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BACKGROUND:-
ECC Virginia Consultants, appointed by Govt. of India
and Asian Development Bank to study “Bulk Power andTransmission Tariff and Regulation” recommended for a
shift from PLF to availability based scenario in order to
improve discipline in Power Sector in the year 1994.
CERC (Central Electricity Regulatory Commission) was
constituted through Indian Electricity Regulatory Act
1998.
CERC issued order for implementation of ABT w.e.f.1.4.2000 in Northern Region (NR) and accordingly
issued the ABT order dtd. 4.1.2000. Implementation of
ABT got delayed due to various petitions by constituents.
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THE 128TH NREB BOARD MEETING ON 16.09.02
DECIDED TO IMPLEMENT ABT IN NR W.E.F.01.12.02 WITH FULL COMMERCIAL
MECHANISM.
THE SCHEDULING OF NCR STATIONS HAD
BEEN DONE AS PER ABT PROVISION SINCE
01.08.01 WITHOUT COMMERCIAL MECHANISM.
REAL TIME SCHEDULING ACTIVITY WAS
ALREADY TAKEN OVER BY RCC (REGIONAL
CONTROL 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 Charges • Return on Equity
• Depreciation
• O&M Charges
• Interest on Working Capital
• Interest on Loan• Taxes on Income, if any
Energy Charges • Cost of Primary Fuel (Coal, Gas)
• Cost of Secondary Fuel
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Working Capital
• O&M expenses for one month
• Coal cost for two months for non-pit head
stations corresponding to Target Availability
(T.A.)• 60 days stock of secondary fuel oil
corresponding 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 average
billing calculated on T.A.
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AVAILABILITY BASED TARIFF (ABT)
Capacity Charge payable based on Declared
Capability (DC)
Energy Charge realised on Scheduled Generation
(SG) and not on actual generation i.e. variable
charge payable on commitment from constituent
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 be
accounted for through Unscheduled Interchange (UI)
Charges. UI for a generating station shall be equal to its
actual generation minus its scheduled generation. UI for abeneficiary shall be equal to its total actual drawal minus
its total scheduled drawal. UI shall be worked out for each
15-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 6.0 paise/kWh in the
50.5-49.8 Hz frequency range, and to 9.0 paise/kWh in the
49.8-49.0 Hz frequency range)
Applicable rates with effect from 1.10.2004:
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UI CHART
0
200
400
600
48.5 49 49.5 50 50.5
FREQUENCY
U I R A T
E
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Frequency UI rate Frequency UI rate Frequency UI rate Frequency UI rate
50.50 0 50.12 114 49.74 237 49.36 408
50.48 6 50.10 120 49.72 246 49.34 417
50.46 12 50.08 126 49.70 255 49.32 426
50.44 18 50.06 132 49.68 264 49.30 435
50.42 24 50.04 138 49.66 273 49.28 444
50.40 30 50.02 144 49.64 282 49.26 453
50.38 36 50.00 150 49.62 291 49.24 462
50.36 42 49.98 156 49.60 300 49.22 47150.34 48 49.96 162 49.58 309 49.20 480
50.32 54 49.94 168 49.56 318 49.18 489
50.30 60 49.92 174 49.54 327 49.16 498
50.28 66 49.90 180 49.52 336 49.14 507
50.26 72 49.88 186 49.50 345 49.12 516
50.24 78 49.86 192 49.48 354 49.10 52550.22 84 49.84 198 49.46 363 49.08 534
50.20 90 49.82 204 49.44 372 49.06 543
50.18 96 49.80 210 49.42 381 49.04 552
50.16 102 49.78 219 49.40 390 49.02 561
50.14 108 49.76 228 49.38 399 49.00 570
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MERITS OF ABT
• ECONOMIC GENERATION• MERIT ORDER DESPATCH
• GRID DISCIPLINE
• GENERATION RELATED TO THE
NEEDS OF THE GRID
• ADHERENCE 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 generating
station to deliver ex-bus MWh for each time block of the
day. 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 shall
ensure that their DC during peak hours is not less thanthat during other hours. However, exception to this rule
shall 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 shall
communicate their shares to beneficiaries out of which
they shall give their requisitions.
