availability based tarrif

8/8/2019 Availability Based Tarrif

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STRUCTURE OF PRESENTATION

BackgroundDefinition of AvailabilityScheduling methodologyOperation philosophyReal time schedulingMetering and billingPre-requisiteEffect of new tariff


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BACKGROUND:-ECC Virginia Consultants, appointed by Govt. of Indiaand Asian Development Bank to study Bulk Power andTransmission Tariff and Regulation recommended for ashift from PLF to availability based scenario in order toimprove discipline in Power Sector in the year 1994.

CERC (Central Electricity Regulatory Commission) wasconstituted through Indian Electricity Regulatory Act1998.

CERC issued order for implementation of ABT w.e.f.1.4.2000 in Northern Region (NR) and accordinglyissued the ABT order dtd. 4.1.2000. Implementation of ABT got delayed due to various petitions by constituents.


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THE 128 TH NREB BOARD MEETING ON 16.09.02DECIDED TO IMPLEMENT ABT IN NR W.E.F.01.12.02 WITH FULL COMMERCIALMECHANISM.

THE SCHEDULING OF NCR STATIONS HAD

BEEN DONE AS PER ABT PROVISION SINCE01.08.01 WITHOUT COMMERCIAL MECHANISM.

REAL TIME SCHEDULING ACTIVITY WASALREADY TAKEN OVER BY RCC (REGIONALCONTROL CENTRE) FROM 11.11.02.


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What is Availability?

The readiness of the generating station to deliver Ex-Bus output.

It is different from the earlier terminology which

includes only the status whether in service(100%) or out of service (0%).

The term availability in the present context

could be defined as the MW capability of thegenerator for supplying to the grid after accounting for planned and unplanned outages,auxiliary consumption and deration due to non-

availability of auxiliaries, fuel, water etc.


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COMPONENTS OF ABT

CAPACITY CHARGES

ENERGY CHARGES

UNSCHEDULED INTERCHANGES

INCENTIVE


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Capacity ChargesReturn on EquityDepreciationO&M ChargesInterest on Working Capital

Interest on LoanTaxes on Income, if any

Energy ChargesCost of Primary Fuel (Coal, Gas)Cost of Secondary Fuel


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Working Capital

O&M expenses for one monthCoal cost for two months for non-pit headstations corresponding to Target Availability(T.A.)60 days stock of secondary fuel oilcorresponding to T.A.Maintenance spares maximum of 1% of historical capital cost escalated @ 6% per annum from COD (Commercial Operation Date)Receivables equivalent to two-months averagebilling calculated on T.A.


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AVAILABILITY BASED TARIFF (ABT)

Capacity Charge payable based on Declared

Capability (DC)Charge realised on Scheduled Generation (SG) andnot on actual generation i.e. variable chargepayable on commitment from

Frequency linked incentive/penalty for Unscheduled Interchange (UI)


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Unscheduled Interchange(UI) Charges:

Variation between actual generation or actual drawal andscheduled generation or scheduled drawal shall beaccounted for through Unscheduled Interchange (UI)Charges. UI for a generating station shall be equal to itsactual generation minus its scheduled generation. UI for abeneficiary shall be equal to its total actual drawal minusits total scheduled drawal. UI shall be worked out for each15-minute time block. Charges for all UI transactions shall

be based on average frequency of the time block.


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(Each 0.02 Hz step is equivalent to 8.0 paise/kWh in the

50.5-50.0 Hz frequency range, and to 16.0 paise/kWh in the50.0-49.0 Hz frequency range)

Applicable rates with effect from 1.10.2004:


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MERITS OF ABT

ECONOMIC GENERATIONMERIT ORDER DESPATCH

GRID DISCIPLINEGENERATION RELATED TO THENEEDS OF THE GRIDADHERENCE TO THE SCHEDULE

FINANCIAL PENALTY / INCENTIVE FORUNSCHEDULED INTERCHANGE

TRADING IN SURPLUS POWER


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Scheduling Methodology

Each day starting from 00:00 hr. will be divided into 96 timeblocks of 15-minute intervals.

The generator will make an advance declaration of capability of its generating station.

The declaration will be for the capability of the generatingstation to deliver ex-bus MWh for each time block of theday. The DC, as declared by generator, would form the

basis of generation scheduling.


