SHARING OF ISTS TRANSMISSION CHARGES & LOSSES

1. ERLDC Power System Operation Corporation SHARING OF ISTS TRANSMISSION CHARGES & LOSSES

2. INTRODUCTION

3. EVOLUTION OF TRANSMISSION PRICING • (Usage & Distance/Direction sensitivity based)

4. PARADIGM CHANGE: EA-2003 AND NEP EA-2003: Facilitate competitive markets Generation de-licensed Non-discriminatory open access Efficient, coordinated and economical development of ISTS: Responsibility of CTU National Electricity Policy Section 5.3.2 and 5.3.5 Prior agreement with beneficiaries not a pre-condition for ISTS development CTU/STU should undertake network expansion after identifying the requirements in consultation with stakeholders and taking up the execution after due regulatory approvals. Transmission tariff to be made sensitive distance, direction and quantum of flow CERC has released the Grant of Regulatory Approval for execution of Inter-State Transmission Scheme to CTU regulations Dtd.31/05/10

5. TARIFF POLICY ON TRANSMISSION PRICING • Section 7.1 (2), (3) & (4) and Section 7.2 • Sensitive to distance, direction and quantum • Sharing in proportion to utilization • Facilitate planned development/augmentation • Discourage non-optimal investment • Prior agreement not pre-condition • Apportionment of losses- distance and direction sensitive

6. POWERGRID 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

7. राष्ट्रीय भार प्रेषण केंद्र Changing Structure of Indian Power Sector and development of Electricity Markets

8. VERTICALLY INTEGRATED UTILITY GENERATION TRANSMISSION DISTRIBUTION

9. Transmission Assets (TA-1 to n) ONE UTILITY (U-1) WITH ONE TRANSMISSION SERVICE PROVIDER ( TSP-1 ) UTILITY (U-1) TRANSMISSION SERVICE PROVIDER (TSP-1)

10. Transmission Assets (TA – 1 to n) ONE REGIONAL GRID TWO UTILITIES WITH ONE TRANSMISSION SERVICE PROVIDER (TSP-1) UTILITY (U-1) TRANSMISSION SERVICE PROVIDER (TSP-1) UTILITY (U-2)

11. Transmission Assets (TA – 1 to n) ONE REGIONAL GRID MULTIPLE UTILITIES WITH ONE TRANSMISSION SERVICE PROVIDER (TSP-1) UTILITY (U-1) UTILITY (U-2) UTILITY (U-3) UTILITY (U-4) TRANSMISSION SERVICE PROVIDER (TSP-1) UTILITY (U-n)

12. ONE REGIONAL GRID MULTIPLE UTILITIES WITH TWO TRANSMISSION SERVICE PROVIDERS UTILITY (U-1) TRANSMISSION SERVICE PROVIDER (TSP – 1) Transmission Assets (T1A 1-n) UTILITY (U-2) UTILITY (U-3) UTILITY (U-4) TRANSMISSION SERVICE PROVIDER (TSP – 2) Transmission Assets (T2A 1-n) UTILITY (U-n)

13. ONE REGIONAL GRID MULTIPLE UTILITIES WITH MULTIPLE TRANSMISSION SERVICE PROVIDERS UTILITY (U-1) TSP – 1 Transmission Assets (T1A 1-n) UTILITY (U-2) TSP – 2 Transmission Assets (T2A 1-n) UTILITY (U-3) TSP – 3 Transmission Assets (T3A 1-n) UTILITY (U-4) TSP – m Transmission Assets (TmA 1-n) UTILITY (U-n)

14. U-1 D-1 D-n TSP – 1 Transmission Assets (T1A 1-n) U-2 D-1 D-n TSP – 2 Transmission Assets (T2A 1-n) U-3 D-1 D-n TSP – 3 Transmission Assets (T3A 1-n) U-4 D-1 D-n TSP – m Transmission Assets (TmA 1-n) ONE REGIONAL GRID U-n D-1 D-n DISCOMS: COMPLEXITY INCREASED FURTHER(D-1 TO D-N): DISCOMS PAY DIRECTLY TO TSPS

