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AVAILABLILITY BASED

TARIFF(ABT)

An OVERVIEW

PMI, 21stNov 2008

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THE PREDECESSOR TWO PART TARIFF (K P RAO FORMULA):

Applicable for Central Generating Stations (CGS)

FIXED AND VARIABLE COST RECOVERED FULL FC RECOVERY LINKED TO TARGET PLF OF 62.78%

VC ON ACTUAL GEN. BASED ON OPERATING NORMS

FC SHARING BASED UPON DRAWAL BYCONSTITUENTS

PROVISION OF BACKING DOWN CERTIFICATION DEEMED GENERATION

MINIMUM FIXED COST RECOVERY OF 50% AT0% DEEMED PLF

INCENTIVE ABOVE 68.49% DEEMED PLF

NO INBUILT MECHANISM FOR FREQUENCYCONTROL- No incentive for Grid Discipline

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POWER SECTOR REFORM THE REGIONAL GRIDS IN INDIA REGULARLY WINESSED

HUGE REQ EXCURSIONS

THE SR GRID FREQ RARELY CROSSED ABOVE 49.5 Hz

ER FREQ WAS BELOW 49 Hz DURING EVENING PEAK HOURSBUT TOUCHED 52 Hz DURING OFF-PEAK

NR GRID FREQ WAS GENERALY LOW BUT HAD HIGH FREQSPELLS DURING MONSOON.

WR GRID FREQ WAS REGULARLY HIGH DURING NIGHT HOURS

THE CENTRAL GOVERNMENT HAD BEEN EXAMINING FOROVER 5 YEARS THE REFORM OF THE TARIFF STRUCTUREFOR BULK POWER

OBJECTIVE:

INDUCING BETTER SYSTEM OPERATION AND GRID DISCIPLINE THROUGH COMMERCIAL INCENTIVES AND DIS-INCENTIVES.

FOR THIS PURPOSE

THE GOVERNMENT HAD ENGAGED INTERNATIONALCONSULTANTS (ECC) TO COMPREHENSIVELY STUDY THEINDIAN POWER SYSTEM AND RECOMMEND A SUITABLE

TARIFF STRUCTURE

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THEIR REPORT (ECC- REPORT) WAS SUBMITTED IN1994. IT RECOMMENDED THE INTRODUCTION OFWHAT WAS CALLED THE "AVAILABILITY BASEDTARIFF" (ABT) STRUCTURE.

A COMMERCIAL RATHER THAN A REGULATORYAPPROACH.

INCENTIVISES MERIT ORDER OPERATION

INCENTIVISES GRID DISCIPLINE.

THE GOVERNMENT CONSTITUTED A NATIONALTASK FORCE (NTF) AS WELL AS REGIONAL TASKFORCES (RTFs)

TO DEBATE ON VARIOUS ISSUES IN THEINTRODUCTION OF AVAILABILITY BASED TARIFF(ABT) FOR BULK POWER.

POWER SECTOR REFORM

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ECC RECOMMENDATION

DECENTRALISED SCHEDULING AND DISPATCH OFCENTRAL SECTOR GENERATION ANDDECENTRALISED INTER-STATE AND INTER-

REGIONAL TRADING. (Option C) CENTRALISED SCHEDULING AND DISPATCH OF

ALL GENERATION, INCLUDING SEB INTERNALRESOURCES, CENTRALISED SCHEDULING OF ALL

INTERNAL TRADING WITHIN THE REGION, ANDEXCLUSIVE AUTHORITY TO NEGOTIATE INTER-REGIONAL TRADING. (Option A & B)

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NTF DECISION

IN LIGHT OF THE VIEWS OFMOST OF SEBs, THE NTFENDORSED ADOPTION OF

OPTION C AVAILABILITY BASED

GENERATION TARIFF WAS TO

BE ADOPTED AND WOULD BEAPPLIED TO ALL ISGSINCLUDING FUTURE IPPs

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New Tariff Mechanism ABT

Introduced through CERC order on Availability

Based Tariff dtd. 04.01.2000 To be applicable to ISGS (NTPC, NHPC, NLC etc.)