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Based on the requisitions given by beneficiaries and taking
into account technical limitations on varying the generation
and also taking into account the transmission system
constraints, if any; RLDC shall prepare the economically
optimal generation schedule and drawal schedule and
communicate the same to generator and beneficiaries.
RLDC shall also formulate the procedure for meeting
contingencies both in the long run and in the short run.
All the scheduled generation and actual generation shall be
at the generator’s ex-bus. For beneficiaries, the scheduled
and 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 Sent
Out ex-bus from the generating station.
In case of forced outage of a unit, RLDC will revise the SG
on the basis of revised DC. The revised SG will become
effective 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 from
the 4th time bock.
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In the event of bottleneck in evacuation of power due to
any constraint, outage, failure or limitation in thetransmission system, associated switchyard and
substat ions owned by CTU (as certified by RLDC)
necessitating reduction in generation; RLDC will revise the
schedules which 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 such
an 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 be
equal to their actual drawals.
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In case of any Grid Disturbance, SG of all Generating
Stations and Scheduled Drawal of all beneficiaries shall be
deemed to have been revised to be equal to their AG/Drawal for all time blocks affected by the Grid
Disturbance. Certification of Grid Disturbance and its
duration shall be done by RLDC.
Revision of DC by generator(s) and requisition by
beneficiary(ies) for the remaining period of the day will also
be 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 revision
has been received in RLDC to be the first one.
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If, at any point of time, RLDC observes that there is need
for revision of schedules in the interest of better system
operation, it may do so on its own and in such cases, therevised schedules shall become effective from the 4th
time block, counting the time block in which the revised
schedule is issued by RLDC to be the first one.
Generation schedules and drawal schedules
issued/revised by RLDC shall become effective from
designated time block irrespective of communication
success.
For any revision of SG, including post facto deemed
revision, there shall be a corresponding revision of
scheduled drawals of beneficiaries.
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A procedure for recording the communication regarding
changes to schedules duly taking into account the timefactor shall be evolved by CTU.
In case of a generat ing s tat ion, contract ing to supp ly
power only to the State in which i t is located; the
schedul ing , meter ing and energy accoun t ing shall be
carr ied out by the respective State Load Despatch
Centre.
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(i) Any generation up to 105% of DC in any 15-minute time
block 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 investigate
so as to ensure that there is no gaming, and if gaming is
found by the RLDC, the corresponding UI charges due to
the generating station on account of such extra
generation shall be reduced to zero and the amount shall
be 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 demonstrate
the DC of its generating station as and when asked by the
RLDC of the region in which the generating station issituated. In the event of the generating company failing to
demonstrate the DC, the capacity charges due to the
generator shall be reduced as a measure of penalty.
The quantum of penalty for the first mis-declaration for any
duration/block in a day shall be the charges correspondingto two days fixed charges. For the second mis-declaration
the 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 be
available for review by the Regional Electricity Board.
These books shall keep record of machine operation and
maintenance.
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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 a
block and up to 101% of DC over a day) during
low 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 AND
REVISIONS THEREOF FROM STATIONS
COMMUNICATING DAY AHEAD DC AND
REVISIONS TO RLDC, ALSO ENSURING ITS
TIMELY IMPLEMENTATION
OBTAINING SCHEDULE AND REVISIONS
FROM RLDC OR THEIR WEBSITE AND
INFORMING STATIONS
RCC IS THE NODAL AGENCY FORINTERACTION WITH RLDC/REB FOR
SCHEDULING 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 IEGC
or INDIAN ELECTRICITY GRID CODE) AND
OTHER DISCREPANCIES AND TAKINGCORRECTIVE STEPS
RECONCILIATION OF DC, SG, AG WITH
STATION AND RLDC AND FORWARDING THE
DATA TO COMMERCIAL DEPTT.
