disciplineviolation, but due to their constitution andconsensus based deliberation ,no case was

reported in past. Now this shall be primarily responsibility of

RLDCs to report serious /repeated violation.

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Part-2

No major change except new functionsassigned to NLDC through other Regulationsincorporated.

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Part-3 PLANNING CODE

Modification: CEA: In formulating perspectivetransmission plan the transmission requirementfor evacuating power from renewable energysources shall also be taken care of. Thetransmission system required for open accessshall also be taken into account in accordancewith National Electricity Policy so thatcongestion in system operation isminimized.

Task force for integration of renewable into Gridindicated that N-1 contingency planning forrenewable shall be uneconomical and CEA musttake need of renewable while planning nearbytransmission system .

Also earlier planning based on Associatedgenerating station Tr system, now open accesshas increased upto 20% , and many timescongestion is being experienced in power marketoperation.

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Part-3 PLANNING CODE

Modification: CTU during planning shallconsiderfollowing

i) Perspective plan formulated by CEA. ii) Electric Power Survey of India published by the CEA. iii) Transmission Planning Criteria and guidelines issued

by the CEA iv) Operational feedback from RPCs v) Operational feedback from NLDC/RLDC/SLDC vi) Central Electricity Regulatory Commission

( Grant of Connectivity, Long-term Access and

Medium-term Open Access in inter-stateTransmission and related matters)- Regulations, 2009.

vii) Renewable capacity addition plan issued byMinistry of New and Renewable Energy Sources( MNRES), Govt of India

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3.PLANNING CODE

In case of associated transmission systemwhere all PPAs have not yet been signed,and where agreement could not be reachedin respect of system strengthening schemes,the CTU may approach CERC for theregulatory approval in accordance withCentral Electricity Regulatory Commission(Grant of Regulatory Approval for CapitalInvestment to CTU for execution of Inter-State Transmission Scheme) Regulations.

As per new Regulation on Regulatory approval Experience: For BPTA signing, Tr system fro

Sasan , Mudradiscussion for about 15 monthand for new IPP tr system was required

urgently.

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3.PLANNING CODE

Suitable System Protection Schemes may beplanned by NLDC/RLDC in consultation withCEA, CTU, RPC and the Regional Entities,either for enhancing transfer capability or totake care of contingencies

Experience of system protection scheme inNR where for any pole outage of Rihand DadriHVDC , backing down Generation inSingrauli RihandComplex and shed

equivalent load in various states. Similar scheme exist for Talcher-Kolar HVDC. Now SPS in SR is being planned to enhance

Transfer capability for Tamilnadu in Winter.

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4.CONNECTION CODE

CTU, STU and Users connected to, or seekingconnection to ISTS shall comply with CentralElectricity Authority (Technical Standards forconnectivity to the Grid) Regulations, 2007which specifies the minimum technical anddesign criteria and Central ElectricityRegulatory Commission (Grant ofConnectivity, Long-term Access and Mediumterm Open Access in inter-state Transmissionand related matters) Regulations,2009.

Previously everything like sub stationparameters, Fault clearance time,connectivity conditions etc were defined inthis , now no need to repeat.

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4.CONNECTION CODE

The objective of the code is :

a) To ensure the safe operation, integrity andreliability of the grid.

b) That the basic rules for connectivity are complied

with in order to treat all users in a non-discriminatorymanner.

c) Any new or modified connections, whenestablished, shall neither suffer unacceptable effectsdue to its connectivity to the ISTS nor impose

unacceptable effects on the system of any otherconnected User or STU. d) Any person seeking a new connection to the grid

is required to be aware, in advance, of the procedure forconnectivity to the ISTS and also the standards andconditions his system has to meet for being integratedinto the grid.

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4.CONNECTION CODE

A Connection agreement shall be signed by theapplicant in accordance with the CentralElectricity Regulatory Commission (Grant ofConnectivity, Long-term Access and Medium-termOpen Access in inter-state Transmission and

related matters) Regulations,2009.

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OPERATING CODE

Governor Action: Since 10 years FGMO was non-statrter, so Restricted Free Governor mode

ii) The restricted governor mode of operation shallessentially have the following features:

a) There should not be any reduction in generation in

case of improvement in grid frequency below 50.2 Hz. ( forexample if grid frequency changes from 49.3 to 49.4 Hz. thenthere shall not be any reduction in generation). Whereas forany fall in grid frequency, generation from the unit shouldincrease by 5% limited to 105 % of the MCR of the unitsubject to machine capability.

b) Ripple filter of +/- 0.03 Hz. shall be provided so thatsmall changes in frequency are ignored for load correction, inorder to prevent governor hunting.( to take care NTPCargument that there are too many fluctuations in grid )

Earlier proposed 50 Hz changed to take care of commercialissues .

