ODISHA ELECTRICITY REGULATORY COMMISSION

BIDYUT NIYAMAK BHAWAN

UNIT-VIII, BHUBANESWAR-751012

ODISHA GRID CODE (OGC) REGULATIONS, 2015

NOTIFICATION

The 11th August, 2015.

No. 967---Engg. 17/2005-(Vol. VIII) - In exercise of the powers conferred by Sub-Section (zp)
of Section 181(2)read with Sub-Section (h) of Section 86 (1) of the Act (36 of 2003), the Odisha
Electricity Regulatory Commission hereby makes the following Regulations, namely:-

1. Short title, extent and commencement

(a) These Regulations may be called the Odisha Grid Code Regulations, 2015, in
short „OGC‟.

(b) These Regulations shall extend to the whole of the State of Odisha and for all
Users who are connected with and/or utilise the State Transmission System
including the Transmission Licensee(s).

(c) These Regulations shall come into force from the date of their publication in the
Official Gazette.

(d) Orissa Grid Code(OGC) Regulations, 2006 is hereby repealed.

2. Definitions

(a) In these Regulations unless the context otherwise requires, words or expressions
used herein have the meanings assigned to them as defined at Section 1.19 (in
Chapter 1) of these Regulations.

(b) In these Regulations, words or expressions used herein and not defined at section
1.19 (in Chapter-1), have the meanings assigned to them under the Act and the
meanings commonly understood in Electrical Engineering.
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CHAPTER-1
GENERAL
1.1 INTRODUCTION

Section 86(1)(h) of the Act requires the Odisha Electricity Regulatory Commission to
specify a State Grid Code consistent with the provisions of Indian Electricity Grid Code
prepared under Section 79(1)(h) of the Act.
1.2 OBJECTIVE

The Odisha Grid Code (OGC) is a document that explains the boundary between the
Transmission Licensee and other Users, who are connected to/or using the State
Transmission System and establishes procedures for operations of the State Transmission
System. It lays down both the information requirements and the procedures governing
the relationship between various Users of State Transmission System as well as the State
Load Despatch Centre. It should be noted that the OGC is not concerned with the
detailed design and operation of generators, Power Stations, suppliers and Distribution
Systems, provided that their overall compatibility with the Transmission System needs
are assured.

The Transmission Licence condition requires that the Transmission Licensee while
implementing and complying with the OGC shall neither discriminate against nor unduly
prefer any one or any group of Users.

The OGC shall cover all material technical aspects relating to connections to and
operation and use of the Transmission System including the operation of electric lines
and electrical plant connected to the transmission system, relevant to the
operation and use of the Transmission System. It shall be designed so as to permit the
planning, development, maintenance and operation to facilitate an efficient, co-ordinated
and economical system for the transmission and supply including trading of electricity in
the State.

The OGC shall provide facilitation for beneficial trading of electricity by defining a
common basis of operation of the State Transmission System (STS), applicable to all the
Users of the STS.

The OGC shall also provide facilitation for the development of renewable energy sources
by specifying the technical and commercial aspects for integration of these resources into
the State grid.

1.3 SCOPE
(1) The OGC shall be complied with by the Odisha Power Transmission Corporation
Limited (OPTCL) in its capacity as a State Transmission Utility and holder of the
Transmission Licence, GRIDCO Limited (GRIDCO) in its capacity of a trader/
bulk supplier, by generators, in capacity of injectors, other Transmission
Licensees, other trading licensees, distribution licensees, suppliers and Bulk
Power Consumers and Open Access Customers in the course of their generation,
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supply, utilisation of electricity and facilitation for beneficial trading of

electricity.
(2) All persons (or) Utilities that connect with and/or utilise the State Transmission
System (STS) of Odisha are required to abide by the principles and procedures
defined in the OGC so far as they apply to that Utility.
The matters relating to State Transmission System (STS) and Interstate
Transmission System (ISTS) as provided in IEGC and its revisions shall be
binding on the Users.

1.4 STRUCTURE OF THE OGC

This OGC contains the following Chapters:

(1) General:

This Chapter describes general features of OGC including definitions.

(2) Role of various organisations:

This chapter defines the functions of the various organisations as are relevant to
OGC.

(3) Planning Code for STS:

This Chapter specifies the technical and design criteria and procedures to be
followed by the State Transmission Utility (STU) i.e. OPTCL in planning and
development of the State Transmission System and by other Users connected or
seeking connection to the Transmission System. This Chapter provides the policy
to be adopted in the planning and development of bulk power transfer and
associated State Transmission System. The Planning Code lays out the detailed
information exchange required between the planning Agencies and the various
participants of the State Power System for load forecasting, generation
availability and Power System planning etc. for the future years under study. The
Planning Code stipulates the various criteria to be adopted during the planning
process.

(4) Connection Conditions:

This Chapter specifies the technical and design criteria and standards to be
complied with by the Transmission Licensee and other Users connected or
seeking Connection to the Transmission System, to maintain uniformity and
quality across the system. This includes:

(a) Procedure for connection to the State Transmission System,

(b) Site responsibility schedule
(c) Connection Agreement

(5) Operating Code for State Grid:

This Chapter specifies the conditions under which the Transmission Licensee
shall operate the Transmission System and other Users of the Transmission
System shall operate their plant and/or systems for the generation and
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distribution of electricity in so far as necessary to protect the security and quality

of supply and safe operation of the Transmission Licensee‟s Transmission
System under both normal and abnormal operating conditions.

(a) Operating Policy

This Operating Policy describes the operational philosophy to maintain

efficient, secure and reliable grid operation and contains the following
aspects / Sections.

(i) System Security Aspects

This Section describes the general security aspects to be followed by

generating companies and all Users of the State grid.

(ii) Frequency and Voltage Management

This Section describes the method by which all Users of the Transmission
System shall co-operate with the State Load Despatch Centre (SLDC) for
effective control of the system frequency and managing the voltage of the
Transmission System.

(iii) Demand Estimation for Operational Purposes

This Section details with the procedures to estimate the demand by the
various Beneficiaries for their systems for the day / week / month / year
ahead, which shall be used for operational planning.

(iv) Demand Management

This Section identifies the methodology to be adopted for demand control

by each Beneficiary as a function of the frequency and deficit generation.

(v) Periodic Reports

This Section provides various provisions for reporting of the operating

parameters of the grid such as frequency, Voltage profile etc.

(vi) Operational Liaison

This Section sets out the requirement for the exchange of information in
relation to normal operation and/or events in the State grid.

(vii) Outage Planning

This Section contains procedure for outage planning relating to co-

ordination of the outages for scheduled maintenance of the Transmission
System, Generating Unit and Distribution System that will use the
Transmission System.
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(viii) Recovery Procedures

This Section sets out the procedures to be adopted following a major grid
disturbance, for Black Start and resynchronisation of islands, etc.

(ix) Operational Event/Accident Reporting

This Section states the procedure by which events are reported and the
information exchange etc. takes place.

(6) Scheduling & Despatch Code:

This Chapter specifies the procedure to be adopted for scheduling and despatch of
generation of the Generators, CGPs, generation from renewable sources
especially wind, solar and other transactions through long-term access, medium-
term and short-term open access including complementary commercial
mechanisms, on a day-ahead basis with the modality of the flow of information
between the Generating Companies and SLDC.

Most of the wind and solar energy sources are presently connected and in future
are likely to be connected to the STU or the State‟s distribution utility. However,
keeping in view the variable nature of generation from such sources and the effect
such variability has on the State grid and in view of the large-scale integration of
such sources into the grid envisaged in view of the Government of India‟s thrust
on renewable sources of energy, scheduling of wind and solar energy sources has
been incorporated in this Code.

(7) Monitoring of Generation and Drawl:

This Chapter specifies responsibilities of all Users in the monitoring of

Generating Unit reliability and performance and SLDC‟s compliance with the
scheduled drawl and injection.

(8) Cross Boundary Safety:

This Chapter specifies safety when working across a control boundary.

(9) Protection:

This Chapter specifies the co-ordination responsibility and minimum standards of

protection that are required to be installed by Users of the Transmission System.

