OPERATING PROCEDURES

FOR

NORTHERN REGION

(as mandated by the Indian Electricity Grid Code)

NORTHERN REGIONAL LOAD DESPATCH CENTRE

18-A Shaheed Jeet Singh Sansanwal MargKatwaria Sarai, New Delhi – 110 016

REV-00(SEPTEMBER, 2000)

CONTENTS

Sl.No.

CHAPTER PAGENo.

1. GENERAL 1-3

2. NETWORK SECURITY AND SYSTEM OPERATION 4-11

3. DEMAND ESTIMATION AND CONTROL 12-14

4. OUTAGE PLANNING 15-17

5. BILATERAL AGREEMENTS 18-19

6. SCHEDULING & DESPATCH 20-26

7. GRID DISTURBANCES AND REVIVAL 27-30

8. EVENT INFORMATION AND REPORTS 31-33

9. SETTLEMENT SYSTEM 34-35

ANNEXE

1. LIST OF IMPORTANT ELEMENTS OF NORTHERNREGIONAL GRID

30 sheets

2. FORMATS FOR DAILY SCHEDULING 26 sheets

3. FORMATS OF EVENT REPORT (FROM CONSTITUENTSTO NRLDC)

1 sheet

4. 400 kV GRID DIAGRAM OF NORTHERN REGION 1 sheet

1

OPERATING PROCEDURE

1

CHAPTER – 1

GENERAL

1.1 OVERVIEW

The power system in the country is operated and controlled on a regionalbasis. Each region comprises a mix of state utilities, central sectorgenerating and transmission utilities, independent power producers andother agencies that play an important role in the integrated grid operation.The requirement to bring out a code, which lays down the rules,guidelines and standards to be followed by all such agencies, was beingfelt for quite some time. A comprehensive document against suchrequirement had been released in December 1999, in the form of theIndian Electricity Grid Code (IEGC) by Power Grid Corporation of IndiaLtd. in its capacity as the Central Transmission Utility (CTU) and in linewith the Central Electricity Regulatory Commission’s (CERC) orders dated21st December 1999. The IEGC brings together the different terms,encompassing all the utilities connected to / or using the Inter-StateTransmission System (ISTS) and provides documentation in regard torelationship between various users of the ISTS. It lays down the rules andguidelines for planning, development, operation and maintenance of thegrid in an efficient, reliable and economical manner.

1.2 INTERNAL OPERATING PROCEDURES

1.2.1 The Section 6.0 of the IEGC covers the operational aspects for theregional grids and clause 6.1(d) of the code specifies the requirement toprepare the set of detailed internal operating procedure for each regionalgrid to be developed and maintained by respective RLDC, in consultationwith the regional constituents. This document viz. “Operating Proceduresfor Northern Region” has been prepared in line with the aboverequirements and consists of the following chapters:

Chapter – 1 : GeneralChapter – 2 : Network Security & System OperationChapter – 3 : Demand Estimation & ControlChapter – 4 : Outage PlanningChapter – 5 : Bilateral AgreementsChapter – 6 : Scheduling & DespatchChapter – 7 : Grid Disturbances & RevivalChapter – 8 : Event Information & ReportsChapter – 9 : Settlement System

1.2.2 The highlights of this document are mentioned below:

2

i) The list of important elements of the Northern regional grid in line withthe stipulations under Chapter 6 viz. Operating Code of the IEGC isenclosed at Annex-I.

ii) Considering that demand estimation & control is under the purview of theState Load Despatch Centres (SLDCs), chapter 3 describes briefly theSLDC’s interface with NRLDC with respect to demand estimation &control.

iii) Chapter 4 contains the procedure to be followed for outage planning &availing the same, handling unforeseen outages and deferment ofplanned shutdowns.

iv) In order to optimise the load-generation balance between differentcontrol areas, the bilateral agreements between two constituents withinor outside the region play a very important role. Chapter 5 indicates theminimum requirements of a bilateral agreement, which would facilitatescheduling.

v) The scheduling procedure to be followed in the regional grid is indicatedin chapter 6, indicating clearly the treatment to be accorded for specialsituations in Northern Region, as well as during revisions of schedule.The order on Availability Based Tariff (ABT) states that the generationschedule and drawal schedule issued / revised by NRLDC shall becomeeffective from the designated time block irrespective of communicationsuccess. The availability of a reliable and fast communication system toachieve the desired purpose assumes prime importance and has alsobeen covered in this chapter. The provisions on scheduling could beimplemented even without ABT, however these would have a totalcommercial bearing only after introduction of ABT.

vi) Chapter 7 on ‘Grid Disturbances & Revival’ provides criteria forcategorizing disturbances & the declaration of normalization. The samecriteria could also be used for suspension & restoration of schedules.This classification is however subject to change, depending on theCTU’s scheme finalised in consultation with the constituents of all theregions and approval by the CERC. The general precautions to beobserved and steps taken during restoration are also included in thischapter.

vii) Timely and accurate reporting of events and exchange of informationplays an extremely vital role in an integrated system. The protocol to befollowed in such cases is indicated in chapter 8.

viii) Chapter-9 gives a broad outline of the settlement system, which is animportant post despatch activity. This activity can commenceimmediately after special energy meters have been commissioned at thedifferent substations. The processed data from these meters would besignificant commercially after implementation of the ABT.

1.2.3 This document does not cover the procedure to be followed in case powersupply has be regulated to any utility on account of non-payment of dues.

3

The same would be implemented by NRLDC in line with the directivesissued by CERC from time to time.

1.2.4 The details indicated in this document are intended to serve only as aguideline for efficient system operation and are not exhaustive. Inparticular, these procedures do not cover the tools required for efficientand effective system operation and analysis viz. Communication Systems,Supervisory Control & Data Acquisition Systems (SCADA), EnergyManagement Systems (EMS), and other recording and control equipment.It is expected that these requirements would be provided by all concernedto enable efficient system operation. Further, these procedures are to beread in conjunction with the various clauses as given in Indian ElectricityGrid Code (IEGC) and are without prejudice to the NRLDC’ s power togive directions and exercises supervision and control as stated underSections 55(3) and 55(6) of the amended Electricity Supply Act, 1948.

1.2.5 This document would come in force with immediate effect. It would alsobe reviewed annually or earlier in case significant changes taking place inthe system warrant a review.

*****

4

CHAPTER-2

NETWORK SECURITY AND SYSTEM OPERATION

2.1 OVERVIEW:

This chapter describes the actions required on the part of the systemoperator to keep the network secured at all times against contingencies. Italso describes the actions required to maintain system parameters close tonominal values in day-to-day operation.

2.2 NETWORK SECURITY

2.2.1 Background

The system planner generally designs & provides a power system, whichcomplies with the various transmission security standards and associatedcriteria mentioned in section 3.5 of the IEGC. Nevertheless, certainassumptions are made while planning and designing the system, which maynot be satisfied in actual operation. These deviations could be classified as:

i) Those amenable to some optimisation during operational planning&

ii) Those outside the operator’s control.

The first category includes planned maintenance programs on the generators& transmission lines. Attempts must be made to ensure that these plannedmaintenance programs are properly coordinated & do not result in weakenednetwork configuration not envisaged during system planning.

The second category of events, are those outside the operator’s control suchas extreme weather conditions either affecting the reliability of transmissionsystem (e.g. thunderstorm, cyclones) or resulting in uneven demand growth(e.g. widespread drought in certain pockets of the system). There could alsobe departures from planned generation pattern due to various conditions.These would fall under the category of crisis management and tackled assuch.

2.2.2 Measures To Maintain Network Security & Reliability

In order to maintain the security of the regional power system in day-to-dayoperation, it is important that the planned outage of generation &transmission system is properly coordinated. Important elements of theregional grid, which have a bearing on the network security, are enclosed atAnnex 1. It is necessary that power system studies to assess the stability ofthe network are carried out while finalizing the annual outage plan of theseimportant elements. The same should also be carried out during the quarterly& monthly review by NREB Secreteriat / NRLDC.

5

Additionally, any opening of the important elements, have to be carried outonly after prior clearance of NRLDC. Emergency openings if any, have to becarried out & immediately informed to NRLDC within a reasonable time, sayten minutes. Likewise, tripping of any of these important elements shouldalso be informed to NRLDC within a reasonable time indicating the likely timeof restoration. In addition to the above, it is necessary that special attentionbe paid to maintaining the reliability of the system. The following areas needcareful implementation by the concerned constituents / stations:

(i) In case of a two-bus system at any substation it must be ensuredthat the segregation of feeders on the different buses is uniform.This would help in minimizing the number of elements lost in caseof a bus fault. This is assuming the availability of bus-bar protectionat such substation(s).

(ii) In 400 kV substations having a breaker and a half scheme, it mustbe ensured that the two buses at such substation remainconnected at least by two parallel paths so that any line / bus faultdoes not result in inadvertent multiple outages. In case anyelement, say a line or an ICT or a bus reactor, is expected toremain out for a period say beyond eight hours at such substation,the main & tie breakers of such elements should be closed afteropening the line side isolator. This should be done after taking allsuitable precautions to avert inadvertent tripping. This of courseassumes that no maintenance is planned on such breakers /isolators.

(iii) The substation operators must ensure the above condition evenwhen any lightly loaded line is opened to control overvoltage. Suchopening of lines is generally superimposed over other line outageson account of faults created by adverse weather conditionsresulting in reduced security of the system.

(iv) Single pole auto-reclose facility on 400 kV lines should always bein service. NRLDC’s approval would be required for taking thisfacility out of service. Likewise, in case any transfer breaker at any400 kV substations having two main and transfer bus scheme isengaged, the same would be informed to NRLDC.

(v). In order to damp out the low frequency oscillations in the system,the power system stabilizers on the generating units would betuned as per the programme drawn out by the CentralTransmission Utility (CTU), in consultation with the constituents.

(vi). All constituents would endeavour to operate the connectedgeneration and reactive power management devices such asSynchronous Condensers, Static Var Compensators (SVCs) etc ina manner which enables stable voltage behaviour at various pointsof the grid under different operating conditions.

(vii). In line with section 6.2(e) to 6.2(g) of the IEGC, the generatingunits should be on free governor operation.

6

2.2.3 Defence Mechanisms For The System

Despite the utmost caution exercised during operational planning andimplementing all the above steps to improve network reliability, the possibilityof a large-scale disturbance in the region cannot be totally eliminated. Thissituation calls for suitable defence mechanisms to be available in the system,which would take care of such large disturbances. At least the followingschemes should be operational in the Northern Region.

i) Underfrequency relay load shedding scheme

NREB Secreteriat would formulate a suitable under frequency relay loadshedding scheme for the Northern Region in consultation with all theconstituents and NRLDC. Such a scheme would be formulated consideringthe largest single credible contingency occurring in the system and based onboth flat frequency as well as rate of change of frequency. The details of thescheme would be documented and circulated to all constituents and NRLDCfor implementation. The scheme would be reviewed and updated once everysix months. Further, from the viewpoint of system security, it is extremelyimportant that there should be no overlapping between areas covered byunderfrequency relay load shedding and that included in the manual loadshedding plan as part of demand control. This would ensure that theautomatic relief through these relays would be available to the system underall conditions. Effectiveness of the scheme would be monitored periodicallyby NRLDC in line with clause 6.2(m) of the IEGC. The same would also bemonitored in the monthly meetings of the Operation Co-ordination Committee(OCC) of NREB.

ii) Islanding scheme

In order to isolate the healthy subsystems following a large-scaledisturbance, NREB Secreteriat would formulate an islanding scheme for theregion in consultation with all constituents and NRLDC. The scheme wouldbe based on underfrequency. The details of the scheme would bedocumented and circulated to all constituents and NRLDC forimplementation. The scheme would be reviewed at least once every sixmonths.

2.2.4 Recording Instruments And Communication Facilities

i) The recording instruments such as Data Acquisition System, DisturbanceRecorder, Event Logger, Fault Locator, Time Synchronisation Equipment,and any other such equipment in each generating station / substation /control centre / SLDCs shall be kept in good working condition in order torecord the events and their sequences. All such places shall have a commontime reference so that any event can be coordinated with respect to differentlocations having common time base.

ii) Each regional constituent shall provide adequate and reliable communicationfacility with NRLDC as well as internally and with other constituents in order

7

to ensure exchange of data / information necessary to maintain reliability andsecurity of the grid.

2.3 SYSTEM OPERATION

One of the main assumptions of the power system planner is that the systemparameters viz. frequency, voltage remain close to nominal values. Thissection lists the measures to be adopted by the system operators at SLDCs /ISGS / substations for frequency and voltage control.

2.3.1 Frequency Control

2.3.1.1 Frequency band

All the regional constituents would make all possible efforts to ensure themaintenance of grid frequency within the normal band i.e. 49.0 to 50.5Hz.This would be ensured by adhering to the following steps:

i) Each SLDC shall regulate the load / own generation under its controlso that it may not draw more than its net drawal schedule during lowfrequency conditions and less than its drawal schedule during highfrequency conditions.

ii) Each of the Inter State Generating Station (ISGS) shall maintaingeneration such that it may not generate less than its generationschedule during low frequency conditions and more than itsgeneration schedule during high frequency conditions

iii) In case any state constituent is likely to face power shortage situationdespite requisitioning its full entitlement from ISGS, then it shallendeavour to enter into a bilateral agreement with the other stateconstituents having a power surplus and vice-versa. In any case,during low frequency conditions no state would carry outoverdrawals.

iv) Sudden reduction in generator output by more than one hundred(100) MW unless under an emergency condition or to prevent animminent damage to the equipment shall be avoided, particularlywhen frequency is falling below 49.0 Hz.

v) Sudden increase in load by more than 100 MW by any SLDC,particularly when frequency is falling below 49.0 Hz. and reduction inload by such quantum when frequency is rising above 50.5 Hz. shallbe avoided.

2.3.1.2 Preventive measures during high frequency conditions

While the grid frequency is higher than 50.5 Hz, the MW generation at nogenerating station (irrespective of type and ownership) shall be increased.Provided that when the frequency has risen from a previous lower level to50.5 Hz. or higher, and due to normal governor action, the MW output of a

8

generating unit has fallen to a level requiring oil support or which results inunstable operation of the unit, then the MW output may be increased to thelowest level,

- at which oil support is not required, and- at which the unit can operate in a stable and safe manner.

Similarly, no generating unit shall be synchronised with the grid while thegrid frequency is above 50.5 Hz. or higher, except with the specificconcurrence of NRLDC and in case of nuclear units, which may have to bere-synchronised to prevent poisoning out of the reactor. NRLDC wouldseparately issue frequency linked despatch guidelines to be followed byeach power station.

2.3.1.3 Regulatory measures by NRLDC under low frequency conditions

NRLDC would observe the drawal pattern of the SLDC’s control area &attention would also be drawn to wilful overdrawals resulting in lowfrequency operation. All SLDCs are expected to suo moto curb suchoverdrawals and abide by NRLDC’s instructions in this matter. In case ofany violation, NRLDC would take such action as it may deem fit includingphysical regulation.

2.3.1.4 Free governor mode of operation

Constituents would ensure that the generating units synchronised with thegrid are operated on free governor mode of operation and with necessaryprimary and secondary control in line with sections 6.2 (e), 6.2 (f), 6.2 (g),and 6.2 (h) of IEGC.

2.3.1.5 Interregional exchanges

NRLDC shall endeavour to exchange power with the neighbouring regionson opportunity basis in addition to the interregional bilateral agreementsalready in vogue. The prime consideration for such exchange would be,improvement in the grid parameters as well as system reliability andeconomy.

2.3.2 Voltage Control

2.3.2.1 Operating range

As defined in the IEGC section 6.2 (g), the operating range of the voltage atvarious voltage levels of grid is as follows:

Voltage in KV (rms)

Nominal Maximum Minimum400 420 360220 245 200132 145 120

9

The maximum and minimum values in the above table are the outer limitsand all the constituents would endeavour to maintain the voltage level wellwithin the above limits.

2.3.2.2 AVRs Controls

All generating units shall keep their Automatic Voltage Regulators (AVRs) inoperation and Power System Stabilisers (PSS) in AVRs shall be tuned in linewith clause 6.2 (j) of IEGC

2.3.2.3 VAR Exchange by Constituents

The constituent states shall take action in regard to VAR exchange with thegrid looking at the topology and voltage profile of the exchange point. Ingeneral the beneficiaries shall endeavour to minimise the VAR drawal atinterchange point when the voltage at that point is below nominal value andshall not return VARs when the voltage is above the nominal value. In factthe beneficiaries are expected to provide local VAR compensation so thatthey do not draw any VARs from the grid during low voltage conditions anddo not inject any VARs to the grid during high voltage conditions.

