1. Indian Electricity Grid Code Asit Singh Southern Regional Power Committee Bangalore June 2010

2. 2 Contents 1.General 2.Role of various organisations and their linkages 3.Planning code for Inter State Transmission 4.Connection Code 5.Operating Code 6.Scheduling and Despatch Code 7. Miscellaneous

3. 1. General

4. 4 Introduction To plan, develop, operate & maintain National/Regional Grid Power System Documentation of the principles which define relationship between various users Facilitation of optimal operation Facilitation power markets and ancillary services Facilitation renewable energy sources IEGC Rules Guidelines Standards Utilities connected with / using for ISTS

5. 5 Compliance Oversight (1.5) CERC Repeated Violation/ Persistent Non Compliance RLDC Report RPC Consensus Report issues not sorted suo-motto Action

6. 6 Compliance Oversight (1.5) CERC Non Compliance by NLDC, RLDC, SLDC, RPC or any other person Action Report by any person through petition

7. 2. Role of Various Organizations and their linkages NLDC, RLDC, RPC, CTU, CEA, SLDC & STU

8. 8 Role of NLDC (2.2) RLDC Inter Regional Links Supervision Economy and Efficiency of National Grid Monitoring of operations and grid security of National Grid Restoration of synchronous operation of National Grid Trans-national exchange of power Feedback to CEA & CTU for national Grid Planning Dissemination of information Levy and collection of fee and charges - CERC Disse NLDC Supervision & control RPC for regional outage Plan Coordinate Accounting

9. 9 Role of RLDC (2.3) Real time operation, control & contingency analysis Generation scheduling/ re-scheduling Restoration Metering & data collection Compiling & furnishing of operation data Operation of Regional UI pool Account. Reactive energy account and Congestion charge account Operation of ancillary services RLDC Exclusive functions

10. 10 Role of RLDC (2.3) Functions optimum scheduling and despatch of electricity Monitor grid operation Keep accounts of electricity transmitted Exercise Supervision and control over the ISTS Real time operations Licensee Generating company Generating station / Sub- stations any other concerned person SLDC CentralState DirectionsComply the directions Apex body for integrated operation For ST Open Access- Nodal Agency RLDC

11. 11 Role of RPC (2.4 ) Facilitate the stable and smooth operations of the system Functions: –regional level operation analysis –facilitate inter-state/inter-regional transfer of power –facilitate planning of inter-state/intrastate transmission system –coordinate maintenance of generating units –coordinate maintenance of transmission system –protection studies –Planning for maintaining proper voltages –Consensus on issues related to economy and efficiency RPC RLDC/SLDC/CTU/ STU/ Users Decisions MS SRPC shall certify Availability of transmission system Prepare Regional Energy Account, Weekly UI, Reactive & Congestion charge account

12. 12 Role of CTU (2.5) to undertake transmission of electricity through ISTS to ensure development of an efficient, co- ordinated and economical ISTS CTU RLDC shall operate ISTS lines CTU/to provide non-discriminatory Open Access –Will not engage in trading and generation –For LTOA & MTOA nodal agency Planning STU Central Govt. State2 State1 State Govt. Generating Companies CEA RPC Licensees

13. 13 Role of CEA (2.6) CEA (Central Electricity Authority) will formulate short-term and perspective plans for transmission system specify technical standards for construction of electrical plants, electric lines and connectivity to the grid specify safety requirements for construction, operation and maintenance of electrical plants and electrical lines specify grid standards for operation and maintenance of transmission lines specify conditions for SEMs Promote and assist timely completion of schemes To collect and record electrical data- cost, efficiency To carry out investigation ( Electrical system) Shall Prepare National Electricity Plan (NEP)

14. 14 Role of SLDC (2.6) SLDC – Apex body in a State Power System State Optimum scheduling and despatch Monitor grid operations Keep accounts of electricity transmitted Activities of Real-time operation exercise supervision and control RLDC Directions Ensure compliance Directions and exercise supervision and control Licensee, generating company, generating station, sub-station and any other concerned person

15. 15 Role of STU (2.8) to undertake transmission of electricity through intra-state transmission system to ensure development of an efficient, co- ordinated and economical intra-state transmission system STU SLDC shall operate Intra-state transmission system STU/to provide non-discriminatory Open Access Planning CTU State Govt. Generating Companies CEA RPC Licensees

