1. o POWER TRADING o OPEN ACCESS o CAPTIVE GENERATION BHANU BHUSHAN Director (Operations ) Power Grid Corporation of India Ltd

2. How do you buy or sell a commodity which can not be seen, counted in numbers, or measured in kg, litres or metres, which can not be put in a container with a forwarding address, on a particular truck taking a particular route, but flows as per laws of physics, which can not be stored, and whose availability and cost keep changing widely,

3. which intermingles with all other supplies in an inevitable pool, and can not have an owner’s name tag ? There is another peculiarity: the buyer has no control over what the seller supplies, and the seller has no control over what the buyer draws from the pool, and the two may not match ! It is crucial to have mechanism for commercial handling of mismatches

5. 1) Power trading has to be notional: buyer to pay the agreed amount to the supplier for scheduled quantum of power. 2) Payment for variations from the schedule through a common mechanism, e.g. U.I. TO AVOID DISPUTES

6. TRADER GRID 10MW 8MW A A B B @ Rs. 2.00/ u @ Rs. 2.20/ u AGREEMENTS ACTUAL FLOW 12 MW

7. TRADER UI POOL A/C UI for 2 MW A B Rs. 2.00/ u for 10 MW Rs. 2.20/ u for 10 MW PAYMENTS UI for 2 MW

8. DEFINITION OF “OPEN ACCESS” IN THE ELECTRICITY ACT, 2003 “The non-discriminatory provision for the use of transmission lines or distribution system or associated facilities with such lines or system by any licensee or consumer or a person engaged in generation in accordance with the regulations specified by the Appropriate Commission”

9. A MORE GENERAL DEFINITION OF “OPEN ACCESS” “Enabling of non-discriminatory sale/ purchase of electric power/energy between two parties utilizing the system of an in- between (third party), and not blocking it on unreasonable grounds”

10. REAL ISSUES Freedom to buy/ sell, and access to market Adequacy of intervening transmission Transmission/ wheeling charges Treatment of transmission losses Energy accounting, scheduling, metering and UI settlement

11. An Example: Suppose TATA POWER want to sell 100 MW to Discom- A in Andhra Pradesh Steps: 1)TPC and Discom-A to agree on terms and conditions of sale 2)TPC to get the consent of MSEB and “no- objection” of MSERC 3)Discom-A to get the consent of APTransco and “no- objection” of APSERC

12. 4)MSLDC and APSLDC to ascertain transmission adequacy, and agree to arrange necessary metering, scheduling, energy accounting and UI settlement 5)WRLDC and SRLDC to ascertain transmission adequacy in their regional transmission systems 6)All concerned to have a common understanding about treatment / sharing of transmission losses, and levy of transmission/ wheeling charges for the use of intra-State and inter-State systems

14. SCHEDULING, METERING, UI SETTLEMENT AGREEMENT & PAYMENT FOR SCHEDULED QUANTAM WRLDCSRLDC APTRANSCO/ APLDC TATA POWERDISCOM-A MSEB/ MSLDC

15. TRANSMISSION IS THE FACILITATOR OF oOPEN ACCESS oTRADING/ MARKET oCAPTIVE GENERATION, AND NOT A STUMBLING BLOCK

16. THANK YOU

18. The Act provides that: 1.Any licensee or generator can seek open access; and 2.Any consumer can also seek as and when provided by the State Commission on payment of surcharge as may be specified by the state commission. The Act specifies who can seek open access. The Act puts no restriction on the type of transactions that can be facilitated. Who can seek access

19. The consultation paper states to facilitate only certain types of transactions. It excludes Trader- Trader transactions and also transactions involving any generator seeking access for selling at consumer door step. Once the Act has provided that who can seek open access, why to limit the types of transactions that are to be facilitated. Whether surcharge will be applicable in case of transactions involving any generator seeking access for selling at consumer door step. Types of transactions to be facilitated

20. Transmission pricing must include the capital costs and O&M costs incurred in providing the services. The concept based on congestion rent should not be applied because it gives incentive to transmission provider for having constraints in his system. Tranmission Pricing

