Extract from GRID CODE of importance to RLDCs

iv) Operating Code for Regional Grids
This Chapter describes the operational philosophy to maintain
efficient, secure and reliable Grid Operation and contains the following
sections.
(a) Operating Policy
(b) System security aspects


This section describes the general security aspects
to be followed by generating companies and all Regional
Constituents of the Grid.
(c) Demand Estimation for operational purposes
This section details the procedures to estimate the
demand by the various constituents for their systems for
the day/week/month/year ahead, which shall be used for
operational planning.


(d) Demand management
This section identifies the methodology to be adopted
for demand control by each regional constituent as a
function of the frequency and deficit generation.


(e) Periodic Reports
This section provides various provisions for reporting
of the operating parameters of the grid such as frequency
profile etc.


(f) Operational liaison
This section sets out the requirement for the
exchange of information in relation to normal operation
and/or events in the grid.


(g) Outage Planning
This section indicates procedure for outage planning.


(h) Recovery procedures
This section contains the procedures to be adopted
following a major grid disturbance, for black start and
resynchronization of islands, etc.


(i) Event Information
This section indicates the procedure by which events
are reported and the information exchange etc. takes place.


v) Scheduling & Despatch Code
This section deals with the procedure to be adopted for
scheduling and despatch of generation of the Inter-State
Generating Stations (ISGS) including complementary commercial
mechanisms, on a daily basis with the modality of the flow of
information between the ISGS, Regional Load Despatch Centre
(RLDC) and the State Load Despatch Centres (SLDCs).


vi) Inter-Regional Exchanges
This Chapter deals with special considerations for
operation of inter-regional links.


vii) Management of IEGC
This Chapter deals with the procedure for
review/amendment and management of IEGC.


1.5 Non-compliance
In case of a persistent non-compliance of any of the
stipulations of the IEGC by a constituent or an agency (other than
RPC and RLDC), the matter shall be reported by any
agency/RLDC to the Member Secretary, RPC.

The Member
Secretary, RPC, shall verify and take up the matter with the
defaulting agency for expeditious termination of the noncompliance.
In case of inadequate response to the efforts made
by the Member Secretary, RPC, the non-compliance shall be
reported to CERC. CERC, in turn after due process, may order
the defaulting agency for compliance, failing which; the CERC
may take appropriate action.


RPC shall maintain appropriate records of such violations.
In case of a non-compliance of any of the stipulations of the
IEGC by RLDC or RPC, the matter shall be reported to the
CERC.


1.6 Free Governor Action
i) All thermal and hydro (except those with zero pondage)
generating units : with effect from the date to be separately
notified by the Commission.
ii) Any exemption from the above may be granted only by CERC for
which the concerned constituent/ agency shall file a petition in
advance.
iii) The Gas turbine/Combined Cycle Power Plants and Nuclear
Power Stations shall be exempted from Sections 4.8 (c), 4.8 (d),
5.2 (e), 5.2 (f), 5.2 (g) and 5.2 (h) till the Commission reviews the
situation.



IEGC 8
1.7 Charge/Payment for Reactive Energy Exchanges
The rate for charge/payment of reactive energy exchanges
(according to the scheme specified in section 6.6 shall be 5.0
paise/kVArh w.e.f 01.04.2006, and shall be escalated at 0.25
paise/kVArh per year thereafter, unless otherwise revised by the
CERC.



1.8 Exemptions
Any exemption from provisions of IEGC shall become effective
only after approval of the Commission, for which the agencies will have
to file a petition in advance.










2.2. Role of RLDCs
2.2.1 According to sections 28 and 29 of Electricity Act, 2003, the functions
of RLDCs are as follows:
(1) The Regional Load Despatch Centre shall be the apex body to
ensure integrated operation of the power system in the
concerned region.
(2) The Regional Load Despatch Centre shall comply with such
principles, guidelines and methodologies in respect of wheeling
and optimum scheduling and despatch of electricity as may be
specified in the Grid Code.
(3) The Regional Load Despatch Centre shall-
(a) be responsible for optimum scheduling and despatch of
electricity within the region, in accordance with the
contracts entered into with the licensees or the
generating companies operating in the region;
(b) monitor grid operations;
(c) keep accounts of quantity of electricity transmitted
through the regional grid;
(d) exercise supervision and control over the Inter-State
transmission system ; and
(e) be responsible for carrying out real time operations for
grid control and despatch of electricity within the region
through secure and economic operation of the regional
grid in accordance with the Grid Standards and the Grid
Code.
(4) The Regional Load Despatch Centre may give such directions
and exercise such supervision and control as may be 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.
(5) Every licensee, generating company, generating station, substation
and any other person connected with the operation of
the power system shall comply with the directions issued by the
Regional Load Despatch Centres.
IEGC 18
(6) All directions issued by the Regional Load Despatch Centres to
any transmission licensee of State transmission lines or any
other licensee of the State or generating company (other than
those connected to inter-State transmission system) or substation
in the State shall be issued through the State Load
Despatch Centre and the State Load Despatch Centres shall
ensure that such directions are duly complied with by the
licensee or generating company or sub-station.
(7) If any dispute arises with reference to the quality of electricity or
safe, secure and integrated operation of the regional grid or in
relation to any direction given by the Regional Load Despatch
Centre, it shall be referred to Central Commission for decision.
However, pending the decision of the Central Commission, the
directions of the Regional Load Despatch Centre shall be
complied with by the State Load Despatch Centre or the
licensee or the generating company, as the case may be.
2.2.2 The following are contemplated as exclusive functions of RLDCs

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


(2) Scheduling / re-scheduling of generation;
(3) System restoration following grid disturbances;
(4) Metering and data collection;


(5) Compiling and furnishing data pertaining to system operation;
(6) Operation of regional UI pool account and regional reactive
energy account.


2.2.3 In case of Open access in Inter-state Transmission, the Regional Load
Despatch Centre of the region where point of drawal of electricity is
situate, shall be the nodal agency for the short-term transmission
access. The procedure and modalities in regard to short-term Open
Access shall be as per the Central Electricity Regulatory Commission
(Open Access in Inter-state Transmission) Regulations, 2004, as
amended from time to time.






2.3 Role of RPC
2.3.1 RPCs have been constituted by resolutions dated 25.5.2005 of Central
Government for the specified Region(s) for facilitating the integrated
operation of the power system in the Region. The Secretariat of the
Board is headed by the Member Secretary who is appointed by the
Central Electricity Authority (CEA), together with the other staff for the
RPC Secretariat. Under section 29(4) of the Electricity Act,2003, the
Regional Power Committee in the region may, from time to time, agree
on matters concerning the stability and smooth operation of the
integrated grid and economy and efficiency in the operation of the
power system in that region.
IEGC 19
2.3.2 The following functions which go to facilitate the stability and smooth
operation of the systems are identified for the RPC:
i) To undertake Regional Level operation analysis for improving grid
performance.
ii) To facilitate inter-state/inter-regional transfer of power.
iii) To facilitate all functions of planning relating to inter-state/ intrastate
transmission system with CTU/STU.
iv) To coordinate planning of maintenance of generating machines of
various generating companies of the region including those of interstate
generating companies supplying electricity to the Region on
annual basis and also to undertake review of maintenance
programmed on monthly basis.
v) To undertake planning of outage of transmission system on monthly
basis.
vi) To undertake operational planning studies including protection
studies for stable operation of the grid.
vii) To undertake planning for maintaining proper voltages through
review of reactive compensation requirement through system study
committee and monitoring of installed capacitors.
viii) To evolve consensus on all issues relating to economy and
efficiency in the operation of power system in the region.
2.3.3 The decision of RPC arrived at by consensus regarding operation of
the regional grid and scheduling and dispatch of electricity will be
followed by RLDC subject to directions of the Central Commission, if
any.
.
2.3.4 All complaints regarding unfair practices, delays, discrimination, lack of
information, supply of wrong information or any other matter related to
open access in inter-state transmission shall be directed to the Member
Secretary, RPC of the region in which the authority against whom the
complaint is made, is located. The Member Secretary, RPC shall
investigate and endeavour to resolve the grievance. In case the
Member Secretary, RPC is unable to resolve the matter, it shall be
reported to the Central Commission for a decision.
2.3.5 Member Secretary, RPC shall, for the purpose of payment of
transmission charges/ capacity charges and incentives, certify:
(1) Availability of Regional Ac and HVDC transmission system
(2) Availability and Plant Load Factor for ISGS (Thermal)
(3) Capacity Index for ISGS (Hydro)








