Salient Features
Northern Regional Power System
INDIAN ELECTRICITY
Welcome
GRID CODE
(IEGC)

Largest sized hydro unit (180 MW at Chamera) in the
country
CONTENTS:

Need for an IEGC

Development of the present
IEGC version

Indian Electricity Grid Code : Contents

IEGC : Demarcation of Resposibilities

ABT / IEGC Clauses

ABT Feedback
NEED FOR AN IEGC
Period
Situation
Early 1970s
Vertically integrated SEBs.
Late 1970sEarly1980s
Entry of Central Generating Utilities.
Gradual increase in disputes
Late 1980s
Increase in Central Sector Utilities.
Early 1990s
Unresolved commercial disputes resulted in need of an umpire.
1994-96
Transfer of RLDCs from CEA to
POWERGRID.
1997-99
Unbundling of SEBs , possible entry
of Mega IPPs and more independent
players - more scope for disputes.
DEVELOPMENT OF IEGC
Feb 1999
Special Working Group Under Shri D.P. Sinha,
Member CERC Submits Its Report Indicating
Modalities for Formulating IEGC.
31st Mar 99
CERC issues directives to POWERGRID for
preparing IEGC and organisational
arrangements for the CTU.
9th April 99
Draft IEGC submitted to CERC (Petition 1/99).
Apr-May 99 Draft IEGC made public on the directions of
CERC to elicit comments from all sections.
DEVELOPMENT OF IEGC
July 1999
Public hearings by CERC on the draft IEGC
on 20th, 21st & 23rd July 1999.
30th Aug 99
Revised IEGC draft submitted by
POWERGRID to CERC.
30th Oct 99& CERC’s orders on above IEGC draft (Aug. 99
22nd Nov 99 Version)
7th Dec 99
IEGC draft (Aug. 99 Version) revised as per
above orders and filed before CERC.
DEVELOPMENT OF IEGC
21st Dec 99 Final directions of CERC on the above IEGC
draft.
28th Dec 99 First version of IEGC as per above orders and
circulated to all agencies & implemented
w.e.from 1st Feb 2000
24th July
2000
IEGC Review Panel constitution approved
by CERC
17th Nov
2000
Rules & Guidelines of IEGC Review Panel
approved by CERC
DEVELOPMENT OF IEGC
29th March
2001
Amendments to IEGC forwarded by
Review Panel to CERC after meetings on
12th Feb & 26th March 2001
22nd Feb
2002
First review of IEGC approved by CERC
based on the draft submitted by CTU based
on orders dated 3rd Aug 2001 and
of Review Panel on 10th Dec
meeting
2001.
1st April
2002
First review of IEGC in force.
Indian Electricity Grid Code
Chapter – 1 --- General
Chapter – 2 --- Role of RLDC, REB, CTU etc.
and their organisational linkages
Chapter – 3 --- Planning Code for Interstate
transmission
Chapter – 4 --- Connection conditions
Chapter – 5 --- Grant of transmission license
Indian Electricity Grid Code
Chapter – 6 --- Operating Code for
Regional Grids
Chapter – 7 --- Scheduling & Despatch
Code
Annex – 1 --- Complementary
Commercial Mechanisms
Annex – 2 --- Metering Details
Chapter – 8 --- Management of IEGC
CHAPTER – 1
GENERAL
Objective of IEGC :The IEGC is a Compendium of Technical Rules, covering
all utilities connected to or using the Inter-state
Transmission System (ISTS) and provides the following :

Documentation of the principles and procedures defining
the relationship between the various users of the ISTS as well
as the RLDCs & SLDCs.

Facilitates the Operation, Maintenance, Development
and Planning of Economic and Reliable Regional Grid.

Facilitates beneficial trading of electricity by defining a
common basis of operation of the ISTS, applicable to all the
users of the ISTS.
CHAPTER – 1
GENERAL
Scope of IEGC :
Applicable to all parties that connect with
and/or utilise the ISTS.

DVC treated similar as STU/SEB.

