1. 1 TTC/ATC Computations and Ancillary Services in the Indian context

2. 2 Outline Part A: TTC/ATC computations Transfer capability-Definitions Relevance of transfer capability in Indian electricity market Difference between Transfer capability and Transmission Capacity Assessment of TTC/TRM/ATC Method for improving Transfer capability Concerns Part B:Ancillary services in the Indian context

3. 3 Part A Total Transfer Capability (TTC)/ Available Transfer Capability (ATC) computations

4. 4 Transfer Capability - Definitions

5. 5 North American Electric Reliability Corporation’s (NERC) definition of TTC The amount of electric power that can be moved or transferred reliably from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths) between those areas under specified system conditions………. 16-Mar-2007(FERC) As per 1995 document of NERC, following conditions need to be satisfied: –all facility loadings in pre-contingency are within normal ratings and all voltages are within normal limits –systems stable and capable of absorbing the dynamic power swings –before any post-contingency operator-initiated system adjustments are implemented, all transmission facility loadings are within emergency ratings and all voltages are within emergency limits”

6. 6 European Network of Transmission System Operators’ definition of Total Transfer Capability (TTC) “TTC is that maximum exchange programme between two areas compatible with operational security standards’ applicable at each system if future network conditions, generation and load patterns were perfectly known in advance.” “TTC value may vary (i.e. increase or decrease) when approaching the time of programme execution as a result of a more accurate knowledge of generating unit schedules, load pattern, network topology and tie-line availability”

7. 7 Total Transfer Capability as defined in the IEGC and Congestion charge Regulations “Total Transfer Capability (TTC)” means the amount of electric power that can be transferred reliably over the inter-control area transmission system under a given set of operating conditions considering the effect of occurrence of the worst credible contingency. “Credible contingency” means the likely-to-happen contingency, which would affect the Total Transfer Capability of the inter-control area transmission system –Outage of single transmission element (N-1) in the transmission corridor or connected system whose TTC is being determined –Outage of the largest unit in the importing control area

8. 8 Available Transfer Capability as defined in the IEGC and Congestion charge regulations “Available Transfer Capability (ATC)” means the transfer capability of the inter-control area transmission system available for scheduling commercial transactions (through long term access, medium term open access and short term open access) in a specific direction, taking into account the network security. Mathematically ATC is the Total Transfer Capability less Transmission Reliability Margin.

9. 9 Non Simultaneous & Simultaneous transfer Capability Non-simultaneous Transfer Capability Amount of electric power that can be reliably transferred between two areas of the interconnected electric system when other concurrent normal base power transfers are held constant Determined by simulating transfers from one area to another independently and non-concurrently with other area transfers. Simultaneous Transfer Capability Is the amount of electric power that can be reliably transferred between two or more areas of the interconnected electric system as a function of one or more other power transfers concurrently in effect.” Reflects simultaneous or multiple transfers with interdependency of transfers among the other areas is taken into account. No simple relationship exists between non-simultaneous and simultaneous transfer capabilities The simultaneous transfer capability MAY be lower than the sum of the individual non-simultaneous transfer capabilities. Simultaneous TTC declared by NR, SR, NER Simutanous TTC can be declared for 2 regions combined also( e.g ER/NER)

10. 10 Simultaneous TTC Area AArea B Area C 2000 MW4000 MW 5000 MW

11. 11 TTC affected by transactions

12. 12 Simultaenous TTC limits to two regions LinkTimeTTCScheduling Limit ER-NRPK25002200 ER-NROFF-PK25002200 ER-NERPK400350 ER-NEROFF-PK400350 January’11 TTC figures N-1 contingency of 400KV FSTPP-Malda FSTPP-KHSTPP D/C limitation during outage of 400Kv Malda-Purnea D/C High voltages along Northern corridor As 400KV FSTPP-Malda serves both NR & ER in case of increase in TTC of ER- NER ER-NR TTC has to be decreased Thus we could declare a simultaneous TTC of ER-NR & ER-NER combined

13. 13 ER-NR February,2011 limits NER TTC INCREASED DUE TO INCREASED GOI ALLOCATION & REQUIREMENT OF NER(ASSAM) NR TTC CORRESPONDINGLY DECREASED INITIALREVISED LINKTIMETTCSCHEDUL ING LIMIT TTCSCHEDUL ING LIMIT ER-NRPK2800250027002400 ER-NROFF-PK28002500 2200 ER-NERPK470420550450 ER-NEROFF-PK470420550450 Simultaneous TTC limits to two regions

14. 14 June, 2011 limits ER TTC REDUCED DUE TO LOW VOLTAGE IN CHENNAI AREA & HIGH LOADING ON 400 KV VIJAYAWADA – NELLORE I & II. INITIAL (Sep-10)REVISED (Jun-11) LINKTIMETTCSCHEDUL ING LIMIT TTCSCHEDUL ING LIMIT ER-SRPK265026001900 ER-SROFF-PK295029002000 WR-SRPK & OFF- PK 1000 Simultaneous TTC limits to two regions July, 2011 limits WR TTC REDUCED TO 800 MW DUE TO COMMISSIONING OF SIMHADRI U # 3.

