1. Largest sized hydro unit (180 MW at Chamera) in the country Salient Features Northern Regional Power System Welcome Session on GRID CODE In the course on “ GRID CODE AND MERIT ORDER SCHEDULING AND DESPATCH UNDER ABT ”

2. Largest sized hydro unit (180 MW at Chamera) in the country Salient Features Northern Regional Power System Welcome INDIAN ELECTRICITY GRID CODE (IEGC)

3. PRESENTATION : ORGANISATION Need for an IEGC Development of the present IEGC version Indian Electricity Grid Code : Contents IEGC : Demarcation of Resposibilities ABT / IEGC Clauses ABT Feedback

4. NEED FOR AN IEGC Period Situation Early 1970sVertically integrated SEBs. Few problems – resolved either bilaterally or at REB level. Late 1970s- Entry of Central Generating Utilities. Early1980s Gradual increase in disputes but consensu generally emerged at REB level. Late 1980s Disputes/conflicts increased in direct proportion to number of Central Sector Power Stations. Limitations in resolving the same at REB level.

5. NEED FOR AN IEGC Period Situation Early 1990s Unresolved commercial disputes resulted in need of an umpire. 1994-96 Transfer of RLDCs from CEA to POWERGRID. 1997-99 Amendments to ES Act, Constitution of CERC / SERCs, Unbundling of SEBs, possible entry of mega IPPs, IPTCs - more players, more scope for confusion.

6. DEVELOPMENT OF IEGC Feb 1999 Special Working Group Under Shri D.P. Sinha, Member CERC Submits Its Report Indicating Modalities for Formulating IEGC. 31 st Mar 99 CERC issues directives to POWERGRID for preparing IEGC and organisational arrangements for the CTU. 9 th April 99 Draft IEGC submitted to CERC (Petition 1/99). Apr-May 99 Draft IEGC made public on the directions of CERC to elicit comments from all sections.

7. DEVELOPMENT OF IEGC July 1999 Public hearings by CERC on the draft IEGC on 20 th, 21 st & 23 rd July 1999. 30 th Aug 99 Revised IEGC draft submitted by POWERGRID to CERC. 30 th Oct 99 & CERC’s orders on above IEGC draft (Aug. 99 22 nd Nov 99 Version) 7 th Dec 99 IEGC draft ( Aug. 99 Version ) revised as per above orders and filed before CERC.

8. DEVELOPMENT OF IEGC 21 st Dec 99 Final directions of CERC on the above IEGC draft. 28 th Dec 99 First version of IEGC as per above orders and circulated to all agencies & implemented w.e.from 1 st Feb 2000 24 th July IEGC Review Panel constitution approved 2000 by CERC 17 th Nov Rules & Guidelines of IEGC Review Panel 2000approved by CERC

9. DEVELOPMENT OF IEGC 29 th March Amendments to IEGC forwarded by 2001 Review Panel to CERC after meetings on 12 th Feb & 26 th March 2001 22 nd Feb First review of IEGC approved by CERC 2002based on the draft submitted by CTU based on orders dated 3 rd Aug 2001 and meeting of Review Panel on 10 th Dec 2001. 1 st April First review of IEGC in force. 2002

10. Indian Electricity Grid Code Chapter – 1 --- General Chapter – 2 --- Role of RLDC, REB, CTU etc. and their organisational linkages Chapter – 3 --- Planning Code for Interstate transmission Chapter – 4 --- Connection conditions Chapter – 5 --- Grant of transmission license

11. Indian Electricity Grid Code Chapter – 6 --- Operating Code for Regional Grids Chapter – 7 --- Scheduling & Despatch Code Annex – 1 --- Complementary Commercial Mechanisms Annex – 2 --- Metering Details Chapter – 8 --- Management of IEGC

12. CHAPTER – 1 GENERAL Objective of IEGC :- The IEGC is a Compendium of Technical Rules, covering all utilities connected to or using the Inter-state Transmission System (ISTS) and provides the following :  Documentation of the principles and procedures defining the relationship between the various users of the ISTS as well as the RLDCs & SLDCs.  Facilitates the Operation, Maintenance, Development and Planning of Economic and Reliable Regional Grid.  Facilitates beneficial trading of electricity by defining a common basis of operation of the ISTS, applicable to all the users of the ISTS.

13. CHAPTER – 1 GENERAL Scope of IEGC :- Applicable to all parties that connect with and/or utilise the ISTS. BBMB Generating Stations treated as Intra-State while its Transmission System treated as ISTS. DVC treated similar as STU/SEB.

