1. Sharing of Inter State Transmission Charges National Load Despatch Centre Implementing Agency

2. Policy Mandate – National Electricity Policy Section 5.3.2 “….Prior agreement with the beneficiaries would not be a pre-condition for network expansion…” Section 5.3.5 “……..The tariff mechanism would be sensitive to distance, direction and related to quantum of flow….”

3. Policy Mandate – Tariff Policy Section 7.1 : Transmission Pricing Section 7.1.1 “The National Electricity Policy mandates that the national tariff framework implemented should be sensitive to distance, direction and related to quantum of power flow……” Section 7.1.2 “Transmission charges, under this framework, can be determined on MW per circuit kilometer basis, zonal postage stamp basis, or some other pragmatic variant, the ultimate objective being to get the transmission system users to share the total transmission cost in proportion to their respective utilization of the transmission system……” Contd…..

4. Historical Background Stage I Cost of Transmission clubbed with Generation Tariff Implicit Stage II Apportioned on the basis of energy drawn (Usage Based) Stage III Apportioned on the basis of MW entitlements (Access Based) Stage IV Hybrid Methodology (Point of Connection) Upto 1991 1992- 2002 2002- 2011 2011 onwards

5. Sharing of Transmission charges - Present Methodology Regulation 33 of Terms and Conditions of Tariff –Regional postage stamp Shared by beneficiaries in the same region as well as other regions Generating companies – if beneficiary not identified Medium term users –Pooling of all ISTS assets as on 1.4.2008 –Charges of new ATS By respective beneficiaries if pooling not agreed Part pooling / part by respective beneficiaries –Treatment of inter-regional link charges –Step down transformers and down-stream system after 28.3.2008 By beneficiary directly served

6. Development of Transmission System GENERATION DISTRIBUTION TRANSMISSION GENCO TRANSCO DISCO Unbundling

7. Scenario in Recent Past TRANSMISSION SERVICE PROVIDER (TSP – 1) Transmission Assets (T1A 1-n) UTILITY (U-2) UTILITY (U-1) UTILITY (U-4) UTILITY (U-3) UTILITY (U-n) TRANSMISSION SERVICE PROVIDER (TSP – 2) Transmission Assets (T2A 1-n) ONE REGIONAL GRID Multiple Utilities With Two Transmission Service Providers

8. Present Scenario: Increasing Complexities REGIONAL GRID -1 TSP – 1 Transmission Assets (T1A 1-n) U-2 U-1 U-4 U-3 U-n TSP – 2 Transmission Assets (T2A 1-n) TSP – m Transmission Assets (TmA 1-n) TSP – 3 Transmission Assets (T3A 1-n) D-1D-n D-1D-n D-1D-n D-1D-n D-1D-n REGIONAL GRID -2 TSP – 1 Transmission Assets (T1A 1-n) U-2 U-1 U-4 U-3 U-n TSP – 2 Transmission Assets (T2A 1-n) TSP – m Transmission Assets (TmA 1-n) TSP – 3 Transmission Assets (T3A 1-n) D-1D-n D-1D-n D-1D-n D-1D-n D-1D-n Inter-Regional Interconnections

9. Future Scenario : More Complexities REGIONAL GRID -1 TSP – 1 Transmission Assets (T1A 1-n) U-2 U-1 U-4 U-3 U-n TSP – 2 Transmission Assets (T2A 1-n) TSP – m Transmission Assets (TmA 1-n) TSP – 3 Transmission Assets (T3A 1-n) D-1D-n D-1D-n D-1D-n D-1D-n D-1D-n REGIONAL GRID -2 TSP – 1 Transmission Assets (T1A 1-n) U-2 U-1 U-4 U-3 U-n TSP – 2 Transmission Assets (T2A 1-n) TSP – m Transmission Assets (TmA 1-n) TSP – 3 Transmission Assets (T3A 1-n) D-1D-n D-1D-n D-1D-n D-1D-n D-1D-n Inter-Regional Interconnections TSPs in One Region Having Customers in Another Region Also

10. Need for change in pricing framework Synchronous integration of Regions- Meshed Grid Changes caused by law and policy Open Access and Competitive Power Markets –Pricing Inefficiencies, Market Players’ concern National Grid / Trans-regional ISGS –Changing Network utilization –Agreement of beneficiaries a challenge –Ab-initio identification beneficiaries difficult