Original Order referred to 16 ISGS of NTPC NHPC, NLC, NEEPCO etc. brought under purview

subsequently NPC exempt from provisions of ABT Subsequent order of CERC has introduced ABT in

Badarpur TPS from 01.04.2005 Further order of CERC directed that ABT is to be

implemented w.e.f. 1.12.2005 for other single statestations of NTPC too. Simhadri, Faridabad, Tanda, TTPS & Kayamkulam NLC TPS-I from 01.01.2007

Recent Order has initiated ABT implementation forBBMB & NHDC IndiraSagar HEP.

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IMPLEMENTATION OF ABT

ABT has been implemented in differentregions from the dates given below:

WR - 01.07.2002

NR - 01.10.2002

SR - 01.01.2003ER - 01.04.2003

NER - 01.11.2003Earlier

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SALIENT FEATURES OF ABT THREE COMPONENTS

CAPACITY CHARGES(FIXED CHARGES) FULL RECOVERY AT 80% OF DECLARED (DEMONSTRATED)

CAPABILITY, DC APPORTIONED TO VARIOUS BENEFICIARIES AS PER ALLOCATION

ENERGY CHARGES SCHEDULED INTERCHANGE (SI)

PAYABLE FOR SCHEDULED ENERGY (IRRESPECTIVE OF ACTUAL GEN) PAYABLE AT NORMATIVE TARIFF INCENTIVE AT 77%+ Scheduled PLF (Subsequently changed to 80%

PLF in 2004-09 Tariff Order) Incentive @: 50% of FC at 80% or 21.5 p/kWh- later 25 p/kWh

UNSCHEDULED INTERCHANGE (UI) DEVIATION FROM SCHEDULE (AG-SG)

RATE LINKED TO FREQUENCY; different UI Charts over time ALL CALCULATION FOR EACH 15 MIN. TIME BLOCK;

SUMMATED ON DAY, MONTH AND ANNUAL BASIS. ACCORDINGLY, SCHEDULE PREPARED ON 15-MIN BASIS SPECIAL ENERGYMETER IN LINE FEEDERS, FOR NET

EXPORT AND AVG. FREQUENCY ON 15 MIN BASIS

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SALIENT FEATURES OF ABT 100% GENERATION CAPACITIES OF A ISGS IS ALLOCATED TO

BENEFICIARIES. CAP CHARGE RECOVERY AS PER ENTITLEMENT OF INDIVIDUAL

BENEFICIARIES (IRRESPECTIVE OF DRAWAL BY THE SEB) &CALCULATED ON ANNUAL BASIS

SEBs CAN REQUISITION DRAWAL FROM ISGS, limited to theirENTITLEMENT ON CAPABILITY DECLARED

SUM OF REQUISITION OF ALL BENFICIARIES IS SCHEDULE FORGEN.

SINCE LIABILITY TO PAY CAPACITY CHARGES IS IRRESPECTIVEOF SCHEDULED CAPACITY, DISPATCH DECISIONS BASED ONVARIBLE CHARGES- PROMOTES MERIT ORDER DISPATCH

VARIABLE CHARGE RECOVERY AS PER NORMS FOR ONLYSCHEDULED ENERGY

NORMS OF FIXED AND VARIABLE CHARGE ARE DECLAREDSTATION-WISE PERIODICALLY BY CERC IN THEIR TARIFFREGULATION. Present Tariff Period of 2004-09.

