Electricity is really just organized lightning. - George Carlin

1

Plan for DiscussionFocus on IEGC Provisions related to SLDCs ,

RLDCs and NLDCWhat is IEGC

Historical BackgroundContents of IEGC

Brief Description of Provisions

Non-Compliance of IEGCImplementation Issues

Way Forward

2

WHAT IS GRID CODEThe Indian Electricity Grid Code (IEGC) is a

Regulation made by the Central Commission in exercise of powers under clause (h) of sub-section (1) of Section 79 read with clause (g) of sub-section (2) of Section 178 of the Act.

IEGC lays down the rules, guidelines and standards to be followed by various persons and participants in the system to plan, develop, maintain and operate the power system, in the most secure, reliable, economic and efficient manner, while facilitating healthy competition in the generation and supply of electricity.

3

Regulation -What and Why Regulation is "controlling human or societal

behaviour by rules or restrictions." Regulation can take many forms: legal restrictions promulgated by a government authority, self-regulation by an industry such as through a trade association, social regulation (e.g. norms), co-regulation and market regulation.

One can consider regulation as actions of conduct imposing sanctions (such as a fine). This action of administrative law, or implementing regulatory law, may be contrasted with statutory or case law

Regulations can be seen as implementation artefacts of policy statements.

4

Historical BackgroundIEGC, 2000CTU prepared this Grid Code in pursuance of

CERC directions issued, on 31st March, 1999, Became effective from 1st Feb,2000 through an

ordder by CERC. A document of CTU, approved by CERC. Main objective - to bring discipline in the

operation of the ISTS so as to enable power to flow at an optimum level while maintaining good quality.

Violations were to be treated as violations of the Commission's orders and subject to penalties.

5

Historical Background---Contd.IEGC, 2006

As per Electricity Act 2003, (the Act) ,which came into force from 10. 6.2003, one of the functions assigned to the Commission under sub-section (1) of Section 79 the Act of was to specify Grid Code having regard to Grid Standards.

Pending finalization of the Grid Standards by CEA ,IEGC was notified by CERC on 14.03.2006, which came into effect from 01.04.2006.

Addition of a new chapter on “Inter-regional Energy Exchanges”

Deletion of Chapter on “Management of IEGC” SLDCs were assigned more responsibilities. REA and UI Account were to be issued by RLDCs in stead of

REBs (RPCs) , which was reversed by first amendment in IEGC,2006, notified on 22.08.2006, and the responsibility of REA and UI accounts was again assigned to REBs.

6

Historical Background---Contd.Amendments in IEGC,2006

Amendments in IEGC,2006 were made vide notification dated 11.12.2006, 18.04.2007 , 11.09.2008 and 30.03.2009. The most comprehensive were that of 30.03.2009.

Narrowing down of frequency range from 49.0-50.5 Hz. to 49.2-50.3 Hz.

Provisions related to NLDC. Provisions related to scheduling from Tariff Regulations 2004-09Defining control area jurisdiction of RLDC and SLDC.  Scheduling of Collective Transaction after operationalisation of

Power Exchanges.Aligning IEGC with CEA and CERC Regulations specially- with

CEA Connectivity Standards and CERC UI Regulations.Omission of Chapter 7 and Annex-2 of Chapter 6

7

Historical Background---Contd.

IEGC,2010The new Regulation on IEGC i.e. Central

Electricity Regulatory Commission (Indian Electricity Grid Code) Regulations, 2010 were notified by CERC on 28.04.2010

Became effective from 03.05.2010. These regulations superseded IEGC,2006. One amendment in these regulations vide

notification dated 05.03.2012 has been madeAmendment was to be made effective from

02.04.2012 , but actually got implemented w.e.f 17.09.2012, due to court case.

8

Key Features of IEGC,2010Focus on Renewable integration, Grid Discipline,

Coherence with other Regulations, Market development, Multiple players with multiple Contracts,

Forecasting, Scheduling of Wind & SolarDeviation Settlement -RRF MechanismTightening of frequency band ‘49.2- 50.3 Hz.’ to ‘49.5

- 50.2 Hz’. Alignment with various RegulationsControl Area Jurisdiction -RedefinedStricter provisions for Grid disciplineAutomatic Demand Management schemes and

Contingency Procedures.9

Legal Provisions in the Act,2003Section 79 (1) (h) - CERC entrusted with the

function of specifying Grid Code having regard to Grid Standards, specified by CEA.

Section 178 (g) – CERC empowered to specify Grid Code under sub-section (2) of section 28.

Sub-section (2) of section 28- RLDC 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.

Section 86 (1) (h) - State Grid Code specified by SERC should be consistent with IEGC

10

ISGS

“Inter-State Generating Station (ISGS)” means a Central generating station or other generating station, in which two or more states have Shares;

“Share” means percentage share of a beneficiary in an ISGS either notified by Government of India or agreed through contracts and implemented through long term access;

11

ISTS“Inter-State Transmission System (ISTS)”

includes i) Any system for the conveyance of electricity by

means of a main transmission line from the territory of one State to another State

ii) The conveyance of electricity across the territory of an intervening State as well as conveyance within the State which is incidental to such inter-state transmission of energy

(iii) The transmission of electricity within the territory of State on a system built, owned, operated, maintained or controlled by CTU;

12

Contents

Part - 1 :General – Objective, Scope, Compliance etc.

Part - 2 :Role of various organizations and their linkages

Part - 3 :Planning Code for Inter - State Transmission

Part - 4 :Connection Code Part - 5 :Operating Code Part - 6 :Scheduling and Despatch Code Part - 7 :Miscellaneous

13

OBJECTIVETo brings together a single set of technical and commercial rules, encompassing all the Utilities connected to/or using ISTS and provide :

• Documentation of the principles and procedures which define the relationship between the various Users of the inter-State transmission system (ISTS), National Load Despatch Centre, as well as the Regional and State Load Despatch Centers

• Facilitation of the optimal operation of the grid, facilitation of coordinated and optimal maintenance planning of generation and transmission facilities in the grid and facilitation of development and planning of economic and reliable National / Regional Grid

• Facilitation for functioning of power markets and ancillary services by defining a common basis of operation of the ISTS, applicable to all the Users of the ISTS.

• Facilitation of the development of renewable energy sources by specifying the technical and commercial aspects for integration of these resources into the grid.

14

SCOPEAllUsers, SLDCs, RLDCs, NLDC, CEA, CTU, STUs, licensees,

RPCs and Power Exchanges.“User” - a person such as a Generating Company including

Captive Generating Plant or Transmission Licensee ( other than the Central Transmission Utility and State Transmission utility) or Distribution Licensee or Bulk Consumer, whose electrical plant is connected to the ISTS at a voltage level 33kV and above.