BBMB Generating Stations treated as Intra-State
while its Transmission System treated as ISTS.
CHAPTER – 1
GENERAL
Non - Compliance of IEGC :
Persistent non - compliance of any stipulation of IEGC by
Constituent / ISGS / CTU shall be reported to Member
Secretary, REB.

Non – compliance of IEGC stipulations by RLDC / REB shall be
reported to CEA.

MS - REB / CEA would take up the matter with the defaulting
agency for terminating non - compliance.

In case of inadequate response to above efforts by MS REB/CEA,
non - compliance shall be reported to CERC.

CERC after due process may order the defaulting agency for
compliance.
CEA/REB SHALL MAINTAIN APPROPRIATE RECORDS OF SUCH VIOLATIONS.
GENERAL
CHAPTER – 1
KEYWORDS / DEFINITIONS
FREQUENCY VARIATION INDEX (FVI) :A performance index representing the degree
of frequency variation from the nominal value
of 50 Hz, over a specified period of time.
N
∑ (Fi – 50)2
i=1
FVI = 10 X ----------------------------N
where,
Fi
=
Actual Frequency in Hz at ith time period,
N
=
Number of measurements over the
specified period of time.
CHAPTER – 1
GENERAL
KEYWORDS / DEFINITIONS
INTER STATE GENERATING STATION (ISGS) :A Central / Mega Power Project/ other Generating
Station in which two or more than two states
have a share and whose scheduling is to be
coordinated by the RLDC.
CHAPTER – 1
GENERAL
KEYWORDS / DEFINITIONS
INTER STATE TRANSMISSION SYSTEM (ISTS) :Any system for the conveyance of energy by the
of a main transmission line from the territory of one
another state and
includes :
means
state to

The conveyance of energy across the territory of an intervening
state as well as
conveyance within the state which is incidental
to such interstate transmission of energy.

The transmission of energy within the territory of a state on a
system built, owned, operated, maintained or controlled by the
Central Transmission Utility (CTU) or by any person /agency under
the supervision and control of a CTU.
CHAPTER – 1
GENERAL
KEYWORDS / DEFINITIONS
STANDING COMMITTEE FOR TRANSMISSION PLANNING :
A committee constituted by the CEA to discuss,
review and finalise the proposals for ISTS and
associated Intra-State Systems.
CHAPTER – 2
ROLE OF RLDC, REB, CTU ETC.
AND THEIR ORGANISATIONAL
LINKAGES
A. Role of RLDCs :EXTRACTS FROM ‘ELECTRICITY SUPPLY ACT, 1948’ –

RLDCs Shall be the Apex body to ensure
integrated operation of the Power System in the
concerned Region.

RLDCs may give such directions and exercise
such supervision and control as may be required
for ensuring integrated grid operations and for
achieving the maximum economy and efficiency in
the operation of the Power System in the Region
under its control.
CHAPTER – 2
ROLE OF RLDC, REB, CTU ETC.
AND THEIR ORGANISATIONAL
LINKAGES
A. Role of RLDCs :EXCLUSIVE FUNCTIONS OF RLDC AS DEFINED IN IEGC





System operation and control including Inter State / Inter - Regional transfer of power, covering
contingency analysis and operational planning,
on real time basis.
Scheduling / Rescheduling of Generation.
System restoration following grid disturbances.
Metering and data collection
Compiling and furnishing data pertaining to
system operation.
CHAPTER – 2
ROLE OF RLDC, REB, CTU ETC.
AND THEIR ORGANISATIONAL
LINKAGES
B. Role of REBs :Subject to the provisions of Sections 55(1) to 55 (6)
of the ES Act 1948,
REBs in the Region may mutually agree from time
to time on matters concerning the smooth
operation of the Power System in that Region and
every agency involved in the operation of the
Power System shall comply with the decision of
the Regional Electricity Boards.
CHAPTER – 2
ROLE OF RLDC, REB, CTU ETC.
AND THEIR ORGANISATIONAL
LINKAGES
A. Role of REBs :Functions of REB which facilitate the smooth operation :
Operational planning including planning of
outages of Generators and Transmission System