16. 16 Role of STU (2.8) Energy transfer Efficient Economical STU SLDC shall operate Provide non-discriminatory open access Intra-state transmission system CTU State Government Generartors RPCs CEA Licencees Planning Coordination

17. 3. Planning Code for Inter-state Transmission Introduction Objective Scope Planning Philosophy Planning Criterion Planning Data Implementation of Transmission Plan

18. 18 Introduction Intra-State Inter-state CEA Intra-State STU CTU Transmission schemes for planning and coordination STU Transmission schemes for planning and coordination

19. 19 Scope of planning code (3.3) ISTS SEBs STU Licensees ISGSGC IPP CTU Generation/Transmission of energy to/from ISTS Connected to/using/developing ISTS specify principles, specify procedures specify criteria promote coordination information exchange Objective

20. 20 Planning Philosophy (3.4) CTU Identification of major inter state/regional lines including system strengthening schemes Planning schemes shall also consider: CEA’s:  Long-term perspective plan  Electric Power Survey of India report  Transmission Planning Criteria and guidelines  RPC Feedback  NLDC/RLDC/SLDC feedback  CERC Regulations  Renewable capacity addition (MNRES) Annual plan (5 year forward term) CEA Long-term plan (10-15 years) inter/intra state transmission system continuously updated to reflect load projections and generation scenarios NEP Avoid congestion

21. 21 Planning philosophy (contd...) System strengthening schemes by CTU: –shall be done in consultation with CEA’s Standing Committee for Transmission System Planning: Planning –On the basis of PPA –No PPA/ no consensus – CTU may approach CERC in accordance with CERC (Grant of Regulatory approval for Capital Investment to CTU for execution of ISTS) Planning data: –submission by STUs/Users to CTU:

22. 22 Planning philosophy (contd...) Voltage management by: –capacitors, reactors, SVC and FACTs –similar exercise by STU STU shall plan to evacuate power from ISTS ISTS & intra-state transmission systems are complementary & interdependent If LTA Applications require strengthening of intra-state transmission system – applicant shall coordinate with STU

23. 23 Planning Criterion (3.5) a) Planning criterion  ISTS’s security philosophy  CEA guidelines ia) Without load shedding or rescheduling of generation, ISTS shall withstand and secure against the following outages: –a 132 KV D/C line, a 220 KV /DC line, –a 400 KV S/C line, 765 KV S/C line –single Inter-Connecting Transformer (ICT ) –one pole of HVDC Bi-pole b) Without load shedding but could be with rescheduling of generation, ISTS shall withstand and secure against the following outages: –a 400 KV D/C line – a 400 KV S/C line with TCSC –both pole of HVDC Bi-pole or HVDV B2B stations –Outage of 765 KV S/C line with series compensation ii) Above contingency assuming a pre contingency system depletion. All generating units within their reactive capability curves and network voltage profile within limits

24. 24 Planning Criterion (3.5) b) ISTS shall withstand the loss of most severe single system in feed without loss of stability c) These outages should not cause: –loss of supply –prolonged operation of frequency below and above limits –unacceptable high or low voltage –system instability –unacceptable overloading of ISTS elements

25. 25 Planning Data & Implementation All S/S (132 kV & above) shall have at least two transformers CTU will carry out reactive power compensation requirement of ISTS & ISGS’ switchyard SPS may be planned by NLDC/RLDC in consultation with CEA, CTU, RPC & Regional entities – for enhancing transfer capability or to take care of additional contingencies

26. 26 Planning Data & Implementation Planning Data (3.6) –As per CERC (Grant of Connectivity, LTA and MTOA in ISTS and related matters) Regulations 2009 Implementation of Transmission Plan (3.7) –Actual program of implementation of transmission lines, ICTs, reactors/capacitors and other transmission elements as per CERC (Grant of Connectivity, LTA and MTOA in ISTS and related matters) Regulations 2009

27. 4. Connection Code Minimum technical & design criteria OBJECTIVE Ensure the safe operation, integrity and reliability of the grid Non-discriminatory New/modified connection not suffer or impose unacceptable effects In advance knowledge about Connectivity ISTS SCOPE CTU STU Users connected to ISTS or seeking connection to ISTS Comply with CEA( Technical Standards for connectivity to the Grid) 2007

