1

Regional Energy Accounting, Disputes Mechanism and

Resolutions

-Rakesh Goyal & Asit Singh.-Executive Engineer,-SRPC, Bangalore

2

WHAT IS Regional Energy Account (REA) ?

• “ REA is Statement of Allocation, Availability,Energy Scheduled/ injected and drawn which forms the basis for payment/ receipt among the constituents”

3

Requirement of REA

• To be FAIR and EQUITABLE• To RECOVER DUES at the EARLIEST • TRANSPERANCY• Dispute Resolution• Reconciliation

RPCs have been entrusted with the responsibility of preparing REA at present

4

Scope of REA

Regional Energy Account

ISGS Other Regions

BeneficiariesTraders

CTU

5

Commercial Settlements

• Fixed/Capacity Charges• Variable/Energy Charges• Wheeling Charges• Ratio(s) in which above to be shared by

the beneficiaries.• Any other charges as been specified by

the competent authority from time to time like UI,Incentive, Transmission Charges etc.

6

Fixed Cost Elements

• Interest on Loan• Return on Equity• Depreciation• O&M (personnel, Lubricants, Chemical etc.)• Interest on Working Capital , IDC• Insurance, Taxes, etc.

(Independent of Energy produced)

7

Variable Cost Elements

• Primary Fuel Cost (Coal)

(depends on Energy produced)

• Secondary Fuel (oil)

8

PRE-REQUISITES

• Notify Two part tariff

• Signing of BPSA/PPA/BPTA

• Payment security mechanism (BG,LC, ESCROW etc.)

• Suitable Metering

• Scheduling mechanism

• Tele-metering/SCADA

9

Pre ABT REA

• Fixed and variable charges merged to make single rate in paisa/KWhr

• Charges to be paid by beneficiaries on the basis of energy drawal

• No weightage to Entitlement/schedule of various beneficiaries in a particular generator (Typically in SR)

• Sample REA

10

PRE ABT TARIFF MECHANISM - ProblemsAll inter-utility exchanges based on single flat paise/kWHThis rate neither change with time of the day i.e; peak/off-peak or system conditions(generation surplus or deficit)Do not discourage MW overdrawals by SEBs.They could avoid this by proper load management, run their own higher cost generator DGs,GTs durng contingenciesDo not induce power plant operator to back down generation during off-peak hoursNo financial compensation to any party for over stressing its power plants for assisting during contingenciesSEBs view this composite figure only and compare with their own generating stations for their dispatch decisionsISGS(pit head plant)with lower incremental costs used to back down before backing down their own costlier load center generatorsThis leads to perpetual operational and commercial disputes in the operation of region grid

11

Availability Based TariffAvailability Based Tariff

• With a view to promote overall economic operation of the power sector and to achieve improvement in operational parameter GOI felt that the existing tariff structure in power sector needs to be rationalized. Accordingly GOI proposed, for sale of electricity by generating companies to the beneficiaries, a three part tariff structure in viz. Capacity charge, Energy charge, Unscheduled interchanges (UI)

12

AVAILABILITY BASED TARIFF(ABT)(a) CAPACITY CHARGE(b) ENERGY CHARGE(c) ADJUSTMENT FOR DEVIATIONS

(UI CHARGE)

(a) = a function of Ex-bus MW availability of power plant for the day declared before the day starts x SEB’s % share

.(b) = MWh for the day as per ex=bus drawl schedule for the SEB

finalized before the day starts x Energy charge rate

(c) =Σ(Actual energy interchange in a 15 min time block – scheduled energy interchange for the time block) x UI rate for the time block.

