Electricity is really just organized lightning.
George Carlin
1

 Focus on IEGC Provisions related to SLDCs , RLDCs and NLDC
What is IEGC
Historical Background
Contents of IEGC
Brief Description of Provisions
Non-Compliance of IEGC
Implementation Issues
Way Forward
2

 The 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

IEGC,
 CTU prepared this Grid Code in pursuance of CERC directions issued, on 31st March, 1999,
 Became effective from 1 st 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







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 subsection (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









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 2004-09
Defining 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

2010
 The 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 made
 Amendment was to be made effective from 02.04.2012 , but actually got implemented w.e.f 17.09.2012, due to court case.
8

 Focus on Renewable integration, Grid Discipline,
Coherence with other Regulations, Market development,
Multiple players with multiple Contracts,
 Forecasting, Scheduling of Wind & Solar
 Deviation Settlement -RRF Mechanism
 Tightening of frequency band ‘49.2- 50.3 Hz.’ to ‘49.5 - 50.2
Hz’.
 Alignment with various Regulations
 Control Area Jurisdiction -Redefined
 Stricter provisions for Grid discipline
 Automatic Demand Management schemes and
Contingency Procedures.
9

 Section 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

 “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

 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

To 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


AllUsers, 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

o 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

.
 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

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

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.
145/2006
Date of order
17.11.2006
Respondents
APTRANSCO, KTPCL, TNEB, KSEB, , , NLC, NTPC
Penalty Amount (in Rs.)
-
14/2007 13.2.2007
-
89/2008
137/2008
152/2008
25/2006
52/2009
59/2009
80/2009
81/2009
105/2009
106/2009 &
130/2009
137/2009
151/2009
107/2010
080/2009
081/2009
133/2010
4.9.2008
31.12.2008
9.1.2009
9.5.2006
6.5.2009
5.5.2009
11.5.2009
8.5.2009
21.8.2009
21.8.2009
30.10.2009
30.11.2009
30.3.2010
11.5.2009
8.5.2009
3.2.2010
UPPCL, HVPNL, PDD, J K, PSEB, RRVPN, DTL,
GUVNL, MSEDCL, CSEB, MPSEB, APTRANSCO,
KPTCL
APTRANSCO, KTPCL, TNEB, KSEB, , , NLC, NTPC
TNEB
UPPCL
UPPCL
KPTCL
RRVPNL
APTRANSCO
TNEB
UPPCL
Tamil Nadu Electricity Board, Chennai
UPPCL
DTL (SLDC)
TNEB
APTRANSCO
TNEB
Tamil Nadu Electricity Board, Chennai
-
1 lakh
1 lakh
1 lakh
17 lakh
5 lakh
1.22 crore
1.5 crore
2.57 crore
4.37 crore
4.62 Crore
25,000/-
-
---
---
----
20

Petition No.
Date of order Respondents Penalty Amount
(in Rs.)
1 lakh.
Adj Case No. 1/2006 25.10.2006
UPPCL
Adj Case No. 5/2009 14.10.2009
UPPCL 1.75 Crore.
Adj. case No. 1/2009
Adj case No. 2/2009
Adj case No. 3/2009
Adj case No. 4/2009
8.5.2009
8.5.2009
8.5.2009
8.5.2009
SLDC,
SLDC,
SLDC, Jammu & Kashmir
SLDC, Rajasthan
2.5 lakh.
3.00 lakh.
2.00 lakh
1.00 lakh.
Adj. Case No. 5/2009 14.10.2009
Adj. Case No. 1/2010 21.9.2010
Adj. Case No. 2/2010
Adj. Case No. 3/2010
Adj. Case No. 4/2010
Adj. Case No. 5/2010
Adj. Case No. 7/2010
25.2.2011
25.2.2011
25.2.2011
25.2.2011
25.2.2011
UPPCL
TNEB
UPPCL
HVPNL
RRVPNL
PTL, Uttarakhand
Power Department Govt. of J&K.
1.75 crore
No penalty imposed.
16 lakh
8.00 lakh
4.00 lakh
9.00 lakh
6.00 lakh
21