COMPILATION OF UI REPORTS RECEIVED
FROM 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 the
constituents are required to send their requisition by 15:00 hr. toRLDC
RLDC prepares the injection and drawal schedule based on the
above and releases the same by 17:00 hr.
Constituents can revise their DC or drawal requirement and
inform to RLDC and based on which RLDC issues the revised
schedule by 23:00 hr. This schedule subsequently undergoes
revision as per the ABT procedure already described. For the
current day, any of the above information can be got at any time
of the day.
SCHEDULING AS BEING FOLLOWED
Stations are declaring their max. Ex-bus DC = (Gross Capacity-
Norm. APC)
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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 PERSUASION
HALF AN HOUR ADVANCE INFORMATION
ABOUT SG REVISION IS GIVEN PRESENTLY.
THE NRLDC HOME PAGE DISPLAYS AND
UPDATE REVISION STATUS.
SCHEDULING AS BEING FOLLOWED
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THE IMPLEMENTED SCHEDULE IS
DISPLAYED 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 BY
NEXT WEDNESDAY
NRLDC FORWARDS DATA FOR THE
ABOVE PERIOD ON THURSDAY TO NREB
SCHEDULING AS BEING FOLLOWED
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PRESENT STATUS OF SCHEDULING
• PRESENTLY, THE MINIMUM SG FOR COALSTATION IS 70% OF DC (AGREED IN 334TH OCC).
UNITS ARE STOPPED IN CONSULTATION WITH
NRLDC UNDER LOW DEMAND. FULL DC IS
ACCEPTED BY NRLDC AND SCHEDULE IS
ISSUED AS PER RUNNING UNITS.
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•
.
On completion of the operating day by 24:00 hr., the SG finally
implemented during the day (taking into account all before-the-fact
changes in despatch schedule of generating stations and drawal
schedule of States) shall be issued by RLDC. This schedule shall
be the datum for commercial accounting. The average ex-bus
capability for each ISGS (Inter State Generating Station) shall also
be worked out based on all before -the- fact advice to RLDC.
The procedure for scheduling and the final schedule issued by
RLDC, shall be open to all constituents for anychecking/verification for a period of 20 days. In case any
mistake/omission is detected, the RLDC shall forthwith make a
complete check and rectify the same.
Stations are required to send the Special Energy Meter readings to
RLDC every Monday. Based on DC, SG, AG data submitted by
RLDC; weekly UI statement and monthly Regional Energy
Accounts (REA) are prepared by REB.
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Metering / Data Collection / Billing
• Data is downloaded from SEM through a hand
held device which is then loaded to a PC.
• A separate software in PC converts the raw
data into “Excel Form” by RLDC.
• The processed data is then sent to REB for the
purpose of preparing REA.
• NTPC regional commercial deptt. collects REA
from REB and raises bills based on the same to
its beneficiaries inclusive of incentive payable,
if any. Data is also available on website.
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Metering / Data Collection / 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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PRE-REQUISITE / INFRASTRUCTURE
REQUIREMENT FOR ABT
Reliable and dedicated voice & data communication link
between BTPS, RLDC / SLDC & RCC.
Installation of special energy meters for recording the
system parameters at a specified time interval (15-minute)
System for certification of DC, preparation of energyaccount and UI
Metering scheme to be jointly approved
Scheduling/operating rules/guidelines to be finalised with
SLDCMode of communication (for transmission of DC/SG)
between SLDC and RCC/BTPS.
