btps abt-R

7/28/2019 btps abt-R

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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.



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.



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.



COMPONENTS OF ABT

CAPACITY CHARGES

ENERGY CHARGES

UNSCHEDULED INTERCHANGES

INCENTIVE



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



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.



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)



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.



(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:



UI CHART

0

200

400

600

48.5 49 49.5 50 50.5

FREQUENCY

U I R A T

E



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



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



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.



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.



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.



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.



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.



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.



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.



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.



(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.



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.



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



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



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



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



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)



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.




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




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.



•

.

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.



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.



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



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



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



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




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





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




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)



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%



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)



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



‘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



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



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




9th month = (9xACC9 - 8xACC8)/1210th month = (10xACC10 - 9xACC9)/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



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

btps abt-R

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