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OPERATING CODE

Governor Action All governors shall have a droop setting of between

3% and 6%.

After stablisation of frequency around 50 Hz, the

CERC may review the above provision regardingthe restricted governor mode of operation andfree governor mode of operation may beintroduced.

All other generating units including the pondageupto 3 hours, Gas turbine/Combined Cycle PowerPlants, wind and solar generators and NuclearPower Stations shall be exempted from theseprovisions the Commission reviews the situation.

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OPERATING CODE

Excitation All generating units shall normally have their

automatic voltage regulators (AVRs) in operation.

Power System Stabilizers (PSS) in AVRs of

generating units (wherever provided), shall begot properly tuned by the respective generatingunit owner as per a plan prepared for the purposeby the CTU/RPC from time to time.

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OPERATING CODE

Protection Coordination Provision of protections and relay settings shall be

coordinated periodically throughout the Regionalgrid, as per a plan to be separately finalized by

the Protection sub-Committee of the RPC. Earlier version missed this important function of

RPC which is required for secure grid operation

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OPERATING CODE

Operating Frequency Range All Users, SEB,, SLDCs , RLDCs, and NLDC shall take

all possible measures to ensure that the gridfrequency always remains within the 49.5 50.2

Hz band. Earlier it was from 49.2- 50.3 Hz.

Low frequency operation endanger life ofGenerating machine which are not design for

continuous low frequency operation

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Experience

Narrowing down of freq from 1st April,2009 hadpositive results

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Experience

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Experience

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Result

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Results

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Result

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Result

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OPERATING CODE

All SEBS, distribution licensees / STUs shall provideautomatic under-frequency and df/dt relays forload shedding in their respective systems, toarrest frequency decline that could result in a

collapse/ disintegration of the grid, as per theplan separately finalized by the concerned RPCand shall ensure its effective application toprevent cascade tripping of generating units incase of any contingency.

All , SEBs, distribution licensees, CTU STUs andSLDCs shall ensure that the above under-frequency and df/dt load shedding/islandingschemes are always functional.

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System Security Aspects 5.2 n

All SEBs, distribution licensees / STUs shall provide automatic under-frequency and df/dt relays for load shedding in their respectivesystems, to arrest frequency decline that could result in acollapse/disintegration of the grid, as per the plan separately finalizedby the concerned RPC and shall ensure its effective application toprevent cascade tripping of generating units in case of any contingency.

All SEBs, distribution licensees, CTU, STUs and SLDCs shall ensure thatthe above under-frequency and df/dt load shedding/islanding schemesare always functional. RLDC shall inform RPC Secretariat aboutinstances when the desired load relief is not obtained through theserelays in real time operation. The provisions regarding under frequencyand df/dt relays of relevant CEA Regulations shall be complied with.

SLDC shall furnish monthly report of UFR and df/dt relay operation in theirrespective system to the respective RPC.

RPC Secretariat shall carry out periodic inspection of the under frequencyrelays and maintain proper records of the inspection. RPC shall decideand intimate the action required by SEB, distribution licensee and STUs

to get required load relief from Under Frequency and df/dt relays. AllSEB,distributionlicensee and STUs shall abide by these decisions.

RLDC shall keep a comparative record of expected load relief and actualload relief obtained in Real time system operation. A monthly reporton expected load relief vis-a-vis actual load relief shall be sent to theRPC and the CERC.

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Under Frequency Relays

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Relay

df/dt relays in NR

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OPERATING CODE

All Users, STU/SLDC , CTU/RLDC and NLDC, shallalso facilitate identification, installation andcommissioning of System Protection Schemes(SPS) (including inter-tripping and run-back) in

the power system to operate the transmissionsystem closer to their limits and to protectagainst situations such as voltage collapse andcascade tripping, tripping of importantcorridors/flow-gates etc.

Such schemes would be finalized by the concernedRPC forum, and shall always be kept in service.

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OPERATING CODE

Special requirements for Solar/ windgenerators

System operator (SLDC/ RLDC) shall make allefforts to evacuate the available solar and wind

power and treat as a must-run station. However,System operator may instruct the solar /windgenerator to back down generation onconsideration of grid security or safety of anyequipment or personnel is endangered and Solar/wind generator shall comply with the same.