21. The existing regional postage stamp type transmission tariff was developed when TEC process of CEA was taking care of optimization of generation & transmission expansion plans. With TEC process gone, there is urgent need to revise transmission pricing so that it has 1.Distance sensitivity 2.Locational sensitivity 3.Remove pancaking. In the existing regional system, a beneficiary utility which may not be actually using or getting benefited from part of regional system, still has to share the total regional transmission charges. The above correction are needed not only for open access tariff, but also for basic transmission service charges. Need for distance sensitivity in transmission pricing

22. 1.Distance sensitivity 2.Locational sensitivity 3.Directional sensitivity Based on pattern of flows as conceived at the time of expansion planning because this would correctly reflect the costs towards sunk capital. The above correction are needed not only for open access tariff, but also for basic transmission service charges. Need for distance sensitivity in transmission pricing

23. Congestion should be resolved based on pre-fixed priorities of transactions. Committed Customers: Level-I Open Access – Long-term: Level-II Open Access – Short-term: Level-III Day-long & Part-day: Level-IV  Lower priority level transactions to be affected only after full curtailment of all higher level transaction constraining the corridor.  Proportionate curtailment in same priority level. Resolving Congestion

24. Margins in existing transmission are limited. Open access charges should be seen not only in comparison with current level of TSC but also with reference to incremental investment in transmission system that is needed for new generation capacities. Open access wheeling charges should encourage economic transactions, but should not discourage TSC based commitments. Else no one would commit for TSC and the process of building the National Grid would suffer. A matter of concern

25. A total solution for – Open Access Charges as well as – Transmission Service Charges

26. From  To  Notional Transmission Distance in 100 kms. StatesABCDEFGHIJKLMN JK,Pb,HPA 4555 557710 12 144 Ch,Hy,DeB 6465 557710 12 144 RajC 7 645 557710 12 144 UP,UtchlD 7 664 557710 12 144 Bihr,JharE1210 7 456 911 9 144 WB,DVC, Sikkim F1412 9 646 911 9 144 Orrisa G1412 9 654 79979 4 MP,Chatt H1210 7556 477 78 4 GujratI11997555 546 79 4 Mah,GoaJ11997555 564 7684 AndhraK11997555576 467 4 KarnatakL11997555576 546 4 TN,KerlaM11997555576 564 4 NER N 1614 12979 14 121416 *

27. AssamNagaland, Ar.Pd. Tripura, Mizoram, Manipur, Meghalaya Assam 456 Nagaland, Ar.Pd. 646 Tripura, Mizoram, Manipur, Meghalaya 654NER

28.  Notional distances have relation to the incremental transmission costs.  When power transfer would take place through displacement, notational distances have been adjusted towards lower side. This way directional sensitivity has been incorporated.  Frequent change in table not required. Revision once in three to four years may be reasonable.  Same table can be used for incremental losses. In most cases it would give reasonably close values. Notional distances

29. MTSC = Monthly Transmission Service Charges pooled for the CTU on all-India basis MLDC = Monthly Load Dispatch Charges also pooled on all-India basis i.e. all RLDCs and also NLDC when it comes G_MW_N100km = Gross-MW-Notional distance of TSC based generation capacity = All India total of MW-km of all allocated Central Sector and Multi-beneficiary generation capacity for which CTU system is primarily built. =  Capacity * Notional Transmission distance as per tableMethodology

30. HBRTSC = Hourly Base Rate of Transmission Service Charges = MTSC 30 * 24 * G_MW_N100km HBRLDC = Hourly Base Rate of Load Dispatch Charges = MLDC 30 * 24 * G_MW_N100km Methodology continued...