4.10 Data and Communication Facilities
Reliable and efficient speech and data communication systems shall
be provided to facilitate necessary communication and data exchange,
and supervision/control of the grid by the RLDC, under normal and
abnormal conditions. All agencies shall 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 to RLDC / SLDC. The associated
communication system to facilitate data flow up to RLDC/SLDC, as the
case may be, shall also be established by the concerned agency as
specified by CTU in connection agreement. All agencies in coordination
with CTU shall provide the required facilities at their respective ends
and RLDC / SLDC as specified in the connection agreement.
4.11 System Recording Instruments
Recording instruments such as Data Acquisition System/Disturbance
Recorder/Event Logger/Fault Locator (including time synchronization
equipment) shall be provided in the ISTS for recording of dynamic
performance of the system. Agencies shall provide all the requisite
recording instruments as specified in the connection agreement
according to the agreed time schedule.
4.12 Responsibilities for operational safety
CTU/Transmission licensee and the Regional Constituents/agency
concerned shall be responsible for safety as indicated in Site
Responsibility Schedules for each connection point.
(a) Site Responsibility Schedules
i) A Site Responsibility Schedule shall be produced by the CTU/
transmission license and agency detailing the ownership
responsibilities of each, before execution of the project or
connection including safety responsibilities.
For connection to the ISTS a schedule shall be prepared by
CTU/transmission licensee pursuant to the relevant Connection
Agreement which shall state for each item of plant and
apparatus at the connection point the following:
- Ownership of the Plant/Apparatus
IEGC 34
- Responsibility for control of the Plant/Apparatus
- Responsibility for operation of the Plant/Apparatus.
- Responsibility for maintenance of the Plant/Apparatus and
- Responsibility for all matters relating to the safety of any
person
at the connection point.
ii) The format, principles and basic procedure to be used in the
preparation of Site Responsibility Schedules shall be formulated
by CTU and shall be provided to each agency/regional
constituents for compliance.
iii) All agencies connected to or planning to connect to ISTS would
ensure providing of RTU and other communication equipment,
as specified by RLDC/SLDC, for sending real-time data to
SLDC/RLDC at least before date of commercial operation of the
generating stations or sub-station/line being connected to ISTS.
(b) Single Line Diagrams
i) Single Line Diagram shall be furnished for each Connection
Point by the connected agencies to RLDC. These diagrams
shall include all HV connected equipment and the connections
to all external circuits and incorporate numbering, nomenclature
and labelling, etc. The diagram is intended to provide an
accurate record of the layout and circuit connections, rating,
numbering and nomenclature of HV apparatus and related plant.
ii) Whenever any equipment has been proposed to be changed,
then concerned agency shall intimate the necessary changes to
CTU and to all concerned. When the changes are implemented,
changed Single Line Diagram shall be circulated by the agency
to RLDC/CTU.
(c) Site Common Drawings
i) Site Common Drawing will be prepared for each Connection
Point and will include site layout, electrical layout, details of
protection and common services drawings. Necessary details
shall be provided by the agencies to CTU.
ii) The detailed drawings for the portion of the agency and CTU/
transmission licensee at each Connection Point shall be
prepared individually and copies shall be handed over to other
party.
iii) If any change in the drawing is found necessary, the details will be
furnished to other party as soon as possible.
IEGC 35
4.13 Procedure for Site Access, Site operational activities and
Maintenance Standards
The Connection Agreement will also indicate any procedure necessary
for Site access, Site operational activities and maintenance standard
for equipment of the CTU/ transmission licensee at
ISGS/SEB/STU/licensee premises and vice versa.
4.14 International Connections to ISTS
The procedure for international Connection to ISTS and the execution
of agreement for the same shall be done by CTU in consultation with
CEA and Ministry of Power (MOP).
4.15 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.
IEGC
36
















