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1 ANNEXURE – 2 PROGRESS OF ALL NEW UPCOMING POWER STATIONS 1.0 Expected date of commissioning committed by the contractors during the CS Review meeting on 11.01.2013 is furnished below. Sl.No Name of the Project Sector Capacity ( in MW) Scheduled date Earlier commitment made by the contractors & indicated in the previous report to TNERC. Expected date of commissioning. Contractor 1 Mettur Thermal Power Project - Stage 3 ( MTPP) ( 1x 600 MW) State 600 23/09/11 Dec 2012 March 2013 M/s.BGRESL 2 North Chennai Thermal Power Project – Stage-II ( 2x600 MW) State 1200 Unit–II - 16/11/11 Unit –I - 18/05/11 Unit-II Dec 2012 Unit-I March 2013 Unit-II March 2013(FL) (COD - April 2013) Unit-I April 2013(FL) (COD- May 2013) M/s.BHEL 3 NTPC TNEB JV Project (NTECL) at Vallur (3x 500MW) ( Share 75 % ) Joint Venture 1500 (Share- 1125) Unit-I –12/10/10 Unit-II-12/03/11 Unit-III- 27/09/12 Unit-I Nov 2012 Unit-II Jan 2013 Unit III July 2013 Unit-I - COD declared on 29.11.2012 Unit-II February 2013 Unit III October 2013 NTPC TNEB JV ( NTECL) Sub- Contractor – for NTPC -M/s. BHEL 4 NLC TNEB JV Project (NTPL) at Tuticorin (2 X 500 MW) (Share 38.7 %) Joint Venture 1000 (Share 387) Unit-I – 28.03.March’12 Unit –II – Aug’12 Unit-I June 2013 Unit II July 2013 Unit-I December 2013 Unit II March 2014 NLC TNEB JV( NTPL) Sub- Contractor- for NLC -M/s. BHEL
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Page 1: Annexures TNERC

1

ANNEXURE – 2

PROGRESS OF ALL NEW UPCOMING POWER STATIONS

1.0 Expected date of commissioning committed by the contractors during the CS Review meeting on 11.01.2013 is furnished below.

Sl.No Name of the Project

Sector Capacity ( in MW)

Scheduled date

Earlier commitment made by the contractors & indicated in the previous report to TNERC.

Expected date of commissioning.

Contractor

1 Mettur Thermal Power Project - Stage 3 ( MTPP) ( 1x 600 MW)

State 600 23/09/11 Dec 2012 March 2013 M/s.BGRESL

2 North Chennai Thermal Power Project – Stage-II ( 2x600 MW)

State 1200 Unit–II -16/11/11 Unit –I -18/05/11

Unit-II Dec 2012 Unit-I March 2013

Unit-II March 2013(FL) (COD - April 2013) Unit-I April 2013(FL) (COD- May 2013)

M/s.BHEL

3 NTPC TNEB JV Project (NTECL) at Vallur (3x 500MW) ( Share 75 % )

Joint Venture

1500 (Share-1125)

Unit-I –12/10/10 Unit-II-12/03/11 Unit-III-27/09/12

Unit-I Nov 2012 Unit-II Jan 2013 Unit III July 2013

Unit-I - COD declared on 29.11.2012 Unit-II February 2013 Unit III October 2013

NTPC TNEB JV ( NTECL) Sub- Contractor – for NTPC -M/s. BHEL

4 NLC TNEB JV Project (NTPL) at Tuticorin (2 X 500 MW) (Share 38.7 %)

Joint Venture

1000 (Share 387)

Unit-I – 28.03.March’12 Unit –II – Aug’12

Unit-I June 2013 Unit II July 2013

Unit-I December 2013 Unit II March 2014

NLC TNEB JV( NTPL) Sub- Contractor- for NLC -M/s. BHEL

Page 2: Annexures TNERC

2

2.0 The Present status of power plants where the anticipated date of commissioning was

committed as November 2012 & December 2012 in the previous report submitted to

Hon’ble TNERC is detailed below:

2.1 Mettur Thermal Power Station Stage 3 (1 x 600 MW)

The EPC cost of the project is Rs.3100.06 crores. The work was awarded to M/s

BGR Energy Systems Ltd and commenced on 25.06.2008. The project is to be

commissioned by September 2011 as per the Contract Schedule. However, there is a

slippage. Due to the delay in Coal handling, Ash Handling, Milling System and Bunkers

Erection, etc., the commissioning is delayed. In order to facilitate the Commissioning,

the Contract has been extended up to 23.12.2012 and further extension upto 31.3.13 is

underway.

So far 87% of works have been completed. Unit Synchronized with oil on

04.05.2012.Full load with 608 MW was achieved on 11.10.12 and the initial operation of

the unit was under progress from 23.11.12 to 04.12.12. Unit load was being maintained

at 350- 500 MW till 04.12.12. The unit was under forced shut down from 04.12.12 to

attend to few technical problems that were encountered during the period of initial

operation. On completion of entire Coal Handling System and Ash Handling system the

unit is expected to be commissioned with full load on sustained basis by March 2013 as

committed by M/s.BGRESL during the Chief Secretary’s review meeting on 11.01.13.

2.2 North Chennai Thermal Power Station stage II (2X600MW) UNIT 2- 600 MW:

The EPC cost of the project is Rs.2175 crores. This work also has been awarded

to M/s.BHEL and commenced on 16.8.2008. The project should have been commissioned

in November 2011 as per Schedule. At present, Coal Handling System, Cooling water

system, Ash handling system etc are under progress.

So far 92% of works have been completed. 400 KV GIS switchyard was commissioned

on 09.12.12. The unit has been synchronized with grid on 17.12.2012 and reached 101

MW (with oil). The boiler has been lit up for coal firing on 19.01.13. Safety valve floating

is under progress. Sustained generation of 250 MW to 300 MW is expected from

30.01.2013. As committed by M/s.BHEL during the Chief Secretary’s review meeting on

11.01.13, sustained full load generation of 600 MW is expected from 31.03.13 after

completion of entire Coal Handling System & Ash Handling System.

Page 3: Annexures TNERC

3

2.3 1500 MW (3 x 500 MW) thermal power project Joint venture with

National Thermal Power Corporation, at Vallur in Thiruvallur District: Unit I

Total cost of the project (3X 500 MW) is Rs.8444 crores. Works commenced on 13.8.07

for Unit 1. Main plant works for all three units have been awarded to M/s. BHEL. Unit I

was synchronized on 09.03.2012 and full load reached on 28.03.12. COD was declared

on 29.11.12. Unit is generating about 300-350 MW after attending to a few teething

problems that were encountered during trial operation. Sustained generation of 500 MW

could not be achieved in January 2013 due to the problems in cooling water system & ID

fan. Further, sufficient coal stock is also not available since NTECL have not signed Fuel

Supply Agreement with Coal India Limited for want of clearance from NTPC. Generation

of 500 MW on sustained basis is expected to be achieved in February 2013.

Page 4: Annexures TNERC

Sl.No Name of the Linelength in

C.Kms

Total

Loc Nos.

Stub

setting

Tower

erection

Line stringing

/Total length

in CKM.

Programme for completion

I NCTPS-Stage -II (2x600 MW)

1

Erection of 400 KV MC line from

NCTPS stage II to -Alamathy 400

KV SS (Two circuits to be

terminated at Alamathy SS & the

other two circuits to be

terminated at the tapping point to

SV Chatram near Alamathy SS)

168 114 114 111 128.0

Right of Way issues involved in 3 locations in the

land belonging to M/s Venkatesh Coke & Power

Ltd., The company has filed Writ Petition in the High

Court/Chennai The High Court/Chennai directed

TANTRANSCO to make an application before the

District Majistrate (District Collector/Thiruvallur) with

directions to the District Collector to pass orders on

or before 10.06.011 and the orders passed on

18.5.2012 rejecting the request of TANTRANSCO to

enter upon the petitioners land meaning that the

line has to be deviated from the original approved

route.In this regard,District Collector/Tiruvallur has

been addressed by Chief Secretary to review and

recosider the judgment .Mean while, Writ Appeal

has been filed in the High Court /Chennai against

the Order passed by the District

Collector/Thiruvallur and interim injunction has

been granted for 4 weeks. Also to resolve the issues

in power evacuation lines, a meeting was conducted

by the Chief Secretary to Govt. on 31.08.12 with

TANTRANSCO and concerned District Collectors.

High court case last hearing was held on 16.11.12

and Judgement pronounced in favor of

TANTRANSCO

2

Erection of 400 KV MC from

Alamathy 400 KV SS to

Sunguvarchatram 400 KV SS (Two

circuits from Alamathy SS to SV

Chatram & two circuits from the

tapping point (near Alamathy SS )

to SV Chatram)

188 160 145 123 99.9

Stub setting pending at 17 locations due to Court

case and other ROW issues and tower erection

pending at 19 locations due to Court case and other

ROW issues.

ANNEXURE 3

STATUS & PROGRAMME OF POWER EVACUATION SCHEMES OF GENERATION PROJECTS AS ON 20.11.12

Page 5: Annexures TNERC

Sl.No Name of the Linelength in

C.Kms

Total

Loc Nos.

Stub

setting

Tower

erection

Line stringing

/Total length

in CKM.

Programme for completion

II MTPS STAGE-III (1x600 MW)

3Erection of 400 KV DC line from

MTPS to ARASUR 400 KV SS280 324 317 315 210.75

Writ Appeal filed in High Court/Chennai, dismiised

on 16.11.12. Court directed TANTRANSCO to

proceed with the work in originally proposed route.

Supreme Court ordered in favor of TANGEDCO

III NTPC Vallur JV (3x500 MW)

4

Erection of 400 KV DC link line on

DC towers from Vallur JV TPS to

NCTPS Stage II.

7.06 14 14 14 7.1 Line work completed.

IVBHAVANI KATTALAI BARRAGE-

II (2x15 MW)

5110KV DC line from Bhavani

Kattalai Barrage-II-common point16.42 69 62 62 7.1 Energised on 23.08.12.

6110KV DC line from common point

to Thiruchenkode SS9.127 40 40 40 9.127 Energised on 23.08.12

7110KV DC line from common point

to Pallipalayam SS2.155 7 7 7 2.16 Energised on 23.08.12

Unit I syncronised and run for 1 hour on partial load of 2 MW on 28.07.11.

Page 6: Annexures TNERC

Sl.No Name of the Linelength in

C.Kms

Total

Loc Nos.

Stub

setting

Tower

erection

Line stringing

/Total length

in CKM.

Programme for completion

VBHAVANI KATTALAI BARRAGE-

III (2x15 MW)

8

110KV SC line from Bhavani

Kattalai Barrage-III-common

point

5.86 13 13 13 5.86 Energised on 13.08.12

9110KV SC line from common point-

Nallur10.26 36 36 36 10.30 Energised on 13.08.12

10110KV SC line from common point-

BKB-II15.01 30 30 30 15.01 Work under progress.

VIBHAVANI BARRAGE-I (2x5

MW)

11

LILO OF 110 KV Pykara-

Mettupalayam line at Bhavani

Barrage-I

5.5 22 22 22 11/11

Line work completed. Linking with the take off

structure will be taken up on completion of switch

yard works.

VIIBHAVANI BARRAGE-II (2x5

MW)

12

LILO OF 110 KV Mettupalayam -

Irumborai line at Bhavani Barrage-

II

3.87 12 12 12 0.86 Energised on 14.09.12

VIIINLC -THOOTHUKUDI JV

(2x500 MW)

13LILO of 230 KV TTPS-TTN at

NTPL JV0.78 6 6.00 6.00 0.78 Energised on 13.08.12

Page 7: Annexures TNERC

ANNEXURE 4

ENERGY AUDIT

As per the provisions made available in the EC Act 2001, the State Designated

Agency (SDA) i.e the Tamil Nadu Electrical Inspectorate (TNEI) has been nominated by

Bureau of Energy Efficiency (BEE) in consultation with GoTN to carry out the schemes

on energy Conservation and other allied activities in the state of Tamil Nadu such as

creating Database, Policy formulation, Annual reports review, Awareness creation on

energy conservation and Safety measures, conducting energy audits for Designated

Consumers, capacity building and to co-ordinate, regulate and enforce the provisions of

the Act.

TANGEDCO as such could not insist for energy audit among industries /

commercial establishments on its own.

GoTN had already been addressed in this regard.

However the TANGEDCO Board has initiated all possible steps in all Thermal &

Gas Power Plants of TANGEDCO being a Designated Consumer (DC) to meet out Energy

Consumption (EC) norms and specified standards based on the notifications issued by

the Ministry of Power (MOP), Govt of India on Perform, Achieve and Trade (PAT)

scheme and the form I required had been submitted before the dead line of 30.06.2012

as per S.O. 687(E) dt.30.03.2012 and PAT Rules vide GSR No. 269(E) dt.30.03.2012.

ENERGY CONSERVATION MEASURES:

TANGEDCO have taken all steps on its own in creating wide awareness among

general public on the need for energy conservation and on the methods available as

follows:

The Energy Conservation Day/Week every year during December across the

state is being celebrated in a grand manner by organizing various events.

Page 8: Annexures TNERC

TANGEDCO have celebrated “Electricity Awareness Week” in all districts across

the state between 21st and 27th of August 2012 to create awareness on Electrical

Safety, Prevention of Electrical Theft and Energy Conservation by disseminating a

Handbook on the same which was released by the Hon’ble Minister for Electricity on

21.08.2012 at Chennai.

TANGEDCO through Hello and Rainbow FM have created awareness among the

general Public on issues related to general in nature, LT billing and Energy

Conservation.

As announced by the GoTN during the Budget Assembly session 2012,

TANGEDCO is taking steps to issue one CFL at free of cost to the Hut Services across

the state and 1 Crore CFLs to metered domestic services at subsidized rate of Rs15/-

per CFL to offset the peak demand.