15. 15 Relevance of Transfer Capability in Indian Electricity Market

16. 16 Open Access in Inter-state Transmission Regulations, 2008 3( 2) The short-term open access allowed after long / medium term by virtue of- –(a) inherent design margins; –(b) margins available due to variation in power flows; and –(c) Margins available due to in-built spare transmission capacity created to cater to future load growth or generation addition.]

17. 17 LT/MT/ Connectivity procedures-2010 ATC checking  MTOA approvals:: CTU(nodal agency) shall notify TTC on 31st day of March of each year: for 4 (four) years Revision by CTU due to change in anticipated network topology or change of anticipated generation or load at any of the nodes Available Transfer Capability (ATC) for MTOA will be worked out after allowing the already approved applications for Long-term access, Medium Term Open Access and Transmission reliability margin Grant of MTOA shall be subject to ATC ATC checking  LTA approvals CTU(nodal agency) shall carry out system studies in ISTS to examine the adequacy of the transmission system corresponding to the time frame of commencement of long-term access to effect the desired transaction of power on long-term basis, using the Available Transfer Capability (ATC). If transmission system augmentation is required LTA would be granted subject to such augmentation Revision by CTU due to change in anticipated network topology or change of anticipated generation or load at any of the nodes

18. 18 Tariff Policy Jan 2006 7.3 Other issues in transmission (2) All available information should be shared with the intending users by the CTU/STU and the load dispatch centres, particularly information on available transmission capacity and load flow studies.

19. 19 Open Access Theory & Practice Forum of Regulators report, Nov-08 “For successful implementation of OA, the assessment of available transfer capability (ATC) is very important. A pessimistic approach in assessing the ATC will lead to under utilisation of the transmission system. Similarly, over assessment of ATC will place the grid security in danger.”

20. 20 Declaration of Security Limits “In order to prevent the violation of security limits, System Operator SO must define the limits on commercially available transfer capacity between zones.” CIGRE_WG_5.04_TB_301 “System Operators try to avoid such unforeseen congestion by carefully assessing the commercially available capacities and reliability margins.” CIGRE_WG_5.04_TB_301

21. 21 Reliability Margin

22. 22 NERC definition of Reliability Margin (RM) Transmission Reliability Margin (TRM) –The amount of transmission transfer capability necessary to provide reasonable assurance that the interconnected transmission network will be secure. TRM accounts for the inherent uncertainty in system conditions and the need for operating flexibility to ensure reliable system operation as system conditions change. Capacity Benefit Margin (CBM) –The amount of firm transmission transfer capability preserved by the transmission provider for Load-Serving Entities (LSEs), whose loads are located on that Transmission Service Provider’s system, to enable access by the LSEs to generation from interconnected systems to meet generation reliability requirements. Preservation of CBM for an LSE allows that entity to reduce its installed generating capacity below that which may otherwise have been necessary without interconnections to meet its generation reliability requirements. The transmission transfer capability preserved as CBM is intended to be used by the LSE only in times of emergency generation deficiencies.

23. 23 Quote on Reliability Margin from NERC document “The beneficiary of this margin is the “larger community” with no single, identifiable group of users as the beneficiary.” “The benefits of reliability margin extend over a large geographical area.” “They are the result of uncertainties that cannot reasonably be mitigated unilaterally by a single Regional entity”

24. 24 ENTSOE definition of Reliability Margin “Transmission Reliability Margin TRM is a security margin that copes with uncertainties on the computed TTC values arising from –Unintended deviations of physical flows during operation due to physical functioning of load-frequency regulation –Emergency exchanges between TSOs to cope with unexpected unbalanced situations in real time –Inaccuracies in data collections and measurements”

25. 25 Reliability margin as defined in Congestion charge regulations “Transmission Reliability Margin (TRM)” means the amount of margin kept in the total transfer capability necessary to ensure that the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions;

26. 26 Distinguishing features of Indian grid Haulage of power over long distances Resource inadequacy leading to high uncertainty in adhering to maintenance schedules Pressure to meet demand even in the face of acute shortages and freedom to deviate from the drawal schedules. A statutorily permitted floating frequency band of 49.5 to 50.2 Hz Non-enforcement of mandated primary response, absence of secondary response by design and inadequate tertiary response. No explicit ancillary services market Inadequate safety net and defense mechanism

