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

INTRODUCTION

EVOLUTION OF TRANSMISSION PRICING 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 (Usage & Distance/Direction sensitivity based) Upto 1991 1992-2002 2002-2011 2011 onwards 4/20/2017

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

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 4/20/2017

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 POWERGRID 4/20/2017

राष्ट्रीय भार प्रेषण केंद्र Changing Structure of Indian Power Sector and development of Electricity Markets 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

VERTICALLY INTEGRATED UTILITY GENERATION TRANSMISSION DISTRIBUTION

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

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

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

MULTIPLE UTILITIES WITH TWO TRANSMISSION SERVICE PROVIDERS ONE REGIONAL GRID 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)

MULTIPLE UTILITIES WITH MULTIPLE TRANSMISSION SERVICE PROVIDERS ONE REGIONAL GRID 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)

DISCOMS: COMPLEXITY INCREASED FURTHER (D-1 TO D-N): DISCOMS PAY DIRECTLY TO TSPS ONE REGIONAL GRID 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-1 D-n

MULTIPLE REGIONS Inter-Regional Interconnections TSP – 1 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-1 D-n REGIONAL GRID -2 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

TSPS IN ONE REGION HAVING CUSTOMERS IN ANOTHER REGION ALSO 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-1 D-n REGIONAL GRID -2 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

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

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

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 POWERGRID 4/20/2017

Transmission Pricing Paradigms

Paradigm Rolled in Paradigm Incremental Transmission Pricing 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

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 POWERGRID 4/20/2017

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.

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

DEFINITIONS 25

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;

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

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)

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

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

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

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

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

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 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

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

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)

राष्ट्रीय भार प्रेषण केंद्र 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 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

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

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

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)

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 Loss Application as per the Procedure prepared by NLDC

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.

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

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

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

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)

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 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

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.

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

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

Data Collection (2) NLDC to specify : IA to specify : Nodes/group of nodes on which DICs would submit the forecasted injection/withdrawal. IA to specify : Peak and other than Peak conditions for each representative blocks for the next application period.

Approved Injection/ Withdrawal Approval of Forecasted Injection/Withdrawal on the basis of Long Term and Existing Medium Term Contracts Database of RLDC/NLDC Approved Demand/Withdrawal to be notified on the website of IA Adjustments in forecasted Injection/withdrawal to be intimated to concerned DIC.

Computation of AC Load Flows Seprately for NEW and SR Grid Adjustments for converging Load Flow If Load > Generation Pro-rata scaling down of Load If Generation > Load Pro-rata scaling down of Generation Validation committee to validate Converged Load Flow Results Basic Network Nodal Injection / Withdrawal

Network Reduction Reduction upto 400 kV (except NER where the network will be reduced to 132 kV) Injection from Lower Voltage : Generation Drawal from Lower Voltage : Demand PoC Charges and LAF Software Reduced Network Average YTC after Truing up

Computation of Charges Annual Average YTC to be apportioned to peak and Other than peak conditions Net PoC Charge = 50% PoC Charge + 50% Uniform Charge UC = Total ARR /(Approved injection +approved Withdrawal) Calculation of Uniform Charge on All India Basis Scaling on Pro-rata basis to adjust over or under recovery Treatment of Generators connected at 220 kV Charged at PoC Charge of the zone

Zoning As per the regulations Fixed for an application period Zonal Charges / Zonal LAF Weighted average of all nodes in the zone Treatment of nodes feeding more than one zone To be used in both zones Pro-rata charges in both zones based on ratio of power flow.

Information to RPC Approved Withdrawal/Injection (MW) for peak and other than peak hours for each season Zonal Point of Connection Charge (Rs/MW/month) for Generation and Demand Zones Approved Additional Medium Term Withdrawal / Injection (MW) Details of Short Term Open Access As per format I and II of the Procedure

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

Format I :Approved Withdrawal/Injection (MW) & Zonal PoC Charge Name of the Zone Approved Withdrawal (MW) Approved Injection Zonal PoC Charge* (Rs/MW/Month) Peak Other Than Peak Season I Season II Season III Season IV Season V

Format II: Approved Additional Medium Term Withdrawal/Injection Name of DIC Duration Approved Additional Medium Term Withdrawal (MW) Approved Additional Medium Term Injection From To Peak Other Than Peak