(10) Metering, Communication and Data Acquisition:

This Chapter specifies the minimum operational and commercial metering to

meet the regulatory requirement.

(11) Management of OGC

This Chapter specifies the procedure for review/amendment and management of

OGC.
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(12) Data Registration:

This Chapter specifies list of all data required to be provided by Users to the
SLDC/Transmission Licensee and vice versa.

(13) Miscellaneous:

This Chapter specifies about issue of Orders and Practice Directions, power to
amend this OGC, saving the inherent power of the Commission and power to
remove difficulties.

1.5 INTERPRETATION

The meaning of certain terms used in the OGC shall be in accordance with the definitions
listed in Section 1.19 “Definitions”, of the OGC.

Words, terms and expressions occurring in this OGC and not defined herein shall bear
the same meaning as in the Act and IEGC. Besides, Section 1.19 of this code has been
developed on the premise that accepted engineering terms are as commonly understood
in electricity industry.

The term “OGC” means any or all parts of these Regulations.

1.6 FREE GOVERNOR MODE OF OPERATION

(1) All thermal and hydro (except with zero pondage) Generating Units: with effect
from the date to be separately notified by CERC.

(2) Any exemption from the above may be granted only by CERC for which the
concerned User / Agency shall file a petition in advance.

1.7 CHARGE/PAYMENT FOR REACTIVE ENERGY EXCHANGES

The rate for charge/payment of reactive energy exchanges shall be as per the order issued
by the Commission from time to time.

1.8 EXEMPTIONS

Any exemption from provisions of OGC shall become effective only after approval of
the Commission, for which the Agencies will have to file a petition in advance to this
Commission.
1.9 IMPLEMENTATION AND OPERATION OF THE OGC

The STU/SLDC have the duty to implement the OGC. All Users are required to comply
with the OGC. Users must provide the STU reasonable rights of access, service and
facilities necessary to discharge its responsibilities in the Users‟ premises and to comply
with instructions issued by the STU/SLDC, reasonably required to implement and
enforce the OGC.
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1.10 GENERAL REQUIREMENTS/LIMITATIONS OF OGC

The OGC contains procedures to permit equitable management of day-to-day technical

situations in the Electricity Supply System (Grid), taking into account a wide range of
operational conditions likely to be encountered under both normal and abnormal
circumstances.

Users must therefore understand and accept that the Transmission Licensee in such
unforeseen circumstances may be required to act decisively to discharge its obligations
under its Licence. Users shall provide such reasonable co-operation and assistance as the
Transmission Licensee may request in such circumstances.

1.11 CODAL RESPONSIBILITIES

In discharging its duties under the OGC, the STU/SLDC has to rely on information,
which Users supply regarding their requirements and intentions. The STU/SLDC shall
not be held responsible for any consequences that arise from its reasonable and prudent
actions on the basis of such information.

1.12 CONFIDENTIALITY

Under the terms of the OGC, the STU/SLDC shall receive information from Users
relating to their intentions in respect of their generation or supply businesses. The STU/
SLDC shall not, other than as required by the OGC, disclose such information to any
other person without the prior written consent of the provider of the information.

1.13 PROCEDURES TO SETTLE DISPUTE

In the event of any dispute regarding interpretation of any part of the OGC provision
between any User and the STU / SLDC, the matter may be referred to the Commission
for its decision. The Commission‟s decision shall be final and binding.

In the event of any conflict between any provision of the OGC and any contract or
agreement between the Users, the provision of the OGC shall prevail.

1.14 COMMUNICATION BETWEEN USERS

All communications between the STU and Users shall be in accordance with the
provisions of the relevant provision of the OGC.

Unless otherwise specifically required by the OGC, all communications shall be in

writing, save that where operation timescales require oral communication, these
communications shall be confirmed in writing as soon as practicable but not later than
two working days.

1.15 PARTIAL INVALIDITY

If any provision or part of a provision of the OGC should become or be declared

unlawful for any reason, the validity of all remaining provisions or parts of provisions, of
the OGC shall not be affected.
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1.16 DIRECTIVE

The State Government may issue policy directives in certain matters consistent with the
provisions of the Act, which the State Load Despatch Centre / Transmission Licensee
shall promptly inform the Commission and all Users of the requirement of such
direction. The directions will be complied with by the Users subject to Section 108 read
with Section 37 of the Act.

1.17 REVIEW

The Commission shall continue to review the OGC to make it compatible with the IEGC.
In the event of any inconsistencies, the provisions of IEGC shall prevail.

1.18 NON-COMPLIANCE

1. In case of a persistent non-compliance of any of the stipulations of the OGC by any User/
Beneficiary (other than STU and SLDC), the matter shall be reported by any User/
Beneficiary to the Member Secretary of the Grid Co-ordination Committee (GCC). The
Member Secretary of the GCC shall verify and take up the matter with the defaulting
User/ Beneficiary for expeditious termination of the non-compliance. In case of
inadequate response to the efforts made by Member Secretary of the GCC the non-
compliance shall be reported to the Commission. The Commission, in turn after due
process, may order the defaulting User/ Beneficiary for compliance, failing which; the
Commission may take appropriate action.

2. In case of non-compliance of any of the stipulations of the OGC by SLDC, the matter
shall be reported to the Commission.
3. Contravention of any of the provision(s) of this OGC or direction of the Commission as
stipulated above may be dealt with Section 142 and other provisions under the Act.
4. Notwithstanding anything contained in these regulations, the Commission may also take
suo-motu action against any person/utility, in case of non-compliance of any of the
provisions of the IEGC/OGC.
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1.19 DEFINITIONS

Word Meaning

(1) ABT Users Users to whom Availability Based Tariff is

applicable.

(2) Act The Electricity Act, 2003 as amended from time

to time.

(3) Ancillary Services Ancillary Services means in relation to power

system (or grid) operation, the services
necessary to support the power system (or grid)
operation in maintaining power quality,
reliability and security of the grid, e.g. active
power support for load following, reactive
power support, black start, etc.

(4) Agency A term used in the various sections of the OGC

to refer to users that utilise the State
Transmission System.

(5) Apparatus Electrical Apparatus and includes all machines,

fittings, accessories and appliances in which
conductors are used.

(6) Annexure or Appendix An Annexure or an Appendix to a Chapter of

the Odisha Grid Code.

(7) Area of Supply As defined in the concerned licence.

(8) Automatic Voltage Regulator (AVR) A continuously acting automatic excitation

control system to control the voltage of a
Generating Unit measured at the generator
terminals.

(9) Auto Transformer Transformer connecting EHV lines/bus bars of

220 and 132 KV voltages.

(10) Available Transfer Capability(ATC) The transfer capability of the transmission

system available for scheduling commercial
transactions (through long term access, medium
term open access and short term open access) in
a specific direction, taking into account the
network security. Mathematically, ATC is the
Total Transfer Capability less Transmission
Reliability Margin.

(11) Beneficiary A person who has a share in State Generating

Station and Inter State Generating Station.
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(12) Bilateral Transaction Bilateral Transaction means a transaction for

exchange of energy (MWh) between a specified
buyer and a specified seller, directly or through
a trading licensee or discovered at Power
Exchange through anonymous bidding, from a
specified point of injection to a specified point
of drawl for a fixed or varying quantum of
power (MW) for any time period during a
month.

(13) Black Start The process of recovery from a total or partial

blackout of the Transmission System.

(14) BIS The Bureau of Indian Standards.

(15) Bulk Power Consumer A person to whom electricity is provided and

who has a dedicated supply at 33 KV and
above.

(16) Bulk Power Transmission Agreement The Commercial Agreement between the
(BPTA) Transmission Licensee and a long Term
Customer for the provision of transmission
service.

(17) Capacitor An electrical facility provided for generation of

reactive power.

(18) Captive Generating Plant (CGP) Captive Generating Plant means a power plant
set up by any person to generate electricity
primarily for his own use and includes a power
plant set up by any cooperative society or
association of persons for generating electricity
and consistent with I.E.Rules, 2005 primarily
for use of members of such cooperative society
or association.

(19) CEA/Authority The Central Electricity Authority.

(20) Central Generating Station The generating stations owned by the

companies owned or controlled by the Central
Government.