2.3.2.4 VAR Generation / Absorption by Generating Units

In order to improve the overall voltage profile, the generators shall run in amanner so as to have counter balancing action corresponding to low / highsupergrid voltage and to bring it towards the nominal value. In order toachieve the same, all generators shall generate reactive power during lowvoltage conditions and absorb reactive power during high voltageconditions as per the capability limits of the respective generating units. TheOn-Load Tap Changers (OLTCs) on the generator transformers whereveravailable, should also be used to achieve this. Off load tap changers wouldalso be used to take care of seasonal variations in the voltage profile.

2.3.2.5 Transformer taps

The transformer tap positions on different transformers forming importantelements of Regional Grid shall be changed as per requirements in order toimprove the grid voltage. NRLDC shall coordinate and advise the settings ofdifferent tap positions and any change in their positions shall be carried outonly after consultation with NRLDC.

2.3.2.6 Control at Grid Substations / Generating Stations

The following specific action at Grid Substations / Generating Stations shallbe taken in the event of voltage going high / low.

i) In the event of high voltage (e.g., 400kV bus voltages going above410kV), the following specific steps would be taken by therespective grid substations / generating station at their own, unlessspecifically mentioned by NRLDC otherwise;

10

! The bus reactors be switched in! The manually switchable capacitor banks be taken out! The switchable line/ tertiary reactors be taken in! Operate synchronous condensers for VAR absorption! Operate hydro generators / gas turbines as synchronous

condenser for VAR absorption wherever possible! Opening of the lightly loaded lines in consultation with

NRLDC, keeping in view the security of the balancenetwork.

ii) In the event of low voltage, (e.g., 400kV bus voltages going downbelow 390kV), the following specific steps would be taken by therespective grid substations / generating station at their own, unlessspecifically mentioned by NRLDC otherwise;

! The bus reactors be switched out! The capacitor banks be switched in! The switchable line / tertiary reactors be taken out! Operate synchronous condensers for VAR generation! Operate hydro generators / gas turbines as synchronous

condenser for VAR generation, wherever possible! Closing of lines which were opened to control high voltage,

in consultation with NRLDC

2.3.2.7 Load management for controlling the voltage

All the state constituents shall identify the radial feeders in their areas whichhave significant reactive drawals and which can be disconnected in order toimprove the voltage conditions in the event of voltage dropping to low levels.The details of all such feeders shall be kept handy in the respective controlrooms and standing instruction would remain with the operating personnel toobtain the requisite relief in the hour of crisis by disconnecting such feeders.

2.3.2.8 Regulatory measures by NRLDC to prevent voltage collapse

In case the state constituents do not take the requisite measures and thevoltage drops down to critically low levels (say 360kV and below at 400kVbus), then NRLDC may resort to regulatory measures by opening of linesincluding those, feeding radial loads in the areas of defaulting constituents.While taking such action, NRLDC would duly consider that the same doesnot result in affecting ISGS generation.

2.3.2.9 Switching-off of the line reactors in case of low voltage

In the event of persistent low voltage conditions, selected line reactorswould be switched off as a voltage control measure. The switching off ofsuch line reactors and reviving them back would be carried out as per theinstructions issued by NRLDC, after taking the line under shutdown.

2.3.2.10 Switching-off of the lines in case of high voltage

In the event of persistent high voltage conditions when all other reactivecontrol measures as mentioned earlier have been exhausted, selected lines

11

shall be opened for voltage control measures. The opening of lines andreviving them back in such an event would be carried out as per theinstructions issued by NRLDC in real time and as per the standinginstructions issued from time to time. While taking such action, NRLDCwould duly consider that the same does not result in affecting ISGSgeneration.

2.3.3 Line loading

In addition to frequency & voltage control measures outlined above, eachsystem operator would also have before him the thermal loading limits,surge impedance loading and the loading permitted from stabilityconsiderations for each line listed under important elements. Each systemoperator at SLDC / substations would endeavour to keep the line/ ICTloadings within limits and inform NRLDC in case of overloading of anyelement. Special emphasis would be paid by each system operator inidentifying credible system contingencies & continuously evaluating thesystem under his control against these contingencies.

It is expected that with the implementation of Availability Based Tariff inNorthern Region, the NRLDC’s focus would gradually shift from the actionslisted under the heading ‘System Operation’ above to Network Reliabilityand Security. All the constituents would extend the necessary cooperation toNRLDC in this endeavour.

2.3.4 Operating manpower

The control rooms of all SLDCs, power plants, grid substations as well asany other control centres of regional constituents shall be manned roundthe clock by qualified and adequately trained manpower who would remainvigilant and cooperative at all the times so as to maintain the system safetyand security and operate it in a most optimum manner.

******

12

CHAPTER – 3

DEMAND ESTIMATION AND CONTROL

3.1 OVERVIEW

Demand estimation plays a very important role in system operation. Long-term demand estimation (five years and beyond) is an important input forgeneration planning. In the medium term, say one year, it constitutes animportant input for outage planning of generating units and transmissionlines. In the short term, say within one week, it is an important input forgeneration scheduling. Variation in demand in real time operation from theestimated values could either be absorbed by the grid or affect itadversely. Even if the estimates are accurate, the generation could varyfrom scheduled values adversely affecting the grid. Demand control thenplays an important role in arresting these adverse effects on the grid.

Demand estimation and control is essentially the responsibility of SLDCsand NRLDC would generally not have a major role in this area. NRLDCwould give instructions to SLDCs on demand control whenever the samehas a bearing on the security of the regional grid & such instructionswould have to be complied forthwith by all SLDCs.

3.2 DEMAND ESTIMATION

3.2.1 The SLDCs would forecast demand (MW peak & energy in MWh) on anannual, quarterly, monthly, weekly and ultimately on daily basis, whichwould be used in the day-ahead scheduling. Each SLDC is expected tomaintain a historical database for the purpose and be equipped with thestate-of-the-art tools such as Energy Management System (EMS) fordemand forecasting. Ideally, the forecasts should be on hourly basis(8760, 720 & 168 values respectively in the annual, monthly and weeklyforecasts) rather than mentioning only the peak MW and energyrequirements for the period.

3.2.2 The annual, quarterly and monthly demand forecasts would be used inthe outage plan prepared by REB Secreteriat in consultation with all theconstituents.

3.2.3 Attention would also be paid by SLDCs in demand forecasting for specialdays such as important festivals and National Holidays having differentcrests and troughs in the daily load-curve as compared to normal days.

3.2.4 The above demand estimation covers only active power. It is alsoimportant that, the reactive power requirements are also forecasted rightfrom substation level by each SLDC. The reactive power planningexercise and programme for installation of reactive compensationequipments should take care of these requirements also.

13

3.3 DEMAND CONTROL

3.3.1 As stated earlier, primarily the need for demand control would arise onaccount of the following conditions.

(i) Variations in demand from the estimated or forecastedvalues, which cannot be absorbed by the grid.

(ii) Unforeseen generation / transmission outages resulting inreduced power availability.

(iii) Heavy reactive power demand causing low voltages.

(iv) Commercial reasons.

3.3.2 As already mentioned in section 7.4.5 of the IEGC, the SLDCs / STUswould regularly carryout the necessary exercises regarding short-termand long-term demand estimation for their respective states to enablethem to plan in advance as to how they would meet their consumers loadwithout overdrawing from the grid. Further, a tight control on the drawalsfrom the grid is not mandated and the deviations from the schedule wouldbe priced appropriately. However, the following deviations from theschedule & other violations would have to be controlled by the SLDCs.

(i) Overdrawals at frequencies below 49.0 Hz.

(ii) Underdrawals at frequencies above 50.5 Hz.

(iii) Reactive power drawals/injection causing low/high voltagerespectively.

3.3.3 Demand control would have to be exercised under these conditions by theSLDCs, which could be done by either of the following methods or acombination thereof.

(i) Manual demand disconnection.

(ii) Shutting off or reconnecting bulk power consumers having aspecial tariff structure linked to number of interruptions in theday.

(iii) PC based system for rotational load shedding with facilitiesfor central programming and uploading of the disconnectionschedule for the day from the SLDC / Sub-LDC to thesubstations.

3.3.4 During the demand control by manual disconnection of loads bystaggering in different groups, the roster changeover from one group toanother shall be carried out in a gradual and scientific manner so as toavoid excursions in the system parameters.

14

3.3.5 Each SLDC would also identify feeders drawing heavy quantum ofreactive power and disconnect the same under low voltage conditions. Asalready mentioned in Sec.2.3.2.3 of Chapter-2, necessary meteringarrangements for identifying such feeders would be provided by theSLDCs.

3.4 LOAD CRASH

3.4.1 In the event of load crash in the system due to weather disturbance orother reasons, the situation would be controlled by the SLDCs/ ISGS bythe following methods:

i) Backing down or closing down of generating unitsii) Lifting of the load restrictions, if anyiii) Exporting the power to neighbouring regions

While implementing the above it may be ensured that the provisions insection 2.3.1.1(iv) & (v) should not be violated. Further in case of hydrogeneration linked with irrigation requirements, the actual backing down orclosing down of units shall be subject to limitations on such account.

*****

15

CHAPTER-4

OUTAGE PLANNING

4.1 OVERVIEW

The earlier chapters have dwelt on the network security, reliability anddemand estimation. The next logical step is outage planning of generatingunits, transmission lines and ICTs subject to the above constraints. Thiswould have to be done in line with section 6.7 of the IEGC. As alreadymentioned earlier, the list of important elements of the Northern RegionalGrid is enclosed at Annex-I. Outage planning would be done centrally onlyin respect of these lines, ICTs and generating units, allowing sufficientdiscretion to the SEBs / STUs in respect of other lines and units, unlessotherwise decided by NREB Secreteriat. Outages in the system have aneffect on the network security and have to be planned carefully. Powersystem studies would have to be done by the NREB and NRLDC for theoutage planning (up to monthly review) and for day-to-day operationsrespectively, to assess the effect of outages on the grid security. Further,outage plan finalised would also have commercial implications for eachSEB / STU / ISGS after the implementation of ABT in the region, thesame would have to be done meticulously.

4.2 OUTAGE PLANNING PROCESS

4.2.1 Annual Outage Planning

The following calendar shall be followed in respect of annual outageplanning for the ensuing financial year:

(i) Constituents will forward to NREB Secretariat the required data forplanning for the next financial year, by 30th November.

(ii) NREB Secretariat will issue the draft outage programme to all theregional constituents and NRLDC by 31st December.

(iii) The mutually agreed final outage plan shall be intimated by NREBSecretariat to all regional constituents and NRLDC forimplementation latest by 31st January.

4.2.2 Quarterly And Monthly Reviews

The annual outage plans formulated as above shall be reviewed onquarterly and monthly basis as per following programme:

(I). In the months just preceding to each quarter i.e. during the secondfortnight of March, June, September and December the outageplans for the balance part of the financial year shall be reviewed in

16

joint meetings to be attended by all regional constituents andNRLDC and co-ordinated by NREB secretariat. The revisions in theoutage plans if any on the basis of above quarterly meetings shallbe issued by NREB Secretariat to all concerned before the end ofthe respective months i.e. by 31st March, 30th June, 30thSeptember and 31st December respectively.

(ii). Monthly review of the outage plan for the current month and theconsecutive month would be done in the Operation Co-ordinationCommittee (OCC) of NREB meeting, generally held in the firstweek of every month. NREB Secretariat would issue the outageplan so frozen in this meeting, to all constituents and NRLDC withinnext two working days.

4.2.3 Unforeseen outages and re-scheduling of outages after freezing ofmonthly schedules

In the event of any requirement to re-schedule any planned shutdown orto avail an emergency / unforeseen shutdown not anticipated earlier, theconcerned constituent shall forward such request to NRLDC indicating thenature of emergency or the reason for deferment. NRLDC would approvesuch unforeseen outages / re-scheduling of an already planned outagebased on the exigency of the case vis-à-vis system conditions. In case,any spill over to the next month occurs on account of the deferment, thesame would have to be brought to the notice of the Operation Co-ordination Committee by the concerned constituent.

4.3 AVAILING OF SHUTDOWNS

4.3.1 NRLDC would review on daily basis the outage schedule for the next twodays and in case of any contingency or conditions described in Sec.6.7.4(g) of the IEGC, defer any planned outage as deemed fit clearly statingthe reasons thereof. The revised dates in such cases would be finalised inconsultation with the constituent.

4.3.2 For a transmission element the outage of which shall affect more than oneconstituent, the information about the approval or deferment shall becommunicated by NRLDC to all such constituents so that they mayremain informed about the said outage

4.3.3 In respect of important elements of the grid, a final code would have to beobtained from NRLDC before taking the said element for maintenance. Allpreparatory works for maintenance must be done well in advance beforeavailing the code so as to avoid any idling time. Similarly, a code wouldhave to be obtained from NRLDC before reviving the element after shutdown.

4.3.4 The code issued by NRLDC for opening / revival of the circuit signifiessuch approval only from the system point of view notwithstandinganything contained in respect of safety measures and other switchingoperations to be carried out locally. The related line / substation personnelwould be responsible for ensuring all safety precautions to be followed

17

while opening / closing of any element to avoid any threat to operatingpersonnel and equipment.

4.3.5 During the period of shutdown, the constituent(s) shall keep NRLDCapprised regarding the status of work and the likely time of return of theshut down. All efforts shall be made by the constituents for timely returnof shutdowns and delays if any shall immediately be reported to NRLDCalong with the reasons and likely time of return of shut down.

4.3.6 Where it is foreseen that return of Permit To Work (PTW) could bedelayed due to physical distance involved in case of a transmission line,mobile satellite phones would be used for communication with thesubstation to minimise the outage period.

4.3.7 Any maintenance work on oppurtunity basis proposed to be carried out byrelated agencies during a 400 kV line / ICT shutdown would need theapproval of NRLDC. The same if approved, would also be intimated byNRLDC to the agency, which initially applied for the planned shutdown.

*****

18

CHAPTER-5

BILATERAL AGREEMENTS

5.1 OVERVIEW

With the implementation of Availability Based Tariff (ABT), bilateralexchanges are expected to provide a suitable hedge for constituents tominimise the Unscheduled Interchanges (UI). The number and quantumof such exchanges are therefore likely to go up tremendously andtherefore it is necessary that a proper mechanism is in place to implementand encourage such transactions. The details regarding suchagreements and their implementation philosophy are explained below.

5.2 BILATERAL AGREEMENT DETAILS

5.2.1 NRLDC would require information in respect of bilateral exchanges for thefollowing:

(i) Working out the net drawal schedule of each constituent.(ii) Checking for transmission constraints, if any arising out of such

exchanges.

In view of the above, it is necessary that a copy of the bilateral agreementbetween any two constituents be lodged with NRLDC. Further in view of(ii) above, it would be desirable for the constituents to seek the opinion ofNRLDC before signing any bilateral agreements whenever anytransmission constraint is foreseen. NRLDC’s concurrence in such caseswould be without prejudice to the conditions prevailing in real time,necessitating a suspension of such exchanges at any time.

5.2.2 The bilateral agreement must include the following minimum information.

(i) The date & time of commencement of the agreement and durationfor which it shall remain in force.

(ii) MW exchange (ceiling value) for each 15 minutes time block andMWH for the entire day (ceiling value).

(iii) The delivery / take-off point for the purpose of accounting fortransmission losses.

(iv) Details of capacity charges and energy charge payments alongwith the arrangements for payment.

(v) Wheeling charges if any, payable to any agency and thearrangements thereof.

19

(vi) Details of information that shall be exchanged with NRLDC inrespect of day-ahead scheduling and revisions thereof.

(vii) The force-majeure conditions under which the agreement can besuspended / discontinued and the period of such notice.

5.2.3 Further it is recommended that in case of bilateral transactions involvingwheeling of power through a third agency, the issue of wheeling chargesmust be resolved satisfactorily and quickly before the bilateral agreementis signed.