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While making or revising their DC, the generator shallensure that their DC during peak hours is not less thanthat during other hours . However, exception to this ruleshall be allowed in case of tripping/re-synchronisation of units as a result of forced outage of units.

Based on the declaration of the generator, RLDC shallcommunicate their shares to beneficiaries out of whichthey shall give their requisitions.


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Based on the requisitions given by beneficiaries and takinginto account technical limitations on varying the generationand also taking into account the transmission system

constraints, if any; RLDC shall prepare the economicallyoptimal generation schedule and drawal schedule andcommunicate the same to generator and beneficiaries.RLDC shall also formulate the procedure for meetingcontingencies both in the long run and in the short run.

All the scheduled generation and actual generation shall beat the generators ex-bus. For beneficiaries, the scheduledand actual net drawals shall be at their respective receiving

points.

For calculating the net drawal schedules of beneficiaries,the transmission losses shall be apportioned to their drawals.


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Scheduled generation (SG) of the generating station for each time block will mean the Scheduled MWh to be Sent

Out ex-bus from the generating station.

Actual generation of the station for each time block,hereinafter referred to as AG, will mean Actual MWh SentOut ex-bus from the generating station.

In case of forced outage of a unit, RLDC will revise the SGon the basis of revised DC. The revised SG will becomeeffective from the 4th time block, counting the time block in

which the revision is advised by the generator to be thefirst one . The revised DC will also become effective fromthe 4th time bock.


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In the event of bottleneck in evacuation of power due toany constraint, outage, failure or limitation in thetransmission system, associated switchyard and substations owned by CTU (as certified by RLDC)necessitating reduction in generation; RLDC will revise the

schedules which will become effective from the 4th timeblock, 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 SG of the station will be deemed to have been

revised to be equal to AG and also the scheduled drawalsof beneficiaries will be deemed to have been revised to beequal to their actual drawals.


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In case of any Grid Disturbance, SG of all GeneratingStations and Scheduled Drawal of all beneficiaries shall bedeemed to have been revised to be equal to their AG/Drawal for all time blocks affected by the GridDisturbance. Certification of Grid Disturbance and itsduration shall be done by RLDC.

Revision of DC by generator(s) and requisition bybeneficiary(ies) for the remaining period of the day will alsobe permitted with advance notice. Revised SG/DC in such

cases shall become effective from the 6th time block,counting the time block in which the request for revisionhas been received in RLDC to be the first one.


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If, at any point of time, RLDC observes that there is needfor revision of schedules in the interest of better systemoperation, it may do so on its own and in such cases, therevised schedules shall become effective from the 4 th

time block, counting the time block in which the revisedschedule is issued by RLDC to be the first one.

Generation schedules and drawal schedulesissued/revised by RLDC shall become effective fromdesignated time block irrespective of communication

success.

For any revision of SG, including post facto deemedrevision, there shall be a corresponding revision of scheduled drawals of beneficiaries.


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A procedure for recording the communication regardingchanges to schedules duly taking into account the timefactor shall be evolved by CTU.

I n case of a generating station, contracting to supply power only to the State in which it is located; thescheduling, metering and energy accounting shall becarried out by the respective State Load DespatchCentre.


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(i) Any generation up to 105% of DC in any 15-minute timeblock and averaging up to 101% of the average DC over a

day shall not be construed as gaming, and the generator shall be entitled to UI charges for such excess generationabove SG.

(ii) For any generation beyond the prescribed limit, theRegional Load Despatch Centre (RLDC) shall investigateso as to ensure that there is no gaming, and if gaming isfound by the RLDC, the corresponding UI charges due tothe generating station on account of such extrageneration shall be reduced to zero and the amount shallbe adjusted in UI account of beneficiaries in the ratio of their capacity share in the generating station.


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Demonstration of DC:The generating company may be required to demonstratethe DC of its generating station as and when asked by theRLDC of the region in which the generating station issituated. In the event of the generating company failing todemonstrate the DC, the capacity charges due to thegenerator shall be reduced as a measure of penalty .The quantum of penalty for the first mis-declaration for anyduration/block in a day shall be the charges correspondingto two days fixed charges. For the second mis-declarationthe penalty shall be equivalent to fixed charges for four days and for subsequent mis-declarations, the penalty

shall be multiplied in the geometrical progression.The operating log books of the generating station shall beavailable for review by the Regional Electricity Board.These books shall keep record of machine operation andmaintenance.