27. 27 Reliability Margins- Inference Grid Operators’ perspective –Reliability of the integrated system –Cushion for dynamic changes in real time –Operational flexibility Consumers’ perspective –Continuity of supply –Common transmission reserve to take care of contingencies –Available for use by all the transmission users in real time Legitimacy of RMs well documented in literature Reliability Margins are non-negotiable

28. 28 Difference between Transfer Capability and Transmission Capacity

29. 29 Area Despatch- Example of TTC 750 MW 630 MVA 515 MW Area A Area B 515 MW

30. 30 Transfer capability & Transmission capacity – what’s the difference? Transfer capacity –Refers to thermal ratings Transfer capability –Refers to the system’s capability of transfer-varies considerably with system conditions –Can not be arithmetically added for the individual line capacities and ratings –Always less than the aggregated transmission interface between two areas 750 MW 630 MVA 1015 MW TTC = 630 MVA

31. 31 TTC is directional 500 MW Area A Area B 500 MW1000 MW Gen 500 MW Transfer Capability from Area A to Area B = 1500MW Transfer Capability from Area B to Area A = 500MW

32. 32 Transmission Capacity Vis-à-vis Transfer Capability Transmission CapacityTransfer Capability 1Declared by designer/ manufacturerDeclared by the Grid Operator 2Is a physical property in isolationIs a collective behaviour of a system 3Depends on design onlyDepends on design, topology, system conditions, accuracy of assumptions 4DeterministicProbabilistic 5Constant under a set of conditionsAlways varying 6Time independentTime dependent 7Non-directional (Scalar)Directional (Vector) 8Determined directly by designEstimated indirectly using simulation models 9Independent of Parallel flowDependent on flow on the parallel path

33. 33 Transfer Capability is less than transmission capacity because Power flow is determined by location of injection, drawal and the impedance between them Transfer Capability is dependent on –Network topology –Location of generator and its dispatch –Pont of connection of the customer and the quantum of demand –Other transactions through the area –Parallel flow in the network Transmission Capacity is independent of all of the above When electric power is transferred between two areas the entire network responds to the transaction

34. 34 77% of electric power transfers from Area A to Area F will flow on the transmission path between Area A & Area C Assume that in the initial condition, the power flow from Area A to Area C is 160 MW on account of a generation dispatch and the location of customer demand on the modeled network. When a 500 MW transfer is scheduled from Area A to Area F, an additional 385 MW (77% of 500 MW) flows on the transmission path from Area A to Area C, resulting in a 545 MW power flow from Area A to Area C.

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36. 36

37. 37 Assessment of Transfer Capability

38. 38 Transfer Capability Calculations must Give a reasonable and dependable indication of transfer capabilities, Recognize time variant conditions, simultaneous transfers, and parallel flows Recognize the dependence on points of injection/extraction Reflect regional coordination to include the interconnected network. Conform to reliability criteria and guides. Accommodate reasonable uncertainties in system conditions and provide flexibility. Courtesy: Transmission Transfer Capability Task Force, "Available Transfer Capability Definitions and Determination", North American Electric Reliability Council, Princeton, New Jersey, June 1996 NERC

39. 39 Europe Increase generation in one area and lower it in the other. A part of cross border capacity is withdrawn from the market to account for –Random threats to the security of the grid, such as loss of a generating unit. This capacity is called as Transmission Reliability Margin (TRM) –TRM based on the size of the biggest unit in the synchronous area and the domestic generation peak of a control area. Net Transfer Capacity = TTC – TRM –published twice a year (winter and summer)

40. 40 United States The commercial capacity available for market players is calculated by deducting Transmission Reliability Margin (TRM) and Capacity Benefit Margin (CBM) from Total Transfer Capability –TRM is set aside to ensure secure operation of the interconnected transmission network to accommodate uncertainties in system operations while CBM is set aside to ensure access to generation from interconnected systems to meet generation reliability requirements.