Co-ordination of protection system

Finalisation of Automatic Under - Frequency Load
Shedding Scheme

Regional Energy Accounting including operation
of the Pool Account
CHAPTER – 2
ROLE OF RLDC, REB, CTU ETC.
AND THEIR ORGANISATIONAL
LINKAGES
A. Role of REBs :Functions of REB which facilitate the smooth operation :
Exploring possibilities of Inter – State / Inter Regional transfer of power

To review reactive compensation to be provided
by various agencies at regular intervals say on a
yearly basis through studies carried out in
association with the CTU and other constituents
CHAPTER – 2
ROLE OF RLDC, REB, CTU ETC.
AND THEIR ORGANISATIONAL
LINKAGES
C. Role of CTU :
To undertake transmission of energy through ISTS

To discharge all functions of planning and coordination related to ISTS with STUs, GoI, State
Govt., Gen. Cos, REBs, CEA and Licensees.

To exercise supervision and control over the ISTS
(for systems owned, operated and maintained by
it as well as transmission licensees)
CHAPTER – 2
ROLE OF RLDC, REB, CTU ETC.
AND THEIR ORGANISATIONAL
LINKAGES
C. Role of CTU :
To operate the RLDCs until otherwise specified by
the Central Government.

To enter into agreements with any transmission
licensee for exclusive use of
the latter’s
Transmission System.
ROLE OF RLDC, REB, CTU ETC.
AND THEIR ORGANISATIONAL
LINKAGES
D. Role of CEA :-
CHAPTER – 2
Subject to regulations made under the ERC Act,1998
by the Central Commission in the case of RLDCs
and
the State Commission in case of SLDCs, any dispute with
reference to the operation of the Power System
including grid operation and as to whether any
directions issued by RLDC under subsection 55(3) or
55(4) of the amended ES Act, 1948 is reasonable or not,
shall be referred to the Authority for decision.
Provided that pending the decision of the Authority, the
directions of the RLDC or the SLDCs, as the case may be,
shall be complied with.
CHAPTER – 2
ROLE OF RLDC, REB, CTU ETC.
AND THEIR ORGANISATIONAL
LINKAGES
D. Role of SLDC :
Demand Estimation & Control

Scheduling of own generation

Scheduling of ISGS limited to entitlements

Ensure compliance of directions of RLDC by all
constituents

Reporting of events to RLDC

System operation & Control
CHAPTER – 3
PLANNING CODE FOR ISTS
Objectives :
Specify principles, procedures and criteria which
shall be used in development of ISTS.

Promote coordination amongst all
constituents in any development of ISTS.

Provide methodology for information exchange
amongst regional constituents in planning and
development of ISTS.
regional
Scope :
Applicable to all utilities using the ISTS and
involved in its development.
CHAPTER – 3
PLANNING CODE FOR ISTS
Planning Methodology :
CEA to develop and update perspective
transmission plan (10-15 yrs) for ISTS as well as
Intra - State.

CTU to develop annually Five Year Plans fitting into
the above perspective plan.

System strengthening schemes to be identified
additionally by CTU in consultation with CEA.

ISTS proposals to be discussed, reviewed and
finalised in the meeting of the ‘Standing
Committee for Transmission System Planning'
constituted by CEA for each Region.
CHAPTER – 3
PLANNING CODE FOR ISTS
Planning Methodology :
CTU Five Year Plan to be finalised by 30th
September each year comprising interalia
•
•
•
additional equipment such as ICTs,
Capacitors, Ractors etc.
Schemes open for private investors.
Action taken and progress of schemes.
STUs should plan their system based on the CTU 5
Year Plan.
CHAPTER – 3
PLANNING CODE FOR ISTS
Planning Criteria :
ISTS shall be capable of withstanding and be
secured against the following outages without
necessitating load shedding or rescheduling of
generation during steady state operation.
Outage of a 132 kV D/C line
or
Outage of a 220 kV D/C line
or
Outage of a 400 kV S/C line
or
Outage of a single ICT
Continued …..
CHAPTER – 3
PLANNING CODE FOR ISTS
Planning Criteria :-
or
Outage of one pole of HVDC bipole
or
Outage of 765 kV S/C line

The aforesaid contingencies would be
superimposed over a planned outage of
another 220 kV D/C line or 400 kV S/C line in
another corridor and not emanating from the
same sub-station.