DVC - similar to a SEB, with its own SLDC at Maithon. BBMB and SSP - intra-State generating stations,

though their transmission systems a part of the ISTS. Scheduling and despatch of BBMB/ SSP generation -

by BBMB/ Narmada Control Authority (NCA), in coordination with the respective RLDC and the beneficiaries.

15

Compliance of IEGC,2010o Mainly RLDCs to report non-compliance to CERC for

taking action against defaulting person, in accordance with provisions of the Act.- A number of Petitions Filed

o In case of non-compliance by NLDC, RLDC, RPC, SLDC and by any other person, the non-compliance may be reported to CERC by any person through petition.

o RLDC to report to the Commission instances of serious or repeated violation of any of the provisions of the IEGC and incidences of persistent non-compliance of the directions of the RLDCs issued in order to exercise supervision and control required for ensuring stability of grid operations and for achieving the maximum economy and efficiency in the operation of the power system in the region under its control.

o  16

IEGC Compliance-Cont.Compliance Oversight (Earlier Non-

Compliance)Role of RPC and RLDC reversed based on

past experience and legal cases.Earlier RPC was assigned task of reporting to

Commission cases of Grid discipline violation, but due to their constitution and consensus based deliberation ,no case was reported in past.

Now this shall be primarily responsibility of RLDCs to report serious /repeated violation.

17

Compliance of IEGC,2010 -- - Contd.o The Regional Power Committee (RPC) in the region

has to continuously monitor the instances of non-compliance of the provisions of IEGC and try to sort out all operational issues and deliberate on the ways in which such cases of non-compliance are prevented in future by building consensus. The Member Secretary, RPC may also report any issue that cannot be sorted out at the RPC forum to the Commission. - No Report Till Date

o The Commission may initiate appropriate proceedings upon receipt of report of RPCs or RLDCs. The Commission, may also take suo-motu action against any person, in case of non-compliance of any of the provisions of the IEGC.

18

Compliance of IEGC,2010 -- - Contd.o The cases of non-compliance of IEGC are normally

undertaken by CERC under section 142 of the Act. o A number of cases of non-compliance of IEGC have

been taken up by CERC under suo-motu proceedings or after reporting by RLDCs.

o Till now , most of the cases had been related to grid indiscipline and penalty up to about Rs. 4.5 Crores were imposed in many cases.

o The cases of non-compliance of RLDC directions are normally dealt under section 29 & 143 of the Act.

o Penalties up to several Lakhs of Rupees, in the adjudication cases under section 29 &143 of the Act, had also been imposed by the Commission.

19

INDICATIE LIST OF PROCEEDINGS BY CERC UNDER SECTION 142 OF ELECTRICITY ACT, 2003

Petition No. Date of order Respondents Penalty Amount (in Rs.)145/2006 17.11.2006 APTRANSCO, KTPCL, TNEB, KSEB, , , NLC, NTPC -

14/2007 13.2.2007 UPPCL, HVPNL, PDD, J K, PSEB, RRVPN, DTL, GUVNL, MSEDCL, CSEB, MPSEB, APTRANSCO, KPTCL

-

89/2008 4.9.2008 APTRANSCO, KTPCL, TNEB, KSEB, , , NLC, NTPC -

137/2008 31.12.2008 TNEB 1 lakh

152/2008 9.1.2009 UPPCL 1 lakh

25/2006 9.5.2006 UPPCL 1 lakh

52/2009 6.5.2009 KPTCL 17 lakh

59/2009 5.5.2009 RRVPNL 5 lakh

80/2009 11.5.2009 APTRANSCO 1.22 crore

81/2009 8.5.2009 TNEB 1.5 crore

105/2009 21.8.2009 UPPCL 2.57 crore

106/2009 & 130/2009

21.8.2009 Tamil Nadu Electricity Board, Chennai 4.37 crore

137/2009 30.10.2009 UPPCL 4.62 Crore151/2009 30.11.2009 DTL (SLDC) 25,000/-

107/2010 30.3.2010 TNEB -080/2009 11.5.2009 APTRANSCO ---081/2009 8.5.2009 TNEB ---133/2010 3.2.2010 Tamil Nadu Electricity Board, Chennai ----

20

INDICATIVE LIST OF PROCEEDINGS BY CERC UNDER SECTION 29 and 143 OF ELECTRICITY ACT,2003 Petition No. Date of order Respondents Penalty Amount

(in Rs.)Adj Case No. 1/2006 25.10.2006 UPPCL 1 lakh.

Adj Case No. 5/2009 14.10.2009 UPPCL 1.75 Crore.

Adj. case No. 1/2009 8.5.2009 SLDC, 2.5 lakh.

Adj case No. 2/2009 8.5.2009 SLDC, 3.00 lakh.

Adj case No. 3/2009 8.5.2009 SLDC, Jammu & Kashmir 2.00 lakh

Adj case No. 4/2009 8.5.2009 SLDC, Rajasthan 1.00 lakh.

Adj. Case No. 5/2009 14.10.2009 UPPCL 1.75 croreAdj. Case No. 1/2010 21.9.2010 TNEB No penalty imposed.

Adj. Case No. 2/2010 25.2.2011 UPPCL 16 lakh

Adj. Case No. 3/2010 25.2.2011 HVPNL 8.00 lakh

Adj. Case No. 4/2010 25.2.2011 RRVPNL 4.00 lakh

Adj. Case No. 5/2010 25.2.2011 PTL, Uttarakhand 9.00 lakh

Adj. Case No. 7/2010 25.2.2011 Power Department Govt. of J&K. 6.00 lakh

21

Role of NLDC According to notification dated 2nd March 2005, by

the Ministry of Power, Government of India, under Section 26(2) of the Act, NLDC is the apex body to ensure integrated operation of the national power system.

NLDC is the nodal agency for collective transactions.NLDC would act as the Central control room in case

of natural & man made emergency/disaster where it affects the power system operation.

Any other function as may be assigned by the Commission by order or regulations from time to time – Implementing Agency for REC, RRF, PoC Charges, PSDF Management.

22

Role of RLDCFunction under sections 28 and 29 of Electricity Act, 2003.Apex body to ensure integrated operation of the power system

in the concerned region.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;

monitor grid operations;keep accounts of quantity of electricity transmitted through

the regional grid;exercise supervision and control over the Inter-State

transmission systemresponsible 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.

23

Role of RLDC -- - Contd.Exclusive functions of RLDCs

System operation and control including inter-state transfer of power, covering contingency analysis and operational planning on real time basis;

Scheduling / re-scheduling of generation;System restoration following grid disturbances;Meter data processing;Compiling and furnishing data pertaining to system

operation;Operation of regional UI pool account, regional

reactive energy account and Congestion Charge Account

Operation of ancillary services 24

Role of SLDC ( Reg-2.7.1)In accordance with section 32 of Electricity Act, 2003 : (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 -(a) 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;(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.