TOTAL PAYMENT = (a) + (b)± ( c)

Advantages of ABT• Improved frequency and voltage• Economic despatch• Autonomy to the utility• Incentive for high plant availability,but no incentive to

over generation during off-peak hours• Technically and commercially right• Immediate solution for IPPs and Captives• True free market ; market forces decide the pool price• Pool price known on-line• Total transparency ; No regulator required• Simple practicable ; Meters already developed and

installed

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Flow chart of Accounting Procedure

Data from RLDC(on every Thursday for the

previous week)

Preparation of Energy Accounts by RPCs

Weekly UI and VARAccounts

(issued on every Tuesday)

Monthly REA(Issued during

1st week of month)

GOI/CERC orders/notifications

Board Decisions

Preparation of Generation ScheduleAnd drawal Schedule

Disputes Mechanism and Resolution

Hydro Generating Station Inter State Transmission

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Preparing final schedule

12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1noon

ISGS

SLDC

Despatch schedule

net Drawal

schedule

revision

revisionstation-wise MW/MWH capability

station-wise W/MWH entitlement

required Drawal

schedule

AM PM

RLDC

Despatch schedule starts

Drawalschedule starts

finalDespatch schedule

final Drawal

schedule

BACKBACK

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Data Required for Preparing these accounts – to be furnished by RLDC

• Declared Capability (DC) and Dispatch/generation Schedule (GS) – Annexure 1A

• Entitlement of various beneficiaries – Annexure 1B• Requisition by various beneficiaries – Annexure 1C• Any bilateral Trading under STOAC – Bilateral Files• Wheeling to/from other regions – Wheeling Files• Processed Meter (SEM) data – 15 min block wise actual

injection/drawal at various locations and reactive drawal/injection for a day – Raw SEM Data SEM Files

BACKBACK

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Weekly Account Contains

• Unscheduled Interchange (UI) charges

• Reactive energy charges

BACKBACK

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Monthly REA Contains

(a) Availability % for Capacity Charge recovery(b) Energy Scheduled for Energy Charges(c) Energy scheduled beyond target PLF for Incentive(d) Ratio for sharing of monthly Transmission Charge

s of CTU(e) Ratio for sharing of monthly RLDC fees and O&M

charges(f) Wheeling Charges for ISGS Power wheeled on sta

te owned inter state lines.(g) Energy Exchanged with other Regions(h) Energy scheduled under STOA

BACKBACK

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Unscheduled Interchange (UI) charges

• For Generators

- UI = Actual Generation – Generation Schedule

• For Beneficiaries

- UI = Actual Drawal – Ex-Periphery drawal Schedule

• For Other Regions

- UI = Actual Metered energy – Net Schedule at Interregional Periphery

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For the day: 0000 hrs. to 2400 hrs. Central Generating Stations

1 2 3

Ex-Bus Declared Capability x1 x2 x3(Forecast) ____ ____ ___

SEB-A’s share a1 a2 a3SEB-B’s share b1 b2 b3SEB-C’s share c1 c2 c3

For a particular 15 minute time block

SEB-A’s requisition a’1 a’2 a’3SEB-B’s requisition b’1 b’2 b’3SEB-C’s requisition c’1 c’2 c’3

___ ___ ___CGS’s schedule x1’ x2’ x3’

MW

Sample UI Calculation

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Issues involved in UI Accounting• If During the day of operation any constituent feels that

its schedule needs to be changed due to load crash/ tripping of generators etc. it can do so but revised schedule will be effective from 6th time block.

• UI is to be suspended during grid disturbance / transmission bottle neck

• No UI for non commercial units and other stations not covered under ABT (Typically Nuclear stations)

• Any generation up to 105% of the declared capacity in any time block and averaging up to 101% of the average DC over a day is allowed. If generation goes beyond this limit, RLDC will investigate and if gaming is found UI charges due to such extra generation shall be reduced to zero and the amount shall be adjusted in UI account of beneficiaries in ratio of their capacity share in that generating station

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Special Note for Gas Turbine Generating Station