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OPERATION PHILOSOPHY UNDER ABT

Commercial declaration of DC without gaming

Advance/prompt intimation of DC revisions

Conservative DC declaration during start-upGeneration above SG (up to 105% of DC in ablock and up to 101% of DC over a day) duringlow freq. spells

Backing down above the threshold frequency


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AG/DC plot against Average Frequency(Ideal) (SG=90%DC)

70

80

90

100

110

48 48.5 49 49.5 50 50.5 51 51.5Av. Frequency (Hz)

A G / D C ( %

)BEF 50.3 Hz


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ACTIVITIES CARRIED OUT BY RCC

COMPILATION OF DAY AHEAD DC ANDREVISIONS THEREOF FROM STATIONS

COMMUNICATING DAY AHEAD DC ANDREVISIONS TO RLDC, ALSO ENSURING ITSTIMELY IMPLEMENTATION

OBTAINING SCHEDULE AND REVISIONSFROM RLDC OR THEIR WEBSITE ANDINFORMING STATIONS

RCC IS THE NODAL AGENCY FORINTERACTION WITH RLDC/REB FORSCHEDULING AND RELATED ACTIVITIES


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ACTIVITIES CARRIED OUT BY RCC CONTD.

CHECKING OF SCHEDULE FOR TECH.MINIMUM AND RAMP UP / DOWN (as per IEGCor INDIAN ELECTRICITY GRID CODE) AND

OTHER DISCREPANCIES AND TAKINGCORRECTIVE STEPSRECONCILIATION OF DC, SG, AG WITHSTATION AND RLDC AND FORWARDING THEDATA TO COMMERCIAL DEPTT.COMPILATION OF UI REPORTS RECEIVEDFROM STATIONS

PREPARATION OF VARIOUS MIS


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The generators to send their day ahead DC in prescribed format

by 9:00 hr. every day to RLDC through RCC

RLDC in turn communicates the same to constituents and theconstituents are required to send their requisition by 15:00 hr. toRLDC

RLDC prepares the injection and drawal schedule based on theabove and releases the same by 17:00 hr.

Constituents can revise their DC or drawal requirement andinform to RLDC and based on which RLDC issues the revisedschedule by 23:00 hr. This schedule subsequently undergoesrevision as per the ABT procedure already described. For thecurrent day, any of the above information can be got at any timeof the day.

SCHEDULING AS BEING FOLLOWED

Stations are declaring their max. Ex-bus DC = (Gross Capacity-Norm. APC)


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FORMAT AAVAILABILITY DECLARATION(EX BUS)

FROM SCE, RCC NOIDA TO SCE, NRLDCDECLARED CAPABILITY (EX BUS) OF DADRI COAL FOR DATE

MSG NO DTDC 0111R0 DATEOF ISSUE

REV NO TIME OF ISSUE

TOKEN NO unit DC TimeUnits anticipated on bar at 00.00 hrs of next day 4 765 0

Units to go under planned S/D during next day 0 0 0Units likely to return after S/D during next day 0 0 0