14. CHAPTER – 1 GENERAL Non - Compliance of IEGC :-  Persistent non - compliance of any stipulation of IEGC by Constituent / ISGS / CTU shall be reported to Member Secretary, REB.  MS - REB / CEA would take up the matter with the defaulting agency for terminating non - compliance.  Non – compliance of IEGC stipulations by RLDC / REB shall be reported to CEA.  In case of inadequate response to above efforts by MS REB/CEA, non - compliance shall be reported to CERC.  CERC after due process may order the defaulting agency for compliance. CEA/REB SHALL MAINTAIN APPROPRIATE RECORDS OF SUCH VIOLATIONS.

15. CHAPTER – 1 GENERAL KEYWORDS / DEFINITIONS FREQUENCY VARIATION INDEX (FVI) :- A performance index representing the degree of frequency variation from the nominal value of 50 Hz, over a specified period of time. N ∑ (F i – 50) 2 i=1 N FVI = 10 X --------------- (  (F i – 50) 2 /N) N i=1 where, F i = Actual Frequency in Hz at i th time period, N = Number of measurements over the specified period of time.

16. CHAPTER – 1 GENERAL KEYWORDS / DEFINITIONS INTER STATE GENERATING STATION (ISGS) :- A Central / Mega Power Project/ other Generating Station in which two or more than two states have a share and whose scheduling is to be coordinated by the RLDC.

17. CHAPTER – 1 GENERAL KEYWORDS / DEFINITIONS The conveyance of energy across the territory of an intervening state as well as conveyance within the state which is incidental to such interstate transmission of energy. The transmission of energy within the territory of a state on a system built, owned, operated, maintained or controlled by the Central Transmission Utility (CTU) or by any person /agency under the supervision and control of a CTU. INTER STATE TRANSMISSION SYSTEM (ISTS) :- Any system for the conveyance of energy by the means of a main transmission line from the territory of one state to another state and includes :

18. CHAPTER – 1 GENERAL KEYWORDS / DEFINITIONS STANDING COMMITTEE FOR TRANSMISSION PLANNING : A committee constituted by the CEA to discuss, review and finalise the proposals for ISTS and associated Intra-State Systems.

19. CHAPTER – 2 ROLE OF RLDC, REB, CTU ETC. AND THEIR ORGANISATIONAL LINKAGES

20. 28 (1) The Regional Load Despatch Centre shall be the apex body to ensure integrated operation of the power system in the concerned region. (2) The Regional Load Despatch Centre shall comply with such principles, guidelines and methodologies in respect of the wheeling and optimum scheduling and despatch of electricity as the Central Commission may specify in the Grid Code. (3) The Regional Load Despatch Centre shall -  be responsible for optimum scheduling and despatch of electricity within the region, in accordance with the contracts entered into with the licensees or the generating companies operating in the region; A.Role of RLDCs :- (EXTRACTS FROM ‘ THE ELECTRICITY ACT, 2003 ’ ) Continued ….. Functions of RLDC’s

21. (b) monitor grid operations; (c) keep accounts of the quantity of electricity transmitted through the regional grid; (d) exercise supervision and control over the inter-State transmission system; and (e) be responsible for carrying out real time operations for grid control and despatch of electricity within the region through secure and economic operation of the regional grid in accordance with the Grid Standards and the Grid Code. (4) The Regional Load Despatch Centre may levy and collect such fee and charges from the generating companies or licensees engaged in inter-State transmission of electricity as may be specified by the Central Commission. A.Role of RLDCs (contd..) :- Functions of RLDC’s (contd..)

22. 29. (1) The Regional Load Despatch Centre may give such directions and exercise such supervision and control as may be required for ensuring stabilityof grid operations and for achieving the maximum economy and efficiency in the operation of the power system in the region under its control. (2) Every licensee, generating company, generating station, substation and any other person connected with the operation of the power system shall comply with the direction issued by the Regional Load Despatch Centres under sub-section (1). (3) All directions issued by the Regional Load Despatch Centres to any transmission licensee of State transmission lines or any other licensee of the State or generating company (other than those connected to inter State transmissionsystem) or sub-station in the State shall be issued through the State Load Despatch Centre and the State Load Despatch Centres shall ensure that such directions are duly complied with the licensee or generating company or sub- station. A.Role of RLDCs (contd..) :- Continued ….. Compliance of Directions of RLDCs