5.3 BILATERAL AGREEMENT IMPLEMENTATION

5.3.1 Each of the constituents involved in the bilateral agreement wouldintimate NRLDC on daily basis the quantum of the power to beexchanged on 15-minute time block basis for the next day. This wouldenable NRLDC to include the quantum of such transfer in day-aheadschedules (in case of the agreement with a state in another region, thisinformation can be passed through concerned RLDC). Similar treatmentwould be accorded for revision in schedule during the course of the day

5.3.2 In case the figures given by the two constituents for any day is at variancewith each other, NRLDC would accord the following treatment for workingout the net drawal schedules.

(i) If neither of the constituents gives any information in the day-aheadschedule, then it would be treated as ‘nil’.

(ii) If only one constituent gives the information in the day-aheadschedule, then the quantum would be according to suchinformation limited to the ceiling values indicated in the bilateralagreement.

(iii) If both the constituents indicate a different quantum then the lowerof the two values would be taken.

5.3.3 No post-facto revisions of schedule would be carried out on account ofbilateral transactions.

*****

20

CHAPTER-6

SCHEDULING AND DESPATCH

6.1 OVERVIEW

In the classical context, scheduling implies drawing up a generationprogramme to cater to a certain forecasted power demand at a minimumcost subject to certain network constraints. This assumed that adequategeneration is available to cater to the demand at all times and all oneneeded to decide was which units would have to be scheduled for howmuch time period. In our context, however, considering the large numberof utilities and the fact that power shortages are common, schedulingacquires a different connotation. In addition to scheduling generation fromInter State Generating Stations (ISGS), drawal schedules of SLDCs arealso required to be drawn up.

With the de centralised market mechanism being adopted for the country,the power system under each SLDC constitutes a notional control area.The states would have full operational autonomy and their SLDCs shallhave the total responsibility for scheduling and despatch of their owngeneration (including generation of their captive licensees), regulating thedemand of their customers, scheduling of their drawals from ISGS,arranging any bilateral exchanges and regulating their net drawal from theregional grid. Section 7.4 of the IEGC indicates in detail the demarcationof responsibilities for the purpose of scheduling and despatch. Thischapter illustrates the procedure for scheduling with the treatment to beaccorded for special situations.

6.2 GENERAL

6.2.1 For the purpose of scheduling each day would be divided into 96 blocks of15 minutes duration each and for each block NRLDC would intimate eachSLDC the drawal schedule and to each ISGS the generation schedule inadvance and as outlined in Section 6.3 below.

6.2.2 The net drawal schedule of any state would be the sum of the ex-powerplant schedules from different ISGS and any bilateral exchange agreedwith other constituent state in Northern or any other region less estimatedtransmission losses. The states would be required to maintain their actualdrawal from the grid close to such ‘net drawal schedule’ by regulating theirown generation and / or consumer’s load.

6.2.3 The generation schedule to each ISGS shall be the sum of therequisitions made by each of the beneficiaries, restricted to theirentitlements and subject to the maximum and minimum value criteria orany other technical constraint as indicated by NRLDC.

21

6.2.4 The states shall endeavor to maintain their drawals in such a manner thatthey do not overdraw from the grid whenever the frequency is below thenormal value and do not underdraw whenever the frequency is above thenormal value. Similarly, each ISGS shall also endeavor to maintain theirgeneration in such a manner that they do not generate above scheduleduring the period when frequency is above the normal value and do notgenerate below schedule, whenever the frequency falls below normalvalue.

6.2.5 The format of the generation schedule for all the ISGS and drawalschedules for all the states shall be as per Annexe-II.

6.2.6 The generation scheduling for the stations under Bhakra BeasManagement Board (BBMB) would be co-ordinated & finalised well before1500 hrs by BBMB in accordance with the requirements of the beneficiarystates viz. Punjab, Haryana, Rajasthan and Himachal Pradesh andsubject to the irrigation and hydrology constraints. The schedules sofinalised for each BBMB station would be communicated to NRLDC by1500 hrs every day.

6.2.7 NREB Secretariat would ensure that any change in the allocations fromeach ISGS is finalised and informed to all concerned at least a month inadvance so that trading of such capacity is facilitated. This is in line withthe spirit of clause 5.1.3 of the ABT order of the CERC.

6.3 SCHEDULING AND DESPATCH PROCEDURE:

6.3.1 By 1000 hrs everyday each ISGS shall advise NRLDC the station-wiseex-power plant MW and MWh capabilities foreseen for the next day i.e.between 0000 to 2400 hrs of the following day, at 15 minutes interval.

6.3.2 The above information shall be compiled by NRLDC and the MW andMWh entitlements available to each state during the following day at 15minutes interval shall be intimated by NRLDC to states by 1100 hrs.

6.3.3 After receipt of the information in regard to the availability from differentISGS, all the states shall review such availability vis-à-vis their foreseendemand and their own generating capability, including the bilateralexchanges if any. By 1500 hrs the SLDCs would advise NRLDC theirrequisition in each of the ISGS alongwith the bilateral exchanges theyintend to have with the other state / states and the estimates of demand /availability in their own states. BBMB would also advise NRLDC of thegeneration schedule finalised for its stations in consultation with itspartner states by 1500 hours. While indicating their station-wiserequisitions SLDCs must ensure that the step increase is not more than1% of the previous requisition. SLDCs, while finalising their requisitionfrom ISGS, shall also consider estimated losses that would be deductedfrom their ex-power plant schedules in ISGS & BBMB stations.

6.3.4 By 1700 hrs NRLDC shall convey to each ISGS the generation schedulei.e., ex-power plant despatch schedule and to each state the net drawal

22

schedule i.e. the schedule at the periphery of the state (after deductingthe apportioned estimated transmission losses).

6.3.5 The SLDC/ ISGS may inform the modifications/ changes to be made ifany in the above schedule to NRLDC by 2200 hrs.

6.3.6 On receipt of such information and after consulting with the concernedconstituents if required, the NRLDC shall issue the final generation /drawal schedule to each ISGS/SLDC by 2300 hrs.

6.3.7 The following specific points would be taken into consideration whilepreparing the schedules:

(i) While finalising the drawal and despatch schedule as above,NRLDC shall also check that the resulting power flows do not giverise to any transmission constraints. In case, any constraints are

foreseen, then NRLDC shall moderate the schedule to therequired extent, under intimation to the concerned constituents.

(ii) After receipt of the requisitions from different states, while finalisingthe generation schedule for ISGS, if it is found by NRLDC that suchschedules are not operationally reasonable particularly in terms oframping up / ramping down rates and ratio between minimum andmaximum generation levels, then NRLDC shall moderate theschedule to the required extent under intimation to the concernedconstituents. The ramping up/ ramping down rates in respect ofdifferent categories of stations would be based on the technicaldata as substantiated by the generating stations and as mutuallyagreed by the constituents. As regards the technical minimum, itwould have to be decided mutually between the beneficiaries andthe ISGS with subsequent information to NRLDC.

(iii) The procedure to be followed for bilateral agreements has alreadybeen indicated in Chapter-5.

6.4 REVISION OF SCHEDULES:

6.4.1 In case of forced outage of a unit, NRLDC will revise the schedules on thebasis of revised declared capability. The revised schedule will becomeeffective from the 4th time block, counting the time block in which therevision is advised by the generator to be the first one.

6.4.2 In the event of a situation arising due to bottleneck in evacuation of powerdue to transmission constraint, NRLDC shall revise the schedule whichshall become effective from the 4th time block, counting the time block inwhich the transmission constraint has been brought to the notice ofNRLDC as the first one. During the first three time blocks also theschedule shall deemed to have been revised to be equal to the actualgeneration by the ISGS and drawal by the states.

6.4.3 In case of any grid disturbance, the scheduled generation of all thegenerating stations and scheduled drawal of all the beneficiaries shall be

23

deemed to have been revised to be equal to their actualgeneration/drawal for all the time blocks affected by the grid disturbance.The exact duration of such grid disturbance would be declared by NRLDCon the basis of mutually agreed guidelines.

6.4.4 Revision of declared capability by generator(s) and requisition bybeneficiary(ies) for the remaining period of the day will also be permittedwith advance notice. Revised schedules / declared capability in suchcases shall become effective from the 6th time block, counting the timeblock in which the request for revision has been received in RLDC to bethe first one.

6.4.5 Similarly, in case any constituent seeks a revision in the bilateralschedules, the same would have to be confirmed by the other partnerwithin a period of one hour. The revised schedules would come in toeffect as per the procedure described in Chapter-5 and made effectivewith effect from 6th time block from this instant.

6.4.6 If, at any point of time, RLDC observes that there is need for revision ofthe schedules in the interest of better system operation, it may do so onits own and in such cases, the revised schedules shall become effectivefrom the 4th time block, counting the time block in which the revisedschedule is issued by RLDC to be the first one.

6.4.7 On completion of the operating day i.e. after 2400 hrs, the final scheduleas implemented shall be issued by NRLDC after incorporating all beforethe fact changes during the day of operation.

6.4.8 Various steps involved in the scheduling and the final schedule issued byRLDC shall be open to all the constituents for any checking/verification fora period of 20 days. In case any mistake/omission is detected, NRLDCshall forthwith make a complete check and rectify the same.

6.5 SPECIAL SITUATIONS RELATED TO SCHEDULING

There would be certain situations needing special treatment whilescheduling. These situations are indicated below along with thesuggested procedure to be followed by NRLDC in such cases.

6.5.1 Standing instructions by SLDC to NRLDC for deciding the bestdrawal schedule

The above situation is permitted as per section 7.5.5 of the IEGC.However in the spirit of de-centralised scheduling market mechanism, it isexpected that such SLDC should convey to NRLDC at least the followinginformation on 15-minute time block basis:

• Total MW required from the grid at its periphery• MW schedule for bilateral exchanges

Based on the above information, NRLDC would work out the requisitionsfrom each ISGS considering the merit order of energy charges in respect

24

of ISGS stations after translating the above MW values to ex-power plant(considering an estimated level of transmission losses). This is withoutprejudice to the procedure given for treatment of bilateral exchanges inChapter 5.

6.5.2 Scheduling of the ISGS hydro stations

(i) In respect of hydro power stations where the MWh generation forthe day is fixed depending on the water inflows, MWh entitlementof each beneficiary is fixed for the day. In case the beneficiariesare allowed full freedom to requisition on 15-minute time blockbasis restricted to their MWh entitlement for the day, it may resultin an ISGS schedule not practicable for the generator to follow(part load or high cavitations zone operation on sustained basis). Itis therefore proposed that each SLDC submits its proposed totalrequirement from the grid, for the next day to NRLDC by 1000hours (format E at Annex-II). An interim schedule would be workedout by adding this forecasted requirement for each state with aweightage corresponding to percentage entitlement of the state inthat ISGS. This interim schedule would be rounded off to thenearest feasible MW for the ISGS station to get the final scheduleof the ISGS. With this procedure, the generation schedule wouldadequately reflect the weightage accorded to:

• MW demand of each beneficiary in the ISGS• Percentage entitlement of each beneficiary in the

ISGS• Operational constraints for each ISGS

The entitlement for each beneficiary would be worked out based onthis ISGS schedule and percentage entitlement of the beneficiary.The above is a general procedure suggested and in case ofextremely low water inflows, the hydro stations would be scheduledfor operation only during the peak hours.

(ii) Another related problem while scheduling ISGS hydro powerstations is planning the filling of reservoir and its depletion. Thisproblem is presently confined only to Chamera power station inNorthern region but could be generalised to other ISGS reservoirbased hydro stations likely to come up in the future. In case all thethree units at Chamera are available and scheduled round theclock and the reservoir is full, then the complete reservoir would bedepleted in 5-6 days during the winter period. This may howevernot be desirable as water may require to be conserved forcontingencies. Therefore the strategy for reservoir filling anddepletion in respect of ISGS hydro would be reviewed in themonthly OCC meetings of NREB, when the outage plan isreviewed. Based on the strategy evolved, the ISGS hydro stationswould declare their MWh capability accordingly in the dailyscheduling.

6.5.3 Allocation of un-requisitioned surpluses

25

In line with section 5.7.3 of the CERC’s orders on ABT, each ISGS couldnegotiate the terms with any beneficiary for such un-requisitioned poweron day-to-day basis. A copy of all such agreements would be madeavailable to NRLDC and NREB Secreteriat. These agreements would getfirst priority in allocation of un-requisitioned surpluses.

6.6 EXCHANGE OF INFORMATION:

6.6.1 With the implementation of ABT, the generation schedules and drawalschedules would have a bearing on the energy charge payments to ISGSand Unscheduled Interchange. Therefore, the timely and accurateexchange of information in regard to schedule is of paramountimportance. This aspect gains extra importance particularly in view of theCERC order on ABT dated 04.01.2000 wherein under schedule 1.0, paraxvi it is stated that “Generation schedule and drawal schedulesissued/revised by RLDC shall become effective from designated timeblock irrespective of communication success”. In order to avoid anyadverse effect commercially on the ISGS / SLDCs, the need for a reliableand fast communication arrangement for exchange of information inrespect of scheduling cannot be overemphasized. The arrangementdescribed below shall be followed to meet such an objective.

6.6.2 As already mentioned in 6.4 above, revisions of schedule would berequired under the following conditions:

i) Forced outage of an ISGSii) Transmission constraint resulting in output reduction from any

ISGSiii) Revision of declared capability by any ISGSiv) Revision of requisition by any beneficiary either due to increase in

demand not forecasted earlier or due to tripping of any of its unit.v) NRLDC on its own accord in the interest of better system

operation.

As the time available for schedule revision is limited (half-an-hour to onehour only), some of the steps mentioned in Section 6.3 above could beskipped. For example, in the cases (i), (ii) and (iii) above, there need notbe any fresh requisition from the beneficiaries and NRLDC would assumethat the MW requirement of the SEB from the grid would be the same asgiven in the day-ahead schedule. The station wise requisition from eachISGS would be re-worked by NRLDC in line with the procedure describedin 6.5.3 above. In respect of (iv) above, revised requisition would beneeded only from the beneficiary seeking such revision.

6.6.3 Considering the large volume of information needed to be exchanged in atime bound manner, the transfer of information between NRLDC andother constituents i.e. states and ISGS shall be carried out on PC-to-PCcommunication link through INTERNET / Public Switched TelephoneNetwork (PSTN).

6.6.4 For this purpose NRLDC would have a dedicated INTERNET connectionon a leased circuit. In order to have fast access on the network, all the

26

constituents should also endeavour to have fast/dedicated connectivity onINTERNET.

6.6.5 The ISGS and states shall upload the information to NRLDC site in regardto scheduling at the agreed time and download the generation schedulesand drawal schedule from NRLDC site at the designated times.

6.6.6 In case any ISGS/State is desirous of changing the schedule, it shallcontact NRLDC telephonically and also notify the requisite informationtelephonically / e-mail / fax/ coded message immediately. The clocktimings of NRLDC at which the telephonic information is received, wouldbe reckoned as the starting block for schedule revision.

6.6.7 NRLDC shall incorporate the required changes and the information inregard to revision of schedule shall be flashed to the constituenttelephonically or e-mail / fax / coded message and accordingly theconstituents can download the revised schedule from NRLDC site.

6.6.8 In case NRLDC wants to revise the schedule due to transmissionconstraints or otherwise, then the required intimation will be flashed byNRLDC to the constituents telephonically/fax/coded message andaccordingly the constituents can download the revised schedule fromNRLDC site.

6.6.9 Each message sent by a constituent to NRLDC or vice-versa shall be dulynumbered and the date and time of issue shall be invariably stampedalong with the subject and revision number etc.

6.6.10 At the end of the day the final schedule as implemented afterincorporating all ‘before the fact changes’ during the day of operation shallbe made available by NRLDC on the network and accordingly can bedownloaded by the constituents.

6.6.11 The conventional voice / fax arrangement would act as back-up in case offailure of PC -to- PC communication link through INTERNET.

*****

27

CHAPTER -7

GRID DISTURBANCES AND REVIVAL

7.1 OVERVIEW:

A ‘Grid Disturbance’ denotes the situation under which a set ofgenerating units / transmission elements trip in an abrupt and unplannedmanner affecting the power supply in a large area and / or causing thesystem parameters to deviate from the normal values in a wide range.In the event of a grid disturbance, utmost priority is to be accorded toearly restoration / revival of the system. It is possible that during such asituation the system may have to be operated with reduced securitystandards and suspension of all commercial incentives / penalties. Thischapter describes the guidelines for classification of disturbances intodifferent categories, for the purpose of analysis and reporting. Themilestone to be reached so as to consider the system as normal is alsoindicated. The general precautions to be observed, while restoring adisturbed system is also covered in this chapter. The detailed sequenceto be followed for restoration would be as per the companion volume‘Black Start Procedures for Northern Region’ brought out by NRLDC.