 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




 Function 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 regional grid; through the
 exercise supervision and control over the Inter-State transmission system
 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.
23

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
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 SLDC
2.7.1
2.7.2- 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

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

 Section 38 of Electricity Act, 2003
 undertake transmission of electricity through inter-State transmission system;
 discharge all functions of planning and co-ordination relating to inter-State transmission system withdifferent agencies
 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 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

 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

 Section 39 of Electricity Act, 2003
 undertake transmission of electricity through intra-State transmission system;
 discharge all functions of planning and co-ordination relating to intra-State transmission system withdifferent agencies
 ensure 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

 Until a Government company or any authority or corporation is notified by the State Government, the
.
31



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

 Task 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

 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

CTU 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
CEA iv) Operational feedback from RPCs v) Operational feedback from NLDC/RLDC/SLDC vi) 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

 In 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 approval
Regulatory approval for several schemes has already been granted by CERC.
36

 For 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



In case Long -Term Access Applications require any strengthening in the intra-State transmission system to absorb/evacuate power beyond ISTS, the applicant shall coordinate with the concerned STU.
STU shall augment the intrastate 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

 In 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 approval
Regulatory approval for several schemes has already been granted by CERC.
39


 The 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

 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 .

 Any one of these events defined above shall not cause: i. Loss of supply ii. Prolonged operation of the system frequency below and above specified limits.
iii. Unacceptable high or low voltage iv. System instability v. Unacceptable overloading of ISTS elements.
 In all substations (132 kV and above), at least two transformers shall be provided. .

 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 interstate Transmission and related matters)
Regulations, 2009.

 Suitable 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

 Specifies 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, Mediumterm 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

 The 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





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.

 Recording 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 .

Specifies the operational rules and procedures to maintain secure, efficient, and reliable grid operation.
49

.
 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



All Users, CTU and STUs shall endeavor to operate their respective power systems and power stations in an integrated manner at all times
(i)
No part of the grid shall be deliberately isolated from the rest of the National/Regional grid, except
(ii) under an emergency, and conditions in which such isolation would prevent a total grid collapse and/or would enable early restoration of power supply, for safety of human life
(iii)
(iv) when serious damage to a costly equipment is imminent and such isolation would prevent it, when such isolation is specifically instructed by RLDC.




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.

 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

 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

 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





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.

Sl. No.
1
2
Period
Till 31.03.2009
01.04.2009-02.05.2012
3
4
03.05.2012-13.09.2012
From 14.09.2012
Operating Range
49.0-50.5 Hz.
49.2-50.3
49.5-50.2
49.7-50.2
57





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 .

 Flat Under Frequency Relays
Region Stage-I
Northern Region 48.8 Hz
Stage-II
48.6 Hz
Stage-III
48.2 Hz
Western Region 48.8 Hz
Eastern Region 48.5 Hz
Southern Region 48.8 Hz
48.6 Hz
48.2 Hz
48.2 Hz
48.2 Hz
48.0 Hz
48.0 Hz
North-eastern region 48.4 Hz - -
 Rate of Change of Frequency Relays
Stage-I Stage-II Stage-III
49.9 / 0.1 Hz/sec 49.9 / 0.2 Hz/sec 49.9 / 0.3 Hz/sec

60

df/dt relays in NR
61

 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

Daily
/Weekly
/Monthly
Inform to
RLDC/
RPC
Wind
Energy
Forecast
Demand Estimation –
Active and reactive power
ATC/
TTC on-line estimation for daily operationa l use historical data and weather forecast
63

 Annual 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.

proposed outage programmes by all concerned (31 st Oct ) draft outage programme by RPC Secretariat (30 th Nov) final outage programme by (31 st Dec ) monthly review quarterly review
Oct Nov Dec Jan Feb
- March next financial year
Review by RPC Secretariat: adjustments made wherever found to be necessary in coordination with all parties concerned
65

765
400
220
132
110
66
33
800
420
245
145
121
72
36
728
380
198
122
99
60
30





SLDC/ 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 managementCERC suo
–Motu Action

 RLDCs 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.