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OPERATING CODE

Demand Estimation for Operational Purposes Each SLDC shall develop

methodologies/mechanisms fordaily/weekly/monthly/yearly demand estimation

(MW, MVAr and MWh) for operational purposes. Based on this demand estimate and the estimated

availability from different sources, SLDC shallplan demand management measures like load

shedding, power cuts, etc. and shall ensure thatthe same is implemented by the SEB/distributionlicensees/SLDCs.

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Demand Estimation strengthen

While the demand estimation for operational purposesis to be done on a daily/weekly/monthly basis initially,mechanisms and facilities at for each 15 minutesblocSLDCs shall be created at the earliest butnot later than 1.1.2011 to facilitate on-lineestimation of demand for daily operational use

k. Each SLDC shall develop methodologies/mechanisms

for daily/ weekly/monthly/yearly demand estimation(MW, MVAr and MWh) for operational purposes. Basedon this demand estimate and the estimatedavailability from different sources, SLDC shall plandemand management measures like load shedding,power cuts, etc. and shall ensure that the same isimplemented by the SEB/distribution licensees.SLDCs. All SEBs/distribution licensees shallabide by the demand management measures ofthe SLDCs and shall also maintain historicaldatabase for demand estimation.

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Demand Disconnection: Earlierprovisions

5.2.(l) All Regional constituents shall make all possibleefforts to ensure that the grid frequency alwaysremains within the [49.2 - 50.3 Hz] band, thefrequency range within which steam turbinesconforming to the IEC specifications can safelyoperate continuously.

5.4.2 Manual Demand Disconnection As mentioned elsewhere, the constituents shall

endeavour to restrict their net drawal from thegrid to within their respective drawal scheduleswhenever the system frequency is below 49.5 Hz.When the frequency falls below [49.2 Hz], requisiteload shedding (manual) shall be carried out in theconcerned State to curtail the over-drawal.

Tribunal interpreted Endeavour as effort and did notagreed with our interpretation of requisite asreducing OD to the extent bring frequency normal.( Case of Rajasthan, Karnataka)

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OPERATING CODE

Demand Disconnection 5.4.2 SLDC/ SEB/distribution licensee and bulk consumer

shall initiate action to restrict the drawal of itscontrol area ,from the grid, within the net drawalschedule whenever the system frequency falls to 49.7Hz.

The SLDC/ SEB/distribution licensee and bulk consumershall ensure that requisite load shedding is carriedout in its control area so that there is no overdrawl

when frequency is 49.5 Hz. or below. Each User/STU/SLDC shall formulate contingency

procedures and make arrangements that will enabledemand disconnection to take place, as instructed bythe RLDC/SLDC, under normal and/or contingent

conditions.

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OPERATING CODE

5.4.2 Automatic demand managementScheme

The SLDC through respective State ElectricityBoards/Distribution Licensees shall also formulate

and implement state-of-the-art demandmanagement schemes for automaticdemand management like rotational loadshedding, demand response (which mayinclude lower tariff for interruptible loads)etc. before 01.01.2011, to reduce overdrawl inorder to comply para 5.4.2 (a) and (b) . A Reportdetailing the scheme and periodic reports onprogress of implementation of the schemes shall

be sent to the Central Commission by the

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OPERATING CODE

Removal of congestion All Users, SLDC/ SEB/distribution licensee or bulk

consumer shall comply with direction ofRLDC/SLDC and carry out requisite load shedding

or backing down of generation in case ofcongestion in transmission system to ensuresafety and reliability of the system. Theprocedure for application of measures to relievecongestion in real time as well as provisions of

withdrawl of congestion shall be in accordancewith Central Electricity Regulatory Commission(Measures to relieve congestion in real timeoperation) Regulations, 2009.

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OPERATING CODE

Outage Planning Procedure for preparation of outage schedules for the

elements of the National/Regional grid in a coordinated andoptimal manner keeping in view the Regional systemoperating conditions and the balance of generation anddemand.

Annual outage plan shall be prepared in advance for thefinancial year by the RPC Secretariat in consultation withNLDC and RLDC and reviewed during the year on quarterlyand Monthly basis. All,Users,CTU,STU etc shall follow theseannual outage plans.

If any deviation is required the same shall be with

prior permission of concerned RPC and RLDC. The outage planning of run-of-the-river hydro plant, wind andsolar power plant and its associated evacuation networkshall be planned to extract maximum power from theserenewable sources of energy. Outage of wind generatorshould be planned during lean wind season, outage ofsolar, if required during the rainy season and outage of run-

of-the river hydro power plant in the lean water season.

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6.SCHEDULING AND DESPATCHCODE

Day ahead SchedulingThis code deals with the procedures to be adopted

for scheduling of the net injection / drawals ofconcerned regional entities on a day ahead basis

with the modality of the flow of informationbetween the NLDC / RLDCs / SLDCs/PowerExchange and regional entities.