The TANGEDCO Board has directed to upscale the replacement of 1 Crore CFLs

after implementing in 2 districts. Accordingly Villupuram and Kanyakumari districts were

selected for implementing the scheme. Procurement of CFLs to distribute to Hut and

Metered domestic services is under process.

TANGEDCO has also proposed to use LED lights in the cabin of HODs in all the

TANGEDCO and TANTRANSCO offices at Head Quarters for its huge energy saving

potential and owing to the high cost of the bulbs as promotional measures in first

phase.

TANGEDCO also made mandatory the use of EEPs (3 Star and above) for the

new agricultural service connection.

TANGEDCO has initiated the pilot study on the feasibility of implementing the

Renewable Energy (RE) based DSM and Demand Response (DR) Strategy at Tiruppur &

Udumalpet with the help of M/s. Shakthi Sustainable Energy (SSE) Foundation Ltd.

Page 9: Annexures TNERC

The pilot study on promotion of Energy Efficient appliances in Domestic and

Commercial sectors at Chennai has also been undertaken by TANGEDCO with the help

of M/s.The Energy Resources Institute (TERI).

Apart from the above, the following activities are also being carried out by

TANGEDCO on Energy Conservation measures.

Energy conservation tips along with other suggestions have been displayed in the

web-site of TANGEDCO for wider publicity among the public.

The need for energy conservation is being emphasized in all training programmes /

workshops / seminars conducted by TANGEDCO.

Page 10: Annexures TNERC

1 2010-11 4,210 132 80 4,422

2 2011-12 9,550 300 181 10,032

3 2012-13 7,563 238 143 7,944

4 2013-14 8,670 273 164 9,107

ANNEXURE 5

TOD CONSUMPTION IN MILLION UNITS

Normal Peak Off PeakSr.No Financial Year Total

Page 11: Annexures TNERC

ANNEXURE 6

PROGRESS ON QUALITY OF SUPPLY

The report on the present position of erection of Automatic Power Factor

Compensation (APFC) equipments and capacitor banks in order to improve ‘quality of

service’ as directed in ref. are as follows:

I. Provision of APFC panels at the LT side of the Distribution Transformers:

1.0. The Automatic Power Factor Compensation (APFC) Panels are envisaged in

Part-B Scheme of R-APDRP in 87 towns of TANGEDCO that are to be provided at the LT

side of the Distribution Transformer.

2.0. The schedule of provision of APFC panels in 28,022 DTs in 87 towns in 5

slots is as under.

S. No. Slot Capacity wise APFC panels (Nos.) Schedule

of

completion

18

KVAR

27

KVAR

36

KVAR

72

KVAR

1 I (10 towns) 604 199 321 61 18.03.2013

2 II (17 towns) 633 556 317 148 01.06.2013

3 III (34 towns) 2321 407 1796 404 15.08.2013

4 IV (21 towns) 7721 1637 6876 3646 07.12.2013

5 V (5 towns) 181 36 140 18 21.02.2014

Total 11460 2835 9450 4277

3.0. The above work has been entrusted to P&C wing. Accordingly, P&C wing

has processed the tender for procurement and installation of APFC panels and

awarded the LoAs as below.

(i) LoA awarded to M/s Herodex Power Systems Pvt. Ltd., Maharashtra

S. No. APFC Panel rating Quantity (Nos.) Amount(Rs. Crores)

1 18 KVAR 11460 50.03

2 27 KVAR 2835 14.40

3 72 KVAR 4277 35.70

Total 100.13

Page 12: Annexures TNERC

(ii) LoA awarded to M/s Shreem Electric Ltd., Maharashtra

S. No. APFC Panel rating Quantity (Nos.) Amount (Rs. Crores)

1 36 KVAR 9450 50.32

Total 50.32

4.0. The present status of the above tenders, as stated by P&C wing, is as

follows.

(i) The Tender for Procurement of APFC panels has been finalised and the LOAs

have been issued to 2 firms viz M/s Herodex Power systems Pvt Ltd &

M/s. Shreem Electric Ltd, on 2.6.2012.

(ii) M/s. Misha Power private ltd, Chennai have filed a writ petition (W.P No

13183/2012) in the High court of Madras challenging the corrigendum &

clarifications issued in respect of the subject tender.

(iii) In view of the above writ petition, the LOAs were issued stating that this LOA

is issued subject to the outcome of Writ petition. The counter affidavit had

been filed in the High Court of Madras and subsequently arguments were also

held. Meanwhile one of the successful bidder viz. M/s. Herodex Power

systems Pvt Ltd have filed an impleading petition and the same has been

admitted by the Honourable High Court of Madras, but no direction has been

issued in this regard, so far.

(iv) Since the firms were insisting for removal of the condition mentioned in the

LOA as well as requesting to confirm that payment will be made for the

materials supplied prior to the date of judgement, irrespective of the outcome

of the writ petition, detailed P.O could not be issued.

Page 13: Annexures TNERC

(v) However, the opinion of the standing counsel is being sought to issue

detailed P.O. with the condition that the P.O. is issued subject to the outcome

of writ petition and to proceed with ground works such as survey etc.,

required for the execution of the work so as to complete the project in time.

II. Erection of capacitor banks in Chennai area:

Out of 48 MVAR capacitor bank,26.4 MVAR has been erected and

commissioned in Chennai area and for the balance capacitor erection works are

under progress and the same will be commissioned before Jan-2013. The work

could not be completed as per schedule ,due to delayed supply of indoor breaker.

Presently the breakers have been allotted and erection works are under progress.

III. Erection of RMU in 7 cities:

The provision of fully automated 22/11kv Ring Main Units (RMUs) are

envisaged in Part-B Scheme of R-APDRP in 7 cities (8 Regions of TANGEDCO) are under

progress.

Page 14: Annexures TNERC

ANNEXURE 7 & 8

Road map for metering in Feeders and Distribution Transformers.

I) 100% Metering in Feeders:

Out of 7968 feeders, 7943 feeders are metered which is 99.69%. All the

remaining feeders will be arranged to be metered and 100% metering could be

achieved within 3 months.

Sl.No Voltage Level

No.Of Feeders

Meters Installed

% Metered

1 230 KV 241 241

2 110 KV 467 463

3 66 KV 3 3

4 33 KV 934 926

5 22 KV 1293 1289

6 11 KV 5030 5021

Total 7968 7943 99.69%

II) 100% metering in Distribution Transformers (DTs) a. Total no. of DTs in service as on 30.09.2012 : 2,17,711Nos.

b. Metering available without AMR facility : 93,101 Nos.*

DTs Covered Under R-APDRP : 40,525 Nos

Dts Covered Under Non R-APDRP area : 1,77,186 Nos.

Proposed Metering Under R-APDRP area : 35,500 Nos.

Meters provided in R-APDRP area : 16,082 Nos.

* It is proposed to replace these meters also with AMR facility, hence not

included in the metered DTs.

Page 15: Annexures TNERC

Balance meters for DTs under R-APDRP area will be provided before

December 2012.

c. 100% metering in DTs in non R-APDRP areas with AMR facility are

proposed with an expenditure of Rs. 355 Crores for the provision of

1,77,186 Nos. meters as follows:

2013-14 : 50000 Meters

2014-15 : 100000 Meters

2015-16 : 27186 Meters

d. Chief Engineers/Distribution have already been instructed to provide

meters as an when new DTs are Commissioned.

Page 16: Annexures TNERC

ANNEXURE 9

REPORT ON KVAH BILLING

As per tariff order dated 30th

March 2012, the Hon’ble Commission has directed TANGEDCO

under chapter 11 of “Summary of Directives” as follows:

The Commission directs TANGEDCO to introduce KVAH billing for LT and HT consumers,

as recommended by Forum of Regulators.

However, TANGEDCO would like to submit that there are some practical difficulties for

implementation of kVah billing for the consumers. The issues related to implementation of

kVah are submitted as follows

1. Tri-vector Meter installation

All HT and LT services with connected load of 18.6 kW in TANGEDCO are provided with

meters for KVAh measurement. However KVAh measurement methods differ in different

makes; some meters may be adopting vector summation, some arithmetic and some True

RMS VxI method. Hence, there will be disparity in the billed KVAh energy for the same load

if metered by different makes of meters.

Another issue of major concern is class of accuracy of kvah meter, in absence of any

standards for kvah measurement may lead to dissatisfaction within the consumers which

may result to dispute in billing and legal issues.

2. Accounting Issue

Some of the HT consumer comes under banking arrangements, and also in certain cases LT

consumers are eligible for the same benefits, wherein Power Purchase agreements are

executed based on the KWh and adjustments are also made on KWh only. If the energy

billing is carried out by KVAh for the HT and LT consumers, then there would be a mismatch

in banking adjustments whereby power generated is measure at kWh level and energy

consumed will be at KVAh level. Also, if Power Purchase is made by TANGEDCO from private

or other producers on KVAh basis, it may even result in loss for TANGEDCO as they may

pump more Reactive power and demand the same rate as for active power.

Page 17: Annexures TNERC

3. Lead + Lag Logic for penalty

All the States, where kVAh tariff has been introduced, the HT meters are capable of

measuring lagging power factor only and leading power factor is blocked (lead as unity).

Where as in Tamil Nadu, the HT meters with lead + lag (lead as lead) logic is being followed.

This will result in increase in the KVAh tariff structure if the consumer supplies reactive

power to the grid.

Proposal of TANGEDCO

It is difficult to implement kVAh billing due to above practical issues and implementation

may kindly be deferred.

Under the above circumstances in order to improve the grid stability, TANGEDCO proposes

that Power Factor penalty limit may be revised from the present 0.9 to 0.95 to HT services

and 0.85 to 0.90 to LT services whose connected load exceeds 25 HP (18.6 KW) by making

suitable amendments in the regulations.

Page 18: Annexures TNERC

Sr.No Particulars FY 2010-11

1 Power Purchase from Own Generation 23,223

2 Power Purchase from Other Sources 45,513

3 Wheeling Units -

4 Power from Kadamparai 568

5 Supply from Pudducherry -

Total Power Purchase 69,304

6 T&D Loss (in MU's) 15,441

7 T&D Loss (in %) 22.28%

Total Sales 53,863

8 Sales to Consumers 53,251

9 Wheeling Units -

10 Power Supply to Kadamparai 612

11 Power Supply to Pudducherry -

Sr.No Particulars FY 2010-11

1 Power Purchase from Own Generation 23,223

2 Power Purchase from Other Sources 45,513

3 Wheeling Units 5,468

4 Power from Kadamparai 568

5 Supply from Pudducherry 423

Total Power Purchase 75,195

6 T&D Loss (in MU's) 15,725

7 T&D Loss (in %) 20.91%

Total Sales 59,470

8 Sales to Consumers 53,251

9 Wheeling Units 5,195

10 Power Supply to Kadamparai 612

11 Power Supply to Pudducherry 412

Exclusive of Wheeling

Inclusive of Wheeling

ANNEXURE 10

T&D LOSS FOR FY 2010-11 (ENTIRE YEAR)

Page 19: Annexures TNERC

ANNEXURE 11

Submission of Capital Cost Estimates for Upcoming Thermal Power Stations

TANGEDCO humbly submits that

1) TANGEDCO herein TANGEDCO LTD (Tamil Nadu Generation and Distribution Corporation

Limited), hereinafter called TANGEDCO, is a Government Company within the meaning of the

Companies Act, 1956.

2) TANGEDCO is a subsidiary Company to Tamil Nadu Electricity Board (TNEB) which came into

existence on 1st July 1957 and has been in the business of generation, transmission and

distribution of electricity in the state of Tamil Nadu.

3) The Electricity Act 2003 mandates unbundling of State Electricity Boards under section 131. In

accordance with the above mandate the Government of Tamil Nadu (GOTN) had given in

principle approval for the re-organization of TNEB by establishing a holding company, named

TNEB Ltd and two subsidiary companies, namely Tamil Nadu Transmission Corporation Limited

(TANTRANSCO) and Tamil Nadu Generation and Distribution Corporation Limited (TANGEDCO)

vide G.O.Ms.No.114 Energy (B2) Department dated 8th October 2008 with the stipulation that

the aforementioned companies shall be fully owned by Government.

4) Based on the approval of Memorandum of Association and Articles of Association of TANGEDCO

and TNEB Limited by the Government of Tamil Nadu vide G.O.Ms.No.94 Energy (B2) Department

dated 16th Nov 2009, Tamil Nadu Generation and Distribution Corporation Limited (TANGEDCO)

and TNEB Limited was incorporated on 1st Dec 2009 with an authorized share capital of Rs. 5.00

Crores and paid up capital of Rs. 5.00 Lakhs each for TANGEDCO and TNEB Limited. The

Certificates of commencement of business have been obtained for the TANGEDCO on 16th

Mar

2010 and for TNEB Ltd on 12th

Mar 2010 respectively.

5) TANGEDCO vide Provisional Transfer Scheme notification dated 19th

October 2010 has been into

existence from 1st

November 2010 and since then TANGEDCO has been in the business of

generation and distribution of electricity in the state of Tamil Nadu.

6) TANGEDCO has mix of the various generating capacities such as 2970 MW of coal based four

thermal stations, 516 MW from the five Gas Turbine Stations and 2223 MW from 39 Hydro

Stations.

Page 20: Annexures TNERC

7) The present submission is been filed for approval of Capital Cost of three upcoming Thermal

Power Stations namely:-

a. Mettur Thermal Power Station (MTPS) Stage III Unit – I (1x600MW);

b. North Chennai Thermal Power Station Stage II Unit – I (1x600MW);

c. North Chennai Thermal Power Station Stage II Unit – II (1x600MW);

a. Mettur Thermal Power Station (MTPS) Stage III Unit – I (1x600MW);

8) The EPC contract for construction of Mettur Thermal Power Station Stage III Unit – I was

awarded to BGR Energy Systems Ltd (BGRESL) and the works commenced on 25th

June 2008. The

project was to be commissioned during September 2011 but was delayed due to delay in Coal

handling, Ash Handling, Milling System and Bunkers Erection, etc. The contract has been

extended up to 31st

March 2013 in order to facilitate the commissioning.