• For the Gas turbine generating station or a combined cycle generating station if the average frequency for any time block, is 49.02<f<49.52Hz and Schedule generation is more than 98.5% of the declared capacity, the scheduled energy shall be deemed to have been reduced to 98.5% of the DC, and if average frequency for any time block, is below 49.02Hz and Scheduled generation is more than 96.5% of DC, the scheduled generation shall be deemed to have been reduced to 96.5% of the DC

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For the day: 0000 hrs. to 2400 hrs. Central Generating Stations

1 2 3

Ex-Bus Declared Capability x1 x2 x3(Forecast) ____ ____ ___

SEB-A’s share a1 a2 a3SEB-B’s share b1 b2 b3SEB-C’s share c1 c2 c3

For a particular 15 minute time block

SEB-A’s requisition a’1 a’2’ a’3SEB-B’s requisition b’1 b’2’ b’3SEB-C’s requisition c’1 c’2’ c’3

___ ___ ___CGS’s schedule x1’ x2’’ x3’

MW

Revised Schedules

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Actual (metered) injection of CGS-1 in the time block = X1 MWh.

Excess injection = (X1 – x1’ ) MWh.

4

Amount payable to CGS-1 for this =(X1-x1’) X UI rate for the block.

4

SEB-A’s scheduled drawl for time block = a’1+a’2’+a’3 = a’ MW (ex-ISGS Bus)

SEB-A’s NET drawal schedule = (a’ – Notional Transm. Loss) MW

= (a’ – Notional Transm. Loss) = A’ MWH

4

Actual (metered) net drawal of SEB-A during time block = A MWH

Excess drawal by SEB-A = (A-A’) MWh.

Amount payable by SEB-A for this = (A-A’) * UI rate for the block.

All above payments for deviations from schedules to be routed through a pool A/C operated by RLDC

SAMPLE UI ACCOUNT STATEMENT

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Variations in actual generation/drawal and scheduled generation /drawal are accounted through UI. This is a frequency linked charge which is worked out for each 15 minute time block.

Charges for all UI transaction, based on average frequency have following rate of paise per KWh from 01.01.03 up to 31.03.04.

UI rate (Paise per KWh)

Average Frequency of time block50.5 Hz. and above 0.0Below 50.5 Hz. and upto 50.48 Hz. 5.6Below 49.04 Hz. and upto 49.02 Hz. 414.4Below 49.02 Hz. 420.0Between 50.5 Hz. and 49.02 Hz. Linear in 0.02 Hz. step

Unscheduled Interchanges (UI)

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UI rate w.e.f 01.04.04 to 30.09.04 UI rate (Paise per KWh)

Average Frequency of time block50.5 Hz. and above 0.0Below 50.5 Hz. and upto 50.48 Hz. 8.0Below 49.04 Hz. and upto 49.02 Hz. 592.0Below 49.02 Hz. 600.0Between 50.5 Hz. and 49.02 Hz. Linear in 0.02 Hz. step

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• UI rate w.e.f 01.10.04

Average Frequency of time block (Hz,) UI rate (Paise per KWh) Below Not below Rate ----- 50.50 0.050.50 50.48 6.050.48 50.46 12.0----- ----- ----- ----- ----- ----- 49.84 49.82 204.049.82 49.80 210.049.80 49.78 219.049.78 49.76 228.0----- ----- ----- ----- ----- ----- 49.04 49.02 561.049.02 ----- 570.0(Each 0.02 Hz. Step is equivalent to 6.0 paise/kWh in the 50.5-49.8 Hz. Frequency range and to 9.0 paise/kWh in the 49.8-49.0 Hz. Frequency range).

