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

2 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

3 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

4 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

5 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

6 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

7 Policy Mandate Electricity Act 2003 National Electricity Policy Tariff Policy

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

9 Policy Mandate – Tariff Policy Section 7.1 : Transmission Pricing Section “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 “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…..

10 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 onwards

11 Development of Transmission System GENERATION DISTRIBUTION TRANSMISSION GENCO TRANSCO DISCO Unbundling

12 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

13 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

14 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

15 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

16 Existing Method Regional Postage Stamp Method in Long Term Market Regional Postage Stamp Method in Long Term Market Contract Path Tariff in Short Term Bilateral Market Point of Connection Tariff in Power Exchanges

17 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 –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 By beneficiary directly served

18 Illustration of Present Methodology (1/2) Gen. AGen. BGen. CGen D State A State B State C State D Region A Gen D State D ARR of Region A : 100 Cr 6/24/2016 राष्ट्रीय भार प्रेषण केंद्र 18

19 Illustration of Present Methodology (2/2) Uniform Charges : Rs Cr / MW Total ARR Demand (State A+ State B+ State C) +Export to Other Region Total ARR Demand (State A+ State B+ State C) +Export to Other Region StateTransmission Charge State A33 Cr State B33 Cr State C25 Cr State D08 Cr 6/24/2016 राष्ट्रीय भार प्रेषण केंद्र 19

20 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

21 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)

22 Methodology Proposed in India Point of Connection (PoC) Charges Usage Based Methodology Handling Transition 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.

23 Proposed Framework NETWORK YTC Injection/ Withdrawal LTA/MTOA DICs ISTS Licensees PoC Tariff (50%UC+50%PoC) RPCs (Billing, Collection and Disbursement) (Accounting) CTU

24 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 –For a period of 5 years unless reviewed or extended by the Commission

25 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.

26 Average Participation Tracing of Power –Load Tracing –Generator Tracing

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

28 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

29 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

30 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

31 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

32 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

33 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

34 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.

35 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

36 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.

37 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

38 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

39 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

40 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

41 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

42 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

43 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

44 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

45 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/ Allocation North SINGRAULI STPS RIHAND I STPS RIHAND0II STPS UNCHAHAR I TPS UNCHAHAR II TPS UNCHAHAR III TPS DADRI NCTPS I DADRI NCTPS II DADRI NCGPS ANTA GPS AURAIYA GPS NAPS RAPP B RAPP C SALAL CHAMERA I HPS CHAMERA II HPS TANAKPUR HPS BAIRASIUL HPS URI HPS DHAULIGANGA NATHPA JHAKRI DULHASTI TEHRI STAGE I SEWA II HEP From North to East Farakka Kahalgaon I Kahalgaon II Talcher Rangeet Teesta Mejia DVC DVC to Delhi Hirakud GRIDCO TALA Chukha Kurichhu From East to West KORBA STPS VINDHYACHAL STPS I VINDHYACHAL STPS II VINDHYACHAL STPS III KAWAS GANDHAR SIPAT KAKRAPAR APS TARAPUR APS 1& TARAPUR APS 3& SSP Pench NSPCL Bhilai From West to South NTPC,RAMAGUNDAM I &II NTPC,RAMAGUNDAM III NTPC,TALCHER II NEYVELLI LC TPS II0I NEYVELLI LC TPS II0II NEYVELLI LC TPS I EXP NPC,MAPS NPC,KGS UNITS 1& NPC,KGS UNITS From South to North East AGBPP, NEEPCO AGTPP, NEEPCO Doyang, NEEPCO Kopili, NEEPCO Kopili 2, NEEPCO Khandong, NEEPCO Ranganadi, NEEPCO Loktak, NHPC From North East to

46 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

47 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

48 Data Quantum Buses Branches Generating Stations Generating Units Loads Transformers 4830 No.s 557 No.s1148 No.s 2672 No.s DC Lines : 7 No.s 765 kV : 2 No.s 400 kV : 622 No.s 220 kV : 3034 No.s 132 kV : 5130 No.s 2031 No.s

49 Thank You!