11. Elegant Model TSP – 1 Transmission Assets (T1A 1-n) TSP – 2 Transmission Assets (T2A 1-n) TSP – m Transmission Assets (TmA 1-n) TSP – 3 Transmission Assets (T3A 1-n) U-2 U-1 U-4 U-3 U-n D-1D-n D-1D-n D-1D-n D-1D-n D-1D-n AGENCY FOR PLANNING U-2 U-1 U-4 U-3 U-n D-1D-n D-1D-n D-1D-n D-1D-n D-1D-n Region -1 Region -2 AGENCY FOR COMPUTATION OF TRANMSSION CHARGES AGENCY FOR BILLING & COLLECTION

12. Regulatory Initiatives Discussion Paper on Sharing of Charges and losses in Inter-State Transmission System (ISTS) (2007) Approach Paper on Formulating Pricing Methodology for Inter-State Transmission in India (May 2009) Draft Regulation on Sharing of Inter-State Transmission Charges and Losses(February 2010) Regulation on Sharing of Inter-State Transmission Charges and Losses(June 2010)

13. CERC Regulations on Sharing of Transmission Charges & Losses Notification of Regulations : 15 th June 2010 Applicable to: –Designated ISTS Customers –Inter State Transmission Licensees –NLDC, RLDC, SLDCs, and RPCs Regulations to come into force from 1.1.2011 –For a period of 5 years unless reviewed or extended by the Commission

14. Methods for Sharing of Transmission Charges Postage Stamp Method Contract Path Method MW Mile Method –Distance Based –Power Flow Based Average Participation Marginal Participation Method Zone to Zone Method Locational Marginal Pricing

15. Methodology Proposed in India Point of Connection (PoC) Charges –In Rs. per MW per month –Nodal / Zonal Charges –Separate Injection & Withdrawal Charge Usage Based Methodology –Based on Load Flow Studies –Hybrid of Average Participation and Marginal Participation methods PoC Charges –To be made known upfront –To be applied on Medium Term and Short Term Trades Handling Transition –To begin with 50% Uniform Charges and 50% PoC Charges –Gradual movement towards 100% PoC Charges

16. Average Participation Tracing of Power –Load Tracing –Generator Tracing

17. Marginal Participation –The charges are based on incremental utilization of network assessed through load flows.

18. Hybrid Methodology Hybrid of –Average Participation –Marginal Participation Average Participation –Used to identify slack (responding) buses for each node Marginal Participation –To compute the participation factor of each node on each line.

19. Introduction to the PoC Charge Computation Algorithms/ Processes  AC Load flow and transmission losses  Slack bus determination- Average Participation method  Participation factor of a node- Marginal Participation method  Loss allocation factor of node- Marginal Participation method Input  Network data for modeling the power system  Nodal injection / Nodal withdrawal for a scenario  Yearly Transmission Charges to be apportioned Output  Point of Connection Charge- Demand Zone/ Generation Zone  Point of Connection Losses- Demand Zone/ Generation Zone

20. Important Definitions Approved Injection “Approved Injection means the injection in MW vetted by Implementing Agency (IA) for the Designated ISTS Customer for each representative block of months, peak and other than peak scenarios at the ex-bus of the generator or any other injection point of the Designated ISTS Customer into the ISTS, and determined based on the generation data submitted by the Designated ISTS Customers incorporating total injection into the grid, considering the long term and medium term contracts.”

21. Approved Withdrawal “Approved withdrawal means the simultaneous withdrawal in MW vetted by Implementing Agency for any Designated ISTS Customer in a control area aggregated from all nodes of ISTS to which Designated ISTS Customer is connected, for each representative block of months, peak and other than peak scenarios at the interface point with ISTS, and where the Approved Withdrawal shall be determined based on the demand data submitted by the Designated ISTS Customers. incorporating long term and medium term transactions.” Important Definitions Chapter 1

22. Designated ISTS Customers “Designated ISTS Customers (‘DIC’s) means the users of any segments/elements of the ISTS and shall include all generators, state transmission utilities, SEBs or load serving entities directly connected to the ISTS including Bulk Consumer and any other entity/person.” Important Definitions Chapter 1