570 9 P/Unit/0.02Hz210

049 49.8 50.5

6 P

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Energy transactions of UI from/to Pool

Over Gen. By ISGS-1

Under drawl by SEB-A

UI import/Export from IR-1

Under gen. By ISGS-2

No one to one correspondence

System frequency UI

RateRegional Pool

Over drawl by SEB-BUI Import/Export to IR-2

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Operation of Pool

Separate Pool a/cs operated by RLDCs on behalf of RPCs for UI, IRE and Reactive charges

Regional Pool

Payable by ISGS-2

Payable by SEB-BPayable/Receivable by IR-2

Receivable by ISGS-1Receivable by SEB-A Payable/ Receivable

by IR-1No one to one correspondence

No cross adjustments allowed between the constituents

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IRE Account

• UI Calculated for Inter Regional Exchange are calculated at different frequency rate so net payable will not be same as net receivable by other region.the difference will go to IRE Account Normally the flow of power will be from higher frequency to lower frequency so there will mostly be surplus in IRE account . This will be shared by the two region on 50:50 basis and will be adjusted towards transmission charges.

BACKBACK

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REACTIVE ENERGY CHARGE :

PAYABLE FOR :

1. VAR DRAWALS AT VOLTAGES BELOW 97%2. VAR INJECTION AT VOLTAGES ABOVE 103%

RECEIVABLE FOR:

1. VAR INJECTION AT VOLTAGES BELOW 97%2. VAR DRAWAL AT VOLTAGES ABOVE 103%

APPLIED FOR VAR EXCHANGES BETWEEN :

A) BENEFICIARY SYSTEM AND ISTS- THROUGH A POOL ACCOUNT

B) TWO BENEFICIARY SYSTEMS ON INTER-STATE TIES- BY THEMSELVES

RATE: @ Rs. 51.05/MVARh (from 1st April 2005)Basic Rate : 4 paise/kvArh ( for the year 2000-01 )

5% ESCALATION PER YEAR SAMPLE VAR ACCOUNT STATEMENT

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Issues in Reactive Energy charges

• Deficit in pool (SR & ER)-due to continuous High voltages in SR

• Surplus in Pool (NR &WR)

Utilization of Accruals

Disputes in payments between Beneficiaries for Reactive charges in Inter-state Lines

BACKBACK

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Capacity charge

• Capacity charge is based on Annual Fixed Charge and will be related to Availability of generating station. Availability means the readiness of the generating station to deliver ex-bus output expressed as a percentage of its rated ex-bus output capability.

• Target Avb. For Fixed charges recovery ( Notified by CERC )

• 100% recovery - if % Availability >=Target Availability• Pro-rata reduction

if %Avl<T.Avl.

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Calculation Of Availability

% Availability =i=1

N

DCi/ {NxICx(100-Auxn) }%10000

Where DCi = Average Declared Capacity for i th day of the period in MW N = Total no. of days during the period Auxn = Normative Auxiliary Consumption as % of gross Gen.

IC= installed capacity in MW

% Availability forms the basis for calculations

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Monthly Capacity charges receivable by an ISGS:1 st Month = (1xACC1)/122 nd Month = (2xACC2-1ACC1)/12….….12 th month = (12xACC12-11ACC11)/12where ACC1,ACC2…….ACC12 = Annual capacity charges corresponding to the cum. Availability up to the corresponding month.

Monthly Capacity charges payable by a beneficiary :1 st Month = (1xACC1xWB1)/122 nd Month = (2xACC2xWB2-1ACC1xWB1)/12….….12 th month = (12xACC12xWB12-11xACC11xWB11)/12where WB1,WB2…..WB12 = Weighted average % share up to the corresponding month.