9) The unit was synchronized with oil on 4th

May 2012 and achieved a full load capacity of 608 MW

on 11th

October 2012. The initial operation of the unit was under progress from 23rd

November

2012 to 04th

December 2012. However the unit was forced shut down from 04th

December 2012

to attend to few technical problems that were encountered during the period of initial

operation.

10) On completion of entire Coal Handling System and Ash Handling system the unit is expected to

be commissioned with full load on sustained basis by March 2013 as committed by M/s.BGRESL

during the Chief Secretary’s review meeting on 11th

January 2013.

b. North Chennai Thermal Power Station Stage II Unit – I & II (2x600MW);

11) The EPC contract for construction of North Chennai Thermal Power Station Stage II Unit – I and

Unit – II was awarded to Bharat Heavy Electricals Ltd (BHEL) and the works commenced on 16th

August 2008. The project was to be commissioned during November 2011 but was delayed due

to delay in Coal Handling System, Cooling water system, Ash handling system etc.

12) The works for 400 KV GIS switch yard has been completed and it was commissioned on 09th

December 2012. The unit was synchronized into the grid with a capacity of 101 MW with oil on

17th

December 2012. The boiler has been lit up for coal firing on 19th

January 2013. Therefore

sustained generation of 250 MW to 300 MW is expected from 30th

January 2013.

13) On completion of entire Coal Handling System and Ash Handling system the unit is expected to

be commissioned with full load capacity on sustained basis by April 2013 as committed by M/s.

BHEL during the Chief Secretary’s review meeting on 11th

January 2013.

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14) It is submitted that power generated from these Thermal Power Stations shall be supplied to

TANGEDCO for retail supply of power to its consumers.

15) The investment approval of Mettur Thermal Power Station Stage III Unit – I was accorded by

TANGEDCO board at its board meeting held on 22nd

October 2008 at the project cost of Rs.

3,550 Crores.

16) The investment approval of North Chennai Thermal Power Station Stage II Unit – I was accorded

by TANGEDCO board at its board meeting held on 24th

April 2008 at the project cost of Rs.

3,095.28 Crores.

17) The investment approval of North Chennai Thermal Power Station Stage II Unit – II was accorded

by TANGEDCO board at its board meeting held on 13th

October 2008 at the project cost of Rs.

2,718.75 Crores.

18) The copy of board approval for all the three Thermal Power Station namely Mettur Thermal

Power Station Stage III Unit – I, North Chennai Thermal Power Station Stage II Unit – I and North

Chennai Thermal Power Station Stage II Unit – II is enclosed at Annexure A.

19) The Hon’ble Commission under Regulation 18 of TNERC Terms and Condition of Tariff is vested

with the jurisdiction to determine/approve capital cost of upcoming power plants of generating

stations of TANGEDCO.

20) The table below shows the installed capacity and the expected COD of all the four Hydro

Stations.

Name of Power

Plant

Installed Capacity

(in MW)

Expected COD Board

Approved Cost

Cost as on

COD

Mettur Thermal

Power Station

Stage III Unit – I

1 x 600 MW 1st

March 2013 3,550 Crores 3,550 Crores

North Chennai

Thermal Power

Station Stage II

Unit – I

1 x 600 MW 1st

May 2013 3,095.28

Crores

3,095.28

Crores

North Chennai

Thermal Power

Station Stage II

Unit – II

1 x 600 MW 1st

April 2013 2,718.75

Crores

2,718.75

Crores

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21) TANGEDCO is filing the present submission for approval of capacity cost up to COD and the cost

of additional capitalization which is estimated to be incurred in the ensuing years.

22) In terms of Tariff Regulations 2005, TANGEDCO has filled in the formats provided in Appendix 1

of Tariff Regulations 2005 as notified by Hon’ble TNERC including that in regards to estimated

capital expenditure from a period from date of commercial operation up to 31st

March 2016.

The formats are enclosed as Annexure I and are based on anticipated date of COD as mentioned

in the table above.

23) The projected estimated capital expenditure claim made by TANGEDCO is based on expected

capitalization as on COD of the respective units of the station. The projected additional capital

expenditure up to cut off date is on works within the original scope of work and is in accordance

with Regulation 18 of TNERC Terms and Conditions of Tariff Regulations, 2005. The capital

expenditure is the actual expenditure incurred up to the cutoff date and in case of additional

expenditure to be incurred after the cutoff date, the same shall be submitted at the time of

truing up before the Hon’ble Commission in respect to the instant station.

24) It is submitted by TANGEDCO that there has been no foreign loans taken for funding of the

capital expenditure for project execution. Therefore there are no details of foreign loans

submitted in the prescribed formats. Also there has been no extra rupee liability with respect to

foreign exchange fluctuation towards interest payment and loan repayment in the relevant

years.

25) In line with TNERC Terms and Conditions of Tariff equity in excess of 30% of the fund deployed

has been considered as normative loan and notional IDC. The return on equity is considered at

normative rate of 14% as specified in the Regulations.

26) It is further submitted that the levies, taxes, duties, service tax etc, levied by various authorities

on TANGEDCO in accordance with the law shall be billed to beneficiaries additionally.

27) It is further submitted that the Hon’ble Commission may be pleased to take the above

details/computations for determination of capital cost.

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PRAYERS

In light of the above submission TANGEDCO, therefore prays that the Hon’ble Commission may

be pleased to:

i. Approve Capital Cost for all three upcoming Thermal Power Stations up to the

anticipated date of Commercial Operation.

ii. Allow TANGEDCO to claim the cost of the respective thermal stations in the ARR of

TANGEDCO as per this submission.

iii. Allow the recovery of filing fees as and when paid to the Hon’ble Commission and

publication expenses from beneficiaries.

iv. Pass any other order as it may deem fit in the circumstances mentioned above.

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ANNEXURE 12

Submitted By

ENERGY DIVISION

TECHNICAL PAPER ON CATEGORY-WISE COST OF SERVICE

STUDY

(DELIVERABLE [4 (1)])

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Table of Contents

1. INTRODUCTION ......................................................................................................... 1

1.1 COMPANY PROFILE OF TANGEDCO ............................................................................... 1

1.2 BACKGROUND OF THE CONCEPT ...................................................................................... 2

2. NEED OF THE STUDY .................................................................................................. 4

2.1 OBJECTIVE OF THE STUDY .............................................................................................. 4

2.2 KEY ISSUES ................................................................................................................. 5

3. STATUTORY & LEGAL PROVISIONS .............................................................................. 7

3.1 ELECTRICITY ACT 2003 ................................................................................................. 7

3.2 NATIONAL TARIFF POLICY .............................................................................................. 8

3.3 NATIONAL ELECTRICITY POLICY ....................................................................................... 9

3.4 TNERC TARIFF REGULATIONS ........................................................................................ 9

3.5 TNERC ORDER DATED 30TH MARCH 2012 .................................................................... 10

3.6 SUMMARY CONCLUSION ON THE APPLICABLE LEGAL AND POLICY FRAMEWORK ....................... 11

4. METHODOLOGY FOR DETERMINATION OF COST OF SERVICE .................................... 13

4.1 LINKAGE OF TARIFFS WITH COST OF SUPPLY ..................................................................... 13

4.2 FUNCTIONALISATION OF COSTS: .................................................................................... 15

4.3 CLASSIFICATION OF COSTS: .......................................................................................... 16

4.4 ALLOCATION OF COSTS: .............................................................................................. 19

4.5 APPROACH FOR SEGREGATION OF COST ........................................................................... 23

4.6 BASIS FOR DETERMINATION OF COST TO SERVICE .............................................................. 24

5. DEFINITIONS ............................................................................................................ 27

5.1 SYSTEM PEAK DEMAND (RESTRICTED) ............................................................................ 27

5.2 CO-INCIDENT PEAK DEMAND ....................................................................................... 27

5.3 NON CO-INCIDENT PEAK DEMAND ................................................................................ 27

5.4 CONNECTED LOAD ..................................................................................................... 27

5.5 CONTRACTED DEMAND ............................................................................................... 27

5.6 SYSTEM LOAD FACTOR ................................................................................................ 28

5.7 CATEGORY LOAD FACTOR ............................................................................................ 28

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5.8 DIVERSITY FACTOR ..................................................................................................... 28

6. CALCULATION OF EXPENSES ..................................................................................... 29

6.1 CLASSIFICATION OF POWER PURCHASE EXPENSES ............................................................. 29

6.2 CLASSIFICATION OF OTHER DISTRIBUTION EXPENSES ......................................................... 29

6.3 ALLOCATION OF DEMAND RELATED COST ......................................................................... 31

6.4 ALLOCATION OF ENERGY RELATED COST .......................................................................... 34

6.5 ALLOCATION OF CUSTOMER RELATED COSTS.................................................................... 38

7. COST OF SERVICE ..................................................................................................... 41

7.1 COST OF SERVICE OF EACH CATEGORY ............................................................................ 41

7.2 CONCLUSION ............................................................................................................ 42

8. WAY FORWARD ....................................................................................................... 44

8.1 WAY FORWARD ......................................................................................................... 44

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List of Table

Table 1: Cost Classification and Functionalisation ................................................................ 18

Table 2: Profit & Loss Statement for FY 2010-11 .................................................................. 25

Table 3: Consumer Category of TANGEDCO ......................................................................... 26

Table 4 – Classified Power Purchase Expenses for FY 2010-11 ............................................. 29

Table 5: Classified Distribution Expenses ............................................................................. 30

Table 6: Category-wise Average & Excess Demand (MW) .................................................... 31

Table 7 - Allocation Factors for Demand Related Power Purchase Costs .............................. 31

Table 8 - Allocation factors for Demand Related Other Distribution Costs ........................... 33

Table 9 - Allocation factors for Demand Related Total Distribution Costs ............................ 34

Table 10 – Losses at TANGEDCO for FY 2010-11 .................................................................. 35

Table 11 – Allocation of Commercial Losses ........................................................................ 36

Table 12 – Allocation of Technical Losses............................................................................. 36

Table 13 – Allocation of Losses to categories ....................................................................... 37

Table 14: Allocation Factors for Energy Related Costs.......................................................... 38

Table 15: Category wise Customer Weightage ..................................................................... 39

Table 16 – Allocation Factors for Customer related Costs .................................................... 40

Table 17 - Category wise Total Cost of Service (Rs. Crs) ....................................................... 41

Table 18 – Category wise per unit Cost of Service ................................................................ 41

Table 17 – Cost of Service against Average Realisation ........................................................ 43

List of Figures

Figure 1: Computation of Cost of Supply.............................................................................. 24

Figure 2 - Category Wise COS and Average Realization ........................................................ 43

List of Annexure

ANNEXURE A - Category Wise Non Coincident Demand....................................................... 45

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1. INTRODUCTION

1.1 Company Profile of TANGEDCO

1.1.1 Tamil Nadu Electricity Board, a State Electricity Board was constituted under section

5 of the Electricity (Supply) Act, 1948 and was in the business of Generation,

Transmission and Distribution of Electricity in the State of Tamil Nadu.

1.1.2 The Government of Tamil Nadu vide G.O Ms No 114 dated 08.10.2008, accorded in-

principle approval for the re-organization of TNEB by establishment of a holding

company, by the name TNEB Ltd and two subsidiary companies, namely Tamil Nadu

Transmission Corporation Ltd (TANTRANSCO) and Tamil Nadu Generation and

Distribution Corporation Ltd (TANGEDCO).

1.1.3 The first provisional Transfer Scheme was notified by the State Government vide

G.O. (Ms.) No.100, Energy (B2) department, dated 19th Oct 2010 issued under Tamil

Nadu Electricity (Reorganization and Reforms) Transfer Scheme, 2010 for the

purpose of transfer and vesting of property, rights and liabilities of the Tamil Nadu

Electricity Board in the State Government and re-vesting thereof by the State

Government into corporate entities and also for the transfer of personnel of the

Tamil Nadu Electricity Board to corporate entities and for determining the terms and

conditions on which such transfer and vesting will be made.

1.1.4 Based on the above G.O. the Tamil Nadu Generation and Distribution Corporation

Ltd (TANGEDCO) was registered on 01.12.2009. The Certificate of commencement of

business was obtained for the TANGEDCO on 16.03.2010.

1.1.5 The second provisional transfer scheme was notified by the State Government vide

G.O. (Ms.) No.2, Energy (B2) department, dated 2nd January 2012 with amendment

in the restructuring of Balance Sheet of TNEB for the successor entities i.e.

TANGEDCO and TANTRANSCO, considering the audited balance sheet of TNEB for FY

2009-10.

1.1.6 The opening balances of assets and liabilities are transferred based on the FY 2009-

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10 audited balances, which was the latest available data at that point of time.

TANGEDCO started functioning independently from 1st November 2010 onwards. As

per clause 9(1) of the transfer scheme the assets transfer is provisional for a period

of one year and employees transfer is provisional for a period of three years from

the effective date of transfer, i.e. 1st November 2010.

1.1.7 Subsequently, as per the request of TNEB Limited, the second provisional transfer

scheme was notified by the State Government vide G.O. (Ms.) No.2, Energy (B2)

department, dated 2nd

January 2012 with amendment in the restructuring of Balance

Sheet of TNEB for the successor entities i.e. TANGEDCO and TANTRANSCO,

considering the audited balance sheet of TNEB for FY 2009-10 and have extended

the provisional time for final transfer of assets and liabilities to the successor entities

of erstwhile TNEB upto 31.10.2012.