ACCOUNTING BILLING & COLLECTION OF CHARGES(CHAPTER 5)

INPUTS FOR MONTHLY TRANSMISSION ACCOUNTS Approved injection / withdrawal from IA Zonal POCs from IA Approved additional MT injection/withdrawal RLDC/NLDC Approved ST injection/withdrawal from RLDC/NLDC SEM data for deviation computations RPCs to issue monthly transmission accounts(1st working day of the Month) RPCs to issue monthly transmission deviation acounts(by 15th of the Month) CTU shall be responsible for raising the transmission bills, collection and disbursement of transmission charges to ISTS transmission licensees Expenses incurred by CTU on account of this function shall be reimbursed as part of YTC

Accounting Regulation 10 Regional Power Committee Regional Transmission Accounts (1st Working Day of Every Month for the previous Month) Regional Transmission Deviation Accounts (by 15th Day 63 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

राष्ट्रीय भार प्रेषण केंद्र Billing (1) Regulation 11 Responsibility of Central Transmission Utility (CTU) Based on Accounts issued by RPC Long Term Customers shall be billed directly for: Own Transmission Charges Generator Transmission Charges in proportion to MW entitlement after “Commercial Operation” Generators shall be billed only for deviations. Bill to be raised only on DIC’s SEB/STU may recover such charges from DISCOMs, Generators and Bulk Consumers. 64 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

Central Transmission Utility राष्ट्रीय भार प्रेषण केंद्र Billing (2) 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 65 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

BILL PART-I To be raised by 1st working day of the month by CTU Independent of Transmission accounts to be issued by RPCs For Generators [ (PoC Transmission Charge of generation zone in Rs / MW / month for peak hours)× (Approved Injection for peak hours) ] + [ (PoC Transmission Charge of generation zone in Rs / MW / month for off-peak hours) x (Approved Injection for off-peak hours) ] For Demand [ (PoC Transmission Charge of demand zone in Rs / MW / month for peak hours)x(Approved withdrawal for peak hours) ] [ (PoC Transmission Charge of demand zone in Rs / MW / month for off-peak hours) x (Approved withdrawal for off-peak hours) ]

BILL PART-II To be simultaneously raised alongwith BILL-PART-I For Generators [ (PoC Transmission Charge of generation zone in Rs / MW / month for peak hours)× (Approved Additional MediumTerm Injection for peak hours) ] + [ (PoC Transmission Charge of generation zone in Rs / MW / month for off-peak hours) x (Approved Additional MediumTerm Injection for off-peak hours) ] For Demand [ (PoC Transmission Charge of demand zone in Rs / MW / month for peak hours)x(Approved Additional MediumTerm withdrawal for peak hours) ] [ (PoC Transmission Charge of demand zone in Rs / MW / month for off-peak hours) x (Approved Additional MediumTerm withdrawal for off-peak hours) ] Revenue from Additional MTOA alongwith interest to be used for truing up the YTC for next F.Y.(i.e would be adjusted in YTC of the licensee for computation of POC for next F.Y.)

BILL PART-IV (TREATMENT OF DEVIATIONS) REGULATION 11(7) Deviation calculations after considering additional MT & Short Term Open Access for each time block Deviation = [Average MW injected/withdrawn] - [ (Approved injection/withdrawal+Approved additional MT injection/withdrawal+ST injection/withdrawal) ] Charge to be Calculated on Block wise Deviation Deviations by Generator shall not be charged to Long Term Customers No additional Charge for Deviations in case : Rescheduling of Maintenance Schedule for reasons beyond control of geenrator OR Certified by RPC

Treatment of Deviations -GENERATOR Net Injection Net Drawl Deviation Less than 20% Deviation Greater than 20% 1.25 times PoC Charge for the average MW withdrawal PoC Charge 1.25 times PoC Charge for the excess deviation > 20%

Treatment of Deviations –Demand Customer Net Drawl Net Injection Deviation Less than 20% Deviation Greater than 20% 1.25 times PoC Charge for the average MW injected PoC Charge 1.25 times PoC Charge for the excess deviation > 20%

BILL PART-IV (TREATMENT OF DEVIATIONS) REGULATION 11(7) Thus additional charges due to deviations = 1.25 x POC transmission charge for demand / withdrawal x Deviations In case a generator withdraws from grid:: Additional charges = 1.25 x POC transmission charge for the demand zone x Average MW withdrawn for the corresponding blocks In case a withdrawing DIC becomes a net injector:: Additional charges = 1.25 x POC transmission charge for the generation zone x Average MW injected for the corresponding blocks Bill for deviations to be raised by CTU within 3 days of issue of Transmission deviation accounts by RPC. This part alongwith interest would be used for truing up the YTC for next F.Y.(i.e would be adjusted in YTC of the licensee for computation of POC for next F.Y.)