15. U-1 D-1 D-n TSP – 1 Transmission Assets (T1A 1-n) U-2 D-1 D-n TSP – 2 Transmission Assets (T2A 1-n) U-3 D-1 D-n TSP – 3 Transmission Assets (T3A 1-n) U-4 D-1 D-n TSP – m Transmission Assets (TmA 1-n) REGIONAL GRID -2 REGIONAL GRID -1 U-n D-1 D-n MULTIPLE REGIONS U-1 D-1 D-n TSP – 1 Transmission Assets (T1A 1-n) U-2 D-1 D-n TSP – 2 Transmission Assets (T2A 1-n) U-3 D-1 D-n TSP – 3 Transmission Assets (T3A 1-n) U-4 D-1 D-n TSP – m Transmission Assets (TmA 1-n) U-n D-1 D-n Inter-Regional Interconnections

16. U-1 D-1 D-n TSP – 1 Transmission Assets (T1A 1-n) U-2 D-1 D-n TSP – 2 Transmission Assets (T2A 1-n) U-3 D-1 D-n TSP – 3 Transmission Assets (T3A 1-n) U-4 D-1 D-n TSP – m Transmission Assets (TmA 1-n) REGIONAL GRID -2 REGIONAL GRID -1 U-n D-1 D-n TSPS IN ONE REGION HAVING CUSTOMERS IN ANOTHER REGION ALSO U-1 D-1 D-n TSP – 1 Transmission Assets (T1A 1-n) U-2 D-1 D-n TSP – 2 Transmission Assets (T2A 1-n) U-3 D-1 D-n TSP – 3 Transmission Assets (T3A 1-n) U-4 D-1 D-n TSP – m Transmission Assets (TmA 1-n) U-n D-1 D-n Inter-Regional Interconnections

17. U-1 D-1 D-n U-2 D-1 D-n U-3 D-1 D-n U-4 D-1 D-n U-1 D-1 D-n U-2 D-1 D-n U-3 D-1 D-n U-4 D-1 D-n U-n D-1 D-n U-n D-1 D-n ALTERNATE FEASIBLE MODEL AGENCY FOR BILLING & COLLECTION TSP – 1 Transmission Assets (T1A 1-n) Region -1 TSP – 2 Transmission Assets (T2A 1-n) TSP – 3 Transmission Assets (T3A 1-n) Region -2 TSP – m Transmission Assets (TmA 1-n)

18. FOCUS • Economic/Regulatory Objective • Operational Efficiency • Minimisation of Present Operating Cost • Dynamic Efficiency • Long-term development of system • Allocative Efficiency • Equity and fairness in assigning costs

19. POWERGRID ALLOCATIVE EFFICIENCY - OBJECTIVES • Simplicity • Non-discriminatory/Equitable • Predictable • Strong signal for efficiency, location and expansion • Ease of regulation and administration • Dispute free Implementation • Minimize Cross Subsidies • Transparency of Procedures • Continuity – Smooth transition from existing practice

20. Transmission Pricing Paradigms

21. Paradigm • Rolled in Paradigm • Postage stamp • Contract Path Method • MW-Mile • Distance based • Power flow based (several variant such as MM, DFM, ZCF) • Incremental Transmission Pricing Paradigm • Long/Short Run Incremental/Marginal • Composite embedded / incremental transmission Pricing Paradigm

22. POWERGRID Comparison of different methods in Transmission Pricing Paradigm • Postage Stamp Method – ++ Simple, familiar, most widely used in developing market -- insensitive to distance & direction • Zonal Postage Stamp Method ++ sensitive to distance and direction -- complex, difficult to implement, load flow condition varies with dispatch scenario • Contract Path Methodology ++ Sensitive to distance -- provides wrong economic signal, based on fictitious path, power flow on parallel path is ignored