BECAUSE OF THE LOW VARIABLE COST OF MOST NTPCSTATIONS, NTPC STATIONS GENERALLY SCHEDULED CLOSE TO

THEIR DC

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SALIENT FEATURES OF ABT

FOR INTRODUCING GRID DISCIPLINE, THE CONCEPT OF

UNSCHEDULUED INTRCHANGE (UI) HAS BEENINTRODUCED. THE AMOUNT OF GENERATION BY ISGS OR DRAWAL BY

CONSTITUENTS, WHICH DEVIATES FROM SCHEDULE ISUNSCHEDULED INTERCHANGE

UI IS PAYABLE OR RECEIVABLE DEPENDING ON OVER ORUNDER GENERATION.

RATE OF UI LINKED TO AVERAGE FREQUENCY OF 15MINUTES TIME BLOCK.

IS ZERO AT 50.5 Hz AND ABOVE INCREASES AT THE RATE OF 8 PAISA FOR EVERY 0.02 Hz

DROP IN FREQUENCY upto 49.8 Hz. Subsequently increases@ 18 p/ 0.02 Hz.

AT & BELOW 49.0 Hz UI RATE IS FIXED AT Rs 10.00. CAPPED AT Rs 4.06 FOR PAYMENT TO GENERATORS (COAL

& APM GAS)

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200

550

1000

280

50.18

0

200

400

600

800

1000

1200

50.5 50.4 50.3 50.2 50.1 50 49.9 49.8 49.7 49.6 49.5 49.4 49.3 49.2 49.1 49Freq

p/kWh

UI CHARTw.e.f. 07.01.2008

P/kWh at 50 Hz

P/kWh at 49.5 Hz

P/kWh at 49 Hz

fe, break even frequency

@8 p/kWh /0.02 Hz upto 49.8 Hz@18 p/kWh /0.02 Hz below 49.8 Hz

Previous

P/kWh at 50 Hz

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ACCOUNTING IN ABTf= 49.7 Hz f = 50.0 Hz f = 50.3 Hz

SD (MW) 1000 1000 1000

AD (MW) 1050 1050 1050

SI (MW) 1000 1000 1000

UI (MW) 50 50 50

SI Amt. (Rs ,000) 1,250,000 1,250,000 1,250,000

UI Rate (Rs/kWh) 3.70 2.00 0.80

UI Amt. (Rs ,000) 185,000 100,000 40,000

Cost of SI (,000) 62,500 62,500 62,500

Gain/Loss

(Rs ,000) 122,500 37,500 -22,500

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ACCOUNTING IN ABTf= 49.7 Hz f = 50.0 Hz f = 50.3 Hz

SD (MW) 1000 1000 1000

AD (MW) 950 950 950

SI (MW) 1000 1000 1000

UI (MW) -50 -50 -50

SI Amt. (Rs ,000) 1,250,000 1,250,000 1,250,000

UI Rate (Rs/kWh) 3.70 2.00 0.80

UI Amt. (Rs ,000) -185,000 -100,000 -40,000

Cost of SI (,000) -55,000 -55,000 -55,000

Gain/Loss

(Rs ,000) -130,000 -45,000 15,000

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ABT For Hydro Stations

UI mechanism of ABT introduced for Hydro ISGS

w.e.f. 07.01.08 through amended to TariffRegulations of CERC

Hydro stations to declare day-ahead capability andenergy availability (water)

To be scheduled on 15-minute block basis Expected to match total energy generated in the

day as declared

However can modulate block wise generation based

on frequency UI to be calculated for the day and paid to the HEP

Excess/ Under generation against declaration to beadjusted on Day+3 schedule.

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SCHEDULING TERMINOLOGY

IEGC: Indian Electricity Grid Code ISGS: Inter-state Generating Stations

RLDC: Regional Load Dispatch Centre

SLDC: State Load Dispatch Centre

FIRM POWER: UPTO ENTITLEMENT ENTITLEMENT: VARIES WITH DECLARED

CAPABILITY. Maximum of ALLOCATED SHARE AT100% DC.

INFIRM POWER: UNREQUISITIONED SURPLUSPOWER & UI.