(21) Central Transmission Utility (CTU) Any Government company, which the Central
Government may notify under sub-section (1)
of Section 38 of the Act.

(22) CERC The Central Electricity Regulatory

Commission.
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(23) Check Meter A meter, which shall be connected to the same

core of the Current Transformer (CT) and
Voltage Transformer (VT) to which main meter
is connected and shall be used for accounting
and billing of electricity in case of failure of
main meter.

(24) Collective Transaction A set of transactions discovered in power

exchange through anonymous, simultaneous
competitive bidding by buyers and sellers.

(25) Commercial Committee (CC) It is a committee of the GCC as referred under

Chapter-6 (Annexure-I) of the OGC.

(26) Commission/OERC Odisha Electricity Regulatory Commission

(27) Congestion A situation where the demand for transmission

capacity exceeds the Available Transfer
Capability.

(28) Connection The electric lines and electrical equipment used

to effect a Connection of a User‟s system to the
Transmission System.

(29) Connection Agreement An agreement between the Transmission

Licensee and a User setting out the terms
relating to the connection to and/or use of the
Transmission System which is referred at
section 4.5.

(30) Connection Conditions The technical conditions to be complied with by

any User having a connection to the State
Transmission System as laid down in Chapter-4
„Connection Conditions‟ of the OGC.

(31) Connection Point A point at which a User‟s plant and/or

Apparatus connects to the State Transmission
System.

(32) Contact Person A person notified by SLDC and Distribution

Company on their behalf to carry out
responsibility as required under Section-5.4
(4)(d)(v).

(33) Control Area An electrical system bounded by

interconnections (tie lines), metering and
telemetry which controls its generation and/or
load to maintain its interchange schedule with
other control areas whenever required to do so
and contributes to frequency regulation of the
synchronously operating system.
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(34) Control Person A person identified as having responsibility for

cross-boundary safety under Chapter-8 of the
OGC. Refer Section 8.3.

(35) Data Acquisition System (DAS) A system provided to record the sequence of
operation in time, of the relays/equipments as
well as the measurement of pre-selected system
parameters.

(36) Demand The demand of active power in MW and

reactive power in MVAR of electricity unless
otherwise stated.

(37) Demand Response Reduction in electricity usage by end customers

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

(38) Despatch Schedule The Ex-power Plant net MW and MWH output
of a generating station, scheduled to be
exported to the Grid from time to time.

(39) Detailed Planning Data As referred to Chapter 12 regarding Data

Registration.

(40) Deviation Deviation in a time block for a seller means its

total actual injection minus its total scheduled
generation and for a buyer means its total actual
drawl minus its total scheduled drawl.

(41) Directive A policy directive issued by the State

Government of Odisha under Sections 37 & 108
of the Act.

(42) Disconnect The act of physically separating User or Bulk

Power Consumer‟s electrical equipment from
the Transmission System.

(43) Distribution Company An organisation that is licensed or exempt from

the requirements to be licensed to own and/or
operate all or part of the Distribution System in
the State.
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(44) Distribution Licensee A licensee authorized by the Commission to

operate and maintain the Distribution System in
the State for supplying electricity to the
consumers in his Area of Supply.

(45) Distribution System “Distribution System” means the system of

wires and associated facilities between the
delivery points on the transmission lines or the
generating station connection and the point of
connection to the installation of the consumers.

(46) Distribution System Operation The Distribution System Operation and Control
& Control Centre (DSOCC) Centre as established by the Distribution
Licensee to carry out the functions as directed
by the OGC and Distribution (Planning and
Operation) Code.

(47) Disturbance Recorder (DR) A device provided to record the behaviour of

the pre-selected digital and analog values of the
system parameters during an event.

(48) Drawl The import from, or export to, State

Transmission System, of electrical energy and
power or both active/ reactive powers.

(49) Drawl Schedule The Ex-power Plant, MW that a Beneficiary is

scheduled to receive from the SGS and ISGS,
including bilateral exchanges from time to time.

(50) Eastern Region/Region Region comprising of the States of West

Bengal, Bihar, Odisha, Sikkim, Jharkhand and
DVC for the integrated operation of the
electricity system.

(51) Electricity Operator Any person who owns and/ or operates

generating plant or who holds a licence under
Section 14 of the Act, connected to the
Transmission System and any bulk supplier.

(52) Electricity Supply System (Grid) The combination of the Transmission System,
Distribution System and Power Stations.

(53) Eastern Regional Power Committee Eastern Regional Power Committee established
(ERPC) under Section 2(55) of the Act by resolution by
the Central Government for facilitating the
integrated operation of the Power System in
Eastern Region.
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(54) Energy Accounting and Audit Meters Meters used for accounting of the electricity to
various segments of electrical system so as to
carry out further analysis to determine the
consumption and loss of energy therein over a
specified time period.

(55) Entitlement A share of a beneficiary (in MW / MWh) in the

installed capacity/output capability of an ISGS.

(56) ERLDC Eastern Regional Load Despatch Centre

established under sub-Section (1) of Section 27
of the Act.

(57) Event An unscheduled or unplanned occurrence on the

Grid including faults, incidents and
breakdowns.

(58) Event Logger (EL) A device provided to record the sequence of

operation in time, of the relays / equipments at a
location during an event.

(59) External Interconnection/Connection Electric lines and electrical equipment used for
Point/ Inter Connection Point the transmission of electricity between the State
Transmission System and the User‟s system.

(60) Extra High Voltage (EHV) Where the voltage exceeds 33,000 volts under
normal conditions, subject, however, to the
percentage variation allowed by the Authority.

(61) Ex-power Plant Net MW/MWH output of a generating Station,

after deducting auxiliary consumption and
transformation losses.

(62) Fault Locator (FL) A device provided at the end of a transmission

line to measure/indicate the distance at which a
line fault may have occurred.

(63) Flexible Alternating Current A power electronics based system and other
Transmission System (FACTS) static equipment that provide control of one or
more AC transmission system parameters to
enhance controllability and increase power
transfer capability.

(64) Force Majeure Any event which is beyond the control of the
Agencies involved which they could not foresee
or with a reasonable amount of diligence could
not have foreseen or which could not be
prevented and which substantially affect the
performance by either Agency such as but not
limited to –
 -15-

a) Acts of God, natural phenomena, including

but not limited to floods, droughts,
earthquakes and epidemics;
b) Acts of any Government domestic or foreign,
including but not limited to war declared or
undeclared, hostilities, priorities,
quarantines, embargoes;
c) Riot or civil commotion
d) Grid‟s failure not attributable to Agencies
involved.

(65) Forced Outage An outage of a Generating Unit or a

transmission facility due to a fault or other
reasons, which has not been planned.

(66) Generator An organisation (including Central/State or

other generating station, in which the State has
a full share) that generates electricity and who
is subject to the OGC.

(67) Generating Company Any company or body corporate or association

or body of individuals, whether incorporated or
not, or artificial juridical person, which owns or
operates or maintains a generating station.

(68) Generating Unit An electrical Generating Unit coupled to a

turbine within a Power Station together with all
plants and Apparatus at that Power Station (up
to the Connection Point) which relates
exclusively to the operation of that turbo-
generator.

(69) Good Utility Practices Any of the practices, methods and acts engaged
in or approved by a significant portion of the
electric utility industry during the relevant time
period which could have been expected to
accomplish the desired results at a reasonable
cost consistent with good business practices,
reliably, safely and with expedition.

(70) Governor Droop In relation to the operation of the governor of a

Generating Unit, the percentage drop in system
frequency which would cause the Generating
Unit under free governor action to change its
output from zero to full load.

(71) Grid Standards Grid Standards specified by the Authority under

sub-section (d) of Section 73 of the Act.

(72) Grid Co-ordination Committee (GCC) The Committee formed under Chapter 11.
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(73) GRIDCO GRIDCO Limited registered under the

Companies Act, 1956, which is a deemed
licensee under the Act and is authorised to trade
electricity for supplying to the Distribution
Licensees. It can act as an intra State trader.

(74) IE Rules Indian Electricity Rules, 1956 or any other

Regulations in lieu of these specified by
Authority under Section 53 of the Act.