OPERATING CODE FOR REGIONAL GRIDS
5.1 Operating Policy
(a) The primary objective of integrated operation of the Regional grids
is to enhance the overall operational economy and reliability of the
entire electric power network spread over the geographical area of
the interconnected States. Participant utilities shall cooperate with
each other and adopt Good Utility Practice at all times for
satisfactory and beneficial operation of the Regional grid.
(b) Overall operation of the Regional grid shall be supervised from the
Regional Load Despatch Centre (RLDC). The roles of RLDC and
RPC shall be in accordance with the provisions made in Chapter-2
of the IEGC.
(c) All Regional constituents shall comply with this Operating Code, for
deriving maximum benefits from the integrated operation and for
equitable sharing of obligations.
(d) A set of detailed internal operating procedures for each regional
grid shall be developed and maintained by the respective RLDC in
consultation with the regional constituents and shall be consistent
with IEGC to enable compliance with the requirement of this IEGC.
(e) The control rooms of the RLDC, all SLDCs, power plants,
substation of 132 kV and above, and any other control centres of all
regional constituents shall be manned round the clock by qualified
and adequately trained personnel.
5.2 System Security Aspects
(a) All Regional constituents shall endeavor to operate their respective
power systems and power stations in synchronism with each other
at all times, such that the entire system within a Region operates as
one synchronized system.
(b) No part of the grid shall be deliberately isolated from the rest of the
Regional grid, except (i) under an emergency, and conditions in
which such isolation would prevent a total grid collapse and/or
would enable early restoration of power supply, (ii) when serious
damage to a costly equipment is imminent and such isolation would
prevent it, (iii) when such isolation is specifically instructed by
RLDC. Complete synchronization of grid shall be restored as soon
as the conditions again permit it. The restoration process shall be
supervised by RLDC, as per operating procedures separately
formulated.
IEGC
38
(c) No important element of the 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 of such important grid elements on which the
above stipulations apply shall be prepared by the RLDC in
consultation with the constituents, and be available at
RLDC/SLDCs. In case of opening/removal of any important element
of the grid under an emergency situation, the same shall be
communicated to RLDC at the earliest possible time after the event.
(d) Any tripping, whether manual or automatic, of any of the above
elements of Regional grid shall be precisely intimated by the
concerned State LDC/agency to RLDC as soon as possible, say
within ten minutes of the event. The reason (to the extent
determined) and the likely time of restoration shall also be
intimated. All reasonable attempts shall be made for the elements’
restoration as soon as possible.
(e) All generating units, which are synchronized with the grid,
irrespective of their ownership, type and size, shall have their
governors in normal operation at all times . If any generating unit of
over fifty (50) MW size (10 MW for North-Eastern Region) is
required to be operated without its governor in normal operation,
the RLDC shall be immediately advised about the reason and
duration of such operation. All governors shall have a droop of
between 3% and 6%.
(f) Facilities available with/in load limiters, Automatic Turbine Run-up
System (ATRS), Turbine supervisory control, coordinated control
system, etc., shall not be used to suppress the normal governor
action in any manner. No dead bands and/or time delays shall be
deliberately introduced.
(g) All Generating Units, operating at or up to 100% of their Maximum
Continuous Rating (MCR) shall normally be capable of (and shall
not in any way be prevented from) instantaneously picking up five
per cent (5%) extra load when frequency falls due to a system
contingency. The generating units operating at above 100% of their
MCR shall be capable of (and shall not be prevented from) going at
least up to 105% of their MCR when frequency falls suddenly. After
an increase in generation as above, a generating unit may ramp
back to the original level at a rate of about one percent (1%) per
minute, in case continued operation at the increased level is not
sustainable. Any generating unit of over fifty (50) MW size (10 MW
for NER) not complying with the above requirements, shall be kept
in operation (synchronized with the Regional grid) only after
obtaining the permission of RLDC. However, a constituent can
make up the corresponding short fall in spinning reserve by
IEGC
39
maintaining an extra spinning reserve on the other generating units
of the constituent.
(h) The recommended rate for changing the governor setting, i.e.,
supplementary control for increasing or decreasing the output
(generation level) for all generating units, irrespective of their type
and size, would be one (1.0) per cent per minute or as per
manufacturer’s limits. However, if frequency falls below 49.5 Hz, all
partly loaded generating units shall pick up additional load at a
faster rate, according to their capability.
(i) Except under an emergency, or to prevent an imminent damage to
a costly equipment, no constituent shall suddenly reduce his
generating unit output by more than one hundred (100) MW (20
MW in case of North-Eastern region) without prior intimation to and
consent of the RLDC, particularly when frequency is falling or is
below 49.0Hz. Similarly, no constituent shall cause a sudden
increase in its load by more than one hundred (100 MW) (20 MW in
case of North-Eastern region) without prior intimation to and
consent of the RLDC.
(j) All generating units shall normally have their automatic voltage
regulators (AVRs) in operation, with appropriate settings. In
particular, if a generating unit of over fifty (50) MW (10 MW in case
of North-Eastern region) size is required to be operated without its
AVR in service, the RLDC shall be immediately intimated about the
reason and duration, and its permission obtained. 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 from time to
time. CTU will be allowed to carry out checking of PSS and further
tuning it, wherever considered necessary.
(k) 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 Committee of the RPC.
(l) All Regional constituents shall make all possible efforts to ensure
that the grid frequency always remains within the 49.0 – 50.5 Hz
band, the frequency range within which steam turbines conforming
to the IEC specifications can safely operate continuously.
(m) All Regional constituents shall provide automatic under-frequency
and df/dt 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
forum, and shall ensure its effective application to prevent cascade
tripping of generating units in case of any contingency. All Regional
constituents shall ensure that the above under-frequency and df/dt
IEGC
40
load shedding/islanding schemes are always functional. However,
in case of extreme contingencies, these relays may be temporarily
kept out of service with prior consent of RLDC. RLDC shall inform
RPC Secretariat about instances when the desired load relief is not
obtained through these relays in real time operation.
RPC Secretariat shall carry out periodic inspection of the under
frequency relays and maintain proper records of the inspection.
(n) All regional constituents shall also facilitate identification,
installation and commissioning of System Protection Schemes
(including inter-tripping and run-back) in the power system to
protect against situations such as voltage collapse and cascading.
Such schemes would be finalized by the concerned RPC forum,
and shall be kept in service. RLDC shall be promptly informed in
case any of these are taken out of service.
(o) Procedures shall be developed to recover from partial/total collapse
of the grid and periodically updated in accordance with the
requirements given under section 5.8. These procedures shall be
followed by all the Regional constituents to ensure consistent,
reliable and quick restoration.
(p) Each Regional constituent shall provide adequate and reliable
communication facility internally and with other constituents/RLDC
to ensure exchange of data/information necessary to maintain
reliability and security of the grid. Wherever possible, redundancy
and alternate path shall be maintained for communication along
important routes, e.g., SLDC to RLDC.
(q) The Regional constituents shall send information/data including
disturbance recorder/sequential event recorder output etc., to
RLDC for purpose of analysis of any grid disturbance/event. No
Regional constituent shall block any data/information required by
the RLDC for maintaining reliability and security of the grid and for
analysis of an event.
(r) All regional constituents shall make all possible efforts to ensure
that the grid voltage always remains within the following operating
range.
------------------------------------------------------------------
VOLTAGE – (KV rms)
------------------------------------------------------------------
Nominal Maximum Minimum
400 420 360
220 245 200
132 145 120
------------------------------------------------------------------
IEGC
41
5.3 Demand Estimation for Operational Purposes
5.3.1 Introduction
(a) This section describes the procedures/responsibilities of the SLDCs for
demand estimation for both Active Power and Reactive Power.
(b) The demand estimation is to be done on daily/weekly/monthly basis for
current year.
(c) Each SLDC shall carry out its own demand estimation from the historical
data and weather forecast data from time to time.
(d) While the demand estimation for operational purposes is to be done on a
daily/weekly/monthly basis initially, mechanisms and facilities at SLDCs
shall be created at the earliest to facilitate on-line estimation for daily
operational use.
5.3.2 Objective
(a) The objective of this procedure is to enable the SLDCs to estimate their
demand over a particular period.
(b) The demand estimates are to enable the SLDC to conduct system studies
for operational planning purposes.
5.3.3 Procedure
Each State/SLDC shall develop methodologies/mechanisms for daily/
weekly/monthly/yearly demand estimation (MW, MVAr and MWh) for
operational purposes. The data for the estimation shall also include load
shedding, power cuts, etc. SLDCs shall also maintain historical database
for demand estimation.
5.4 Demand Management
5.4.1 Introduction
This section is concerned with the provisions to be made by SLDCs to
effect a reduction of demand in the event of insufficient generating
capacity, and transfers from external interconnections being not available
to meet demand, or in the event of breakdown or operating problems
(such as frequency, voltage levels or thermal overloads) on any part of the
grid.
IEGC
42
5.4.2 Manual Demand Disconnection
(a) As mentioned elsewhere, the constituents shall endeavour to restrict their
net drawal from the grid to within their respective drawal schedules
whenever the system frequency is below 49.5 Hz. When the frequency
falls below 49.0 Hz, requisite load shedding (manual) shall be carried out
in the concerned State to curtail the over-drawal.
(b) Further, in case of certain contingencies and/or threat to system security,
the RLDC may direct an SLDC to decrease its drawal by a certain
quantum. Such directions shall immediately be acted upon.
(c) Each Regional constituent shall make arrangements that will enable
manual demand disconnection to take place, as instructed by the
RLDC/SLDC, under normal and/or contingent conditions.
(d) The measures taken to reduce the constituents’ drawal from the grid shall
not be withdrawn as long as the frequency/voltage remains at a low level,
unless specifically permitted by the RLDC.
5.5 Periodic Reports
5.5.1 A weekly report shall be issued by RLDC to all constituents of the Region
and RPC Secretariat and shall cover the performance of the Regional grid
for the previous week. Such weekly report shall also be available on the
website of the RLDC concerned for at least 12 weeks.
The weekly report shall contain the following:-
(a) Frequency profile
(b) Voltage profile of selected substations
(c) Major Generation and Transmission Outages
(d) Transmission Constraints
(e) Instances of persistent/significant non-compliance of IEGC.
5.5.2 Other Reports
(a) The RLDC shall prepare a quarterly report which shall bring out the
system constraints, reasons for not meeting the requirements, if any, of
security standards and quality of service, along with details of various
actions taken by different agencies, and the agencies responsible for
causing the constraints.
(b) The RLDC shall also provide information/report which can be called for by
RPC in the interest of smooth operation of ISTS.
IEGC
43
5.6 Operational Liaison
5.6.1 Introduction
(a) This section sets out the requirements for the exchange of
information in relation to Operations and/or Events on the total grid
system which have had or will have an effect on:
1. The Regional grid
2. The ISTS in the Region
3. The system of a Regional constituent
The above generally relates to notifying of what is expected to
