1. 1 Regional Energy Accounting, Disputes Mechanism and Resolutions -R M Rangarajan & Asit Singh. -Executive Engineer, -SRPC, Bangalore

2. 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. 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

4. 4 Scope of REA Regional Energy Account ISGS Other Regions Beneficiaries Traders CTU

5. 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. 6 Fixed Cost Elements Interest on Loan Return on Equity ( Presently 14% From 01.04.2009 -15.5% and additional 0.5% if projects are completed within time frame ) Depreciation O&M (cost of maintaining fuel, spares, receivables, personnel etc.)

7. O & M for Thermal Year200/210/250 MW 300/330/350 MW 500 MW600 MW and above 2009-1018.2016.0013.0011.70 2010-1119.2416.9213.7412.37 2011-1220.3417.8814.5313.08 2012-1321.5118.9115.3613.82 2013-1422.7419.9916.2414.62 7 Rs. In lakh/MW Hydro Normalised O& M for 2003-04 to 2007-08 escalated at 5.17 %

8. O & M for Transmission System SS2009-102010-112011-122012-122013-14 765 kV73.3677.5681.9986.6891.64 400 kV52.4055.4058.5761.9265.46 220 kV36.6838.7841.0043.3445.82 132 kV & <26.2027.7029.2830.9632.73 HVDC Stations HVDC B2B Rs. Lakh/ 500 MW 443.00468.00495.00523.00553.00 Rihand- Dardri (Rs. Lakh) 1450.001533.001621.001713.001811.011 Talcher-Kolar (Rs. Lakh) 1699.001796.001899.002008.002122.00 8 Rs. In lakh/bay

9. O & M for Transmission System TL2009-102010-112011-122012-122013-14 AC and HVDC lines S/C ( Bundled conductor) 0.537.568.600.635.671 S/C ( Twin or Triple conductor) 0.3580.3780.4000.4230.447 S/C ( Single conductor) 0.1790.1890.2000.2120.224 D/C (Bundled Conductor 0.9400.9941.0511.1111.174 D/C ( Twin & Triple Conductor) 0.6270.6630.7010.7410.783 D/C ( Single) 0.2690.2840.3010.3180.336 9 Rs. In lakh/km

10. 10 Fixed Cost Elements Cost of secondary fuel( for coal-based and lignite fired generating stations only – From 01.04.2009 ) Insurance, Taxes, etc. ( Not there from 01.04.2009) Special allowance in lieu of R&M or separate compensation allowance (Independent of Energy produced)

11. 11 Variable Cost Elements Primary Fuel Cost (Coal) (depends on Energy produced) Secondary Fuel (oil) ( In FC from 01.04.2009)

12. 12 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

13. 13 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)

14. 14 PRE ABT TARIFF MECHANISM - Problems All inter-utility exchanges based on single flat paise/kWH This 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 contingencies Do not induce power plant operator to back down generation during off-peak hours No financial compensation to any party for over stressing its power plants for assisting during contingencies SEBs view this composite figure only and compare with their own generating stations for their dispatch decisions ISGS(pit head plant)with lower incremental costs used to back down before backing down their own costlier load center generators This leads to perpetual operational and commercial disputes in the operation of region grid

15. 15 Availability 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)

16. 16 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)

17. 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

18. 18 Flow chart of Accounting Procedure Data from RLDC (on every Thursday for the previous week) Preparation of Energy Accounts by RPCs Weekly UI and VAR Accounts (issued on every Tuesday) Monthly REA (Issued during 1 st week of month) GOI/CERC orders/notifications Board Decisions Preparation of Generation Schedule And drawal Schedule Disputes Mechanism and Resolution Hydro Generating StationInter State Transmission

19. 19 Preparing final schedule 121234567891011121234567891011121 noon ISGS SLDC Despatch schedule net Drawal schedule revision station-wise MW/MWH capability station-wise W/MWH entitlement required Drawal schedule AMPM RLDC Despatch schedule starts Drawal schedule starts final Despatch schedule final Drawal schedule BACK

20. 20 Data Required for Preparing these accounts – to be furnished by RLDC Declared Capability (DC) and Dispatch/generation Schedule (GS) – Annexure 1AAnnexure 1A Entitlement of various beneficiaries – Annexure 1BAnnexure 1B Requisition by various beneficiaries – Annexure 1CAnnexure 1C Any bilateral Trading under STOAC – Bilateral FilesBilateral Files Wheeling to/from other regions – Processed Meter (SEM) data – 15 min block wise actual injection/drawal at various locations and reactive drawal/injection for a day – SEM Files BACK

21. 21 Weekly Account Contains Unscheduled Interchange (UI) charges Reactive energy charges BACK