23. Implementing Agency (IA) “Implementing Agency shall mean the agency designated by the Commission to undertake the estimation of allocation of transmission charges and transmission losses at various nodes/zones for the Application Period along with other functions as per [Chapter-4, Chapter-5, Chapter-6, Chapter- 7and Chapter-8] of these regulations.” Important Definitions Chapter 1

24. Point of Connection (PoC) Charging Method “ Point of connection Charging Method shall mean the methodology of computation of sharing of ISTS charges and losses amongst Designated ISTS Customers, which depends on the location of the node in the grid and is calculated in accordance with Regulation 7(1(q)) and 7(1(s)) of chapter 4 of these regulations.” Important Definitions Chapter 1

25. Inputs for PoC Charge Determination Implementing Agency ISTS Licensees 1.Network Parameters 2.Yearly Transmission Charges 3.DOCO of New Assets to Commission STURPCs 1.Network Parameters 2.DOCO of New Assets to Commission 3.Nodal Injection / Nodal Withdrawal 1.List of non-ISTS lines which are being used as ISTS

26. STU/SEBs/CTU Implementing Agency Network Parameters Line wise YTC Designated ISTS Customers Nodal Demand / Generation Medium Term Injection / Withdrawal Approved Injection Approved Withdrawal Basic Network Network Parameters Forecast Injection / Withdrawal Flow Chart for Input Data Acquisition

27. Timelines for Submission of Information Details of data submitted by DICs Injection and Withdrawal forecast for different blocks of months (Peak and Other than Peak): –April to June…………………………… (for May 15) –July to September……………………. (for August 31) –October to November………………… (for October 30) –December to February……………….. (for January 15) –March…………………………………… (for March 15) In case the dates appearing in brackets fall on a weekend/public holiday, the data shall be submitted for working days immediately after the dates indicated

28. Determination of PoC Charges (1) Consultancy Assignment for Software development –IIT, Mumbai & Power Anser Labs (PAL) Web based Software developed for calculation of PoC Charges –WebNetUse Software Approved by CERC

29. Determination of PoC Charges (2) Compilation & checking of network data Assumptions for missing data Formulation of Base case for load flow studies –Based upon the Network Data submitted by the DICs –All elements up to 132 kV included in the model Load Flow Studies on the Full Network Truncation for the purpose of PoC Charge Determination –Network truncation at 400 kV –Except NER, where it is done at 132 kV.

30. Determination of PoC Charges (3) Inputs to the WebNetUse Software –Truncated Network Data –YTC Details Load Flow Study by WebNetUse Identification of Slack Bus Calculation of Marginal Participation Factors for each line/bus Calculation of PoC Charges for each Node Results obtained from WebNetUse –Node wise PoC Charges Injection charge Withdrawal charge

31. Determination of PoC Charges (4) Philosophy for identification of coherent nodes for zoning –State control areas to be separate demand zone except in the case of North Eastern States, which are considered as a single demand zone. –State control areas considered as generation zone except NER states which are considered as a single generation zone. –All ISGS connected at 400 kV considered as separate generation zone.

32. Determination of PoC Charges (4) Calculation of Zonal PoC Charges –Weighted average of nodal PoC Charges –Separate Charge for Injection Withdrawal Scaling of Charges –To ensure full recovery PoC Charges in Rs. / MW / Month

33. Treatment of HVDC Zero Marginal Participation for HVDC Line –HVDC line flow regulated by power order. MP Method can not recover its cost directly. HVDC line can be modeled as: –Load at sending end –Generator at receiving end

34. Compute Transmission Charges for all load and generators with all HVDC lines in service. Disconnect HVDC line and again compute new transmission charges for all loads and generators Compute difference between nodal charges with or without HVDC. Identify nodes which benefits with the presence of HVDC Allocate HVDC line cost to the identified nodes. Indirect Method for HVDC Cost Allocation

35. YTC assigned to each line Slack bus Point of Connection Loss Point of Connection Transmission Charge Power System Model YTC of line + YTC of substation apportioned to lines of a voltage level Information flow chart Average Transmission Charge per ckt kilometer for a voltage level & conductor configuration Basic Network data Nodal Injection & withdrawal Approved Injection, Approved Drawal, Transmission losses of truncated network Load flow on complete network Algorithm for average participation Algorithm for computing marginal participation Generation Zone Demand Zone PoC for billing Generation Zone Demand Zone loss for scheduling List of state lines used as ISTS