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6.SCHEDULING AND DESPATCHCODE

Demarcation of control area How issue arises: Earlier central sector or state

sector generator . Central station 85% firmallocation and 15% unallocated distributed

among beneficiary so clear full contract. Now comes IPP, Merchant Power have multiple

contract of multiple duration Long Term , shortterm, Case-I , case-II bidder connected to eitherISTS or STU or both.

So issue arises who will be responsible for theirscheduling, earlier Central ( except dedicated)RLDC, State & embedded ( SLDC)

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SCHEDULING AND DESPATCHCODE

Demarcation of control areaThe national interconnected grid is divided into

control areas, like Regional ISTS, States, DVC, etc.where the load dispatch centre or system

operator of the respective control area controlsits generation and/or load to maintain itsinterchange schedule with other control areaswhenever required to do so and contributes tofrequency regulation of the synchronously

operating system.

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Control Area:

Earlier provision: RLDCs shall coordinate thescheduling of generating stations owned byCentral Government organizations (excludingstations where full share is allocated to hoststate),Ultra-Mega power projects and other

generating stations of 1000 MW or largersize in which, States, other than the hostState have permanent shares of 50% ormore. ( on which date, what capacity ?)

Generating stations not meeting the above criteriaregarding plant size and share of other Statesshall be scheduled by the SLDC of the State inwhich they are located. However, there may beexceptions for reasons of operationalexpediency, subject to approval of CERC.

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Demarcation of control area( 6.4)The Load Despatch Centre of a control area

therefore is responsible for coordinating thescheduling of a generating station, within thecontrol area, real-time monitoring of the stationsoperation, checking that there is no gaming(gaming is an intentional mis-declaration of aparameter related to commercial mechanism invogue, in order to make an undue commercialgain) in its availability declaration, or in any otherway revision of availability declaration andinjection schedule, switching instructions,metering and energy accounting, issuance of UIaccounts within the control area,collections/disbursement of UI payments, outageplanning, etc.

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Demarcation of control areaThe following generating stations shall come under

the respective Regional ISTS control area andhence the respective RLDC shall coordinate the

scheduling of the following generating stations : a) Central Generating Stations (excluding

stations where full Share is allocated to host state), b) Ultra-Mega power projects

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Demarcation of control area In other cases, the control area shall be decided on

the following criteria: (i) If a generating station is connected only to

the ISTS, RLDC shall coordinate the scheduling,except for Central Generating Stations where fullShare is allocated to one State.

(ii) If a generating station is connected only to

the State transmission network, the SLDC shallcoordinate scheduling, except for the case as at (a)above.

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Demarcation of control area If a generating station is connected both to ISTS

and the State network, scheduling and otherfunctions performed by the system operator of a

control area will be done by SLDC, only .if statehas more than 50% Share of power ,The roleof concerned RLDC, in such a case, shall belimited to consideration of the schedule for interstate exchange of power on account of this ISGS

while determining the net drawal schedules ofthe respective states. If the State has a Share of50% or less, the scheduling and other functionsshall be performed by RLDC.

SCHEDULING AND DESPATCH

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Demarcation of control area In case commissioning of a plant is done in

stages the decision regarding scheduling andother functions performed by the system operator

of a control area would be taken on the basis ofabove criteria depending on generatingcapacity put into commercial operation atthat point of time. Therefore it could happenthat the plant may be in one control area (i.e.

SLDC) at one point of time and another controlarea (i.e. RLDC) at another point of time. Theswitch over of control area would be doneexpeditiously after the change, w.e.f. the next

billing period.


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UI mechanismThe algebraic summation of scheduled drawal from ISGS

and from contracts through a long term access,medium term and short term open accessarrangements shall provide the drawal schedule ofeach regional entity, and this shall be determined inadvance on day-ahead basis. The regional entitiesshall regulate their generation and/or consumers loadso as to maintain their actual drawal from the regionalgrid close to the above schedule.

If regional entities deviate from the drawal schedule,

within the limit specified by the CERC in UIRegulations as long as such deviations do not causesystem parameters to deteriorate beyond permissiblelimits and/or do not lead to unacceptable line loading,However, such deviations from net drawal schedule

shall be priced through the Unscheduled Interchange(UI) mechanism.


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Grid Security Considerations However, notwithstanding the above, the RLDC

may direct the SLDCs/ISGS/other regional entitiesto increase/decrease their drawal/generation incase of contingencies e.g. overloading oflines/transformers, abnormal voltages, threat tosystem security.