1.1.8 The TNEB limited in its 22nd

Board meeting held on 27.09.2012, has approved the

proposal to seek 6 months time extension i.e up to 30.04.2013 for final transfer of

assets and liabilities to successor entities of erstwhile TNEB and the same has been

addressed to the GoTN for approval and notification.

1.1.9 Tamil Nadu Generation and Distribution Corporation Limited has installed generating

stations of capacity 10,380 MW which includes State, Central share and Independent

power producers and has achieved a consumer base of about 223.44 lakh consumers

at the end of FY 2010-11

1.2 Background of the concept

1.2.1 With the advent of the Electricity Act 2003 and various policy initiatives thereof, it

has now become mandatory for the Electrical utilities to gradually reduce the cross

subsidy and move the tariffs in the State towards the “Cost of Supply”. Traditionally,

in the Indian context, tariffs for domestic and agricultural consumers have been

heavily subsidised either by the state through subsidies and subventions or through

cross subsidisation by other consumer categories, primarily the consumers using

electricity at high voltages.

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1.2.2 A basic principle that has been widely accepted in electricity sector regulation is that

the tariffs for various categories of customers should be, as far as practicable, equal

to the costs imposed by that category of customers on the system. This is what is

currently understood as Cost of Service (CoS).

1.2.3 With the focus now shifting to cost- reflective tariffs, it has now become necessary

to compute the cost to serve to individual consumer categories and the gradual

reduction of the cross subsidies existing between the consumer categories today. A

basic principle that has been widely accepted in electricity sector regulation is that

the tariffs for various categories of customers should be, as far as practicable, equal

to the costs imposed by that category of customers on the system.

1.2.4 The focus of the reforms envisaged by the Electricity Act, 2003 (EA 2003) is to

establish competitive environment for economical and financial viability of the

power sector. The prices at every stage of the value chain of the sector should reflect

marginal cost. Cross subsidy which is another form of subsidy affect economic

efficiency and environmental performance.

1.2.5 The estimation of cost to supply to category of consumers enables the calculation of

cross subsidy. The obligation to reduce cross subsidy comes from the legal, policy

and regulatory framework of the power sector. The Electricity Act 2003 requires the

Distribution Licensee to reduce cross subsidy and if the State Government requires

tariff of any consumer category to be subsidized then it would be required to provide

subsidy in advance equivalent to the subsidized amount.

1.2.6 In relation to this, TANGEDCO will be submitting the best possible methodology to

be adopted for determining cost of supply taking into account various constraints

and various other conditions to the Hon’ble Commission for approval.

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2. NEED OF THE STUDY

2.1 Objective of the Study

2.1.1 Cost of service study seeks to allocate all the costs of a utility to each of the

customer classes it serves. Such allocation reflects the costs attributable to electricity

supplied and related services provided to categories. The costs can then be used as

an input into tariff design or to determine cross subsidy, if any, existing in tariffs. The

determination of cost of service for each of customer categories requires

disaggregating the utility’s costs into functions, services and categories.

2.1.2 In setting tariffs, cross-subsidies have been retained with the ostensive objective of

balancing the effect of price increase on certain categories of consumers who have

been paying lower tariffs historically. Efforts to make the reforms successful in

power sector will have to take note of the need to reduce and eventually phasing out

cross-subsidies.

2.1.3 Objectives of the Cost of Service study:

- Formulate a long-term tariff strategy;

- Establish cross subsidy reduction path;

- Provide right signals for efficient use of energy;

- Provide price signals for rendering specific services especially in the competitive

markets;

- Facilitate directed and transparent administration of subsidies to the deserving

classes;

2.1.4 There is a need that the tariff of all subsidized categories of consumers would need

to be rationalised in phased manner, such that the consumers who are enjoying

subsidy for years accept the tariff increase supplemented with improved quality of

supply. It will also have to be ensured that there is no disparity in quality & quantity

of power supply amongst all the consumers, including these subsidized category

consumers. Consumers shall be liable to bear the cost of supply and the loss levels

expressing the efficiency of the respective consumer category only. Cost of Supply

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shall be determined on the actual cost to supply to each of the consumer class

without subsidies and cross subsidies. Such determination of actual costs requires

apportionment of a utility’s costs to the various customer classes it serves.

2.1.5 Therefore, to achieve the objectives, Study of Cost needs to be carried out for the

following purposes:

• To attribute costs to different categories of customers based on how those

customers cause costs to the utility;

• To provide a comparison of the allocated costs with revenues from existing

tariff;

• To illustrate the Extent of existing cross-subsidisation between consumer

categories;

2.2 Key issues

2.2.1 The key issues which is required to undertake the study of CoS and reduction of

Cross Subsidies are as follows:

• Initially, the category wise tariff was decided after taking cognizance of socio-

economic consideration in line with state government policy.

• Cost of Service (CoS) for agricultural consumers in isolation is not feasible as it

involves many other issues like allocation of cost of supply i.e. cheap and costly

power purchased by utility;

• The prevailing levels of electricity tariff contain a large degree of cross subsidy,

with some categories of consumers paying well above the economic cost of

supply. It has to be recognised that low and subsidised tariff inflict inefficient

high demand for power, which puts pressure on the system capacity and the

quality of service.

• The slab rates are so designed that the affluent customers are paying more and

economically weaker consumers paying less for their consumption. The paradox

often faced is that while efficiency criterion calls for a cost based tariff, the social

criteria may at times call for relief to certain consumer’s e.g. low-income group.

2.2.2 It is a well known fact that supplying electricity at tariffs less than the actual cost, to

various categories of consumers leads to financial losses for Utilities. It is also a well

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know fact that the State Utilities have to make the electricity, a basic necessity,

available to all poorer citizens who are unable to pay for it at affordable cost price.

The following concerns need to be addressed

• Categories of consumers who should be subsidized;

• Quantum of Subsidy including the government subsidy;

• Ability of State Government to bear the burden of Cross Subsidy;

• Mechanism of flow of subsidy from State Govt to Utility

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3. STATUTORY & LEGAL PROVISIONS

The current treatment of cross subsidies by State Electricity Regulatory Commission and

other options available to address the cross subsidy reduction issue have to be in

consonance with the provisions of the Electricity Act 2003, the National Electricity Policy,

Tariff Policy and the decisions of Appellate Tribunal for Electricity (ATE). In the following

sections the various provisions of the Act, Policies, Regulations, Tariff order and the

decisions of the Appellate Tribunal have been quoted and interpreted in order to develop

an understanding of the framework which will form the basis for the development of the

Methodology for carrying out Cost to Service Calculation.

3.1 Electricity Act 2003

3.1.1 Subsection (g) of Section 61 of EA 2003 stipulates that the tariff should progressively

reflect cost of supply of electricity and also reduces cross subsidies in the manner

specified by the Appropriate Commission;

3.1.2 Section 62(3) provides for the factors on which the tariffs of the various consumers

can be differentiated. Some of these factors like load factor, power factor, voltage,

total electricity consumption during any specified period or time or geographical

position also affects the cost of supply to the consumer. Due weightage can be given

in the tariffs to these factor to differentiate the tariffs;

3.1.3 As per the Section 62 of the EA 2003, the SERC is required to determine the retail

tariff to be charged by the Distribution Licensees from its consumers. The

Commission while determining the tariffs is required to give considerations to the

factors (load factor, power factor, voltage, total consumption of electricity during

any specified period or the time at which the supply is required or the geographical

position of any area, the nature of supply and the purpose for which the supply is

required.) listed in Section 62(3), 61(c) and 61(e) of the EA 2003, which are

essentially cost determinants and economically efficient tariffs should consider the

cost impact of these factors only without providing for any cross subsidies.

3.1.4 The Tariff may be fixed as per the consumer’s load factor, power factor, voltage,

total consumption of electricity and should reflect the Cost of Supply to the

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concerned consumer category.

3.1.5 The EA 2003 recognizes the fact that tariffs of some consumer categories are

presently below cost of supply and tariff shock due to abrupt elimination of subsidy

may not be in the interest of such consumers therefore it provides for progressive

reduction in cross subsidy. As said earlier, the tariffs must reflect the underlying cost

of supply and if the State Government wishes that any particular consumer category

is to be charged lower than the cost of supply then as per Section 65 of the EA 2003

the State Government has to provide subsidy to such consumers. The EA 2003 has

preferred direct subsidy over cross subsidy. However the amendment to the section

61 replacing the word elimination with reduction provides for some amount of

continued cross subsidy.

3.2 National Tariff Policy

3.2.1 The National Tariff Policy (NTP) prescribes the principles to be adopted by the

Commission for determining tariffs for generation, transmission, distribution and

retail consumers. The clauses dealing with the issue of Cost to Supply are given in the

table below:

3.2.2 Section 8.3 (2) reads -

For achieving the objective that the tariff progressively reflects the cost of supply

of electricity, the SERC would notify roadmap within six months with a target that

latest by the end of year 2010-2011 tariffs are within ± 20 % of the average cost

of supply. The road map would also have intermediate milestones, based on the

approach of a gradual reduction in cross subsidy;

3.2.3 The NTP provides that tariffs is required to reflect efficient costs and gradual

reduction of cross subsidy inherent in existing tariffs but consumers below poverty

line (BPL) for life line consumption can have cross subsidized tariff rates. Also, a

direct subsidy support by the State Government to the other poorer categories of

consumers for pre-identified level of consumption is allowed.

3.2.4 The clause 8.5 which defines cross subsidy charge as the difference between the (i)

tariff applicable to the relevant category of consumers and (ii) the cost of the

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distribution licensee to supply electricity to the consumers of that category provides

an indication how to compute cross subsidy.

3.2.5 The NTP recognizes data and other issues in the determination of cost of supply

consumer category wise and alternatively provides that tariff should be within ± 20

% of the average cost of supply.

3.3 National Electricity Policy

3.3.1 The Commission while discharging its functions as required by the Electricity Act

2003 is to be guided by the National Electricity Policy (NEP). The NEP provides

guidance and clarifications on issues which either have not been or have been

inadequately addressed in the EA 2003. The relevant clauses in the context of this

study are:

3.3.2 Clause 5.5.1 reads that there is an urgent need for ensuring recovery of cost of

service from consumers to make the power sector sustainable;

3.3.3 Clause 5.5.2 stipulates that consumers below poverty line, who consume below a

specified level, say 30 units per month, may receive a special support through cross

subsidy. Tariffs for such designated group of consumers will be at least 50% of the

average cost of supply. This provision will be re-examined after five years;

3.3.4 Further, the National Electricity Policy provides for reducing the cross subsidies

progressively and gradually. The gradual reduction is envisaged to avoid tariff shock

to the subsidized categories of consumers. It also provides for subsidized tariff for

consumers below poverty line for minimum level of support. Cross subsidy for such

categories of consumers has to be necessarily provided by the subsidizing consumers

3.3.5 The thrust of the NEP is that the tariffs should reflect cost and existing cross

subsidies should progressively and gradually reduce. However there can be cross

subsidy support for very poor categories of consumers.

3.4 TNERC Tariff Regulations

3.4.1 Clause 23(e) of MYT Regulations 2009 reads that application for determination of

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Tariff under MYT framework shall be accompanied with –

a statement showing cost to supply for electricity to different category of

consumers at different voltage level with the allocation of Transmission and

Distribution loss and consumer wise cross subsidy at the existing tariff

3.4.2 As per the Tariff Regulation 7 (c) (iii) of the State Commission, it stipulates that the

cross subsidy has to be computed as difference between cost-to-serve a category of

consumer and average tariff realization of that category;

3.5 TNERC Order dated 30th March 2012

3.5.1 As highlighted in the Tariff order dated 30th

March 2012, the Cost to serve, Average

Cost of supply and Cross Subsidy are inter-related issues which are extensively

covered in the Order of the Hon’ble Appellate Tribunal of Electricity dated 11th

January2012 in Appeal Nos. 57 of 2008, 155 of 2007, 125 of 2008, 45 of 2010, 40 of

2010, 196 of 2009, 199 of 2009, 163 of 2010, 6 of 2011 and 144 of 2010.

3.5.2 Following is the opinion of the APTEL on the issue related to Cost to Serve and

Average Cost of Supply:

• If strict commercial principles are followed, then the tariffs have to be based on

the cost to supply a consumer category. However, it is not the intent of the Act

after the amendment in the year 2007 (Act 26 of 2007) that the tariff should be

the mirror image of the cost of supply of electricity to a category of consumer.

• The cross subsidies may gradually be reduced but should not be increased for a

category of subsidizing consumer.

• APTEL has advised to initiate a simple formula which could take into account the

major cost element to a great extent reflecting the cost of supply. There is no

need to make distinction between the distribution charges of identical

consumers connected at different nodes in the distribution network. It would be

adequate to determine the voltagewise cost of supply taking into account the

major cost element which would be applicable to all the categories of consumers

connected to the same voltage level at different locations in the distribution

system.

• As segregated network costs are not available, all the costs such as Return on

Equity, Interest on Loan, depreciation, interest on working capital and O&M costs

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can be pooled and apportioned equitably, on pro-rata basis, to all the voltage

levels to determine the cost of supply.

• Segregating Power Purchase cost taking into account voltage-wise transmission

and distribution losses will be a major step in the right direction for determining

the actual cost of supply to various consumer categories.

• All consumer categories connected to the same voltage will have the same cost

of supply.

3.5.3 Based on the above points as specified in APTEL order, it is very clear, that the cross

subsidies needs to be reduced and not to be eliminated. Also, even though the

accurate data is not available, a simple formulation based on certain assumption can

be carried out to calculate Cost to Serve of different categories of consumers.

However, there is no clarity that the Cost to serve and Cross subsidy impact to be

calculated needs to be at macro level or at micro level, i.e. to be determined at

category of consumers level or at sub-category level also.