23. COMPARISON OF DIFFERENT METHODS IN TRANSMISSION PRICING PARADIGM • Distance Based MW-Mile Methodology ++ Simple, sensitive to distance -- based on physical distance, not on actual power flow • Power Flow Based MW- Methodology ( MM/ DFM/ZCF)/Power Tracing ++ sensitive to distance, takes planning and usage of network in consideration -- issue of net vs absolute power flow, absolute ignores directional sensitiveness, varies with dispatch scenario • Point tariff, Nodal Pricing or Locational Marginal Pricing (LMP) ++Provides economic signals, suitable for developed/saturated market -- complex, not suitable for developing market, losses forms the part of transmission pricing, based on MWh not on MW.

24. SHARING OF INTER-STATE TRANSMISSION CHARGES AND LOSSES-REGULATIONS

25. DEFINITIONS

26. DEFINITIONS • Designated ISTS Customers (‘DIC’s)  Users of any segments/elements of the ISTS and shall include all generators, STUs, SEBs or load serving entities directly connected to the ISTS including Bulk Consumer and any other entity/person • Implementing Agency (IA) 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 • Approved Injection Injection in MW vetted by IA for the DIC 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 DIC incorporating total injection into the grid, considering the long term and medium term contracts;

27. DEFINITIONS • Approved Additional Medium Term Injection  means the additional injection, as per the MTOA approved by CTU after submission of data to NLDC by the DIC over and above the Approved Injection for the DIC for each representative block of months, peak and off-peak scenarios at the ex-bus of the generator or any other injection point of the DIC into the ISTS • Approved Short Term Injection The injection, as per the STOA approved by RLDC /RLDC & including PX • Similarly we have Approved Withdrawal (simultaenous withdrawal), Approved additional MT withdrawal & Approved ST withdrawal • Deemed Inter State Transmission System (Deemed ISTS) Transmission system which has regulatory approval of the Commission as being used for interstate transmission of power and qualified as ISTS • Point of Connection (PoC) transmission charges  Nodal / zonal charges determined using the POC method

28. DEFINITIONS • Yearly Transmission Charge (YTC) Annual Transmission Charges for existing lines determined by the Commission in accordance with the Terms and Conditions of Tariff Regulations or adopted in the case of tariff based competitive bidding in accordance with the Transmission License Regulations and for new lines based on benchmarked capital costs • Uniform Charge  Charged determined by dividing the YTC of the ISTS Licensees by the sum of the Approved Injection and Approved Withdrawal from the grid(postage stamp charge)

29. SCOPE OF THE REGULATIONS • Power Stations / Generating Stations that are regional entities as defined in the Indian Electricity Grid Code (IEGC) • SEBs/ STUs connected with ISTS (on behalf of distribution companies, generators and other bulk customers connected to the transmission system owned by the SEB/STU/intrastate transmission licensee) • Any bulk consumer directly connected with the ISTS • Any designated entity representing a physically connected entity as per clauses above • Regional Entity Those who are in the RLDC control area and whose metering and energy accounting is done at the regional level

30. PRINCIPAL/MECHANISM FOR SHARING OF ISTS CHARGES AND LOSSES PRINCIPLES: Load Flow Based Method Point of Connection Charging Method MECHANISM PoC Charges and Losses in advance Based on Technical and Commercial Information provided by DICs, ISTS Transmission Licensees, NLDC, RLDCs and SLDCs Charges for LTA/MTOA : Rs/MW/Month Charges for STOA : Rs/MW/Hour

31. PROCESS FOR DETERMINATION OF POC CHARGES & LOSSES Data Collection Regulation 7(1) DICs, Transmission Licensees to submit Basic Network Data Network Data for Load Flow Analysis Regulation 7(1)(b) Electrical Plant or line upto 132 kV Generators connected at 110 kV Inflow from lower levels  generation at that node Outflow towards lower levels  Load at that node Dedicated Transmission Lines Regulation 7(1)(c) Owned and Operated by ISTS………. Included in Basic Network Owned and Operated by Generator….Excluded