ISTS shall be capable of withstanding the loss
of most severe single system infeed without
loss of stability.
CHAPTER – 3
PLANNING CODE FOR ISTS
Planning Criteria :ANY ONE OF THE AFORESAID EVENTS SHALL
NOT CAUSE
o
loss of supply
o
abnormal frequency on sustained basis
o
unacceptable high or low voltage
o
system instability
o
unacceptable overloading of ISTS elements
CHAPTER – 3
PLANNING CODE FOR ISTS
Planning Data :SEBs/ Utilities/ MPPs/ ISGS/ IPPs to supply
standard planning data to CTU by 31st March
every year in formats as approved by CERC in
August 2001
CHAPTER – 4
CONNECTION CONDITION
Connection conditions specify the minimum technical
and design criteria to be complied with by CTU and
any agency connected to or seeking connection to
ISTS.
Objectives :
Basic rules for connections are complied with to
treat all agencies in a non-discriminatory
manner.

No adverse effects on the new equipment
connected to ISTS, the ISTS and other agency’s
system.
Continued …..
CHAPTER – 4
CONNECTION CONDITION
Objectives :
Clear
identification
of
ownership
and
responsibility for all equipment at the connection
point.
Scope :Applicable to all constituents and agencies
connected to and involved in developing the
ISTS.
CHAPTER – 4
CONNECTION CONDITION
For New Connections :Connection Agreement is a must.
For Existing Connections :Agreement should be in place within one year
i.e. by 01.04.2003. In case of a delay in
finalising the connection conditions, constituent
to approach CERC with a petition along with
CTU’s recommendation/comments. Cost of
modification, if any, shall be borne by
concerned constituent.
CHAPTER – 4
CONNECTION CONDITION
CONNECTION AGREEMENT WOULD INCLUDE :-

A condition requiring both parties to comply with
the IEGC.

Details of connection, technical requirements and
commercial arrangements.

Details of any capital expenditure arising from
reinforcements required, if any.

Site Responsibility Schedule.

General philosophy, guidelines etc. on protection.
CHAPTER – 4
CONNECTION CONDITION
RELEVANT AREAS IN CONNECTION CONDITIONS :-
•
•
•
•
•
•
•
•
•
ISTS parameter variations
Substation equipment
Fault Clearance Times
Generating Units and Power Stations
Reactive Power Compensation
Communication Facilities
System Recording Instruments
Responsibilities for operational safety
Procedure for site access, site operational
activities and maintenance standards
CHAPTER – 4
CONNECTION CONDITION
SCHEDULE OF ASSETS OF REGIONAL GRID :CTU shall submit annually to CERC by 30th
September each year a schedule of
transmission assets which constitute the regional
grid as on 31st March of that year indicating
ownership on which RLDC has operational
control and responsibility
CHAPTER – 5
GRANT OF TRANSMISSION
LICENCE
•
Separate regulations by CERC would govern the
grant of transmission license.
•
This chapter shall not be subject to review by the
IEGC Review Panel.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
COVERING









Operational policy
System security aspects
Demand estimation
Demand control
Periodic reports
Operational liasion
Outage planning
Recovery procedures
Event information
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
OPERATIONAL POLICY :
Primary objective of integrated operation is to
enhance the overall operational economy and
reliability of the entire network.

RLDC shall supervise overall real time operation
of the regional code.

Regional constituents shall comply with this
operating code.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
OPERATIONAL POLICY :
Detailed
internal
operating
procedures
consistent with IEGC to be developed and
maintained by each RLDC.