happen or what has happened and not the reasons why.
(b) The Operational liaison function is a mandatory built-in hierarchical
function of the RLDC and Regional constituents, to facilitate quick
transfer of information to operational staff. It will correlate the
required inputs for optimization of decision making and actions.
5.6.2 Procedure for Operational Liaison
(a) Operations and events on the Regional grid
• Before any Operation is carried out on Regional grid, the RLDC will inform
each Regional constituent, whose system may, or will, experience an
operational effect, and give details of the operation to be carried out.
• Immediately following an event on Regional grid, the RLDC will inform
each Regional Constituent, whose system may, or will, experience an
operational effect following the event, and give details of what has
happened in the event but not the reasons why.
(b) Operations and events on a Constituent’s system.
• Before any operation is carried out on a constituent’s system, the
constituent will inform the RLDC, in case the Regional grid may, or will,
experience an Operational effect, and give details of the operation to be
carried out.
• Immediately following an event on a constituent’s system, the constituent
will inform the RLDC, in case the Regional grid may, or will, experience an
operational effect following the event, and give details of what has
happened in the event but not the reasons why.
IEGC
44
5.7 Outage Planning
5.7.1 Introduction
a) This section sets out the procedure for preparation of outage schedules for
the elements of the Regional grid in a coordinated and optimal manner
keeping in view the Regional system operating conditions and the balance
of generation and demand. (List of elements of grid covered under these
stipulations shall be prepared and be available with RLDC and SLDCs).
b) The generation output and transmission system should be adequate after
taking into account the outages to achieve the security standards.
c) Annual outage plan shall be prepared in advance for the financial year by
the RPC Secretariat and reviewed during the year on quarterly and
Monthly basis.
5.7.2 Objective
a) To produce a coordinated generation outage programme for the Regional
grid, considering all the available resources and taking into account
transmission constraints, as well as, irrigational requirements.
b) To minimise surplus or deficits, if any, in the system requirement of power
and energy and help operate system within Security Standards.
c) To optimize the transmission outages of the elements of the Regional grid
without adversely affecting the grid operation but taking into account the
Generation Outage Schedule, outages of SEB/STU systems and
maintaining system security standards.
5.7.3 Scope
This section is applicable to all Regional constituents including RLDC,
SLDCs, SEBs/STUs, ISGS and CTU.
5.7.4 Outage Planning Process
a) The RPC Secretariat shall be responsible for analyzing the outage
schedule given by all Regional Constituents, preparing a draft annual
outage schedule and finalization of the annual outage plan for the
following financial year by 31st January of each year.
IEGC
45
b) All SEBs/STUs, CTU, ISGS shall provide RPC Secretariat their proposed
outage programmes in writing for the next financial year by 30th November
of each year. These shall contain identification of each generating
unit/line/ICT, the preferred date for each outage and its duration and
where there is flexibility, the earliest start date and latest finishing date.
c) RPC Secretariat shall then come out with a draft outage programme for
the next financial year by 31st December of each year for the Regional grid
taking into account the available resources in an optimal manner and to
maintain security standards. This will be done after carrying out necessary
system studies and, if necessary, the outage programmes shall be
rescheduled. Adequate balance between generation and load requirement
shall be ensured while finalising outage programmes.
d) The final outage plan shall be intimated to all Regional constituents and
the RLDC for implementation latest by 31st January of each year as
mutually decided in RPC forum.
e) The above annual outage plan shall be reviewed by RPC Secretariat on
quarterly and monthly basis in coordination with all parties concerned, and
adjustments made wherever found to be necessary.
f) In case of emergency in the system, viz., loss of generation, break down
of transmission line affecting the system, grid disturbances, system
isolation, RLDC may conduct studies again before clearance of the
planned outage.
g) RLDC is authorized to defer the planned outage in case of any of the
following, taking into account the statutory requirements:
i. Major grid disturbances (Total black out in Region)
ii. System isolation
iii. Black out in a constituent State
iv. Any other event in the system that may have an adverse
impact on the system security by the proposed outage.
h) The detailed generation and transmission outage programmes shall be
based on the latest annual outage plan (with all adjustments made to
date).
i) Each Regional constituent shall obtain the final approval from RLDC prior
to availing an outage.
5.8 Recovery Procedures
a) Detailed plans and procedures for restoration of the regional grid under
partial/total blackout shall be developed by RLDC in consultation with all
Regional constituents/RPC Secretariat and shall be reviewed / updated
annually.
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b) Detailed plans and procedures for restoration after partial/total blackout of
each Constituents’ system within a Region, will be finalized by the
concerned constituent in coordination with the RLDC. The procedure will
be reviewed, confirmed and/or revised once every subsequent year. Mock
trial runs of the procedure for different sub-systems shall be carried out by
the constituents at least once every six months under intimation to the
RLDC.
c) List of generating stations with black start facility, inter-State/inter regional
ties, synchronizing points and essential loads to be restored on priority,
shall be prepared and be available with RLDCs.
d) The RLDC is authorized during the restoration process following a black
out, to operate with reduced security standards for voltage and frequency
as necessary in order to achieve the fastest possible recovery of the grid.
e) All communication channels required for restoration process shall be used
for operational communication only, till grid normalcy is restored.
5.9 Event Information
5.9.1 Introduction
This session deals with reporting procedures in writing of reportable
events in the system to all Regional constituents, RPC Secretariat and
RLDC/SLDC.
5.9.2 Objective
The objective of this section is to define the incidents to be reported, the
reporting route to be followed and information to be supplied to ensure
consistent approach to the reporting of incidents/events.
5.9.3 Scope
This section covers all Regional constituents, RPC Secretariat, RLDCs
and SLDCs.
5.9.4 Responsibility
a) The RLDC/SLDCs shall be responsible for reporting events to the
Regional constituents/RLDC/RPC Secretariat.
b) All Regional constituents and the SLDCs shall be responsible for collection
and reporting of all necessary data to RLDC and RPC Secretariat for
monitoring, reporting and event analysis.
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5.9.5 Reportable Events
Any of the following events require reporting by RLDC/Regional
constituent:
i) Violation of security standards.
ii) Grid indiscipline.
iii) Non-compliance of RLDC’s instructions.
iv) System islanding/system split
v) Regional black out/partial system black out
vi) Protection failure on any element of ISTS, and on any item on the
“agreed list” of the intra-State systems.
vii) Power system instability
viii) Tripping of any element of the Regional grid.
5.9.6 Reporting Procedure
(a) Written reporting of Events by Regional Constituents to RLDC:
In the case of an event which was initially reported by a Regional
constituent or a SLDC to RLDC orally, the constituent/SLDC will give a
written report to RLDC in accordance with this section.
(b) Written Reporting of Events by RLDC to Regional Constituents.
In the case of an event which was initially reported by RLDC to a
constituent/SLDC orally, the RLDC will give a written weekly report to the
constituent/SLDC in accordance with this section.
(c) Form of Written Reports:
A written report shall be sent to RLDC or a Regional constituent/SLDC, as
the case may be, and will confirm the oral notification together with the
following details of the event:
i) Time and date of event
ii) Location
iii) Plant and/or Equipment directly involved
iv) Description and cause of event
v) Antecedent conditions
vi) Demand and/or Generation (in MW) interrupted and duration
of interruption
vii) All Relevant system data including copies of records of all
recording instruments including Disturbance Recorder, Event
Logger, DAS etc.
viii) Sequence of trippings with time.
ix) Details of Relay Flags.
x) Remedial measures.
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CHAPTER-6
SCHEDULING AND DISPATCH CODE
6.1 Introduction
This Chapter sets out the
a) Demarcation of responsibilities between various Regional
constituents and RLDC in scheduling and dispatch
b) the procedure for scheduling and dispatch
c) the reactive power and voltage control mechanism
d) complementary commercial mechanisms (in the Annexure– 1).
6.2 Objective
This code deals with the procedures to be adopted for scheduling of the
inter-State generating stations (ISGS) and net drawals of concerned
constituents on a daily basis with the modality of the flow of information
between the ISGS/RLDCs/beneficiaries of the Region. The procedure for
submission of capability declaration by each ISGS and submission of
drawal schedule by each beneficiary is intended to enable RLDCs to
prepare the dispatch schedule for each ISGS and drawal schedule for
each beneficiary. It also provides methodology of issuing real time
dispatch/drawal instructions and rescheduling, if required, to ISGS and
beneficiaries along with the commercial arrangement for the deviations
from schedules, as well as, mechanism for reactive power pricing. The
provisions contained in this chapter are without prejudice to the powers
conferred on RLDC under section 28 and 29 of the Electricity Act, 2003.
6.3 Scope
This code will be applicable to RLDC/SLDCs, ISGS, SEBs/STUs and other
beneficiaries in the Regional grid.
The scheduling and dispatch procedure for the generating stations of
Bhakra Beas Management Board (BBMB) shall be separately formulated
by the Northern Regional Load Dispatch Centre (NRLDC) in consultation
with BBMB.
Similarly, the scheduling and dispatch procedure for the generating
stations of Sardar Sarover Project (SSP) shall be separately formulated by
the Western Regional Load Dispatch Centre (WRLDC) in consultation with
Sardar Sarover Narmada Nigam Ltd (SSNNL) /Narmada Control Authority
(NCA).
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6.4 Demarcation of responsibilities
1. The Regional grids shall be operated as loose power pools (with
decentralized scheduling and dispatch), in which the States shall have full
operational autonomy, and SLDCs shall have the total responsibility for (i)
scheduling/dispatching their own generation (including generation of their
embedded licensees), (ii) regulating the demand of their customers, (iii)
scheduling their drawal from the ISGS (within their share in the respective
plant’s expected capability), (iv) arranging any bilateral interchanges, and
(v) regulating their net drawal from the regional grid as per following
guidelines.
2. The system of each State shall be treated and operated as a
notional control area. The algebraic summation of scheduled drawal from
ISGS and any bilateral inter-change shall provide the drawal schedule of
each State, and this shall be determined in advance on daily basis. While
the States would generally be expected to regulate their generation and/or
consumers’ load so as to maintain their actual drawal from the regional
grid close to the above schedule, a tight control is not mandated. The
States may, at their discretion, deviate from the drawal schedule, as long
as such deviations do not cause system parameters to deteriorate beyond
permissible limits and/or do not lead to unacceptable line loading.
3. The above flexibility has been proposed in view of the fact that all
States do not have all requisite facilities for minute-to-minute on-line
regulation of the actual net drawal from the regional grid. Deviations from
net drawal schedule are however, to be appropriately priced through the
Unscheduled Interchange (UI) mechanism.
4. Provided that the States, through their SLDCs, shall always
endeavour to restrict their net drawal from the grid to within their
respective drawal schedules, whenever the system frequency is below
49.5 Hz. When the frequency falls below 49.0 Hz, requisite load shedding
shall be carried out in the concerned State(s) to curtail the over-drawal.
5. The SLDCs/STUs shall regularly carry out the necessary exercises
regarding short-term and long-term demand estimation for their respective
States, to enable them to plan in advance as to how they would meet their
consumers’ load without overdrawing from the grid.