31. Basic Transmission Charges to CTU = MW * (N100km – 1 ) * HBRTSC * Compensatory Transmission Charges to CTU = MW * HBRTSC * Supplementary Transmission Charges to STU = MW * HBRTSC * Basic Load Dispatch Charges to RLDC = MW * (N100km – 1 ) * HBRLDC * Compensatory LD Charges to RLDC = MW * HBRLDC * Supplementary LD Charges to SLDC = MW * HBRLDC * If generation wheeling through State system is involved then Wheeling Charges to STU = Av. MW wheeled *HBRTSC * Charges for dedicated system would be separate where is a factor which would vary for different types of open access customers Open Access – Basic Charges

32. To CTU óMTSC minus amount billed by CTU on Open Access Customers as Basic Transmission Charges óIn proportion to MW_N100km of allocated capacity To RLDC óMTSC minus amount billed by RLDC on Open Access Customers as Basic Transmission Charges óIn proportion to MW_N100km of allocated capacity Charges payable by Charges payable by Long-term Commitment Customers

33. Customer TypeDuration of agreement Capacity Access duration PriorityValue of 1. Long-term Nodal: CTU 12 months or more than 12 months in multiple of months. Fixed for entire period of agreement. Level-II1.2 2. Short-term Nodal: CTU One month or more than one month in multiple of months. Fixed for period of one month but may vary from month to month. Level-III2.5 3. Day-long Nodal:RLDC One day or more than one day in multiple of days. Fixed for period of one day but may vary from day to day. Level-IV3.5 4. Part-day Nodal RLDC Four hours or more than four hours in multiple of hours. Fixed for blocks of four hours or more. May vary from block to block but no block to be less than four hours. Level-IV5.0 Types of Open Access Customers and their Types of Open Access Customers and their

34. Figures are indicative only Customer Type option-1 option-2 reduced Long-term1.21.00.6 Short-term2.51.50.8 Day-long3.52.01.0 Part-day5.02.51.2 Reducing when margins are available and extent of Open Access business increases

35. P/kwh for different values of and OA % P/kwh for different values of and OA %

36. Indicative Transmission Charges under the various options Indicative Transmission Charges under the various options

37.  RLDC should be empowered to curtail any transaction irrespective of priority.  Restoration of priority level curtailment as soon as emergency is over.  Regulatory check on RLDC to ensure that off-priority curtailments are not unduly prolonged on pretext of continued emergency. Full charges irrespective of curtailments during Grid Emergencies. Reduced charges when curtailments are due to congestion management other than Grid Emergencies. Grid Emergency Grid Emergency

38. Transmission tariff related to power flow is desired. The rates should be fixed based on pattern of flows as conceived at the time of expansion planning because this would correctly reflect the costs towards sunk capital. The rates should be applied on scheduled transactions. The rates/tariff should not be based on actual power flows because: 1.The transacting parties have no control over it. 2.The cost implication of transaction decision will not be known in advance. 3.The system will be prone to disputes. Power flow based transmission pricing

39. Congestion should be resolved based on pre-fixed priorities of transactions. Variable or bid based pricing mechanism may not be a practical method for resolving transaction conflicts. We disagree with concept of pricing mechanism based on degree of congestion in the transmission system as it gives commercial signals to transmission providers for planning a constrained system. Resolving Congestion

40. Imaginary connectivity not reflecting actual power flow pattern. Unfavorable to transactions that take place through displacement. Path connectivity based on segment wise transmission capacity allocation to transactions is quite complex. Little practical advantage of this complexity because actual power flows may be quite different. Not towards true open access. The Contract Path Method (Alternative-I of consultation paper)

41. Requires a demarcation which is artificial and so far non- existent. 100km x 100km is not in line with our field configuration of network. The regional networks, mostly 400kV, the line segments are generally of 300 – 400 km length. Transaction metering is based on State boundaries and there is no system for the 100km x 100km zones. Multiple choice of path connectivity in diagonal transactions. Blind to locational merits of transactions. Unfavorable to transactions taking place through displacement. Incremental Postage Stamp Method (Alternative-II of consultation paper)

42. Focus of development has changed from Regional to National. In transmission, the objective is to develop National Power Grid. To facilitate development of National Grid, tariff design in transmission should also change from Regional pool to National pool. Suggested approach National approach

43. Introduce distance sensitivity through zonal concept. Use existing State boundaries in zonal demarcation. Zone to zone notional transmission distances in multiple of 100km. Notional transmission distances to have directional sensitivity. Suggested approach Zonal concept based on State boundaries