3.5.4 Also, Clause 2.1.46 of Issue 6 (Cost of Supply) of the Tariff Order for TANGEDCO

dated 30.03.12 reads-

“The Tariff may be fixed as per the consumer’s load factor, power factor, voltage,

total consumption of electricity and should reflect the Cost of Supply to the concerned

consumer category”

3.5.5 Further, Clause 2.1.47 of Issue 6 (Cost of Supply) of the Tariff Order for TANGEDCO

dated 30.03.12 reads-

“TANGEDCO should furnish a statement showing the Cost to Serve for each category

of consumers at different voltage level with allocation of Transmission & Distribution

loss and consumer wise cross subsidy at the existing tariff while submitting ARR.”

3.6 Summary conclusion on the Applicable Legal and Policy Framework

3.6.1 Following conclusions can be drawn from the above discussion on the legal and

policy framework applicable to cross subsidy determination and its reduction

• Consumer tariffs to reflect efficient cost of supply but can be differentiated only

on grounds specified in Section 62(3).

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• Cross subsidies to reduce gradually with out tariff shock to consumers

• SERC is required to notify a road map along with intermediate milestones for

cross subsidy (reduction) to be within ± 20 % of the average cost of supply.

• The cross subsidies can exist for BPL categories of consumers for life line

consumption but consumption in excess of this lifeline consumption is to be

charged at full cost. Paying capacity can be one of the factors for determination

of tariff payable by BPL categories. The tariffs payable for this lifeline

consumption should be 50% of the average cost of supply.

• The State Government can provide subsidy to any disadvantaged consumer

groups for increased access to electricity provided that this subsidy amount is

provided in advance as per the Section 65 of the EA 2003.

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4. METHODOLOGY FOR DETERMINATION OF COST OF SERVICE

4.1 Linkage of Tariffs with Cost of Supply

4.1.1 The amount of cross subsidy received/contributed by various consumer categories is

dependent on the way the cost of supply is defined. Accordingly Cost of supply can

be defined as:

• Average cost of supply;

• Cost of supply voltage wise; and

• Cost of supply to various consumer categories

4.1.2 Depending upon the definition adopted for cost of supply, the cross subsidy

reduction may accordingly be different. The EA 2003, the NEP and the NTP requires

the tariffs to reflect efficient cost of supply and while determining tariff as required

by section 61(c) of the EA 2003 the SERC needs to consider factors which would

encourage competition, promote efficiency, economical use of the resources, good

performance and optimum investments section.

4.1.3 Though the term Cost of Supply has not been defined explicitly in the legal and policy

framework but from the simultaneous reading of the Electricity Act 2003, NEP and

particularly the clause 8.5 of the TP, the cost of supply can be construed to mean the

cost of supply to the relevant consumer category. It has also been proven in

economic theory that tariffs that reflect the cost of supply to the consumer category

provide economic signals for the optimum use of electricity and investment in the

sector. Further cost reflecting prices will be fair to consumers receiving the supply at

higher voltages as the cost of supply at higher voltages is lower than the cost of

supply at lower voltages, on account of higher distribution losses at lower voltages,

and the incidence of costs getting passed on to the lower voltages since energy flows

from higher to lower voltages.

4.1.4 The cost of supply to consumer categories can be determined either on the

Embedded (Historical) cost or marginal cost approach basis. Usually, the approach

adopted by many SERC’s and utilities is to consider the average cost of supply

method to calculate the Cross Subsidy as the data required to calculate the cost of

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supply category wise and voltage wise is not available. However, the average cost of

supply is not the efficient way of determination of cost of supply.

4.1.5 Every approach has its Pros and Cons whereby the Embedded cost based

methodology uses the historical accounting information for cost determination

whereas the marginal cost based methodology uses the future costs to determine

tariffs. The first methodology ensures that all the prudent costs of the Licensees are

allocated but does not provide any economic signal to the consumers of the future

costs. The second methodology based on marginal cost provides economic signal for

economically efficient investments and optimum use of electricity but it does not

ensure the recovery of entire costs (particularly when the past costs are higher than

the future costs) and may require some adjustment in the tariffs for recovery of the

actual cost.

4.1.6 Given the current regulatory regime (MYT framework is based on historical cost),

lack of reliable information and generation & system planning studies, it would be

desirable to use historical costs for cost of supply determination in the near future.

The interim period (during the period embedded cost approach is used) to conduct

studies so that marginal cost can latter be used. The switch from embedded cost to

marginal cost approach will be easier as the two approaches have similar cost

allocation principles.

4.1.7 It is submitted that for calculation of voltage wise cost it is important that the

accounting system of the Licensees are sufficient enough to capture the costs

voltage wise at the point of origin as and when these are incurred. However, since at

current stage it is not possible, an assumption is considered for the allocation of

expenses and calculation of diversity factor.

4.1.8 To determine the cost of supply voltage wise, getting voltage wise cost right is the

first step in determining consumer wise costs. However, the availability of voltage

wise accurate data is one of the key issues and again a certain assumption has been

carried out.

4.1.9 Usually, the traditional approach adopted for calculation of cost of supply is using

Embedded Cost Method. The embedded cost based approach allocates the total

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revenue requirement to various categories of consumers based on an analysis of the

embedded or historic costs of the utility. In such an analysis, the revenue

requirement is allocated to classes of service to fix tariff based on various allocation

factors. The factors can be the contribution of classes to the peak demand, the

energy purchased by each class as a percentage of total sales, the number of

consumers in the class etc.

4.1.10 The advantage of the embedded cost approach is that embedded costs and

allocation factors can be measured based on data that is recorded in the books of

the utility. However, it suffers from the lacunae of not accounting for the inflation

and also true economic cost of the electricity delivered to consumer.

4.1.11 Considering the above highlighted issues, a systematic approach to the CoS study

shall involve three steps of functionalisation, classification and allocation of costs to

various customer categories.

4.2 Functionalisation of Costs:

4.2.1 The first stage of a cost of service study shall involve functionalisation of all the costs

of the TANGEDCO to various functions such as power generated, purchased and

distribution (termed as “Functionalisation”).

4.2.2 It is relatively easy to capture these costs from the books of accounts as the chart of

accounts maintained by the company would provide for capture of these

assets/costs separately. Within the assets and costs it is however, difficult to capture

the voltage class wise assets and costs as the accounts of company does not capture

this information. But TANGEDCO has carried out the assessment of the fixed assets

voltage wise and therefore a data will be collected on a sample basis based on the

information available. This will enable TANGEDCO to bifurcate its assets and costs as

relating to LT network and HT network. This logic has been largely used for

functionalization of assets and costs for this exercise

4.2.3 The power purchase costs include the costs of transmission of power from the

generating stations to the transmission-distribution interface point. Also, though

TANGEDCO is carrying the generation and distribution function, the expenses related

to State own Generating station such as Fuel is considered as variable charges in

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power purchase cost and the other cost has been added with the expenses of

distribution. Also, the transmission cost has been considered in the fixed cost of

power purchase for last 5 months of FY 2010-11 and an initial expense during the

time of erstwhile TNEB has been considered in the respective head of account.

4.3 Classification of Costs:

4.3.1 The costs are classified as being demand, energy or customer/service related. Such a

classification is done on the basis of the cause of such costs, as specified below:

• Costs which are triggered by peak demands imposed on the system are classified

as “demand related”;

• Cost related to level of power purchase as “energy related” and

• Cost related to number and type of customers as “customer related”.

4.3.2 Classification of Generation and Power Purchase Costs

4.3.2.1 Generation Costs and Power Purchase cost are identified to be energy as well as

demand related as TANGEDCO shall not only supply the energy required over a

period of time but shall generate or purchase sufficient capacity to meet the

peak demand of the system.

4.3.2.2 Power purchase cost generally will have two elements i.e., fixed cost and variable

cost. The fixed cost include costs associated with the plant capacity i.e.

depreciation, interest relating to capital investment for the plant, income tax,

rate of return etc. They are treated as demand related. Fuel cost, fuel related

costs are treated as variable or energy related costs.

4.3.2.3 The method to be adopted for generation cost classification is explained below:

o System Load Factor Approach - treats all the generation costs in

proportion to the system load factor as energy related and the remaining

as demand related.

o Average Approach - classifies fixed costs of generation into demand and

energy related using an arbitrary ratio, say 50:50. The variable costs are

classified as energy costs.

o Marginal Cost Approach - usually takes into account market prices of

capacity and energy to classify fixed as well as variable costs.

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o Specific Resource Approach - uses different classification approach for

each resource (or plant); say 100% demand related for peaking units.

o Specific Expenditure Approach - classifies each expenditure item using

one of the above methods.

4.3.2.4 However, the method to be adopted will be finalised based on the availability

and the quality of the data.

4.3.3 Classification of Transmission Costs

4.3.3.1 The transmission system is designed to handle certain peak demand and as such

the costs are fixed in nature & as such they can be entirely treated as demand

related. the methods of classification are as follows –

o 100% Demand Related – Simple but ignores that some of the

transmission investment is made partly to facilitate energy transfer from

generating stations or import/export of energy ;

4.3.4 Classification of Distribution Costs

4.3.4.1 The distribution system apart from serving the demand also provides various

services to the customers such as metering, billing, break down repair etc.

Hence, distribution costs need to be classified as partly demand related and

partly customer related;

o Distribution related components like meters could be considered 100%

consumer related;

o Distribution assets that are used by a single consumer (e.g., Service Lines)

and cost associated with it could be classified as entirely consumer

related;

o 100% Demand Related - classifies all other costs as entirely demand

related on the rationale that distribution networks are set up to meet the

local maximum demands;

o Partly Demand and Customer Related - attempts to work out appropriate

ratios for each component of distribution costs for classification into

demand related and customer related costs;

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4.3.4.2 The distribution system apart from serving the demand also provides various

services to the customers such as metering, billing, break down repair etc.

Hence, other distribution costs need to be classified as partly demand related

and partly customer related.

4.3.4.3 The distribution costs such as repair and maintenance, employee cost &

administrative and general expenses have been equally apportioned (50:50) into

customer cost and demand related costs, as these vary with the number and the

type of customer as well as with their demand. Rest of the distribution expenses

are classified into demand related as they are only dependent on how much

demand needs to be cater and not on number of consumers.

Table 1: Cost Classification and Functionalisation

Cost Classification Explanation Functions Cost Classification

Demand

Triggered by peak

demands and Fixed

in nature

Power Purchase Demand Related

Energy Related

Energy Vary with volume of

energy increased

Transmission Demand Related

Customer

Depend on number

and type of

consumer served

Distribution Demand Related

Consumer Related

4.3.5 Demand related costs will include a major portion of deprecation, interest on capital

borrowings, income tax, RoR etc. Customer related costs generally include R&M

expenses, Employee costs, A&G expenses, Bad debts, interest on consumer security

deposits & other debits that are directly attributable to consumers.

4.3.6 Unless a detailed study of each these costs and their relation to demand, energy and

customer functions are identified, true classification of costs may not possible.

However, for the purpose this study, given the constraints, an effort has been made

to properly classify the costs. Classification of fixed assets is generally made on the

basis of nomenclature of the fixed assets and judgement.

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4.3.7 It is submitted that there are no set of prescribed rules for functionalisation and

classification of costs. It depends on the experience and judgement of the utility to

classify costs in the best manner possible.

4.4 Allocation of Costs:

4.4.1 The functionalised and classified costs are then allocated to various customer classes

of the utility based on allocation factors derived from demand, consumption of

energy and number of customers such as Energy usage and a measure of demand

(peak, average etc.), Load Pattern, etc. Such allocation arrives at the cost of service

for each customer class.

4.4.2 The classified costs may be allocated on the basis on time differentiated allocation

factors. The energy and demand related costs are split into several costing periods.

The energy usage and a measure of demand (peak, average etc.) within such periods

form the basis for allocation of costs.

4.4.3 The total revenue from each of the customer classes together with the cost of

service so derived reflects upon the adequacy of current tariffs and the level of cross

subsidies between classes existent in the utility’s system.

4.4.4 Load profile of each category of consumers

4.4.4.1 In developing the profile, the following activities are required to be considered:

o Identification of typical load curves for each consumer category across

the company. This will be done on the basis of selection of statistically

significant samples to eliminate geographical bias. This would be used to

analysis the load curves, duration and consumption pattern, which can

then be extrapolated to the population.

o Based on load curves, load duration and consumption of particular

feeder, a profile of a particular consumer category is assessed.

o Determination of coincident peak demands for various categories will be

carried out. This is a method wherein the coincidences of the consumer

category peak demand to that of TANGEDCO coincident demand at the

time of system peak for the State as a whole.

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4.4.5 Diversity Factor

4.4.5.1 Diversity factor is the ratio of peak demand to connected/contracted load.

4.4.5.2 The sample feeders need to be identified for arriving at diversity factors for

Residential, LT Industrial, Public Water Works and Agricultural categories. The

diversity factor has been assumed for many categories based on the number of

hours of consumption and the power supply position.

4.4.6 Allocation of Demand Related Costs

4.4.6.1 The choices for allocation criteria for demand related costs presents a number of

options that may have significant impact on the cost allocation to various classes.

The choice will depend upon data availability, characteristics and constraints

associated with TANGEDCO and the objectives of the study. The following are the

allocation criteria for demand related costs –

4.4.6.2 Range of Methods-

• Co-incident Peak Contribution

The category coincident demand or contribution to the system peak demand

may be defined as the demand in MW for each category of customer that occurs

at the time of the system’s peak demand. The sum of all such demand for every

customer category plus losses will be equal to the peak demand of the system.

• Non-Coincident Peak

The non - coincident demand may be defined as the demand in MW for each

category of customer regardless of when it happens. This non-coincident

demand will be greater than or equal to the category’s contribution to the

system’s maximum demand. Thus, the sum of all such demand for every

customer category will be greater than the peak demand of the system.

• Average and Excess

This method allocates demand related cost to the customer category using

factors that combine the category average demand and excess demand. Excess

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demand for a category is defined as –Category Excess Demand = Non-Coincident

Demand – Average Demand The method uses two factors for allocation. The first

component, or contribution to average, is the proportion of category’s average

demand to the system average demand times the system load factor.