6. The ISGS shall be responsible for power generation generally
according to the daily schedules advised to them by the RLDC on the
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basis of the requisitions received from the SLDCs, and for proper
operation and maintenance of their generating stations, such that these
stations achieve the best possible long-term availability and economy.
7. While the ISGS would normally be expected to generate power
according to the daily schedules advised to them, it would not be
mandatory to follow the schedules tightly. In line with the flexibility allowed
to the States, the ISGS may also deviate from the given schedules
depending on the plant and system conditions. In particular, they would be
allowed / encouraged to generate beyond the given schedule under deficit
conditions. Deviations from the ex-power plant generation schedules shall,
however, be appropriately priced through the UI mechanism.
8. Provided that when the frequency is higher than 50.5 Hz, the actual
net injection shall not exceed the scheduled dispatch for that time. Also,
while the frequency is above 50.5 Hz, the ISGS may (at their discretion)
back down without waiting for an advice from RLDC to restrict the
frequency rise. When the frequency falls below 49.5 Hz, the generation at
all ISGS (except those on peaking duty) shall be maximized, at least upto
the level which can be sustained, without waiting for an advise from
RLDC.
9. However, notwithstanding the above, the RLDC may direct the
SLDCs/ISGS to increase/decrease their drawal/generation in case of
contingencies e.g. overloading of lines/transformers, abnormal voltages,
threat to system security. Such directions shall immediately be acted
upon. In case the situation does not call for very urgent action, and RLDC
has some time for analysis, it shall be checked whether the situation has
arisen due to deviations from schedules, or due to any power flows
pursuant to short-term open access. These shall be got terminated first, in
the above sequence, before an action which would affect the scheduled
supplies from ISGS to the long term customers is initiated.
10. For all outages of generation and transmission system, which may
have an effect on the regional grid, all constituents shall cooperate with
each other and coordinate their actions through Operational Coordination
Committee (OCC) for outages foreseen sufficiently in advance and
through RLDC (in all other cases), as per procedures finalized separately
by OCC. In particular, outages requiring restriction of ISGS generation
and/or restriction of ISGS share which a beneficiary can receive (and
which may have a commercial implication) shall be planned carefully to
achieve the best optimization.
11. The regional constituents shall enter into separate joint/bilateral
agreement(s) to identify the State’s shares in ISGS projects (based on the
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allocations by the Govt. of India, where applicable), scheduled drawal
pattern, tariffs, payment terms etc. All such agreements shall be filed with
the concerned RLDC(s) and RPC Secretariat, for being considered in
scheduling and regional energy accounting. Any bilateral agreements
between constituents for scheduled interchanges on long-term/short-term
basis shall also specify the interchange schedule, which shall be duly filed
in advance with the RLDC.
12. All constituents should abide by the concept of frequency-linked
load dispatch and pricing of deviations from schedule, i.e., unscheduled
interchanges. All generating units of the constituents, their licensees and
generating companies should normally be operated according to the
standing frequency-linked load dispatch guidelines issued by the RLDC, to
the extent possible, unless otherwise advised by the RLDC/SLDC.
13. It shall be incumbent upon the ISGS to declare the plant capabilities
faithfully, i.e., according to their best assessment. In case, it is suspected
that they have deliberately over/under declared the plant capability
contemplating to deviate from the schedules given on the basis of their
capability declarations (and thus make money either as undue capacity
charge or as the charge for deviations from schedule), the RLDC may ask
the ISGS to explain the situation with necessary backup data.
14. The CTU shall install special energy meters on all inter connections
between the regional constituents and other identified points for recording
of actual net MWh interchanges and MVArh drawals. The type of meters
to be installed, metering scheme, metering capability, testing and
calibration requirements and the scheme for collection and dissemination
of metered data are detailed in the enclosed Annexure-2. All concerned
entities (in whose premises the special energy meters are installed) shall
fully cooperate with the CTU/RLDC and extend the necessary assistance
by taking weekly meter readings and transmitting them to the RLDC.
15. The RLDC shall be responsible for computation of actual net MWh
injection of each ISGS and actual net drawal of each beneficiary, 15
minute-wise, based on the above meter readings and for preparation of
the Regional Energy Accounts. All computations carried out by RLDC
shall be open to all constituents for checking/verifications for a period of 15
days. In case any mistake/omission is detected, the RLDC shall forthwith
make a complete check and rectify the same.
16. RLDC shall periodically review the actual deviation from the
dispatch and net drawal schedules being issued, to check whether any of
the constituents are indulging in unfair gaming or collusion. In case any
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such practice is detected, the matter shall be reported to the Member
Secretary, RPC for further investigation/action.
17. In case the State in which an ISGS is located has a predominant
share in that ISGS, the concerned parties may mutually agree (for
operational convenience) to assign the responsibility of scheduling of the
ISGS to the state’s LDC. The role of the concerned RLDC, in such a case,
shall be limited to consideration of the schedule for inter-state exchange of
power on account of this ISGS while determining the net drawal schedules
of the respective states.
6.5 Scheduling and Dispatch procedure (to be read with provisions
on ‘scheduling’ in CERC Notification dated 26.03.2004):
1. All inter-State generating stations (ISGS), in whose output more
than one State has an allocated/contracted share, shall be duly listed. The
station capacities and allocated/contracted shares of different beneficiaries
shall also be listed out.
2. Each State shall be entitled to a MW dispatch upto (foreseen expower
plant MW capability for the day) x (State’s share in the station’s
capacity) for all such stations. In case of hydro-electric stations, there
would also be a limit on daily MWh dispatch, equal to (MWh generation
capacity for the day) x (State’s share in the station’s capacity).
3. By 9 AM every day, the ISGS shall advise the concerned RLDC,
the station-wise ex-power plant MW and MWh capabilities foreseen for the
next day, i.e., from 0000 hrs to 2400 hrs of the following day.
4. The above information of the foreseen capabilities of the ISGS and
the corresponding MW and MWh entitlements of each State, shall be
compiled by the RLDC every day for the next day, and advised to all
beneficiaries by 10 AM. The SLDCs shall review it vis-à-vis their foreseen
load pattern and their own generating capability including bilateral
exchanges, if any, and advise the RLDC by 3 PM their drawal schedule for
each of the ISGS in which they have shares, long-term bilateral
interchanges, approved short-term bilateral interchanges and composite
request for day-ahead open access and scheduling of bilateral
interchanges.
5. The SLDCs may also give standing instructions to the RLDC such
that the RLDC itself may decide the drawal schedules for the States.
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6. By 5 PM each day, the RLDC shall convey:
i) the ex-power plant “dispatch schedule” to each of the ISGS, in MW
for different hours, for the next day. The summation of the ex-power
plant drawal schedules advised by all beneficiaries shall constitute
the ex-power plant station-wise dispatch schedule.
ii) The “net drawal schedule” to each beneficiary, in MW for different
hours, for the next day. The summation of the station-wise expower
plant drawal schedules for all ISGS and drawal from regional
grid consequent to bilateral interchanges, after deducting the
transmission losses (estimated), shall constitute the State-wise
drawal schedule.
7. While finalizing the above daily dispatch schedules for the ISGS,
RLDC shall ensure that the same are operationally reasonable, particularly
in terms of ramping-up/ramping-down rates and the ratio between
minimum and maximum generation levels. A ramping rate of upto 200 MW
per hour should generally be acceptable for an ISGS and for a regional
constituent (50 MW in NER), except for hydro-electric generating stations
which may be able to ramp up/ramp down at a faster rate.
8. The SLDCs/ISGS may inform any modifications/changes to be
made in station-wise drawal schedule & bilateral interchanges /foreseen
capabilities, if any, to RLDC by 10 PM.
9. Upon receipt of such information, the RLDC after consulting the
concerned constituents, shall issue the final ‘drawal schedule’ to each
SLDC and the final ‘dispatch schedule’ to each ISGS by 11 PM.
10. Also, based on the surpluses foreseen for the next day, if any, the
constituents may arrange for bilateral exchanges. The schedules for such
arrangements shall be intimated latest by 10 PM to RLDC, who in turn will
take into account these agreed exchanges while issuing the final
dispatch/drawal schedules at 11 PM provided they would not lead to a
transmission constraint.
11. While finalizing the drawal and dispatch schedules as above, the
RLDC shall also check that the resulting power flows do not give rise to
any transmission constraints. In case any constraints are foreseen, the
RLDC shall moderate the schedules to the required extent, under
intimation to the concerned constituents. Any changes in the scheduled
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quantum of power which are too fast or involve unacceptably large steps,
may be converted into suitable ramps by the RLDC.
12. In case of forced outage of a unit, the RLDC shall revise the
schedules on the basis of revised declared capability. The revised
declared capability and the revised schedules shall become effective from
the 4th time block, counting the time block in which the revision is advised
by the ISGS to be the first one.
13. In the event of bottleneck in evacuation of power due to any
constraint, outage, failure or limitation in the transmission system,
associated switchyard and sub- stations owned by the Central
Transmission Utility or any other transmission licensee involved in interstate
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 to be equal to their
actual drawals.
14. 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.
15. Revision of declared capability by the ISGS(s) 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, counting the time block in
which the request for revision has been received in the RLDC to be the
first one.
16. 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, counting the time block in which the
revised schedule is issued by the RLDC to be the first one.
17. To discourage frivolous revisions, an RLDC may, at its sole
discretion, refuse to accept schedule/capability changes of less than two
(2) percent of the previous schedule/capability.
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18. After the operating day is over at 2400 hours, the schedule finally
implemented during the day (taking into account all before-the-fact
changes in dispatch schedule of generating stations and drawal schedule
of the States) shall be issued by RLDC. These schedules shall be the
datum for commercial accounting. The average ex-bus capability for each
ISGS shall also be worked out based on all before-the-fact advise to
RLDC.
19. RLDC shall properly document all above information i.e. stationwise
foreseen ex-power plant capabilities advised by the generating
stations, the drawal schedules advised by beneficiaries, all schedules
issued by the RLDC, and all revisions/updating of the above.
20. The procedure for scheduling and the final schedules issued by
RLDC, shall be open to all constituents for any checking/verification, for a
period of 5 days. In case any mistake/omission is detected, the RLDC
shall forthwith make a complete check and rectify the same.
21. While availability declaration by ISGS may have a resolution of one
(1) MW and one (1) MWh, all entitlements, requisitions and schedules
shall be rounded off to the nearest decimal, to have a resolution of 0.1
MW.
6.6 Reactive Power and Voltage Control
1. Reactive power compensation should ideally be provided locally, by
generating reactive power as close to the reactive power consumption as
possible. The beneficiaries are therefore expected to provide local VAr
compensation/generation such that they do not draw VArs from the EHV
grid, particularly under low-voltage condition. However, considering the
present limitations, this is not being insisted upon. Instead, to discourage