36. Regional Transmission Accounts (1 st Working Day of Every Month for the previous Month) Regional Transmission Deviation Accounts (15 th Day of Every Month for the previous Month) Regional Power Committee Accounting of Charges : Monthly accounts in each region shall be prepared by respective RPC Regulation 10(1) Accounting of Transmission Charges

37. Central Transmission Utility (CTU) shall be responsible for –Raising the bills, collection and disbursement to ISTS licensees based on Accounts issued by RPC Bill to be raised only on DIC’s –SEB/STU may recover such charges from DISCOMs, Generators and Bulk Consumers connected to the intra-state system. The billing from CTU for ISTS charges for all DICs shall be : –In 3 parts on the basis of Rs/MW/Month and; –the fourth part for deviations would be on the basis of Rs/MW/Block Billing of Transmission Charges

38. Central Transmission Utility First Part (Based on Approved Injection/Withdrawal and PoC Charge) Third Part (Adjustments Based on FERV, Interest, Rescheduling of Commissioning) Fourth Part (Deviations) Second Part (Recovery of Charges for Additional Medium Term Open Access) 1 st Day of a Month Biannually (1 st Day of September and March 18 th Day of a Month Billing and Collection of Charges by CTU

39. Generator Net Injection Net Drawl 1.25 times PoC Charge Deviation upto than 20% Deviation Greater than 20% PoC Charge 1.25 times PoC Charge Treatment of Deviations : Generator

40. Demand Net Drawl Net Injection 1.25 times PoC Charge Deviation upto 20% Deviation Greater than 20% PoC Charge 1.25 times PoC Charge Treatment of Deviations : Generator