44.  Notional distance within the same zone fixed at 400 km.  Maximum distance limited to 1600 km so as to limit maximum transmission charges. This would help in commercial viability of NER hydro projects.  Notional distances have relation to the incremental transmission costs.  When power transfer would take place through displacement, notational distances have been adjusted towards lower side. This way directional sensitivity has been incorporated.  Figures in the table are indicative. These may be fine tuned based on incremental load flow studies.  Could be revised once in five years or so. Notional distances

45.  RLDC should be empowered to curtail any transaction irrespective of priority.  Restoration of priority level curtailment as soon as emergency is over.  Regulatory check on RLDC to ensure that off-priority curtailments are not unduly prolonged on pretext of continued emergency. Grid Emergency Grid Emergency

46. Charges based on MW_N100km as per access agreed. Full charges irrespective of curtailments during Grid Emergencies. Reduced charges when curtailments are due to congestion management other than Grid Emergencies. Availability based Open Access Charges

47. Scheme based on line-wise transmission capacity allocation requiring declaration of TTC and ATC etc. as suggested in consultation paper may not be practical. Simpler methods should be evolved and adopted. Need for simple scheme

48. RLDC can be nodal agency for Day-long and Part-day Open Access customers. However, for Long-term and Short-term customers seeking access for yearly or monthly basis, CTU should be nodal agency. Nodal Agency

49. We are not convinced of practicability of the scheme based on dynamic declaration of prices by transmission service provider and customers replacing each others through higher price or duration bids in which there is also scope of hoarding of transmission capacities. These complexities seems to be unnecessary and have potential for completely jeopardizing the purpose of open access. Para 5.14, 5.15, 5.16 & 5.17 of consultation paper

50. Assessment of incremental energy losses is an important step in optimum generation dispatch. Open access customers cause incremental transactions and therefore should bear incremental losses. Due to current square dependence of losses, incremental losses in percent are double of average losses. Loss apportionment should be based on product of (a) MW (b) Notional distance and (c) incremental loss factor ; In consultation paper is it proposed to be based only on MW, to which we differ. Apportionment of transmission losses

51. Assuming burden of open access customers to be 10% of committed customers, the incremental loss percentages for committed customers, first entrant open access customer and the last entrant customers would be (approximatly) in ratio of 1:2:2.2 Accordingly, following Incremental Loss Factors are suggested: Committed Customer1.0 Open Access – Long-term2.0 Open Access – Short-term2.1 Day-long and Part-day2.2 Incremental loss factor

52. Charges based on MW_N100km as per access agreed. Full charges irrespective of curtailments during Grid Emergencies. Reduced charges when curtailments are due to congestion management other than Grid Emergencies. Availability based Open Access Charges

53. CERC Paper on Open Access Presentation by the MPERC Bhopal At New Delhi 25 September 2003

54. –The Open Access Paper Pricing design objectives Existing Scenario Open access transmission tariff Methodology and procedure Energy accounting –Other Discussion Points Objective(s) of the Paper: 1.To generate a debate on the important issues a.Identification of key issues b.Understanding the implications c.Understanding stakeholder perspectives 2.Frame regulations

55. Transmission Pricing Design Definition of Objectives (3.1) –Objectives defined in the Paper Efficiency of operations and trading Efficient use of resources Signal for investment Signal for location of generation/load Compensate owner of the wires Simple and practical –Comments on Objectives Agree Ensure safety of grid (Needed for all users) Provide regulatory certainty (For overall development of the power market and removal of uncertainty to attract investors) Provide level playing field (To new transmission utilities and transmission users)

56. Existing Scenario Role of the CTU (2.1), CTU Tariffs (2.2) –Proposals Current lines based on BPTA’s Open access only for spare capacity “Existing transmission agreements will have to be honored…” for current and future lines built on BPTA’s –Comments Agree that open access only for spare capacity Agree that existing arrangements should be honored. –Who is the successor entity to SEB – State Trader / STU / DICSOM’s? Division ratio? What when a BPTA expires, say at the end of 5 years? Consider as Open Access. –Proposals TSC apportioned based on CGS allocation Spare capacity paid for by beneficiaries Open access will reimburse them partially –Comments Need to decide who pays for unapproved expansion of system. –Transmission pays: Transmission should not be allowed to take uncovered risks –Beneficiary pays: In effect he is subsidizing later users. Preferable. Relevant Commission must approve the excess investment in capacity at a certain margin above what is immediately required