25

Role of SLDC2.7.1

Role of SLDC2.7.2- In accordance with section 33 of the Electricity Act,2003

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. Every licensee, generating company, generating station, sub-station and any other person connected with the operation of the power system shall comply with the directions issued by the State Load Depatch Centre under sub-section (1) of Section 33 of the Electricity Act,2003. The State Load Despatch Centre shall comply with the directions of the Regional Load Despatch Centre. .

26

Role of SLDC2.7.1

Role of SLDC

2.7.3 - In case of inter-state bilateral and collective short-term open access transactions having a state utility or an intra-state entity as a buyer or a seller, SLDC shall accord concurrence or no objection or a prior standing clearance, as the case may be, in accordance with the Central Electricity Regulatory Commission (Open Access in inter-state Transmission) Regulations,2008 , amended from time to time.

27

Role of CTUSection 38 of Electricity Act, 2003undertake transmission of electricity through inter-State transmission system; discharge all functions of planning and co-ordination relating to inter-State transmission system withdifferent agenciesensure 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 centers provide non-discriminatory open access to its transmission system for use by any licensee or generating company on payment of the transmission charges; or any consumer.

28

Role of CTU- - - - Contd.Ministry of Power vide its notification dated

27.9.2010 notified that POSOCO shall operate the five Regional Load Despatch Centres (RLDCs) and the National Load Despatch Centre (NLDC) w.e.f. 1.10.2010.

Presently, POSOCO is a subsidiary of Power Grid. CTU can not engage in the business of

generation of electricity or trading in electricity. In case of Inter-state Transmission System,

Central Transmission Utility shall be the nodal agency for the connectivity, long-term access and medium –term open access .

29

Role of STUSection 39 of Electricity Act, 2003undertake transmission of electricity through intra-State transmission system; discharge all functions of planning and co-ordination relating to intra-State transmission system withdifferent agenciesensure development of an efficient, co-ordinated and economical system of intra-State transmission lines for smooth flow of electricity from generating stations to the load centers provide non-discriminatory open access to its transmission system for use by any licensee or generating company on payment of the transmission charges; or any consumer.

30

Role of STU- Contd.

Until a Government company or any authority or corporation is notified by the State Government, the State Transmission Utility shall operate the State Load Despatch Centre.

31

Part-3 PLANNING CODE

CEA would formulate perspective transmission plan for inter -State transmission system as well as intra-State transmission system.

In formulating perspective transmission plan the transmission requirement for evacuating power from renewable energy sources shall also be taken care of. The transmission system required for open access shall also be taken into account in accordance with National Electricity Policy so that congestion in system operation is minimized.

32

Part-3 PLANNING CODETask force for integration of renewable into Grid

indicated that N-1 contingency planning for renewable shall be uneconomical and CEA must take need of renewable while planning nearby transmission system .

Also earlier planning based on Associated generating station Tr system, now open access has increased upto 20% , and many times congestion is being experienced in power market operation as well as real time operation.

33

Part-3 PLANNING CODE

The CTU shall carry out planning process from time to time as per the requirement for identification of inter-State transmission system including transmission system associated with Generation Projects, regional and inter-regional system strengthening schemes which shall fit in with the perspective plan developed by CEA.

34

Part-3 PLANNING CODECTU during planning shallconsider following :i) Perspective plan formulated by CEA.ii) Electric Power Survey of India published by the CEA.iii) Transmission Planning Criteria and guidelines issued

by the CEAiv) Operational feedback from RPCsv) Operational feedback from NLDC/RLDC/SLDCvi) Central Electricity Regulatory Commission ( Grant

of Connectivity, Long-term Access and Medium-term Open Access in inter-state Transmission and related matters)- Regulations , 2009.

vii) Renewable capacity addition plan issued by Ministry of New and Renewable Energy Sources ( MNRES), Govt of India

35

3.PLANNING CODEIn case of associated transmission system where

all PPAs have not yet been signed, and where agreement could not be reached in respect of system strengthening schemes, the CTU may approach CERC for the regulatory approval in accordance with Central Electricity Regulatory Commission (Grant of Regulatory Approval for Capital Investment to CTU for execution of Inter-State Transmission Scheme) Regulations.

As per new Regulation on Regulatory approvalRegulatory approval for several schemes has

already been granted by CERC.

36

3.PLANNING CODEFor voltage management in inter-state transmission

of energy, special attention shall be accorded, by CTU, for planning of capacitors, reactors, SVC and Flexible Alternating Current Transmission Systems (FACTS), etc. Similar exercise shall be done by STU for intra-State transmission system to optimize the utilistion of the integrated transmission network.

Based on Plans prepared by the CTU, State Transmission Utilities (STU) shall have to plan their systems to further evacuate power from the ISTS and to optimize the use of integrated transmission network.

37

3.PLANNING CODE

In case Long -Term Access Applications require any strengthening in the intra-State transmission system to absorb/evacuate power beyond ISTS, the applicant shall co ordinate with the concerned STU. STU shall augment the intra-state transmission system in a reasonable time to facilitate the interchange of such power.

The Inter-State Transmission System and associated intra-State transmission system are complementary and inter-dependent and planning of one affects the other's planning and performance. Therefore, the associated intra-State transmission system shall also be discussed and reviewed before implementation during the discussion for finalizing ISTS proposal.

38

3.PLANNING CODEIn case of associated transmission system where

all PPAs have not yet been signed, and where agreement could not be reached in respect of system strengthening schemes, the CTU may approach CERC for the regulatory approval in accordance with Central Electricity Regulatory Commission (Grant of Regulatory Approval for Capital Investment to CTU for execution of Inter-State Transmission Scheme) Regulations.

As per new Regulation on Regulatory approvalRegulatory approval for several schemes has

already been granted by CERC.

39

Planning CriteriaThe planning criterion is based on the security philosophy on

which the ISTS has been planned. The security philosophy may be as per the Transmission Planning Criteria and other guidelines as given by CEA.

As a general rule, the ISTS shall be capable of withstanding and be secured against the following contingency 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,- Outage of single Interconnecting Transformer, or- Outage of one pole of HVDC Bipole line, or one

pole of HVDC back to back Station or- Outage of 765 kV S/C line

Planning Criteria The above contingencies shall be considered assuming a pre-contingency system depletion (Planned outage) of another 220 kV D/C line or 400 kV S/C line in another corridor and not emanating from the same substation.

The planning study would assume that all the Generating Units operate within their reactive capability curves and the network voltage profile are also maintained within voltage limits specified.

The ISTS shall be capable of withstanding the loss of most severe single system infeed without loss of stability.