7.2 CLASSIFICATION OF GRID DISTURBANCES:

The suggested criteria for classifying grid disturbances, is indicated in theTable below.

CLASSIFICATION OF GRID DISTURBANCESSl.No. Category

No.Severity Description

1. A Major Total blackout in the regionOR

Loss of 40% or more of the antecedentgeneration in the system

ORSeparation into two or moresubsystems and loss of 30% or moreof the antecedent generation

2. B Moderate Loss of 20 - 40% of the antecedentgeneration in the system

ORSeparation into two or moresubsystems having antecedentload in each of the first twosubsystems equivalent to thirtypercent (30%) or more of theantecedent generation.

ORInstantaneous loss of load

28

corresponding to more than 15% ofthe antecedent generation

3. C Minor Loss of 10 – 20% of the antecedentgeneration in the system

ORTotal loss of power supply at apower station contributing 5% ormore to the antecedent generation

ORTotal loss of power supply at a220kV or above substation cateringto load corresponding to 5% ormore of the antecedent generation

ORSeparation into two or moresubsystems having antecedentload in each of the first twosubsystems equivalent to fivepercent (5%) or more of theantecedent generation.

The above is a general guideline for the purpose of analysis andreporting. The generation schedules for ISGS and net drawal schedulesfor states would be suspended for the first two categories viz. A and Bwhile for category C, it would be on case-to-case basis as decided byNRLDC. However, if only one state system or one ISGS is affected, theschedules would not be suspended even for category-B disturbances butonly revised.

7.3 SYSTEM REVIVAL:

7.3.1 The recovery of the system shall be carried out as mentioned in thecompanion document ‘Black Start Procedures for Northern Region’prepared by NRLDC in consultation with constituents and amended fromtime to time.

7.3.2 The general guidelines and precautions to be followed during systemrevival is indicated below:

i) While building up the system, it would be ensured that the voltageat the charging end remains within limits. A small amount ofessential load should be connected at each substation beforeextending the network. However, the ultimate objective viz.building up of the network should not be lost sight of, whileconnecting the loads.

ii) Security of the network being built up would be strengthened atthe earliest by closing the parallel lines available in the restorationpath.

iii) Priority would be accorded for extending supplies to railwaytraction and installations where safety is of paramount importance

29

such as nuclear power stations.

iv) All switching instructions for a particular system have to emanatefrom a single agency viz. SLDC/CPCC as the case may be. Forsynchronisation of two systems, NRLDC would be the co-ordinating agency. Wherever a communication problem isforeseen, proper standing instructions would be issued to thesubstation engineers for implementation.

v) During revival of the system, only authorised personnel would bepresent in control rooms of substations / power stations / SLDCs /NRLDC so as to expedite restoration of the system.

vi) In line with Section 6.8(e) of IEGC, all communication channelsrequired for restoration process shall be used for operationalcommunication only, till grid normalcy is restored.

vii) All generating units would be on free governor operation and theexcitation controlled to maintain proper voltage profile.

viii) Synchronising facility should be available at major gridsubstations so as to have maximum flexibility in choosing thepoint of synchronisation.

7.4 DECLARATION OF SYSTEM NORMALISATION:

7.4.1 After a category ‘A’ or ‘B’ disturbance, the system would be deemed tohave been normalised if

i) All subsystems have been synchronised and

ii) 80% of the total loss of generation at ISGS stations, during theincident, has been revived.

7.4.2 After a category-C disturbance, the system would be deemed to have beennormalised if,

i) All subsystems have been synchronised

ii) Power has been extended to each affected grid substation

iii) At least one unit at the affected power station has beensynchronised (subject to a maximum of three hours of receipt ofstart-up power)

7.5 INTER REGIONAL SUPPORT

30

In case of disturbance or any other contingency in the Northern Region or anyother neighbouring region, NRLDC shall permit exchange of such power withthe neighbouring region on Unscheduled Interchange (UI) basis, needed tomeet the essential load, start-up-power, railway traction and other suchemergent requirements for the duration of such contingencies.

*****

31

CHAPTER-8

EVENT INFORMATION AND REPORTING

8.1 OVERVIEW

Timely and accurate reporting and exchange of information plays a veryimportant role in system operation. Since the Northern Regional Grid hasa large number of constituents with wide spread boundaries, the mannerin which the information flow would take place becomes very important.This is particularly important during a grid disturbance or a crisis situation.Timely and accurate information flow under such conditions would greatlyreduce an element of uncertainty and help people in making an informeddecision. In case system restoration is likely to get delayed, it is importantthat the general public is also well informed to avoid any unrest. Suchinstances could result in a major credibility crisis for the Electricity SupplyIndustry (ESI) and has to be avoided at all cost. This chapter describesthe information to be exchanged between the constituents and NRLDCand its periodicity.

8.2 EVENT INFORMATION

8.2.1 Any tripping of an element falling under the list of “Important elements ofRegional Grid”, whether manual or automatic, shall be intimated by thecontrol centre of the constituent to NRLDC in a reasonable time say withinten (10) minutes of the occurrence of the event. Along with the trippingintimation, the reason for tripping (to the extent determined) and the likelytime of restoration shall also be intimated. Such intimation can be ontelephone or fax or e-mail.

8.2.2 Any operation planned to be carried out by a constituent which may havean impact on the regional grid, or on any of the “Important Element ofNorthern Regional Grid”, shall be reported by the constituent to NRLDC inadvance.

8.2.3 Any operations planned to be carried out on the instructions of NRLDCwhich may have an impact on the system of a constituent / constituentsshall be reported by NRLDC to all such constituents in advance.

8.2.4 The intimation and the exact time of revival of an element falling under thecategory of “Important Elements of Northern Regional Grid” whetherrevived after a tripping or after a prolonged outage shall be intimated toNRLDC immediately.

8.3 REPORTING SYSTEM

32

The details of the Event Reports and the Periodic Reports to be preparedand issued by Constituents / NRLDC are as follows:

8.3.1 Event Report (Constituent to NRLDC)

In the event of tripping of any element falling under the category of“Important Elements of Northern Regional Grid” the “EVENT REPORT”shall be sent by the concerned constituent to NRLDC within a period offour (4) hours of the occurrence of the event in the form detailed underSection 6.9.6 of IEGC. Such report shall follow the telephonic / flashreporting the constituent would do in a reasonable time, say within ten(10) minutes of the occurrence of the event as stated under para 8.2.1above.

8.3.2 Grid Disturbance Report (Constituent to NRLDC)

In the event of a grid disturbance the constituents whose areas / stationsget affected in the disturbance shall submit a report to NRLDC at theearliest. Along with the report clear copies of Disturbance Recorder (DR),Sequential Event Recorder (SER) and Data Acquisition System (DAS)outputs, relay flag indications and restoration sequence would be sent soas to reach NRLDC at the earliest and not later than within three (3)working days of the incident.

8.3.3 Grid Disturbance Report (NRLDC to Constituents)

In the event of a grid disturbance NRLDC shall issue a flash report to befollowed by a detailed report. in the following manner.

i) Grid Disturbance Category - A (Major Disturbance):

Flash report within a period of six (6) hours followed by a detailedreport within ten (10) working days.

ii) Grid Disturbance Category- B (Moderate Disturbance)

Flash report within a period of five (5) hours, followed by a detailedreport within a period of seven (7) working days.

iii) Grid Disturbance Category – C (Minor disturbance)

Flash report within a period of four (4) hours, followed by a detailedreport within a period of four (4) working days.

The number of days mentioned above for issuing of detailed report byNRLDC is indicative only and would depend upon timely furnishing ofinformation / data by the concerned constituents in line with section 8.3.2above.

8.3.4 Under Frequency Relay Operations (Constituents to NRLDC)

33

In line with the Clause 6.2(m) of the IEGC, all state constituents have toprovide automatic under-frequency load shedding in their respectivesystems as per plans approved by NREB to arrest frequency decline thatcould result in collapse / disintegration of the grid. In order to check andascertain their operation as per approved plans, the details of all suchtripping in their areas shall be intimated by each SLDC to NRLDC,whenever required by the latter.

8.3.5 Weekly Report (NRLDC to Constituents):

A weekly report shall be issued by NRLDC to all constituents of the regioncovering the performance of the regional grid during the previous week, inline with Section 6.5.1 of IEGC. Such report shall be issued within two (2)working days of the completion of the week.

8.3.6 Quarterly Report (NRLDC to constituents)

A quarterly report shall be issued by NRLDC to all the constituentselaborating the power supply position during the last quarter, quality ofsupply, the system constraints and other relevant information in line withSection 6.5.2 of IEGC. Such report shall be issued within two (2) weeksof the completion of the quarter.

8.3.7 Exceptional Reporting (constituents to NRLDC)

The above reporting schedules are to be strictly followed. However, incase of any contingency such as an industrial unrest, natural calamity inany part of the region etc., there could be additional reportingrequirements not covered in the above schedule. NRLDC would inform allconstituents of any such exceptional requirement and the constituentswould extend the necessary co-operation in this regard.

*****

34

CHAPTER -9

SETTLEMENT SYSTEM

9.1 OVERVIEW

The settlement system is an important part in implementation ofAvailability Based Tariff (ABT). The system involves metering, datacollection and processing, energy accounting and raising of bills by thedifferent constituents. This chapter indicates the roles and responsibilitiesof the different constituents in making the settlement system operative.The activities listed under section 9.2 & below would commenceimmediately after special energy meters are installed and energised atinter-utility exchange points.

9.2 METERING AND DATA COLLECTION

9.2.1 As per Chapter 7, Clause 7.4.14 of IEGC, CTU shall be allowed to installSpecial Energy Meters on all interconnections between the regionalconstituents and other identified points for recording of actual netinterchanges and average frequency on 15-minute time block basis andMVARh drawals under low/high voltage conditions.

9.2.2 In the Northern Region, all such inter-utility exchange points have alreadybeen identified and shall be equipped with Special Energy Meters in orderto record the values stated above.

9.2.3 All the constituents shall extend the necessary assistance in timelycollection of data from these meters. For this purpose, a Data CollectionDevice (DCD) would be handed over generally to each sub-station wherespecial energy meters are installed by POWERGRID. The agency inwhose sub-station / power station these Special Energy Meters areinstalled would be responsible for transferring the data from the meters toDCD and thereafter from the DCD to a local Personal Computer (PC) tobe provided by the agency. The data would then be transferred from thesub-station to NRLDC on Public Switched Telephone Network (PSTN) /Internet. The above activities would be carried out on weekly basis andshall be completed between 0030 - 0400 hrs every Monday, whereverDCD & PC location is the same and between 0030-1000 hrs. in case PCis located at an adjacent sub-station. However till the existinginfrastructure limitations are overcome, the data could be transmitted toNRLDC latest by 1300 hrs.

9.2.4 NRLDC would be circulating from time-to-time the responsibility schedulefor data collection along with back-up modes of data communication.

9.3 DATA PROCESSING

35

9.3.1 Based on above meter readings, the computation of the net injection ofeach ISGS and actual net drawal of each beneficiary shall be carried outin line with clause 7.4.15 of IEGC. This information along with theschedules with all post-facto corrections would be forwarded by NRLDCto NREB Secretariat by Thursday noon (for the previous Monday toSunday period) to enable the latter to prepare and issue the RegionalEnergy Account.

9.3.2 As mentioned in Section 9.2.3 above, all the energy meter data wouldreach NRLDC by 1000 hours every Monday. NRLDC would carry outdata validation and in case of any problem, request any sub-station tosend the data again. Each substation would therefore have the necessaryback up of data on floppies while carrying out the steps in 9.2.3 above.

9.3.3 Reactive energy transactions between SEB to SEB and from one SEB tothe ISTS points would also be worked out by NRLDC & communicatedto NREB Secretariat and all the constituents.

9.3.4 All computations carried out by NRLDC shall be open to all constituentsfor checking / verification for a period of 20 days and mistakes/omissions detected, if any, would be rectified.

9.4 ENERGY ACCOUNTING

9.4.1 NREB Secretariat would process the information provided by NRLDC towork out the following on a monthly basis:

- Capacity charges payable by each beneficiary to each ISGS.

- Energy charges payable by each beneficiary to each ISGS.

- UI charges payable between each beneficiary and ISGS.

- Reactive energy charges payable between constituents and thepool.

9.4.2 All computations carried out by NREB Secreteriat shall be open to allconstituents for checking / verification for a period of 20 days andmistakes / omissions detected, if any, would be rectified.

*****

LIST OF IMPORTANT ELEMENTS(Please see the file “Imp_element_NR.xls”)

FORMATS FOR DAILY SCHEDULING(please see files “SCH_OPEC_form.doc” & “Annex-II.xls”)

ANNEX - III

EVENT REPORT(From Constituents to NRLDC)

(As per clause 6.9.6 (c) of IEGC)

1. Time of event: Date of event:

2. Location:

3. Plant and/or equipment directly involved:

4. Description and cause of event:

5. Antecedent conditions:

6. Interruption of

Quantum DurationParticulars

(MW) From To

Demand

Generation

7. All relevant system data (copies to be attached):

Sl. No. Descriptions √/ X

1 Disturbance recorder

2 Event logger

3 Data Acquisition system

4 Any other

8. Sequence of tripping with time:

9. Details of relay flags:

10. Remedial measures:

500 kV (HV400 kV 220 kV 132 kV TotalUPPCL 2825.25 1008.17 0.00 3833.42DVB 48.00 239.65 287.65PDD J&K 529.00 529.00HPSEB 90.19 0.00 90.19PSEB 3.60 3.60HVPNL 87.00 87.00BBMB 574.00 278.00 852.00RSEB 287.98 959.27 0.00 1247.25POWERGRIDNR - I 1630.00 4804.72 2781.17 9215.89NR - II 2756.00 1049.00 3805.00Total 1630.00 11295.95 7025.05 0.00 19950.99

Annex - IPage 2 of 30

1. The details of the Important Elements in Northern Region (ownership wise) is as follows

A. List of important transmission lines Page 3 to 15

B. List of important 400/220 kV and 400/132 kV ICTs Page 16 to 18

C. List of 400 kV switchable reactors Page 19 to 20

D. List of important generating units Page 21 to 24

2. The list of other ISTS trasmission lines in Northern Region not included in the " Important

Elements of Northern Regional Grid" is detailed subsequent to D above (page 25 to 30).

3. The following points are specifically indicated in respect of lists indicated from A to D above

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

i) The line(s) in the above context means a grid element from bus-bar to bus-bar andincludes all equipments such as associated circuit breaker(s), line reactor(s),isolator(s), CVT(s), CT(s) etc.

ii) Any 400 kV bus shutdown at substations needs the approval of NRLDC.

iii) Outage or the intention to take under outage, of any major component/ sub-system,which would reduce security/ redundancy level of the above elements, shall beprecisely intimated to NRLDC along with the likely time and status regardingrevival.

iv) In respect of two main and transfer bus switching scheme at 400 kV substations,NRLDC shall be informed whenever the 400 kV transfer breaker(s) at anysubstation is utilized for switching any line/ICT.

v) In respect of 400 kV substation/ power station switchyards having breaker and ahalf switching scheme, outages within the substation (say main or tie circuitbreaker) not affecting power flow on any line/ ICT can be availed by theconstituents under intimation to NRLDC. However, while availing such shutdownsor carrying out switching operations it must be ensured by the substation that atleast two dias are complete even after such outages from the view point of networkreliability.Any outage not fulfilling the above condition needs the approval ofNRLDC.

Annex - IPage 3 of 30

4. The criteria adopted in drawing up the lists indicated at point 1 above is as follows :

i) HVDC Rihand-Dadri bipole, HVDC B/B stations & all 800 kV/ 400 kV lines in the Region.ii) All 220 kV lines belonging to the Central Transmission Utility (CTU).iii) All 220 kV lines emanating from Inter State Generating Station (ISGS).iv) Important 220 kV & 132 kV lines from the territory of one state to another state.v) Lines affecting system security or forming part of islanding scheme.vi) Lines feeding loads of a strategic/sensitive nature.vii) All ISGS and BBMB power stations (excluding Ganguwal & Kotla)viii) All units of 100 MW and above capacity.