BACKBACKExtract from SR REA

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Extract of SR REA

Apr-05

May-05

Apr-05

May-05

Apr-05

May-05

Apr-05

May-05

Apr-05

May-05

Apr-05

May-05

STATION / BENIFICIERY APTRANSCO KPTCL KSEB TNEB PONDY PG-HVDC GOA DNH

Daman & Diu

NTPC - RSTPS STAGE- I & II 32.25 19.86 14.72 25.24 3.06 0.11 3.57 0.95 0.24

NTPC - RSTPS STAGE- III 32.13 21.67 15.76 27.15 3.29

STATION / BENIFICIERY APTRANSCO KPTCL KSEB TNEB PONDY NLC MINES

NLC TPS II - STAGE-I 16.78 23.10 11.61 29.56 11.01 7.94

NLC TPS II - STAGE-II 22.79 23.34 12.31 33.14 2.47 5.95

NLC TPS I - EXPN. 0.00 27.27 18.52 50.42 3.79

NPC - MAPS 9.33 7.64 6.27 75.39 1.37

NPC - KGS 0.00 29.91 13.11 54.47 2.51

NTPC - TALCHER STAGE -II APTRANSCO KPTCL KSEB TNEB PONDY PG-HVDC

West Bengal Bihar

Jharkhand

01.05.05 to 03.05.05 21.34 21.32 14.00 28.54 3.59 0.26 6.17 3.60 1.18

04.05.05 to 31.05.05 24.13 23.99 17.49 30.54 3.59 0.26 0.00 0.00 0.00

99.489 90.907 99.489 90.710

93.410 93.319

82.038 82.038 81.638 81.638

93.649 93.649

84.429 75.251 84.291

93.612 90.932 92.982

98.543 93.224 93.224

CUMULATIVE PLF

( % )

98.634

99.405

PLF

( % )( % )

98.799 98.634

99.527 100.152

NLC TPS II - STAGE - I Installed Capacity = 630 MW Normative Aux. Consumption = 10.00 %

98.490 98.490 98.218

101.456 99.997 101.456

100.231

NLC TPS II - STAGE - II Installed Capacity = 840 MW Normative Aux. Consumption = 10.00 %

MONTH

Installed Capacity = 2100 MW Normative Aux. Consumption = 7.93%

STATION

NTPC - RSTPS STAGE - I & II

75.288

91.667

98.543

Installed Capacity = 1500 MW Normative Aux. Consumption. = 7.67/7.5

CUMULATIVE AVAILABLITY

NTPC - TALCHER STAGE-II

AVAILABLITY

( % )

98.799

NTPC - RSTPS STAGE-III Installed Capacity = 500 MW Normative Aux. Consumption. = 8.0 %

MAY 2005

Installed Capacity = 420 MW Normative Aux. Consumption = 9.50 %

NLC TPS I - EXPN.

98.218

99.864

93.890 93.890

ON GOI ORDERS ) OF BENEFICIARIES IN I.S.G.S FOR THE MONTH OF

B. PERCENTAGE OF ALLOCATED CAPACITY SHARE ( INCLUDING UNALLOCATED PORTION BASED

FOR THE PERIOD FROM 01.05.05 TO 31.05.05

95.621 95.621 95.100 95.100

94.646 96.563

BACKBACK

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Energy charge:Energy charge is related to the scheduled ex-bus energy to be sent out from the generating station and will be worked out on the basis of paise per KWh.

The Energy Charges Payable by beneficiary to the ISGS = Variable Charge of ISGS X

Ex – Power Plant Schedule

The Energy Charges Receivable by ISGS from beneficiaries = Variable Charge of ISGS X

Despatch schedule of ISGS

BACKBACKExtract from SR REA

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Extract of SR REA

MAY 2005( Energy Figures in KWHrs )

NLC TPS - I

STAGE- I & II Stage-III UNIT-3,4 & 5 UNIT-6 *

-732,922( 24.18 %)

-728,981( 24.05 %)

-526,807( 17.38 %)

-932,066( 30.75 %)

-110,332( 3.64%)

NLC - MINES 27,606,303 28,467,075

PG-HVDC 1,600,051 2,013,679

GOA # 51,468,980

DNH 13,694,444

Daman & Diu 3,476,915

West Bengal 5,131,724

Bihar 2,994,199

Jharkhand 981,432

TOTAL 1,440,681,250 347,222,726 776,819,942 -3,031,108 383,593,425 525,399,825 281,349,250 132,651,972 108,822,788 125,083,548