From To From To From To(Hrs) (Hrs) DC (Hrs) (Hrs) DC (Hrs) (Hrs) DC

00:00 00:15 765 08:00 08:15 765 16:00 16:15 765

00:15 00:30 765 08:15 08:30 765 16:15 16:30 765

00:30 00:45 765 08:30 08:45 765 16:30 16:45 765

00:45 01:00 765 08:45 09:00 765 16:45 17:00 765

01:00 01:15 765 09:00 09:15 765 17:00 17:15 765

01:15 01:30 765 09:15 09:30 765 17:15 17:30 765

01:30 01:45 765 09:30 09:45 765 17:30 17:45 765

01:45 02:00 765 09:45 10:00 765 17:45 18:00 765

02:00 02:15 765 10:00 10:15 765 18:00 18:15 765

02:15 02:30 765 10:15 10:30 765 18:15 18:30 765

02:30 02:45 765 10:30 10:45 765 18:30 18:45 765

02:45 03:00 765 10:45 11:00 765 18:45 19:00 765

03:00 03:15 765 11:00 11:15 765 19:00 19:15 765

03:15 03:30 765 11:15 11:30 765 19:15 19:30 765

03:30 03:45 765 11:30 11:45 765 19:30 19:45 765

03:45 04:00 765 11:45 12:00 765 19:45 20:00 765

04:00 04:15 765 12:00 12:15 765 20:00 20:15 765

04:15 04:30 765 12:15 12:30 765 20:15 20:30 765

04:30 04:45 765 12:30 12:45 765 20:30 20:45 765

04:45 05:00 765 12:45 13:00 765 20:45 21:00 765

05:00 05:15 765 13:00 13:15 765 21:00 21:15 765

05:15 05:30 765 13:15 13:30 765 21:15 21:30 765

05:30 05:45 765 13:30 13:45 765 21:30 21:45 765

05:45 06:00 765 13:45 14:00 765 21:45 22:00 765

06:00 06:15 765 14:00 14:15 765 22:00 22:15 765

06:15 06:30765

14:15 14:30765

22:15 22:30765

06:30 06:45 765 14:30 14:45 765 22:30 22:45 765

06:45 07:00 765 14:45 15:00 765 22:45 23:00 765

07:00 07:15 765 15:00 15:15 765 23:00 23:15 765

07:15 07:30 765 15:15 15:30 765 23:15 23:30 765

07:30 07:45 765 15:30 15:45 765 23:30 23:45 765

07:45 08:00 765 15:45 16:00 765 23:45 24:00 765TOTAL MWHR 18360

Remarks Ex bus DC includes: unit MW MWH0 0 0

The technical minimum loading is 80% of the MCR of units on bar Units in reserve S/D 0 0 0The Benefici aries may b e advised to Schedule their drawl c onsidering

the merit order of their own generation,

generation of IPPs , l icensees etc., and the s hare of the beneficiary i n ISGS.

The ramp up rate is 1 MW/Min/unit

SCE, RCC

01.11.04

0

01.11.04

0 1000


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SG REVISIONS FOLLOWING DC REVISIONSARE FOLLOWED UP BY RCC.

INITIALLY NRLDC WAS GIVING ONLY 5 TO 10

MINUTES FOR IMPLEMENTATION OF SGREVISIONS. HOWEVER, AFTER PERSUASIONHALF AN HOUR ADVANCE INFORMATIONABOUT SG REVISION IS GIVEN PRESENTLY.

THE NRLDC HOME PAGE DISPLAYS ANDUPDATE REVISION STATUS.



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THE IMPLEMENTED SCHEDULE ISDISPLAYED AFTER A LAPSE OF 2-3 DAYSON NRLDC WEBSITE

THE SAME IS CHECKED AND

DISCREPANCY, IF ANY, IS BROUGHT TOTHE NOTICE OF NRLDC

DISCREPANCIES FOR THE PERIOD

MONDAY TO SUNDAY ARE SORTED OUT BYNEXT WEDNESDAY

NRLDC FORWARDS DATA FOR THE

ABOVE PERIOD ON THURSDAY TO NREB



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PRESENT STATUS OF SCHEDULING

PRESENTLY, THE MINIMUM SG FOR COALSTATION IS 70% OF DC (AGREED IN 334 TH OCC).

UNITS ARE STOPPED IN CONSULTATION WITHNRLDC UNDER LOW DEMAND. FULL DC ISACCEPTED BY NRLDC AND SCHEDULE ISISSUED AS PER RUNNING UNITS.


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.

On completion of the operating day by 24:00 hr., the SG finallyimplemented during the day (taking into account all before-the-factchanges in despatch schedule of generating stations and drawalschedule of States) shall be issued by RLDC. This schedule shallbe the datum for commercial accounting. The average ex-buscapability for each ISGS (Inter State Generating Station) shall alsobe worked out based on all before -the- fact advice to RLDC.

The procedure for scheduling and the final schedule issued byRLDC, shall be open to all constituents for anychecking/verification for a period of 20 days. In case anymistake/omission is detected, the RLDC shall forthwith make acomplete check and rectify the same.

Stations are required to send the Special Energy Meter readings toRLDC every Monday. Based on DC, SG, AG data submitted byRLDC; weekly UI statement and monthly Regional EnergyAccounts (REA) are prepared by REB.


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REA ISSUED BY NREB

DC, SG & AG ARE RECONCILED WEEKLY WITH NRLDCAND INFORMED TO STATIONS. MINOR DISCREPANCIES(OF OUR INTEREST) ARE INGNORED.