Contribution to Average = (Category Average Demand/System Average

Demand) * System Load Factor.

The second component, or contribution to excess, reflects the proportion of the

excess demand (non coincident peak demand minus the average demand) of the

category to the sum of excess demand of all categories. The advantage of the

said approach is that coincident peak demand for a category is not required.

Contribution to Excess = (Category Excess Demand/ S Category Excess

Demand) * (1 – System Load Factor)

4.4.6.3 Choice of Methods

• All energy related costs have been allocated on the basis of the class-wise energy

consumption. All customers’ related costs have been allocated on the basis of

number of customers with category wise weights. The appropriate allocation

criteria for demand related costs are as follows –

Demand related power purchase costs

• The power purchase, serves the entire system and further investments are

triggered by increase in the peak demand of the system as a whole. Hence,

category co-incident peak demand is the appropriate criteria for allocation of

such costs. However, in case the data with regards to the category co-incident

peak are not available, the Average and Excess method as discussed earlier will

be considered as a suitable alternative.

Demand related other distribution costs

• The distribution network services local maximum demands and investments are

triggered by the local (in other words, non co-incident) peaks in demand.

Therefore, the category non co-incident peak demand for each class is the most

appropriate basis for allocation of demand related other distribution costs.

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Demand related Total Distribution costs

• Allocation factors for demand related total distribution costs will be worked out

based on weightages of power purchase and other distribution costs.

4.4.7 Allocation of Energy Related Costs

Energy related costs shall be allocated in the ratio of energy consumed by the

customer classes. The energy consumed shall include sales to categories and

allocated losses to such categories.

4.4.7.1 Allocation of Losses

Though sales to each of the classes shall be easily available, but allocation of losses

shall require considerable judgment. The allocation of technical losses is largely

dependent upon the voltage at which a customer category is connected. However,

before allocating technical losses, commercial losses shall be allocated to various

categories. The technical losses shall then be allocated in the ratio of sales plus

commercial losses for a category.

Determination of Technical & Commercial Losses

The total transmission and distribution losses of TANGEDCO for FY 2010-11 were

20.91% including both technical and commercial losses. Distribution Losses (Total

Losses -Transmission Losses) shall be broken up into technical and commercial

losses. Technical Losses shall be further broken up into HT and LT level losses.

Allocation of Commercial Losses

Commercial losses are determined as the difference between total losses and

technical losses. The commercial losses shall be allocated to the customer categories

in ratio of sales. Thus, no commercial losses shall be allocated to the energy

transferred at lower voltage level as the consumers using such energy are not

responsible for commercial losses at the higher voltage.

Allocation of Technical Losses

Technical losses at HV and LV levels are allocated to the categories in ratio of sales to

customer categories connected at that voltage and energy transferred to the

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immediate lower voltage level.

The above method for allocation of technical losses shall be done in two steps.

• Firstly, the losses shall be allocated to various voltages levels in the ratio

of voltage level sales and transfer (to next category).

• Then, the losses allocated to various voltage levels shall be allocated to

the respective categories in the ratio of category sales.

4.4.8 Allocation of Customer related Costs

Customer related costs, primarily, include the costs of providing servicing other than

supply of electricity, namely – metering, billing, collection, fault repair etc. These

costs, though directly relate to the number of customers in a particular category,

vary significantly with across categories. For instance, the per customer servicing

costs for HT Industrial category will be much higher than that for a Residential

category customer.

Category-wise Customer Weightages

4.4.8.1 To address the variance in per customer service costs across categories, category

wise weight-ages shall be derived to determine allocation factors for customer-

related costs.

4.4.8.2 The weight-ages shall be a function of two parameters - Sales per Customer and

Load per Customer.

4.4.8.3 The average of these two ratios for each category shall give the ‘Category Wise

Customer Weightage’.

4.4.8.4 The minimum & maximum limit for such ratios will be set at 1 and 200

respectively. The average of these two ratios for each category gives the

‘Category Wise Customer Weightage’.

4.5 Approach for segregation of cost

4.5.1 Cost of service study may also be conducted using forecasts for costs, customer data

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Category 1

Category 2

Category 3

Category 4

Allocation

Demand Related

Category 1

Category 2

Category 3

Category 4

Allocation

Energy Related

Classification

Generation

Category 1

Category 2

Category 3

Category 4

Allocation

Demand Related

Classification

Transmission

Category 1

Category 2

Category 3

Category 4

Allocation

Demand Related

Category 1

Category 2

Category 3

Category 4

Allocation

Customer/Service Related

Classification

Distribution

Functionalisation

Costs

and load patterns. The cost of service so derived may provide an input into tariff

design. Together with the desired level of tariffs for each category, cost of service

can clearly define the level of subsidies required for each category and the system as

a whole.

4.5.2 The methods for functionalisation, classification and allocation of costs are as varied

as there are utilities each producing a different result. The fact that there is no set

methodology requires careful selection and regular update of the same in line with

the changing characteristics of the utility and objectives of the study.

4.5.3 The Figure given below indicates the flowchart for Cost of Service study;

Figure 1: Computation of Cost of Supply

4.6 Basis for determination of Cost to Service

4.6.1 Cost for FY 2010-11

4.6.1.1 Even though TANGEDCO has come into existence from 1st

November 2010 due to

segregation of erstwhile TNEB and as per the provisional transfer scheme

notified by GoTN on 19th

October 2010 and 2nd

January 2012, for calculation of

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Cost of Supply, the financial data related to whole FY 2010-11 is considered by

clubbing Profit & Loss account for 7 months and 5 months.

4.6.1.2 Costs as per audited accounts of FY 2010-11 shall be taken as the base for

determination of category wise cost of service for TANGEDCO;

4.6.1.3 The revenue from sale of power to other States and Puducherry has been

adjusted in the variable cost of power purchase and therefore the Revenue from

such sale of power to Other States and Puducherry has been deducted from

variable cost to determine the exact cost to be allocated to consumers.

4.6.1.4 Such costs shall be broken up into Generation, Power Purchase, Transmission

and Distribution costs. The details of the cost to be allocated for FY 2010-11 has

been identified as below:

Table 2: Profit & Loss Statement for FY 2010-11

PROFIT & LOSS STATEMENT

(Rs. in Crores)

INCOME

1 Revenue 58,446.15 20,644.42

2 Non-Tariff Income 544.29

3 Other Income 452.33

4 Sale to Other States and Puducherry

Total Income 58,446.15 21,641.04

EXPENDITURE

5 Cost of Power Purchased 73,961.57 25,143.15

'- Fixed Power Purchase Cost 3,453.91

'- Variable Power Purchase Cost 21,901.43

Less: Sales to Other States and Puducherry (212.18)

6 Other Expenditure 8,914.53

Operation & Maintenance Expenses 4,495.89

Depreciation 786.14

Interest and Financial Charges 3,591.15

Provision for bad debt 41.34

Income Tax

Expenses Capitalized 351.17

7 Total EXPENDITURE (4+5) 33,706.51

8 Return on Equity 356.69

Net prior period charges/Credit 848.66

9 Profit/Loss before tax (6-11) (13,270.82)

MUs 2010-11ParticularsSr. No.

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4.6.2 Category wise sales and revenue

4.6.2.1 The tariff categories wise sales have been regrouped in the following categories –

Table 3: Consumer Category of TANGEDCO

Particulars

HT Category

I-A Industries

I-B Railway Traction

II-A Govt. Educational Institution etc.

II-B Private Educational Inst. Etc

II-C Place of Worship

III Commercial

IV Lift Irrigation

LT Category

I-A Domestic

I-C LT bulk supply

II-A Public Lighting and Water Supply

II-B-1 Govt. & Govt. Aided Education Institutions etc.

II-B-2 Private College etc

IIC Places of Public Worship

IIIA 1 Cottage and Tiny Industries

IIIA 2 Power Looms

IIIB L.T. Industries

V L.T. Commercial

VI Temporary supply

4.6.3 Transmission and Distribution Losses

4.6.3.1 Transmission and Distribution losses will be bifurcated into technical and

commercial losses as explained in para 4.4.7.1.

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5. DEFINITIONS

5.1 System Peak Demand (Restricted)

Maximum demand (MW), in the utility’s system, during a period measured as the

sum of generation from all the sources.

5.2 Co-incident Peak Demand1

Co-incident peak demand or contribution to system peak demand is the demand for

a customer category (Domestic, Industrial etc) occurring at the time of system peak

demand. The sum of co-incident peak demands of all customer categories is equal to

the system peak demand.

5.3 Non Co-incident Peak Demand2

Non co-incident peak demand is the peak demand for a category during a period.

Such a peak may or may not occur at the time of system peak demand. Hence, the

non-coincident peak demand may be greater than or equal to the co-incident peak

demand for a category.

5.4 Connected Load

Connected load is the sum of all the electricity consuming items (Appliances,

machines, motors etc) connected to the distribution system of the utility. Connected

load may be defined for the entire system, a particular unit of the utility or for

customer categories.

5.5 Contracted Demand

Contracted demand is agreed upon by the buyer as the maximum demand that the

buyer will have at any point in time during the contract period. The seller agrees to

make power available to serve such demand.

1 Coincident Peak Demand for each category – TANGEDCO serves the customers through feeders with mixed load, i.e., a feeder may

serve customers from various categories. Such a situation makes it difficult to determine Coincident peak demand (Contribution to system

peak demand). 2 Non-coincident peak demand can be estimated applying the diversity factor to the connected load for each category. Calculations are

provided in Annexure 2

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5.6 System Load Factor

The ratio of the average demand to system peak demand, it is calculated as the ratio

of total number of units consumed in the system during a period to that had the

demand been at system peak throughout the same period.

5.7 Category Load Factor

The ratio of the average demand to non co-incident peak demand, it is calculated as

the ratio of total number of units consumed by the category during a period to that

had the category demand been at non co-incident peak throughout the same period.

5.8 Diversity Factor

Usually measured at the feeder level, it is the ratio of non co-incident peak to

connected load.

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6. CALCULATION OF EXPENSES

Classification of costs involves identification of costs as demand related, energy related and

customer related, based on some notion of cost causation. Demand-related costs are those

triggered by peak demands imposed on the system. Energy-related costs are related to the

level of energy production. Customer costs vary according to the number and type of

customers.

6.1 Classification of Power Purchase Expenses

Power purchase costs are identified to be energy as well as demand related as the utility

should not only be able to supply the energy required over a period of time but must also

install or purchase sufficient capacity to meet the peak demand of the system. The power

purchase cost of TANGEDCO comprises of fixed and variable charges whereby the cost of

generation of own generating station as specified in the profit & loss account has been

considered as variable cost. Also, the power purchase cost has been segregated in variable

cost and the fixed cost of the total power purchase cost3. The fixed cost is classified as

demand related whereas the variable as energy related.

Table 4 – Classified Power Purchase Expenses for FY 2010-11

Rs. in Crores

Particulars

Power

Purchase

Cost

Demand

Related

Energy

Related

Customer

Related

Power Purchase Cost

- Fixed Cost 3,454 3,454 - -

- Variable Cost 21,689 - 21,689 -

Classified Power

Purchase Costs

25,143 3,454 21,689 -

6.2 Classification of Other Distribution Expenses

Other distribution costs are classified as either demand related or customer related or a

combination of the two. Other distribution related components like meters and Distribution

assets that are used by a single customer (e.g., Service Lines) could be classified as 100%

customer related. The costs associated with such items can also be classified as entirely

3 The power purchase is classified as demand and energy based on the structure of fixed charges and energy

charges in power purchase bill of FY 2010-11.

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customer related.

Distribution costs other than those entirely customer related may be classified using the

following methods –

� 100% demand related approach classifies all other costs as entirely demand related

on the rationale that distribution networks are set up to meet the local maximum

demands.

� Partly demand and partly customer related approach attempts to work out

appropriate ratios for each component of distribution costs for classification into

demand related and customer related costs. The rationale for this approach is that

the extent of distribution lines, especially in a Universal Service Obligation scenario,

depends upon the location and number of customers. Hence, a component of

customer related distribution cost exists.

The distribution system apart from serving the demand also provides various services to the

customers such as metering, billing, break down repair etc. Hence, other distribution costs

need to be classified as partly demand related and partly customer related.

Table 5: Classified Distribution Expenses

Demand

Related

Energy

Related

Customer

related

Low Tension

Operation & Maintenance Expenses 4,495.89 2,247.95 - 2,247.95

Depreciation 786.14 786.14 -

Interest and Financial Charges 3,591.15 3,591.15 -

Provision for bad debt 41.34 41.34 -

Income Tax 0.00 0.00 -

Total Expenditure (1 to 5) 8,914.53 6,666.58 - 2,247.95

Return on Equity 356.69 356.69

Expenses Capitalized 351.17 175.59 - 175.59

Classified Distribution Costs 8,920.05 6,847.69 - 2,072.36

Classification

Rs. in Crores

2010-11Categories

The distribution costs such as repair and maintenance, employee cost & administrative and

general expenses have been equally apportioned (50:50) into customer cost and demand

related costs, as these vary with the number and the type of customer as well as with their

demand. Rest of the distribution expenses are classified into demand related as they are

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only dependent on how much demand needs to be catered and not on number of

consumers

6.3 Allocation of demand related cost

6.3.1 Demand related power purchase costs

The power purchase, serves the entire system and further investments are triggered

by increase in the peak demand of the system as a whole. Hence, category co-

incident peak demand is the appropriate criteria for allocation of such costs.

However, due to non-availability of the data with regards to the category co-incident

peak, the Average and Excess method as discussed earlier is a suitable alternative.