Dedicated hardware in control room
Software for comparing SG vs AG on real time basis
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Evolution of Tariff
Pre-1992 period
Single part tariff considering the fuel cost and other costs
assuming a certain level of minimum performance
Post-1992 period Two part tari ff
a) Fixed charge (full recovery at specified level of performance)
b) Variable charge (fuel charge) including FPA (Fuel Price
Agreement)
December 2002 onwards (ABT) Three part tar i ff
a) Capacity charge
b) Energy charge including FPA (schedule based)
c) Unscheduled Interchange charge
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Comparison of Tariff Systems
Tariff before2001-02 Tariff after 2001-02
Fixed 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 on
Actual Generation
Incentive related to PLF based on
Scheduled Generation only
Incentive rate @1 paisa/kWhfor every 1% increase in PLF
above 68.49% PLF including
deemed generation
21.5 paise/kWh for scheduled PLFabove 77% and up to 90% PLF on
annual basis
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Comparison of Tariff Systems
O&M charges to be 2.5%of current capital cost
escalated @10% per
annum
Base level of O&M to beaverage of actual expenditure
in last five years escalated
twice 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 Surcharge5% of the fixed charges to be
additionally billed as
Developmental Surcharge
Tariff before2001-02 Tariff after 2001-02
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Comparison of Tariff Systems
Certifies deemed generation No such certification
Incentive billing as per actual
drawal
Incentive billing in the ratio of energy
scheduled beyond target PLF
ROE = 16% ROE = 16%
Operational Norms Same norms for all operational
parameters except PLF and
Availability
Depreciation
Coal - 7.84%Gas - 8.24%
Depreciation
Coal - 3.6%Gas - 6.0%
All tax on Income including
Incentive 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 01.04.04Where tariff has been determinedthrough transparent process of biddingin accordance with guidelines issued bythe Central Government, the
Commission shall adopt such tariff inaccordance with provisions of the Act
1 Target availability = 80% Target availability = 80%
2 DC cannot be more than
Installed CapacityThere is no such provision
3 Capital expenditure
includes reasonableamount of capitalised
spares
Capital expenditure includes amount of
capitalised spares as % of originalproject cost as follows:
Coal 2.5% Gas 4.0%
4 PLF = kWh generated /
kWh at Installed Capacity
PLF = kWh sent out / kWh sent out
corresponding to Installed Capacity
5 Auxiliary power = (Gross
energy – Energy delivered
at switchyard)
Auxiliary power = (Energy consumed
by auxiliaries + transformer losses
within the station)
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Provisions as on 31.03.04 Provisions from 01.04.04
6 Scheduled PLF for
incentive = 77%
Scheduled PLF for incentive = 80%
7 Incentive rate 50% of the
fixed charge/unit subject tomax. 21.5 p/kWh up to 90%,
half of that for PLF above
90%
Incentive rate 25 p/kWh for PLF above
80%
8 Specific oil consumption:
3.5 ml/kWh
Specific oil consumption:
2.0 ml/kWh
9 Debt equity ratio = 50:50 Debt equity ratio = 70:30
Where 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 01.04.04
12 0&M Cost
For 2000 -2001: Average actual
cost from 1995-2000, twice
escalated at 10%; for 2000-01onwards 6 % escalation every
year
0&M Cost
Based on normative Rs./MW
escalated @ 4% every year from
2005-06For 2004-05
Gas 200 MW 500 MW
5.2 10.4 9.36
13 Depreciation
Straight-line depreciation up to
90% considering different life
for different components
Depreciation
Straight-line depreciation up to
90% considering different life for
different components14 Auxiliary power
200 MW 9.5%
500 MW 8.0%