 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

 Demarcates 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

Demarcation of responsibilities of SLDC
Permitting Open
Access
Scheduling drawal from ISGS
Regulating net drawal
SLDC
6.4.8 Demand Estimation in coordination with
STU/Discoms
Demand Regulation
Scheduling and despatching
71

Demarcation of responsibilities -Role of RLDC
Periodically review UI
Report
RLDC
MS RPC
15 min drawal and injection
Gaming by ISGS
105 % in one block of 15 minutes and 101% over a day no gaming
72

Scheduling of
Inter-Regional
Power
Exchanges
Trans-National
Exhange of Power
HVDC Settings
Collective
Transaction
Scheduling
NLDC
Energy accounting on
IR Links- with
RLDC
Scheduling on
Inter Regional
Links .
73

 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

 Earlier 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

 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

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

 coordinating 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

 Central Generating Stations (excluding stations where full Share is allocated to host state),
 Ultra-Mega power projects
 If 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

Demarcation of responsibilities (6.4.1) -Role of RLDC
Scheduling of CGS (Except where full share is allocated to host state)
Scheduling of GS connected both to ISTS
& state grid and home state Share is less then
50%
RLDC
Scheduling of GS connected to ISTS except for
CGS where full Share is allocated to one State
Scheduling of UMPP
80

 If 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

Demarcation of responsibilities (6.4.1) -Role of SLDC
Scheduling of CGS- where full share is allocated to host state
Scheduling of
GS connected both to ISTS
& state grid and home state has
More than
50%
Scheduling of GS connected to
Intra-State
Transmission system except where share is for more than one State
82

 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

 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

 Scheduled 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

final
Despatch schedule
Despatch schedule starts
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 1
AM noon PM final
Drawal schedule
Drawal schedule starts
86

Collective Scheduling Procedure - Regulation 6.5
10 11 12 13 14
15 16
17
1730 18
S
L
D
C
Final schedule for regional entities at their boundary by
1800 hrs
87

Power
Exchanges
1.
List of
Interfaces,
Control areas
2. Interchanges on
Interfaces, Control areas
3. Check for
Congestion , reworked as per
CERC directive
NLDC
6.
Individual
Transaction s
4.
Consultatio n
SLDC
7.
Schedule individual transaction
RLDC
5 .
Schedule at respective
88

 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

 The 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



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


If, 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

 In 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

 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

 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

 A 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 and short-term open access (except collective transactions through power exchange), shall be reduced on pro-rata basis.
”
96

 In 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

 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 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

 For 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

 A 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

 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

150
100
50
0
300
250
200
A Windy Day (July '08)
20 MW 48 MW time of the day
74 MW 113 MW 44 MW TOTAL
104

60
40
20
0
140
120
100
80
A Moderate windy day (September)
Though there is much variation, the ramp-up & ramp down happens over several hours
20 MW 48 MW
Time of the day
74 MW 113 MW 44 MW TOTAL
105

 In 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

107

 The 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

 The 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

 RGMO 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

Load 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

 Automatic 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

 Telemetry 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 of RLDC instructions
Switching of ISTS elements without RLDC permission (except under emergency)
Manning of control centres by inadequately qualified & untrained personnel
Deliberately isolating part of the grid from the rest of the regional grid
Not 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

 CERC 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 services
 establishment of proper data transfer and communication facility should be ensured before granting connectivity to generating station or substation by CTU/STU.
115

 augmentation/up-gradation facilities, of communication
 implementation of WAMS schemes and up-gradation of
ULDC system
 IEGC 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

.
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

 “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