Table 6: Category-wise Average & Excess Demand (MW)

MW

Categories

Non

Coincident

Demand

Average

Demand

Excess

Demand

Low Tension 22,333.46 5,862.21 16,471.25

LT I A- Domestic, handloom,Nutirition centres etc. 11,240.84 2,495.43 8,745.41

LT I B-Huts services 72.22 54.52 17.70

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 2.73 2.28 0.45

LT II A- Local body(Vil lage panchayat,town panchayat, Muncipality &corporation) 336.52 247.16 89.37

LT II B(1)-Govt.Educational Instititions 44.09 31.33 12.76

LT II B(2)-Private Educational Institutions 94.49 47.00 47.49

LT II C-Place of public worship 48.04 15.11 32.93

LT III A(1)-Cottage &tiny Industries 116.04 104.03 12.01

LT III A(2)-Power loom 289.53 126.29 163.24

LT III B- Industries 3,981.21 623.81 3,357.40

LT IV-Agriculture 2,688.84 1,445.10 1,243.74

LT V-Commercial 3,414.01 667.09 2,746.93

LT VI-Temporary supply 4.89 3.07 1.82

High Tension 5,387.76 2,575.18 2,812.58

Industries 4,374.69 2,116.83 2,257.86

HT I B-Railway Traction 186.58 47.32 139.27

HT II A-Govt.educational Institutions 49.65 45.99 3.67

HT II B-Private EducationalInstitutions, Hostels 173.78 107.30 66.48

Worship 5.71 4.53 1.18

HT III - Commercial 591.76 251.00 340.77

HT IV- Lift Irrigation and cooperative societies 5.58 2.22 3.36

Total 27,721.22 8,437.39 19,283.83

Based on the above allocation of category-wise average and excess demand, the

allocation factor has been determined for demand related power purchase costs as

outlined in the following table:

Table 7 - Allocation Factors for Demand Related Power Purchase Costs

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Categories

Average

Demand

Component

for Allocation

(%)

Excess

Demand

Component

for Allocation

(%)

Total

Allocation

Factor (%)

Low Tension 56.78% 15.62% 72.39%

LT I A- Domestic, handloom,Nutirition centres etc. 24.17% 8.29% 32.46%

LT I B-Huts services 0.53% 0.02% 0.54%

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 0.02% 0.00% 0.02%

LT II A- Local body(Village panchayat,town panchayat, Muncipality &corporation) 2.39% 0.08% 2.48%

LT II B(1)-Govt.Educational Instititions 0.30% 0.01% 0.32%

LT II B(2)-Private Educational Institutions 0.46% 0.05% 0.50%

LT II C-Place of public worship 0.15% 0.03% 0.18%

LT III A(1)-Cottage &tiny Industries 1.01% 0.01% 1.02%

LT III A(2)-Power loom 1.22% 0.15% 1.38%

LT III B- Industries 6.04% 3.18% 9.22%

LT IV-Agriculture 14.00% 1.18% 15.18%

LT V-Commercial 6.46% 2.60% 9.07%

LT VI-Temporary supply 0.03% 0.00% 0.03%

High Tension 24.94% 2.67% 27.61%

Industries 20.50% 2.14% 22.64%

HT I B-Railway Traction 0.46% 0.13% 0.59%

HT II A-Govt.educational Institutions 0.45% 0.00% 0.45%

HT II B-Private EducationalInstitutions, Hostels 1.04% 0.06% 1.10%

Worship 0.04% 0.00% 0.04%

HT III - Commercial 2.43% 0.32% 2.75%

HT IV- Lift Irrigation and cooperative societies 0.02% 0.00% 0.02%

Total 81.72% 18.28% 100.00%

6.3.2 Demand related other distribution costs

The distribution network services local maximum demands and investments are

triggered by the local (in other words, non co-incident) peaks in demand. Therefore,

the category wise non co-incident peak demand

for each class is the most

appropriate basis for allocation of demand related other distribution costs. The same

is outlined in Table 8.

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Table 8 - Allocation factors for Demand Related Other Distribution Costs

Low Tension 80.56%

LT I A- Domestic, handloom,Nutirition centres etc. 40.55%

LT I B-Huts services 0.26%

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 0.01%

LT II A- Local body(Village panchayat,town panchayat, Muncipal ity &corporation) 1.21%

LT II B(1)-Govt.Educational Instititions 0.16%

LT II B(2)-Private Educational Institutions 0.34%

LT II C-Place of public worship 0.17%

LT III A(1)-Cottage &tiny Industries 0.42%

LT III A(2)-Power loom 1.04%

LT III B- Industries 14.36%

LT IV-Agriculture 9.70%

LT V-Commercial 12.32%

LT VI-Temporary supply 0.02%

High Tension 19.44%

Industries 15.78%

HT I B-Rai lway Traction 0.67%

HT II A-Govt.educational Institutions 0.18%

HT II B-Private EducationalInstitutions, Hostels 0.63%

Worship 0.02%

HT III - Commercial 2.13%

HT IV- Lift Irrigation and cooperative societies 0.02%

Total 100.00%

ParticularsAllocation

Factors

6.3.3 Demand related Total Distribution costs

Allocation factors for demand related total distribution costs is worked out based on

weightages of power purchase and other distribution costs. The allocation factors for

demand related total distribution costs are as given in Table 9.

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Table 9 - Allocation factors for Demand Related Total Distribution Costs

Particulars

Demand

Related

Allocation

Low Tension 77.93%

LT I A- Domestic, handloom,Nutirition centres etc. 37.94%

LT I B-Huts services 0.35%

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 0.01%

LT II A- Local body(Vil lage panchayat,town panchayat, Muncipality &corporation) 1.62%

LT II B(1)-Govt.Educational Instititions 0.21%

LT II B(2)-Private Educational Institutions 0.39%

LT II C-Place of public worship 0.17%

LT III A(1)-Cottage &tiny Industries 0.61%

LT III A(2)-Power loom 1.15%

LT III B- Industries 12.71%

LT IV-Agriculture 11.46%

LT V-Commercial 11.27%

LT VI-Temporary supply 0.02%

High Tension 22.07%

Industries 17.99%

HT I B-Railway Traction 0.65%

HT II A-Govt.educational Institutions 0.27%

HT II B-Private EducationalInstitutions, Hostels 0.78%

Worship 0.03%

HT III - Commercial 2.33%

HT IV- Lift Irrigation and cooperative societies 0.02%

Total 100.00%

6.4 Allocation of Energy related cost

Energy related costs are allocated in the ratio of energy consumed by the customer classes.

The energy consumed includes sales to categories and allocated losses.

Allocation of Losses

Though sales to each of the classes are easily available, allocation of losses requires

considerable judgement. The allocation of technical losses is largely dependent upon the

voltage at which a customer category is connected. However, before allocating technical

losses, commercial losses are allocated to various categories. The technical losses are then

allocated in the ratio of sales plus commercial losses for a category.

6.4.1 Determination of Technical and Commercial Losses

The total distribution loss of TANGEDCO is 20.91% including both technical and commercial

losses which are considered in line with the tariff petition and includes transmission and

distribution loss. The technical losses of TANGEDCO distribution system are 18.12%. The

technical losses on the basis of actual network data are broken up into HT and LT level

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losses whereby balance LT technical loss is considered as 80% of the balance loss and

accordingly the HT losses are 6.95% and LT losses are 11.17%. The remaining losses are

taken commercial distribution losses. The breakup of the same is as below –

Table 10 – Losses at TANGEDCO for FY 2010-11

Total Technical Losses 18.12%

HT 6.95%

LT 11.17%

Total Commercial Losses 2.79%

Total Losses in the system 20.91%

6.4.2 Allocation of Commercial Losses

Commercial losses are determined as the difference between total losses and

technical losses. The commercial losses are allocated to the customer categories in

ratio of the number of units assessed in theft (category wise). In other words, no

commercial losses are allocated for the energy transferred to the lower voltage level,

as the consumers using such energy are not responsible for commercial losses at the

higher voltage.

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Table 11 – Allocation of Commercial Losses

Categories Sales (MU)

Allocation

Factor for

Commercial

Losses

Commercial

Losses (MU)

Low Tension 38,173 65.31% 1,348.71

LT I A- Domestic, handloom,Nutirition centres etc. 16,249 27.80% 574.12

LT I B-Huts services 355 0.61% 12.54

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 15 0.03% 0.53

LT II A- Local body(Village panchayat,town panchayat, Muncipality &corporation) 1,609 2.75% 56.86

LT II B(1)-Govt.Educational Instititions 204 0.35% 7.21

LT II B(2)-Private Educational Institutions 306 0.52% 10.81

LT II C-Place of public worship 98 0.17% 3.48

LT III A(1)-Cottage &tiny Industries 677 1.16% 23.93

LT III A(2)-Power loom 822 1.41% 29.06

LT III B- Industries 4,062 6.95% 143.52

LT IV-Agriculture 9,410 16.10% 332.47

LT V-Commercial 4,344 7.43% 153.48

LT VI-Temporary supply 20 0.03% 0.71

High Tension 20,273 34.69% 716.30

Industries 16665 28.51% 588.80

HT I B-Railway Traction 372.5 0.64% 13.16

HT II A-Govt.educational Institutions 362.037 0.62% 12.79

HT II B-Private EducationalInstitutions, Hostels 844.753 1.45% 29.85

Worship 35.65 0.06% 1.26

HT III - Commercial 1976 3.38% 69.82

HT IV- Lift Irrigation and cooperative societies 17.47 0.03% 0.62

Total 58446.15 100.00% 2,065.01

6.4.3 Allocation of Technical Losses

Technical losses at HV and LV levels are allocated to the categories in ratio of sales to

customer categories connected at that voltage and energy transferred to the

immediate lower voltage level. For instance, if at HV level sale to HV Industry is 20

MU while the sales to other categories at HV level is 5 MU and the transfer to LV

level is 75 MU – 20% of the losses at HV level will be allocated to HV Industry

category.

The above method for allocation of technical losses is done in two steps. Firstly, the

losses are allocated to various voltages levels in the ratio of voltage level sales and

transfer (to next category). Then, the losses allocated to various voltage levels are

allocated to the respective categories in the ratio of category sales.

Table 12 – Allocation of Technical Losses

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MUs

Particulars HT LT Total

Percent 6.95% 11.17% 18.12%

Losses to be allocated 5,140.33 8,260.03 13,400.36

LT System

Sales 0.00 38,172.74 38,172.74

Commercial losses 0.00 1,348.71 1,348.71

Technical losses 0.00 8,260.03 8,260.03

Input to LT System 0.00 47,781.48 47,781.48

Allocation of LT Technical Losses 0.00 8,260.03 8,260.03

HT System

Sales 20,273.41 0.00 20,273.41

Commercial losses 716.30 0.00 716.30

Input to LT System 0.00 47,781.48 47,781.48

Input to HT System 20,989.71 47,781.48 68,771.19

Technical losses in HT system 5,140.33 0.00 5,140.33

Allocation of HT Technical Losses 1,568.88 3,571.45 5,140.33

-

Technical Losses Allocated to Customer Categories 1,568.88 11,831.47 13,400.36

Based on the above allocation of technical and commercial losses, the detailed

allocation of losses to each category of consumers is outlined below:

Table 13 – Allocation of Losses to categories

Categories Sales (MU)Commercial

Losses (MU)

Technical

Losses (MU)

Total Energy

Input into the

system (MU)

Low Tension 38,172.74 1,348.71 11,831.47 51,352.93

LT I A- Domestic, handloom,Nutirition centres etc. 16,249.41 574.12 5,036.43 21,859.96

LT I B-Huts services 355.00 12.54 110.03 477.57

LT I C -LT Bulk supply,Rai lway colonies, Defence colonies etc. 14.86 0.53 4.61 19.99

LT II A- Local body(Vil lage panchayat,town panchayat, Muncipality &corporation) 1,609.40 56.86 498.83 2,165.09

LT II B(1)-Govt.Educational Instititions 204.02 7.21 63.24 274.47

LT II B(2)-Private Educational Institutions 306.04 10.81 94.85 411.70

LT II C-Place of public worship 98.36 3.48 30.49 132.32

LT III A(1)-Cottage &tiny Industries 677.42 23.93 209.96 911.32

LT III A(2)-Power loom 822.35 29.06 254.88 1,106.29

LT III B- Industries 4,062.06 143.52 1,259.02 5,464.60

LT IV-Agriculture 9,410.00 332.47 2,916.59 12,659.06

LT V-Commercial 4,343.84 153.48 1,346.35 5,843.67

LT VI-Temporary supply 19.98 0.71 6.19 26.88

High Tension 20,273.41 716.30 1,568.88 22,558.59

Industries 16,665.00 588.80 1,289.64 18,543.45

HT I B-Rai lway Traction 372.50 13.16 28.83 414.49

HT II A-Govt.educational Institutions 362.04 12.79 28.02 402.85

HT II B-Private EducationalInstitutions, Hostels 844.75 29.85 65.37 939.97

Worship 35.65 1.26 2.76 39.67

HT III - Commercial 1,976.00 69.82 152.92 2,198.73

HT IV- Lift Irrigation and cooperative societies 17.47 0.62 1.35 19.44

Total 58,446.15 2,065.01 13,400.36 73,911.52

6.4.4 Allocation of Energy Related Costs

Energy related costs are allocated to categories in the ratio of energy consumed. The

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energy consumed includes not only the sales but also the losses allocated to the

respective categories.