GAS 3% (C/C), 1% (O/C)
Auxiliary power
200 MW 9.0%
500 MW 7.5%
GAS 3% (C/C), 1% (O/C)
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Provisions as on 31.0304 Provisions from 01.04.04
15 Heat Rate
Coal
200 MW 2500
500MW 2500Gas C/C O/C
Anta 2100 3150
Auraiya 2125 3190
Dadri 2100 3150
F’bad 2000 2900
K’kulam 2000 2900
Kawas 2100Gandhar 2125
Heat Rate
Coal
200 MW 2500
500MW 2450Gas C/C O/C
Anta 2075 3010
Auraiya 2100 3045
Dadri 2075 3010
F’bad 2000 2900
K’kulam 2000 2900
Kawas 2075 3010Gandhar 2000 2900
16 UI rate: 0 to 420 p/kWh
For freq. 50.5 Hz to 49.02 Hz
No UI for generation above DC
UI rate: 0 to 600 p/kWh (up to 30.09.04)
For freq. 50.5 Hz to 49.02 Hz
Generation above DC up to 5% in a
block subject to 1% in a day qualifies for
UI17 Development Surcharge
Provision for billing 5% Capacity
Charge as Development
Surcharge
Development Surcharge
No provision for Development Surcharge
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‘Availability' in relation to a thermal generating station for any period means
the average of the daily average Declared Capacities (DC) for all the days
during that period expressed as a percentage of the installed capacity of the
generating station minus normative auxiliary consumption in MW, and shall
be computed in accordance with the following formula:
N
Availability = 10000 x DCi / {N x IC x (100-AUXn)} %
i=1
where
IC = Installed Capacity of the generating station in MW,
DCi = Average Declared Capacity for the ith day of the period in MW,
N = Number of days during the period, and
AUXn = Normative Auxiliary Energy Consumption as a percentage of grossgeneration
‘Declared Capacity’ or ‘DC' means the capability of the generating station to deliver
ex-bus electricity in MW declared by such generating station in relation to any period
of the day or whole of the day, duly taking into account the availability of fuel.
‘Plant Load Factor' or 'PLF' for a given period, means the total sent out
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g p ,
energy corresponding to scheduled generation during the period, expressed
as a percentage of sent out energy corresponding to installed capacity in that
period and shall be computed in accordance with the following formula:
N
PLF = 10000 x SGi / {N x IC x (100-AUXn) }%
i=1
where,
IC = Installed Capacity of the generating station in MW,SGi= Scheduled Generation in MW for the ith time block of the period,
N = Number of time blocks during the period, and
AUXn = Normative Auxiliary Energy Consumption as a percentage of gross
generation
T l C i Ch bl h h l i f
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Total Capacity Charges payable to the thermal power generating company for
the:
1st month = (1xACC1)/12
2nd month = (2xACC2 - 1xACC1)/12
3rd month = (3xACC3 - 2xACC2)/124th month = (4xACC4 - 3xACC3)/12
5th month = (5xACC5 - 4xACC4)/12
6th month = (6xACC6 - 5xACC5)/12
7th month = (7xACC7 - 6xACC6)/12
8th month = (8xACC8 - 7xACC7)/12
9th month = (9xACC9 - 8xACC8)/1210th month = (10xACC10 - 9xACC9)/12
11th month = (11xACC11 - 10xACC10)/12
12th month = (12xACC12 - 11xACC11)/12
where
ACC1, ACC2, ACC3, ACC4, ACC5, ACC6, ACC7, ACC8, ACC9, ACC10, ACC11and ACC12 are the amount of Annual Capacity Charge corresponding to
‘Availability’ for the cumulative period up to the end of 1st, 2nd, 3rd, 4th, 5th, 6th,
7th, 8th, 9th, 10th, 11th and 12th month respectively.
RCC SET UP
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S. NO. PARTICULARS AVAILABILITY REMARKS
1 MANPOWER 2IN EACH SHIFT E5 --- 1 NO.
E2/E3 -- 1 NO.
2 PC 3 P3
3 FAX MACHINE 2 PC LINKED
4 VOICE RECORDER 1
5 BSNL PHONE 3 1 NO. DEDICATED
FOR FAX6 SATCOM 2 1 NO. DEDICATED
FOR FAX
7 RAX 1
8 HOTLINE TO RLDC 1
9 INTERNET AVAILABLE THRO' DIAL UP &
NTPC SERVER
10 MESSAGING/FILE AVAILABLE THRO' LOTUS NOTE
TRANSFER