(75) ICT Transformer connecting EHV lines/bus bars of

400 and 220 kV voltages.

(76) IEC International Electro-Technical Commission.

(77) Indian Electricity Grid Code (IEGC) A document describing the philosophy and the
responsibilities for planning and operation of
Indian Power System specified by the CERC in
accordance with Sub Section 1(h) of Section 79
of the Act.

(78) Independent Power Producer (IPP) A generating Company not owned/controlled by

the Central/State Government.

(79) Interface Meters Interface Meters as defined by the CEA

(Installation and Operation of Meters)
Regulations, 2006 as amended from time to
time.

(80) Inter-State Generating Station (ISGS) A Central and other generating station in which
two or more than two States have a share and
whose scheduling is to be coordinated by the
RLDC.

(81) Inter-State Transmission System (ISTS) Inter-State Transmission System includes -

(i) Any system for the conveyance of

electricity by means of a main transmission
line from the territory of one State to
another State,
(ii) The conveyance of energy across the
territory of an intervening State as well as
conveyance within the State which is
incidental to such inter-State transmission
of energy, and
(iii) The transmission of electricity within the
territory of State on a system built, owned,
operated, maintained or controlled by
CTU.
(82) Lean Period That period when electrical demand is at its
lowest.
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(83) Licensee The holder of a licence in the State of Odisha

who has been granted a license under Section
14 of the Act.

(84) License Any license granted by OERC under Section 14

of the Act.

(85) Load The MW /MWH/MVAR/MVARh consumed by

a utility.

(86) Long Term Access The right to use the intra-state transmission
system for a period of 25 years or more.

(87) Long Term Customer A person availing or intending to avail access to

the STS for a period of 25 years or more and
who has signed BPTA with the Transmission
Licensee.

(88) Maximum Continuous Rating (MCR) The normal rated full load MW output capacity
of a Generating Unit that can be sustained on a
continuous basis at specified conditions.

(89) NALCO National Aluminium Company Limited.

(90) National Grid The entire inter-connected electric power

network of the country.

(91) Net Drawl Schedule The Drawl Schedule of a Beneficiary after

deducting the apportioned transmission losses
(estimated).

(92) NTPC National Thermal Power Corporation Limited.

(93) OHPC Odisha Hydro Power Corporation Limited.

(94) Operation A scheduled or planned action relating to the

operation of a system.

(95) Operation Coordination Committee (OCC) A committee of ERPC with members from all
constituents, which decides the operational
aspects of the regional grid.

(96) Open Access Open Access means the non-discriminatory

provision for the use of transmission lines or
Distribution System or associated facilities with
such lines or system by any licensee or
consumer or a person engaged in generation in
accordance with the regulations specified by the
Appropriate Commission.
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(97) Open Access Customer Open Access Customer means a consumer

permitted by the Commission to receive supply
of electricity from a person other than the
Distribution Licensee of his Area of Supply,
and the expression includes a generating
Company and licensee, who has availed of or
intends to avail of Open Access.

(98) Operating Margin Contingency reserve plus Operating Reserve.

(99) Operating Range The Operating Range of frequency and voltage

as specified under the operating code Chapter-5
of this OGC.

(100) Operating Reserve The additional output from a generating plant,

which must be realizable in real-time operation
to correct any system frequency fall to an
acceptable level, in the event of a loss of
generation, or loss of import from an External
Interconnection or mismatch between
generation and demand.

(101) OPGC Odisha Power Generation Corporation Limited.

(102) OPTCL Odisha Power Transmission Corporation

Limited.

(103) Orissa Act The Orissa Electricity Reform Act, 1995 as

referred u/s 185(3) of the Act.

(104) Outage The reduction of capacity or taking out of

service of a Generating Unit, Power Station or
part of the Transmission System or Distribution
System.

(105) Power System Operational Co-ordination A committee of SLDC with members from all
Committee Agencies, which decides the operational aspects
of the State grid as referred under Regulation
5.8 (4)(i) of the OGC.

(106) Peak Period That period in a day when electrical demand is

at its highest.

(107) Power Exchange The power exchange which has been granted
registration in accordance with CERC (Power
Market Regulations), 2010 as amended from
time to time.
 -19-

(108) Power Purchase Agreement (PPA) The agreement between a generator and the
licensee in which, subject to certain conditions,
the licensee agrees to purchase the electrical
output of the generator‟s Generating Unit and
the generator agrees to provide services from
this unit.

(109) Power Grid (POWERGRID) The Power Grid Corporation of India Limited,
which has been notified as CTU.

(110) Power Station An installation of one or more Generating Units

(even when sited separately) owned and/or
operated by the same Generator and which may
reasonably be considered as being managed as a
single integrated generating complex.

(111) Power System Power System means all aspects of generation,

transmission, distribution and supply of
electricity and includes one or more of the
following namely:
(a) Generating stations;
(b) Transmission or main transmission lines;
(c) Sub-stations;
(d) Tie-lines;
(e) Load despatch activities;
(f) Mains or distribution mains;
(g) Electric supply lines;
(h) Overhead lines;
(i) Service lines;
(j) Works.

(112) Protection Co-ordination Committee (PCC) It is a committee of the STU as referred under
Paragraph 4.8, 5.2(13) and 9.4 of the OGC.

(113) Reactor An electrical facility specifically designed to

absorb Reactive Power.

(114) Regional Transmission System The combination of EHV electric lines and
electrical equipment owned or operated by
Power Grid.

(115) Regional Grid The entire synchronously connected electric

power network of the concerned Region,
comprising of ISTS, ISGS and intra state
systems.

(116) Regional Load Despatch Centre (RLDC) Regional Load Despatch Centre means the
Centre established under sub-section (1) of
Section 27 of the Act.

(117) Section A part of any Chapter of OGC, which is,

identified as covering a specific topic.
 -20-

(118) Single Line Diagram (SLD) Diagrams, which are a schematic representation
of the HV/EHV Apparatus and the connections
to all external circuits at a connection, point
incorporating its numbering nomenclature and
labelling.

(119) System Operational Procedure (SOP) Procedure for various system operational
activities as provided in the OGC.

(120) Site Common Drawing Drawings prepared for each Connection Point,
which incorporates layout drawings, electrical
layout drawings, common protection/control
drawings and common service drawings.

(121) Spinning Reserve Part loaded generating capacity with some

reserve margin that is synchronized to the
system and is ready to provide increased
generation at short notice pursuant to despatch
instruction or instantaneously in response to a
frequency drop.

(122) Sub-LDC (Sub-Load Despatch Centre) The Area–wise Load Despatch Centre, as
established by SLDC to carry out the
instructions of SLDC and perform all the duties
assigned to it in the OGC and Distribution
Code.

(123) State The State of Odisha.

(124) State Generating Station (SGS) A generating station whose entire generation of
electricity is dedicated to the State.

(125) State Load Despatch Centre (SLDC) This means the centre established under Sub
Section 31 of the Act.

(126) Standard Planning Data As referred to in Data Registration Section

under Chapter 12.

(127) Standing Committee for A Committee constituted by the CEA to discuss,

Transmission Planning discuss, review and finalise the proposals for
expansion or modification in the ISTS and
associated intra-State systems.

(128) State Transmission System (STS) The transmission of electricity within the
territory of State on a system built, owned,
operated, maintained or controlled by STU /
Transmission Licensee.
 -21-

(129) State Transmission Utility (STU) State Transmission Utility notified by the State
Government of Orissa under Section 39 (1) of
the Act. OPTCL has been notified as the STU.

(130) Static VAR Compensator (SVC) An electrical facility designed for the purpose
of generating or absorbing reactive power.

(131) Supervisory Control and Data The combination of transducers, communica-

Acquisition/SCADA tion links and data processing systems, which
provides information to the SLDC on the
operational State of the Transmission System
and the generators‟ Generating Units.

(132) Supplier A person authorised to sale electricity to

licensee(s) or consumer(s) under a license
granted under the Act and who is subject to the
OGC.

(133) Supply Supply in relation to electricity, means the sale

of electricity to a licensee or consumer.

(134) Technical Coordination Committee (TCC) The committee set up by RPC to Coordinate the
technical and commercial aspects of the
operation of the regional grid.