PRIORITY IN SCHEDULING & ACCOUNTING:1 FIRM POWER

2 BILATERAL POWER

3 INFIRM POWER-UI

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SCHEDULING RESPONSIBILITIES Generators:

Communication of Day-ahead capability (DC) Communication of revision of capabilities Adherence to IEGC and directions of LDCs

Load Dispatch Centres: Preparation and communication of Schedules Keeping Accounts of Energy Instructions w.r.t. Real time operation

Frequency Management Network Congestion

Jurisdiction: Regional Load Dispatch Centre :

Inter-state CGS

UMPPs Inter-state Bilateral transactions For all private ISGS of size >500 MW where at least 50% power is

allocated outside the home state

State Load Dispatch Centre : Intra-state generators IPPs except those above Embedded Open Access customers

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DAY-AHEAD SCHEDULING

DECLARATION OF STATION-WISE CAPABILITY BYISGS: 09:00 HRS.

ADVISE ON ENTITLEMENTS OF CONSTITUENTS BYRLDC: 1000 HRS.

DRAWAL REQUISITIONS AND BILATERALEXCHANGES BY SLDCs TO RLDC: 1500 HRS.

ANNOUNCEMENT OF SURPLUS :-----

DISPATCH & DRAWAL SCHEDULE (1st draft) TOEACH CONSTITUENT: 1800 HRS.

SLDCs/ ISGS MAY INFORM CHANGES TO THEIRCAPABILITY/ DRAWAL : 2200 HRS.

FINAL DAY-AHEAD SCHEDULE: 2300 HRS.

SCHEDULING TIME-TABLE

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GENERATOR ADVISES HIS EX-BUS 96 BLOCK WISE DC

RLDC ADVISES ALL BENEFICIARIES OF THEIR STATIO-WISEENTITLEMENT BASED ON THEIR SHARES IN THE STATION-BLOCK WISE

BENEFICIARIES ADVISE RLDC THEIR STATION-WISE DRAWALREQUISITIONS plus any BILATERAL TRANSACTIONS. REQUISITIONS EX-SENDING END BUS & BLOCKWISE

CAN GIVE STANDING INSTRUCTIONS GENERATOR DRAWAL SCHEDULE IS THE SUM OF ALL

REQUISTIONS FOR THAT STATION- 96 BLOCKWISE CHECKED FOR ANY LINE LOADING LIMITATIONS & MODERATED IN CASE OF NTPC MULTI-STAGE STATIONS, SEPARATE

SCHEDULE FOR STAGES DRAWAL SCHEDULE OF CONSTITUENTS IS CALCULATED AFTER

ADJUSTING AVG. REGIONAL LOSSES ANY URS KNOWN AFTER (1st draft) OF SCHEDULE (REV. 0) GENERATOR/ BENEFICIARIES CAN TIE UP ANY URS FINAL DAY-AHEAD SCHEDULE: 2300 HRS- FAXED & ON

RLDC WEBSITE.

SCHEDULE PREPARATION

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PROVISIONS IN ABTORDER CAPABILITY REVISION DUE TO TRIPPING :In case

offorced outage of a unit, RLDC will revise theschedules on the basis of revised declared capability.The revised schedules will become effective from the4th time block, counting the time block in which the

revision is advised by the generator to be the first one.The revised DC will also become effective from the 4thtime bock.

REVISION OF CAPABILITY/ REQUISITION:

...permitted with advance notice. Revisedschedules/declared capability in such cases shallbecome effective from the 6th time block, counting thetime block in which the request for revision has beenreceived in RLDCto be the first one.

REAL TIME SCHEDULING

REAL TIME SCHEDULING d

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SCHEDULE REVISION DUE TO TRANSMISSIONCONSTRAINTS :... (as certified by RLDC) necessitating

reduction in generation, RLDC will revise the scheduleswhich will become effective from the 4th time block,counting the time block in which the bottleneck inevacuation of power has taken place to be the first one.Also, during the first, second and third time blocks of suchan event, the scheduled generation of the station will be

deemed to have been revised to be equal to actualgeneration and also the scheduled drawals of thebeneficiaries will be deemed to have been revised to beequal to their actual drawals..