32. Data Collection (1) As per the Regulation and Data Collection Procedure All concerned entities to submit Details of Network Elements Generation and Load at various nodes Yearly Transmission Charges Forecast Injection / Withdrawal Additional Medium Term Withdrawal / Injection By 10th of every month by every DIC RPC to send list of certified non-ISTS lines to IA IA to send the lists to CERC for approval YTC of Certified non-ISTS lines to be approved from appropriate commission

33. INFORMATION PROCEDURES Data to be submitted by DICs YTC, Basic Network Details of ISTS, Deemed ISTS, Certified ISTS Lines Demand or Injection Forecast for each season On or Before the end of fourth week of November Data to be submitted by CTU, Owners of Deemed ISTS and DICs Entire Network Data for first year of Implementation Dates and data of commissioning of any new transmission asset for subsequent years

34. INFORMATION PROCEDURES Injection and Withdrawal forecast for different blocks of months (Peak and Other than Peak): Regulation 16(4) April to June…………………………… (May 15) July to September……………………. (August 31) October to November………………… (October 30) December to February……………….. (January 15) March…………………………………… (March 15) In case any of the above fall on a Weekend/Public Holiday, the data shall be submitted for working days immediately after the dates indicated. 34 11/17/2014 राष्ट्रीय भार प्रेषण केंद्र

35. FLOW CHART FOR DATA ACQUISITION Designated ISTS Customers STU/SEBs/CTU Nodal Injection / Withdrawal Additional Medium Term Injection / Withdrawal Network Parameters Line wise YTC Network Parameters Implementing Agency Approved Injection Approved Withdrawal Basic Network

36. Nodal Generation / Demand Regulation 7(1)(d) / (e) Based on Forecast provided by DICs Forecast should be based on Long Term and Medium Term Contracts Forecast Generation to be vetted by IA based on Historic Generation / Demand. Changes in Generation /Demand to be Communicated to DICs In case of conflict validation committee to take final decision IA to perform AC Load flow Regulation 7(1)(h) To obtain LGB & for achieving convergence adjustments may be required to be made on vetted generation/demand Converged Load Flow results to be verified by Validation Committee Regulation 7(1)(i)

37. VALIDATION COMMITTEE Nominee from Commission to Chair the Committee Regulation 7(1)(g) Validation Committee Comprises two officials each from: Implementing Agency National Load Despatch Centre Regional Power Committee Central Transmission Utility Central Electricity Authority Central Electricity Regulatory Commission 37 11/17/2014 राष्ट्रीय भार प्रेषण केंद्र

38. NETWORK TRUNCATION Network Truncation by IA Regulation 7(1)(k) Upto 400 kV except NER, where it shall be reduced to 132 kV Annexure I, Clause 2.3 Power inflow from Lower voltage Level : Generation Node Annexure I, Clause 2.3 Power outflow from Lower voltage Level : Demand Node Annexure I, Clause 2.3 AC Load Flow on Truncated Network Annexure I, Clause 2.3

39. COMPUTATION OF POC CHARGES (1) Average YTC per circuit km(for each voltage level & conductor configuration) shall be used for computation of charges Regulation 7(1)(l) e.g. 400 KVD/C twin Moose, 400 kV Quad Moose, 400 kV Quad Bersimis etc., YTC of substations to be apportioned in line Regulation 7(1)(m) 2/3 to higher voltage lines 1/3 to lower voltage lines Apportionment among lines on the basis of length in ckt. kms PoC Charges to be computed for 5 blocks of month for peak and other the peak conditions

40. COMPUTATION OF POC CHARGES (2) Representative Blocks of Months Regulation 7(1)(o) April to June July to September October to November December to February March Peak Hours : 8hrs Regulation 7(1)(o) Other the Peak Hours :16 Hrs Average YTC to be apportioned to peak and other than peak based on the no. of hours constituting these periods Regulation 7(1)(p) 50% recovery through Hybrid Methodology and 50% through Uniform Charge Sharing Mechanism(for first two years ) Regulation 7(1)(q)