28. 28 Procedure for connection (4.4) User seeking new/modified connection: –Shall submit an application on standard format in accordance with CERC (Grant of Connectivity, LTA and MTOA in ISTS and related matters) Regulations 2009 –CTU shall process as per above regulations

29. 29 4.5 Connection Agreement –Connection agreement would be signed by the applicant in accordance with CERC (Grant of Connectivity, LTA and MTOA in ISTS and related matters) Regulations 2009

30. 30 Reactive Power Compensation 4.6.1 –by /STUs and Users in the low voltage systems close to the load points therby avoiding exchange of reactive power to/ from the ISTS –Already connected shall provide additional reactive compensation as per the quantum and time frame decided by the RPC in consultation with RLDC. –Installation and healthiness would be monitored by RPC

31. 31 Data and Communication Facilities (4.6.2) – reliable and efficient speech and communication system to be provided –Users/STU/CTU shall provide systems Flow Voltage Status of switches Status of transformer taps –Associated communication system to facilitate data flow up to appropriate data collection point on CTU’s system as specified by CTU in the Connection Agreement

32. 32 System Recording Instruments (4.6.3) –Data Acquisition System/Disturbance Recorder/Event Logging facilties/Fault Locator (including time synchronization equipment ) shall be provided and always kept in working condition Responsibility for safety (4.6.4) –CEA (Technical Standards for connectivity to the Grid), Regulations 2007 –CERC (Grant of Connectivity, LTA and MTOA in ISTS and related matters) Regulations 2009 –CEA (Safety Requirements for construction, operation and maintenance of electrical and electric lines) Regulations, 2008

33. 33 Cyber Security (4.6.5) International Connections to ISTS (4.7) –By CTU in consultation with CEA and MOP Schedule of assets of Regional Grid (4.8) –CTU and other transmission licensees shall submit by 30 th Sep a schedule of transmission assets as on 31 st March indicating ownership on which RLDC has operational control and

34. 34 5. Operating Code

35. 35 Operating philosophy (5.1) objective of the integrated operation: –enhance overall operational reliability and economy –Cooperate and adopt Good Utility Practice NLDC: –overall operation of National/Inter-Regional Grid –develop/maintain detailed internal operating procedures for national grid RLDC: –overall operation of Regional Grid –develop/maintain detailed internal operating procedures for regional grid

36. 36 Operating philosophy (5.1) SLDC: –develop/maintain detailed internal operating procedures for State grid All licensee, generating company, generating station and any other concerned person: –comply with directions of RLDC/SLDC e) round-the clock manning by qualified and trained oersonnelof: –control rooms of NLDC, RLDC, SLDC, Power Plant, Sub Stations (132 kV & above) –control centres of all regional constituents

37. 37 System Security Aspects (5.2) Synchronism: –all Users, CTU & STU –operate their power systems/stations in an integrated manner No deliberate isolation of part of the grid: –except under emergency –safety of human/equipment –when instructed by RLDC –restoration to be supervised by RLDC in coordination with NLDC/SLDC

38. 38 System Security Aspects (5.2) Important elements list at RLDC: –not removed without RLDC’s consent or prior consent –when specifically instructed –list of important elements to be prepared and shall be put on website of NLDC/RLDC/SLDC –emergency removal intimated to RLDC –tripping, reason, likely time of restoration intimated to RLDC say within 10 minutes –Important elements tripping to be informed to NLDC by RLDC –Prolonged outage ------ sub-optimal operation---- monitored by RLDC------report to RPC-------- finalise action plan for restoration

39. 39 Restricted Governor Action (5.2(f)) Thermal generating > 200 MW and hydro units > 10 MW on RGMO wef 01.08.2010 Hydro with pondage upto 3 hrs, Gas Units, Combined Cycle, wind, solar & nuclear exempted till CERC reviews When frequency stabilise at 50.0 Hz FGMO would be intoduced RGMO –For Frequency < 50.2 Hz no reduction in generation when frequency rises –Any fall in frequency generation should pick upto 105% MCR (thermal), 110% MCR (Hydro) –Ramp down/ Ramp down at 1% per minute –At Frequency < 49.7 Hz ramp up cold be at higher rate –Ripple factor of +/- 0.3 Hz shall be provided to avoid Governor hunting –governors: 3% - 6% droop –any exception: reason & duration to RLDC –Governor operation shall not be suppressed by: load limiters, Automatic Turbine Run up Systems (ATRS), Turbine Supervisory Control, Coordinated control system, deliberate dead bands/time delays