BILL PART-III The 3rd Part of the Bill to be raised bi-annully by CTU on the first working day of September & March for the previous six months The bill shall be used to adjust any variations in interest rates, FERV, rescheduling of commissioning of transmission assets, etc. Recovery/Reimbursement would be on basis of under-recovery/over-recovery, in proportion to average approved injection/withdrawal over previous six months CTU to transfer the 3rd part to respective ISTS licensees for whom the adjustment is required

COLLECTION AND DISBURSEMENT REGULATION 12 CTU to collect charges on behalf of ISTS service providers. CTU to disburse in proportion to Monthly Transmission Charges. Payment and Disbursement shall be executed through RTGS. Delayed Payments shall result in pro-rata reduction in all payouts Payment Security as per detailed procedure prepared by CTU

TRANSMISSION SERVICE AGREEMENT(TSA) REGULATION 13 Existing BPTAs realigned  TSA TSA provides for all relevant matters regarding the POC losses/charges mechanism(e.g.):: Detailed Commercial/adminsitrative provisions Metering, accouitnitng, billing, charges recovery provisions Procedures for interconnection Treatment in delay of line commissioning Payment security mechanisms default & consequences Termination & Force majeure conditions Draft TSA to be finalized by CTU and approved by CERC Notified TSA would be the default transmission agreement and would mandatorily apply to all DICs Signing of TSA not a precondition for construction of new network elements by CTU/licensees after approval by CERC TSA may have certain aspects which could be modified from time to time without rendering the TSA infructuous e.g. contracted capacity, etc..

TRANSMISSION SERVICE AGREEMENT(TSA) REGULATION 13 CTU to prepare revenue sharing agreement which is to be approved by CERC for disbursal of monthly transmission charges to various ISTS licnesees The impact of any delayed payment/non-payment by any DIC would be shared pro-rata in proportion of YTC by all the ISTS transmission licensees including CTU Users to ensure that existing contracts(e.g. BPTAs) are realigned to these regulations within a period of 60 days from the date of notification of the TSA

LIST OF PROCEDURES AS A PART OFTRANSITION REGULATION 15 Commission would notify detailed procedures prepared by IA, NLDC & CTU as a part of transition mechanism Procedure for obtaining data  IA Procedure for computation of POC charges  IA Procedure for sharing of losses  IA Procedures for Billing and collection of charges by the CTU on behalf of Transmission Licensees and redistribution  CTU Payment and payment security related procedures  CTU

Information on Public Domain Regulation 17 Approved Basic Network Data and Assumptions, if any Zonal or nodal transmission charges for each block of month Zonal or Nodal Transmission losses data Schedule of Charges payable by each constituent after undertaking necessary true up costs Underlying network information & base load flows

Module on Information Submission By DIC’s National Load Despatch Centre Power System Operation Corporation

Introduction Hybrid Method : Based on Load Flow (Offline Studies) Average participation for slack bus identification Marginal Participation for usage identification Recovery of Charges 50% by Uniform Charge Method 50% by PoC Charge Method

Importance of Data in Hybrid Methodology Input to the Offline Line Model for Load Flow Studies Network Parameters Load and Generation Data ( MW & MVAr) Results of offline line studies highly dependent upon the input to the model Inconsistent data may not make solution Converged May lead to modifications in Approved Demand / Injection

PoC Charge Calculation depends upon : Converged and Reduced Network Line wise YTC provided by Transmission Licensees Approved Injection / Withdrawal Data to be submitted on or before 4th Week of November for next F.Y. The information may be sought by the IA at times other than those if necessary

Software for PoC Charge & Loss Computation Flow Chart Input Network Parameters Load & Generation Data Load Flow Studies Converged Network Network Reduction Reduced Network Software for PoC Charge & Loss Computation Line wise YTC PoC Charges and LAF Output

How to Give Information to IA ? Identify a person(s) who will coordinate with Implementing Agency Communicate the details of Identified Person to the Designated Officer of IA. Name Designation Company Name Office Address Contact Number : Official (Landline) Mobile Number Letter of Authorization

For all communication puposes Formats would be available on the website of IA and all RLDCs after getting permission from the Commission www.nldc.in www.nldcindia.in Submission of data shall be only in electronic spreadsheet formats (MS Excel). For all communication puposes emailid of IA : implementingagency@powergridindia.com Written communication confirming submission of data by e-mail.

