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Sharing of Inter State Transmission Charges

Sharing of Inter State Transmission Charges. Eastern Regional Load Despatch Centre. Contents. Historical Background Overview of proposed framework Important decisions of Implementation Committee Important decisions of Validation Committee Orders on removal of difficulties

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Sharing of Inter State Transmission Charges

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  1. Sharing of Inter State Transmission Charges Eastern Regional Load Despatch Centre

  2. Contents Historical Background Overview of proposed framework Important decisions of Implementation Committee Important decisions of Validation Committee Orders on removal of difficulties Progress of Implementation Results of Computation of PoC Charges and Losses for 2011-12

  3. Fundamental Principles • Objectives of Pricing system • Promote the efficient day-to-day operation of the bulk power market; • Signal locational advantages for investment in generation and demand; • Signal the need for investment in the transmission system; • Compensate the owners of existing transmission assets; • Simple and transparent • Politically implementable

  4. Desirable Features of a Transmission Pricing Scheme • Reasonable revenue to the transmission system owners • Equitable sharing of the above payment between the transmission system users, according to benefits derived • Inducement to transmission system owner to enhance the availability of the system • Ensuring that merit - order dispatch of generating stations does not get distorted due to defective transmission pricing

  5. Desirable Features of a Transmission Pricing Scheme • Ensures that planned development / augmentation of the transmission system, which is otherwise beneficial, does not get inhibited • Appropriate commercial signal for optimal location of new generating stations and loads • Treatment of transmission losses – whether handled separately or as a part of transmission charges • Priority of transmission system usage between users under different categories

  6. Desirable Features of a Transmission Pricing Scheme • Revenue of transmission system owner, in a vertically unbundled scenario, should not depend on dispatch decisions and actual power flows • To the extent possible, the users should know upfront what charges they would have to pay, and retrospective adjustments should be avoided • Dispute-free implementation on a long-term basis

  7. 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

  8. Policy Mandate Electricity Act 2003 • National Electricity Policy • Tariff Policy

  9. 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….”

  10. 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…..

  11. Historical Background

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

  13. 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

  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) 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

  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 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

  16. 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)

  17. Previous Method Regional Postage Stamp Method in Long Term Market Contract Path Tariff in Short Term Bilateral Market Point of Connection Tariff in Power Exchanges

  18. Sharing of Transmission charges - earlier 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

  19. Illustration of earlier Methodology (1/2) Gen D Region A State D ARR of Region A : 100 Cr राष्ट्रीय भार प्रेषण केंद्र

  20. Illustration of earlier Methodology (2/2) • Uniform Charges : Rs 0.083 Cr / MW Total ARR --------------------------------------------------------------------------------------- Demand (State A+ State B+ State C) +Export to Other Region राष्ट्रीय भार प्रेषण केंद्र

  21. Drivers for change in pricing framework • Pricing inefficiency in the emerging circumstances • 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

  22. 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)

  23. New Methodology • In Rs. per MW per month • Nodal / Zonal Charges • Separate Injection & Withdrawal Charges • To be made known upfront • To be applied on Medium Term and Short Term Trades • Based on Load Flow Studies • Hybrid of Average Participation and • Marginal Participation methods • To begin with 50% Uniform Charges and 50% PoC Charges • Gradual movement towards 100% PoC Charges • Three Slab Rates for initial years.

  24. New Framework CTU IMPLEMENTING AGENCY NETWORK DICs (Billing, Collection and Disbursement) YTC PoC Tariff (50%UC+50%PoC) Injection/ Withdrawal ISTS Licensees RPCs LTA/MTOA (Accounting)

  25. 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

  26. Hybrid Methodology • Hybrid of • Average Participation • Marginal Participation • Average Participation • Used to identify slack (responding) buses for each node using the theory of real power tracing • Marginal Participation • To compute the participation factor of each node on each line.

  27. What is Power Tracing?: Definition power flow snap-shot Power Tracing is a tool, applied Post-facto on that provides complete power audit information like: Share of loads in Generation Generators’ contribution in Loads Decomposition of Transmission line flows into Generator and Load Components Loss allocation to generators and Loads

  28. What are pre-requisites of Power Tracing? Power Flows over lines and, Injections at generator and load buses and, Network topology (single line diagram) State Estimation Solution Or

  29. Power Tracing: Two Versions Downstream Algorithm Each Generator’s contribution in Transmission Line flows Generator Side Statements Each Generator’s contribution in Transmission Line losses Net power sent to a particular load Upstream Algorithm Each Load’s contribution in Transmission Line flows Load Side Statements Each Load’s contribution in Transmission Line losses Power received from a particular generator including losses

  30. Proportionate Sharing Principle j k 40 60 i 70= (28 + 42) 30 = (12 +18) m l

  31. 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

  32. 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

  33. 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

  34. Information flow chart Truncation of basic network, (creation of virtual generators / loads) load flow, & Transmission losses of truncated network Basic Network data Load flow on complete network Power System Model ApprovedNodal Injection & withdrawal Average Transmission Charge per ckt kilometer for a voltage level & conductor configuration YTC of line + YTC of substation apportioned to lines of a voltage level 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

  35. 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

  36. 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.

  37. 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

  38. Sample Calculation

  39. 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

  40. Determination of PoC Charges (4) • Philosophy for identification of coherent nodes for zoning • Zones to be geographically and electrically proximate • Shall contain relevant nodes whose costs determined by the hybrid method are within same range • 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 thermal plants ≥ 1500 MW / hydro plants ≥ 500 MW connected directly to ISTS or through pooling stations to be considered as separate generation zone.

  41. 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

  42. 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

  43. 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.

  44. Advantages Fulfill Policy mandate Scientific and elegant way of handling the complexities in planning network Accommodates Multiple Transmission Licensee Regime Necessary for Large Capacity Corridors Certainty in Transmission Rate : Year ahead declaration Market Friendly Facilitate competitive bidding Single Point Clearance Prior agreement not a pre-condition Declaration of Transmission requirement No Pancaking

  45. 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)

  46. 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

  47. Billing and Collection of Charges by CTU Central Transmission Utility First Part (Based on Approved Injection/Withdrawal and PoC Charge) After issuance of RTA Second Part (Recovery of Charges for Additional Medium Term Open Access) After issuance of RTA 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

  48. 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

  49. 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

  50. 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

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