41. COMPUTATION OF POC LOSSES Loss Allocation Factor to be computed for each season using Hybrid Methodology Regulation 7(1)(r) 50% losses through Hybrid Method and 50% through Uniform Loss Allocation Mechanism(for first two years) Regulation 7(1)(s) Weighted average of LAF for peak and other than peak conditions shall be used Regulation 7(1)(s) Loss Application as per the Procedure prepared by NLDC

42. ZONING Criteria for Zoning of nodes: Regulations7(1)(t) Costs within the same range Geographically and electrically proximate Nodes with connectivity to Thermal Generators > 1500 MW or Hydro Generators > 500 MW to be taken as separate zone. Demand zones : Sate Control Area Except NER states where entire region is to be taken as one zone. Zonal Charges : Weighted Average of Nodal Charges Annexure I, Clause 2.2 Revision of Zones in a financial year Significant Changes in Power System Prior approval from commission Regulations7(1)(t)(vi) Generating stations connected to ISTS network < 400KV would be charged at zonal charges where physically located No transmission charges/losses for solar projects (for the entire useful life) commissioned within next 3 years.

43. SPECIFIC CHARGES Charges thus determined to the extent of approved injection/withdrawal for each DIC In the event of a Designated ISTS Customer failing to provide its requisition for demand or injection for an Application Period, the last demand or injection forecast supplied by the DIC and as adjusted by the Implementing Agency for Load Flow Analysis shall be deemed to be Approved Withdrawal or Approved Injection In case the metered MWs (ex-bus) of a power station or the aggregate demand of a Designated ISTS Customer exceeds, in any time block, (a) In case of generators: The Approved Injection + Approved Additional Medium Term Injection + Approved Short Term Injection or; (b) In case of demand customers: The Approved Withdrawal + Approved Additional Medium Term Withdrawal + Approved Short Term Demand, Additional charges would be applicable for deviation

44. SPECIFIC CHARGES For deviation > 20% in any time block, the DIC shall be required to pay transmission charges for excess generation @ 25% above the zonal POC charges determined for zone where the Designated ISTS Customer is physically located Such additional charges would not be applicable in case:: Rescheduling of the planned maintenance program which is beyond the control of the generator Certified by RPC Payment on account of additional charges for deviation by the generator shall not be charged to its long term customer and shall be payable by the generator

45. SPECIFIC CHARGES Even if in case of injection / withdrawal < Approved injection/withdrawal allocated transmission charges to be fully paid After declaration of COD of a generator, charges payable by generators for LT supply shall be billed directly to the LT customers based on capacity share in the generating stations However, before COD, charges to be borne by generators There would be no differentiation between POC charges/losses for LT/MT/ST customers

46. IMPLEMENTING AGENCY (IA) (Chapter 8) For First Two Years Regulation 18(1) NLDC shall be Implementing Agency Procedures to be prepared by IA Procedure for Data Collection Procedure for Loss Sharing Procedure for Transmission Charge Computation Expenses of IA to be included in YTC and approved by Commission Regulation 18(4)

47. TREATMENT OF HVDC Annexure I Clause 2.7 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 47 11/17/2014 राष्ट्रीय भार प्रेषण केंद्र

48. Indirect Method for HVDC Cost Allocation 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[Benefit = (old cost i.e. base case with injection from Talchar Kolar) minus (new usage cost i.e. with link disconnected)] In case benefit –ve same to be collared to zero Allocate HVDC line cost to the identified nodes.

49. Module on Computation of PoC Transmission Charges National Load Despatch Centre Power System Operation Corporation

50. Process Chart for Computation of PoC Charges Data Collection Zoning PoC Charges & Losses Computation Basic Network Preparation Load Flow Studies Network Reduction