23. (4) The Regional Power Committee in the region may, from time to time, agree on matters concerning the stability and smooth operation of the integrated grid and economy and efficiency in the operation of the power system in that region. (5) If any dispute arises with reference to the quality of electricity or safe, secure and integrated operation of the regional grid or in relation to any direction given under sub-section (1), it shall be referred to the Central Commission for decision: Provided that pending the decision of the Central Commission, the directions of the Regional Load Despatch Centre shall be complied with by the State Load Despatch Centre or the licensee or the generating company, as the case may be. (6) If any licensee, generating company or any other person fails to comply with the directions issued under sub-section (2) or sub-section (3), he shall be liable to penalty not exceeding rupees fifteen lacs. A.Role of RLDCs (contd..) :- Compliance of Directions of RLDCs (contd..)

24. 32. (1) The State Load Despatch Centre shall be the apex body to ensure integrated operation of the power system in a State. (2) The State Load Despatch Centre shall -  be responsible for optimum scheduling and despatch of electricity within a State, in accordance with the contracts entered into with the licensees or the generating companies operating in that State; (b) monitor grid operations; (c) keep accounts of the quantity of electricity transmitted through the State grid; B. Role of SLDCs :- (EXTRACTS FROM ‘ THE ELECTRICITY ACT, 2003 ’ ) Continued ….. Functions of SLDCs

25. (d) exercise supervision and control over the intra-state transmission system; and (e) be responsible for carrying out real time operations for grid control and despatch of electricity within the State through secure and economic operation of the State grid in accordance with the Grid Standards and the State Grid Code. (3) The State Load Despatch Centre may levy and collect such fee and charges from the generating companies and licensees engaged in intra-State transmission of electricity as may be specified by the State Commission. B. Role of SLDCs (contd..):- Functions of SLDCs (contd..)

26. Continued ….. Compliance of Directions of SLDCs 33. (1) The State Load Despatch Centre in a State may give such directions and exercise such supervision and control as may be required for ensuring the integrated grid operations and for achieving the maximum economy and efficiency in the operation of power system in that State. (2) Every licensee, generating company, generating station, substation and any other person connected with the operation of the power system shall comply with the direction issued by the State Load Depatch Centre under subsection (1). (3) The State Load Despatch Centre shall comply with the directions of the Regional Load Despatch Centre. B. Role of SLDCs (contd..):-

27. Compliance of Directions of SLDCs (contd..) (4) If any dispute arises with reference to the quality of electricity or safe, secure and integrated operation of the State grid or in relation to any direction given under sub-section (1), it shall be referred to the State Commission for decision: Provided that pending the decision of the State Commission, the direction of the State Load Despatch Centre shall be complied with by the licensee or generating company. (5) If any licensee, generating company or any other person fails to comply with the directions issued under sub-section(1), he shall be liable to penalty not exceeding rupees five lacs. B. Role of SLDCs (contd..):-

28. C. Role of CTU :- Functions of CTU  to undertake transmission of electricity through inter-State transmission system; (b) to discharge all functions of planning and co-ordination relating to inter-state transmission system with - (i) State Transmission Utilities; (ii) Central Government; (iii) State Governments; (iv) generating companies; (v) Regional Power Committees; (vi) Authority; (vii) licensees; (viii) any other person notified by the Central Government in this behalf; Continued ….. (EXTRACTS FROM ‘ THE ELECTRICITY ACT, 2003 ’ )

29. C. Role of CTU (contd..):- Functions of CTU (contd..) (c) to ensure development of an efficient, co-ordinated and economical system of inter-State transmission lines for smooth flow of electricity from generating stations to the load centres; (d) to provide non-discriminatory open access to its transmission system for use by-  any licensee or generating company on payment of the transmission charges; or (ii) any consumer as and when such open access is provided by the State Commission under sub-section (2) of section 42, on payment of the transmission charges and a surcharge thereon, as may be specified by the Central Commission:

30. D. Role of STU :- Functions of STUs (a) to undertake transmission of electricity through intra-State transmission system; (b) to discharge all functions of planning and co-ordination relating to intra-state transmission system with - (i) Central Transmission Utility; (ii) State Governments; (iii) generating companies; (iv) Regional Power Committees; (v) Authority; (vi) licensees; (vii) any other person notified by the State Government in this behalf; Continued ….. (EXTRACTS FROM ‘ THE ELECTRICITY ACT, 2003 ’ )