Planning CriteriaAny one of these events defined above shall not cause:

i. Loss of supplyii. Prolonged operation of the system frequency

below and above specified limits.iii. Unacceptable high or low voltageiv. System instabilityv. Unacceptable overloading of ISTS elements.

In all substations (132 kV and above), at least two transformers shall be provided. .

Reactive Power Planning CTU has to carry out planning studies for Reactive Power compensation of ISTS including reactive power compensation requirement at the generator’s /bulk consumer’s switchyard and for connectivity of new generator/ bulk consumer to the ISTS in accordance with Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-state Transmission and related matters) Regulations, 2009.

Special Protection SchemeSuitable System Protection Schemes may

be planned by NLDC/RLDC in consultation with CEA, CTU, RPC and the Regional Entities, either for enhancing transfer capability or to take care of contingencies

Experience of system protection scheme in NR where for any pole outage of Rihand –Dadri HVDC , backing down Generation in Singrauli Rihand Complex and shed equivalent load in various states.

Similar schemes exist for Talcher-Kolar HVDC Tr. Line

44

Part - 4 Connection CodeSpecifies to comply with CEA (Technical

Standards for connectivity to the Grid) Regulations, 2007 which gives the minimum technical and design criteria and CERC (Grant of Connectivity, Long-term Access, Medium-term Open Access and Short-term Open access in inter-state Transmission and related matters) Regulations,2 009.

Also specifies Responsibilities for safety, Cyber Security and schedule of assets.

45

4.CONNECTION CODEThe objective of the code is :

a) To ensure the safe operation, integrity and reliability of the grid.b) basic rules for connectivity are complied with in order to treat all users in a non-discriminatory manner.c) Any new or modified connections, when established, shall neither suffer unacceptable effects due to its connectivity to the ISTS nor impose unacceptable effects on the system of any other connected User or STU.d) Any person seeking a new connection to the grid is required to be aware, in advance, of the procedure for connectivity to the ISTS and also the standards and conditions his system has to meet for being integrated into the grid.

46

Connection Code

Reliable and efficient speech and data communication systems are to be provided to facilitate necessary communication and data exchange, and supervision/control of the grid by the RLDC, under normal and abnormal conditions.

All Users, STUs and CTU should provide Systems to telemeter power system parameter such as flow, voltage and status of switches/ transformer taps etc. in line with interface requirements and other guideline made available by RLDC.

The associated communication system to facilitate data flow up to appropriate data collection point on CTU’s system, are also to be established by the concerned User or STU as specified by CTU in the Connection Agreement.

All Users/STUs in coordination with CTU have to provide the required facilities at their respective ends as specified in the Connection Agreement.

Connection CodeRecording instruments such as Data

Acquisition System/Disturbance Recorder/Event Logging Facilities/Fault Locator (including time synchronization equipment) are to be provided and are always to be kept in working condition in the ISTS for recording of dynamic performance of the system.

All Users, STUs and CTU have to provide all

the requisite recording instruments and have always to keep them in working condition.

Part - 5 Operating CodeSpecifies the operational rules and procedures to maintain secure, efficient, and reliable grid operation.

49

Operating philosophy.The primary objective of integrated operation of

the National/ Regional grids is to enhance the overall operational reliability and economy of the entire electric power network spread over the geographical area of the interconnected system.

Overall operation of the National / inter-regional grid are to be supervised from the National Load Despatch Centre (NLDC).

Operation of the Regional grid shall be supervised from the Regional Load Despatch Centre (RLDC).

Detailed operating procedures to be developed by NLDC and RLDC for the National grid and regional grid , respectively.

50

System Security Aspects

All Users, CTU and STUs shall endeavor to operate their respective power systems and power stations in an integrated manner at all times

No part of the grid shall be deliberately isolated from the rest of the National/Regional grid, except

(i) under an emergency, and conditions in which such isolation would prevent a total grid collapse and/or would enable early restoration of power supply,

(ii) for safety of human life (iii) when serious damage to a costly equipment is

imminent and such isolation would prevent it, (iv) when such isolation is specifically instructed by RLDC.

System Security Aspects No important element of the National/Regional grid

shall be deliberately opened or removed from service at any time, except when specifically instructed by RLDC or with specific and prior clearance of RLDC. The list shall be prepared by the RLDC.

Any prolonged outage of power system elements of any User/CTU/STU, which is causing or likely to cause danger to the grid or sub-optimal operation of the grid shall regularly be monitored by RLDC.

RLDC shall report such outages to RPC. RPC shall finalise action plan and give instructions to restore such elements in a specified time period.

Restricted Free Governor mode (RGMO)Governor Action: Since 10 years FGMO was non-

starter, so Restricted Free Governor mode (RGMO)The restricted governor mode of operation shall essentially

have the following features:a) There should not be any reduction in generation in case of improvement in grid frequency below 50.2 Hz. ( for example if grid frequency changes from 49.3 to 49.4 Hz. then there shall not be any reduction in generation). Whereas for any fall in grid frequency, generation from the unit should increase by 5% limited to 105 % of the MCR of the unit subject to machine capability.b) Ripple filter of +/- 0.03 Hz. shall be provided so that small changes in frequency are ignored for load correction, in order to prevent governor hunting.( to take care Generator argument that there are too many fluctuations in grid )

. 53

RGMO

All other generating units including the pondage upto 3 hours, Gas turbine/Combined Cycle Power Plants, wind and solar generators and Nuclear Power Stations shall be exempted from these provisions

Provided that if a generating unit cannot be operated under restricted governor mode operation, then it shall be operated in free governor mode operation with manual intervention to operate in the manner required under restricted governor mode operation- First Amendment

54

AVR & PSS

Power System Stabilizers (PSS) in AVRs of generating units (wherever provided), shall be got properly tuned by the respective generating unit owner as per a plan prepared for the purpose by the CTU/RPC from time to time.

CTU /RPC will be allowed to carry out checking of PSS and further tuning it, wherever considered necessary.

55

System Security Aspects

Provision of protections and relay settings shall be coordinated periodically throughout the Regional grid, as per a plan to be separately finalized by the Protection sub-Committee of the RPC.

All Users, SEB, SLDCs , RLDCs, and NLDC shall take all possible measures to ensure that the grid frequency always remains within the 49.7 –50.2 Hz band.

All Users, STU/SLDC , CTU/RLDC and NLDC, shall also facilitate identification, installation and commissioning of System Protection Schemes (SPS)

SPS schemes would be finalized by the concerned RPC forum, and shall always be kept in service.

Frequency Range Variation

Sl. No. Period Operating Range

1 Till 31.03.2009 49.0-50.5 Hz.

2 01.04.2009-02.05.2012 49.2-50.3

3 03.05.2012-13.09.2012 49.5-50.2

4 From 14.09.2012 49.7-50.2

57

System Security Aspects- UFR

All SEBS, distribution licensees / STUs shall provide automatic under-frequency and df/dt relays for load shedding in their respective systems, to arrest frequency decline that could result in a collapse/disintegration of the grid,

as per the plan separately finalized by the concerned RPC and shall ensure its effective application to prevent cascade tripping of generating units in case of any contingency.

