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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
14
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
15
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
16
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
17
Weekly Account Contains
• Unscheduled Interchange (UI) charges
• Reactive energy charges
BACKBACK
18
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
19
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
20
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
21
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
22
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
23
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
24
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
25
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)
26
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
27
• 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
28
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
29
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
30
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
31
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
32
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
33
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.
34
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
35
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
36
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
37
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
38
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
39
• 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
40
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
41
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
42
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
43
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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