Qualified and adequately trained personnel at
all locations.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
SYSTEM SECURITY ASPECTS :All regional constituents shall endeavor to
operate their systems in synchronism with each
other at all times.
Deliberate isolation of any part of the grid should
be done only under a grave emergency or
when specifically instructed by RLDC. In case of
such isolation, synchronisation of the isolated
system to be done at the earliest.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
SYSTEM SECURITY ASPECTS :Removal of any trunk element from service to
be done only on RLDC's instructions. Any such
operations under emergency situation to be
informed to RLDC at the earliest.
Trippings of trunk elements to be informed to
RLDC as soon as possible, say within ten minutes
of the event with reason (to the extent
determined) and likely time of restoration.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
SYSTEM SECURITY ASPECTS :Governors, with 3 to 6% droop setting, to be in
normal operation on all generating units
irrespective of ownership, type & size. Any
deviation for units > 50 mw size to be informed to
RLDC along with reason and duration of such
operation.
Suppression of normal governor action, dead
band, time delays introduced through other
control features not to be resorted to.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
SYSTEM SECURITY ASPECTS :All generating units shall normally be capable of
picking up 5% extra load instantaneously (at
least up to 105% MCR) for at least five minutes
when frequency falls due to any contingency.
RLDC’s approval required for any unit > 50 MW
kept in operation without this requirement.
Recommended rate for decrease or increase of
generation through supplementary control is
1.0% per minute or as per manufacturer’s limits.
Faster pick up possible if frequency falls below
49.5 Hz.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
SYSTEM SECURITY ASPECTS :Reduction in generation / increase in load by
100 MW and above suddenly would not be
permitted without prior intimation to and consent
of the RLDC.
AVRs on all generating units to be in service and
PSS (wherever provided) to be properly tuned as
per the plan of CTU. CTU will be allowed to carry
out tuning / checking of PSS wherever
considered necessary.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
SYSTEM SECURITY ASPECTS :Provision of protection and relay settings to be
coordinated periodically by the protection
committee of the REB.
Constituents to endeavor operation of system
between 49.0 - 50.5 Hz, the frequency range
within which all steam turbines conforming to IEC
standards can safely operate.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
SYSTEM SECURITY ASPECTS :All regional constituents to provide automatic
under frequency relay load-shedding in their
respective systems as finalised by REB.
Constituents to ensure that the scheme is
functional. No u/f relay to be bypassed without
RLDC's prior consent, who shall also promptly
inform REB about the locations where these
relays are temporarily out. Periodic inspection of
u/f relays to be done by REBs who shall also
maintain proper records of such inspection.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
SYSTEM SECURITY ASPECTS :Procedures to recover from partial / total
collapse of the grid to be developed and
followed by all constituents.
Adequate and reliable communication facility
internally and with other constituents / RLDC to
be provided by all constituents.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
SYSTEM SECURITY ASPECTS :All
regional
constituents
shall
send
all
information / data, including DR/SER output, to
RLDC for analysis of any grid disturbance / event.
Access by RLDC to such information should not be
blocked by any constituent.
Grid voltage should always be maintained within
the operating range
NOMINAL(kV)
400
220
132
MAX. (kV)
420
245
145
MIN. (kV)
360
200
120
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
DEMAND ESTIMATION
(Daily/Weekly/Monthly/Annually)
DEMAND CONTROL
(including manual disconnection)
Continued …..
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
PERIODIC REPORTS
Weekly report shall be issued by RLDC to all
constituents and REB Secretariat covering for the
past week
•
•
•
•
•
Frequency profile
Voltage profile
Major generation and transmission outages
Transmission constraints
Instances of persistent / significant non compliance of IEGC.
Continued …..
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
OTHER REPORTS
RLDC to prepare quarterly report, bringing out
System constraints
Reduction in security standards & quality
of service and reasons thereof.
Actions taken by different agencies
Agencies responsible for constraints
as above.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
OPERATIONAL LIASION PROCEDURE :To facilitate quick transfer of information between
operational staff so as to correlate the required
inputs for optimisation of decision making and
actions.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID
OBJECTIVE
To produce a coordinated Generation
Outage Programme for the Regional Grid
considering all available resources and
constraints.
To minimise surplus or deficits, if any, in the
system requirement of power and energy
and operate system within security
standards.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID
OUTAGE PLANNING PROCESS
All SEBs/STUs, CTU, ISGS to provide REB
Secreteriat
their
proposed
outage
programme of all elements in writing for the
next financial year by 30th November each
year.
Draft outage programme by 31st December
to be brought out by REB Secreteriat.
Continued …..
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID
OUTAGE PLANNING PROCESS
Final outage programme ready by 31st
January latest or as mutually decided in REB
coordination meeting. This programme to
be intimated to all regional
constituents /
RLDC.
Above annual programme to be reviewed
on quarterly and monthly basis by REB
Secreteriat.
Continued …..
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
OUTAGE PLANNING FOR ELEMENTS OF REGIONAL GRID
OUTAGE PLANNING PROCESS
Final approval required from RLDC prior to
availing an outage. RLDC authorised to
defer the planned outage in case of