Annex -IPage 3 of 30

End - 1 End - 2800 kV UPPCL

1 Anpara-Unnao S/C 409.00 UPPCL UPPCL UPPCL POWERGRIDCharged at

400 kV

400 kV UPPCL1 Obra-Panki S/C 386.60 UPPCL UPPCL UPPCL POWERGRID2 Obra-Sultanpur S/C 230.40 UPPCL UPPCL UPPCL POWERGRID3 Obra-Anpara S/C 40.00 UPPCL UPPCL UPPCL POWERGRID4 Anpara-A-Sarnath S/C 140.00 UPPCL UPPCL UPPCL5 Anpara-B-Sarnath I D/C 159.00 UPPCL UPPCL UPPCL6 Anpara-B-Sarnath II D/C 159.00 UPPCL UPPCL UPPCL7 Sarnath-Azamgarh S/C 95.00 UPPCL UPPCL UPPCL8 Sarnath-Mau S/C 106.00 UPPCL UPPCL UPPCL9 Azamgarh-Sultanpur S/C 125.50 UPPCL UPPCL UPPCL

10 Sultanpur-Lucknow S/C 145.10 UPPCL UPPCL UPPCL POWERGRID11 Panki-Muradnagar S/C 395.20 UPPCL UPPCL UPPCL POWERGRID12 Moradabad-Rishikesh S/C 159.80 UPPCL UPPCL UPPCL POWERGRID13 Muradnagar-Rishikesh S/C 182.75 UPPCL UPPCL UPPCL POWERGRID14 Mau-Azamgarh S/C 48.40 UPPCL UPPCL UPPCL15 Azamgarh-Gorakhpur S/C 90.00 UPPCL UPPCL UPPCL16 Unnao-Agra S/C 274.80 UPPCL UPPCL UPPCL POWERGRID17 Unnao-Lucknow S/C 39.16 UPPCL UPPCL UPPCL POWERGRID18 Unnao-Panki S/C 48.54 UPPCL UPPCL UPPCL POWERGRID

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

Annex -IPage 4 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)2825.25

220 kV UPPCL1 Sahupuri-Dehri (U.P. portion only) S/C 36.66 UPPCL UPPCL BSEB ERLDC2 Unchahar-Fatehpur I D/C 56.50 UPPCL NTPC UPPCL3 Unchahar-Fatehpur II D/C 56.50 UPPCL NTPC UPPCL4 Unchahar-Lucknow S/C 115.00 UPPCL NTPC UPPCL5 Unchahar-Chinhat S/C 120.00 UPPCL NTPC UPPCL

6Agra (220 kV)-Agra (400 kV) -Harduaganj

S/C 97.70 UPPCL UPPCL UPPCL

7 NAPP-Harduaganj S/C 34.00 UPPCL NPC UPPCL8 NAPP-Moradabad S/C 84.94 UPPCL NPC UPPCL9 NAPP-Khurja I D/C 60.05 UPPCL NPC UPPCL

10 NAPP-Khurja II D/C 60.05 UPPCL NPC UPPCL11 NAPP-Simboli S/C 83.00 UPPCL NPC UPPCL12 Khurja-Harduaganj I D/C 42.50 UPPCL UPPCL UPPCL13 Khurja-Harduaganj II D/C 42.50 UPPCL UPPCL UPPCL14 Moradabad-C.B.Ganj S/C 86.54 UPPCL UPPCL UPPCL15 Sahibabad-Gazipur-Noida-BTPS S/C 25.23 UPPCL UPPCL NTPC DVB16 Sahibabad-Patparganj S/C 7.00 UPPCL UPPCL DVB

1008.17132 kV UPPCL

1 Morwa-Bina S/C MPEB/UPPCL MPEB UPPCL WRLDC2 Morwa-Anpara S/C MPEB/UPPCL MPEB UPPCL WRLDC

Annex -IPage 5 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

3 Karamnasa-Sahupuri - I D/C BSEB/UPPCL BSEB UPPCL ERLDC4 Karamnasa-Sahupuri - II D/C BSEB/UPPCL BSEB UPPCL ERLDC5 Sonenagar-Pipri(Rihand HEP)-I D/C BSEB/UPPCL BSEB UPPCL ERLDC6 Sonenagar-Pipri(Rihand HEP)-II D/C BSEB/UPPCL BSEB UPPCL ERLDC7 Pipri-Singrauli S/C UPPCL UPPCL NTPC

0.00400 kV DVB

1 Mandola-Bawana I D/C 24.00 DVB POWERGRID DVB2 Mandola-Bawana II D/C 24.00 DVB POWERGRID DVB

48.00220 kV DVB

1 BTPS-Mehrauli I D/C 16.60 DVB NTPC DVB2 BTPS-Mehrauli II D/C 16.60 DVB NTPC DVB3 BTPS-Okhla I D/C 9.75 DVB NTPC DVB4 BTPS-Okhla II D/C 9.75 DVB NTPC DVB5 BTPS-IP Extn I D/C 24.10 DVB NTPC DVB6 BTPS-IP Extn II D/C 24.10 DVB NTPC DVB7 Mandola-Narela I D/C 18.99 DVB POWERGRID DVB8 Mandola-Narela II D/C 18.99 DVB POWERGRID DVB9 Mandola-Patparganj I D/C 25.02 DVB POWERGRID DVB

10 Mandola-Patparganj II D/C 25.02 DVB POWERGRID DVB11 Mandola-Gopalpur I D/C 24.19 DVB POWERGRID DVB12 Mandola-Gopalpur II D/C 24.19 DVB POWERGRID DVB

Annex -IPage 6 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

13Kashmiri Gate T-off on Mandola-Patparganj-II

S/C 2.35 DVB DVB DVB POWERGRID

239.65220 kV PDD J&K

1 Kishenpur-Pampore I D/C 174.00 PDD J&K POWERGRID PDD J&K NHPC2 Kishenpur-Pampore II D/C 174.00 PDD J&K POWERGRID PDD J&K NHPC3 Sarna-Udhampur S/C 125.00 PDD J&K PDD J&K PDD J&K4 Wagoora-Ziankote I D/C 28.00 PDD J&K POWERGRID PDD J&K5 Wagoora-Ziankote II D/C 28.00 PDD J&K POWERGRID PDD J&K

529.00220 kV HPSEB

1 Khodri-Majri (Giri) S/C 35.16 HPSEB UPPCL HPSEB

2 Kunihar-Panchkula I (upto Barotiwala) D/C 26.02 HPSEB HPSEB HVPNL

3Kunihar-Panchkula II (uptoBarotiwala)

D/C 26.02 HPSEB HPSEB HVPNL

4 Dehar-Kangoo S/C 3.00 HPSEB BBMB HPSEB90.19

132 kV HPSEB1 132kV Kulhal-Giri S/C HPSEB UPPCL HPSEB

220 kV PSEB

Annex -IPage 7 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

1Link line between 400 kV & 220 kVMalerkotla I

D/C 0.30 POWERGRID POWERGRID PSEB

2Link line between 400 kV & 220 kVMalerkotla II

D/C 0.30 PSEB POWERGRID PSEB

3Link line between 400 kV Moga to220 kV Moga I

D/C 1.50 PSEB POWERGRID PSEB

4Link line between 400 kV Moga to220 kV Moga II

D/C 1.50 PSEB POWERGRID PSEB

3.60220 kV HVPNL

1Kunihar-Panchkula I (HVPNLportion)

D/C 41.00 HVPNL HPSEB HVPNL

2Kunihar-Panchkula II (HVPNLportion)

D/C 41.00 HVPNL HPSEB HVPNL

3 Hisar(HVPNL)-Hisar (BBMB) S/C 5.00 HVPNL HVPNL BBMB87.00

400 kV BBMB1 Dehar-Panipat S/C 262.00 BBMB BBMB BBMB2 Dehar-Bhiwani S/C 312.00 BBMB BBMB BBMB

574.00220 kV BBMB

1 Panipat-Narela I D/C 64.00 BBMB BBMB DVB HVPNL2 Panipat-Narela II D/C 64.00 BBMB BBMB DVB HVPNL

Annex -IPage 8 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

3 Panipat-Narela III S/C 58.00 BBMB BBMB DVB HVPNL4 Narela-Rohtak Road I D/C 21.00 BBMB DVB BBMB HVPNL5 Narela-Rohtak Road II D/C 21.00 BBMB DVB BBMB HVPNL6 Ballabhgarh-Badarpur I D/C 25.00 BBMB BBMB NTPC DVB7 Ballabhgarh-Badarpur II D/C 25.00 BBMB BBMB NTPC DVB

278.00400 kV RRVPNL

1 Suratgarh-Ratangarh I * S/C 143.74 RRVPNL RRVPNL RRVPNLCharged at

220 kV

2 Suratgarh-Ratangarh II * S/C 144.25 RRVPNL RRVPNL RRVPNLCharged at

220 kV287.98

220 kV RRVPNL1 BTPS-Alwar S/C 136.00 RRVPNL NTPC RRVPNL

2 LILO of Anta-H’pura I & II at Dausa I D/C 7.42 RRVPNL NTPC RRVPNL

3LILO of Anta-H’pura I & II at DausaII

D/C 7.42 RRVPNL NTPC RRVPNL

4LILO of Anta-H’pura I & II at DausaIII

D/C 7.42 RRVPNL NTPC RRVPNL

5LILO of Anta-H’pura I & II at DausaIV

D/C 7.42 RRVPNL NTPC RRVPNL

* Would be part of this list only after it is commissioned at 400 kV

Annex -IPage 9 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

6 Anta-Kota (S) S/C 68.00 RRVPNL NTPC RRVPNL7 Udaipur-RAPP (A) S/C 198.00 RRVPNL RRVPNL NPC8 RAPP (B)-Kota (S) -II D/C 44.00 RRVPNL NPC RRVPNL9 RAPP (A)-Kota (S) I S/C 44.00 RRVPNL NPC RRVPNL

10 RAPP (A)-Kota (S) III D/C 44.00 RRVPNL NPC RRVPNL

11Kota(S)- Ujjain (Rajasthan portiononly)

S/C 56.00 RRVPNL RRVPNL MPEB WRLDC

12Morak - Ujjain (Rajasthan portiononly)

S/C 28.52 RRVPNL RRVPNL MPEB WRLDC

13 Hissar-Khetri S/C 115.00 RRVPNL BBMB RRVPNL14 Dadri-Khetri-I S/C 70.91 RRVPNL BBMB RRVPNL15 Dadri-Khetri-II S/C 77.18 RRVPNL BBMB RRVPNL16 Agra-Bharatpur S/C 48.00 RRVPNL UPPCLL RRVPNL

959.27132 kV RRVPNL

1132kV Gandhi Sagar-Rana PratapSagar HEP S/C

MPEB RRVPNL WRLDC

2 132kV Sheopur-Sawaimadhopur S/C MPEB RRVPNL WRLDC3 132kV Gandhi Sagar-RAPS-A S/C MPEB NPC WRLDC

0.00POWERGRID+ 500 kV HVDC

1 Rihand-Dadri Pole-I bi-pole 815.00 POWERGRID POWERGRID POWERGRID NTPC, UPPCL

Annex -IPage 10 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

2 Rihand-Dadri Pole-II bi-pole 815.00 POWERGRID POWERGRID POWERGRID NTPC, UPPCL1630.00

HVDC Back to Back Station1 Vindhyachal Block - I 0.00 POWERGRID POWERGRID POWERGRID WRLDC2 Vindhyachal Block - II 0.00 POWERGRID POWERGRID POWERGRID WRLDC

400 kV in NR-11 Singrauli-Anpara S/C 25.057 POWERGRID NTPC UPPCL2 Singrauli-Kanpur-I S/C 447.00 POWERGRID NTPC POWERGRID UPPCL3 Singrauli-Kanpur-II S/C 424.15 POWERGRID NTPC POWERGRID UPPCL4 Singrauli-Lucknow S/C 408.60 POWERGRID NTPC UPPCL5 Singrauli-Rihand-I S/C 42.026 POWERGRID NTPC NTPC6 Singrauli-Rihand-II S/C 43.95 POWERGRID NTPC NTPC7 Singrauli-Vindhyachal S/C 3.34 POWERGRID NTPC POWERGRID WRLDC8 Vindhyachal-Kanpur S/C 398.00 POWERGRID POWERGRID POWERGRID UPPCL9 Kanpur-Ballabhgarh S/C 385.60 POWERGRID POWERGRID POWERGRID

10 Kanpur-Agra S/C 240.00 POWERGRID POWERGRID POWERGRID11 Kanpur-Panki-I S/C 5.62 POWERGRID POWERGRID UPPCL12 Kanpur-Panki-II S/C 5.70 POWERGRID POWERGRID UPPCL13 Lucknow-Moradabad S/C 331.18 POWERGRID UPPCL UPPCL14 Moradabad-Muradnagar S/C 133.00 POWERGRID UPPCL UPPCL15 Dadri-Muradnagar S/C 33.10 POWERGRID NTPC UPPCL16 Dadri-Panipat S/C 112.32 POWERGRID NTPC BBMB HVPNL

Annex -IPage 11 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

17 Dadri-Ballabhgarh I D/C 53.40 POWERGRID NTPC POWERGRID HVPNL,DVB18 Dadri-Ballabhgarh II D/C 53.40 POWERGRID NTPC POWERGRID HVPNL,DVB19 Dadri-Mandola I D/C 46.30 POWERGRID NTPC POWERGRID DVB20 Dadri-Mandola II D/C 46.30 POWERGRID NTPC POWERGRID DVB21 Dadri-Malerkotla S/C 310.00 POWERGRID NTPC POWERGRID PSEB22 Ballabhgarh-Bassi S/C 226.00 POWERGRID POWERGRID POWERGRID23 Ballabhgarh-Agra S/C 181.14 POWERGRID POWERGRID POWERGRID24 Bassi-Heerapura-I S/C 47.76 POWERGRID POWERGRID RRVPNL25 Bassi-Heerapura-II S/C 48.99 POWERGRID POWERGRID RRVPNL26 Auraiya-Agra I D/C 165.84 POWERGRID NTPC POWERGRID27 Auraiya-Agra II D/C 165.84 POWERGRID NTPC POWERGRID28 Agra-Bassi S/C 211.43 POWERGRID POWERGRID POWERGRID29 Bassi-Hissar S/C 276.77 POWERGRID POWERGRID POWERGRID

4804.72220 kV in NR-1

1 Anta-Bhilwara- I D/C 186.67 POWERGRID NTPC RRVPNL2 Anta-Bhilwara- II D/C 186.67 POWERGRID NTPC RRVPNL3 Anta Dausa- I D/C 215.70 POWERGRID NTPC RRVPNL4 Anta Dausa- II D/C 215.70 POWERGRID NTPC RRVPNL5 Dausa-Heerapura- I D/C 76.86 POWERGRID RRVPNL RRVPNL6 Dausa-Heerapura- II D/C 76.86 POWERGRID RRVPNL RRVPNL7 Auraiya-Sikandara I D/C 182.18 POWERGRID NTPC UPPCL8 Auraiya-Sikandara II D/C 182.18 POWERGRID NTPC UPPCL

Annex -IPage 12 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

9 Tanakpur-Bareilly (CB ganj) I D/C 106.00 POWERGRID NHPC UPPCL10 Tanakpur-Bareilly (CB ganj) II D/C 106.00 POWERGRID NHPC UPPCL11 RAPP-B-Chittorgarh D/C I D/C 128.83 POWERGRID NPC RRVPNL12 RAPP-B-Chittorgarh D/C II D/C 128.83 POWERGRID NPC RRVPNL13 RAPP-A - RAPP-B D/C 1.45 POWERGRID NPC NPC RRVPNL14 Unchahar-Kanpur I D/C 143.55 POWERGRID NTPC POWERGRID UPPCL15 Unchahar-Kanpur II D/C 143.55 POWERGRID NTPC POWERGRID UPPCL16 Unchahar-Kanpur III D/C 144.53 POWERGRID NTPC POWERGRID UPPCL17 Unchahar-Kanpur IV D/C 144.53 POWERGRID NTPC POWERGRID UPPCL18 FaridabadGPS-Samaypur I D/C 17.69 POWERGRID NTPC BBMB HVPNL19 FaridabadGPS-Samaypur II D/C 17.69 POWERGRID NTPC BBMB HVPNL20 RAPS.B-Udaipur S/C 230.30 POWERGRID NPC RRVPNL21 FaridabadGPS-Palla I D/C 15.70 POWERGRID NTPC HVPNL22 FaridabadGPS-Palla I D/C 15.70 POWERGRID NTPC HVPNL23 RAPS.B-Anta I D/C 114.00 POWERGRID NPC NTPC RRVPNL