SCHEDULE REVISION DUE TO GRID DISTURBANCES :Scheduled Generation of all the Generating Stations andScheduled Drawal of all the Beneficiaries shall be deemedto have been revised to be equal to their ActualGeneration/Drawal for all the time blocks affected by theGrid Disturbance. Certification of Grid Disturbance and its

duration shall be done by RLDC.

REAL TIME SCHEDULING contd.

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SCHEDULE REVISION DUE TO SYSTEMREQUIREMENT :... RLDC observes thatthere is need for revision of the schedulesin the interest of better system operation,it may do so on its own. The revised

schedules shall become effective from the4th time block, counting the time block inwhich the revised schedule is issued byRLDC to be the first one.

REVISION OF SCHEDULES W.E.F......:

Generation schedules and drawalschedules issued/revised by RLDC shallbecome effective from designated timeblock irrespective of communicationsuccess.

REAL TIME SCHEDULING contd.

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Relevant IEGC Provisions 6.4.2 The system of each State shall be treated and operated as a notional control

area. While the States would generally be expected to regulate their generation

and/or consumers load so as to maintain their actual drawal from the regional gridclose to the above schedule, a tight control is not mandated. The States may, at theirdiscretion, deviate from the drawal schedule, as long as such deviations do not causesystem parameters to deteriorate beyond permissible limits and/or do not lead tounacceptable line loading.

6.4.4. Provided that the States, through their SLDCs, shall always endeavour torestrict their net drawal from the grid to within their respective drawal schedules,whenever the system frequency is below 49.5 Hz. When the frequency falls below

49.0 Hz, requisite load shedding shall be carried out in the concerned State(s) tocurtail the over-drawal.

6.4.7. While the ISGS would normally be expected to generate power according tothe daily schedules advised to them, it would not be mandatory to follow theschedules tightly. In line with the flexibility allowed to the States, the ISGS may alsodeviate from the given schedules depending on the plant and system conditions. Inparticular, they would be allowed / encouraged to generate beyond the givenschedule under deficit conditions.

6.4.8. Provided that when the frequency is higher than 50.5 Hz, the actual netinjection shall not exceed the scheduled dispatch for that time.Also, while thefrequency is above 50.5 Hz, the ISGS may (at their discretion) back down withoutwaiting for an advice from RLDC to restrict the frequency rise. When the frequencyfalls below 49.5 Hz, the generation at all ISGS (except those on peaking duty) shallbe maximized, at least upto the level which can be sustained, without waiting for anadvise from RLDC.

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Relevant IEGC Provisions .contd. 6.5.5. The SLDCs may also give standing instructions to the RLDC such that the RLDC

itself may decide the drawal schedules for the States. 6.5.7. While finalizing the above daily dispatch schedules for the ISGS, RLDC shall

ensure that the same are operationally reasonable, particularly in terms of ramping-up/ramping-down rates and the ratio between minimum and maximum generationlevels. A ramping rate of upto 200 MW per hour should generally be acceptable foran ISGS and for a regional constituent (50 MW in NER), except for hydro-electricgenerating stations which may be able to ramp up/ramp down at a faster rate.

6.5.11. While finalizing the drawal and dispatch schedules as above, the RLDC shallalso check that the resulting power flows do not give rise to any transmissionconstraints. In case any constraints are foreseen, the RLDC shall moderate theschedules to the required extent, under intimation to the concerned constituents. Anychanges in the scheduled quantum of power which are too fast or involveunacceptably large steps, may be converted into suitable ramps by the RLDC.