22. 22 Monthly REA Contains (a)Availability % for Capacity Charge recoveryAvailability % for Capacity Charge recovery (b)Energy Scheduled for Energy ChargesEnergy Scheduled for Energy Charges (c)Energy scheduled beyond target PLF for IncentiveEnergy scheduled beyond target PLF for Incentive (d)Ratio for sharing of monthly Transmission Charges of CTURatio for sharing of monthly Transmission Charges of CTU (e)Ratio for sharing of monthly RLDC fees and O&M chargesRatio for sharing of monthly RLDC fees and O&M charges (f)Wheeling Charges for ISGS Power wheeled on state owned inter state lines.Wheeling Charges for ISGS Power wheeled on state owned inter state lines. (g)Energy Exchanged with other RegionsEnergy Exchanged with other Regions (h)Energy scheduled under STOAEnergy scheduled under STOA BACK

23. 23 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

24. 24 For the day: 0000 hrs. to 2400 hrs. Central Generating Stations 1 23 Ex-Bus Declared Capability x1x2x3 (Forecast) ____ _______ SEB-A’s sharea1a2a3 SEB-B’s shareb1b2b3 SEB-C’s sharec1c2c3 For a particular 15 minute time block SEB-A’s requisition a’1a’2a’3 SEB-B’s requisition b’1b’2b’3 SEB-C’s requisition c’1c’2c’3 _________ CGS’s schedule x1’x2’x3’ MW Sample UI Calculation

25. 25 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 6 th 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

26. 26 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

27. 27 For the day: 0000 hrs. to 2400 hrs. Central Generating Stations 1 23 Ex-Bus Declared Capability x1x2x3 (Forecast) ____ _______ SEB-A’s sharea1a2a3 SEB-B’s shareb1b2b3 SEB-C’s sharec1c2c3 For a particular 15 minute time block SEB-A’s requisition a’1a’2’a’3 SEB-B’s requisition b’1b’2’b’3 SEB-C’s requisition c’1c’2’c’3 _________ CGS’s schedule x1’x2’’x3’ MW Revised Schedules

28. 28 Actual (metered) injection of CGS-1 in the time block = X 1 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

29. 29 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 Unscheduled Interchanges (UI)

30. 30 UI rate in effect UI rate (Paise per KWh) Average Frequency of time block 50.5 Hz. and above 0 At 49.82 Hz 280 Between 50.5 Hz and 49.80 Hz 8 P/ 0.02 Hz At 49.80 Hz 298 Between 49.80 Hz and 49.00 Hz 18 P/ 0.02 Hz At 49.00 Hzand less then 1000 ISG Stations capped at 406 P

31. 31

32. 32 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 Rate Regional Pool Over drawl by SEB-B UI Import/Export to IR-2

33. 33 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-B Payable/Receivable by IR-2 Receivable by ISGS-1 Receivable by SEB-A Payable/ Receivable by IR-1 No one to one correspondence No cross adjustments allowed between the constituents

34. 34 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. BACK

35. 35 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 Basic Rate : 5 paise/kvArh ( for the year 2006-09 ) 0.25 Paisa ESCALATION PER YEAR SAMPLE VAR ACCOUNT STATEMENT

36. 36 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 BACK

37. 37 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 Around 85 % from 01.04.2009 )

38. 38 Calculation Of Availability % Availability = i=1 N DC i / {NxICx(100-Aux n ) }% 10000 Where DC i = Average Declared Capacity for i th day of the period in MW N = Total no. of days during the period Aux n = Normative Auxiliary Consumption as % of gross Gen. IC= installed capacity in MW % Availability forms the basis for calculations

39. Capacity Charges for Thermal Inclusive of Incentive GS < 10 years of COD = AFC x ( NDM/NDY) x ( 0.5 +0.5 x (PAFM/NAPAF) (in Rupees) GS > 10 years of COD = AFC x ( NDM/NDY) x (PAFM/NAPAF) (in Rupees) AFC = Annual FC NAPAF= Normative Annual Plant Availability Factor NDM= Number of days in a month NDY= Number of days in a year PAFM= PAF achieved for the month PAFY= PAF acheived for the year 39

40. 40 Monthly Capacity charges receivable by an ISGS: (Not there from 01.04.2009) 1 st Month = (1xACC1)/12 2 nd Month = (2xACC2-1ACC1)/12 …. …. 12 th month = (12xACC12-11ACC11)/12 where 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)/12 2 nd Month = (2xACC2xWB2-1ACC1xWB1)/12 …. …. 12 th month = (12xACC12xWB12-11xACC11xWB11)/12 where WB1,WB2…..WB12 = Weighted average % share up to the corresponding month. BACK Extract from SR REA

41. 41 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 BACK Extract from SR REA

42. 42 From 01.04.2009 Incentive recovered in Fixed charges 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 SG i / {NxICx(100-Aux n ) }% BACK