2781.17800 kV in NR-2

1 Kishenpur-Moga I S/C 275.00 POWERGRID POWERGRID POWERGRIDChared at 400kV

400 kV in NR-21 Uri-Wagoora I D/C 93.00 POWERGRID NHPC POWERGRID PDD J&K2 Uri-Wagoora II D/C 93.00 POWERGRID NHPC POWERGRID PDD J&K

Annex -IPage 13 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

3 Kishenpur-Chamera S/C 101.00 POWERGRID POWERGRID NHPC PDD J&K,PSEB4 Dulhasti-Kishenpur S/C 120.00 POWERGRID NHPC POWERGRID5 Chamera-Moga I D/C 236.00 POWERGRID NHPC POWERGRID PSEB6 Chamera-Moga II D/C 236.00 POWERGRID NHPC POWERGRID PSEB7 Moga-Hissar I D/C 209.00 POWERGRID POWERGRID POWERGRID PSEB,HVPNL8 Moga-Hissar II D/C 209.00 POWERGRID POWERGRID POWERGRID PSEB,HVPNL9 Hissar-Bhiwani S/C 33.00 POWERGRID POWERGRID BBMB HVPNL

10 Bhiwani-Bawana S/C 99.00 POWERGRID BBMB DVB HVPNL11 Hissar-Bawana S/C 133.00 POWERGRID POWERGRID DVB HVPNL12 Hissar-Nalagarh I D/C 250.00 POWERGRID POWERGRID POWERGRID HVPNL13 Hissar-Nalagarh II D/C 250.00 POWERGRID POWERGRID POWERGRID HVPNL14 Abdullapur-Bawana I D/C 167.00 POWERGRID POWERGRID DVB HVPNL15 Abdullapur-Bawana II D/C 167.00 POWERGRID POWERGRID DVB HVPNL16 NJPC-Abdullapur I D/C 180.00 POWERGRID NJPC POWERGRID17 NJPC-Abdullapur II D/C 180.00 POWERGRID NJPC POWERGRID

2756.00220 kV in NR-2

1 Wagoora-Pampore I D/C 11.00 POWERGRID POWERGRID PDD J&K NHPC2 Wagoora-Pampore II D/C 11.00 POWERGRID POWERGRID PDD J&K NHPC3 Salal-Kishenpur I D/C 59.00 POWERGRID NHPC POWERGRID4 Salal-Kishenpur II D/C 59.00 POWERGRID NHPC POWERGRID5 Salal-Kishenpur III D/C 60.00 POWERGRID NHPC POWERGRID6 Salal-Kishenpur IV D/C 60.00 POWERGRID NHPC POWERGRID

Annex -IPage 14 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

7 Kishenpur-Udhampur I D/C 23.00 POWERGRID POWERGRID PDD J&K8 Kishenpur-Udhampur II D/C 23.00 POWERGRID POWERGRID PDD J&K9 Kishenpur-Sarna I D/C 103.00 POWERGRID POWERGRID PSEB PDD J&K

10 Kishenpur-Sarna II D/C 103.00 POWERGRID POWERGRID PSEB PDD J&K11 Salal-Jammu I S/C 56.00 POWERGRID NHPC PDD J&K12 Salal-Jammu II S/C 63.00 POWERGRID NHPC PDD J&K13 Jammu-Heeranagar S/C 46.00 POWERGRID PDD J&K PDD J&K14 Heeranagar-Sarna S/C 45.00 POWERGRID PDD J&K PSEB15 Sarna-Dasuya I D/C 53.00 POWERGRID PSEB PSEB16 Sarna-Dasuya II D/C 53.00 POWERGRID PSEB PSEB17 Bairasiul-Jessore S/C 57.00 POWERGRID NHPC HPSEB BBMB18 Jessore-Pong S/C 40.00 POWERGRID HPSEB BBMB NHPC19 Bairasiul-Pong S/C 97.00 POWERGRID NHPC BBMB20 Hissar(PG)-Hissar(HVPNL) I D/C 13.50 POWERGRID POWERGRID HVPNL21 Hissar(PG)-Hissar(HVPNL) II D/C 13.50 POWERGRID POWERGRID HVPNL

1049.00220 kV Others

1 Auraiya - Malanpur I D/C MPEB NTPC MPEB WRLDC2 Auraiya - Malanpur II D/C MPEB NTPC MPEB WRLDC3 Auraiya - UPPC (GAIL) Pata I D/C GAIL NTPC GAIL4 Auraiya - UPPC (GAIL) Pata II D/C GAIL NTPC GAIL

132 kV Others

Annex -IPage 15 of 30

End - 1 End - 2

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Agency atO&M by

A. LIST OF IMPORTANT TRANSMISSION LINES

RemarksOther Agencies

AffectedSl.No.

Name of Line/ICTCkt. Confi-

guration(Towers)

LineLength(in km)

1 Singrauli -Rihand -Vindhyachal S/C POWERGRID NTPC NTPC WRLDC

Annex -IPage 16 of 30

Sl.NoMVA

CapacityMake

315 BHEL315 BHEL315 BHEL315 BHEL315 BHEL315 BHEL315 CGL315 CGL315 CGL

315 BHEL315 BHEL250 BHEL250 BHEL250 BHEL315 BHEL315 BHEL315 BHEL315 CGL315 BHEL315 BHEL315 BHEL315 BHEL315 BHEL315 BHEL

B. LIST OF IMPORTANT 400/220 kV & 400/132 kV ICTs

ICT -IICT -II 3 phase unit

7 WagooraICT -II

PSEBPSEB

PDD J&KPDD J&K

Chandigarh/PSEB

1 phase unit

4 MalerkotlaICT -IIICT -I 3 phase unit

ICT -I

3 phase unit

1 phase unit

5

HVPNL3 Hissar

HVPNLICT -II 3 phase unitICT -I 3 phase unit

PSEB2 Moga PSEB

PSEB

ICT -I 3 phase unit3 phase unit3 phase unit

ICT -II

ICT -II 1 phase unitICT -I

DVBDVBDVBDVB

ICT -III

3 phase unit3 phase unit3 phase unit3 phase unit

1 phase unitPOWERGRID – NR 2

1 Kishenpur

Mandola

ICT -IICT -IIICT -IIIICT -IV

HVPNL, DVBHVPNL, DVBHVPNL, DVB

2 BallabhgarhICT -I 3 phase unit

ICT -III 3 phase unitICT -II 3 phase unit

3

Other AgenciesAffected

POWERGRID – NR 1

1 KanpurUPPCL

Sub-Station ICT no. Configuration

UPPCL3 phase unit

3 phase unit HVPNLICT -II 3 phase unit HVPNL

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

Chandigarh/PSEB6 Nalagarh

ICT -I 3 phase unitICT -II 3 phase unit

AbdullapurICT -I

Annex -IPage 17 of 30

Sl.NoMVA

CapacityMake

B. LIST OF IMPORTANT 400/220 kV & 400/132 kV ICTs

Other AgenciesAffected

Sub-Station ICT no. Configuration

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

100 BHEL100 BHEL200 BHEL200 BHEL500 CGL500 CGL500 BHEL500 BHEL315 BHEL315 TELK

1 250 TELK2 500 TELK

450 TELK450 TELK

100 BHEL100 CGL100 CGL240 GEC, ALSTHOM240 GEC, ALSTHOM240 BHEL240 BHEL240 BHEL240 TELK

* Owned by POWERGRID

ICT -III(400/132 kV)

ICT -I 3 phase unit3 phase unitICT -II

3 phase unit

3 phase unit

ICT -I

ICT -I

4 Sarnath

3 Panki

ICT -II 3 phase unit

Obra

1 phase unit1 phase unit

3 phase unit3 phase unit

UPPCL

1 AnparaICT -I(400/132 kV)ICT -II(400/132 kV)

3 PanipatICT -I

ICT -II *

ICT -II3 phase unit3 phase unit

HVPNL

HVPNLHVPNL

BBMB

Bhiwani ICT -I1 phase unit1 phase unit

Dehar ICT -I

5ICT -I

Auraiya3 phase unit3 phase unitICT -II

ICT -II 1 phase unit3 Dadri (Thermal)

1 phase unitICT -I

ICT -II(400/132 kV) 3 phase unitSingrauli STPS

3 phase unitICT -I(400/132 kV)

ICT -2(400/132 kV) 3 phase unit POWERGRID

1

NTPC

DVB, HVPNLDVB, HVPNL

POWERGRIDPOWERGRID

All CONSTITUENTS4 Dadri (Gas)

ICT -III All CONSTITUENTSICT -IV 1 phase unit

1 phase unit

2

ICT -1(400/132 kV) 3 phase unit POWERGRID2 Rihand STPS

Annex -IPage 18 of 30

Sl.NoMVA

CapacityMake

B. LIST OF IMPORTANT 400/220 kV & 400/132 kV ICTs

Other AgenciesAffected

Sub-Station ICT no. Configuration

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

5 200 ABB240 BHEL240 BHEL240 BHEL240 HITACHI240 GEC, ALSTHOM240 HITACHI240 MITSUBISHI240 BHEL240 BHEL315 BHEL240 BHEL

11 240 MITSUBISHI12 315 BHEL

315 BHEL315 BHEL

250 TELK250 TELK250 TELK315 TELK

315 BHEL315 BHEL

315 BHEL

3 phase unit

ICT -III 3 phase unit

ICT -II

ICT -III

ICT -IDVB

3 phase unit1 Bawana

Owned byPOWERGRID

3 phase unit

ICT -I 3 phase unit

ICT -IV 3 phase unit

ICT -II 3 phase unit1 Heerapura

ICT -II

7 SultanpurICT -I 3 phase unit

Mau

3 phase unitICT -II

10

6 AzamgarhICT -I 3 phase unitICT -II 3 phase unit

RRVPNL3 phase unit

ICT -I 3 phase unit

3 phase unit13 Unnao

Agra

3 phase unit3 phase unit

MuradnagarICT -I

ICT -IIIRishikesh

ICT -I

ICT -II

3 phase unit3 phase unit

ICT -I 3 phase unit

3 phase unit

9 MoradabadICT -IICT -II

3 phase unit3 phase unit

8 LucknowICT -IICT -II

ICT -I(400/132 kV) 3 phase unit

Annex -IPage 19 of 30

Sl.No Sub-Station Capacity Configuration Make Remarks/ Other Agencies Affected

80 MVAR 3 phase unit ACEC UPPCL+ 140 MVAR (SVC

-I)3 phase unit ABB UPPCL

+ 140 MVAR (SVC-II)

3 phase unit ABB UPPCL

2 Agra 50 MVAR 1 phase unit CGL 3x(1 phase of 16.67 MVAR)3 Bassi 50 MVAR 3 phase unit FUJI RSEB4 Ballabhgarh 80 MVAR 3 phase unit BHEL HVPNL, DVB5 Mandola 50 MVAR 3 phase unit BHEL DVB

6Vindhyachal (Back to Back

S/S)93 MVAR 3 phase unit ASEA UPPCL, NTPC

1 Kishenpur 63 MVAR 3 phase unit BHEL PDD J&K2 Moga 50 MVAR 3 phase unit BHEL PSEB

3Hissar (Switchable on

Moga -Hissar -I)50 MVAR 3 phase unit BHEL HVPNL

4 Malerkotla 50 MVAR 3 phase unit BHEL PSEB5 Abdullapur 50 MVAR 3 phase unit BHEL HVPNL6 Nalagarh 50 MVAR 3 phase unit BHEL HPSEB

1 Bhiwani 50 MVAR 3 phase unit TELK HVPNL

1 Panki 50 MVAR 3 phase unit CGLUPPCL

POWERGRID - NR -1

1 Kanpur

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

C. LIST OF 400 kV SWITCHABLE REACTORS

POWERGRID - NR - 2

BBMB

Annex -IPage 20 of 30

Sl.No Sub-Station Capacity Configuration Make Remarks/ Other Agencies Affected

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

C. LIST OF 400 kV SWITCHABLE REACTORS

2 Sarnath 50 MVAR 3 phase unit CGL3 Azamgarh 50 MVAR 3 phase unit CGL

4 Lucknow 50 MVAR 3 phase unit ACECOwned by POWERGRID & UPPCL

in ratio of 2/3 & 1/3 respectively.Maintained by UPPCL.

5 Moradabad 50 MVAR 3 phase unit ACEC

6 Muradnagar 50 MVAR1 phase unit (3x 1

phase of 16.67MVAR)

CGLOwned by POWERGRID & UPPCL

in ratio of 2/3 & 1/3 respectively.Maintained by UPPCL.

7 Rishikesh 50 MVAR 3 phase unit CGL

Annex -IPage 21 of 30

INSTALLED EFFECTIVECAPACITY (MW) CAPACITY (MW)

1 CENTRAL SECTORA NTPC

1 100.00 95.002 100.00 95.003 100.00 95.004 210.00 210.005 210.00 210.001 200.00 200.002 200.00 200.003 200.00 200.004 200.00 200.005 200.00 200.006 500.00 500.007 500.00 500.001 500.00 500.002 500.00 500.001 210.00 210.002 210.00 210.003 210.00 210.004 210.00 210.001 210.00 210.002 210.00 210.003 210.00 210.004 210.00 210.001 110.00 110.002 110.00 110.003 110.00 110.004 110.00 110.00

GT #1 88.71 88.71GT #2 88.71 88.71GT #3 88.71 88.71

ST 153.20 153.20GT #1 111.19 111.19GT #2 111.19 111.19GT #3 111.19 111.19GT #4 111.19 111.19ST #1 109.30 109.30ST #2 109.30 109.30GT #1 130.19 130.19GT #2 130.19 130.19GT #3 130.19 130.19GT #4 130.19 130.19ST #1 154.51 154.51ST #2 154.51 154.51GT #1 143.00 143.00GT #2 143.00 143.00

ST 146.00 146.00Sub-Total 8184.47 8169.47

UNIT No.STATIONSl. No.

Auraiya GPS(h)

Anta GPS(g)

Faridabad GPS(j)

Dadri GPS(i)

(e) Unchahar TPS

(f) Tanda TPS

Singrauli STPS

(c) Rihand STPS

(d) Dadri NCTPS

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

D. LIST OF IMPORTANT GENERATING UNITS

(a) Badarpur TPS

(b)

Annex -IPage 22 of 30

INSTALLED EFFECTIVECAPACITY (MW) CAPACITY (MW)

UNIT No.STATIONSl. No.

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

D. LIST OF IMPORTANT GENERATING UNITS

B NHPC1 60.00 60.002 60.00 60.003 60.00 60.001 115.00 115.002 115.00 115.003 115.00 115.004 115.00 115.005 115.00 115.006 115.00 115.001 40.00 31.402 40.00 31.403 40.00 31.401 180.00 180.002 180.00 180.003 180.00 180.001 120.00 120.002 120.00 120.003 120.00 120.004 120.00 120.00

Sub-Total 2010.00 1984.20C NPC

1 220.00 100.002 220.00 200.001 220.00 220.002 220.00 220.001 235.00 220.002 235.00 220.00

Sub-Total 1350.00 1180.002 BBMB

Bhakra Complex1 108.00 108.002 108.00 108.003 108.00 108.004 108.00 108.005 108.00 108.001 157.00 157.002 132.00 132.003 157.00 157.004 157.00 157.005 132.00 132.001 165.00 165.002 165.00 165.003 165.00 165.004 165.00 165.005 165.00 165.006 165.00 165.001 60.00 60.00

(c) NAPS

(ii) Bhakra (R) HPS

(i) Bhakra (L) HPS

(a)

(b)

Uri HPS(e)

RAPS -A(a)

Tanakpur HPS(c)

Chamera HPS(d)

Bairasiul HPS(a)

Salal HPS(b)

Dehar HPS

(b) RAPS -B

Annex -IPage 23 of 30

INSTALLED EFFECTIVECAPACITY (MW) CAPACITY (MW)

UNIT No.STATIONSl. No.