42. Long Term Allocation Matrix Allocation Matrix ( all figures in MW) North East West South North East CHANDIGARH DTL HVPNL HPSEB PDD,J&K PSEB RRVPNL UPPCL UPCL Railways HVDC Rihand HVDC Dadri To North From PUSAULI BIHAR JHARKHAND DVC ORISSA WEST BENGAL SIKKIM To East From GUVNL MPPTCL CSEB MSEDCL GOA D&DDNH BHADRAWATI HVDC VINDHYACHAL HVDC MPAKVNL, Indore Heavy Water Plant of DAE To West From APTRANSCO KPTCL KSEB TNEB PUDUCHERRY NLC Mines GOA HVDC Gazuwaka HVDC Talcher HVDC Kolar To South From Arunachal Pradesh Assam Manipur Meghalaya Mizoram Nagaland Tripura To North East From Total LTA/ Allocation1803533145970613442410165345836331001116603116674991611025119514546922358237551432523082135442112179596173813769372331339909322269101237181161896494971402 North SINGRAULI STPS1845161562280222472777961020001845 14973 00000000 0 000000000000 0 00000000000 0 00000000 0 RIHAND I STPS940181038333771358935744010940000000000000000000000000000000000000000 RIHAND0II STPS9401612776311001289433039000940000000000000000000000000000000000000000 UNCHAHAR I TPS38432313614371823534000384000000000000000000000000000000000000000 UNCHAHAR II TPS384647301132683513917000384000000000000000000000000000000000000000 UNCHAHAR III TPS1923281571422216813000192000000000000000000000000000000000000000 DADRI NCTPS I764068800000760000764000000000000000000000000000000000000000 DADRI NCTPS II916082500000920000916000000000000000000000000000000000000000 DADRI NCGPS80589249245914175259306801805000000000000000000000000000000000000000 ANTA GPS4751054391739729412921000475000000000000000000000000000000000000000 AURAIYA GPS6469744821489659231283200646000000000000000000000000000000000000000 NAPS387845341234583914217000387000000000000000000000000000000000000000 RAPP B3870124203188143710000387000000000000000000000000000000000000000 RAPP C38765331134153779716000387000000000000000000000000000000000000000 SALAL683075208820318000000683000000000000000000000000000000000000000 CHAMERA I HPS53516280518414216376000535000000000000000000000000000000000000000 CHAMERA II HPS29733017108233722541000297000000000000000000000000000000000000000 TANAKPUR HPS9311053597381400093000000000000000000000000000000000000000 BAIRASIUL HPS178225140402119499000178000000000000000000000000000000000000000 URI HPS475661301836855510876000475000000000000000000000000000000000000000 DHAULIGANGA277112244411128545610000277000000000000000000000000000000000000000 NATHPA JHAKRI148526215127233115209144404130001485000000000000000000000000000000000000000 DULHASTI38665531142852379865000386000000000000000000000000000000000000000 TEHRI STAGE I9901714181020211610727748000990000000000000000000000000000000000000000 SEWA II HEP11911363401611244000119000000000000000000000000000000000000000 From North to14973 17830361334684119421781493416860710011 0000000 00000000000 0000000000 0000000 149730000 East Farakka1489021100132110310000106 1630 04371460203455241265 4505 000000000000 557 0005940000063 134 2400707056 200 Kahalgaon I764046230284623700000237130935011601247400000000000000030200000321140304021 Kahalgaon II14033147642178112100235260007870942302905150132692813802300003720000000000007102200093 Talcher93500000000000000374863297852286700000000000000037200000391190405029 Rangeet590000000000000021860178590000000000000000000000000000000 Teesta504000000000000001076244104121665040000000000000000000000000000000 Mejia DVC36602713016271340000013700000460 0183000000000 0000000000000000000 DVC to Delhi2300 0000000000 00000000 000000000000 00000000000 0000 Hirakud GRIDCO20000000000000000000000020000000020000000000000000000 TALA8910261301626133900001340227102493834107570000000000000000000000000000000 Chukha333000000000000009936345110673330000000000000000000000000000000 Kurichhu500000000000000000250 0500000000000000000000000000000000 From East to7025 34971242115123316041526000 116674991618381195145 132252301380230000 000125800000 51430360150 16304505557134200 West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ench00000000000000000000000000000000000000000000000000000 NSPCL Bhilai170000000000000000000000000007010000001700000000000000000000 From West to9039 000000000000 0000000 222621224843114308211541211217 0000000000 0000000 00903900 South NTPC,RAMAGUNDAM I &II19490000000000000 0 00000000 187 000000000000 0 652371227511930 2001949 6776 00000000 0 NTPC,RAMAGUNDAM III4680000000000000000000000000000000001649457129240000046800000000 NTPC,TALCHER II18700000000000000000018700 0000000000003943463934747200022168300000000 NEYVELLI LC TPS II0I567000000000000000000000000000000000109116571726845000056700000000 NEYVELLI LC TPS II0II756000000000000000000000000000000000190157812572745000075600000000 NEYVELLI LC TPS I EXP380000000000000000000000000000000000010153210160000038000000000 NPC,MAPS39600000000000000000000000000000000041292129970000039600000000 NPC,KGS UNITS 1&238000000000000000000000000000000000012210333106160000038000000000 NPC,KGS UNITS 31980000000000000000000000000000000006759164980000019800000000 From South to6963 000000000000 000018700 00000000000 1738137693722063309093222 0000000 0187067760 North East AGBPP, NEEPCO2820000000000000 0 00000000 0 000000000000 0 00000000000 0 161592333151620282 1202 AGTPP, NEEPCO830000000000000000000000000000000000000000000053879551483 Doyang, NEEPCO740000000000000000000000000000000000000000000053268413574 Kopili, NEEPCO19800000000000000000000000000000000000000000000101061534912 198 Kopili 2, NEEPCO25000000000000000000000000000000000000000000002122521225 Khandong, NEEPCO50000000000000000000000000000000000000000000002283823350 Ranganadi, NEEPCO40100000000000000000000000000000000000000000000741743445232130401 Loktak, NHPC8900000000000000000000000000000000000000000000426271156 89 From North East to1202 000000000000 0000000 0 00000000000 0000000000 119575116153647897 00001202

43. Information on Public Domain Approved Basic Network Data and Assumptions, if any Zonal or nodal transmission charges for the next financial year differentiated by block of months; Zonal or nodal transmission losses data; Schedule of charges payable by each constituent for the future Application Period, after undertaking necessary true-up of costs Username and Password to view critical data

44. Implementation Related Issues Definition of –Approved Injection –Approved Withdrawal Determination of YTC & Substation Cost Apportionment Multiple Scenarios for PoC computation and Basis of furnishing nodal generation and withdrawal data Collection and disbursement of STOA Charges –Avoidance of double charging Connectivity without Long Term Access Treatment of HVDC Links

45. Thank You!