VAr drawals by Beneficiaries, VAr exchanges with ISTS shall be priced as
follows:
- The Beneficiary pays for VAr drawal when voltage at the metering
point is below 97%
- The Beneficiary gets paid for VAr return when voltage is below 97%
- The Beneficiary gets paid for VAr drawal when voltage is above
103%
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- The Beneficiary pays for VAr return when voltage is above 103%
Provided that there shall be no charge/payment for VAr drawal/return by a
Beneficiary on its own line emanating directly from an ISGS.
2. The charge/payment for VArs, shall be at a nominal paise/kVArh
rate as may be specified by CERC from time to time, and will be between
the Beneficiary and the regional pool account for VAr interchanges.
3. Notwithstanding the above, RLDC may direct a beneficiary to curtail
its VAr drawal/injection in case the security of grid or safety of any
equipment is endangered.
4. In general, the Beneficiaries shall endeavour to minimize the VAr
drawal at an interchange point when the voltage at that point is below 95%
of rated, and shall not return VAr when the voltage is above 105%. ICT
taps at the respective drawal points may be changed to control the VAr
interchange as per a Beneficiary’s request to the RLDC, but only at
reasonable intervals.
5. Switching in/out of all 400 kV bus and line Reactors throughout the
grid shall be carried out as per instructions of RLDC. Tap changing on all
400/220 kV ICTs shall also be done as per RLDCs instructions only.
6. The ISGS shall generate/absorb reactive power as per instructions
of RLDC, within capability limits of the respective generating units, that is
without sacrificing on the active generation required at that time. No
payments shall be made to the generating companies for such VAr
generation/absorption.
7. VAr exchange directly between two Beneficiaries on the
interconnecting lines owned by them (singly or jointly) generally address or
cause a local voltage problem, and generally do not have an impact on the
voltage profile of the regional grid. Accordingly, the management/control
and commercial handling of the VAr exchanges on such lines shall be as
per following provisions, on case-by-case basis:
i) The two concerned Beneficiaries may mutually agree not to have
any charge/payment for VAr exchanges between them on an
interconnecting line.
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iii) The two concerned Beneficiaries may mutually agree to adopt a
payment rate/scheme for VAr exchanges between them identical to
or at variance from that specified by CERC for VAr exchanges with
ISTS. If the agreed scheme requires any additional metering, the
same shall be arranged by the concerned Beneficiaries.
iv) In case of a disagreement between the concerned Beneficiaries
(e.g. one party wanting to have the charge/payment for VAr
exchanges, and the other party refusing to have the scheme), the
scheme as specified in Annexure-3 shall be applied. The per kVArh
rate shall be as specified by CERC for VAr exchanges with ISTS.
iv) The computation and payments for such VAr exchanges shall be
effected as mutually agreed between the two Beneficiaries.
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Annexure-1
(refer section 6.1 (d))
COMPLEMENTARY COMMERCIAL MECHANISMS
1. The beneficiaries shall pay to the respective ISGS Capacity
charges corresponding to plant availability and Energy charges for the
scheduled dispatch, as per the relevant notifications and orders of CERC.
The bills for these charges shall be issued by the respective ISGS to each
beneficiary on monthly basis.
2. The sum of the above two charges from all beneficiaries shall fully
reimburse the ISGS for generation according to the given dispatch
schedule. In case of a deviation from the dispatch schedule, the
concerned ISGS shall be additionally paid for excess generation through
the UI mechanism approved by CERC. In case of actual generation being
below the given dispatch schedule, the concerned ISGS shall pay back
through the UI mechanism for the shortfall in generation.
3. The summation of station-wise ex-power plant dispatch schedules
from each ISGS and any bilaterally agreed interchanges of each
beneficiary shall be adjusted for transmission losses, and the net drawal
schedule so calculated shall be compared with the actual net drawal of the
beneficiary. In case of excess drawal, the beneficiary shall be required to
pay through the UI mechanism for the excess energy. In case of underdrawal,
the beneficiary shall be paid back through the UI mechanism, for
the energy not drawn.
4. When requested by a constituent, RLDC shall assist the constituent
in locating a buyer/seller and arranging a scheduled interchange within the
Region or across the regional boundary. The RLDC shall act only as a
facilitator (not a trader / broker), and shall assume no liabilities under the
agreement between the two parties, except (i) ascertaining that no
component of the power system of any other constituent shall be overstressed
by such interchange/trade, and (ii) incorporating the agreed
interchange/trade in the net interchange schedules for the concerned
constituents.
5. Regional Energy Accounts and the statement of UI charges shall be
prepared by the RLDC on a weekly basis and these shall be issued to all
constituents by Saturday for the seven-day period ending on the previous
Sunday mid-night. Payment of UI charges shall have a high priority and
the concerned constituents shall pay the indicated amounts within 10 (ten)
days of the statement issue into a regional UI pool account operated by
the RLDC. The agencies who have to receive the money on account of UI
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charges would then be paid out from the regional UI pool account, within
three (3) working days.
6. The RLDC shall also issue the weekly statement for VAr charges,
to all constituents who have a net drawal/injection of reactive energy under
low/high voltage conditions. These payment shall also have a high priority
and the concerned constituents shall pay the indicated amounts into
regional reactive account operated by the RLDC within 10 (ten) days
of statement issue. The constituents who have to receive the money on
account of VAr charges would then be paid out from the regional reactive
account, within three (3) working days.
7. If payments against the above UI and VAr charges are delayed by
more than two days, i.e., beyond twelve (12) days from statement issue,
the defaulting constituent shall have to pay simple interest @ 0.04% for
each day of delay. The interest so collected shall be paid to the
constituents who had to receive the amount, payment of which got
delayed. Persistent payment defaults, if any, shall be reported by the
RLDC to the Member Secretary, RPC, for initiating remedial action.
8. The money remaining in the regional reactive account after pay-out
of all VAr charges upto 31st March of every year shall be utilized for
training of the SLDC operators, and other similar purposes which would
help in improving/streamlining the operation of the respective regional
grids, as decided by the respective RPC from time to time.
9. In case the voltage profile of a regional grid improves to an extent
that the total pay-out from the regional VAr charges account for a week
exceeds the total amount being paid-in for that week, and if the regional
reactive account has no balance to meet the deficit, the pay-outs shall be
proportionately reduced according to the total money available in the
above account.
10. The RLDC shall table the complete statement of the regional UI
account and the regional Reactive Energy account in the RPC’s
Commercial Committee meeting, on a quarterly basis, for audit by the
latter.
11. All 15-minute energy figures (net scheduled, actually metered and
UI) shall be rounded off to the nearest 0.01 MWh.
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Annexure-2
REGULATORY REQUIREMENTS OF SPECIAL ENERGY METERS
1. Special energy meters of a uniform technical specification shall be
provided on the electrical periphery of each regional constituent, to
determine its actual net interchange with the regional grid. Each
interconnection shall have one (1) Main meter. In addition, Standby/check
meters shall be provided such that correct computation of net interchange
of a constituent is possible even when a Main meter, a CT or a VT has a
problem.
2. The Special energy meters shall be static type, composite meters,
installed circuit-wise, as self-contained devices for measurement of active
and reactive energy, and certain other parameters as described in the
following paragraphs. The meters shall be suitable for being connected
directly to voltage transformers (VTs) having a rated secondary line-to-line
voltage of 110 V, and to current transformers (CTs) having a rated
secondary current of 1A (model-A) or 5A (model-B). The reference
frequency shall be 50 Hz.
3. The meters shall have a non-volatile memory in which the following shall
be automatically stored:
i) Average frequency for each successive 15-minute block, as a two
digit code (00 to 99 for frequency from 49.0 to 51.0 Hz).
ii) Net Wh transmittal during each successive 15-minute block, upto
second decimal, with plus/minus sign.
iii) Cumulative Wh transmittal at each midnight, in six digits including
one decimal.
iv) Cumulative VArh transmittal for voltage high condition, at each
midnight, in six digits including one decimal.
v) Cumulative VArh transmittal for voltage low condition, at each
midnight, in six digits including one decimal.
vi) Date and time blocks of failure of VT supply on any phase, as a star
(*) mark.
4. The meters shall store all the above listed data in their memories for a
period of ten (10) days. The data older than (10) days shall get erased
automatically. Each meter shall have an optical port on its front for tapping
all data stored in its memory using a hand held data collection device.
IEGC
61
5. The active energy (Wh) measurement shall be carried out on 3-phase, 4-
wire principle, with an accuracy as per class 0.2 S of IEC-687/IEC-62053-
22. In model-A, the energy shall be computed directly in CT and VT
secondary quantities, and indicated in watt-hours. In model-B, the energy
display and recording shall be one fifth of the Wh computed in CT and VT
secondary quantities.
6. The VAr and reactive energy measurement shall also be on 3-phase, 4-
wire principle, with an accuracy as per class 2 of IEC-62053-23 or better.
In model-A, the VAr and VArh computation shall be directly in CT and VT
secondary qualities. In model-B, these shall be displayed and recorded as
one-fifth of those in CT and VT secondary quantities. There shall be two
reactive energy registers, one for the period when average RMS voltage is
above 103% and the other for the period the voltage is below 97%.
7. The 15-minute Wh shall have a +ve sign when there is a net Wh export
from substation busbars, and a -ve sign when there is a net Wh import.
The integrating (cumulative) registers for Wh and VArh shall move forward
when there is Wh/VArh export from substation busbars, and backward
when there is an import.
8. The meters shall also display (on demand), by turn, the following
parameters:
i) Unique identification number of the meter
ii) Date
iii) Time
iv) Cumulative Wh register reading
v) Average frequency of the previous 15-minute block
vi) Net Wh transmittal in the previous 15-minute block, with +/- sign
vii) Average percentage voltage
viii) Reactive power, with +/- sign
ix) Voltage-high VArh register reading
x) Voltage-low VArh register reading
9. The three line-to-neutral voltages shall be continuously monitored, and in
case any of these falls below 70%, the condition shall be suitably indicated
and recorded. The meters shall operate with the power drawn from the VT
secondary circuits, without the need for any auxiliary power supply. Each
meter shall have a built-in calendar and clock, having an accuracy of 30
seconds per month or better.
10. The meters shall be totally sealed and tamper-proof, with no possibility of
any adjustment at site, except for a restricted clock correction. The
harmonics shall preferably be filtered out while measuring Wh, VAr and
VArh, and only fundamental frequency quantities shall be
measured/computed.
IEGC
62
11. All metering equipment shall be of proven quality, fully type-tested,
individually tested and accepted by the CTU before dispatch from
manufacturer’s work.
12. In-situ functional checking and rough testing of accuracy shall be carried
out for all meters once a year by the CTU, with portable test equipment
complying with IEC-60736, for type and acceptance testing of energy
meters of 1.0 class.
13. Full testing for accuracy for every meter shall be carried out by the CTU at
an accredited laboratory, once every five (5) years.
14. The current and voltage transformers to which the above special energy
meters are connected shall have a measurement accuracy class of 0.5 or
better. Main and Standby/check meters shall be connected to different
sets of CTs and VTs, wherever available.
15. Only functional requirements from regulatory perspective are given in this
code. Detailed specifications for the meters, their accessories and testing,
and procedures for collecting their weekly readings shall be finalized by
the CTU.
IEGC
63