Ann-1.5. Regional Energy Accounts and the statement of UI charges shall beprepared by the RLDC on a weekly basis and these shall be issued to all constituentsby Saturday for the seven-day period ending on the previous Sunday mid-night.Payment of UI charges shall have a high priority and the concerned constituents shallpay the indicated amounts within 10 (ten) days of the statement issue into a regionalUI pool account operated by the RLDC. The agencies who have to receive the moneyon account of UI charges would then be paid out from the regional UI pool account,within three (3) working days.

Ann-1.10. The RLDC shall table the complete statement of the regional UI accountand the regional Reactive Energy account in the RPCs Commercial Committeemeeting, on a quarterly basis, for audit by the latter.

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In the CERC Order for Conditions of Tariff for2001-04, it was directed that any generationbeyond DC would not be eligible for UI. In case it is observed that the declaration of its

capability by the generator is on lower side and theactual generation is more than DC, then UI chargesdue to the generator on account of such extrageneration shall be reduced to zero and the amountshall be credited towards UI account of beneficiaries

in the ratio of their capacity share in the station. When generators were scheduled their full DC, it

became a lose-lose situation for the stations.

Other Important Tariff Regulation Provisions

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In the CERC Order for Conditions of Tariff for 2004-09,

CERC addressed this issue. (i) Any generation up to 105% of the declared

capacity in any time blockof 15 minutes and averagingup to 101% of the average declared capacity over aday shall not be construed as gaming, and the

generator shall be entitled to UI charges for suchexcess generation above the sch. generation (SG).

(ii) For any generation beyond the prescribed limits, theRLDC shall investigate so as to ensure that there is no

gaming, and if gaming is found by the Regional LoadDespatch Centre, the corresponding UI charges due tothe generating station on account of such extrageneration shall be reduced to zero and the amountshall be adjusted in UI account of beneficiaries in the

ratio of their capacity share in the generating station.

Other Important Tariff Regulation Provisions

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Relevant IEGC Provisions .contd.7.6 INTERFACES FOR SCHEDULING AND UI ACCOUNTING: The regional boundaries for scheduling, metering and UI accounting

of inter-regional exchanges shall be as follows: NR-WR :

400 kV West bus of Vindhyachal HVDC Gwalior end of 765 kV Agra-Gwalior line

WR-SR : 400 kV West bus of Chandrapur HVDC NR-ER :

400 kV East bus of Sasaram HVDC Muzaffarpur end of 400 kV Mzf-Gkp line Patna end of 400 kV Patna-Balia line

ER-SR : 400 kV Bus couplers between Talcher-I and Talcher-II 400 kV East bus of Gazuwaka HVDC

ER-WR : Rourkela end of 400 kV D/C Rourkela-Raipur line Budhipadhar end of 220 kV Budhipadar-Korba Lines

ER-NER : Bongaigaon end of the 400 kV D/C Malda-Purnea/Binaguri -Bongaigaon line Salakati end of 220 kV D/C Birpara-Salakati line

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Station to declare day-ahead DC on ex-bus

basis to RLDC by 0900 hrs- Station O&E Based on best estimate of availability of units. Realistic APC assessment Availability and quality of fuel Loading limitations & Operational constraints-

condenser vacuum, ID Fan margins etc. Peak hour demand Coordinated through RCC.

Prompt REVISION OF CAPABILITY in real-time-SCE (THROUGH RCC OR DIRECTLY) Delay of 15 mins in reporting tripping of 500 MW unit

could mean a UI of Rs 11.62 lacs (a loss ofRs 10.2lacs considering a variable cost of Rs. 1.25 P/Kwh.)

Revision based on unit performance and fuelcharacteristics.