RLDC shall keep a comparative record of expected load relief and actual load relief obtained in Real time system operation.

A monthly report on expected load relief vis-a-vis actual load relief shall be sent to the RPC and the CERC.

System Security Aspects- UFR

Flat Under Frequency RelaysRegion Stage-I Stage-II Stage-IIINorthern Region 48.8 Hz 48.6 Hz 48.2 HzWestern Region 48.8 Hz 48.6 Hz 48.2 HzEastern Region 48.5 Hz 48.2 Hz 48.0 HzSouthern Region 48.8 Hz 48.2 Hz 48.0 HzNorth-eastern region 48.4 Hz - -Rate of Change of Frequency Relays

Stage-I Stage-II Stage-III49.9 / 0.1 Hz/sec 49.9 / 0.2 Hz/sec 49.9 / 0.3 Hz/sec

Under Frequency Relays-NR

60

Relay df/dt relays in NR

61

System Security Aspects

All the Users , STU/SLDC and CTU shall send information/data including disturbance recorder/sequential event recorder output to RLDC within 24 hours for purpose of analysis of any grid disturbance/event.

Based on demand estimate, SLDC shall plan demand management measures like load shedding, power cuts, etc. and shall ensure that the same is implemented by the SEB/distribution licensees/ SLDCs. –CERC Order

63

DEMAND ESTIMATION FOR OPERARTIONAL PURPOSES

on-line estimation for daily operationa

l use historical data

and weather forecast

Daily/Weekly/Monthly

Demand Estimation – Active and reactive

power

Inform to RLDC/RPCWind

Energy Forecast

ATC/TTC

Outage PlanningAnnual outage plan shall be prepared

in advance for the financial year by the RPC Secretariat in consultation with NLDC and RLDC and reviewed during the year on quarterly and Monthly basis.

All Users, CTU, STU etc. shall follow these annual outage plans.

If any deviation is required the same shall be with prior permission of concerned RPC and RLDC.

65

LGBR & Outage Planning Process

Feb- March

DecOct next financial year

proposed outage programmes by all concerned (31st Oct )

Nov

draft outage programme by RPC Secretariat (30th Nov)

final outage programme by (31st Dec )

JanReview by RPC Secretariat: adjustments made wherever found to be necessary in coordination with all parties concerned

monthly review quarterly review

Voltage Ratings

Voltage – (kV rms)Nominal Maximum Minimum

765 800 728400 420 380220 245 198132 145 122110 121 9966 72 6033 36 30

Demand DisconnectionSLDC/ SEB/distribution licensee and bulk consumer

shall initiate action to restrict the drawal of its control area ,from the grid, within the net drawal schedule whenever the system frequency falls to 49.8 Hz

Ensure that requisite load shedding is carried out in its control area so that there is no overdrawl when frequency is 49.7 Hz. or below. - Monitoring by CERC

formulate contingency procedures and make arrangements that will enable demand disconnection to take place, as instructed by the RLDC/SLDC, under normal and/or contingent conditions.

The SLDC through respective State Electricity Boards/Distribution Licensees shall also formulate and implement state-of-the-art demand management schemes for automatic demand management- CERC suo –Motu Action

Demand DisconnectionRLDCs shall devise standard, instantaneous,

message formats in order to give directions- Message A,B,C, D- Continuous Monitoring by CERC

The concerned SLDC shall ensure immediate compliance with these directions of RLDC and send a compliance report to the concerned RLDC.

The measures taken by the Users, SLDC SEB/distribution licensee or bulk consumer shall not be withdrawn as long as the frequency remains at a level lower than the limits specified or congestion continues, unless specifically permitted by the RLDC/SLDC.

OPERATING CODE

Special requirements for Solar/ wind generators

System operator (SLDC/ RLDC) shall make all efforts to evacuate the available solar and wind power and treat as a must-run station.

However, System operator may instruct the solar /wind generator to back down generation on consideration of grid security or safety of any equipment or personnel is endangered and Solar/ wind generator shall comply with the same.

69

Part - 6 Scheduling and Despatch CodeDemarcates responsibilities between various

regional entities, SLDC, RLDC and NLDC in scheduling and despatch

Procedure for scheduling and despatch procedure on a day ahead basis .

Reactive power and voltage control mechanism.

Complementary Commercial Mechanisms (in the Annexure–1).

70

71

Demarcation of responsibilities of SLDC

SLDC

Permitting Open Access

Regulating net drawal

Scheduling and despatching

Scheduling drawal from ISGS

Demand Regulation6.4.8 Demand Estimation in coordination with STU/Discoms

72

Demarcation of responsibilities -Role of RLDC

RLDC

Periodically review UI

Gaming by ISGS

15 min drawal and injection MS RPC

Report

105 % in one block of 15 minutes and 101% over a day no gaming

73

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

Demarcation of control area

Earlier central sector or state sector generator . Central station 85% firm allocation and 15% unallocated distributed among beneficiary so clear full contract. Central ( except dedicated) RLDC; State & embedded ( SLDC)

Now IPP, Merchant Power have multiple contract of multiple duration Long Term , short term, Case-I , case-II bidder connected to either ISTS or STU or both.

So issue arises who will be responsible for their scheduling

74

Demarcation of control areaEarlier provision: RLDCs shall coordinate the

scheduling of generating stations owned by Central Government organizations (excluding stations where full share is allocated to host state),Ultra-Mega power projects and other generating stations of 1000 MW or larger size in which, States, other than the host State have permanent shares of 50% or more. ( on which date, what capacity ?)

Generating stations not meeting the above criteria regarding plant size and share of other States shall be scheduled by the SLDC of the State in which they are located. However, there may be exceptions for reasons of operational expediency, subject to approval of CERC.

75

Demarcation of control area

The national interconnected grid is divided into control areas, like Regional ISTS, States, DVC, etc. where the load dispatch centre or system operator of the respective control area controls its generation and/or load to maintain its interchange schedule with other control areas whenever required to do so and contributes to frequency regulation of the synchronously operating system.

76

Definition of control area

an electrical system bounded by interconnections (tie lines), metering and telemetry which controls its generation and/or load to maintain its interchange schedule with other control areas whenever required to do so and contributes to frequency regulation of the synchronously operating system;

77

Demarcation of control area- Responsibility of LDCcoordinating the scheduling of a generating

station, within the control area, real-time monitoring of the station’s operation,

checking that there is no gaming (gaming is an intentional mis-declaration of a parameter related to commercial mechanism in vogue, in order to make an undue commercial gain) in its availability declaration, or in any other way

revision of availability declaration and injection schedule, switching instructions,

Meter data Processing; collections/disbursement of UI payments, outage planning, etc.