Such directions shall immediately be acted upon.


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Special provisions for renewable Since variation of generation in run-of-river power

stations shall lead to spillage, these shall betreated as must run stations. All renewableenergy power plants, except for biomass powerplants, , and non-fossil fuel based cogenerationplants whose tariff is determined by the CERCshall be treated as MUST RUN power plants andshall not be subjected to merit order despatch

principles.


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Special provisions for grid problem In the event of bottleneck in evacuation of power due toany constraint, outage, failure or limitation in thetransmission system, associated switchyard andsubstations owned by the Central Transmission Utilityor any other transmission licensee involved in inter-state transmission (as certified by the RLDC)necessitating reduction in generation, the RLDC shallrevise the schedules which shall become effectivefrom the 4th time block, counting the time block inwhich the bottleneck in evacuation of power has taken

place to be the first one. Also, during the first, second and third time blocks of

such an event, the scheduled generation of the ISGSshall be deemed to have been revised to be equal toactual generation, and the scheduled drawals of the

beneficiaries shall be deemed to have been revisedaccordin l .


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Special provisions for grid problem In case of any grid disturbance, scheduled

generation of all the ISGS and scheduled drawalof all the beneficiaries shall be deemed to havebeen revised to be equal to their actual

generation/drawal for all the time blocks affectedby the grid disturbance. Certification of griddisturbance and its duration shall be done by theRLDC.


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Special provisions for ISGS(s) having two parttariff

Revision of declared capability by the ISGS(s)having two part tariff with capacity charge andenergy charge(except hydro stations) and

requisition by beneficiary(ies) for the remainingperiod of the day shall also be permitted withadvance notice. Revised schedules/declaredcapability in such cases shall become effective

from the 6th time block


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SCHEDULING AND DESPATCHCODE: Forced Outage

Special provisions for forced outage of a unitof 100 MW and above for STOA transaction Notwithstanding anything contained in Regulation

6.5(18), in case of forced outage of a unit for aShort Term bilateral transaction, where a

generator of capacity of 100 MW and above isseller, the generator shall immediately intimatethe same along with the requisition for revision ofschedule and estimated time of restoration of theunit, to SLDC/RLDC as the case may be.

The revised schedules shall become effective fromthe 4th time block.

Transmission charges for OA granted continued tobe paid by Generator


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SCHEDULING AND DESPATCHCODE: Forced Outage

Rationale for allowing revision in case offorced outage of a unit of 100 MW andabove for STOA transaction

In case of Short Term bilateral transaction, OA cannot be withdrawn before three days as per OA

regulation i.e. not allowing revision negativeeffects:

1. Buyer of this power can keep on drawing powerwithout paying UI as his schedule is not revised.

Grid imbalance due to less generation, lowfrequency.

Generator will pay unnecessary UI because forcedoutage is not controllable .

Technical and Commercial issues in

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Technical and Commercial issues inRenewable

Technical: There are two major

attributes of variable generation

that notably impact the bulk power

system planning and operations:

Tamil Nadu ,Gujarat, Rajasthan

are Wind Rich states

Variability: The output of

variable generation changes

according to the availability of the

primary fuel (wind, sunlight andmoving water) resulting in

fluctuations in the plant output on

all time scales.

Uncertainty: The magnitude

and timing of variable generation

output is less predictable than for

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Task Force

Government of India through the National ActionPlan on Climate Change has the objective ofpromoting renewable sources of energy, in linewith the Electricity Act 2003.

However, some of the renewable sources ofenergy namely wind energy, solar energy etc.,

depends on nature and hence cannot bepredicted with accuracy. This causes problem ofscheduling of this power by the Regional LoadDespatch Centers and State Load DespatchCenter.

CERC in September, 2009 constituted a Task Forcewith representation of Engineering Wing of theCommission Staff, CEA, System Operator, C-WET,WISE and State Commissions/ Utilities/ SLDCs of

Tamil Nadu, Rajasthan, Gujarat and Karnataka forintegration of renewable sources energy into theGrid

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Though there is much variation,

the ramp-up & ramp down

happens over several hours

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Task Force Recommendations:

Connectivity, it was decided that connectivity should be allowed withtransmission system or distribution system, in line with the CERCregulations on Renewable Energy tariff in this regard.

It was decided that forecasting of wind generation shall be madecompulsory and so also provision of SCADA for all future windgenerators. For existing wind Farms, some time would be given forimplementation of the same.