(135) Time Block Block of 15 minutes each for which special

energy meters record specified electrical
parameters and quantities with first Time Block
starting at 00.00 Hrs.

(136) Transmission Licence The licence granted by the Commission to

transmit electricity in the State under Section 14
of the Act.

(137) Transmission Licensee A licensee authorised by the Commission to

establish or operate transmission lines.

(138) Transmission System Transmission System means the system

consisting of Extra High Voltage electric lines,
having design voltage of 33 kV and higher
owned and/or operated by the licensee for the
purposes of the transportation of electricity
from one Power Station to a substation or to
another Power Station or between substations or
to or from any External Interconnection
including 33/11 kV bays/equipment up to the
interconnection with the Distribution System,
any plant and Apparatus and meters owned or
used in connection with transmission, and such
buildings or part thereof as may be required to
accommodate such plant Apparatus, other
works and operating staff thereof.
 -22-

(139) Transmission Reliability Margin (TRM) The amount of margin kept in the total transfer
capability necessary to ensure that the
interconnected transmission network is secure
under a reasonable range of uncertainties in
system conditions.

(140) Unscheduled Interchange In a time block for a generating station or a

seller means its total actual generation minus its
total scheduled generation and for a beneficiary
or buyer means its total actual drawl minus its
total scheduled drawl.

(141) User A term utilised in various Sections of the OGC

to refer to the Persons including Beneficiaries,
Generating Stations, Licensees, Open Access
Customers, EHT Consumers, Power Grid, other
Regional and States using STS, as more
particularly identified in each Section of the
OGC.

(142) Utility The electric lines or electrical plant, including

all lands, buildings, works and materials
attached thereto belonging to any person acting
as a generating Company or Licensee under
provisions of the Act.

Words and expressions used in these Regulations and not defined herein but defined in the Act,
IEGC and other Regulations of OERC shall have the meaning assigned to them in the Act, IEGC
and OERC Regulations.
 -23-

CHAPTER-2

ROLE OF VARIOUS ORGANISATIONS AND THEIR LINKAGES

2.1 INTRODUCTION

In the light of the Act, it has become necessary to re-define the role of State Load
Despatch Centre (SLDC), the State Transmission Utility (STU) etc. and their
organisational linkage so as to facilitate development and smooth operation of State grid.
This Chapter defines the function of the various organisations so far as it relates to the
OGC.

2.2 ROLE OF SLDC

2.2.1 As per Section 32 of the Act, the functions of the SLDC are as follows:
(1) The SLDC shall be the apex body to ensure integrated operation of the Power
System in the State.

(2) The State 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 OGC.

(3) SLDC shall-

(a) be responsible for optimum scheduling and despatch of electricity within

the State, in accordance with the contracts entered into with the licensees or
the generating companies operating in Odisha;
(b) monitor grid operations;
(c) keep accounts of the quantity of electricity transmitted through the State
grid;
(d) exercise supervision and control over the State Transmission System;
(e) be responsible for carrying out real time operations for grid control and
despatch of electricity within the State through secure and economic
operation of the State grid in accordance with the Grid Standards and the
OGC;
(f) shall comply with the directions of the RLDC;
(g) levy and collect such fees and charges from the generating companies and
licensees using the intra State Transmission System as may be specified by
the Commission;
(h) discharge the functions assigned to it under the provisions of the Act and
these Regulations in an independent and unbiased manner.

Provided that in event of a SLDC being operated by the STU, as per first
proviso of sub-section (2) of Section 31 of the Act, adequate autonomy shall
be provided to the SLDC in order to discharge its functions in the above
mentioned manner.

(4) The State 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.
 -24-

(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 State Load Despatch Centres.

(6) All directions issued by the State Load Despatch Center to any Transmission
Licensee of the State or any other licensee of the State or State Generating
Company or substation in the State and shall be 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 Sate grid or in relation to any direction given by the
State Load Despatch Centre, it shall be referred to the Commission for decision.
However, pending the decision of the Commission, the directions of the State
Load Despatch Centre shall be complied with by the licensee or the Generating
Company, as the case may be.

2.2.2 The following are contemplated as exclusive functions of SLDC

(1) System operation and control including intra-state 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 state deviation/ unscheduled interchange (UI) pool account and State
reactive energy account.
(7) Operation of ancillary services

2.2.3 In case of inter-state bilateral and collective short-term open access transactions having a
state utility or an intra-state entity as a buyer or seller, SLDC shall accord concurrence or
no objection or a prior standing clearance, as the case may be, in accordance with the
Central Electricity Regulatory Commission (Open Access in inter-state Transmission)
Regulations, 2008 and Orissa Electricity Regulatory Commission (Terms and Conditions
of Open Access) Regulations, 2005, amended from time to time.

2.2.4 All complaints regarding unfair practices, delays, discrimination, lack of information,
supply of wrong information or any other matter related to Open Access in intra-state
transmission shall be directed to the SLDC. The SLDC shall investigate and endeavour
to resolve the grievance. In case the SLDC is unable to resolve the matter, it shall be
reported to the Commission for a decision.

2.2.5 SLDC shall establish Sub-LDCs to carry out the following functions:
(a) The Sub-LDC shall help in focused monitoring and control of Distribution
System in its local area.
(b) Receive and carryout the instructions of SLDC.
(c) Co-ordinate with Distribution System operation and control centre (DSOCC) and
SLDC to streamline the operation and enhance case of operation efficiency.
 -25-

2.2.6 SLDC shall, for the purpose of payment of transmission charges/ capacity charges and
incentives, certify:

(1) Availability of State Transmission System,

(2) Availability and Plant Load Factor for SGS (Thermal) and IPP whose scheduling
is done by SLDC,
(3) Capacity Index for SGS (Hydro).

2.3 ROLE OF STU

(1) Section-39 of the Act outlines that the functions of the STU shall be –
(a) To undertake transmission of electricity through the State Transmission System.
(b) To discharge all functions of planning and co-ordination relating to the State
Transmission System with
 Central Transmission Utility;
 State Governments;
 Generating companies;
 Regional Power Committees;
 Authority;
 Licensees;
 Any other person notified by the State Government in this behalf;

(c) To ensure development of an efficient, co-ordinated and economical system of

the State transmission lines for smooth flow of electricity from a generating
station to the load centres;
(d) To provide non-discriminatory Open Access to its Transmission System for use
by -

(i) Any licensee or generating Company on payment of the transmission

charges; or
(ii) Any consumer as and when such Open Access is provided by the
Commission under sub-section (2) of Section- 42 of the Act, on payment
of the transmission charges and a surcharge thereon, as may be specified
by the Commission.

(2) Until a Government company or any authority or corporation is notified by the

State Government, the STU shall operate the SLDC.

2.4 ROLE OF TRANSMISSION LICENSEE

The functions of Transmission Licensee are as follows:

(a) Build, maintain and operate an efficient, co-ordinated and economical
Transmission System.
(b) Comply with the directions of SLDC.
(c) Provide Open Access as in 2.3. (1)(d) Above

2.5 ROLE OF DISTRIBUTION LICENSEE

(1) The functions of Distribution Licensee are as follows:

(a) Develop and maintain an efficient, co-ordinated and economical Distribution

System in his Area of Supply;
 -26-

(b) Provide non-discriminatory Open Access to its Distribution System for use by
(i) Any licensee or generating Company on payment of the distribution
charges; or
(ii) Any consumer as and when such Open Access is provided by the
Commission under sub-section (2) of Section-42 of the Act, on payment
of the transmission charges and a surcharge thereon, as may be specified
by the Commission.