78

Demarcation of control area- RLDC Control

Central Generating Stations (excluding stations where full Share is allocated to host state),

Ultra-Mega power projectsIf a generating station is connected only to the

ISTS, RLDC shall coordinate the scheduling, except for Central Generating Stations where full Share is allocated to one State.

If a generating station is connected both to ISTS and the State network, and if the State has a Share of 50% or less, the scheduling and other functions shall be performed by RLDC.

79

80

Demarcation of responsibilities (6.4.1) -Role of RLDC

Scheduling of CGS (Except where full share is allocated to host state)

Scheduling of UMPP

Scheduling of GS connected to ISTS except for CGS where full Share is allocated to one State

Scheduling of GS

connected both to ISTS & state grid and home

state Share is less then

50%

RLDC

Demarcation of control area-SLDCIf a generating station is connected only to

the State transmission network, the SLDC shall coordinate scheduling, except for Central Generating Stations with share more than one State.

If a generating station is connected both to ISTS and the State network, scheduling and other functions performed by the system operator of a control area will be done by SLDC, only if state has more than 50% Share of power .

81

82

Demarcation of responsibilities (6.4.1) -Role of SLDC

Scheduling of CGS- where full share is allocated to host state

Scheduling of GS connected to Intra-State Transmission system except where share is for more than one State

Scheduling of GS

connected both to ISTS & state grid and home state has More than

50%

RLDCSLDC

Demarcation of control area- Switching In case commissioning of a plant is done in stages

the decision regarding scheduling and other functions performed by the system operator of a control area would be taken on the basis of above criteria depending on generating capacity put into commercial operation at that point of time.

it could happen that the plant may be in one control area (i.e. SLDC) at one point of time and another control area (i.e. RLDC) at another point of time.

The switch over of control area would be done expeditiously after the change, w.e.f. the next billing period.

83

Decentralized Scheduling - SLDC Responsibility The Regional grids shall be operated as power pools

with decentralized scheduling and despatch, in which the States shall have operational autonomy with SLDC Responsibility for

scheduling/despatching their own generation (including generation of their embedded licensees)

regulating the demand of its control area scheduling their drawal from the ISGS (within their

share in the respective plant’s expected capability)permitting long term access, medium term and short

term open access transactions for embedded generators/consumers, in accordance with the contracts

regulating the net drawal of their control area from the regional grid in accordance with the respective regulations of the CERC.

84

Drawal Schedule- Deviation ManagementScheduled drawal - the algebraic summation of

schedule from from ISGS and from contracts through a long – term access, medium –term and short –term open access arrangements

determined in advance on day-ahead basis. Regional entities shall regulate their generation

and/or consumers’ load so as to maintain their actual drawal from the regional grid close to the above schedule.

If regional entities may deviate from the drawal schedule, within the limit specified by the CERC in UI Regulations as long as such deviations do not cause system parameters to deteriorate beyond permissible limits and/or do not lead to unacceptable line loading. 85

86

Scheduling Procedure - Regulation 6.5

12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1noon

ISGS

SLDC

Despatch schedule

Net D

rawa

l sch

edul

eRev

ision

Revision

station-wise MW/MW

H

capability

station-wise MW/MWH

entitlement

Drawal

sche

dule

for

ISGS, L

TA, MTOA&

STOA

AM PM

RLDC

Despatch schedule starts

Drawalschedule starts

finalDespatch schedule

final Drawal

schedule

87

Collective Scheduling Procedure - Regulation 6.5

10 11 12 13 14 15 16 17 1730

Exchanges

RLDC

list of interfaces/control areas/

regional transm

ission system

s

on w

hich unconstrained

flows

are required

Scheduling Request of

Collective Transactio

n

Applicatio

n for S

cheduling

interchange

on various

interfaces/control

areas/regional transm

ission

systems

period of co

ngestion & ava

ilable

limit f

or sch

eduling

NLDC

conf

irm a

ccep

tanc

e

total drawal and injection in

each of the regions

conf

irm a

ccep

tanc

e

18SLDC

Individual Trans.

Of intra-state

utili ty

Final schedule for regional entities at their boundary by 1800 hrs

Scheduling of Collective Transaction 6.5.5

88

Power Exchanges

NLDC

SLDC RLDC

1. List of Interfaces, Control areas 2. Interchanges on

Interfaces, Control areas

3. Check for Congestion , reworked as per CERC directive

4. Consultation6.

Individual Transactions

7. Schedule individual transaction

5.Schedule at respective periphery

Drawal Schedule- Deviation by Gen. The ISGS would normally be expected to generate power

according to the daily schedules advised to them. The ISGS may also deviate from the given schedules

within the limits specified in the CERC UI Regulations of CERC, depending on the plant and system conditions.

Deviations, if any, to be priced in accordance with UI Regulations and Congestion Charge Regulations of CERC

Hydro generating stations are expected to respond to grid frequency changes and inflow fluctuations. The hydro generating stations are free to deviate from the given schedule without causing grid constraint. Deviation to be compensated on D+3 basis

89

SEM Installation and Data HandlingThe CTU shall install special energy meters

on all inter connections between the regional entities and other identified points for recording of actual net MWh interchanges and MVArh drawals.

All concerned entities (in whose premises the special energy meters are installed) shall take weekly meter readings and transmit them to the RLDC by Tuesday noon.

The SLDC must ensure that the meter data from all installations within their control area are transmitted to the RLDC within the above schedule.

90

Special provisions for grid Constraints (6.5.16)In the event of bottleneck in evacuation of power due

to any constraint, outage, failure or limitation in the transmission system, associated switchyard and substations owned by the Central Transmission Utility or any other transmission licensee involved in inter-state transmission (as certified by the RLDC) necessitating reduction in generation, the RLDC shall revise the schedules which shall become effective from the 4th time block, counting the time block in which the bottleneck in evacuation of power has taken place to be the first one.

Also, during the first, second and third time blocks of such an event, the scheduled generation of the ISGS shall be deemed to have been revised to be equal to actual generation, and the scheduled drawals of the beneficiaries shall be deemed to have been revised accordingly. 91

Special provisions for grid ConstraintsIf, at any point of time, the RLDC observes that there is need for revision of the schedules in the interest of better system operation, it may do so on its own, and in such cases, the revised schedules shall become effective from the 4th time block.

When for the reason of transmission constraints e.g. congestion or in the interest of grid security, it becomes necessary to curtail power flow on a transmission corridor, the transactions already scheduled may be curtailed by the Regional Load Despatch Centre. The short-term customer shall be curtailed first followed by the medium-term customers, which shall be followed by the long-term customers and amongst the customers of a particular category, curtailment shall be carried out on pro rata basis.