41. 41 Operating Limits Thermal Limit Maximum electrical current that a transmission line or electrical facility can conduct over specified time periods before it sustains permanent damage by overheating or before it violates public safety requirements. Source CBIP Technical Report Voltage limit To be maintained as per IEGC Minimum voltage limits can establish the maximum amount of electric power that can be transferred without causing damage to the electric system or customer facilities Widespread collapse of system voltage can result in a black out of portions or the entire interconnected network Critical voltage for these nodes may also be different. Thus the proximity of each node to the voltage collapse point may be different(VCPI Index) 0 < VCPI < 1 0  stability 1  instability Voltage collapse  credible event

42. 42

43. 43 Operating Limits Stability Limits property of a power system that enables it to remain in a state of operating equilibrium under normal operating conditions and to regain an acceptable state of equilibrium after being subjected to a disturbance(small or large) All generators connected to ac interconnected transmission system operate in synchronism. Immediately following a system disturbance, generators begin to oscillate relative to each other,causing fluctuations in system frequency, line loadings, and system voltages. oscillations must diminish as the electric systems attain a new, stable operating point. If stable point is not quickly established, the generators will likely lose synchronism & result of generator instability may damage equipment and lead to widespread loadsheddings

44. 44 Total Transfer Capability: TTC Voltage Limit Thermal Limit Stability Limit Total Transfer Capability Total Transfer Capability is the minimum of the Thermal Limit, Voltage Limit and the Stability Limit Time Power Flow

45. 45 Intra-day STOA Day-ahead STOA Collective (PX) STOA First Come First Served STOA Advance Short Term Open Access (STOA) Medium Term Open Access (MTOA) Long Term Access (LTA) Reliability Margin (RM) Available Transfer Capability is Total Transfer Capability less Reliability Margin TTCATC RM

46. 46 Input Data and Source S No.Input DataSuggested Source 1Planning CriteriaManual on Transmission Planning Criteria issued by CEA 2Network TopologyExisting network with full elements available Planned outages during the entire assessment period New transmission elements expected / CTU & STU data 3Transmission line limitsMinimum of thermal limit, stability limit and voltage limit 4Thermal unit availabilityLoad Generation Balance report, Maintenance schedule Anticipated new generating units 5Thermal despatchEx bus after deducting the normative auxiliary consumption Output could be further discounted by the performance index of generating units of a particular size as compiled by CEA 6Gas based thermal despatch Past trend 7Hydro despatchPeak and off peak actual hydro generation on median consumption day of same month last year The current inflow pattern to be duly accounted 8LoadForecast by SLDCs/LGBR of RPCs/past trend/Anticipated 9Credible contingenciesPlanning criteria + Operator experience

47. 47 Model to be considered for simulation studies Assumption of standard data from CEA manual on Transmission planning criteria Separate base cases for calculating the export and import capability corresponding to both peak and off- peak load and generation with the likely scenario Wind generation also needs to be modelled  forecasts Reactive capability of units  Actual generator capability curve / CEA manual in Transmission planning Nodal MW demand  forecast by SLDCs/LGBR of RPCs/past trend Nodal MVAR demand  SLDC forecast OR CEA Planning criteria : Normal operating limits for transmission line: CEA planning criteria (detailed calculation methodology  ) Emergency limit for transmission line  110% of normal operating limit Continuous Operating limit for ICTs  generally 90% of MCR Reasonable assumptions in case data NA

48. 48 Data preparation for LF studies Where actual system is not available data from CEA Manual on transmission planning criteria can be used w.r.t parameters as: –Load Power factor 0.85 lag – peak 0.90 lag – Off-peak OR 0.75 lag-peak 0.85 lag – off-peak [Agricultural] –Reactive limits Qmax = 0.5* Active generation Qmin = -0.5 *Qmax –transformer/ reactance – 14-15% –GT – 12.5% Where actual system data is not available: –Standard R, X, B parameters(p.u/km/ckt) at 100MVA base may be used –Other typical system data may be used

49. 49 Ampacity Conductor Type Ampacity More than 10 years of age 65 degree conductor75 degree conductor 40 o ambient10 o ambient40 o ambient10 o ambient ACSR Bersimis69314769451601 ACSR Moose57512407991344 ACSR Zebra52710717181161 For bundled conductors ACSR Twin Moose1150247915982687 ACSR Quad Moose2300495831965374 ACSR Quad Bersimis2773590537796403 ACSR Triple Snowbird1725371923974031

50. 50 Thermal limit derived from ampacity Conductor Type Thermal limit in MW at 0.975 pu voltage and unity p.f. More than 10 years of age 65 degree conductor75 degree conductor 40 o ambient10 o ambient 40 o ambient10 o ambient 400 kV ACSR Twin Moose777167510791815 400 kV ACSR Quad Moose1554334921593630 400 kV ACSR Quad Bersimis1873398925534325 400 kV ACSR Triple Snowbird1165251216192723 220 kV ACSR Zebra196398267431

51. 51 Permissible Line Loading Limits From Sec 4.1 of Transmission Planning Criteria SIL at certain voltage levels modified to account for  Shunt compensation k1 = sqrt (1- degree of shunt compensation)  Series compensation k2 = 1 / [sqrt (1-degree of series compensation)  Variation in line loadability with line length(St.Clair’s curve) K3  Permissible line loading = SIL X k1 x k2 x k3 From Sec 4.2 of Transmission Planning Criteria Thermal loading limits at conductor temperature of 75 o Ambient 40 o in summer and 10 o in winter