40. 40 System Security Aspects (5.2(j)(k)(l)(m)) Generating output cannot be reduced by 100 MW(20 MW NER) User/SEB no variation of load by 100 MW(20 MW NER) - exception with RLDC permission AVR shall be in operation: –exception with RLDC permission: 50MW –CTU/RPC shall tune/check PSS in AVR Protection & relay settings: finalized by Protection sub-Committtee 49.5 – 50.2 Hz freq. Band

41. 41 System Security Aspects (5.2(n)) automatic under frequency & df/dt Relays : –as per the plan of RPC; –Relays/islanding schemes to be always functional –RLDC shall inform RPC Secretariat when desired load relief is not obtained in real time –SLDC should monthly report to RPC/ CERC –RPC Secretariat shall inspect relays and keep proper record –RPC shall decide and intimate action required to get desired load relief –RLDC shall keep a comparative statement of actual/desired relief. Monthly report shall be sent to RPC/CERC

42. 42 System Security Aspects (5.2(o) (p) (q) (r)) System Protection Scheme (SPS) (including inter-tripping and run-back): –To be provided –Protection against Voltage Collapse, Cascade tripping, tripping of important corridors/flow-gates etc. –Finalized in RPC forum, always in service Adequate and reliable communication to be provided. Redundancy & alternate path to be provided. Information/data regarding Disturbance recorder/ Sequential event recorder to RLDC within one week. No data/information to be blocked to RPC/RLDC.

43. 43 System Security Aspects 5.2 (s) Voltage- (kV rms) NominalMaximumMinimum 765800728 400420380 220245198 132145122 11012199 667260 333630

44. 44 System Security Aspects (5.2 (t) (u)) Provide adequate voltage control measures through Voltage Relay as finalized by RPC Special requirement for Solar/wind generators: –RLDC/SLDC shall make all efforts – must run –Backdown – system/ equipment/personnel security –Data Acquisition System facility – data transfer- SLDC/RLDC –Var injection/drawal to be curtailed on instruction by SLDC/RLDC –During start up Var drawal (inrush) shall not affect the grid performance

45. 45 DEMAND ESTIMATION FOR OPERARTIONAL PURPOSES Demand Estimation – Active and reactive power Daily /Weekly /Monthly historical data and weather forecast on-line estimation for daily operationa l use By 01.01.2011 – online estimation of demand for each 15 min block Inform to RLDC/ RPC Wind Energy Forecast ATC/ TTC

46. 46 Demand Management(5.4) SLDCs shall control demand in the event of: insufficient generating capacity/inadequate external transfer breakdown/congestion problems Demand disconnection –frequency: below 49.7 Hz: shall initiate action to restrict their net drawal below 49.5 Hz: requisite load shedding –Each User/STU/SLDC shall formulate contingency procedures and make arrangements. Contingency Procedure to be regularly updated and monitored by SLDC/RLDC –SLDC through respective SEBs/Discoms shall formulate and implement state-of-the-art demand management schemes- roatational load shedding/demand response (which may include lower tariff for interruptible load) etc. SLDC to furnish periodic report to CERC.

47. 47 Demand Management(5.4.2(e)(f)(g)(h)) Interruptible load in four groups: Scheduled load shedding/power cuts Unscheduled load shedding UFR/df/dt loads SPS loads No overlapping RLDC may direct to decrease drawal in contingency---SLDCto send compliance report SLDC may direct SEB/Discom/bulk consumer to curtail drawal and monitor RLDC shall devise standard, instantaneous, message formats Congestion – requisite load shedding or generation backing down. Implementation as per CERC ( Measures to relieve congestion in real time operation), Regulations, 2009