43. 43 Ratio for sharing of monthly Transmission Charges of CTU Monthly Weighted average entitlement % from all ISGS in the region and other regions BACK Extract from REA

44. 44 Ratio for sharing of monthly RLDC fees and O&M charges Monthly Weighted average entitlement % from all ISGS in the region BACK Extract from REA

45. 45 Wheeling Charges for ISGS Power wheeled on state owned inter state lines. BACK Extract from REA

46. 46 Energy Exchanged with other Regions As furnished by RLDC BACK Extract from REA

47. 47 HYDRO POWER GENERATING STATIONS

48. 48 CAPACITY INDEX Daily Capacity Index = Declared Capacity(MW) Maximum Available Capacity(MW) Monthly Capacity Index = (Average of Daily Capacity Index)

49. Capacity Charges from 01.04.2009 for Hydro Capacity Charges ( inclusive of incentive) = AFC x 0.5 x NDM/ NDY x (PAFM/NAPAF) 9 (in Rupees) AFC = Annual Fixed Cost specified for the year NDM – No of days in the month NDY - No of days in the year PAFM – Plant A F achieved during the month NAPAF – Normative PAF 49

50. 50 PAFM=10000 * AUX – Normative Aux. Cons. DCi - Declared Capacity for the i th day of the month (atleast 3 hours) certified by nodal LDC IC - Installed Capacity in MW N - No of days in a month PAFM for HYDRO i=1 N DC i / {NxICx(100-Aux) }% BACK

51. 51 NORMATIVE CAPACITY INDEX FOR RECOVERY OF FULL CAPACITY CHARGES During 1 st Year of Commercial Operation Run-of-river85% Storage Type80% After 1 st Year of Commercial Operation Run-of-river90% Storage Type85% From 01.04.2009 Norms are revised

52. 52 COMPUTATION OF ANNUAL CHARGES TWO PART TARIFF –Annual Capacity Charge based on Capacity Index –Primary Energy Charge based on Scheduled Energy

53. 53 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 Energy Secondary Energy Rate=Primary Energy Rate

54. Energy Charges for Hydro from 01.04.2009 EC=(Engy chg rate (ECR) in Rs/KWH *Sch. Engy )*(100-FEHS)/100 ECR = AFC*0.5*10/(DE*(100-AUX)*(100- FEHS) DE - Annual Design Energy in MU FEHS – Free Energy for Home State 54

55. 55 INCENTIVE = 0.65 x Annual Fixed Charges (CIA- CIN)/100 CIA = Capacity Index Achieved CIN = Normative Capacity Index From 01.04.2009 incentive included in the Capacity Charges BACK

56. 56 INTER STATE TRANSMISSION

57. 57 TARGET AVAILABILTY Target Availability for recovery of full transmission charges AC system 98% DC system95% (HVDC Bi-pole links and HVDC back- back stations)

58. 58 TARGET AVAILABILTY From 01.04.2009 Normative Annual Transmission System Availability Factor (NATAF) AC system 98% HVDC Bi Pole 92% HVDC B2B 95%

59. 59 SHARING OF CHARGES FOR INTRAREGIONAL ASSETS n =  Tci-TRSCx CL i=1 12 SCL TCi = 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

60. 60 SHARING OF CHARGES FOR INERREGIONAL ASSETS = 0.5xTCj-RSCj x CL 12 SCL TCj = Annual Transmission charge for jth interregional asset RSCj=Total recovery from Open Access CL=Allotted transmission capacity to a customer SCL=Sum of all the allotted transmission capacities

61. 61 INCENTIVE = Equity x (Annual Availability- Target Availability)/100 BACK

62. Monthly Transmission Charges from 01.04.2009 =AFC*(NDM/NDY)*(TAFM/NATAF) AFC – Annual F C specified for the year NATAF – Normative Annual Tr. AF in % NDM – No of days in the month NDY - No of days in the year TAFM – Tr. Sys Avblty Factor achieved for the month 62

63. Sharing of Tr. Charges from 01.04.2009 By all regional beneficiaries in proportion to their entitlement By the beneficiaries of other region in proportion to their entitlement Generating Companies if ATS not developed Medium term users 63

64. Sharing of Inter Regional Link Charges from 01.04.2009 ER – NR by NR beneficiaries ER-WR by WR beneficiearies ER-SR by SR beneficiaries NR-WR and WR-SR 50:50 64

65. New Regulations from 01.04.2009 ATS not to be pooled would shared by the concerned beneficiaries 400/220 KV step down ICTs and down stream systems by the beneficiary only(DOC after 28.03.2008) For MW Benificiary not identified Tr. Charges to be borne by the concerned gen station. 65

66. 66 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.

67. Rebate and Late Payment Surcharges 2% Rebate for payment of bills through LC 1% Rebate for payment made within one month Late Payment 1.25% per month for delayed payment beyond a period of 60 days 67

68. 68