57. Open Access Transmission Tariff Alternatives (4.1) –Contract path May be adopted for those transactions where clear line of power flow can be determined. Exhibit. Contract Path B Seller Exportin g Region A C Buyer Importin g Region IPS –Incremental postage stamp method Adopt for places where clear lines cannot be determined. Minimum charge should be fixed for use of transmission facility for very small distances Grid support charges also to be levied

58. Open Access Transmission Tariff Pricing Philosophy (4.2) –Proposals Ceiling on an all-India basis: Purpose is to provide a signal for location of lines and transmission system users. –Observations Purpose of allowing market forces to operate and create correct economic signals for siting of generation, loads and new lines may not be adequately met 1.98142.223329 2 236.7 4 Total 1.1280.51475219.13ER 3.14225.35684777.15SR 1.3294.68916843.40WR 2.16154.991252 5 97.06NR Increme ntal Postage Stamp Charge Unit TSC (Rs / km / MW / Month) Ckt- km Total TSC (Rs. Cror es) Regio n –Suggestions Different postage stamps for different regions Concern: Determination of IPS For cross- regional squares

59. Open Access Transmission Tariff Pricing Philosophy (4.2) –Proposals Levy on capacity reservation –Observations Paper proposes that open access ceiling be determined assuming average loading of 500 MW as per Annexure I. This benefits open access users at the cost of “original beneficiaries” –Comments actual loading and not total line capacityactual loading Disincentive to BPTA! Ceiling should be higher than derived as above Apply percentage markup Alternative method may be used for determination of OA-TSC ceiling based on actual loading and not total line capacity actual loading

60. Open Access Transmission Tariff Sharing of TSC (4.6), LD Charges (4.7) Sharing of TSC among beneficiaries (4.6) –Proposals TSC to be apportioned to regions based on CGS generation capacity –Comments Inter-regional TSC should be apportioned to regions based on BPTA share from CGS plus share of IPP’s –Sharing of LDC charges (4.7) –Proposal Total LDC charges to be calculated from the weekly LDC charges divided by installed capacity of CGS = 200 rupees per week per MW = 0.12 P/U Revenue to go to reduce costs to original beneficiaries / successors –Comments Treat all as equal Bill original beneficiaries also on a weekly basis Weekly LDC charges should be divided by total generation capacity scheduled to be handled in the week = CGS + IPP + Traded power

61. Methodology and Procedure Information Systems (5.1) –Proposals Hourly updating of information Dissemination over the Internet or other dedicated communication channel –Comments Incorporate mechanism for advance declaration of available capacity. This will allow users to plan for open access and a move towards the development of a spot and futures market. Frequency of advance declarations: –Twelve months ahead spare availability information –Week ahead in hourly blocks –Day ahead in 30-minute blocks –Information updating frequency: 30 minutes for actual values in real time. Dissemination of information: –Centrally at NLDC / RLDC’s in tandem –Dedicated communication channels connecting central database, traders, distribution licensees, transmission utilities. –Information may also be posted on the Internet

62. Methodology and Procedure Nodal Agency (5.2, 5.4) –Proposed: Processes all applications on FCFS In order of priority of service –Suggestions: Options may be considered FCFS. Bidding. Beauty Contest. Who judges in case of beauty contest? Mix of the above. –What would be an appropriate mix? –A pecking order should be defined

63. Methodology and Procedure Special Energy Meters (5.8) and Creditworthiness (5.11) Special Energy Meters (5.8) –Proposals: As and when required, open access customer will have to install required special energy meters –Suggestions: May be an expensive proposition for small customers. Credit worthiness (5.11) –Proposals: Prospective open access consumer must establish credit-worthiness –Suggestions: Establish creditworthiness to whom? CERC / RLDC What shall be the measurement basis for creditworthiness? Creditworthiness of SEB’s very low Alternatives to measurement of credit-worthiness: Security deposit, margin money, LC, bank guarantee, advance