48. 48 Periodic Reports (5.5) weekly report by NLDC (put on website): –Performance of national/integrated grid daily report by RLDC (put on website): –Performance of national/integrated grid –Wind power injection quarterly report by RLDC : –system constraints, reasons for not meeting the requirements, security standards & quality of service –actions taken by different persons –persons responsible for causing the constraints weekly report by RLDC (put on website): –Frequency and voltage profiles –Major generation & transmission outages –Transmission constraints –Instances of persistent/significant non-compliance of IEGC –Instances of congestion –Instance of inordinate delay in restoration –Non-compliance of instructions of SLDCs by SEB/Discom RLDC shall provide information/report to RPC for smooth operation of ISTS

49. 49 Operational Liaison (5.6) Introduction a) requirements for the exchange of information in relation to Operations/Events on the total grid system which have had or will have an effect on: National grid the regional grid the ISTS in the region the system of a User/STU (the above generally relates to notifying of what is expected to happen or has happened and not the reasons why) b) Operational liaison function is a mandatory built-in hierarchical function of the NLDC/RLDC/SLDC/Users to facilitate quick transfer of information to operational staff

50. 50 Procedure for Operational Liaison a) Operations and event on the regional grid before carrying out any operation, RLDC will inform User/SLDC/CTU whose system will be affected immediately following an event, RLDC will inform the User/SLDC/CTU with details of what happened but not the reasons why RLDC to NLDC if other region is going to be affected immediately following an event, NLDC would keep all RLDCs informed b) Operations and events on a User/STU system before carrying out any operation that will affect regional grid, constituent shall inform RLDC with details RLDC to NLDC if other region is going to be affected immediately following an event, the User/SLDC shall inform RLDC with details but not the reasons why immediately following an event, NLDC would keep all RLDCs informed Prolonged Forced outages – monitored at RPC level. RPC shall send a monthly report to CERC

51. 51 Outage Planning (5.7) Introduction a) procedures for preparation of outage schedules for the elements of the National/Regional in a coordinated and optimal manner and the balance of generation and demand b) generation output and transmission system should be adequate after taking outages into account to achieve security standards c) annual outage plan for the financial year shall be prepared by RPC Secretariat and reviewed during the quaterly and monthly basis. ROR, wind & solar power to be extracted to maximum

52. 52 Outage Planning Process MarJanNov next financial year proposed outage programmes by all concerned (30 th Nov) Dec draft outage programme by RPC Secretariat (31 st Dec) final outage programme by (31 st Jan) Feb Review by RPC Secretariat: adjustments made wherever found to be necessary in coordination with all parties concerned monthly review quarterly review

53. 53 Outage Planning (5.7.4) In consultation with NLDC/RLDC In Emergency – RLDCs may conduct studies before clearance NLDC/RLDC are authorized to defer - grid disturbance - system isolation - partial black out in a state - any other critical event Latest detailed outage plan – updated Each user, CTU and STU shall obtain one final approval from RLDC RPC shall submit quarterly, half yearly reports to CERC indicating deviations

54. 54 Recovery Procedures (5.8) Detailed plans/procedures for restoration of partial/total blackout regional grid consultations RLDC Concerned Constituents SRPC secretariat develops reviewed/updated annually Detailed plans/procedures for restoration of partial/total blackout develop reviewed/updated annually Mock trials once every 6 months DG sets to be tested on weekly basis- quarterly report to be sent to RLDC

55. 55 Recovery Procedures (contd...) List of the following shall be available with NLDC/RLDC/SLDC: –generating stations with black start facility –inter-state/regional ties –synchronising points –essential loads to be restored on priority During restoration following blackout, RLDC authorized to operate the grid with reduced security standards for v & f all communications channels for restoration shall be used for operational communications only till grid normalcy is restored

56. 56 Event Information (5.9) Introduction –reporting procedures in respect of events to all Users, STU,CTU RPC secretariat, NLDC/RLDC/ SLDC Responsibility –RLDC/SLDC shall be responsible for reporting events to the Users/SLDC/ STU/CTU RPC secretariat/ NLDC /RLDC –Users/ STU/CTU /SLDC shall be responsible for collection and reporting all necessary data to NLDC/RLDC and RPC secretariat for monitoring, reporting, and event analysis

57. 57 Reportable events (5.9.5) iViolation of security Standards iiGrid indiscipline iiiNon-Compliance of RLDC’s instruction ivSystem islanding/ system split vRegional black out/partial system black out viProtection failure viiPower system instability viiiTripping of any element ixSudden load Reduction