52. 52 St.Clair’s curve Line loading in terms of SIL of an uncompensated line as a function of Length assuming voltage regulation of 5% and 30 deg angular difference

53. 53 1Line length386in kilometer 2From end shunt reactor in MVAr at 400 kV72.5680 MVAr 420 kV 3To end shunt reactor in MVAr at 400 kV72.5680 MVAr 420 kV 4Surge Impedance Loading (SIL)515in MW 5Conductor type ACSR Twin Moose 75 o C design conductor temperature and age >10 years 6Line reactance (X)0.0002075Per unit / kilometer / circuit 7Line susceptance (B)0.0055Per unit / kilometer / circuit 8Base MVA100 9 Power transfer between adjacent buses at 5 % voltage regulation and 30 deg angular separation = P B 593(in MW) 10Total shunt compensation for the line in MVAr145Sl. No. (2) + (3) 11Line charging MVAr212 Line length X B x Base MVA = Sl. No. (1) x (7) x (8) 12Degree of shunt compensation = D sh 0.68Sl No. (10)/ (11) 13Degree of series compensation = D se 0.3535 % Fixed compensation 14Multiplying factor-1 (shunt compensation) = k 1 0.56Sqrt(1-D sh ) 15Multiplying factor-2 (series compensation) = k 2 1.241/ Sqrt (1-D se ) 16Multiplying factor-3 (St. Clair’s line loadability) = k 3 1.15P B / SIL 17Permissible line loading P L 414SIL x k 1 x k 2 x k 3 18Ampacity of the conductor in summer conditions1598at ambient temperature of 40 o C 19Thermal limit (MW) in summer = P th_summer 1079at 0.975 pu voltage and unity p.f. 20Operating limit (in MW) in summer414Min of P L and P th_summer Illustration of calculation of operating limits of transmission line 53

54. 54 TTC/ATC calculation methodology-As per congestion charge procedures Total Transfer Capability between two areas would be assessed by increasing the load in the importing area and increasing the generation in the exporting area or vice versa till the constraints are hit for a credible contingency Credible contingencies Outage of single transmission element (N-1) in the transmission corridor or connected system whose TTC is being determined as defined in IEGC Outage of a largest unit in the importing control area Station. TTC is limited by:: Violation of grid voltage operating range OR Violation of transmission element operating limit in the base case OR Violation of emergency limit in the contingency case

55. 55 Credible contingencies From Section 3.5 of IEGC –Outage of a 132 kV D/C line or –Outage of a 220 kV D/C line or –Outage of a 400 kV S/C line or –Outage of a single ICT or –Outage of one pole of HVDC bi pole or –Outage of 765 kV S/C line without necessitating load shedding or rescheduling of generation during steady state operation

56. 56 Process for assessment Base case construction (The biggest challenge) –Anticipated network representation –Anticipated load generation –Anticipated trades Simulations –Increase generation in exporting area with corresponding decrease in importing area till network constraint observed

57. 57 TTC calculation process Considerations for calculation of TRM – as per congestion procedures Two percent (2%) of the total anticipated peak demand met in MW of the control area/group of control area/region (to account for forecasting uncertainties) Size of largest generating unit in the control area/ group of control area/region Single largest anticipated in feed into the control area/ group of control area Data flow  TTC calculation SLDC  RLDC  Import/Export TTC of control areas NLDC  RLDC  Fixation of inter-regional export RLDC  NLDC  Preparation of converged base case NLDC  RLDC  Stitching of base cases from all regions & re-consideration for modification if any RLDC  NLDC  Final Base Case NLDC  Final TTCs uploaded to NLDC wesbite & linked from RLDC websites(upto 3 months advance) NLDC can revise the TTC/ATCs on requests by RLDCs/SLDCs/suo-motto The TTC/RM/LTA/approved STOA(till date) & path margin available are declared alongwith the rationale/path limiting the TTC

58. 58 Procedure for declaration of TTC, TRM, ATC and anticipated Constraints Role of SLDC Assess the TTC, TRM and ATC on its inter-State transmission corridor, considering its own control area Indicate details of anticipated transmission constraints in the intra State system Forward these figures along with the assumptions made, to the respective RLDC, for assessment of TTC at the regional level

59. 59 Role of RLDCs Consider the inputs provided by SLDCs Assess TTC, TRM and ATC for –intra regional corridors (group of control –areas) –individual control areas within the region (if required) –Inter-regional corridors at respective ends for a period of three months in advance. Forward the results along with the input data considered, to NLDC Also indicate the anticipated constraints in the intra-regional transmission system Procedure for declaration of TTC, TRM, ATC and anticipated Constraints