Table 14: Allocation Factors for Energy Related Costs

2010-11

Allocation

Factors

Low Tension 69.48%

LT I A- Domestic, handloom,Nutirition centres etc. 29.58%

LT I B-Huts services 0.65%

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 0.03%

LT II A- Local body(Village panchayat,town panchayat, Muncipality &corporation) 2.93%

LT II B(1)-Govt.Educational Instititions 0.37%

LT II B(2)-Private Educational Institutions 0.56%

LT II C-Place of public worship 0.18%

LT III A(1)-Cottage &tiny Industries 1.23%

LT III A(2)-Power loom 1.50%

LT III B- Industries 7.39%

LT IV-Agriculture 17.13%

LT V-Commercial 7.91%

LT VI-Temporary supply 0.04%

High Tension 30.52%

Industries 25.09%

HT I B-Railway Traction 0.56%

HT II A-Govt.educational Institutions 0.55%

HT II B-Private EducationalInstitutions, Hostels 1.27%

Worship 0.05%

HT III - Commercial 2.97%

HT IV- Lift Irrigation and cooperative societies 0.03%

Total 100.00%

Particulars

6.5 Allocation of Customer Related Costs

Customer related costs, primarily, include the costs of providing servicing other than

supply of electricity, namely – metering, billing, collection, fault repair etc. These

costs, though directly relate to the number of customers in a particular category,

vary significantly with across categories. For instance, the per customer servicing

costs for HT Industrial category will be much higher than that for a Residential

category customer.

6.5.1 Category Wise Customer Weightages

To address the variance in per customer service costs across categories, category

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wise weight-ages have been derived to determine allocation factors for customer-

related costs. The weight-ages are a function of two parameters - Sales per Customer

and Load per Customer. Category wise parameters have been divided by average of

such parameter for arrive at a ratio. The minimum & maximum limit for such ratios

has been set at 1 and 200 respectively. The average of these two ratios for each

category gives the ‘Category Wise Customer Weightage’.

Table 15: Category wise Customer Weightage

Categories

Connected

Load

(MW)

Consumers Sales

Weight

(sales/

consumer)

Weight

(load/

consumer)

Average

Weight

Low Tension 39,395.13 22,611,491 38,173 -

LT I A- Domestic, handloom,Nutirition centres etc. 18,734.74 15,056,087 16,249 1.00 1 1.00

LT I B-Huts services 120.36 1,467,708 355 1.00 1 1.00

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 4.56 1,010 15 5.69 1 3.35

LT II A- Local body(Vil lage panchayat,town panchayat, Muncipality &corporation) 807.65 466,024 1,609 1.34 1 1.17

LT II B(1)-Govt.Educational Instititions 151.18 45,973 204 1.72 1 1.36

LT II B(2)-Private Educational Institutions 226.77 68,960 306 1.00 1 1.00

LT II C-Place of public worship 144.12 131,869 98 1.00 1 1.00

LT III A(1)-Cottage &tiny Industries 198.93 57,077 677 4.59 1 2.80

LT III A(2)-Power loom 496.33 124,026 822.3518 2.57 1 1.78

LT III B- Industries 5,308.29 359,819 4062.064 4.37 1 2.68

LT IV-Agriculture 8,066.53 1,999,237 9409.997 1.82 1 1.41

LT V-Commercial 5,121.02 2,820,301 4343.84 1.00 1 1.00

LT VI-Temporary supply 14.66 13,400 19.98068 1.00 1 1.00

High Tension 6,612.52 6,940 20273.41

Industries 5,146.70 5,091 16665 200.00 1 100.50

HT I B-Railway Traction 219.51 21 372.5 200.00 1 100.50

HT II A-Govt.educational Institutions 99.30 127 362.037 200.00 1 100.50

HT II B-Private EducationalInstitutions, Hostels 231.71 297 844.753 200.00 1 100.50

Worship 14.26 6 35.65 200.00 1 100.50

HT III - Commercial 887.64 1,387 1976 200.00 1 100.50

HT IV- Lift Irrigation and cooperative societies 13.39 11 17.47 200.00 1 100.50

Total 46,007.65 22,618,431 58446.15

6.5.2 Allocation of Customer Related Costs

Customer related as arrived at after Classification of Distribution Cost is allocated as

per the weight-ages derived.

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Table 16 – Allocation Factors for Customer related Costs

Low Tension 97.21%

LT I A- Domestic, handloom,Nutirition centres etc. 60.14%

LT I B-Huts services 5.86%

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 0.01%

LT II A- Local body(Village panchayat,town panchayat, Muncipality &corporation) 2.17%

LT II B(1)-Govt.Educational Instititions 0.25%

LT II B(2)-Private Educational Institutions 0.28%

LT II C-Place of public worship 0.53%

LT III A(1)-Cottage &tiny Industries 0.64%

LT III A(2)-Power loom 0.88%

LT III B- Industries 3.86%

LT IV-Agriculture 11.27%

LT V-Commercial 11.27%

LT VI-Temporary supply 0.05%

High Tension 2.79%

Industries 2.04%

HT I B-Railway Traction 0.01%

HT II A-Govt.educational Institutions 0.05%

HT II B-Private EducationalInstitutions, Hostels 0.12%

Worship 0.00%

HT III - Commercial 0.56%

HT IV- Lift Irrigation and cooperative societies 0.00%

Total 100.00%

ParticularsAllocation

Factors

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7. COST OF SERVICE

7.1 Cost of Service of each Category

Based on the above allocation factors, the cost of service each category has 3

elements, namely –

1. Demand Related Costs;

2. Energy Related Costs; and

3. Customer Related Costs;

Table 17 - Category wise Total Cost of Service (Rs. Crs)

Demand

Related

Energy

Related

Customer

RelatedTotal

Low Tension 7,764.75 15,701.35 1,807.41 25,273.51

LT I A- Domestic, handloom,Nutirition centres etc. 3,481.62 7,040.30 810.42 11,332.34

LT I B-Huts services 58.43 118.16 13.60 190.20

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 2.42 4.89 0.56 7.87

LT II A- Local body(Vil lage panchayat,town panchayat, Muncipality &corporation) 265.84 537.57 61.88 865.29

LT II B(1)-Govt.Educational Instititions 33.85 68.44 7.88 110.17

LT II B(2)-Private Educational Institutions 53.65 108.49 12.49 174.63

LT II C-Place of public worship 19.04 38.50 4.43 61.98

LT III A(1)-Cottage &tiny Industries 109.29 221.00 25.44 355.74

LT III A(2)-Power loom 147.79 298.85 34.40 481.05

LT III B- Industries 989.44 2,000.78 230.31 3,220.53

LT IV-Agriculture 1,627.68 3,291.39 378.88 5,297.96

LT V-Commercial 972.31 1,966.15 226.33 3,164.79

LT VI-Temporary supply 3.37 6.82 0.79 10.98

High Tension 2,961.18 5,987.90 689.28 9,638.35

Industries 2,428.62 4,911.00 565.31 7,904.94

HT I B-Railway Traction 63.31 128.03 14.74 206.08

HT II A-Govt.educational Institutions 48.15 97.36 11.21 156.71

HT II B-Private EducationalInstitutions, Hostels 118.23 239.08 27.52 384.83

Worship 4.82 9.75 1.12 15.70

HT III - Commercial 295.39 597.33 68.76 961.48

HT IV- Lift Irrigation and cooperative societies 2.65 5.35 0.62 8.62

Total 10,725.93 21,689.24 2,496.69 34,911.86

Particulars

2010-11

The above provides the total cost of service of each category. However for

calculation of Cost to Serve per consumer, the same is derived on the basis of Per

unit (energy, demand or customer as unit) cost of service for each category as under.

Table 18 – Category wise per unit Cost of Service

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Demand

Related

(Rs/Kwh)

Energy

Related

(Rs/Kwh)

Customer

Related

(Rs/Kwh)

Total Cost

(Rs/Kwh)

Low Tension

LT I A- Domestic, handloom,Nutirition centres etc. 2.14 4.33 0.50 6.97

LT I B-Huts services 1.65 3.33 0.38 5.36

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 1.63 3.29 0.38 5.29

LT II A- Local body(Vil lage panchayat,town panchayat, Muncipality &corporation) 1.65 3.34 0.38 5.38

LT II B(1)-Govt.Educational Instititions 1.66 3.35 0.39 5.40

LT II B(2)-Private Educational Institutions 1.75 3.55 0.41 5.71

LT II C-Place of public worship 1.94 3.91 0.45 6.30

LT III A(1)-Cottage &tiny Industries 1.61 3.26 0.38 5.25

LT III A(2)-Power loom 1.80 3.63 0.42 5.85

LT III B- Industries 2.44 4.93 0.57 7.93

LT IV-Agriculture 1.73 3.50 0.40 5.63

LT V-Commercial 2.24 4.53 0.52 7.29

LT VI-Temporary supply 1.69 3.41 0.39 5.49

High Tension

Industries 1.46 2.95 0.34 4.74

HT I B-Railway Traction 1.70 3.44 0.40 5.53

HT II A-Govt.educational Institutions 1.33 2.69 0.31 4.33

HT II B-Private EducationalInstitutions, Hostels 1.40 2.83 0.33 4.56

Worship 1.35 2.74 0.31 4.40

HT III - Commercial 1.49 3.02 0.35 4.87

HT IV- Lift Irrigation and cooperative societies 1.52 3.06 0.35 4.93

2010-11

Particulars

7.2 Conclusion

The cost of service study seeks to establish the adequacy of tariffs, category wise

cross subsidy in the system and provide a path for elimination of the same. The

results of the study also establish the cross subsidy surcharge applicable to open

access consumers. The table below compares the cost of service and average

realisation.

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Methodology for Carrying out

Cost to Serve Model

Table 19 – Cost of Service against Average Realisation

ParticularsCost of Service

(Rs/Kwh)

Average Realisation

(Rs/Kwh)

Gap

(Rs/Kwh)Gap %

Low Tension

LT I A- Domestic, handloom,Nutirition centres etc. 6.97 2.50 4.47 178.67%

LT I B-Huts services 5.36 0.50 4.85 961.17%

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 5.29 3.85 1.44 37.45%

LT II A- Local body(Village panchayat,town panchayat, Muncipality &corporation) 5.38 3.44 1.94 56.51%

LT II B(1)-Govt.Educational Instititions 5.40 4.75 0.65 13.72%

LT II B(2)-Private Educational Institutions 5.71 4.75 0.96 20.18%

LT II C-Place of public worship 6.30 4.20 2.10 49.94%

LT III A(1)-Cottage &tiny Industries 5.25 2.72 2.53 93.28%

LT III A(2)-Power loom 5.85 2.05 3.80 185.16%

LT III B- Industries 7.93 4.88 3.05 62.36%

LT IV-Agriculture 5.63 0.29 5.34 1814.85%

LT V-Commercial 7.29 6.62 0.67 10.08%

LT VI-Temporary supply 5.49 9.86 (4.37) -44.29%

High Tension

Industries 4.74 4.86 (0.11) -2.32%

HT I B-Railway Traction 5.53 4.81 0.72 14.97%

HT II A-Govt.educational Institutions 4.33 4.69 (0.36) -7.68%

HT II B-Privat+B2e EducationalInstitutions, Hostels 4.56 4.69 (0.13) -2.84%

Worship 4.40 3.30 1.10 33.38%

HT III - Commercial 4.87 6.88 (2.01) -29.28%

HT IV- Lift Irrigation and cooperative societies 4.93 0.51 4.42 858.16%

The graph below shows category-wise cost of service and average realisation of

TANGEDCO for FY 2010-11.

Figure 2 - Category Wise COS and Average Realization

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Methodology for Carrying out

Cost to Serve Model

8. WAY FORWARD

8.1 Way forward

Considering the study undertaken to determine the Cost to Serve categorywise and

voltagewise, the following conclusion will be able to be derived:

• Result into a movement towards the actual cost to serve pricing principle and will

introduce transparency in rate designing and hence in subsidy/ cross subsidy

assessment;

• Special attention may be shifted for allocating power purchase costs;

• Modify the total cost of power purchase on account of agriculture consumers

considering the average voltage deviations beyond permissible limit

• Aggregating the penalty levied on licensees due to poor quality supply and,

thereby, moderating the power purchase cost

• Will be useful for use of appropriate load curves and load research study for

assessment of power demand of consumer class

• Need to change the assets/expenditure accounting practices whereby Utilities

will have to maintain the voltage wise inventory of assets

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Methodology for Carrying out

Cost to Serve Model

ANNEXURE A - Category Wise Non Coincident Demand

The diversity factors derived from the sample of feeders and from available records are

applied to the total connected load of the respective categories to arrive the non-coincident

peak.

Table A1 – Category Wise Non-coincident Demand

CategoriesConnected

Load (MW)

Diversity

Factor

(%)

Non

Coincident

Peak Demand

Low Tension 39,395.13 22,333.46

LT I A- Domestic, handloom,Nutirition centres etc. 18,734.74 60.00% 11,241

LT I B-Huts services 120.36 60.00% 72.22

LT I C -LT Bulk supply,Railway colonies, Defence colonies etc. 4.56 60.00% 2.73

LT II A- Local body(Village panchayat,town panchayat, Muncipality &corporation) 807.65 41.67% 336.52

LT II B(1)-Govt.Educational Instititions 151.18 29.17% 44.09

LT II B(2)-Private Educational Institutions 226.77 41.67% 94.49

LT II C-Place of public worship 144.12 33.33% 48.04

LT III A(1)-Cottage &tiny Industries 198.93 58.33% 116.04

LT III A(2)-Power loom 496.33 58.33% 289.53

LT III B- Industries 5,308.29 75.00% 3,981.21

LT IV-Agriculture 8,066.53 33.33% 2,688.84

LT V-Commercial 5,121.02 66.67% 3,414.01

LT VI-Temporary supply 14.66 33.33% 4.89

High Tension 6,612.52 5,387.76

Industries 5,146.70 85.00% 4,374.69

HT I B-Railway Traction 219.51 85.00% 186.58

HT II A-Govt.educational Institutions 99.30 50.00% 49.65

HT II B-Private EducationalInstitutions, Hostels 231.71 75.00% 173.78

Worship 14.26 40.00% 5.71

HT III - Commercial 887.64 66.67% 591.76

HT IV- Lift Irrigation and cooperative societies 13.39 41.67% 5.58

Total 46007.65 27,721.22