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Sharing of Inter State Transmission Charges

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

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Sharing of Inter State Transmission Charges

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  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

  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 GENCO Unbundling TRANSCO TRANSMISSION DISCO DISTRIBUTION

  7. Scenario in Recent Past 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) ONE REGIONAL GRID

  8. 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 Present Scenario: Increasing Complexities 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

  9. 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 Future Scenario : More Complexities 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

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

  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 : 15th 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 • 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. Important Definitions Chapter 1 ApprovedWithdrawal “Approved withdrawal means the simultaneous withdrawal in MW vetted byImplementing Agency for any Designated ISTS Customer in a control areaaggregated from all nodes of ISTS to which Designated ISTS Customer isconnected, for each representative block of months, peak and other than peakscenarios at the interface point with ISTS, and where the ApprovedWithdrawal shall be determined based on the demand data submitted by theDesignated ISTS Customers. incorporating long term and medium term transactions.”

  22. Important Definitions Chapter 1 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.”

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

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

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

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

  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. 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 • Allocate HVDC line cost to the identified nodes.

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

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

  37. Billing of Transmission Charges • 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

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

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

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

  41. Long Term Allocation Matrix

  42. 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

  43. 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

  44. Thank You!

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