Fault ride through would be made compulsory for new wind generation

machine. For old machines some time would be given for retro fitting ofthe same. Scheduling of wind and solar power generation plants would be mandated

for all wind and solar plants where the sum of generation capacity ofsuch plants connected at the connection point to the transmission ordistribution system is greater than 10 MW and connection point is 33KV and above,

The wind or solar generators have to be responsible for forecasting uptothe accuracy of 70% and bear UI charges if they deviate from this.SLDC shall do the UI calculation and segregate the 30% explicitly.

For the remaining deviation, the state which purchases power from thewind or solar generators, have to bear the UI charges. However, the UIcharges borne by the State/s due to the wind or solar generation wouldbe socialized among all the States of the country in the ratio of theirpeak demands, in the form of a regulatory charge known as the

ancillary service charge for wind/solar energy from the pool.

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Forecasting

Statistical Tool available for Forecasting WindPattern taking input from Metrological Websites and On Field measurements.

Create ARIMA Models for short term

forecasting. ANEMOS R&D project France and Prediktor

on-line wind power forecasting tool ,Denmark

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ARMA Forecast of Wind Generation

ARMA : Autoregressive Moving Average

Problems in Open Access and Grid

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Problems in Open Access and GridDiscipline

In case of states having substantial wind potentialsay in Tamil Nadu with 4050 MW schedule ofwind , if actual generation is 2000 MW then statewould face problem of load generation balanceand may overdraw heavily from grid. The statewould be reluctant to allow Open Access to thesegenerators, if suitable penal action is notimposed.

If it is scheduled in State , then its failure wouldresult in heavy Overdrawl ,more than CERClimits.

Arranging balancing power: In case of substantial deviation of Wind generation

from Schedule ,sufficient stand by quick rampup power is to be arranged , the cost of whichwould add on to ultimate cost of purchase of

power for utility as a whole.

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Congestion Management

If wind farms are located in concentrated area( Map of India showing wind potential isenclosed) , which is normally the case there maybe instances of transmission congestionaffecting the system stability.

In this case wind generation need to be instructedfor stopping generation. Without propermetering structure ( RTUs) and communicationsystem , it would not be possible to monitorimplementation of instruction and if schedulingand UI mechanism is not there , investment on

this infrastructure would not come. NYSIO : Tariff Order revision dated

11.5.2009 Dispatch Down instructions toWind generator in case of Systemcongestion.

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Wind potential

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Final IEGC

For technical issues , as CEA is statutory bodyfor Technical standards , it was decided thattechnical provision would be specified inSOR , instead of IEGC in form of suggestionto CEA for inclusion in Technical Standardsfor connectivity to Grid.

For commercial issues it was decided toaccept Task Force recommendation andcreation of Regulatory Renewable

Fund( RRF).


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Special dispensation for scheduling of windand solar generation

The schedule of solar generation shall be given bythe generator based on availability of thegenerator, weather forecasting, solar insolation,

season and normal solar generation curve andshall be vetted by the RLDC in which thegenerator is located and incorporated in the inter-state schedule. If RLDC is of the opinion that the

schedule is not realistic , it may ask the solargenerator to modify the schedule.


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SCHEDULING AND DESPATCHCODE Special dispensation for scheduling of wind and solar

generation (i) With effect from 1.1.2011 Scheduling of wind power

generation plants would have to be done for the purpose ofUI where the sum of generation capacity of such plantsconnected at the connection point to the transmission ordistribution system is 10 MW and above and connection

point is 33 KV and above, and where PPA has not yet beensigned. For capacity and voltage level below this, as well as for old

wind farms ( A wind farm is collection of wind turbinegenerators that are connected to a common connectionpoint) it could be mutually decided between the WindGenerator and the transmission or distribution utility, as thecase may be, if there is no existing contractual agreementto the contrary .

The schedule by wind power generating stations may berevised by giving advance notice to SLDC/RLDC, as thecase may be. Such revisions by wind power generatingstations shall be effective from 6th time-block ,the first

being the time block in which notice was given. There may


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SCHEDULING AND DESPATCHCODE UI for Wind generators The wind generators shall be responsible for forecasting their

generation upto an accuracy of 70%. Therefore, if theactual generation is beyond +/- 30% of the schedule, windgenerator would have to bear the UI charges. For actualgeneration within +/- 30% of the schedule, no UI would be

payable/receivable by Generator, The host state , shall bearthe UI charges for this variation, i.e within +/- 30%.However, the UI charges borne by the host State due to thewind generation, shall be shared among all the States ofthe country in the ratio of their peak demands in theprevious month based on the data published by CEA, in theform of a regulatory charge known as the RenewableRegulatory Charge operated through the RenewableRegulatory Fund (RRF).