(2) Establish DSOCC at a strategic location near the geographical centre and load
centre of the Distribution Licensees‟ Area of Supply, having adequate
communication facilities. The DSOCC shall be manned round the clock with the
required staff during emergency periods. It shall take appropriate action in
response to grid warnings as decided by the Distribution Licensee and convey
suitable instructions to the operating staff. It shall take timely action in response to
grid warnings as per standard instructions laid down by the Distribution Licensee
in this regard and if necessary issue appropriate instructions in addition, if a
particular situation warrants. The SLDC / Sub-LDC shall intimate the Distribution
Licensee through DSOCC, regarding significant deviations of final schedules of
State generators and CGS on overall merit order. The DSOCC shall undertake
suitable load management and curtailment.
 -27-

CHAPTER -3
PLANNING CODE FOR THE STATE TRANSMISSION SYSTEM

3.1 INTRODUCTION

(1) The Planning Code specifies the policy and procedures to be applied in planning
of State Grid and the regional links.
(2) This Chapter identifies the method for data submissions by Users to the STU for
the planning and development of the Transmission System. This Chapter also
specifies the technical and design criteria and procedure to be applied by the STU
in the planning and development of the Transmission System.

3.2 OBJECTIVE

(1) The provisions of this Chapter are intended to enable the STU in consultation
with Users, to provide an efficient, co-ordinated, secure and economical
Transmission System in order to satisfy requirement of future demand. It also
provides methodology and information exchange amongst Users STU/SLDC and
CTU/RLDC, RPC, NLDC and CEA in planning and development of the STS.
(2) A requirement for reinforcement or extension of the Transmission System may
arise for a number of reasons, including but not limited to the following.
(a) Development on a User‟s system already connected to the Transmission
System.
(b) The introduction of a new Connection Point between the User‟s system
and the Transmission System.
(c) A general increase in system capacity to remove operating constraints and
maintain standards of security.
(d) Stability considerations.
(e) Cumulative effect of any of the above.

(3) Accordingly, the reinforcement or extension of the Transmission System may

involve work at an entry or exit point (Connection Point) of a generator or
Distribution Company or Open Access customer to the Transmission System.

(4) Since development of all Users‟ systems must be planned well in advance to
permit consents and way leaves to be obtained and detailed engineering design /
construction work to be completed, the STU will require information from Users
and vice versa. To this effect the Planning Code imposes a time scale, for
exchange of necessary information between the STU and Users having regard,
where appropriate, to the confidentiality of such information.

3.3 SCOPE

The Planning Code applies to STU, other Transmission Licensees, the State Generating
Station, IPPs, IPPs selling power on merchant basis and all other Users, connected to
and/or using and involved in developing the State Transmission System.
 -28-

3.4 PLANNING PHILOSOPHY

(1) CEA would formulate perspective transmission plan for inter-State Transmission
System as well as Intra State Transmission System. These perspective
transmission plans would be continuously updated to take care of the revisions in
load projections and generation scenarios considering the seasonal and time of the
day variations. In formulating perspective transmission plan the transmission
requirement for evacuating power from renewable energy sources shall also be
taken care of. The transmission system required for open access shall also be
taken into account in accordance with National Electricity Policy so that
congestion in system operation is minimized.

(2) The STU shall carry out planning process from time to time as per the requirement
for identification of major State Transmission System, including the transmission
system associated with generation projects and system strengthening schemes,
which shall fit in with the perspective plan developed by CEA. While planning
schemes, the following shall be considered in addition to the data of authenticated
nature collected from and in consultation with various Agencies/
generators/licensees by STU:
(a) Perspective plan formulated by CEA.
(b) Electric Power Survey of India published by the CEA.
(c) Transmission Planning Criteria and guidelines issued by the CEA.
(d) Operational feedback from SLDC.
(e) Reports on National Electricity Policy, issued by Govt. of India, which are
relevant for development of the State Transmission System.
(f) Central Electricity Regulatory Commission (Grant of Connectivity, Long-
term Access and Medium-term Open Access in inter-state Transmission
and related matters) Regulations, 2009.
(g) OERC (Terms and Conditions for Open Access) Regulations, 2005.
(h) Renewable capacity addition plan issued by Ministry of New and
Renewable Energy Sources (MNRES), Govt of India.

(3) In addition to the major State Transmission System, the STU shall plan, from
time to time, system-strengthening schemes, need of which may arise to
overcome the constraints in power transfer and to improve the overall
performance of the grid. The State transmission proposals including system-
strengthening scheme identified on the basis of the planning studies would be
discussed, reviewed and finalised by the STU in consultation with -
(a) Central Transmission Utility,
(b) State Government,
(c) Generating Companies,
(d) Regional Power Committee,
(e) Authority,
(f) Licensees,
(g) Any other person notified by the State Government in this behalf.

(4) As per OERC Regulation for providing Open Access in the State transmission,
the nodal Agency for arranging the long-term transmission access to the applicant
shall be the STU, if its system is used and for the short-term transmission access
shall be the SLDC.
 -29-

(5) In case long-term Open Access in State Transmission System cannot be allowed
without system strengthening, the applicant may request STU to carry out system
studies to identify strengthening requirement and its cost estimates.

Further, to provide long-term Open Access as per the terms and conditions
formulated by OERC and STU from time to time, the application for long-term
Open Access including system strengthening identified by STU in State
Transmission System shall be discussed and finalised in consultation with other
Agencies.

(6) All Users and Agencies will supply to the STU, the desired planning data from
time to time to enable to formulate and finalize its plan.

(7) The plan reports shall contain a Chapter on additional transmission requirement,
which may include not only State transmission lines but also additional
equipment such as transformer, capacitors, reactors etc.

(8) The plan report shall also indicate the action taken to fulfill the additional
requirement and actual progress made on new schemes. These reports will be
available to any interested party for making investment decision/connection
decisions to the State Transmission System.

(9) As voltage management plays an important role in inter/intra State transmission

of energy, special attention shall be accorded to planning of capacitors, reactors,
Static VAr Compensators (SVC) and Flexible Alternative Current Transmission
Systems (FACTS), etc.

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

In case of long-term Open Access applications requiring any strengthening in the

Distribution System to absorb/evacuate power beyond STS, the STU shall co-
ordinate with the concerned Distribution Company(s). The Distribution
Company(s) shall augment the Distribution System in a reasonable time to
facilitate the interchange of such power.

(11) The Inter-State Transmission System and associated State Transmission System
are complementary and inter-dependent and planning of one affects the other's
planning and performance. Therefore, the associated State Transmission System
shall also be discussed and reviewed before implementation during the discussion
for finalising State Transmission System proposal indicated at section 3.4 (3)
above.

3.5 PLANNING CRITERION

General Policy
(1) The planning criterion is based on the security philosophy on which the State
Transmission System has been planned. The security philosophy may be as per
the Transmission Planning Criteria and other guidelines as given by CEA. The
general policy shall be as detailed below:
 -30-

(a) As a general rule, the State Transmission System shall be capable of

withstanding and be secured against the following contingency outages
a. without necessitating load shedding or rescheduling of generation during
steady State operation:
- Outage of a 132 kV S/C line or,
- Outage of a 220 kV S/C line or,
- Outage of a 400 kV S/C line or,
- Outage of single Interconnecting transformer, or
- Outage of one pole of HVDC bipolar line, or one pole of HVDC back to
back Station or
- Outage of 765 kV S/C line.
b. without necessitating load shedding but could be with rescheduling of
generation during steady state operation-
- Outage of a 400 kV S/C line with TCSC, or
- Outage of a 400kV D/C line, or
- Outage of both pole of HVDC Bipole line or both poles of HVDC back to
back Station or
- Outage of a 765kV S/C line with series compensation.

The above contingencies shall be considered assuming a pre-contingency system

depletion (Planned outage) of another 220 kV D/C line or 400 kV S/C line in
another corridor and not emanating from the same substation. All the Generating
Units may operate within their reactive capability curves and the network voltage
profile shall also be maintained within voltage limits specified.

(b) The State Transmission System shall be capable of withstanding the loss of
most severe single system in feed without loss of stability.