92

Special provisions for grid ConstraintsIn case of any grid disturbance, scheduled

generation of all the ISGS and scheduled drawal of all the beneficiaries shall be deemed to have been revised to be equal to their actual generation/drawal for all the time blocks affected by the grid disturbance. Certification of grid disturbance and its duration shall be done by the RLDC.

In a petition filed to CERC, NLDC suggested that the clause may be modified in line with clause 6.5.16 (transmission bottleneck), wherein schedule of ISGS is made equal to actual and schedule of beneficiaries is revised accordingly (based on entitlement).

93

Special provisions for ISGS(s) having two part tariff (6.5.18)

Revision of declared capability by the ISGS(s) having two part tariff with capacity charge and energy charge(except hydro stations) and requisition by beneficiary(ies) for the remaining period of the day shall also be permitted with advance notice. Revised schedules/declared capability in such cases shall become effective from the 6th time block.

RLDC may allow revision, of the DC at 6 hourly intervals effective form 0000,0600,1200 and 1800 hours in case of Run of the River (ROR) and pondage based hydro generating stations, if there is large variation of expected energy (MWh) for the day compared to previous declaration.

94

Special provisions for Forced outage of ISGS(s) having two part tariff

Notwithstanding anything contained in Regulation 6.5.18, in case of forced outages of a unit, for those stations who have a two part tariff based on capacity charge and energy charge for long term and medium term contracts, the RLDC shall revise the schedule on the basis of revised declared capability.

The revised declared capability and the revised schedules shall become effective from the fourth time block, counting the time block in which the revision is advised by the ISGS to be the first one.”

95

Forced outage of a unit under STOA transactionA unit of a generating station (having generating capacity of 100

MW or more) and selling power under Short Term bilateral transaction (excluding collective transactions through power exchange),

effective from the 4th time block, counting the time block in which the forced outage is declared to be the first one.

The original schedule shall become effective from the estimated time of restoration of the unit.

the transmission charges as per original schedule shall continue to be paid for two days.

only if the source of power for a particular transaction has clearly been indicated during short-term open access application and the said unit of that generating station goes under forced outage.

In case of revision of schedule of a generating unit, the schedules of all transactions under the long-term access, medium-term open access andshort-term open access (except collective transactions through powerexchange), shall be reduced on pro-rata basis.”

96

RationaleIn case of Short Term bilateral transaction, OA can

not be withdrawn before three days as per OA regulation i.e. not allowing revision negative effects

Buyer of this power can keep on drawing power without paying UI as his schedule is not revised. Grid imbalance due to less generation, low frequency.

Generator will pay unnecessary UI because forced outage is not controllable .Apprehension-With provision for revision, contracts would no longer have any sanctity. They would become options. It could also lead inter alia to blocking of corridor.

97

Special provisions for renewable

Since variation of generation in run-of-river power stations shall lead to spillage, these shall be treated as must run stations. All renewable energy power plants, except for biomass power plants, , and non-fossil fuel based cogeneration plants whose tariff is determined by the CERC shall be treated as ‘MUST RUN’ power plants and shall not be subjected to ‘merit order despatch’ principles.

98

Wind generation Scheduling With effect from 1.7.2011 Scheduling of Wind Gen.

necessary:i) where the sum of generation capacity of such plants connected at the connection point to the transmission or distribution system is 10 MW and above ii) and connection point is 33 KV and above, iii) and where PPA has not been signed before 03.05.2010.

For capacity and voltage level below this, as well as for old wind farms ( A wind farm is collection of wind turbine generators that are connected to a common connection point) it could be mutually decided between the Wind Generator and the transmission or distribution utility, as the case may be, if there is no existing contractual agreement to the contrary .

There may be maximum of 8 revisions starting from 00:00 hours during the day.

99

scheduling of solar generationScheduling necessary with effect from 1.7.2011, for

new solar generating plants with capacity of 5 MW and above connected at connection point of 33 KV level and above and , who have not signed any PPA with states or others as on 03.05.2010.

Schedule to be given by the generator based on availability of the generator, weather forecasting, solar insolation, season and normal solar generation curve

to be vetted by the RLDC in which the generator is located and incorporated in the inter-state schedule.

If RLDC is of the opinion that the schedule is not realistic , it may ask the solar generator to modify the schedule.

100

UI for Wind generatorsFor actual generation within +/- 30% of the schedule,

no UI would be payable/receivable by Generator, The host state , shall bear the UI charges for this

variation, i.e within +/- 30%. the UI charges borne by the host State due to the

wind generation, shall be shared among all the States of the country in the ratio of their peak demands in the previous month based on the data published by CEA, in the form of a regulatory charge known as the Renewable Regulatory Charge operated through the Renewable Regulatory Fund (RRF).

if the actual generation is beyond +/- 30% of the schedule, wind generator would have to bear the UI charges.

101

UI for Wind generatorsA maximum generation of 150% of the

schedule only, would be allowed in a time block, for injection by wind, from the grid security point of view.

For any generation above 150% of schedule, if grid security is not affected by the generation above 150%, the only charge payable to the wind energy generator would be the UI charge applicable corresponding to 50- 50.02 HZ .( About Rs 1.55/kwh)

102

UI for Solar Gen.In case of solar generation no UI shall be

payable/receivable by Generator. The host state, shall bear the UI charges for

any deviation in actual generation from the schedule. The net UI charges borne by the host State due to the solar generation, shall be shared as per RRF mechanism.

NLDC is implementing agency for RRF Mechanism.

Detailed procedure by NLDC

103

104

Though there is much variation, the ramp-up & ramp down happens over several hours

105

Problems in Open Access and Grid DisciplineIn case of states having substantial wind potential say in

Tamil Nadu with 4050 MW schedule of wind , if actual generation is 2000 MW then state would face problem of load generation balance and may overdraw heavily from grid. The state would be reluctant to allow Open Access to these generators, if suitable penal action is not imposed.

If it is scheduled in State , then its failure would result in heavy Overdrawl ,more than CERC limits.

Arranging balancing power: In case of substantial deviation of Wind generation from

Schedule ,sufficient stand by quick ramp up power is to be arranged , the cost of which would add on to ultimate cost of purchase of power for utility as a whole.

106

Wind potential

107

Reactive Energy ChargesThe Regional Entities except Generating Stations are

expected to provide local VAr compensation/generation such that they do not draw VArs from the EHV grid, particularly under low-voltage condition.

To discourage VAr drawals by Regional Entities except Generating Stations, VAr exchanges with ISTS are priced .

The Regional Entity except Generating Stations pays/ get payed for VAr drawal/return when voltage at the metering point is below 97%.