Major grid disturbance
System isolation
Black out in a constituent state
Any other event affecting system
security
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
RECOVERY PROCEDURES
Detailed plans & procedures for restoration
of the Grid to be developed by RLDC in
consultation with all regional constituents /
REB Secreteriat
and to be reviewed /
updated annually.
Restoration within the system of each
constituent to be finalised by concerned
constituent in co-ordination with RLDC. To be
reviewed once every year.
Continued …..
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
RECOVERY PROCEDURES
List of Generating Stations with black start
facility, inter-state / inter-regional ties,
synchronising points and essential loads to
be restored on priority to be prepared and
to be available with RLDCs.
For fast recovery, RLDC authorised to
operate system with reduced security
standards for voltage and frequency.
Continued …..
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
RECOVERY PROCEDURES
All communication channels required for
restoration process shall be used for
operational communication only, till grid
normalcy is restored.
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
EVENT INFORMATION
REPORTABLE EVENTS BY RLDC/ REGIONAL CONSTITUENTS
•
•
•
•
•
•
•
•
Violation of security standards
Grid indiscipline
Non-compliance of RLDC's instructions
System islanding/system split
Region black out/partial black out
Protection failure on any element of ISTS,
and on any item on the 'agreed list' of the
intra - state systems
Power system instability
Tripping of any element of the regional grid
CHAPTER – 6
OPERATIONAL CODE FOR
REGIONAL GRIDS
FORM OF WRITTEN REPORTS
•
•
•
•
•
•
•
•
•
•
Time and date of event
Location
Plant and / or equipment directly involved
Description and cause of event
Antecedent conditions
Demand and / or generation (in MW)
interrupted and its duration
All relevant system data including copies of
all DR/EL/DAS outputs
Sequence of trippings with time
Details of relay flags
Remedial measures
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
COVERING

Objective

Scope

Demarcation of responsibilities

Scheduling & Despatch procedure

Reactive Power and Voltage Control
ANNEX
 Complementary Commercial Mechanism
 Metering Details (to be included later)
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
OBJECTIVE :To enable RLDCs to prepare the despatch
schedule for each beneficiary. It also provides
methodology of issuing real time despatch /
drawal instructions and rescheduling, if required,
as also commercial arrangement for the
deviations from schedules and mechanism for
reactive power pricing.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
SCOPE :Applicable to RLDC / SLDCs, ISGS, SEBs / STUs and
other beneficiaries in the Grid.
Procedure for the generating stations of BBMB
shall be separately formulated by NRLDC in
consultation with BBMB.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
DEMARCATION OF RESPONSIBILITIES :-
Regional grid shall be operated as loose
power pools with states having full operational
autonomy.
System of each state shall be treated as a
notional control area. States shall generally be
expected to maintain their actual drawal from
the Regional Grid close to the net drawal
schedule (sum of scheduled drawal from ISGS
and any bilateral inter change).
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
DEMARCATION OF RESPONSIBILITIES :-
Tight control on the deviations from schedule by
states not mandated due to non availability of
requisite facilities for minute – to - minute on line
regulation of drawals. Deviations from schedule
to be priced appropriately.
Whenever system frequency is below 49.5 Hz,
states shall endeavor to restrict their net drawal
to within the schedule. Loadshedding to be
resorted to in case frequency < 49.0 Hz.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
DEMARCATION OF RESPONSIBILITIES :-
SLDCs / STUs to carry out short - term and long term demand estimation to enable advance
planning to meet the consumer’s load without
overdrawing.
ISGS shall be responsible for generating as per
the daily schedule advised by RLDC.
ISGS allowed to deviate from the schedule, in
line with the flexibility allowed to States.
Deviations are to be appropriately priced.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
DEMARCATION OF RESPONSIBILITIES :-
Whenever system frequency > 50.3 Hz, actual net
injection of ISGS should not exceed scheduled
despatch.
RLDC nay direct the SLDCs / ISGS to increase /
decrease their drawal / generation in case of
contingencies and such directions shall be
immediately complied.
Outage of Generation and Transmission system
to be coordinated through OCC / RLDC. Outage
requiring restriction on ISGS generation to be
planned carefully.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
DEMARCATION OF RESPONSIBILITIES :-
Agreements between constituents and ISGS
indicating shares, drawal pattern, tariffs,
payment terms etc. to be filed with RLDCs and
REB Secreteriats for being considered in REA.
Similar filing required in respect of bilateral
agreements.
Frequency linked despatch guidelines, as issued
by RLDC, should be followed by all constituents
unless otherwise advised by RLDC.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
DEMARCATION OF RESPONSIBILITIES :-
ISGS to declare plant capabilities faithfully and
avoid gaming. RLDC may ask the ISGS to explain
instances of gaming, if any, with necessary
backup data.
CTU would be allowed to install Special Energy
Meters on all Inter-Utility Exchange Points and
the constituents would extend the necessary
assistance to CTU in timely collection of metered
data.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
DEMARCATION OF RESPONSIBILITIES :-
RLDC to compute