F. ENERGY SCHEDULED TO THE BENEFICIERIES FROM ISGS ( SR ) FOR THE

12,376,429

10,134,611

STAGE-II MAPS KGS UNIT-I

BENIF / STATION

STAGE -I

NPC *

SCHEDULED ENERGY FROM STATIONS UNDER ABTENERGY DRAWAL FROM STATIONS NOT

UNDER ABT

NLC TPS - II

11,421,734

111,572,334

75,247,239

RSTPS

54,734,704

94,246,715

42,582,527

NTPC

KSEB

TNEB

KPTCL

PONDY

KGS UNIT -II

32,548,895

16,398,453

37,412,489

0 0

10,664,03713,145,227 1,817,332 2,731,45244,124,843 27,895,124

363,917,715

117,586,211

89,328,765 124,245,200

65,536,708

64,888,470

44,892,897

APTRANSCO

132,963,323

0

76,716,327

463,837,188

286,318,189

212,242,925

68,133,009

3,139,597

100,006,321 59,275,773

52,111,515 8,317,279 14,266,668

TALCHER STPS STAGE -II

185,116,810

184,138,890

141,857,371235,584,761 114,294,463 176,419,404

EXPN. **

BACKBACK

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• Flat rate of 25ps/u

• For ex-bus Schedule Energy in Excess of ex-bus energy corresponding to Target PLF

Incentive for ISGS

PLF = 10000

i=1

N

SGi/ {NxICx(100-Auxn) }%

BACKBACK

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Ratio for sharing of monthly Transmission Charges of CTU• Monthly Weighted average entitlement % from all ISGS

in the region and other regions

RSTPS Stg. I & II RSTPS Stg.III Talcher NLC ST-I NLC ST-II

NLC -I

Expn. MAPS KGS ER-NTPC

MW 2100 500 1500 630 840 420 340 440 305%

APTRANSCO 32.25 32.13 24.13 16.78 22.79 0.00 9.33 0.00 21.917

KPTCL 19.86 21.67 23.99 23.10 23.34 27.27 7.64 29.91 21.490

KSEB 14.72 15.76 17.49 11.61 12.31 18.52 6.27 13.11 36.06 15.679

TNEB 25.24 27.15 30.54 29.56 33.14 50.42 75.39 54.47 59.02 35.502

PONDY 3.06 3.29 3.59 11.01 2.47 3.79 1.37 2.51 4.92 3.889

GOA 3.57 1.075

DNH 0.95 0.286

Daman & Diu 0.24 0.072

ISGS BENIFICIERY

Weighted Average

% OF ALLOCATION

BACKBACK

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Ratio for sharing of monthly RLDC fees and O&M charges

• Monthly Weighted average entitlement % from all ISGS in the region

RSTPS

Stg. I & II

RSTPS

Stg.III Talcher NLC ST-I NLC ST-IINLC -I Expn. MAPS KGS

2100 500 1500 630 840 420 340 440

APTRANSCO 32.25 32.13 24.13 16.78 22.79 0.00 9.33 0.00 22.685

KPTCL 19.86 21.67 23.99 23.10 23.34 27.27 7.64 29.91 22.244

KSEB 14.72 15.76 17.49 11.61 12.31 18.52 6.27 13.11 14.596

TNEB 25.24 27.15 30.54 29.56 33.14 50.42 75.39 54.47 34.075

PONDY 3.06 3.29 3.59 11.01 2.47 3.79 1.37 2.51 3.803

NLC MINES 7.94 5.95 1.484

GOA 3.57 1.113

TOTAL 98.70 100.00 99.74 100.00 100.00 100.00 100.00 100.00 100.00

W.A. %BENIFICERY% OF ALLOCATION

BACKBACK

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Wheeling Charges for ISGS Power wheeled on state owned inter state lines.

RATE = 2.5 Ps./KWHr.