RECONCILED FIGURES ARE INFORMED TO NCRCOMMERCIAL GROUP FOR FURTHER RECONCILIATIONWITH NREB, IF ANY, IN REA AND UI ACCOUNT.

THERE IS MIS-MATCH IN UI FIGURES GIVEN BY NREB ASCOMPARED TO STATION FIGURES . THIS APPEARS TOBE DUE TO THE DIFFERENCE IN STATION FREQ. ANDNREB REFERENCE FREQ.


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Metering / Da ta Coll ecti on / Billing

Data is downloaded from SEM through a handheld device which is then loaded to a PC.

A separate software in PC converts the rawdata into Excel Form by RLDC.

The processed data is then sent to REB for thepurpose of preparing REA.

RPSCl regional commercial deptt. collects REAfrom REB and raises bills based on the same toits beneficiaries inclusive of incentive payable,if any. Data is also available on website.


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Metering / Da ta Coll ecti on / Billing

REA prepared by REB contains followings:

Monthly and cumulative DC of each ISGS

Scheduled Energy from each ISGS to variousbeneficiaries

Bilateral and inter-regional exchange details

A separate weekly UI statement is issued byREB indicating UI payable and receivable

UI pool account is maintained by RLDC


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Evolution of Tariff

Pre-1992 period

Single part tariff considering the fuel cost and other costsassuming a certain level of minimum performance

Post-1992 period Two part tariff

a) Fixed charge (full recovery at specified level of performance)

b) Variable charge (fuel charge) including FPA (Fuel PriceAgreement)

December 2002 onwards (ABT) Three part tariff a) Capacity chargeb) Energy charge including FPA (schedule based)c) Unscheduled Interchange charge


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Comparison of Tariff Systems

Tariff before2001-02 Tariff after 2001-02Fixed Charges (F.C.) arelinked to Actual drawal

Fixed Charges are linked to theAvailability

50% F.C. ensured even at 0%PLF

Zero F.C. at zero availability

Full F.C. recovered at 62.49%PLF

Full F.C. recovered when T.A. isachieved (80%)

Incentive on PLF based onActual Generation

Incentive related to PLF based onScheduled Generation only

Incentive rate @1 paisa/kWhfor every 1% increase in PLFabove 68.49% PLF includingdeemed generation

21.5 paise/kWh for scheduled PLFabove 77% and up to 90% PLF onannual basis


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O&M charges to be 2.5%of current capital costescalated @10% per annum

Base level of O&M to beaverage of actual expenditurein last five years escalatedtwice at 10% to bring it to

1999-2000 level, the base levelto be escalated @6% per annum w.e.f. 1.4.2001

No provision for Developmental Surcharge 5% of the fixed charges to beadditionally billed as

Developmental Surcharge

Tariff before2001-02 Tariff after 2001-02


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Certifies deemed generation No such certification

Incentive billing as per actualdrawal

Incentive billing in the ratio of energyscheduled beyond target PLF

ROE = 16% ROE = 16%

Operational Norms Same norms for all operationalparameters except PLF andAvailability

Depreciation

Coal - 7.84%Gas - 8.24%

Depreciation

Coal - 3.6%Gas - 6.0%

All tax on Income includingIncentive is pass-through

Existing system to continue

Fuel risk generally passed onto beneficiaries Fuel risk with NTPC

Tariff before2001-02 Tariff after 2001-02


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Provisions as on 31.03.04 Provisions from 01.04.046 Scheduled PLF for

incentive 77 Scheduled PLF for incentive 80

7 Incentive rate 50% of thefixed charge/unit subject tomax. 2 1.5 p/kWh up to 90%,half of that for PLF above90%

Incentive rate 25 p/k h for PLF above80

8 Specific oil consumption:3.5 ml/k h

Specific oil consumption:2.0 ml/k h

9 Debt equity ratio 50:50 Debt equity ratio 70:30Where equity employed is more than30%, the amount of equity for determination of tariff shall be limitedto 30% and the balance amount shallbe considered as the normative loan(modified now)

10 Return on equity 16 Return on equity 14

11 Transit loss of coal:No norms

Transit loss of coal:Pit head: 0.3 , rail fed: 0.8


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Provisions as on 31.03.04 Provisions from 01.04.0412 0&M Cost