Spreading out the generation over the day in case ofshortage of fuel

Peak hour DC should not be less than other periods

OPERATION IN ABT REGIME

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Real-time management of ABT performance Stations have installed ABT compliant meters for monitoring and

management of ABT performance ABT monitoring software- Shows real time values derived from ABT

meters DC & SG for the block Instantaneous AG (unit wise) & freq & UI rate; SG rate Running average AG & freq for the block Required average AG for the remaining period of block Current Variable Cost and Break-even Frequency

Total Cumulative AG for the day (as % of DC). Total cumulative UI for the day

Splitting ex-bus schedule into unit wise schedule- relative of units Raise lower decisions based on unit conditions Estimating start-up times and DC matching expected load ramp-up

UI Accounting AG calculated as sum of net export on all outgoing feeders. Daily UI report (96 block-wise) prepared by O&E Commercial export meters downloaded every Monday and forwarded

(e-mail) to RLDC. RLDC calculates station AG Standard Meter Frequency for the week

(block-wise) and post on its website Station cross-checks the same and revises its UI account RPC issues weekly regional UI pool account by next Wed. UI payments settled in the next 10 days

OPERATION IN ABT REGIME ..contd.

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URS: Un-requisitioned Surplus;Capacity remaining un requisitionedand scheduled by the beneficiaries.

Issues in Sale of URS: Infirm nature of power- beneficiaries have right

to recall

Identifying customers for URS- use of traders

Finalising terms and conditions of Saleincluding tariff

Very short duration of contracts.

Real time issues- revision of schedules

Commercial issues- billing, settlement,payment security etc.

Sale of URS

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NTPC has been trying to sell any URS capacity

with the idea of optimising all available capacity Pricing of URS:

p.u. Capacity charges @80% DC (in case of WR, forRLNG/ naphtha power only 50% of FC)- approvedcharges as on 15th April; provisional charges beingbilled where not determined.

Variable charges on normative basis based on lastavailable FPA Incentive @25 p/kWh Income Taxes and duties etc. as applicable. Transmission OA charges, Scheduling & RLDC

charges extra at actuals Trading Margin of NVVN (4p/kWh)

Sale of URS through NVVN All inter-regional sale of URS Within region sale in NR, SR & ER; WR directly by

NTPC. NVVN arranges for open access & scheduling with

RLDC

Sale of URS .contd.

S l f URS d

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Operationalisation Annual FC, VC & Monthly FPA available with RCC

After finalisation of daily schedules, RCC informs NVVNof availability of URS NVVN locates buyer and Faxes OA application to RLDC

for scheduling- parties, quantum, duration Buyer also Faxes to RLDC its consent to purchase

Billing and Payments Liability of payment of fixed charges with original

beneficiary All charges collected by NTPC in excess of variable

charges and incentive to be passed on to originalbeneficiary

In case of sale in NR, SR & ER through NVVN, bills for

FC & Taxes raised by NTPC to NVVN VC+ FPA & Incentive billed directly by NTPC to the buyer Any subsequent adjustment in FC, taxes, duties etc. to

the a/c of original beneficiary. NVVN directly bills and collects OA charges, RLDC

scheduling and operation charges.

Sale of URS .contd.

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Challenges Quantum of URS Available very dynamic Very Short window for finalising the sale.

Standard procedures finalised in RPCs

Current regulations do not permit revisionof schedules in real time for bilateral

transactions including URS. Chances of recall of capacity by original

beneficiary. Changes in capability of generator- tripping,

partial outages, fuel constraints. Shortfall in generation to be paid as UI by

GENERATOR. Taken up with CERC for necessary amendment

Very limited scope for retrospectiveadjustments- tariff revisions, statutorycharges, fuel price adjustments

Sale of URS .contd.

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DISTINCTIVE FEATURES OF

ABT THE COMMERCIAL MECHANISM IS A SELF

REGULATED DISCIPLINEANDBINDING ON

ALL CONCERNED FACILITATING GRID DISCIPLINE

FACILITATING TRADING IN CAPACITY

AND ENERGY- Short-term energy needs FACILITATING MERIT ORDER DESPATCH

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Eastern Region

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Eastern Region

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Thank you for

A LivelyDiscussion