ENERGY MAPS / KGS Share NET ENERGY WHEELINGWHEELED to be Wheeled WHEELED CHARGES

KWHrs KWHrs KWHrs Rs.KPTCL 14,825,180TNEB 5,968PONDY 7,525,076APTRANSCO 42,551,588 0KSEB 17,945,784 30,665,121TNEB 133,644 127,408,782KPTCL 39,954TNEB 8,926,339APTRANSCO 12,433 12,376,429KPTCL 37,242,287 10,134,611KSEB 197,694,939 8,317,279APTRANSCO 0 0 0

TOTAL 290,359,441 7,258,986

KWHrs Rs.132,651,972 3,316,299 233,906,336 5,847,658

TO BE SHARED IN THE RATIO OF DRAWAL FROM MAPS TO BE SHARED IN THE RATIO OF DRAWAL FROM KGS

Energy Ratio Wheeling charges in Rs. Beneficary Energy Ratio Wheeling charges in Rs.

TO P

AY

TO P

AY

KGS ENERGY WHEELED BY KPTCL

K. DETAILS OF WHEELING CHAREGES FOR THE MONTH OF MAY 2005.

TO

224,157

42,551,588 1,063,790

FOR THE PERIOD FROM 01.05.05 TO 31.05.05.

T

O

RE

CE

IVE

MAPS ENERGY WHEELED BY TNEB

216,485,336 5,412,133

22,356,224 558,906

8,966,293

12,376,429 0.0933 309,411 APTRANSCO 0 0 010,134,611 0.076400003 253,365 KPTCL 69,961,384 0.2991 1,749,0358,317,279 0.062700003 207,932 KSEB 30,665,121 0.1311 766,628

100,006,321 0.753899995 2,500,158 TNEB 127,408,782 0.5447 3,185,2201,817,332 0.0137 45,433 PONDY 5,871,049 0.0251 146,776

Receivable Payable NET

558906 1861416 -1,302,510

6911448 3378161 3,533,287

224157 1900154 -1,675,996

8728433 7538999 1,189,434

TO P

AY

NET WHEELING CHARGES IN Rs.

TO P

AY

BACKBACK

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Energy Exchanged with other Regions• As furnished by RLDC

BACKBACK

AT ER - NR PERIPHERY at Chandrapur South Bus AT ER - WR PERIPHERY at Chandrapur South Bus

896,344 823,648 315,213 297,949 24.13

891,036 818,771 313,347 296,184 23.99

649,534 596,855 228,419 215,908 17.49

1,134,528 1,042,515 398,975 377,122 30.54

133,357 122,541 46,897 44,328 3.59

PG-HVDC 9,952 9,145 3,500 3,308 0.26

TOTAL 3,714,751 3,413,475 1,306,351 1,234,799

FSTPP KHSTPP TSTPP TOTAL

0 0 0 0

0 0 0 0

39,858,425 7,724,500 9,985,175 57,568,100

30,823,075 45,390,825 14,753,500 90,967,400

2,667,150 3,936,000 1,261,300 7,864,450

TOTAL 73,348,650 57,051,325 25,999,975 156,399,950

VIA ER-NR- WR VIA ER- WR

KSEB

ENERGY SCHEDULED FROM NTPC STATIONS IN ER

APTRANSCO

DETAILS OF ENERGY SCHEDULED FROM ISGS IN OTHER REGION ( INTER REGIONAL)

TNEB

PONDY

BENIFICIERY

APTRANSCO

KPTCL

PONDY

BENIFICIERY

KPTCL

TNEB

Ratio

( Energy figures in KWHrs )

KSEB

Metering Points of ER & SR

Chandrapur

South BusAEL 3,886,700 3,757,975

AEL 475,875 460,151PTC 691,900 672,596

MPSEB ( WR )

TraderTo BeneficieryScheduled at

FROM NER / ER TO WR / NR

GRIDCO ( ER )