The Regional Entity except Generating Stations gets paid/to pay for VAr drawal/return when voltage is above 103%.

108

Reactive Energy ChargesThe charge for VArh to be at the rate of 10

paise/kVArh w.e.f. 03.05.2010, and this will be applicable between the Regional Entity, except Generating Stations, and the regional pool account for VAr interchanges. This rate shall be escalated at 0.5paise/kVArh per year thereafter, unless otherwise revised by the Commission.

Rate increased from 6.25 paise/kVArh to 10 paise/kVArh to incentivize Capacitor installation, as it would be cheaper to install Capacitor .Within three year capital investment in capacitor would be recovered through saving in Reactive energy charge. This will discourage drawl of reactive power from the Grid. 109

Implementation Issues- RGMO/FGMORGMO Implementation ( Regulation 5.2

(f) ) : Provisions of FGMO is in IEGC since very beginning, but it could not be implemented fully.

Many generators have requested CERC for exemption from RGMO on technical ground.

CERC has initiated suo-motu action against defaulting utilities and issued order , but still the RGMO could not be implemented as per provisions of the Grid.

In order dated 09.10.2012, CERC has issued notice to many CMDs/Chairmen of generating companies like NEEPCO, SJVNL, Uttar Pradesh RUVNL, DVC, ASEB, Uttarakhand Power Gen, Haryana Power Gen, Rajasthan RVUNL etc. for non-compliance of this provision and non-implementation of RGMO. Vide order dated 31.12.2013 penalty of 1 Lakh imposed on each of Haryana, Uttarakhand, J&K and Assam Gencos/SEB. Task Force under M (TH), CEA.

Petitions have also been filed by RLDCs to ensure primary response by generators. The matter is pending in CERC.

110

Implementation Issues- Load ManagementLoad Management ( Regulation 5.4.2 (a) &

(b)) : A number of petitions had been filed by RLDCs and

several suo-motu proceedings had also been initiated by CERC. Penalties up to few Crores of Rupees have been imposed on erring utilities.

Several other steps like increase in UI charges, introduction of additional UI charges, narrowing down of frequency band and application of congestion charge have been taken.

These steps, had surely been helpful in reducing fluctuation of frequency and in improvement of quality of supply. But, even now, grid discipline is not being maintained by some utilities.

111

Implementation IssuesAutomatic Demand Management ( Regulation 5.4.2

(d)): Provision has been made for automatic demand management system and contingency procedure, but till now except a few utilities in Delhi, Maharashtra & Karnataka (CERC order dt. 14.01.2013) the implementation has not been done. CERC have issued directions for implementation of the same but due to one or other reasons these measures to ensure grid discipline could not be implemented by all the utilities.

Demand Estimation (Regulation 5.3): One of the reason for grid indiscipline is lack of proper advance planning to meet the load by State utilities. In spite of provisions in Grid Code and several directions by CERC, most of the State utilities failed in proper demand estimation.

112

Implementation IssuesTelemetry and Communication Facilities

(Regulation 4.6.2): In orders dated 26.09.2012 and 11.10.2012 in petitions by RLDCs, CERC has observed that these facilities must be provided by every user, CU and STUs. It was also mentioned that the generating stations and sub-stations should provide these facilitate before start of power flow, even the infirm power.

Operationalisation of RRF Mechanism ( Regulation 6.5.23): One of the main features of IEGC, 2012 was provisions to facilitate integration of renewables with Grid. RRF mechanism was to be implemented w.e.f 01.01.2011, which was rescheduled to 01.07.2011. But due to implementation issues this mechanism could not be operationalised till date.

113

Non-Compliance –Transmission LicenseeNon-compliance of RLDC instructionsSwitching of ISTS elements without RLDC permission

(except under emergency)Manning of control centres by inadequately qualified &

untrained personnelDeliberately isolating part of the grid from the rest of the

regional gridNot ensuring providing of RTU and other communication

equipment for sending real-time data In adequate Protection systems unable to isolate the faulty

equipments within the specified fault clearance time with reliability, selectivity and sensitivity

Not sending information/data including disturbance recorder/sequential event recorder output etc., to RLDC for purpose of analysis of any grid disturbance/event.

114

Way ForwardCERC should establish a mechanism for regular

monitoring of compliance of various provisions of Grid Code.

RPCs and RLDCs have to play more active role in reporting non-compliance to CERC. Strict action against erring utilities

To ensure integration, the RRF mechanism is to be made operational as soon as possible.

Implementation of RGMO/FGMO Introduction of Ancillary servicesestablishment of proper data transfer and

communication facility should be ensured before granting connectivity to generating station or sub-station by CTU/STU.

115

Way Forwardaugmentation/up-gradation of communication

facilities, implementation of WAMS schemes and up-

gradation of ULDC systemIEGC should be regularly reviewed and

updated/ amended to align it with the operational needs, technological and market developments.

CTU and POSOCO have to play pro-active role, as these two organisations are up to a great extent responsible for planning, developing, controlling and operating the Indian electricity grid. 

116

With Hope that We all together will be able to Organise Lightening

Always for Mankind

Thank You.117

118

IMPORTANT DEFINITIONS- New and Modified“Long –term Access” means the right to use

the inter-State transmission system for a period exceeding 12 years but not exceeding 25 years;

“Medium-term Open Access” means the right to use the inter- State transmission system for a period exceeding 3 months but not exceeding 3 years;

“Short-term Open Access” means open access for a period up to one (1) month at one time;

119

ISGS

“Inter-State Generating Station (ISGS)” means a Central generating station or other generating station, in which two or more states have Shares;

“Share” means percentage share of a beneficiary in an ISGS either notified by Government of India or agreed through contracts and implemented through long term access;

120

ISTS“Inter-State Transmission System (ISTS)”

includes i) Any system for the conveyance of electricity by

means of a main transmission line from the territory of one State to another State

ii) The conveyance of electricity across the territory of an intervening State as well as conveyance within the State which is incidental to such inter-state transmission of energy

(iii) The transmission of electricity within the territory of State on a system built, owned, operated, maintained or controlled by CTU;

121

IMPORTANT DEFINITIONS- New and Modified“Demand response” means reduction in

electricity usage by end customers from their normal consumption pattern, manually or automatically, in response to high UI charges being incurred by the State due to overdrawal by the State at low frequency, or in response to congestion charges being incurred by the State for creating transmission congestion, or for alleviating a system contingency, for which such consumers could be given a financial incentive or lower tariff;

122

IMPORTANT DEFINITIONS- New and Modified“User” means a person such as a Generating

Company including Captive Generating Plant or Transmission Licensee ( other than the Central Transmission Utility and State Transmission utility) or Distribution Licensee or Bulk Consumer, whose electrical plant is connected to the ISTS at a voltage level 33kV and above;

123