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 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 1991 1992- 2002 2002- 2011 2011 onwards

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

13. 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

14. 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

15. 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

16. 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

17. Previous 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

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. AGen. BGen. CGen D State A100 200----- State B2005010050 State C50 200 State D-----100----- Region A Gen D State D ARR of Region A : 100 Cr 5/25/2016 राष्ट्रीय भार प्रेषण केंद्र 19

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 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 5/25/2016 राष्ट्रीय भार प्रेषण केंद्र 20

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 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.

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

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

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 Upstream Algorithm Generator Side Statements Load Side Statements Each Generator’s contribution in Transmission Line flows Each Generator’s contribution in Transmission Line losses Net power sent to a particular load Each Load’s contribution in Transmission Line flows Each Load’s contribution in Transmission Line losses Power received from a particular generator including losses

30. Proportionate Sharing Principle LineShare of line j-i Share of line k-i i-m i-l j k ml i 4060 70= (28 + 42) 30 = (12 +18)

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 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

33. 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

34. 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 ApprovedNodal Injection & withdrawal Truncation of basic network, (creation of virtual generators / loads) load flow, & 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

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. 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

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. 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

46. 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

47. 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) After issuance of RTA Biannually (1 st Day of September and March 18 th Day of a Month Billing and Collection of Charges by CTU

48. 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

49. 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

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

51. 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

52. CERC Orders on Removal of Difficulties

53. Definition of Approved Injection / Withdrawal Long Term Access (LTA) or PPA/ Contracts –LTA: Most Sacrosanct figure for transmission –PPA/Contracts: used for scheduling purpose Transmission is a sunk investment –Recovery as per approved Transmission Access –Entities availing long term transmission services : liable to pay Proper signal for transmission planning –Incentive for submitting correct transmission requirement 53

54. Scenarios for PoC Computation……..(1) Peak/ Off-peak Scenario –Individual Peak v/s Simultaneous Peak? –Consumption Peak or Network Peak? Fixed and Variable Cost in Transmission –Fixed Cost: Transmission Charges –Variable Cost: Losses; seasonal, peak/ off-peak variation Single PoC rate for a year –Market Friendly –Facilitates Case I bidding

55. Scenarios for PoC Computation……..(2) Tariff Stability: Multi Year Tariff –Para 5.3(h) of National Tariff Policy –Long term visibility Transmission system r emains same irrespective of season / time of day Ease of implementation, comprehension and administration Interplay of multiple PoC with Merit Order Absence of data with DICs Gaming / Disputes / Litigation 55

56. YTC Related Difficulties Avoid Tariff Shock Vintage Issue Separate Line wise and substation wise approved tariff not available. Status of Approved Tariff –Available for 2004-2009 control period. –Not Available for 2009-14 control period –Projects to be commissioned: tariff yet to be determined Total reflection of the actual tariff, through benchmark cost is an issue

57. Slab Rates for PoC Charges…….(1) POC charges obtained vary widely between zones from 5 paisa to over 25 paisa, considering both injection POC and drawal POC separately. CERC directed IA to arrive at three slab rates for the first year, to smoothen the transition process Philosophy of slabs may also be extended to POC losses Slabs determined on the economic principle of “Minimum regret” / “Min-Max Fairness”, which reduce the spread or standard deviation and thus reduce feeling of heartburns

58. Slab Rates for PoC Charges…………(2) Market Friendly More Stability / Certainty More Rational Lesser chances of dispute Easily comprehendible Futuristic 58

59. Tier-based Slab PoC Rates for NEW and SR Grid approved. Average Rates for NEW Grid - 85000 (Rs./MW/Month) and SR Grid - 95000 (Rs./MW/Month), respectively. Tier-based Slab PoC Losses for NEW and SR Grid also approved. CERC Order on Removal of Difficulties dated 22nd June 2011

60. Approved Slab PoC Rates Slab for PoC rates approved by CERC 100000 85000 70000 110000 95000 80000 NEW Grid SR Grid

61. Approved Slab PoC Losses Average Loss (Based on previous week SEM Data) Average Loss + 0.3% Average Loss - 0.3%

62. Progress of Implementation…(1) Two Rounds of Capacity Building Workshops in each Region 6 Meetings of the Implementation Committee 4 Meetings of the Validation Committee Submission of Results for Input Data, PoC Charges and Losses to the Validation Committee on 22nd December 2010, 20th January 2011, 29th March 2011 and 27th May 2011 CERC Orders on Removal of Difficulties dated 4th April 2011, 2nd June 2011, 22nd June 2011, 28 th June 2011 and 29 th June 2011

63. CERC Order on Determination of PoC Rates and Transmission Losses in accordance with the Sharing Regulations dated 29th June 2011 CERC Order on Approval of Procedure of Data Collection along with formats, Procedure for Computation of PoC Transmission Charges and Procedure for Sharing of Losses under the Sharing Regulations Inputs on PoC Charges for each Regional Entity provided to the Power Exchanges on 30 th June 2011 PoC Charges and Losses for 2011-12 implemented w.e.f 1 st July 2011 Weekly Loss Application Provisional RTA Progress of Implementation…(2)

64. Results of PoC Computation of Charges and Losses (2011-12)

65. Handling Bulk Data Buses 4830 Generating Stations 557 Generating Units 1148 Loads 2672 Branches DC Lines7 765 kV2 400 kV622 220 kV3034 132 kV5130 Total8795 Transformers 2031

67. Average Monthly Transmission Charges (Rs/ckm/Month)

69. Slab Rates : NEW Grid Rs/MW/Month

70. Slab Rates : SR Grid Rs/MW/Month

71. COMPARISION OF POC CHARGES AND PRE-POC TRANSMISSION CHARGES

75. PoC Losses Paid in Kind Entities to be placed in the slabs based on the moderated PoC Losses –Moderation to be done based on the average losses of past 52 weeks –On Regional Basis. Slab Rates for PoC Losses –Average Loss + 0.3% –Average Loss –Average Loss – 0.3% Average Loss to be declared by RLDCs on weekly basis.

76. Thank You!