31. D. Role of STU (contd..):- Functions of STUs (contd..) (c) to ensure development of an efficient, co-ordinated and economical system of intra-State transmission lines for smooth flow of electricity from a generating station to the load centres; (d) to provid non-discriminatory open access to its transmission system for use by-  any licensee or generating company on payment of the transmission charges ; or (ii) any consumer as and when such open access is provided by the State Commission under sub-section (2) of section 42, on payment of the transmission charges and a surcharge thereon, as may be specified by the State Commission:

32. E.Role of CEA :- Subject to regulations made under the ERC Act,1998 by the Central Commission in the case of RLDCs and the State Commission in case of SLDCs, any dispute with reference to the operation of the Power System including grid operation and as to whether any directions issued by RLDC under subsection 55(3) or 55(4) of the amended ES Act, 1948 (sections 29(1) and 33(1) of the Electricity Act 2003) is reasonable or not, shall be referred to the Authority for decision. Provided that pending the decision of the Authority, the directions of the RLDC or the SLDCs, as the case may be, shall be complied with.

33.  Specify principles, procedures and criteria which shall be used in development of ISTS.  Promote coordination amongst all regional constituents in any development of ISTS.  Provide methodology for information exchange amongst regional constituents in planning and development of ISTS. CHAPTER – 3 PLANNING CODE FOR ISTS Objectives :- Scope :-  Applicable to all utilities using the ISTS and involved in its development.

34.  CEA to develop and update perspective transmission plan (10-15 yrs) for ISTS as well as Intra - State.  CTU to develop annually Five Year Plans fitting into the above perspective plan.  System strengthening schemes to be identified additionally by CTU in consultation with CEA.  ISTS proposals to be discussed, reviewed and finalised in the meeting of the ‘Standing Committee for Transmission System Planning' constituted by CEA for each Region. CHAPTER – 3 PLANNING CODE FOR ISTS Planning Methodology :-

35.  CTU Five Year Plan to be finalised by 30th September each year comprising interalia additional equipment such as ICTs, Capacitors, Ractors etc. Schemes open for private investors. Action taken and progress of schemes. STUs should plan their system based on the CTU 5 Year Plan. CHAPTER – 3 PLANNING CODE FOR ISTS Planning Methodology :-

36. ISTS shall be capable of withstanding and be secured against the following outages without necessitating load shedding or rescheduling of generation during steady state operation. 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 O utage of a single ICT CHAPTER – 3 PLANNING CODE FOR ISTS Planning Criteria :- Continued …..

37. CHAPTER – 3 PLANNING CODE FOR ISTS Planning Criteria :- or Outage of one pole of HVDC bipole or Outage of 765 kV S/C line The aforesaid contingencies would be superimposed over a planned outage of another 220 kV D/C line or 400 kV S/C line in another corridor and not emanating from the same sub-station. ISTS shall be capable of withstanding the loss of most severe single system infeed without loss of stability.

38. CHAPTER – 3 PLANNING CODE FOR ISTS Planning Criteria :- ANY ONE OF THE AFORESAID EVENTS SHALL NOT CAUSE o loss of supply o abnormal frequency on sustained basis o unacceptable high or low voltage o system instability o unacceptable overloading of ISTS elements

39. SEBs/ Utilities/ MPPs/ ISGS/ IPPs to supply standard planning data to CTU by 31st March every year in formats as approved by CERC in August 2001 CHAPTER – 3 PLANNING CODE FOR ISTS Planning Data :-

40. Connection conditions specify the minimum technical and design criteria to be complied with by CTU and any agency connected to or seeking connection to ISTS. CHAPTER – 4 CONNECTION CONDITION Objectives :-  Basic rules for connections are complied with to treat all agencies in a non-discriminatory manner.  No adverse effects on the new equipment connected to ISTS, the ISTS and other agency’s system. Continued …..

41. CHAPTER – 4 CONNECTION CONDITION Objectives :-  Clear identification of ownership and responsibility for all equipment at the connection point. Scope :- A pplicable to all constituents and agencies connected to and involved in developing the ISTS.

42. CHAPTER – 4 CONNECTION CONDITION For Existing Connections :- Agreement should be in place within one year i.e. by 01.04.2003. In case of a delay in finalising the connection conditions, constituent to approach CERC with a petition along with CTU’s recommendation/comments. Cost of modification, if any, shall be borne by concerned constituent. For New Connections :- C onnection Agreement is a must.