Actual Net Injection of each ISGS
Actual Net Drawal of each beneficiary
based on above meter readings and forward the
same to REB Secreteriat on weekly basis by each
Thursday noon for the seven day period ending
previous Sunday Mid-Night.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
DEMARCATION OF RESPONSIBILITIES :-
Computations of RLDC open to checking /
verification by constituents for 20 days. In case
any mistake / omission is detected, the RLDC
shall forthwith make a complete check and
rectify the same.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
SCHEDULING AND DESPATCH PROCEDURE
All ISGS stations with capacities and allocated shares to be listed out
By 10.00 hrs.
Each ISGS advises RLDC of its Ex-Power Plant MW and MWh
capabilities anticipated for next day i.e. 00:00 to 24:00 hrs
By 1100 Hrs.
Beneficiaries advised of above information along with their
entitlements
By 1500 hrs.
SLDCs advise RLDC their drawal schedule for each of the ISGS
in which they have share
By 1700 hrs.
RLDC conveys the ‘Ex-Power Plant Despatch Schedule (in
MW)' to each ISGS and ‘Net Drawal Schedule (in MW)' to each
beneficiary (after deducting transmission losses)
By 2200 hrs.*
ISGSs / States / Beneficiaries shall inform the modifications, if
any, for incorporating in the final schedule
By 2300 hrs.
RLDC shall issue the final despatch and drawal schedule.
* Since issuing the final despatch and drawal schedule is a critical activity and
considerable time is involved in its preparation and carrying out requisite
moderation, if any, it is desirable that this activity is completed by 2100 hrs.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
SCHEDULING AND DESPATCH PROCEDURE :RLDC to ensure schedules are operationally
reasonable with respect to ramping up / ramping
down rates and the minimum to maximum ratio of
generation.
ISGS / SLDCs to inform any modifications in
foreseen capability / station wise drawal
schedule to RLDC by 2200 hrs. RLDC to issue
final schedule in such cases by 2300 hrs.
Revisions in schedule permitted during the
course of the day. Such revisions effective one
hour after the first advise is received by the
RLDC.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
SCHEDULING AND DESPATCH PROCEDURE :RLDC to check for transmission constraints, if
any, before finalising the drawal / despatch
schedule.
On completion of the operating day, schedule, as
finally implemented during the day shall be
issued by RLDC. This would be the datum for
commercial accounting.
RLDC to properly document all the above
information exchanged between ISGS and RLDC,
constituents and RLDC etc.
REVISION OF SCHEDULES
S.no.
Event
Revision effective from
1.
Forced outage of an ISGS
unit.
4th
time
block
after
generator advises NRLDC of
change in declared capability.
2.
Transmission constraint
3.
Revision of ISGS capability
4th time block + post facto
revisions for first three time
blocks.
6th time block.
4.
Revision of requisition by any
beneficiary
6th time block
5.
Suo-moto
NRLDC
4th time block.
revisions
by
Note:
In all the above cases, the 15 minute time block in which NRLDC receives the above
advise would be considered as the first one.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
SCHEDULING AND DESPATCH PROCEDURE :-
All records in respect of above open to all
constituents for any checking / verification for a
period of 20 days.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
REACTIVE POWER AND VOLTAGE CONTROL :Beneficiaries
to
provide
local
VAR
compensation / generation so as not to draw
VARs from EHV grid. Tight control not being
insisted upon presently. However, VAR pricing for
beneficiaries would be as under :