This provision shall be applicable with effect from1.1.2011,for new wind farms with collective capacity of 10MW and above connected at connection point of 33 KV

level and above , and who have not signed any PPA with


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UI for Wind generators A maximum generation of 150% of the schedule

only, would be allowed in a time block, forinjection by wind, from the grid security point ofview. For any generation above 150% of

schedule, if grid security is not affected by thegeneration above 150%,, the only charge payableto the wind energy generator would be the UIcharge applicable corresponding to 50- 50.02 HZ .

( About Rs 1.55/kwh)

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Commercial Explained

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Wind


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SCHEDULING AND DESPATCHCODE UI for Solar generators

In case of solar generation no UI shall bepayable/receivable by Generator.

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Solar

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Solar


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SCHEDULING AND DESPATCHCODE Curtailment of schedule during congestion

When for the reason of transmission constraintse.g. congestion or in the interest of grid security,it becomes necessary to curtail power flow on atransmission corridor, the transactions already

scheduled may be curtailed by the Regional LoadDespatch Centre.

The short-term customer shall be curtailed firstfollowed by the medium term customers, which

shall be followed by the long-term customers andamongst the customers of a particular category,curtailment shall be carried out onpro rata basis.


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SCHEDULING AND DESPATCHCODE Final schedule for energy accounting

After the operating day is over at 2400 hours, theschedule finally implemented during the day(taking into account all before-the-fact changes indespatch schedule of generating stations and

drawal schedule of the States) shall be issued byRLDC. These schedules shall be the datum forcommercial accounting. The average ex-buscapability for each ISGS shall also be worked out

based on all before-the-fact advice to RLDC.


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The charge for VArh shall be at the rate of 10paise/kVArh w.e.f. 1.4.2010, and this will beapplicable between the Regional Entity, exceptGenerating Stations, and the regional poolaccount for VAr interchanges. This rate shall be

escalated at 0.5paise/kVArh per year thereafter,unless otherwise revised by the Commission.

Rate increased from 6.25paise/kVArh to 10paise/kVArh to incentivize Capacitor installation,

as it would be cheaper to install Capacitor .Withinthree year capital investment in capacitor wouldbe recovered through saving in Reactive energycharge. This will discourage drawl of reactivepower from the Grid.

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Unscheduled Interchange Charges

Charges are payable for Over-drawal by the buyer or the beneficiary

under-injection by the generating station or the seller

Charges are receivable for

Under-drawal by the buyer or the beneficiary and Over injection by the generating station or the seller

. . / . - .Each 0 02 Hz step is equivalent to 15 5 paise kWh in the 50 2 49 7 Hz. / . - .frequency range and 47 0 Paise kWh in the 49 7 49 50 Hz frequency .range

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UI Regulation

As effective implementation of IEGC with narrowfrequency band, Load Forecasting and AutomaticLoad shedding require that commercialmechanism also be in tune with this hencefollowing changes were incorporated in UIregulation:

1. 40 % Additional UI on OD below 49.5 Hz. 2. 100% Additional UI for OD below 49.2 HZ. 3.Underdrwal above 20% of schedule.( < 0.8 of

schedule) will not get full UI but Capped UI of Rs4.03

4. Over injection upto 120% of schedule restrictedto 105% of installed capacity to get only cappedrate of Rs 4.03 under low freq instead of full UI.

OI above 120% of schedule & 105% of IC to getonly Rs 1.55 ( UI charge for 50-50.02 Hz)

UI Price Vector Overdrawal

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(Payable)

UI Price Vector UnderInjection

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(Payable)

Ps / kWh (C/L/APM) are payable by coal / lignite / APM Gas based

generators

Ps / kWh (Others) are payable by generators that do not fall in the

above cate or

UI Price Vector Underdrawal

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(Receivable)

*Receivable by buyers/beneficiaries who under draw in excess of 20% of

their Schedule or 250 MW, whichever is less.

**Buyers / beneficiaries who draw less than 120% of their schedule get

the normal UI rate (excluding the additional charges)

UI Price Vector Overinjection(R i bl )

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(Receivable)

*Overinjection by non-coal, non-lignite and non-APM gas based generators**Overinjection by coal, lignite and non-APM gas based generators and also

other generators for generation in excess of 120% of the schedule subject to a

maximum of 105% of Installed capacity or 101% of installed capacity over the day

***Over injection by the seller in excess of ex-bus generation

corresponding to 105% of the Installed Capacity of the station in a

time block or 101% of the Installed Capacity over a day

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Before and after

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Before and after

UP deviationForecasting error or bad operational

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g pplanning

Up deviation: Now commercial error

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too

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Compendium of Regulation

. The Compendium contains all theregulations notified by CERC in the

recent past including the regulations

regarding Renewable Energy Tariff,

Renewable Energy Certificate

Mechanism, Implementation of Open

Access, Regulation of Power Market, etc.