43. CHAPTER – 4 CONNECTION CONDITION CONNECTION AGREEMENT WOULD INCLUDE :-  A condition requiring both parties to comply with the IEGC.  Details of connection, technical requirements and commercial arrangements.  Details of any capital expenditure arising from reinforcements required, if any.  Site Responsibility Schedule.  General philosophy, guidelines etc. on protection.

44. CHAPTER – 4 CONNECTION CONDITION RELEVANT AREAS IN CONNECTION CONDITIONS :- ISTS parameter variations Substation equipment Fault Clearance Times Generating Units and Power Stations Reactive Power Compensation Communication Facilities System Recording Instruments Responsibilities for operational safety Procedure for site access, site operational activities and maintenance standards

45. CHAPTER – 4 CONNECTION CONDITION SCHEDULE OF ASSETS OF REGIONAL GRID :- CTU shall submit annually to CERC by 30 th September each year a schedule of transmission assets which constitute the regional grid as on 31 st March of that year indicating ownership on which RLDC has operational control and responsibility

46. CHAPTER – 5 GRANT OF TRANSMISSION LICENCE Separate regulations by CERC would govern the grant of transmission license. This chapter shall not be subject to review by the IEGC Review Panel.

47. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS COVERING Operational policy System security aspects Demand estimation Demand control Periodic reports Operational liasion Outage planning Recovery procedures Event information

48. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS OPERATIONAL POLICY :-  Primary objective of integrated operation is to enhance the overall operational economy and reliability of the entire network.  RLDC shall supervise overall real time operation of the regional code.  Regional constituents shall comply with this operating code.

49. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS OPERATIONAL POLICY :-  Detailed internal operating procedures consistent with IEGC to be developed and maintained by each RLDC.  Qualified and adequately trained personnel at all locations.

50. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- All regional constituents shall endeavor to operate their systems in synchronism with each other at all times. Deliberate isolation of any part of the grid should be done only under a grave emergency or when specifically instructed by RLDC. In case of such isolation, synchronisation of the isolated system to be done at the earliest.

51. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Removal of any trunk element from service to be done only on RLDC's instructions. Any such operations under emergency situation to be informed to RLDC at the earliest. Trippings of trunk elements to be informed to RLDC as soon as possible, say within ten minutes of the event with reason (to the extent determined) and likely time of restoration.

52. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Governors, with 3 to 6% droop setting, to be in normal operation on all generating units irrespective of ownership, type & size. Any deviation for units > 50 mw size to be informed to RLDC along with reason and duration of such operation. Suppression of normal governor action, dead band, time delays introduced through other control features not to be resorted to.

53. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- All generating units shall normally be capable of picking up 5% extra load instantaneously (at least up to 105% MCR) for at least five minutes when frequency falls due to any contingency. RLDC’s approval required for any unit > 50 MW kept in operation without this requirement. Recommended rate for decrease or increase of generation through supplementary control is 1.0% per minute or as per manufacturer’s limits. Faster pick up possible if frequency falls below 49.5 Hz.

54. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Reduction in generation / increase in load by 100 MW and above suddenly would not be permitted without prior intimation to and consent of the RLDC. AVRs on all generating units to be in service and PSS (wherever provided) to be properly tuned as per the plan of CTU. CTU will be allowed to carry out tuning / checking of PSS wherever considered necessary.

55. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Provision of protection and relay settings to be coordinated periodically by the protection committee of the REB. Constituents to endeavor operation of system between 49.0 - 50.5 Hz, the frequency range within which all steam turbines conforming to IEC standards can safely operate.

56. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- All regional constituents to provide automatic under frequency relay load-shedding in their respective systems as finalised by REB. Constituents to ensure that the scheme is functional. No u/f relay to be bypassed without RLDC's prior consent, who shall also promptly inform REB about the locations where these relays are temporarily out. Periodic inspection of u/f relays to be done by REBs who shall also maintain proper records of such inspection.

57. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- Procedures to recover from partial / total collapse of the grid to be developed and followed by all constituents. Adequate and reliable communication facility internally and with other constituents / RLDC to be provided by all constituents.

58. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS SYSTEM SECURITY ASPECTS :- All regional constituents shall send all information / data, including DR/SER output, to RLDC for analysis of any grid disturbance / event. Access by RLDC to such information should not be blocked by any constituent. Grid voltage should always be maintained within the operating range NOMINAL(kV)MAX. (kV)MIN. (kV) 400420360 220245200 132145120

59. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS DEMAND ESTIMATION (Daily/Weekly/Monthly/Annually) DEMAND CONTROL (including manual disconnection) Continued …..

60. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS PERIODIC REPORTS Weekly report shall be issued by RLDC to all constituents and REB Secretariat covering for the past week Frequency profile Voltage profile Major generation and transmission outages Transmission constraints Instances of persistent / significant non - compliance of IEGC. Continued …..

61. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS OTHER REPORTS RLDC to prepare quarterly report, bringing out System constraints Reduction in security standards & quality of service and reasons thereof. Actions taken by different agencies Agencies responsible for constraints as above.

62. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS OPERATIONAL LIASION PROCEDURE :- To facilitate quick transfer of information between operational staff so as to correlate the required inputs for optimisation of decision making and actions.

63. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS OBJECTIVE OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID To produce a coordinated Generation Outage Programme for the Regional Grid considering all available resources and constraints. To minimise surplus or deficits, if any, in the system requirement of power and energy and operate system within security standards.

64. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS OUTAGE PLANNING PROCESS OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID All SEBs/STUs, CTU, ISGS to provide REB Secreteriat their proposed outage programme of all elements in writing for the next financial year by 30 th November each year. Draft outage programme by 31 st December to be brought out by REBSecreteriat. Continued …..

65. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS OUTAGE PLANNING PROCESS OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID Final outage programme ready by 31 st January latest or as mutually decided in REB coordination meeting. This programme to be intimated to all regional constituents / RLDC. Above annual programme to be reviewed on quarterly and monthly basis by REB Secreteriat. Continued …..

66. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS OUTAGE PLANNING PROCESS OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID Final approval required from RLDC prior to availing an outage. RLDC authorised to defer the planned outage in case of  Major grid disturbance  System isolation  Black out in a constituent state  Any other event affecting system security

67. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS RECOVERY PROCEDURES Detailed plans & procedures for restoration of the Grid to be developed by RLDC in consultation with all regional constituents / REB Secreteriat and to be reviewed / updated annually. Restoration within the system of each constituent to be finalised by concerned constituent in co-ordination with RLDC. To be reviewed once every year. Continued …..

68. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS RECOVERY PROCEDURES List of Generating Stations with black start facility, inter-state / inter-regional ties, synchronising points and essential loads to be restored on priority to be prepared and to be available with RLDCs. For fast recovery, RLDC authorised to operate system with reduced security standards for voltage and frequency. Continued …..

69. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS RECOVERY PROCEDURES All communication channels required for restoration process shall be used for operational communication only, till grid normalcy is restored.

70. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS EVENT INFORMATION Violation of security standards Grid indiscipline Non-compliance of RLDC's instructions System islanding/system split Region black out/partial black out Protection failure on any element of ISTS, and on any item on the 'agreed list' of the intra - state systems Power system instability Tripping of any element of the regional grid REPORTABLE EVENTS BY RLDC/ REGIONAL CONSTITUENTS

71. CHAPTER – 6 OPERATIONAL CODE FOR REGIONAL GRIDS FORM OF WRITTEN REPORTS Time and date of event Location Plant and / or equipment directly involved Description and cause of event Antecedent conditions Demand and / or generation (in MW) interrupted and its duration All relevant system data including copies of all DR/EL/DAS outputs Sequence of trippings with time Details of relay flags Remedial measures

72. CHAPTER – 7 SCHEDULING AND DESPATCH CODE COVERING Objective Scope Demarcation of responsibilities Scheduling & Despatch procedure Reactive Power and Voltage Control ANNEX  Complementary Commercial Mechanism  Metering Details (to be included later)

73. CHAPTER – 7 SCHEDULING AND DESPATCH CODE OBJECTIVE :- To enable RLDCs to prepare the despatch schedule for each beneficiary. It also provides methodology of issuing real time despatch / drawal instructions and rescheduling, if required, as also commercial arrangement for the deviations from schedules and mechanism for reactive power pricing.

74. CHAPTER – 7 SCHEDULING AND DESPATCH CODE SCOPE :- Applicable to RLDC / SLDCs, ISGS, SEBs / STUs and other beneficiaries in the Grid. P rocedure for the generating stations of BBMB shall be separately formulated by NRLDC in consultation with BBMB.