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

D. LIST OF IMPORTANT GENERATING UNITS

2 60.00 60.003 66.00 66.004 60.00 60.005 60.00 60.006 60.00 60.00

Total BBMB 1802.00 1802.003 HARYANA

1 110.00 110.002 110.00 110.003 110.00 110.004 110.00 110.005 210.00 210.00

650.00 650.004 PSEB

1 110.00 110.002 110.00 110.003 110.00 110.004 110.00 110.001 210.00 210.002 210.00 210.003 210.00 210.004 210.00 210.005 210.00 210.006 210.00 210.001 210.00 210.002 210.00 210.00

Total Thermal 2120.00 2120.005 RAJASTHAN

1 110.00 110.002 110.00 110.003 110.00 110.004 210.00 210.005 210.00 210.001 250.00 250.002 250.00 250.00

Total Thermal 1250.00 1250.006 UP

6 100.00 94.007 100.00 94.008 100.00 94.009 200.00 200.00

10 200.00 200.0011 200.00 200.0012 200.00 200.0013 200.00 200.003 110.00 105.004 110.00 105.00

(d) Harduaganj - C 10 110.00 105.00

(c)

(c)

(b)

Lehra Mohabbat TPS(c)

Kota TPS

(a) Obra Extn. - I

Panki Extn.(c)

Obra Extn. - II

(a)

(a)Guru Nanak Dev TPS

(Bhatinda)

Guru Gobind Singh TPS(Ropar)

(b)

Panipat(a)

Pong HPS

Pong HPS

(b) Suratgarh TPS

Annex -IPage 24 of 30

INSTALLED EFFECTIVECAPACITY (MW) CAPACITY (MW)

UNIT No.STATIONSl. No.

IMPORTANT ELEMENTS OF THE NORTHERN REGIONAL GRID

D. LIST OF IMPORTANT GENERATING UNITS

1 110.00 110.002 110.00 110.001 210.00 210.002 210.00 210.003 210.00 210.001 500.00 500.002 500.00 500.00

Anpara - B(g)

Anpara - A(f)

Paricha(e)

Annex -IPage 25 of 30

End - 1 End - 2

1 220 kV Ganguwal-Dhulkote I D/C 110.00 BBMB BBMB BBMB HVPNL

2 220 kV Ganguwal-Dhulkote II D/C 110.00 BBMB BBMB BBMB HVPNL

3 Dehar-Ganguwal I D/C 56.00 BBMB BBMB BBMB

4 Dehar-Ganguwal II D/C 56.00 BBMB BBMB BBMB

5 220 kV Dhulkote-Panipat I D/C 130.00 BBMB BBMB BBMB HVPNL

6 220 kV Dhulkote-Panipat II D/C 130.00 BBMB BBMB BBMB HVPNL

7 220 kV Pong-Jallandhar I D/C 98.00 BBMB BBMB BBMB

8 220 kV Pong-Jallandhar II D/C 98.00 BBMB BBMB BBMB

9 220 kV Pong-Dasuya I S/C 42.00 PSEB BBMB PSEB

10 221 kV Pong-Dasuya II S/C 43.00 PSEB BBMB PSEB

11 220 kV Dasuya-Jallandhar I S/C 56.00 PSEB PSEB PSEB

LIST OF OTHER ISTS ELEMENTS IN NORTHERN REGION NOT INCLUDED IN THE LIST OF"IMPORTANT ELEMENTS OF REGIONAL GRID"

Sl.No.

Name of Line/ICTCkt. Confi-guration

LineLength(in km)

O&M byAgency at Other Agencies

AffectedRemarks

Annex -IPage 26 of 30

End - 1 End - 2

LIST OF OTHER ISTS ELEMENTS IN NORTHERN REGION NOT INCLUDED IN THE LIST OF"IMPORTANT ELEMENTS OF REGIONAL GRID"

Sl.No.

Name of Line/ICTCkt. Confi-guration

LineLength(in km)

O&M byAgency at Other Agencies

AffectedRemarks

12 221 kV Dasuya-Jallandhar II S/C 57.00 PSEB PSEB PSEB

13 220 kV Ganguwal-Jagadhari S/C 158.00 BBMB BBMB BBMB HVPNL

14 220 kV Jagadhari-Kurukshetra S/C 48.00 BBMB BBMB BBMB HVPNL

15 220 kV Kurukshetra-Panipat S/C 73.00 BBMB BBMB BBMB HVPNL

16 220 kV Jallandhar-Jamalpur I D/C 63.00 BBMB BBMB BBMB

17 220 kV Jallandhar-Jamalpur II D/C 63.00 BBMB BBMB BBMB

18 220 kV Bhakra (R)-Jamalpur I D/C 86.00 BBMB BBMB BBMB PSEB

19 220 kV Bhakra (R)-Jamalpur II D/C 86.00 BBMB BBMB BBMB PSEB

20 220 kV Bhiwani-Dadri I D/C 36.00 BBMB BBMB BBMB HVPNL

21 220 kV Bhiwani-Dadri II D/C 36.00 BBMB BBMB BBMB HVPNL

22 220 kV Bhiwani-Dadri III D/C 37.00 BBMB BBMB BBMB HVPNL

Annex -IPage 27 of 30

End - 1 End - 2

LIST OF OTHER ISTS ELEMENTS IN NORTHERN REGION NOT INCLUDED IN THE LIST OF"IMPORTANT ELEMENTS OF REGIONAL GRID"

Sl.No.

Name of Line/ICTCkt. Confi-guration

LineLength(in km)

O&M byAgency at Other Agencies

AffectedRemarks

23 220 kV Bhiwani-Dadri IV D/C 38.00 BBMB BBMB BBMB HVPNL

24 220 kV Panipat-Dadri S/C 115.00 BBMB BBMB BBMB HVPNL

25 220 kV Sangrur-Barnala S/C 39.00 BBMB BBMB BBMB

26 220 kV Barnala-L’ mohabat S/C 35.00 BBMB BBMB PSEB

27 220 kV L’ mohabat-Bhatinda S/C 32.00 BBMB PSEB PSEB

28 220 kV Ganguwal-Bhakra (L) I D/C 24.00 BBMB BBMB BBMB

29 220 kV Ganguwal-Bhakra (L) II D/C 24.00 BBMB BBMB BBMB

30 220 kV Ganguwal-Bhakra (L) -III S/C 24.00 BBMB BBMB BBMB

31 220 kV Ganguwal-Bhakra (R) I D/C 25.00 BBMB BBMB BBMB

32 220 kV Ganguwal-Bhakra (R) II D/C 25.00 BBMB BBMB BBMB

33 220 kV Bhakra (R)-Jamsher S/C 98.38 PSEB BBMB PSEB

Annex -IPage 28 of 30

End - 1 End - 2

LIST OF OTHER ISTS ELEMENTS IN NORTHERN REGION NOT INCLUDED IN THE LIST OF"IMPORTANT ELEMENTS OF REGIONAL GRID"

Sl.No.

Name of Line/ICTCkt. Confi-guration

LineLength(in km)

O&M byAgency at Other Agencies

AffectedRemarks

34 220 kV Bhakra (R)-Mahilpur S/C 51.00 PSEB BBMB PSEB

3566kV Mohali(PSEB)-ChandigarhUTSec-39 - I

D/C UT Chandigarh PSEB Chandigarh

3666kV Mohali(PSEB)-ChandigarhUTSec-39 - II

D/C UT Chandigarh PSEB Chandigarh

3766kV Mohali(PSEB)-ChandigarhUTSec-52 - I

D/C UT Chandigarh PSEB Chandigarh

3866kV Mohali(PSEB)-ChandigarhUTSec-52 - II

D/C UT Chandigarh PSEB Chandigarh

3966kV Pinjore(HVPN)-Ch'garhUTSec-28(BBMB)-I

D/C BBMB HVPNL Chandigarh

4066kV Pinjore(HVPN)-Ch'garhUTSec-28(BBMB)-II

D/C BBMB HVPNL Chandigarh

4166kV Dhulkote(BBMB)-Ch'garh UTSec-28(BBMB)-I

D/C BBMB BBMB Chandigarh

4266kV Dhulkote(BBMB)-Ch'garh UTSec-28(BBMB)-II

D/C BBMB BBMB Chandigarh

43 33kV Kundli-Narela S/C HVPNL HVPNL DVB

44 132kV Narela -Sonipat S/C HVPNL BBMB HVPNL

Annex -IPage 29 of 30

End - 1 End - 2

LIST OF OTHER ISTS ELEMENTS IN NORTHERN REGION NOT INCLUDED IN THE LIST OF"IMPORTANT ELEMENTS OF REGIONAL GRID"

Sl.No.

Name of Line/ICTCkt. Confi-guration

LineLength(in km)

O&M byAgency at Other Agencies

AffectedRemarks

45 132kV Narela -Bahadurgarh S/C HVPNL BBMB HVPNL

46 66kV Rohtak Road-Gurgaon - I D/C HVPNL BBMB HVPNL

47 66kV Rohtak Road-Gurgaon - II D/C HVPNL BBMB HVPNL

48 33 kV Rohtak Road-Gurgaon S/C HVPNL BBMB HVPNL

49 66kV Pinjore-Parwanoo S/C HPSEB/HVPNL HVPNL HPSEB

50 132kV Chohal-Hamirpur S/C PSEB PSEB HPSEB

51 132kV Giri-Abdullapur S/C HPSEB/HVPNL HPSEB BBMB

52 66kV Bhakra-L-Rakkar S/C BBMB BBMB HPSEB

53 33kV Ganguwal-Bilaspur - I S/C HPSEB BBMB HPSEB

54 33kV Ganguwal-Bilaspur - II S/C HPSEB BBMB HPSEB

55 11kV Ganguwal-Nainadevi S/C HPSEB BBMB HPSEB

Annex -IPage 30 of 30

End - 1 End - 2

LIST OF OTHER ISTS ELEMENTS IN NORTHERN REGION NOT INCLUDED IN THE LIST OF"IMPORTANT ELEMENTS OF REGIONAL GRID"

Sl.No.

Name of Line/ICTCkt. Confi-guration

LineLength(in km)

O&M byAgency at Other Agencies

AffectedRemarks

56 132kV Ropar-Pinjore - I D/C HVPNL PSEB HVPNL

57 132kV Ropar-Pinjore - II D/C HVPNL PSEB HVPNL

58 33kV Rohtak Road-Bahadurgarh S/C HVPNL BBMB HVPNL

59 66kV Pathankote-Kathua S/C PSEB PSEB PDD J&K

60 66kV Sarna-Kathua S/C PDD J&K PSEB PDD J&K

61 11kV Pathankote-Basoli S/C PSEB/PDD PSEB HPSEB

62 33kV Chamera-Sewah S/C HPSEB/PDD NHPC PDD

63 66kV Muktsar-Sri Ganga Nagar S/C PSEB PSEB RRVPNL

64 66kV Pong-Talwara S/C PSEB BBMB PSEB

65 66kV Bhakra-L-NFF -I S/C BBMB BBMB NFF

66 66kV Bhakra-L-NFF -II S/C BBMB BBMB NFF

Annex -IPage 31 of 30

End - 1 End - 2

LIST OF OTHER ISTS ELEMENTS IN NORTHERN REGION NOT INCLUDED IN THE LIST OF"IMPORTANT ELEMENTS OF REGIONAL GRID"

Sl.No.

Name of Line/ICTCkt. Confi-guration

LineLength(in km)

O&M byAgency at Other Agencies

AffectedRemarks

67 66kV Bhakra-L-PACL S/C BBMB BBMB PACL

68 132kV Hissar-Rajgarh S/C RRVPNL BBMB RRVPNL

69 132kV Hissar-AmarpuraThedi S/C RRVPNL BBMB RRVPNL

ANNEX – IISHEET 1 of 26

FORMAT-AAVAILABILITY DECLARATION (Ex BUS) BY COAL FIRED / NUCLEAR ISGS

(TO BE SENT BY ISGS TO NRLDC BY 10:00 HRS)

FROM: ( Name of power station ) TO: SCE, NRLDC, NEW DELHI

DECLARED CAPABILITY ( Ex-BUS ) OF (Name of power station) FOR DATE: dd.mm.yy

MSG NO. ......... REVISION NO .......... DATE OF ISSUE : dd.mm.yy TIME OF ISSUE: hh : mm

( A ) DECLARED CAPABILITY UNIT NOs. CAPABILITY TIMEEx-BUS (MW) (hh : mm)

( i ) Units anticipated on bar at 00:00 hrs of next day ................ ..................... 00 : 00

( ii ) Units to go under planned shut down during next day ................ ..................... ............................ ..................... ............

(iii) Units likely to return from planned shutdown ................ ..................... ............during next day ................ ..................... ............

TIME DURATION DECLAREDFROM TO CAPABILITY

(hh : mm) (hh : mm) Ex-BUS (MW)

(iv)Declared capability based on A-(i), (ii) & (iii) above 00 : 00 ..................... ............................ ..................... ............................ ..................... ............................ ..................... ............................ ..................... ............

Ex-BUS MWH* ............

( B ) DETAILS OF CONSTRAINTS IF ANY :

NAME OF OFFICER INCHARGE WITH DESIGNATION

* The Ex-BUS MWH declared capability (DC) is a value which can be lower than the arithmetic sum of the capability declaredfor different blocks due to fuel or any other technical constraints and should be stated by the station after taking into considerationall such factors.

FORMAT-A , DECLARED CAPABILITY ( Ex-bus ) OF (Name of power station), FOR DATE: dd.mm.yy, REVISION NO .........., ( Page 1/ 1 )

ANNEX – IISHEET 2 of 26

FORMAT-BAVAILABILITY DECLARATION (Ex BUS) BY GAS FIRED / LIQUID FIRED ISGS

(TO BE SENT BY ISGS TO NRLDC BY 10:00 HRS)

FROM: ( Name of power station ) TO: SCE, NRLDC, NEW DELHI

DECLARED CAPABILITY ( Ex-BUS ) OF (Name of power station) FOR DATE: dd.mm.yy

MSG NO. .........REVISION NO .......... DATE OF ISSUE : dd.mm.yy TIME OF ISSUE: hh : mm

( A ) DECLARED CAPABILITY UNIT NOs. CAPABILITY TIMEEx-BUS (MW) (hh : mm)

( i ) Units anticipated on bar at 00:00 hrs of next day ................ ..................... 00 : 00

( ii ) Units to go under planned shut down during next day ................ ..................... ............................ ..................... ............

(iii) Units likely to return from planned shutdown ................ ..................... ............during next day ................ ..................... ............

TIME DURATION DECLARED CAPABILITYFROM TO Gas firing Liquid firing

(hh : mm) (hh : mm) Ex-BUS (MW) Ex-BUS (MW)

(iv)Declared capability based on A-(i), (ii) & (iii) above 00 : 00 .................. ................. ................................. .................. ................. ................................. .................. ................. ................................. .................. ................. ................................. .................. ................. .................

Ex-BUS MWH* ................. .................

TOTAL Ex-BUS MWH* ...................

( B ) GAS / LIQUID CONSUMPTION STATUS

( i ) Gas allocation for next day ................ MCMD

( ii ) Usable liquid fuel stock ( current ) ................ kL

( iii ) Liquid fuel arrival anticipated for next day ................ kL

( iv ) Gas consumed during previous day ................ MCMD

( v ) Liquid fuel consumed during previous day ................ kL

( C ) DETAILS OF CONSTRAINTS IF ANY :

NAME OF OFFICER INCHARGE WITH DESIGNATION

* The Ex-BUS MWH declared capability (DC) is a value which can be lower than the arithmetic sum of the capability declaredfor different blocks due to fuel or any other technical constraints and should be stated by the station after taking into considerationall such factors.

FORMAT-B , DECLARED CAPABILITY ( Ex-bus ) OF (Name of power station), FOR DATE: dd.mm.yy , EVISION NO........, ( Page 1 / 1 )

ANNEX – IISHEET 3 of 26

FORMAT-CAVAILABILITY DECLARATION (Ex BUS ) BY RESERVOIR BASED HYDRO ISGS

(TO BE SENT BY ISGS TO NRLDC BY 10:00 HRS)

FROM: ( Name of power station) TO: SCE, NRLDC, NEW DELHI

DECLARED CAPABILITY (Ex-BUS) OF (Name of power station) FOR DATE: dd.mm.yy

MSG NO. ......... REVISION NO .......... DATE OF ISSUE : dd.mm.yy TIME OF ISSUE: hh : mm

( A ) DECLARED CAPABILITY UNIT NOs. CAPABILITY TIMEEx-BUS (MW) (hh : mm)

( i ) Capability at 00:00 hrs of next day ................ ..................... 00 : 00

( ii ) Units to go under planned shut down during next day ................ ..................... ............................ ..................... ............