60. 60 Procedure for declaration of TTC, TRM, ATC and anticipated Constraints Role of NLDC Assess the TTC, TRM and ATC of inter and intra-regional links/ Corridors respectively for three months in advance based on –The inputs received from RLDCs –TTC/ TRM/ ATC notified/ considered by CTU for medium-term open access. Inform the TTC/ TRM/ ATC figures along with constraints observed in inter-regional/ intra-regional corridors to the RLDCs

61. 61 Procedure for declaration of TTC, TRM, ATC and anticipated Constraints Role of NLDC (contd) Revise the TTC, TRM and ATC due to change in system conditions (including commissioning of new transmission lines/ generation), vis-à-vis earlier anticipated system conditions Revise TTC, TRM and, ATC based on its own observations or based on inputs received from SLDCs/ RLDCs

62. 62 Transfer Capability assessment Anticipated Network topology + Capacity additions Anticipated Substation Load Anticipated Ex bus Thermal Generation Anticipated Ex bus Hydro generation LGBR Last Year Reports Weather Forecast Trans. Plan + approv. S/D Last Year pattern Operator experience Planning criteria Operating limits Credible contingencies Simulation Analysis Brainstorming Total Transfer Capability Reliability Margin less Available Transfer Capability equals Planning Criteria is strictly followed during simulations

63. 63 Sample TTC uploaded at NLDC website

64. 64

65. 65

66. 66 EASTERN REGION SOUTHERN REGION WESTERN REGION NORTHERN REGION NORTH- EASTERN REGION 2 8 4 16 4

67. 67 Possible scenarios for a control area with N interconnections Total No. of scenarios possible = 2 n ER  4 inter-regional interconnections  16 possible scenarios WR  3 inter-regional interconnections  8 possible scenarios Out of above only limited No. of scenarios applicable For ER only 3 to 4 out of 16 scenarios possible Different scenarios dependent upon seasonal characteristics due to the nature of skewed geo-spatial positioning of hydro/Thermal Generators in ER From the analysis below we see that simultaneous export/import capability calculation is not possible for ER

68. 68 Possible scenarios for Eastern Regional Grid Sl.NO.NRWRSRNERRemarks 1Exp Simultaenous Export capability. Probability extremely low 2Exp ImpProbability very low 3Exp ImpExpProbability very low 4Exp Imp Probability low. Only in high hydro season & high demand in WR/NR 5ExpImpExp Probable in winter load / low hydro conditions 6ExpImpExpImp lesser Probability 7ExpImp ExpProbability low 8ExpImp Probable in high hydro season

69. 69 Possible scenarios for Eastern Regional Grid Sl.NO.NRWRSRNERRemarks 9Imp Exp Very low probability-Temporarily possible only in case of demand crash/trippings in NR 10Imp Exp Imp Very low probability 11ImpExpImpExpVery low probability 12Imp ExpImp Very low probability 13Imp Exp low probability-in case of demand crash/trippings in NR 14Imp ExpImpvery low probability 15Imp ExpVery low probability 16Imp Simultaenous import cabaility Probability extremely low

70. 70 N-1 criteria “Element” in theory “Event” in practice In real time a Single event can lead to multiple outages

71. 71 (n-1)  Element or event ? Difference exists in n-1 criteria in planning and operating horizon –Tower collapse/lightning stroke on a D/C Tower. –Two main one transfer scheme-Failure of opening of 400 kV Line breaker In practice-Results in multiple loss in elements As per planning criteria- not more than two elements should be affected –Coal fired station Fault in 132kV system- may result in loss of power supply to CW system vis a vis tripping of multiple units

72. 72 Non availability/Outage/Non operation of Bus bar protection –Results in tripping of all lines from remote stations Weather disturbance or floods –Might result in loss of substation/multiple lines in the same corridor Breaker and a half scheme –Outage of combination of breakers may result in tripping of multiple line for a fault in one line (n-1)--Element or event ? … contd

73. 73 FLOWGATES NR: Central UP-Western UP UP-Haryana/Punjab WR: Chandrapur-Padghe Chandrapur-Parli Bina-Gwalior Soja-Zerda SR: Vijaywada-Nellore Hossur-Selam Cadappa-Kolar Neyvelli-Sriperumbudur ER: Farakka-Malda Malda-Purnea Talcher-Rourkela Farakka-Kahalgaon Kolaghat-Baripada-Rengali