75. CHAPTER – 7 SCHEDULING AND DESPATCH CODE DEMARCATION OF RESPONSIBILITIES :- Regional grid shall be operated as loose power pools with states having full operational autonomy. System of each state shall be treated as a notional control area. States shall generally be expected to maintain their actual drawal from the Regional Grid close to the net drawal schedule (sum of scheduled drawal from ISGS and any bilateral inter change).

76. CHAPTER – 7 SCHEDULING AND DESPATCH CODE DEMARCATION OF RESPONSIBILITIES :- Tight control on the deviations from schedule by states not mandated due to non availability of requisite facilities for minute – to - minute on line regulation of drawals. Deviations from schedule to be priced appropriately. Whenever system frequency is below 49.5 Hz, states shall endeavor to restrict their net drawal to within the schedule. Loadshedding to be resorted to in case frequency < 49.0 Hz.

77. CHAPTER – 7 SCHEDULING AND DESPATCH CODE DEMARCATION OF RESPONSIBILITIES :- SLDCs / STUs to carry out short - term and long - term demand estimation to enable advance planning to meet the consumer’s load without overdrawing. ISGS shall be responsible for generating as per the daily schedule advised by RLDC. ISGS allowed to deviate from the schedule, in line with the flexibility allowed to States. Deviations are to be appropriately priced.

78. CHAPTER – 7 SCHEDULING AND DESPATCH CODE DEMARCATION OF RESPONSIBILITIES :- W henever system frequency > 50.3 Hz, actual net injection of ISGS should not exceed scheduled despatch. RLDC nay direct the SLDCs / ISGS to increase / decrease their drawal / generation in case of contingencies and such directions shall be immediately complied. Outage of Generation and Transmission system to be coordinated through OCC / RLDC. Outage requiring restriction on ISGS generation to be planned carefully.

79. CHAPTER – 7 SCHEDULING AND DESPATCH CODE DEMARCATION OF RESPONSIBILITIES :- Agreements between constituents and ISGS indicating shares, drawal pattern, tariffs, payment terms etc. to be filed with RLDCs and REB Secreteriats for being considered in REA. Similar filing required in respect of bilateral agreements. Frequency linked despatch guidelines, as issued by RLDC, should be followed by all constituents unless otherwise advised by RLDC.

80. CHAPTER – 7 SCHEDULING AND DESPATCH CODE DEMARCATION OF RESPONSIBILITIES :- ISGS to declare plant capabilities faithfully and avoid gaming. RLDC may ask the ISGS to explain instances of gaming, if any, with necessary backup data. CTU would be allowed to install Special Energy Meters on all Inter-Utility Exchange Points and the constituents would extend the necessary assistance to CTU in timely collection of metered data.

81. CHAPTER – 7 SCHEDULING AND DESPATCH CODE DEMARCATION OF RESPONSIBILITIES :- RLDC to compute  Actual Net Injection of each ISGS  Actual Net Drawal of each beneficiary based on above meter readings and forward the same to REB Secreteriat on weekly basis by each Thursday noon for the seven day period ending previous Sunday Mid-Night.

82. CHAPTER – 7 SCHEDULING AND DESPATCH CODE DEMARCATION OF RESPONSIBILITIES :- Computations of RLDC open to checking / verification by constituents for 20 days. In case any mistake / omission is detected, the RLDC shall forthwith make a complete check and rectify the same.

83. SCHEDULING AND DESPATCH PROCEDURE By 10.00 hrs.Each ISGS advises RLDC of its Ex-Power Plant MW and MWh capabilities anticipated for next day i.e. 00:00 to 24:00 hrs By 1100 Hrs.Beneficiaries advised of above information along with their entitlements By 1500 hrs.SLDCs advise RLDC their drawal schedule for each of the ISGS in which they have share By 1700 hrs.RLDC conveys the ‘Ex-Power Plant Despatch Schedule (in MW)' to each ISGS and ‘Net Drawal Schedule (in MW)' to each beneficiary (after deducting transmission losses) By 2200 hrs.*ISGSs / States / Beneficiaries shall inform the modifications, if any, for incorporating in the final schedule By 2300 hrs.RLDC shall issue the final despatch and drawal schedule. * Since issuing the final despatch and drawal schedule is a critical activity and considerable time is involved in its preparation and carrying out requisite moderation, if any, it is desirable that this activity is completed by 2100 hrs. All ISGS stations with capacities and allocated shares to be listed out CHAPTER – 7 SCHEDULING AND DESPATCH CODE

84. SCHEDULING AND DESPATCH PROCEDURE :- RLDC to ensure schedules are operationally reasonable with respect to ramping up / ramping down rates and the minimum to maximum ratio of generation. ISGS / SLDCs to inform any modifications in foreseen capability / station wise drawal schedule to RLDC by 2200 hrs. RLDC to issue final schedule in such cases by 2300 hrs. Revisions in schedule permitted during the course of the day. Such revisions effective one hour after the first advise is received by the RLDC.