CHAPTER-7
INTER-REGIONAL EXCHANGES
7.1 INTRODUCTION
1. India was demarcated into five (5) electrical regions in Sixties, for
planning, development and operation of the power system. For over three
decades, the generation and transmission planning continued with
regional self-sufficiency as an objective/criterion, and consequently the
inter-regional links were planned only for marginal exchange of power. Till
2002, the inter-regional links comprised either of 220 kV/132 kV A.C. lines
operating in radial mode, or of HVDC back-to-back links, which allowed
different regions to operate at their own frequency.
2. The picture has changed dramatically since 2003, with synchronizing of
Western, Eastern and North-Eastern regional grids through 400 kV A.C.
lines, which enable substantial amounts of power to flow across the
regional boundaries. Commissioning of 2000 MW Talcher-Kolar HVDC link
between ER and SR, and 500 MW Sasaram HVDC link between ER and
NR also facilitate controlled exchange of power between these regions.
Many more inter-regional links are planned to be commissioned in the
coming years. The special considerations to be applied for operation of
these links are set out in this chapter.
3. The stipulations in this chapter may be supplemented by CTU (as operator
of RLDCs) depending on operational needs. They may also need
revision/updating as and when further inter-regional links come into
operation. In due course, this responsibility may be transferred to the CTU,
and this chapter withdrawn from IEGC.
7.2 PRESENT SYSTEM
1. India has three (3) synchronous power systems today: (a) Northern, (b)
Central (WR-ER-NER), and (c) Southern. The Northern system is
connected to Central mainly through two (2) back to back HVDC links: (a)
2x250 MW Vindhyachal (NR-WR), and (b) 1x500 MW Sasaram (ER-NR).
The Southern system is connected to Central mainly through three (3)
HVDC links: (a) 2x1000 MW Talcher-Kolar (ER-SR), (b) 2x500 MW
Gazuwaka (ER-SR), and (c) 2x500 MW Chandrapur (WR-SR).
ER and WR are presently synchronized through the 400 kV D/C Rourkela-
Raipur line, and three (3) 220 kV circuits between Budhipadhar and Korba.
ER and NER are synchronized through the 400 kV D/C Malda-
Purnea/Binaguri-Bongaigaon line and 220 kV D/C Birpara-Salakati line.
2. While power flows on HVDC links can be controlled or set at any
required level in either direction, and thereby the exchanges between
Northern and Central, and between Southern and Central can be
IEGC
66
controlled directly, the power inter-changes between West, East and
North-East depend on relative load-generation balances in the three
regions.
7.3 SCHEDULING OF ISGS
1. All ISGS, except Talcher-II STPS, shall be scheduled through the RLDC of
the region in which they are located, even if they have Beneficiaries in
other regions. In other words, an ISGS shall interact with the host RLDC
only. For allocations to Beneficiaries in other regions, the host RLDC shall
interact with the concerned RLDC, as per modalities worked out between
them. The concerned RLDC shall in turn interact with the SLDC of the
respective Beneficiary, and then revert to the host RLDC.
2. Scheduling procedure for Talcher-II STPS is described separately.
Chukha HEP and Kurichhu HEP in Bhutan shall be scheduled through
ERLDC.
3. Each RLDC shall estimate and apportion transmission losses of its own
region, for the purpose of determining the drawal schedules of the
Beneficiaries and inter-regional schedules with a resolution of 0.1 MW.
7.4 SCHEDULING/SETTING AND OPERATION OF TALCHER-II
STPS/TALCHER-KOLAR HVDC:
1. 4x500 MW Talcher-II STPS, though located in Orissa in Eastern region, is
fully assigned to the Beneficiaries in Southern region. Also, it is
synchronized with the Eastern region and operates at the Central (WRER-
NER) frequency. Power is transmitted to the Southern region, primarily
through the 2x 1000 MW, +/- 500 kV Talcher-Kolar HVDC link, built as a
part of the associated transmission system of Talcher-II. It is thus a special
case which requires specific stipulations in this grid code.
2. For a clear demarcation of responsibilities and minimal to-and-fro
coordination, the scheduling of Talcher-II shall be coordinated by SRLDC,
and the 400 kV AC bus-couplers between Talcher-I (2x500 MW) and
Talcher-II (4x500 MW) shall be treated as the interface between ER and
SR.
3. Talcher-II STPS shall advise the SRLDC (with copies to ERLDC and
Talcher HVDC terminal) the ex-power plant MW and MWh capabilities for
the next day, by 9 AM every day. The SRLDC shall then interact with the
SLDCs of SR, and convey the dispatch schedule of Talcher-II for the next
day to Talcher-II STPS, with copies to ERLDC and Talcher HVDC
terminal, by 5 PM.
4. Any changes in foreseen power plant capability and in Beneficiaries’
requisitions shall be coordinated by SRLDC, and final dispatch and drawal
schedules for the next day shall be issued by SRLDC by 11 PM. Any
IEGC
67
bilateral exchanges of Talcher-II (for unrequisitioned capability, if any)
shall also be included in the schedules issued by SRLDC.
5. The base MW level for Talcher-Kolar HVDC link at Talcher end shall be
separately advised by SRLDC to Talcher HVDC terminal. It need not be
equal to the Talcher-II dispatch schedule, since power can flow to SR via
other routes as well, i.e., Gazuwaka HVDC and Chandrapur HVDC. (The
HVDC settings are to be optimized by SRLDC).
6. The actual net injection of Talcher-II STPS shall be as metered on 400 kV
side of generator transformers of Talcher-II units. The difference between
the above actual injection and the dispatch schedule shall constitute the UI
of Talcher-II, for which payments shall be made from/into the UI pool
account of Southern region operated by SRLDC, but at the UI rate
corresponding to ER repeat ER frequency. The energy accounting for
Talcher-II STPS shall be carried out by SRLDC.
7. While the dispatch schedule for Talcher-II shall be as advised by SRLDC,
the actual generation at Talcher-II may be varied by station operators
depending on ER frequency, as long as the resulting UI does not cause a
transmission constraint in ER. In case of a transmission constraint being
caused in ER by the UI of Talcher-II, ERLDC may advise Talcher-II to
curtail its UI under intimation to SRLDC. Any such advise shall be
immediately complied with by Talcher-II.
8. CEA, ERLDC, SRLDC, NTPC and Powergrid shall jointly work out and
implement the required inter-tripping/runback arrangements between
Talcher-II STPS and Talcher-Kolar HVDC link. In particular, the
arrangements shall aim at keeping within permissible limits the frequency
rise and line overloading in ER and WR in the event of tripping of one or
both poles of the HVDC link.
9. In the event of tripping of a Talcher-II unit, the power flow on Talcher-Kolar
HVDC link shall not be ramped down as long as ER frequency is higher
than the SR frequency. Only when ER frequency is tending to fall below
the SR frequency, shall the power flow on Talcher-Kolar HVDC link be
ramped down, but gradually and only to the extent necessary to keep the
ER frequency just above the SR frequency. However, in case the ER
frequency was already below the SR frequency, or has fallen below 49.0
Hz, HVDC power shall be ramped down to the extent of generation loss at
Talcher-II without any delay, to save the ER grid from any harmful impact
of tripping of the Talcher-II unit.
7.5 DEMARCATION OF SCHEDULING AND HVDC SETTING
RESPONSIBILITIES:
1. NRLDC shall schedule the interchanges of NR with all other regions, and
also advise the power settings to Vindhyachal and Sasaram HVDC
IEGC
68
stations. The total scheduled import of power from ER/NER into NR may
presently be restricted to 500 MW (the capacity of Sasaram HVDC).
2. The SRLDC shall schedule the interchanges of SR with all other regions,
and also advise the power settings to Talcher, Chandrapur and Gazuwaka
HVDC stations.
3. While specifying the above interchange schedules and HVDC settings,
NRLDC and SRLDC shall ascertain (in coordination with ERLDC/WRLDC)
that no transmission overloading would be caused on either side of the
HVDC links.
4. The settings of HVDC links may not match with the respective interregional
schedules. Specifically, unscheduled interchange (UI) may be
allowed from the system with a higher frequency to the system with a
lower frequency, by setting the HVDC links at power levels differing from
the respective inter-regional schedules.
5. While specifying the settings of HVDC links under their jurisdiction,
NRLDC and SRLDC shall also see whether a diversion of some power
from one link to another would reduce transmission losses and/or
transmission loading (thereby permitting more inter-regional power
transfer), and improve the overall system security/voltage profile.
6. As a general guideline, whenever NR frequency is higher than Central
(WR-ER-NER) frequency by more than about 0.2 Hz, the NR→WR power
flow through Vindhyachal HVDC shall be maximized. If such frequency
differential persists, the ER→NR power flow through Sasaram HVDC shall
also be reduced, to the extent possible without overloading ER→WR links.
7. When NR frequency is lower than Central frequency by more than about
0.2 Hz, ER→NR power flow through Sasaram HVDC shall first be
maximized. If such frequency differential persists, WR→NR power flow
through Vindhyachal HVDC shall be increased, to the extent possible
without overloading ER→WR links and the transmission lines in NR.
8. Similarly, when SR frequency is higher than the Central (WR-ER-NER)
frequency by more than about 0.2 Hz, the SR→WR power flow through
Chandrapur HVDC shall be maximized. If such frequency differential
persists, ER→SR power flow through Gazuwaka and Talcher-Kolar HVDC
may be reduced to the extent possible without overloading ER→WR links.
9. When SR frequency is lower than Central frequency by more than about
0.2 Hz, ER→SR power flow through Talcher-Kolar and Gazuwaka HVDC
shall be maximized. If such frequency differential persists, WR→SR power
flow through Chandrapur HVDC shall be increased, to the extent possible
without overloading ER→WR links.
IEGC
69
10. The WRLDC shall schedule the interchange of power of WR with ER and
NER, presently limiting the scheduled import to 1000 MW (thus keeping a
security margin of about 500 MW) on ER-WR links. It shall also monitor
the power flow on ER-WR ties, and in the event of overloading may
request NRLDC/SRLDC to divert some ER-WR power flow through their
respective regions. If the required assistance is not forthcoming or is not
possible, WRLDC shall order any necessary preventive action in its own
region.
11. It is expected that in the normal course, with all major transmission
elements available, there would be no transmission constraints between
NER and ER, and between ER and SR. If any constraints do arise, the
RLDCs shall coordinate between themselves, and with NLDC if
necessary, to remedy the situation.