Network Parameters Network Data upto 132 kV except where generators are connected to Grid at 110KV Injection below 132 kV : Generation Withdrawal below 132 kV : Load Also include states generation.

Transmission Licensees Forecast Injection / Withdrawal Type of Data DIC’s Transmission Licensees YTC of each ISTS Line Network Data Load & Generation Data Forecast Injection / Withdrawal

Category of Network Parameters Bus Data Generator Data AC Line Data DC Line Data Transformer Data Switched Shunt Data

Bus Data Bus Type Bus Name : Full Name of Substation Conductance Real Component of Shunt admittance to ground In MW at one per unit voltage Should not include resistive impedance load

- for Reactor Susceptance Voltage in kV Reactive Component of Shunt admittance to ground In Mvar at one per unit Should not include reactive impedance load , line charging and line connected shunts Sign Convention + for Capacitor - for Reactor Voltage in kV

Generator Data Bus Name Generator Real Power Ouput Ex Bus Output in MW Generator Reactive Power Output Ex Bus Output in Mvar Maximum and Minimum Generator Reactive Power Output IREG Bus Name of remote type 1 bus whose voltage is to be regulated by this plant

Resistance and Reactance on MVA base MVA Base Total MVA base of the units represented by this machine RT, XT Step up Transformer Impedance in per unit on MVA Base GTAP Step up Transformer off-nominal turns ratio (in pu) Maximum and Minimum Real Power Output RMPCT Percent of total Mvar required to hold the voltage at bus IREG

Load Data Bus Name Real & Reactive Power Component Constant MVA Load Constant Current Load Constant Admittance Load

AC Line Data From Bus Name (I) To Bus Name (J) Circuit Number For D/C line one line will have 1 in this data and 2 for other line Branch Resistance, Reactance and Charging Susceptance In pu on 100 MVA base Rate A Operating limit considering the compensations and length of line Minimum of Thermal, Voltage and Stability limits.

Transformer off-nominal tap ratio Transformer phase shift angle In degrees Positive from untapped to tapped side and vice versa Complex admittance of the line shunt at bus I (GI+j BI) Complex admittance of the line shunt at bus J (GJ+j BJ) Line Length

DC Line Data (Line quantities and Control) DC Line Number Control Mode 0 – Blocked 1 – Power 2 – Current DC Line resistance in Ohms Current or Power Demand If Control mode is 1 then power, if 2 then current.

Scheduled Compounded dc voltage in kV Mode Switch dc voltage If inverter voltage falls below this value and control mode is 1 then it changes to 2. Compounding Resistance Metered end code R for rectifier or I for inverter Minimum Compounded dc voltage

DC Line Data (Rectifier & Inverter Rectifier converter bus name Number of bridges in series Nominal maximum rectifier firing angle Minimum steady state rectifier firing angle Rectifier commutating transformer resistance & reactance per bridge

Rectifier primary base ac voltage Rectifier transformer ratio Rectifier tap setting Maximum rectifier tap setting Minimum rectifier tap setting Rectifier tap step

Rectifier firing angle Tapped side “ from bus” name Untapped side “ to bus” name Commutating capacitor reactance

Transformer Data From Bus To Bus Circuit Number Resistance and Reactance in per unit Phase shift angle Nominal Tap Ratio

Controlled Bus Name Maximum Voltage of Controlled Bus Minimum Voltage of Controlled Bus Max Turns Ratio Turns Ratio Step Increment

Switched Shunt Data Bus Name Control Mode 0 – Fixed 1 – Discrete 2 – Continuous Desired Voltage Upper & Lower Limit Ni : Number of steps for block I Bi : Admittance increment for each Ni steps in block i