85. CHAPTER – 7 SCHEDULING AND DESPATCH CODE SCHEDULING AND DESPATCH PROCEDURE :- RLDC to check for transmission constraints, if any, before finalising the drawal / despatch schedule. O n completion of the operating day, schedule, as finally implemented during the day shall be issued by RLDC. This would be the datum for commercial accounting. RLDC to properly document all the above information exchanged between ISGS and RLDC, constituents and RLDC etc.

86. CHAPTER – 7 SCHEDULING AND DESPATCH CODE SCHEDULING AND DESPATCH PROCEDURE :- All records in respect of above open to all constituents for any checking / verification for a period of 20 days.

87. CHAPTER – 7 SCHEDULING AND DESPATCH CODE REACTIVE POWER AND VOLTAGE CONTROL :- Beneficiaries to provide local VAR compensation / generation so as not to draw VARs from EHV grid. Tight control not being insisted upon presently. However, VAR pricing for beneficiaries would be as under : pay for VAR drawal at points where voltage < 97% get paid for VAR return at points where voltage < 97% get paid for VAR drawal at points where voltage > 103% pay for VAR return at points where voltage > 103%

88. CHAPTER – 7 SCHEDULING AND DESPATCH CODE REACTIVE POWER AND VOLTAGE CONTROL :- Charges / payments for VARs - 4 paise/kVARh upto 31st March, 2001 and escalated at 5% per year thereafter unless otherwise revised by CERC. RLDC may direct a beneficiary to curtail its VAR drawal / injection in case of threat to equipment safety / grid security. Switching IN / OUT of Bus / Line Reactors of 400 kV lines and tap changing of 400 / 220 kV ICTs to be done as per RLDC instructions only.

89. CHAPTER – 7 SCHEDULING AND DESPATCH CODE REACTIVE POWER AND VOLTAGE CONTROL :- ISGS to generate / absorb Reactive Power as per RLDC instructions taking into account capability limits and without sacrificing active generation required. No payments to generating companies for such VAR generation / absorption.

90. CHAPTER – 7 SCHEDULING AND DESPATCH CODE COMPLEMENTARY COMMERCIAL MECHANISMS :- Payments to ISGS from beneficiaries :  Capacity charge based on declared (before the fact) ex-power plant capability and entitlement of beneficiary  Energy charge (rupees per MWh) based on schedule drawals Payments to / from UI settlement system based on Unscheduled Interchange (UI) and frequency.

91. CHAPTER – 7 SCHEDULING AND DESPATCH CODE COMPLEMENTARY COMMERCIAL MECHANISMS :- REA to be prepared by REB Secreteriat on weekly basis based on Special Energy Meter (SEM) data provided by RLDCs. Weekly bills for UI and Reactive Exchanges to be raised by REB Secreteriat. These bills to have higher priority.

92. CHAPTER – 8 MANAGEMENT OF IEGC OBJECTIVES :- Methodology of managing the IEGC document, pursuing of any change / modifications required and constituents responsibility to effect that change.

93. CHAPTER – 8 MANAGEMENT OF IEGC SCOPE :- CTU responsible for coordinating, managing and servicing the IEGC document IEGC Review Panel to consider proposals for modifications Decision of review panel to be put upto CERC

94. CHAPTER – 8 MANAGEMENT OF IEGC IEGC REVIEW PANEL :- To be constituted by CERC comprising one representative from 01.CEA 02.NTPC 03.NHPC 04.NPC 05.Two from each REB representing the constituents 06.PTC 07.One representative from Mega Power Projects 08.One representative from Railways / Steel / Coal 09.One representative from CII / FICCI / ASSOCHAM 10.One representative from CERC as an observer

95. CHAPTER – 8 MANAGEMENT OF IEGC IEGC REVIEW PANEL :- Director (Operations), POWERGRID shall be the Chairman and Convener of the Panel and preside over its meetings.

96. Thank You