7.6 INTERFACES FOR SCHEDULING AND UI ACCOUNTING:
1. The regional boundaries for scheduling, metering and UI accounting of
inter-regional exchanges shall be as follows:
a) NR-WR : 400 kV West bus of Vindhyachal HVDC
b) WR-SR : 400 kV West bus of Chandrapur HVDC
c) NR-ER : 400 kV East bus of Sasaram HVDC
d) ER-SR : 400 kV Bus couplers between Talcher-I and
Talcher-II
400 kV East bus of Gazuwaka HVDC
e) ER-WR : Rourkela end of 400 kV D/C Rourkela-Raipur
line
Budhipadhar end of 220 kV Budhipadar-Korba
Lines
f) ER-NER : Bongaigaon end of the 400 kV D/C Malda-
Purnea/Binaguri-Bongaigaon line
Salakati end of 220 kV D/C Birpara-Salakati
line
2. The NR-WR and WR-SR exchanges of UI shall be at the UI rate in WR. All
other UI exchanges shall be at the UI rate in ER. Payments for interregional
UI exchanges shall be between the respective regional UI pool
accounts, region-to-region.
3. No attempt shall be made to split the inter-regional schedules into linkwise
schedules (where two regions have two or more interconnections).
IEGC
70
CHAPTER – 8
MANAGEMENT OF INDIAN ELECTRICITY GRID CODE
8.1 The Indian Electricity Grid Code (IEGC) shall be specified by the Central
Electricity Regulatory Commission (CERC) as per section 79 (1) (h) of the
Electricity Act, 2003. Any amendments to IEGC shall also be specified by
CERC only.
8.2 The IEGC and its amendments shall be finalized and notified adopting the
prescribed procedure followed for regulations issued by CERC.
8.3 The requests for amendments to / modifications in the IEGC and for
removal of difficulties shall be addressed to Secretary, CERC, for periodic
consideration, consultation and disposal.
8.4 Any dispute or query regarding interpretation of IEGC may be addressed
to Secretary, CERC and clarification issued by the CERC shall be taken
as final and binding on all concerned.
8.5 The State Electricity Regulatory Commissions (SERC) shall specify the
Grid Codes for operation of the respective intra-State system as per
section 86 (1) (h) of Electricity Act, 2003, ensuring that they are consistent
with the IEGC.
IEGC
71
BACKGROUND NOTE
1. The Central Electricity Regulatory Commission (CERC) had asked the
Central Transmission Utility (CTU) i.e. the Power Grid Corporation of India
(PGCI) in March 1999 to prepare the draft Indian Electricity Grid Code
(IEGC), as per certain directives issued by CERC. In response, PGCI had
submitted a draft IEGC dated 08.04.1999, which was then made available
through PGCI offices to all those interested in perusing and commenting
on the same. A public notice was also issued in newspapers inviting
objections on the above draft IEGC by 25.05.1999.
2. The comments and objections received from all parties who responded
were discussed in the hearings held by CERC in July 1999, and after
further interaction between CERC and PGCIL, the first IEGC was issued in
January 2000. There was a review of the IEGC in early 2002 and the first
revision as per CERC’s order dated 22.02.2002 was issued by PGCIL in
March, 2002.
3. Some of the provisions in the current IEGC dated 14.03.2002 require a
revision to get aligned with the provisions in the Electricity Act, 2003,
which has come into force from 10.06.2003. An important provision under
section 79(1) (h) in the new Act is that CERC has “to specify Grid Code
having regard to Grid Standards.” This implies that the new IEGC has to
be a CERC document, rather than a document owned by CTU (and only
approved by CERC). As per directive 4 of CERC on 31.03.1999, the CTU
had to, in consultation with all utilities, prepare, implement, periodically
review and revise and comply with the IEGC. This position has now
substantially changed.
4. As per Section 73(d) of the Act, the “Grid Standards for operation and
maintenance of transmission lines” are to be specified by Central
Electricity Authority (CEA). As and when Grid Standards are specified by
CEA, if required, the IEGC shall be amended.
IEGC
72
5. The present IEGC has a chapter titled “Management of Indian Electricity
Grid Code”, which was relevant in the previous scenario. It provided for
an IEGC Review Panel, with Director (Operation), PGCI as its chairman
and convenor. Any change in IEGC required agreement in the IEGC
Review Panel and approval by CERC. Now that the responsibility for
specifying the Grid code directly vests in CERC, and the Grid Code and its
revisions are to be issued adopting the procedure followed for CERC’s
regulations, the IEGC Review Panel is no longer necessary. The current
exercise of preparing the new draft IEGC is also not being routed through
the present IEGC Review Panel, for the same reasons. The above chapter
has been rewritten, removing all references to the IEGC Review Panel.
6. As per section 28 (3) (c) of the Electricity Act, 2003, the Regional Load
Despatch Centres (RLDC) shall “keep accounts of quantity of electricity
transmitted through the regional grid”. Accordingly, the responsibility of
preparation of Regional Energy Accounts hitherto with the REB
Secretariats, shall stand transferred to the respective RLDCs with effect
from 01.04.2006.
7. The Regional Electricity Boards (REB) have been replaced in the new Act
by Regional Power Committees (RPC). The Central Government vide its
principal resolution dated 25.05.2005 have notified establishment of
RPCs. The IEGC has been revised accordingly.
8. Reorganization of the State Electricity Boards (SEBs) envisaged in Part
XIII of the Electricity Act, 2003 would lead to formation of a large number
of independent entities (generating companies, transmission licensees
and distribution licensees) in each State, and consequently a very large
number of such intra-State entities in each region. All these entities would
come under the regulatory jurisdiction of the concerned State Electricity
Regulatory Commission (SERC), and the operational jurisdiction of the
concerned State Load Despatch Centre (SLDC). While they would also be
connecting into and be synchronized with the same A.C. interconnection,
IEGC
73
i.e., the regional grid, their operation shall be governed by the State
Electricity Grid Code specified by the concerned S.E.R.C. Even the
directions issued to them by the Regional Load Despatch Centre (the apex
body to ensure integrated operation of the regional power system) have to
be routed through the concerned SLDC, as per section 29 (3) of the Act.
9. As a logical extension of the above approach and to ensure clear chain of
accountability, the following is proposed: (1) The RLDC shall interact and
coordinate only with the SLDCs (and the STUs if necessary) on all matters
concerning a State, and with no other intra-State entity. (2) The SLDCs
shall be responsible for all related coordination with the intra-State entities,
and interacting on their behalf with the RLDC. (3) Each State as a whole
shall be treated as an entity in the regional grid, and as one entity for the
purpose of allocations/shares in Inter-State Generating Station (ISGS), for
daily scheduling and despatch, for accounting of unscheduled interchange
(UI) and reactive energy. (4) The bifurcation of the State’s total entitlement
in ISGS availability for the day, advising the intra-State entities about their
respective entitlements, and collecting their requisitions, compiling them
into State’s total requisition from ISGS, etc shall be carried out by the
SLDC. (5) The STU/SLDC shall be responsible for installation of special
energy meters on the interconnecting points of all intra-State entities who
need to have such meters, for organizing the periodic collection of meter
readings, preparation of intra-State energy accounts and issuing the UI
statements for all concerned entities (.once a week).
10. This revised IEGC shall be effective from 1st April 2006.
11. The earlier IEGC was silent regarding the payment for reactive energy
exchanges directly between the States on State-owned transmission lines.
This aspect is now being covered in the revised IEGC under a new section
(6.6.7).
IEGC
74
12. The intra-State scheme for pricing of reactive energy exchanges between
the intra-State entities has to be very carefully deliberated upon by the
concerned SERC/STU, and duly covered in the State Electricity Grid
Code. The requirements of local reactive support may differ from State to
State and the approach may differ from that in this IEGC. For example, the
inter-State generating stations (ISGS) have to generate/absorb reactive
power as per instructions of RLDC, “without sacrificing on the active
generation required at that time”, and “no payment shall be made to the
generating companies for such VAr generation/absorption”. This is
because (1) the ISGS are mostly located away from load-centres, (2) they
generally have a lower variable cost, and (3) they are paid a capacity
charge covering the cost of entire installation, including their reactive
power capability. The situation of intra-State stations may differ in these
respects, and a different approach to their reactive energy output may be
necessary.
13. When the first version of IEGC was drafted in 1999, inter-regional
exchanges were minimal. Many new inter-regional links have since been
commissioned and substantial amounts of energy is now being exchanged
between the regional grids. A new chapter is being added in the IEGC
accordingly, to cover various aspects of scheduling, control and
commercial issues of inter-regional exchanges.




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Grid Code
At privatisation and as required by the transmission licence, National Grid implemented the Grid Code, which is designed to permit the development, maintenance and operation of an efficient, co-ordinated and economical system for the transmission of electricity, to facilitate competition in the generation and supply of electricity and to promote the security and efficiency of the power system as a whole. National Grid and users of its transmission system are required to comply with the Grid Code.
The Grid Code available here is the designated revised code under BETTA and is effective from 1st September, 2004 (BETTA Go-Active date).
The Grid Code is required to cover all material technical aspects relating to connections to and the operation and use of the transmission system or, in as far as relevant to the operation and use of the transmission system, the operation of the electric lines and electrical plant connected to it or to a distribution system.
The Grid Code also specifies data which system users are obliged to provide to National Grid for use in the planning and operation of the transmission system, including demand forecasts, availability of generating sets and intended dates of overhaul of large generating sets.
Any changes to the Grid Code are subject to the approval of the Authority.
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Complete Grid Code13 October 2008
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