58. 58 Reporting Procedure RLDC Users/STU/ CTU/SLDC written report of events weekly written report of events Form of written reports: NLDC i) Time and datevi) Duration of interruption ii) Locationvii) Recording System informations iii) Plant or equipment directly involved viii) Sequence of trippings with time iv) Description and cause of eventix) Remedial Measures v) Antecedent Condition

59. 59 6. Scheduling & Despatch Code a)demarcation of responsibilities b)procedure for scheduling & despatch c)Reactive power and voltage control mechanism d)complementary commercial mechanism (Annexure-I)

60. OBJECTIVE Procedure for submission of Capability declaration Procedure for submission of requistion/ drawal schedule by regional entities Real time despatch/drawal instructions Rescheduling Commercial arrangement for UI/Reactive Scheduling of wind/solar on 3 hourly basis Appropriate Metering Discoms SCOPE Power Exchanges ISGS SEBs/STUs Other concerned Wind/Solar generators NLDC RLDC SLDC

61. 61 Demarcation of responsibilities (6.4) Role of RLDC RLD C Scheduling of CGS (Except where full share is allocated to host state) Scheduling of UMPP Schedul ing of GS connect ed to ISTS Scheduling of GS connected both to ISTS and state grid and home state is less then 50%

62. 62 Demarcation of responsibilities (6.4.4) SLDC SLDC Permitting Open Access Regulating net drawal Scheduling and despatching Scheduling drawal from ISGS Demand Regulation 6.4.8 Demand Estimation in coordination with STU/Discoms

63. 63 Demarcation of responsibilities (6.4.6/7) System of each regional entity shall be operated as notional control area Scheduled drawal + Bilaterals on day ahead basis Regional entity would regulate its own generation and load so that drawals are close to schedules Regional entity would Endeavour for UI=0 at F<49.7 Hz. At F< 49.5 Hz,automatic demand management scheme/manual demand disconnection

64. 64 Regional Entities Agreements ISGS project2 Joint/bilateral agreements for –State’s share in ISGS projects –scheduled drawal pattern –tariffs –payment terms ISGS project1 ISGS projet3 State3 State4 State5 State2State1 RLDCRPC CTU Long Term, MTOA RLDC/SLDC

65. 65 6.4.9 Role of ISGS/ Generating Station ISGS Generate as per despatch schedule advised to them by RLDC Deviation from Schedule UI Proper Operation and Maintenance When F>50.2, backdown generation When F<49.7, maximize generation Planned Outages OCC of RPC DC during Peak Hours > Other Hours Declare DC Faithfully Penalty : Capacity Charges reduced

66. 66 Hydro ISGS Hydro ISGS DC should take care of irrigation, drinking water, industrial and environmental concerns Deviation from Schedule. Adjusted in 44 th day schedule S4=E4+(A1-E1) Respond to frequency and inflows- no gaming & System Constraint Run of river with pondage DC= IC + Over Load capacity – Aux. Con Run of river = must run stations Otherwise spillage

67. 67 Role of CTU CTU Install SEMs CEA (Installation and operation of Meters ) Regulations Weekly Readings Constituents where SEMs are located

68. 68 Demarcation of responsibilities Role of RLDC RLD C Periodically review UI Gaming by ISGS 15 min drawal and injectio n MS SRPC Report 105 % in one block of 15 minutes and 101% over a day no gaming

69. 69 Role of RPC RPC Outage Planning REA, UI, Var Accounting

70. 70 Role of NLDC NLDC Trans-National Exhange of Power Scheduling on Inter Regional Links. Energy accounting on IR Links- with RLDC HVDC Settings Scheduling of Inter-Regional Power Exchanges Collective Transaction Scheduling

71. 71 Scheduling & Despatch Procedure (6.5) List of ISGSs and beneficiaries –all ISGS whose output is shared by more than state shall be listed on RLDC and SLDC websites –the station capacities and allocated/contracted shares of different beneficiaries shall also be listed out State’ entitlement: –Thermal ISGS: (foreseen ex-power plant MW capability for the day) X (state’s share in the station’s capacity) –Hydro ISGS: (MWH generation capacity for the day) X (state’s share in the station’s capacity)