The Compendium would be useful for all

the stakeholders as a good reference

book.

The Compendium of Regulations of

CERC can be obtained from AssistantSecretary (P&A), CERC on payment

ofRs. 500/- per copy in cash or in

Demand Draft drawn in favour of

Assistant Secretary, Central

Electricity Regulatory Commission

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Thank You.

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117

Messages

A message is a Warning Message below 49.5 Hz.

B message is violation of IEGC clause 5.4.2(a) and 6.4.7.

C message is violation of Clause 5.4.2(b) of IEGC and sections 29(2)/29(3) ofEA 2003

Frequency OD

A

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Unscheduled Interchange (UI) means in atime block for a generating station or aseller means its total actual generationminus its total scheduled generation and fora beneficiary or buyer means its total actual

drawal minus its total scheduled drawal;

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State Transmission System (ISTS) means i) Any system for the conveyance of

electricity by means of a main transmissionline from the territory of one State to anotherState

ii) The conveyance of electricity across theterritory of an intervening State as well asconveyance within the State which isincidental to such inter-state transmission of

energy (iii) The transmission of electricity within

the territory of State on a system built, owned,operated, maintained or controlled by CTU;

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Net Drawal Schedule means the drawalschedule of a Regional Entity after deductingthe apportioned transmission losses(estimated);

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OPERATING CODE

Reliable Communication Each User, STU, RLDC, NLDC and CTU shall provide

and maintain adequate and reliablecommunication facility internally and with otherUsers/STUs /RLDC/SLDC to ensure exchange ofdata/information necessary to maintain reliabilityand security of the grid. Wherever possible,redundancy and alternate path shall bemaintained for communication along important

routes, e.g., SLDC to RLDC to NLDC.

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OPERATING CODE

The primary objective of integrated operationof the National/Regional grids is to enhancethe overall operational reliability andeconomy of the entire electric powernetwork spread over the geographical area

of the interconnected system. Participantutilities shall cooperate with each other andadopt Good Utility Practice at all times forsatisfactory and beneficial operation of the

National/Regional grid.

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OPERATING CODE

Overall operation of the National / inter-regional grid shall be supervised from theNational Load Despatch Centre (NLDC).Operation of the Regional grid shall besupervised from the Regional Load Despatch

Centre (RLDC).

OPERATING CODE

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OPERATING CODE

Governor Action Following Thermal and hydro (except those

with upto three hours pondage) generatingunits shall be operated under restrictedgovernor mode of operation with effect fromthe date given below:

a) Thermal generating units of 200 MWand above,

1) Software based Electro HydraulicGovernor (EHG) system : 01.08.2010

2) Hardware based EHG system01.08.2010

b) Hydro units of 10 MW and above

PLANNING CODE

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PLANNING CODE

As voltage management plays an importantrole in inter-state transmission of energy,special attention shall be accorded, by CTU,for planning of capacitors, reactors, SVC andFlexible Alternating Current Transmission

Systems (FACTS), etc. Similar exercise shallbe done by STU for intra-State transmissionsystem to optimize the utilistion of theintegrated transmission network.

PLANNING CODE

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PLANNING CODE

Based on Plans prepared by the CTU, StateTransmission Utilities (STU) shall have toplan their systems to further evacuatepower from the ISTS and to optimize the useof integrated transmission network.

PLANNING CODE

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PLANNING CODE

Planning Philosophy Security philosophy may be as per theTransmission Planning Criteria and otherguidelines as given by CEA.

OPERATING CODE

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OPERATING CODE

Disturbance recorder/sequential eventrecorder

All the Users , STU/SLDC and CTU shall sendinformation/data including disturbancerecorder/sequential event recorder output toRLDC within one week for purpose of analysis ofany grid disturbance/event.

Behavior of machine during Fault

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Behavior of machine during FaultConditions:

Fault Ride through /Voltage ride through

For large wind farms connected to bulk transmission system it is expected thatthe wind turbine should be able to ride through a normally cleared single ormulti-phase fault that occurred at the transmission voltage level.

Fault Ride-Through (FRT) capability during voltage drops in TransmissionSystem of 15% of nominal voltage during 300 ms with recovery up to 80% ofnominal voltage after 3 s, with the slope as shown in Figure.

F lt Rid th h

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Fault Ride through

F lt Rid th h

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Fault Ride through

Fault Ride through

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Fault Ride through

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IEGC 2010_vijay