Forecast Nodal Injection / Withdrawal (1) Two figure for each block of months One for peak and other for offpeak Five Representative Blocks April to June…………………………… (May 15) July to September……………………. (August 31) October to November………………… (October 30) December to February……………….. (January 15) March…………………………………… (March 15) The data should be of the date mentioned against each block of month. 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. In case large changes in POC are foreseen on account of network or usage IA may undertake revised computations after petition from Commission & directions from CERC Duration of peak hours for each block Specified by NLDC

Forecast Nodal Injection / Withdrawal (2) MW & MVAr Injection / Withdrawal at each node Forecast of MVAr on the basis of Historic Injection /Withdrawal Anticipated Change in Load pf Forecast of MW On the basis of MW entitlements Forecast required for 5 blocks of month For Generators forecast should be equal to the rated capacity Forecast = max(G1) + max(G1) +……………….

Commercial Data Line wise YTC of each ISTS Line Breakup of total YTC among different Voltage Levels. In case of YTC not approved by SERC/CERC Benchmark/Reference cost to be used. YTC of substations to be apportioned in line 2/3 to higher voltage lines 1/3 to lower voltage lines Apportionment among lines on the basis of length.

Certified Non-ISTS Lines Non-ISTS lines certified by RPC as being used as ISTS line will be included in the model. Transmission Licensees to get them certified in RPC. Line wise YTC to be also certified by RPC and approved by CERC. Such List to be provided to IA by Transmission Licensee Latest by Fourth week of November

Sharing of Inter-State Transmission Losses Based on PoC Losses National Load Despatch Centre Power System Operation Corporation

राष्ट्रीय भार प्रेषण केंद्र Introduction The procedure aims to keep computation: Simple Non-Recursive Loss Application on Regional Basis In line with existing practice No Pan caking. Injection and withdrawal loss would be calculated for each zone. 108 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

राष्ट्रीय भार प्रेषण केंद्र New Methodology Point of Connection Losses Independent of Contract Path 50% PoC losses + 50% Uniform Losses Uniform Loss component Based on Regional Losses of last week Moderation of Losses Based on Actual Regional Losses of last week and Losses based on studies 109 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

PoC Loss Computation (1) Computation of changes in losses in the system due to incremental injection / withdrawal at each node. Loss Allocation Factor 110 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

PoC Loss Computation (2) Output of System Studies MW Losses of each node Loss Allocation Factor Weighted average losses (%) for each region Zonal Loss : Weighted Average of losses at each node Moderation of Zonal Losses One PoC Loss for each entity per day Weighted average of peak and other than peak 111 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

Loss Sharing Mechanism Software Provided by CERC Calculation of Previous week Losses from SEM Data Total Losses based on PoC Zonal Losses as Computed from Hybrid Method Moderation Of PoC Losses Total Losses (50% PoC+50%UC) 112 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

Moderation of Losses (1) Need of Moderation Difference in actual and study scenarios Correct computation of injection and drawal schedule of various utilities. Scheduled losses to be closer to actual losses in the system so that system mismatch is avoided. Minimizing the mismatch between UI payable and receivable Moderation at regional Level Moderation Factor = Actual Losses of previous week (Aact) ( In %) ------------------------------------------------------------------ Regional Losses based on Studies (As)(In %) 113 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

राष्ट्रीय भार प्रेषण केंद्र Regional Losses Based on Studies (As) Weighted average losses of a region where A is Total MW losses of a region ∑GNG = Total Injection in a region ∑IIR = Inter Regional Exchange A*100 / (∑GNG ±(∑IIR ) 114 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

Application of Losses in Scheduling Net PoC Loss = 50% Moderated PoC Loss + 50% Uniform Loss Net PoC Loss to be applied on each regional entity Drawee Entity to bear full losses for : Long Term Transactions Medium Term Transactions Bilateral Transactions Injecting Entity and Drawee Entity to share losses for: Collective Transactions 115 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

Case I : Intra-Regional Transactions Zone Moderated Loss (%) A 3 B 5 B A 92.15 MW 100 MW 116 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

Case II : Inter Regional Transactions Zone Moderated Loss (%) A 3 B 5 B 92.15 MW A 97 MW 100 MW 117 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

Case III : Transactions Involving Wheeling Region B 92.15 MW 97 MW A 97 MW 100 MW 118 4/20/2017 राष्ट्रीय भार प्रेषण केंद्र

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