(2) Any one of these events defined above shall not cause:
(a) Loss of supply
(b) Prolonged operation of the system frequency below and above specified limits.
(c) Unacceptable high or low voltage
(d) System instability
(e) Unacceptable overloading of the State Transmission System element.
(3) In all substations (132 kV and above), at least two transformers shall be provided.
(4) STU shall carry out planning studies for reactive power compensation including
reactive power compensation requirement at the existing generator's/ bulk consumer's
switchyard and for connectivity of new generator/bulk consumer to the state
transmission system.
(5) Suitable System Protection Schemes may be planned by SLDC in consultation with
CEA, CTU, ERPC and the Users, either for enhancing transfer capability or to take
care of contingencies beyond that indicated in a(1) above.
3.6 PLANNING DATA REQUIREMENT

(1) Under this Planning Code, the Distribution Licensees/State generating

companies/ IPPs/licensees are to supply two types of data to STU:
 -31-

(a) Standard Planning Data

To enable the STU to discharge its responsibilities under the licence, to conduct
system studies and prepare perspective plans for electricity demand, generation
and transmission as detailed in Section 3.8 below, the Users shall furnish data to
the STU from time to time as detailed under Data Registration Chapter in this
OGC and categorised as Planning Data (PD).
(i) Standard planning data consists of details, which are expected to be
normally sufficient for the STU to investigate the impact on the STS due to
User development.

(ii) Standard planning data covering (a) preliminary project planning data (b)
committed project planning data and (c) connected planning data should
be furnished by the Distribution Licensees and Generating companies
connected to the STS. This data shall be furnished to STU from time to
time in the standard formats supplied by the STU.

(b) Detailed Planning Data

To enable Users to co-ordinate planning, design and operation of their plants and
systems with the Transmission System they may seek certain salient data of
Transmission System as applicable to them, which the STU shall supply from
time to time as detailed under Data Registration Chapter of this OGC and
categorised as Detailed System Data (Transmission).

Detailed planning data consist of additional, more detailed data not normally
expected to be required by STU to assess the impact of User development on the
STS. The Users of STS shall furnish this data as and when requested by STU.

3.7 IMPLEMENTATION OF TRANSMISSION PLAN

The actual program of implementation of transmission lines, interconnecting

transformers, reactors/capacitors and other transmission elements will be determined by
STU in consultation with the concerned Agencies/Users. The Transmission Licensee
through the concerned Agency shall ensure the completion of these works in the required
time frame.

3.8 PERSPECTIVE PLAN

(1) The STU is charged with the responsibility to prepare and submit a long-term (10
years) plan to the Commission for Transmission System expansion to meet the
future demand in accordance with the Licence Conditions and the practice
direction of the Commission.

(2) For fulfilment of the above requirement the STU shall:

(a) Forecast the demand for power within the State in each of the succeeding five
years and provide to the Commission details of the demand forecasts, data,
methodology and assumptions on which the forecasts are based.
 -32-

(b) GRIDCO shall prepare a least cost generation plan for the State to meet the ten
years load demand as per the forecast, after examining the economic, technical
and environmental aspects of all available alternatives taking into account the
existing contracted generation resources and effects of demand side
management.

(c) Discharge all functions of planning and co-ordination relating to the State
Transmission System compatible with the above load forecast and generation
plan a long-term (10 years) plan for the Transmission System in accordance
with Section-39 (2) (b) of the Act, compatible with the above load forecast and
generation plan in consultation with CEA. Central Transmission Utility (CTU)
shall have to be consulted in connection with systems to evacuate power from
inter-State Transmission System.

(3) The STU shall prepare and submit to the Commission on an annual basis, a
statement showing in respect of each of the 5 succeeding financial years forecasts
of circuit capacity, power flows and loading on the Transmission System under
Transmission Licence General Conditions Clause-15.5 of Appendix 4B to OERC
(Conduct of Business) Regulations, 2004.

3.9 PLANNING STANDARDS AND PROCEDURES

The Transmission System shall be planned in accordance with the Transmission System
planning and security standards under Transmission Licence General Conditions Clause-
13 of Appendix 4B to OERC (Conduct of Business) Regulations, 2004.

The generation expansion planning shall be carried by GRIDCO out in accordance with
the Power Supply Planning and Security Standards under aforesaid Clause-13.

3.10 PLANNING RESPONSIBILITY

(1) The primary responsibility of load forecasting within its area rests with each of
the Distribution Companies. The Distribution Companies shall determine peak
load and energy forecasts of their respective areas for each category of loads for
each of the succeeding five years and submit the same annually by 31st
December to the Transmission Licensee along with details of the demand
forecasts, data, methodology and assumptions on which the forecasts are based.
The load forecasts shall be made for each of the External Connection Points
between the STU and User and shall include annual peak load and energy
projections and daily load curve. The demand forecasts shall be updated annually
or whenever major changes are made in the existing forecasts or planning. While
indicating requirements of single consumer with large demands (5 MW or higher)
the Distribution Company shall satisfy itself as to the degree of certainty of the
demand materialising.

(2) The STU is responsible for integrating the load forecasts submitted by each of the
Distribution Companies and determining the long term (10 years) load forecasts
for the State within ninety days of the date on which the distribution companies
furnished all the required information consistent to provisions of the OGC. In
doing so the STU may apply appropriate diversity factors, and satisfy itself
regarding probability of materialisation of bulk loads of consumers with demands
 -33-

above 5 MW in consultation with that Distribution Company concerned.

(3) The STU may also review the methodology and assumptions used by the
Distribution Company in making the load forecast, in consultation with the
Distribution Company. The resulting overall load forecast will form the basis of
planning for expansion of generation and the Transmission System.

(4) In the event, Distribution Companies failed to provide all the requisite
information within the time frame and in accordance with the form provided by
the STU, the STU shall approach to the Commission for a directive.
 -34-

CHAPTER– 4
CONNECTION CONDITIONS
4.1 INTRODUCTION

Connection Conditions specify the minimum technical and design criteria, which shall be
complied with by STU/Transmission Licensee and any Agency connected to or seeking
the connection to the State Transmission System. Such agencies, connected to or seeking
the connection to the State Transmission System shall comply with CEA (Technical
Standards for connectivity to the Grid) Regulations, 2007. They also set out the
procedures by which Transmission Licensee shall ensure compliance by any Agency
with above criteria as pre-requisite for the establishment of an agreed connection.

4.2 OBJECTIVE

The objective of this Section is to ensure the following:

(1) To ensure the safe operation, integrity and reliability of the grid.
(2) That the basic rules for connectivity are complied with in order to treat all users
in a non-discriminatory manner.
(3) Any new or modified connections, when established, shall neither suffer from
unacceptable effects due to its connections to the State Transmission System nor
impose unacceptable effects on the system of any other connected Agency.
(4) By specifying minimum design criteria, to assist Users in their requirement to
comply with licence obligations and hence ensure that a system of acceptable
quality is maintained.
(5) Any person seeking a new connection to the grid is required to be aware, in
advance, of the procedure for connectivity to the STU and also the standards and
conditions his system has to meet for being integrated into the grid.
(6) The ownership and responsibility for all items of equipment is clearly specified in
a schedule (Site Responsibility Schedule) for every site where a connection is
made.

4.3 SCOPE

(1) The Connection Conditions apply to all STU/SGSs and any other User/ Licensee
connected to and involved in developing the State Transmission System. This
Connection Code also applies to all Agencies, which are planning to
generate/transmit/utilise and/or are generating / transmitting / utilising energy to/from
the State Transmission System. The Connection Conditions for Generating Units
embedded in the Distribution Systems and not connected to the Transmission
Systems, shall be finalised by the respective Distribution Licensees and Generators.
However, such entities shall abide by the CEA (Technical Standards for connectivity
to the Grid) Regulations, 2013, in order to ensure that the integrated grid is not
adversely affected.

(2) These conditions shall apply to all new connections. All the existing Users shall
modify their systems for complying with this Section within two years from the date
of this Code comes into effect.
 -35-

4.4 PROCEDURE FOR CONNECTION TO AND/OR USE OF THE

TRANSMISSION SYSTEM

(1) Prior to an Agency being connected to the State Transmission Systems all
necessary conditions outlined in the OGC in addition to other mutually agreed
requirements to be complied with, must be fulfilled by the Agency. Any Agency
seeking to establish new or modified arrangements for connection to and/or use
of the Transmission System shall submit the following report, data and
undertaking along with an application to the Transmission Licensee:

(a) Report stating purpose of proposed connection and/or modification, connection

site, Transmission Licensee to whose system connection is proposed Connection
Point, description of Apparatus to be connected or modification to Apparatus
already connected and Beneficiaries of the proposed connection.

