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Regional Energy Accounting, Disputes Mechanism and Resolutions

Regional Energy Accounting, Disputes Mechanism and Resolutions

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Regional Energy Accounting, Disputes Mechanism and Resolutions

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

  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” 2

  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 3

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

  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. 5

  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.) 6

  7. O & M for Thermal Rs. In lakh/MW Hydro Normalised O& M for 2003-04 to 2007-08 escalated at 5.17 % 7

  8. O & M for Transmission System Rs. In lakh/bay 8

  9. O & M for Transmission System Rs. In lakh/km 9

  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) 10

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

  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 12

  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) 13

  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 14

  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) 15

  16. AVAILABILITY BASED TARIFF(ABT) (a) CAPACITY CHARGE (b) ENERGY CHARGE • ADJUSTMENT FOR DEVIATIONS (UI CHARGE) • = a function of Ex-bus MW availability of power plant for the day declared before the day starts x SEB’s % share . • = MWh for the day as per ex=bus drawl schedule for the SEB finalized before the day starts x Energy charge rate • =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) 16

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

  19. Preparing final schedule ISGS station-wise MW/MWH capability finalDespatch schedule Despatch schedule starts revision Despatch schedule RLDC 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 1 AM noon PM station-wise W/MWH entitlement Drawalschedule starts revision net Drawal schedule final Drawalschedule required Drawalschedule SLDC BACK 19

  20. 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 – • Processed Meter (SEM) data – 15 min block wise actual injection/drawal at various locations and reactive drawal/injection for a day – SEM Files BACK 20

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

  22. Monthly REA Contains • Availability % for Capacity Charge recovery • Energy Scheduled for Energy Charges • Energy scheduled beyond target PLF for Incentive • Ratio for sharing of monthly Transmission Charges of CTU • Ratio for sharing of monthly RLDC fees and O&M charges • Wheeling Charges for ISGS Power wheeled on state owned inter state lines. • Energy Exchanged with other Regions • Energy scheduled under STOA BACK 22

  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 23

  24. Sample UI Calculation 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 a3 SEB-B’s share b1 b2 b3 SEB-C’s share c1 c2 c3 For a particular 15 minute time block SEB-A’s requisition a’1 a’2 a’3 SEB-B’s requisition b’1 b’2 b’3 SEB-C’s requisition c’1 c’2 c’3 ___ ___ ___ CGS’s schedule x1’ x2’ x3’ MW 24

  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 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 25

  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 26

  27. Revised Schedules 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 a3 SEB-B’s share b1 b2 b3 SEB-C’s share c1 c2 c3 For a particular 15 minute time block SEB-A’s requisition a’1 a’2’ a’3 SEB-B’s requisition b’1 b’2’ b’3 SEB-C’s requisition c’1 c’2’ c’3 ___ ___ ___ CGS’s schedule x1’ x2’’ x3’ MW 27

  28. Actual (metered) injection of CGS-1 in the time block = X1MWh. 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 28

  29. Unscheduled Interchanges (UI) 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 29

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

  31. 31

  32. Under drawl by SEB-A Over Gen. By ISGS-1 UI import/Export from IR-1 Regional Pool System frequency UI Rate Under gen. By ISGS-2 UI Import/Export to IR-2 Over drawl by SEB-B No one to onecorrespondence Energy transactions of UI from/to Pool 32

  33. Operation of Pool Separate Pool a/cs operated by RLDCs on behalf of RPCs for UI, IRE and Reactive charges Payable by SEB-B Payable/Receivable by IR-2 Payable by ISGS-2 Regional Pool Receivable by ISGS-1 Payable/ Receivable by IR-1 Receivable by SEB-A No one to one correspondence No cross adjustments allowed between the constituents 33

  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 34


  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 36

  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 ) 37

  38. Calculation Of Availability % Availability = N DCi/ {NxICx(100-Auxn) }% 10000 i=1 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 38

  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. Monthly Capacity charges receivable by an ISGS: (Not there from 01.04.2009)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. BACK Extract from SR REA 40

  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 41

  42. Incentive for ISGS • 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 N PLF = 10000 SGi/ {NxICx(100-Auxn) }% i=1 BACK 42

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

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

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

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


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

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