74. 74 Suggestions for improving transfer capability-1 installation of shunt capacitors in pockets prone to high reactive drawal & low voltage strengthening of intra-state transmission and distribution system improving generation at load centre based generating stations by R&M and better O & M practices avoiding prolonged outage of generation/transmission elements reduction in outage time of transmission system particularly those owned by utilities where system availability norms are not available

75. 75 Suggestions for improving transfer capability-2 minimising outage of existing transmission system for facilitating construction of new lines expediting commissioning of transmission system-planned but delayed execution enhance transmission system reliability by strengthening of protection system strengthening the safety net:  UFLS,  UVLS,  SPS

76. 76 Part B Ancillary Services in the Indian context

77. 77 Outline Definition of ancillary services Categories of ancillary services Ancillary services in the Indian context

78. 78 Ancillary services……definitions Those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission Service Provider's transmission system in accordance with good utility practice. (From FERC order 888-A.) “Ancillary services are those functions performed to support the basic services of generation, transmission, energy supply and power delivery. Ancillary services are required for the reliable operation of the power system.”… Para 30, judgment in appeal no.202 dated 13th December 2006, The Appellate Tribunal for Electricity[4] “Ancillary services are those functions performed by the equipment and people that generate, control, transmit, and distribute electricity to support the basic services of generating capacity, energy supply, and power delivery.”….Electric Power Ancillary Service, Eric Hirst and Brendan Kirby[5]

79. 79 Ancillary services……definitions (2) “Ancillary Services” means in relation to power system (or grid) operation, the services necessary to support the power system (or grid) operation in maintaining power quality, reliability and security of the grid, eg. active power support for load following, reactive power support, black start, etc;…………………. Indian Electricity Grid Code 2010 Approach Paper on Ancillary Services submitted to CERC in June 2010 by National Load Despatch Centre (NLDC)

80. 80 Relevance of ancillary services Four pillars of market structure

81. 81 Categories of ancillary services Frequency Control Services Network control Services System Restart Services

82. 82 Levels of frequency control Primary frequency response Immediate response by  adjustment of active power of generating units & consumption of controllable loads to check the deviation in frequency –speed governor (having droop settings)-FGMO/RGMO –self-regulating effect of frequency-sensitive loads (e.g.induction motors)or the action of frequency-sensitive relays Secondary frequency response Centralized automatic control that adjusts the active power production of the generating units to restore the frequency and the interchanges with other systems to their target values following an imbalance by: –setpoint or reference point adjustment of generators, –starting and stopping of power plants Goal of secondary frequency control is to minimize the area control error (ACE) [ACE is the instantaneous difference between net actual and scheduled interchange, taking into account the effects of frequency bias] Absent by design in India In US/UK known as AGC / LFC

83. 83 Levels of frequency control Tertiary frequency rseponse Manual changes in the despatching and commitment of generating units Used to restore the primary and secondary frequency control reserves, to manage congestions in the transmission network, and to bring the frequency and the interchanges back to their target value in case secondary control is unable India  Manual load shedding / ABT mechanism

84. 84 Frequency Control Services Deployment times a key factor for categorizing Governing system AGC or LFC Re-dispatch

85. 85 Frequency Reserves Spinning/Reliability reserves Fast acting units/ controllable loads capable of instantaneous response Cannot support for long durations Can be provided by synchronized Hydro units/DG sets having reserve margins Supplementary reserves Response time not as quick as spinning reserves Capable of operating at increased power output for longer duration Manual intervention for activation Can be provided by units on hot standby Backup reserves Can stay in service for a longer time Response time higher e.g. > 30mins

86. 86 Generating unit -levels of control

87. 87 Voltage Control Primary voltage control Local automatic control that maintains the voltage at a set point vide AVR of generator Devices as static voltage compensators(SVC), can also participate Secondary voltage control Is a centralized automatic control that coordinates the actions of local regulators in order to manage the injection of reactive power within a regional power system. Tertiary voltage control Refers to the manual optimization of reactive power flows by say: –Switching in/out shunt/series compensations –Opening of lines to control overvoltage,etc –Asking generators to operate in lead/lag mode –Using other dynamic/static reactive compensating equipments IEGC mandates charging VAR exchanges with ISTS beyond the range 97% to 103%

88. 88 Drivers for Ancillary Services Reliability and Security Deregulated Power Systems Services to be obtained from Service Providers Decoupling with basic energy services Regulatory Directives: –NLDC/RLDCs to identify ancillary services as per clause 11.1 of the amended CERC UI Regulations, 2009 ““ b. Providing ancillary services including but not limited to ‘load generation balancing’ during low grid frequency as identified by the Regional Load Despatch Centre, in accordance with the procedure prepared by it, to ensure grid security and safety:”