72. 72 Preparing final schedule 121234567891011121234567891011121 noon ISGS SLDC Despatch schedule net Drawal schedule revision station-wise MW/MWH capability station-wise W/MWH entitlement required Drawal schedule AMPM RLDC Despatch schedule starts Drawal schedule starts final Despatch schedule final Drawal schedule

73. Scheduling of Collective Transaction 6.5.5 73 Power Exchanges NLDC SLDC RLDC 1. List of Interfaces, Control areas 2. Interchanges Interfaces, Control areas 3. Check for Congestion, reworked as per CERC directive 4. Consultation 6. Individual Transactions 7. Schedule individual transaction 5. Schedule at respective periphery

74. 74 Revision of schedules during the day any State may revise: –drawal schedule from any/all ISGS within their entitlementsto be effective from 6 h time block) an ISGS may revise: –capability on account of forced outage. (to be effective from 4 th time block) –Revision (to be effective from 6 h time block) Generator for STOA > 100 MW may revise: –capability on account of forced outage. (to be effective from 4 th time block) RLDC can revise: –In the interest of better system operation (to be effective from 4 th time block) –Shall formulate procedure for meeting contingency

75. 6.5.23 Special dispensation for scheduling of wind and solar generation wef 01.01.2011 scheduling and UI would be done for wind - > 10 MW - connection point at 33 kV and above - PPA has not been signed Revisions effective from 6 th time block. 8 revisions allowed for each 3 hour slot

76. 6.5.23 Special dispensation for scheduling of wind and solar generation Schedule of solar generation –Availability of generators –Weather forecasting –Solar insulation –Seasonal and normal solar generation curve Forecast to be vetted by RLDC Concerned RLDC/SLDC shall maintain records and shall aim at utilizing the available wind and solar energy fully

77. 77 Other Contingencies In the event of bottleneck in evacuation of power, RLDC may revise the schedules which will be effective from 4 th time block and for 1-3 time blocks schedules would deemed to have been replaced by actual. Similarly for entire period of grid disturbance, schedules will be replaced by actual No revision – if change in previous schedule/capability is less than 2%.

78. 78 Other Contingencies Revised schedules implemented irrespective of communication success For every change in generation schedule there would be corresponding change in drawal schedule Procedure for recording the communication regarding changes in schedules taking into account to be developed by CTU Curtailment STOA -Collective Transactions- MTOA-LTOA

79. 79 Final schedule & Documentation RLDC’s final implemented schedule: –shall be the datum for commercial accounting –shall be open for 5 days for verification/correction RLDC shall properly document the following: –station-wise foreseen ex-power plant capabilities advised by the generating stations –the drawal schedules advised by beneficiaries –all schedules issued by RLDC –all revisions/updating of the schedules

80. 80 Reactive Power & Voltage Control (6.6) VAR Charges under Low Voltage VAR Charges under High voltage Beneficiary1 Voltage: < 97% Pool Account VAR charges EHV grid Beneficiary2 Q Q Beneficiary1 Voltage: > 103% Pool Account VAR charges EHV grid Beneficiary2 QQ

81. 81 VAR charges settlement No VAR charges for its own lines emanating directly from ISGS VAR charges at the nominal paise/KVArh rate as may be specified by CERC and will be between beneficiaries and POOL (Present rate is 10.0 p/kvarh with escalation of 0.5 p/kvarh every year) RLDC may direct Regional entity to curtail VAR drawal/injection for safety and security of grid or safety of equipment Beneficiaries to minimise injection/drawal of VAR if voltage goes beyond + 5%. ICT taps may changed as per regional entity request to RLDC Tap changing (400/220 kV)and switching in/out of line reactors (400kV) shall be carried out as per RLDC instruction. ISGS to generate/absorb VAR as per RLDC instruction, within its capabilities and without sacrificing active generation..