pay for VAR drawal at points where
voltage < 97%
get paid for VAR return at points where
voltage < 97%
get paid for VAR drawal at points where
voltage > 103%
pay for VAR return at points where voltage
> 103%
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
REACTIVE POWER AND VOLTAGE CONTROL :Charges / payments for VARs - 4 paise/kVARh
upto 31st March, 2001 and escalated at 5% per
year thereafter unless otherwise revised by CERC.
RLDC may direct a beneficiary to curtail its VAR
drawal / injection in case of threat to equipment
safety / grid security.
Switching IN / OUT of Bus / Line Reactors of 400
kV lines and tap changing of 400 / 220 kV ICTs to
be done as per RLDC instructions only.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
REACTIVE POWER AND VOLTAGE CONTROL :ISGS to generate / absorb Reactive Power as per
RLDC instructions taking into account capability
limits and without sacrificing active generation
required. No payments to generating companies
for such VAR generation / absorption.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
COMPLEMENTARY COMMERCIAL MECHANISMS :Payments to ISGS from beneficiaries :

Capacity charge based on declared
(before the fact) ex-power plant capability
and entitlement of beneficiary

Energy charge (rupees per MWh) based
on schedule drawals
Payments to / from UI settlement system based
on Unscheduled Interchange (UI) and frequency.
CHAPTER – 7
SCHEDULING AND DESPATCH CODE
COMPLEMENTARY COMMERCIAL MECHANISMS :REA to be prepared by REB Secreteriat on weekly
basis based on Special Energy Meter (SEM) data
provided by RLDCs.
Weekly bills for UI and Reactive Exchanges to be
raised by REB Secreteriat. These bills to have
higher priority.
CHAPTER – 8
MANAGEMENT OF IEGC
OBJECTIVES :Methodology of managing the IEGC document,
pursuing of any change / modifications required
and constituents responsibility to effect that
change.
CHAPTER – 8
MANAGEMENT OF IEGC
SCOPE :CTU responsible for coordinating, managing and
servicing the IEGC document
IEGC Review Panel to consider proposals for
modifications
Decision of review panel to be put upto CERC
CHAPTER – 8
MANAGEMENT OF IEGC
IEGC REVIEW PANEL :To be constituted
representative from
01.
02.
03.
04.
05.
06.
07.
08.
09.
10.
by
CERC
comprising
one
CEA
NTPC
NHPC
NPC
Two from each REB representing the constituents
PTC
One representative from Mega Power Projects
One representative from Railways / Steel / Coal
One representative from CII / FICCI / ASSOCHAM
One representative from CERC as an observer
CHAPTER – 8
MANAGEMENT OF IEGC
IEGC REVIEW PANEL :-
Director (Operations), POWERGRID shall be the
Chairman and Convener of the Panel and preside over
its meetings.
Back
Thank You
Central Govt.
CEA
REB
CERC
State Govt.
SEB/STU
CTU
G1
RLDC
SLDC
SERC
G2
Intra State
System
ISTS
ISGS
Load
X=
L - G
G L1
L2
IEGC to Operate
on the periphery
CONTROL AREAS
CS - 2
CS - 1
CS - 3
RLDC
COORDINATES/
REGIONAL GRID
SEB-A
STATE
IPP
SEB-B
STATE
GENR.
SEB-C
CENTRAL
SHARE
SLDC
COORDINATES/
DIRECTS
SEB's GRID
DISTR - A
DISTR - C
DISTR - B