64. Methodology and Procedure Types of Service (5.13), Priority of Allotment (5.15) and Penalty for Hoarding (5.16) Types of Service (5.13) Need to clearly define Firm and Non-Firm. Also, consider number of hours per day. What is the treatment for Non-Firm agreement longer than 1 Month? Need to outline difference of charges for Firm and Non-firm power transmission Long Term >= 1 Y Short Term: 1 W – 1 M 1 W – 1 M 1 D – 1 W 1 H – 1 D { { Firm Service Non-Firm Service Priority of Allotment (5.15) –Proposals: Hierarchy defined. –Suggestions: Agree Penalty for Hoarding (5.16) –Proposal: CERC to act on complaint. –Suggestions: Suggest periodic review

65. Methodology and Procedure Curtailment Due to Constraints –Proposal Non-Firm users before Firm users Short-Term users before Long-Term users 1.What if there are two consumers of the same level in pecking order, and one is paying more or offers to pay more? What considerations for payment history? 2.Why should open access original beneficiaries be the last to be disconnected? Why should they not be treated at par as far as their open access portion is concerned? 1 2 3 4 5 6 >= 1 Y 1 M – 1 Y 1 W – 1 M 1 D – 1 W 1 H – 1 D { { Firm Service Non-Firm Service Money:The Third Dimension –Suggestion Pecking order outlined as below. What is the treatment of Non-Firm agreement longer than 1 Month? Define an order considering 1. Firm / Non-firm, 2. Duration and 3. Price Paid

66. Energy Accounting Active Energy (6.1), Reactive Energy (6.2) and Energy Loss (6.3) Active Energy (6.1) –Proposals Direct CTU users to comply with ABT Embedded customers to comply with Intra- State ABT For embedded customer, STU / SEB to be billed –Suggestions Fix a minimum threshold for applying ABT (1. Avoids complexity, and 2. saves customer the cost of Special Energy Meters) Dependent on whether and when State implements ABT STU should not be billed because it is a pure wires company and has nothing to do with users of its wires adhering to schedules. Consider billing the SLDC (1. Incentive for SLDC to perform, 2. May be difficult since SLDC is non-profit). SLDC may pass on to embedded customers or deduct from margin money / advance Reactive Energy (6.2) –Proposals Apply to direct CTU customers Not appropriate to apply to embedded customers –Suggestions SERC’s shall decide whether to apply to since it impacts the State system May have very high cost implications for smaller open access consumers Energy Loss (6.3) –Proposals Measure past weeks losses and apply to ensuing week. –Suggestions Agree. Simple, easy to implement and accurate Consideration for incremental postage stamp application of losses. It is complex and not necessarily accurate.

67. Additional Discussion Points –Scheduling of direct contracts Will direct contracts be incorporated into the ABT mechanism? If yes, above what threshold level of MW contract? If not, how will any variability on account of them be reconciled with ABT billing? –ABT in case of bilateral agreement / Dishonoring of bilateral agreement A and B enter into agreement for 50 MW How will ABT apply to A and B? Case 1: A feeds the power, B does not draw fully Case 2: A does not feed power, B continues to draw Clear need to outline mechanism for settlement –Wheeling charges –Energy Accounting –Assessing transmission capacity (Section 5.2) Uniform mechanism should be adopted by all constituents CERC may like to outline assessment mechanism –Surcharge (4.9): How will CERC determine surcharge? Loss incurred by State utilities – SERC should decide.

68. Open Access Transmission Tariff Pricing Philosophy – Regional Ceilings TSC in ER = 10 TSC in SR = 41 Total TSC = 51 Signal to generators: Move towards SR to reduce number of expensive SR zones Effect: Generation moves towards load Signal to transmission utilities: Invest in SR since there is more income to be made. Effect: This will reduce the SR postage stamp. SRER Signal to load: Invest in ER since TSC costs are lower. Effect: Load moves towards generation TSC in ER = 18 TSC in SR = 26 Total TSC = 43 Generation Load

69. Open Access Transmission Tariff Pricing Philosophy (4.2) – 1