82. 82 VAR charges between two beneficiaries on interconnecting line owned by them singly or jointly Can agree mutually not to have any charges. Can mutually agree to adopt any payment rate / scheme. Or can adopt rate specified by CERC. In case of disagreement, they have to adopt scheme specified by CERC in Annexure -3 (given below) Payment to be made if one is to pay and other is to receive and will be min(x1,x3)+min(x2,x4). IN SR it is min(x1+x2,x3+x4) Payment will be between the two beneficiaries on one to one basis State A State B X1 X2 X3 X4 V > 103% V < 97 %

83. 83 7. Miscellaneous Nothing in this Regulation shall be deemed to limit or affect the power of the Commission…. Conformity with the provision of Act… Nothing in this Regulation shall bar the Commission to deal with any matter or exercise any power under Act…. May grant relaxation…

84. 84 Annexure-1 (6.1 d) Complementary Commercial Mechanisms

85. 85 Capacity charge + Energy charge ISGS beneficiary1 beneficiary2 UI Capacity charge + Energy charge UI Generation Cost UI Settlement System UI Full reimbursement for generation as per the generation schedule

86. 86 Weekly bills & penalty (12, 13, 14) RLDC Constituents UI Settlement System Pool Account UI bills UI payment VAR payment payment within 10 days from date of billing simple interest @ 0.04% per day to constituent for delayed payment beyond 12 days. RPC VAR bills monthly payment status CERC payment defaults

87. 87 Regional Energy Accounting Sun 15-minute block SEM readings for a week RLDC Constituents Weekly raw SEM data Weekly UI and VAR Account ISTS Connections Mon Tue Wed Thu Fri Sat Sun Mon Tue Wed Thu Fri Sat Sun Mon Tue   Monthly (6 th ): REA RLDC to tabulate UI account and REA in RPC’s CC meeting on a quarterly basis for audit by the later.

88. Complementary Commercial Mechanism Money left in VAR account shall be utilized for training of SLDC operators and other similar purposes If paid-out > paid-in, proportionate reduction

89. Commercial settlement for Wind Generators Schedule (MW) Actual (MW) Implication on Purchaser UI Implication in host state UI implication on wind generator 100 To pay WG for 100 MW Nil 10070To pay WG for 70 MW and 30 MW to RRF at UI rate of his region 30 MW UI from RRF Nil 10060To pay WG for 70 MW and 30 MW to RRF at UI rate of his region 30 MW UI from RRF 10 MW UI from the pool UI for 10 MW by WG to UI Pool

90. Commercial settlement for Wind Generators Schedul e (MW) Actual (MW) Implication on PurchaserUI Implication in host state UI implication on wind generator 100130To pay WG for 130 MW. For 30 MW receive UI from RRF at UI rate of his region UI for 30 MW to be passed on RRF Nil 100140To pay WG for 130 MW. For 30 MW receive UI from RRF at UI rate of his region UI for 30 MW to be passed on RRF. UI for 10 MW passed to UI pool UI for 10 MW received from UI pool 100160To pay WG for 130 MW. For 30 MW receive UI from RRF at UI rate of his region UI for 30 MW to be passed on RRF. UI for 30 MW passed to UI pool UI for 20 MW received from UI pool at UI rate and for balance 20 MW at UI rate of 50.02 Hz- 50.00 Hz

91. Commercial settlement for Wind and Solar Generators Balance in Renewable Regulatory Fund (RRF) surplus/deficit would be shared by states in the ratio of the peak demands in the previous month NLDC would prepare a detailed procedure

92. 6.5.23 Special dispensation for scheduling of solar generation wef 01.01.2011 scheduling and UI would be done for solar - > 5 MW - connection point at 33 kV and above - PPA has not been signed

93. Commercial settlement for Solar Schedule (MW) Actual (MW) Implication on Purchaser UI Implication in host state UI implication on solar generator 55To pay SG for 5 MWNil 54To pay SG for 4 MW and 1 MW to RRF at UI rate of his region 1 MW UI from RRF Nil 56To pay WG for 6 MW and receive for 1 MW UI from RRF at contracted rate 1 MW UI to RRF at UI rate Nil

94. NRWRERSR GorakhpurMuzzafarpur AllahabadSasaram MughalsaraiSasaram RaipurRourkela KorbaBudhipara TalcherKolar JeyporeGazuwaka

95. NRWRERSRNER Chandrapu r Ramagund am KankroliZerda RihandVindhayac hal AgraGwalior MaldaBongaigao n PurneaBongaigao n BirparaSalakati

96. 96 References websites: www.cercind.gov.in www.srldc.org www.srpc.kar.nic.in

97. Thank you!