89. 89 Ancillary services-comparison with international markets

90. 90 POSOCO’s Approach Paper Approach paper on ‘Ancillary Services in Indian Context’ published by POSOCO in June’10 –Submitted to the Commission –Comments sought from stakeholders Proposed services in the approach paper –Load Generation Balancing Service (LGBS) Use of un-despatched surplus, peaking and pumping stations –Network Control Ancillary Service (NCAS) Power Flow Control Ancillary Service (PFCAS) Voltage Control Ancillary Service (VCAS) –use of synchronous condensers –System Restart Ancillary Service (SRAS)

91. 91 POSOCO’s Approach Paper Comments received from various stakeholders Service identified for immediate implementation –Frequency Support Ancillary Service (FSAS) LGBS renamed as FSAS –Other services identified to be introduced subsequently, as the market matures Petition filed by NLDC –proposing roadmap and mechanism for introducing FSAS

92. 92 Frequency Support Ancillary Service (FSAS) Focus on utilizing idle generation –High liquid fuel and diesel cost –Fragmented need of load serving entities/buyers –Concern with frequent start stop operation Utilization of un-despatched generation from –Liquid fuel based –Diesel based –Merchant/ IPPs/ CPPs Quantum available under this service could be limited –frequency may not always be contained in the operation band Proposed amendments for introduction of separate peak tariff would compliment with monetary recovery / incentives

93. 93 Implementation of FSAS Facilitation through Power Exchange –Separate category of user group –Standing clearance from SLDC/RLDC –Bids to be invited after closure of DAM –Supplier, bid area, quantum, duration and price to be specified –NLDC to compile bids as per bid price, area –Transmission charges/losses as applicable for collective transactions would be applicable Despatch of bids under FSAS –System Operator to dispatch based on anticipated deficit and frequency profile –Threshold frequency: lower limit in the IEGC band –Dispatch certainty of at least 12 time blocks –Merit order to be ensured: low cost bids dispatched first

94. 94 Implementation of FSAS Dispatch in case of congestion –ATC limits to be honored –Merit order discounted in case of congestion –Lower price bids may be skipped –Downstream bids dispatched first Scheduling of bids under FSAS –Directly incorporated in the schedule of sellers –No matching one-to-one drawal schedule –Attributed towards drawal of a fictitious entity i.e ‘POOL’ –buyer/ drawee entity to pay back in the form of UI charges –Difference expected to be +ve in low frequency & -ve in case of high frequency –Frequency can deviate despite service triggering due to limited quantum Consent from sellers before dispatch –To ascertain readiness for dispatch –Agreed quantum scheduled after 6 time blocks –UI liability in case of failure to honour commitment

95. 95 Implementation of FSAS Options for settlement –‘Pay-as-bid price’ –‘Uniform Pricing’  All bids dispatched uniformly @ price of highest accepted bid –To be finalized by the Commission Ceiling price for despatch of bids –CERC’s UI vector ceiling price Payment settlement through power exchange Settlement on post-facto basis –On (n+1) th day or next working day Amount equivalent to FSAS bids dispatched in a region at the respective bid price would be transferred from regional UI pool to Power Exchanges Deficit if any to be funded from the PSDF via the Ancillary services fund Power exchanges to be paid facilitation charges

96. 96 Ancillary Services Fund ‘Ancillary Services Fund’ account to be opened and maintained by NLDC Procurement of Ancillary Services –Funded from the PSDF via Ancillary Services Fund –Clause 4 of CERC’s PSDF Regulation –Clause 11 of CERC’s amended UI Regulations

97. 97 Ancillary services-further scope Pumped storage plants Reimbursement of loss amount corresponding to power consumed and generated on UI discounted by efficiency factor Network Control ancillary services(NCAS) Power flow control ancillary services(PFCAS) –Settlement similar to FSAS Voltage control ancillary services –Operation of synchronous machines in synchronous condenser mode – initially hydro but could be possible for Gas & old Thermal stations in future –Reimbursement of charges on paise/KVARH basis discounting voltage factor –Power consumed due to windage/friction losses & resulting UI to be nullified and socilized in the pooled losses –Mobile reactive installations System restart ancillary services(SRAS) Incnetivization for successful mock black starts

98. 98 System restart services Black start capability of generating units –Dead bus charging on request –Ability to feed load –Frequency control –Voltage control –Act on the directions of system operator

99. 99 Ancillary services-Into the future Primary frequency control Frequency responsive demand disconnection by Bulk consumers Spinning reserves Contracted hydro / demand disconnection Frequency responsive automated initiation Reactive ancillary market Separation of FC in terms of utilization to produce real & reactive power Bid based procurement of reactive power Reatime reactive market Procurement of Dynamic Vars-voltage stability & enhancement of Transfer capability

100. 100 Thank you