From Utility

SIKKIM ( NER )

ARUNACH ( NER )

44

Energy scheduled under STOA• As Furnished by RLDC in Bilateral File

BACKBACK

To Beneficiery Trader Scheduled at Energy in KWHrs

Metering Points of ER & SR 467,000

APTRANSCO Periphery 451,869

Chandrapur South Bus 2,481,100

APTRANSCO Periphery 2,403,199

APTRANSCO Periphery 20,040,000

Chandrapur South Bus 19,391,616

APTRANSCO Periphery 60,400,000

Chandrapur South Bus 58,325,688

KSEB Periphery 60,182,500

TNEB Periphery 58,295,997

KSEB Periphery 0

TNEB Periphery 0

PSEB ( NR ) APTRANSCO PTC

APTRANSCO MPSEB ( WR ) PTC

TNEB

APTRANSCO MSEB ( WR )

KSEB

From Utility

DETAILS OF INTRA REGIONAL AND INTER REGIONAL SCHEDULED BILATERAL EXCHANGES ON SHORT TERM OPEN ACCESS

PTC

TNEB

NVVNL

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HYDRO POWER GENERATING STATIONS

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CAPACITY INDEX

Daily Capacity Index = Declared Capacity(MW)

Maximum Available Capacity(MW)

Monthly Capacity Index

= (Average of Daily Capacity Index)

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NORMATIVE CAPACITY INDEX FOR RECOVERY OF FULL CAPACITY

CHARGES• During 1st Year of Commercial Operation

Run-of-river 85%

Storage Type 80%

• After 1st Year of Commercial Operation

Run-of-river 90%

Storage Type 85%

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COMPUTATION OF ANNUAL CHARGES

• TWO PART TARIFF– Annual Capacity Charge based on

Capacity Index

– Primary Energy Charge based on Scheduled Energy

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PRIMARY ENERGY RATE

• Minimum Variable charge of Central Sector thermal power station

• If Primary Energy Charge > Annual Fixed Charges, then

Primary Energy Rate

= Annual Fixed Charges

Saleable Primary EnergySecondary Energy Rate=Primary Energy Rate

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INCENTIVE

= 0.65 x Annual Fixed Charges (CIA-CIN)/100

CIA = Capacity Index Achieved

CIN = Normative Capacity Index

BACKBACK

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INTER STATE TRANSMISSION

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TARGET AVAILABILTY• Target Availability for recovery of full

transmission charges

AC system 98%

DC system 95%

(HVDC Bi-pole links and HVDC back- back stations)

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SHARING OF CHARGES FOR INTRAREGIONAL ASSETS

n

= Tci -TRSC x CL

i=1 12 SCLTCi = Annual Transmission charge for ith project

TRSC=Total recovery from Open Access

CL=Allotted transmission capacity to a customer

SCL=Sum of all the allotted transmission capacities

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SHARING OF CHARGES FOR INERREGIONAL ASSETS

= 0.5x TCj -RSCj x CL

12 SCLTCj = Annual Transmission charge for jth

interregional assetRSCj=Total recovery from Open Access CL=Allotted transmission capacity to a customerSCL=Sum of all the allotted transmission

capacities

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INCENTIVE

= Equity x (Annual Availability-Target Availability)/100

BACKBACK

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Disputes Mechanism and Resolutions

• All Accounts to remain open for 20 days for verification.• Any Deviation to be bought to the notice to RPC

Secretariat.• RPC Secretariat will verify the data and take corrective

action if required and issue the revised account.• If it is found that account is as per the data furnished by

RLDC. RPC Secretariat may ask the aggrieved Party to verify the correctness of the data with RLDC.

• If RLDC finds data needs to be changed, such changes will be intimated to RPC and then RPC will issue the revised account based on the revised data.

• If aggrieved Party is still not satisfied it may take up the issue with CERC for its decision.

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