For 2000 -2001: Average actual

cost from 1995-2000, twiceescalated at 10 ; for 2000-01onwards 6 escalation everyyear

0&M CostBased on normative Rs./M

escalated @ 4 every year from2005-06For 2004-05Gas 200 M 500 M5.2 10.4 9.36

13 DepreciationStraight-line depreciation up to

90 considering different lifefor different components

DepreciationStraight-line depreciation up to

90 considering different life fordifferent components14 Auxiliary power

200 M 9.5500 M 8.0GAS 3 (C/C), 1 (O/C)

Auxiliary power200 M 9.0500 M 7.5GAS 3 (C/C), 1 (O/C)


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Provisions as on 31.0304 Provisions from 01.04.0415 Heat Rate

Coal200 M 2500500M 2500Gas C/C O/CAnta 2100 3150Auraiya 2125 3190Dadri 2100 3150Fbad 2000 2900Kkulam 2000 2900Kawas 2100Gandhar 2125

Heat RateCoal200 M 2500500M 2450Gas C/C O/CAnta 2075 3010Auraiya 2100 3045Dadri 2075 3010Fbad 2000 2900Kkulam 2000 2900Kawas 2075 3010Gandhar 2000 2900

16 UI rate: 0 to 420 p/k hFor freq. 50.5 Hz to 49.02 Hz

No UI for generation above DC

UI rate: 0 to 600 p/k h (up to 30.09.04)For freq. 50.5 Hz to 49.02 Hz

Generation above DC up to 5 in ablock subject to 1 in a day qualifies for

UI17 Development Surcharge

Provision for billing 5 CapacityCharge as DevelopmentSurcharge

Development SurchargeNo provision for Development Surcharge


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Availability' in re la tion to a therm al gener a ting st a tion f or a ny peri od me a nsthe av er a ge of the da ily av er a ge Dec la re d Ca pa cities ( DC) f or all the da ysdu ring th a t peri od expresse d a s a percent a ge of the inst alle d ca pa city of the

gener a ting st a tion min us n orma tive au xilia ry cons umpti on in MW, a nd sh allbe c omp ute d in a cc or da nce with the f ollowing f orm ula:

NAvailability = 10000 x DC i / {N x IC x (100-AUX n)} %

i=1

where

IC = Inst alle d Ca pa city of the gener a ting st a tion in MW,DC i = Aver a ge Dec la re d Ca pa city f or the ith da y of the peri od in MW,N = Number of da ys du ring the peri od , a nd

AUXn = Norma tive Auxilia ry Energy Co ns umpti on a s a percent a ge of gr ossgener a tion

Declared Capacity or DC' me a ns the c a pab ility of the gener a ting st a tion to d e liver ex- bu s e lectricity in MW dec lare d b y s uch gener a ting st a tion in re lation to a ny peri odof the da y or whole of the da y, dul y tak ing int o a cc ou nt the ava ilab ility of f ue l.


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Total Ca pa city Cha rges pa yabl e to the therm al power gener a ting comp a ny f or the :1st month = (1x ACC1)/122nd month = (2x ACC2 - 1x ACC1)/123r d month = (3x ACC3 - 2x ACC2)/124th month = (4x ACC4 - 3x ACC3)/125th month = (5x ACC5 - 4x ACC4)/126th month = (6x ACC6 - 5x ACC5)/127th month = (7x ACC7 - 6x ACC6)/128th month = (8x ACC8 - 7x ACC7)/129th month = (9x ACC9 - 8x ACC8)/1210 th month = (10 x ACC10 - 9x ACC9)/1211 th month = (11 x ACC11 - 10 x ACC10)/1212 th month = (12 x ACC12 - 11 x ACC11)/12

where

ACC1 , ACC2 , ACC3 , ACC4 , ACC5 , ACC6 , ACC7 , ACC8 , ACC9 , ACC10 , ACC11a nd ACC12 a re the a mou nt of Ann ual Ca pa city Cha rge c orresp onding to Ava ilab ility f or the c umula tive peri od u p to the en d o f 1st, 2nd, 3r d, 4th, 5th, 6th,7th, 8th, 9th, 10 th, 11 th a nd 12 th m onth respecti ve ly.


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RCC SET UPT ER ET E T R U P

R P S C S ER ER

ES S E E T R T U S T EST R S ER

E T E T RR R C C C S S T E

availability based tarrif

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