(iii) Units likely to return from planned shutdown ................ ..................... ............during next day ................ ..................... ............

TIME DURATION DECLAREDFROM TO CAPABILITY

(hh : mm) (hh : mm) Ex-BUS (MW)

(iv)Declared capability based on A-(i), (ii) & (iii) above 00 : 00 ..................... ............................ ..................... ............................ ..................... ............................ ..................... ............................ ..................... ............

Ex-BUS MWH* ............

( B ) RESERVOIR LEVEL AND INFLOWS STATUS

( i ) Reservoir level (current) ..................... mt / ft

( ii ) Inflows on previous day ..................... comecs / cusecs

( iii ) Anticipated inflows for the next day ..................... cumacs / cusecs

GENERATION TIME(MW) (hh : mm)

( iv ) Time duration for which maximum generation can be sustained ..................... ............at a stretch

( v ) Minimum 'must-run' generation ( if any ) alongwith time period ..................... ............

( vi) Any other constraint

NAME OF OFFICER INCHARGE WITH DESIGNATION

* The Ex-BUS MWH declared capability (DC) is a value which can be lower than the arithmetic sum of the capability declaredfor different blocks due to fuel or any other technical constraints and should be stated by the station after taking into considerationall such factors.

FORMAT-C , DECLARED CAPABILITY ( Ex-bus ) OF (Name of power station), FOR DATE: dd.mm.yy , EVISION NO........, ( Page 1 / 1 )

ANNEX – IISHEET 4 of 26

FORMAT-DAVAILABILITY DECLARATION (Ex BUS) BY RUN OFF THE RIVER HYDRO ISGS

(TO BE SENT BY ISGS TO NRLDC BY 10:00 HRS)

FROM: ( Name of power station) TO: SCE, NRLDC, NEW DELHI

DECLARED CAPABILITY ( Ex-BUS ) OF (Name of power station) FOR DATE: dd.mm.yy

MSG NO. ......... REVISION NO .......... DATE OF ISSUE : dd.mm.yy TIME OF ISSUE: hh : mm

( A ) DECLARED CAPABILITY UNIT NOs. CAPABILITY TIMEEx-BUS (MW) (hh : mm)

( i ) Capability at 00:00 hrs of next day ................ ..................... 00 : 00

( ii ) Units to go under planned shut down during next day ................ ..................... ............................ ..................... ............

(iii) Units likely to return from planned shutdown ................ ..................... ............during next day ................ ..................... ............

TIME DURATION DECLAREDFROM TO CAPABILITY

(hh : mm) (hh : mm) Ex-BUS (MW)

(iv)Declared capability based on A-(i), (ii) & (iii) above 00 : 00 ..................... ............................ ..................... ............................ ..................... ............................ ..................... ............................ ..................... ............

Ex-BUS MWH* ............

( B ) INFLOWS STATUS

(i ) Inflows on previous day ..................... comecs / cusecs

( ii ) Anticipated inflows for the next day ..................... cumacs / cusecs

GENERATION TIME(MW) (hh : mm)

( iii ) Time duration for which maximum generation can be sustained ..................... ............at a stretch

( iv ) Minimum 'must-run' generation ( if any) alongwith time period ..................... ............

( v) Any other constraint

NAME OF OFFICER INCHARGE WITH DESIGNATION

* The Ex-BUS MWH declared capability (DC) is a value which can be lower than the arithmetic sum of the capability declaredfor different blocks due to fuel or any other technical constraints and should be stated by the station after taking into considerationall such factors.

FORMAT-D , DECLARED CAPABILITY ( Ex-bus ) OF (Name of power station), FOR DATE: dd.mm.yy , REVISION NO........, ( Page 1 / 1 )

ANNEX - IISHEET 19 of 26

FROM : SCE, NRLDC, NEW DELHI

DRAWAL SCHEDULE ( Ex STATE PERIPHERY ) FROM THE GRID FOR ( Name of constituent state ) FOR DATE: dd.mm.yy

MSG NO………. REVISION NO………. DATE OF ISSUE : dd.mm.yy TIME OF ISSUE: hh : mm

BLOCK TIME

NO. POINT SINGRAULI RIHAND DADRI(T) UNCH-I UNCH-II NAPS RAPP'B' BAIRASIUL SALAL TANAKPUR

( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW )

hh : mm 1 2 3 4 5 6 7 8 9 10

1 00:00

2 00:15

3 00:30

4 00:45

5 01:00

6 01:15

7 01:30

8 01:45

9 02:00

10 02:15

11 02:30

12 02:45

13 03:00

14 03:15

15 03:30

16 03:45

17 04:00

18 04:15

19 04:30

20 04:45

21 05:00

22 05:15

23 05:30

24 05:45

25 06:00

26 06:15

27 06:30

28 06:45

29 07:00

30 07:15

31 07:30

32 07:45

33 08:00

34 08:15

35 08:30

36 08:45

37 09:00

38 09:15

39 09:30

40 09:45

41 10:00

42 10:15

43 10:30

44 10:45

NOTE: Net drawal schedule in respect of Bhakra, Dehar & Pong is as finalised by BBMB

FORMAT- J, DRAWAL SCHEDULE FOR ( Name of constituent state ), FOR DATE: dd.mm.yy, REVISION NO……, ( Page 1 / 8 )

DRAWAL SCHEDULE FOR CONSTITUENT STATESFORMAT- J

( TO BE ISSUED BY NRLDC TO CONSTITUENT STATES BY 1700 HRS )

TO : ( Name of the constituent state )

Ex-POWER PLANT DRAWAL SCHEDULE FROM STATION

ANNEX - IISHEET 20 of 26

BLOCK TIME

NO. POINT SINGRAULI RIHAND DADRI(T) UNCH-I UNCH-II NAPS RAPP'B' BAIRASIUL SALAL TANAKPUR

( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW )

hh : mm 1 2 3 4 5 6 7 8 9 10

45 11:00

46 11:15

47 11:30

48 11:45

49 12:00

50 12:15

51 12:30

52 12:45

53 13:00

54 13:15

55 13:30

56 13:45

57 14:00

58 14:15

59 14:30

60 14:45

61 15:00

62 15:15

63 15:30

64 15:45

65 16:00

66 16:15

67 16:30

68 16:45

69 17:00

70 17:15

71 17:30

72 17:45

73 18:00

74 18:15

75 18:30

76 18:45

77 19:00

78 19:15

79 19:30

80 19:45

81 20:00

82 20:15

83 20:30

84 20:45

85 21:00

86 21:15

87 21:30

88 21:45

89 22:00

90 22:15

91 22:30

92 22:45

93 23:00

94 23:15

95 23:30

96 23:45

ENERGY IN MWH

NOTE: Net drawal schedule in respect of Bhakra, Dehar & Pong is as finalised by BBMBFORMAT- J, DRAWAL SCHEDULE FOR ( Name of constituent state ), FOR DATE: dd.mm.yy, REVISION NO……, ( Page 2 / 8 )

Ex-POWER PLANT DRAWAL SCHEDULE FROM STATION

ANNEX - IISHEET 21 of 26

BLOCK TIME

NO. POINT CHAMERA URI ANTA ANTA AURAIYA AURAIYA DADRI DADRI BHAKRA DEHAR

GAS FIRED LQD FIRED GAS FIRED LQD FIRED GAS FIRED LQD FIRED

( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW )

hh : mm 11 12 13 14 15 16 17 18 19 20

1 00:00

2 00:15

3 00:30

4 00:45

5 01:00

6 01:15

7 01:30

8 01:45

9 02:00

10 02:15

11 02:30

12 02:45

13 03:00

14 03:15

15 03:30

16 03:45

17 04:00

18 04:15

19 04:30

20 04:45

21 05:00

22 05:15

23 05:30

24 05:45

25 06:00

26 06:15

27 06:30

28 06:45

29 07:00

30 07:15

31 07:30

32 07:45

33 08:00

34 08:15

35 08:30

36 08:45

37 09:00

38 09:15

39 09:30

40 09:45

41 10:00

42 10:15

43 10:30

44 10:45

45 11:00

46 11:15

47 11:30

48 11:45

NOTE: Net drawal schedule in respect of Bhakra, Dehar & Pong is as finalised by BBMB

FORMAT- J, DRAWAL SCHEDULE FOR ( Name of constituent state ), FOR DATE: dd.mm.yy, REVISION NO……, ( Page 3 / 8 )

Ex-POWER PLANT DRAWAL SCHEDULE FROM STATION

ANNEX - IISHEET 22 of 26

BLOCK TIME

NO. POINT CHAMERA URI ANTA ANTA AURAIYA AURAIYA DADRI DADRI BHAKRA DEHAR

GAS FIRED LQD FIRED GAS FIRED LQD FIRED GAS FIRED LQD FIRED

( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW )

hh : mm 11 12 13 14 15 16 17 18 19 20

49 12:00

50 12:15

51 12:30

52 12:45

53 13:00

54 13:15

55 13:30

56 13:45

57 14:00

58 14:15

59 14:30

60 14:45

61 15:00

62 15:15

63 15:30

64 15:45

65 16:00

66 16:15

67 16:30

68 16:45

69 17:00

70 17:15

71 17:30

72 17:45

73 18:00

74 18:15

75 18:30

76 18:45

77 19:00

78 19:15

79 19:30

80 19:45

81 20:00

82 20:15

83 20:30

84 20:45

85 21:00

86 21:15

87 21:30

88 21:45

89 22:00

90 22:15

91 22:30

92 22:45

93 23:00

94 23:15

95 23:30

96 23:45

ENERGY IN MWH

NOTE: Net drawal schedule in respect of Bhakra, Dehar & Pong is as finalised by BBMB

FORMAT- J, DRAWAL SCHEDULE FOR ( Name of constituent state ), FOR DATE: dd.mm.yy, REVISION NO……, ( Page 4 / 8 )

Ex-POWER PLANT DRAWAL SCHEDULE FROM STATION

ANNEX - IISHEET 23 of 26

BLOCK TIME PONG Ex-PP from Bilateral-1 Bilateral-2 Bilateral-3 Bilateral-4 Bilateral-5 Bilateral-6

NO. POINT ISGS/JS * With….. With….. With….. With….. With….. With…..

( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW )

hh : mm 21 22 23 24 25 26 27 28

1 00:00

2 00:15

3 00:30

4 00:45

5 01:00

6 01:15

7 01:30

8 01:45

9 02:00

10 02:15

11 02:30

12 02:45

13 03:00

14 03:15

15 03:30

16 03:45

17 04:00

18 04:15

19 04:30

20 04:45

21 05:00

22 05:15

23 05:30

24 05:45

25 06:00

26 06:15

27 06:30

28 06:45

29 07:00

30 07:15

31 07:30

32 07:45

33 08:00

34 08:15

35 08:30

36 08:45

37 09:00

38 09:15

39 09:30

40 09:45

41 10:00

42 10:15

43 10:30

44 10:45

45 11:00

46 11:15

47 11:30

48 11:45

NOTE: Net drawal schedule in respect of Bhakra, Dehar & Pong is as finalised by BBMB* Ex-POWER PLANT FROM ISGS / JS = {SUM OF DRAWAL SCHEDULE FROM ISGS / JS} = [SUM OF ENTITIES FROM (1) TO (21)]

** NET BILATERAL = {SUM OF BILATERAL-1 TO BILATERAL-6} = [SUM OF ENTITIES FROM (22) TO (28)]

FORMAT- J, DRAWAL SCHEDULE FOR ( Name of constituent state ), FOR DATE: dd.mm.yy, REVISION NO……, ( Page 5 / 8 )

29

Net Bilateral **

( MW )

ANNEX - IISHEET 24 of 26

BLOCK TIME PONG Ex-PP from Bilateral-1 Bilateral-2 Bilateral-3 Bilateral-4 Bilateral-5 Bilateral-6

NO. POINT ISGS/JS * With….. With….. With….. With….. With….. With…..

( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW ) ( MW )

hh : mm 21 22 23 24 25 26 27 28

49 12:00

50 12:15

51 12:30

52 12:45

53 13:00

54 13:15

55 13:30

56 13:45

57 14:00

58 14:15

59 14:30

60 14:45

61 15:00

62 15:15

63 15:30

64 15:45

65 16:00

66 16:15

67 16:30

68 16:45

69 17:00

70 17:15

71 17:30

72 17:45

73 18:00

74 18:15

75 18:30

76 18:45

77 19:00

78 19:15

79 19:30

80 19:45

81 20:00

82 20:15

83 20:30

84 20:45

85 21:00

86 21:15

87 21:30

88 21:45

89 22:00

90 22:15

91 22:30

92 22:45

93 23:00

94 23:15

95 23:30

96 23:45

ENERGY IN MWH

NOTE: Net drawal schedule in respect of Bhakra, Dehar & Pong is as finalised by BBMB

FORMAT- J, DRAWAL SCHEDULE FOR ( Name of constituent state ), FOR DATE: dd.mm.yy, REVISION NO……, ( Page 6 / 8 )

Net Bilateral **

( MW )

29

ANNEX - IISHEET 25 of 26

BLOCK TIME

NO. POINT

hh : mm

1 00:00

2 00:15

3 00:30

4 00:45

5 01:00

6 01:15

7 01:30

8 01:45

9 02:00

10 02:15

11 02:30

12 02:45

13 03:00

14 03:15

15 03:30

16 03:45

17 04:00

18 04:15

19 04:30

20 04:45

21 05:00

22 05:15

23 05:30

24 05:45

25 06:00

26 06:15

27 06:30

28 06:45

29 07:00

30 07:15

31 07:30

32 07:45

33 08:00

34 08:15

35 08:30

36 08:45

37 09:00

38 09:15

39 09:30

40 09:45

41 10:00

42 10:15

43 10:30

44 10:45

45 11:00

46 11:15

47 11:30

48 11:45

NOTE: Net drawal schedule in respect of Bhakra, Dehar & Pong is as finalised by BBMB*** NET DRAWAL SCHEDULE (Ex POWER PLANT) = { [Ex-PP DRAWAL SCHEDULE FROM ISGS / JS] + [NET BILATERAL] } = [(22) + (29)]

**** NET DRAWAL SCHEDULE (Ex-SEB PERIPHERY)= NET DRAWAL SCHEDULE (Ex POWER PLANT) - TRANSMISSION LOSSES (ESTIMATED)

FORMAT- J, DRAWAL SCHEDULE FOR ( Name of constituent state ), FOR DATE: dd.mm.yy, REVISION NO……, ( Page 7 / 8 )

DRAWAL SCHEDULE DRAWAL SCHEDULE

*** NET **** NET

( MW ) ( MW )

( Ex-POWER PLANT ) ( Ex-SEB PERIPHERY )

30 31

ANNEX - IISHEET 26 of 26

BLOCK TIME

NO. POINT

hh : mm

49 12:00

50 12:15

51 12:30

52 12:45

53 13:00

54 13:15

55 13:30

56 13:45

57 14:00

58 14:15

59 14:30

60 14:45

61 15:00

62 15:15

63 15:30

64 15:45

65 16:00

66 16:15

67 16:30

68 16:45

69 17:00

70 17:15

71 17:30

72 17:45

73 18:00

74 18:15

75 18:30

76 18:45

77 19:00

78 19:15

79 19:30

80 19:45

81 20:00

82 20:15

83 20:30

84 20:45

85 21:00

86 21:15

87 21:30

88 21:45

89 22:00

90 22:15

91 22:30

92 22:45

93 23:00

94 23:15

95 23:30

96 23:45

ENERGY MWH

NOTE: Net drawal schedule in respect of Bhakra, Dehar & Pong is as finalised by BBMB*** NET DRAWAL SCHEDULE (Ex POWER PLANT) = { [Ex-PP DRAWAL SCHEDULE FROM ISGS / JS] + [NET BILATERAL] } = [(22) + (29)]

**** NET DRAWAL SCHEDULE (Ex-SEB PERIPHERY)= NET DRAWAL SCHEDULE (Ex POWER PLANT) - TRANSMISSION LOSSES (ESTIMATED)

FORMAT- J, DRAWAL SCHEDULE FOR ( Name of constituent state ), FOR DATE: dd.mm.yy, REVISION NO……, ( Page 8 / 8 )

*** NET **** NET

( Ex-POWER PLANT ) ( Ex-SEB PERIPHERY )

DRAWAL SCHEDULE DRAWAL SCHEDULE

( MW ) ( MW )

30 31