(b) Data as applicable and as listed in the Data Registration Chapter in this OGC.

(c) Construction schedule and target completion date.

(d) An undertaking that the User shall abide by the OGC, IEGC and provisions of IE
Rules and various standards including Grid Connectivity Standards made
pursuant to the Act for installation and operation of the Apparatus.

(2) However, in case of the existing connections between State Transmission System
and State Generating Station, a relaxation of one year in respect of the
Connection Conditions is allowed so that the present arrangements may continue.
The process of re-negotiation of the Connection Conditions with generating
station should be completed within a period of one year. In case it is determined
that the compliance of Connection Conditions would be delayed further, the
Commission may consider further relaxation for which a petition will have to be
filed by the concerned User along with STU‟s recommendation/comments. The
cost of modification, if any, shall be borne by the concerned User.

(3) The Transmission Licensee/STU shall normally make a formal offer to the User
within one month of receipt of the application complete with all information as
may reasonably be required, subject to provision in section 4.4(6) below.

(4) The offer shall specify and take into account any works required for the extension
or reinforcement of the Transmission System to satisfy the requirements of the
connection application and for obtaining statutory clearances, way leaves as
necessary.

(5) In respect of offers for modification of existing connection, the terms shall take
into account, the existing Connection Agreement.

(6) (a) If the nature of complexity of the proposal is such that the prescribed time limit
for making the offer is not adequate, the Transmission Licensee / STU shall make
a preliminary offer within the prescribed time limit indicating the extent of further
time required with the consent of the Commission for more detailed examination
of the issues.
 -36-

(b) On receipt of the preliminary offer, the User shall indicate promptly whether the
Transmission Licensee/STU should precede further to make a final offer within
the extended time limit.

(7) All offers (other than preliminary offers) including revised offers shall remain
valid for sixty days of issue of offer.

(8) The Transmission Licensee/STU shall make a revised offer, upon request by a
User, if necessitated by changes in data earlier furnished by the User.

(9) In the event of the offer becoming invalid or not being accepted by any User
within the validity period, no further action shall be taken by the Transmission
Licensee / STU on the connection applications.

(10) The Transmission Licensee/STU may reject any application for connection to
and/or use of Transmission System:

(a) If such proposed connection will violate any provision(s) under clause-15.3 to
Appendix-4B to OERC (Conduct of Business) Regulations, 2004.

(b) If the proposed works stated in the application do not lie within the purview of
the licence or do not conform to any provision of the OGC.

(c) If the applicant fails to give confirmation and undertakings according to sections
4.4(1)(d) of this Chapter.

4.5 CONNECTION AGREEMENTS

A Connection Agreement shall include, as appropriate, within its terms and conditions
the following:

(1) A condition requiring both parties to comply with the OGC;

(2) Details of connection, technical requirements with specific references to reactive
power compensation/operation of Generating Units and Power Station, if any,
and commercial arrangements, (in accordance with relevant provision of Indian
Electricity Grid Code wherever applicable).
(3) Details of any capital related payments arising from necessary reinforcement or
extension of the system, data communication, RTU etc. and demarcation of the
same between the concerned parties;
(4) A Site Responsibility Schedule as referred at section 4.13(1);
(5) General philosophy, guidelines etc. on protection and telemetry.

A model Connection Agreement is placed at Annexure-1 to Chapter-4.

4.6 PROCEDURE FOR SITE ACCESS, SITE OPERATIONAL ACTIVITIES AND

MAINTENANCE STANDARDS

(1) The Connection Agreement will also indicate any procedure necessary for site
access, site operational activities and maintenance standard for equipment of the
STU/Transmission Licensee at SGS/Licensee premises and vice-versa.
 -37-

(2) The User owning the connection site shall provide reasonable access and other
required facilities to another User whose equipment is installed at the connection site
for installation, operation and maintenance, etc.

4.7 SYSTEM PERFORMANCE

Transmission System Parameter variations

(1) General

Within the Power System, instantaneous values of system frequency and voltage are
subject to variation from their nominal value. All Agencies shall ensure that plant and
Apparatus requiring service from/to the State Transmission System is of such design and
construction that satisfactory operation will not be prevented by such variation.

(2) Frequency variations

Rated frequency of the system shall be 50.0 Hz and shall normally be controlled within
the limits as per regulations /Standards framed by the Authority subject to allowable
limit as specified by the manufacturer (within the limits of the Regulations).

(3) Voltage variations

(a) The variation of voltage may not be more than the voltage range specified in the
regulations / Standards framed by the Authority.

(b) The Agency engaged in sub-transmission and distribution shall not depend upon
the State Transmission System for reactive support when connected. The Agency
shall estimate and provide the required reactive compensation in its transmission
and distribution network to meet its full reactive power requirement, unless
specifically agreed to with STU/Transmission Licensee.

(4) Harmonics

Total Voltage Harmonic Distortion (THD) in the Power System is required to be within
the limit for various applications. (Refer IEEE Standard 519)
Voltage THD is generally defined as below:

Total Harmonic Distortion of the voltage waveform is the VTHD, which is the ratio of
the root-sum-square value of the harmonic content of the voltages to the root-mean-
square value of the fundamental voltage.

VTHD = V2 2 + V3 2 + V4 2+ V5 2+V6 2+ ..... X 100%

√ V12
The limits of harmonics shall be maintained as per CEA‟s notification of Grid Standards
from time to time, the current limits are as specified hereunder:
 -38-

System voltage (kV rms) Total Harmonic Individual Harmonic of

Distortion (%) any particular Frequency
(%)
765 1.5 1
400 2 1.5
220 2.5 2
33 to 132 5 3

(5) Insulation Co-ordination and Rupturing capacity of Switchgear

Insulation co-ordination of the Users‟ equipment shall conform to applicable Indian

Standards/Codes. Rupturing capacity of switchgear shall not be less than that notified by
the Transmission Licensee / STU/Authority from time to time.

4.8 USER’S AND TRANSMISSION LICENSEE’S EQUIPMENT AT CONNECTION

POINTS

(1) General

All equipment connected to the State Transmission System shall be of such design and
construction as to satisfy at least the requirements of the relevant Bureau of Indian
Standards (BIS)/IEC/ prevailing Code of Practice.

Installation of all electrical equipment shall comply with IE Rules/CEA Regulations.

For every new connection sought, the Transmission Licensee shall specify the
Connection Point and the voltage to be used, along with the metering and protection
requirements as specified in the Metering and Protection Chapter.

(2) Sub-Station Equipment

(a) All EHV sub-station equipments and installations shall comply with Bureau of
Indian Standards (BIS)/ IEC/prevailing Code of practice.
(b) All equipment shall be designed, manufactured and tested and certified in
accordance with the quality assurance requirements as per IEC/BIS standards.
(c) Each connection between a User and State Transmission System shall be
controlled by a circuit breaker capable of interrupting, at the Connection Point,
the short circuit current as advised by Transmission Licensee in the specific
Connection Agreement.

(3) Fault Clearance Times

(a) The fault clearance time when all equipments operate correctly, for a three phase
fault (close to the bus-bars) on User‟s equipment directly connected to State
Transmission System and for a three phase fault (close to the bus-bars) on State
Transmission System connected to Agencies equipment, shall not be more than:
(i) 100 milli seconds (ms) for 800 kV & 400 kV
(ii) 160 milli seconds (ms) for 220 kV & 132 kV
 -39-

(b) Back-up protection shall be provided for required isolation/protection in the event
of failure of the primary protection systems provided to meet the above fault
clearance time requirements. If a Generating Unit is connected to the State
Transmission System directly, it shall withstand, until clearing of the fault by
back-up protection on the State Transmission System.

(4) Protection

Protection systems are required to be provided by all Users connected to the State
Transmission System in co-ordination with STU. In case of installation of any device,
which necessitates modification/replacement of existing protection relays/ scheme in the
network, owner of respective part of network shall carry out such modification/
replacement.

Protection systems are required to isolate the faulty equipments and protect the other
components against all types of faults, internal/ external to them, within the specified
fault clearance time with reliability, selectivity and sensitivity. All Agencies connected to
the State Transmission System shall provide protection systems and metering systems as
agreed in the Connection Agreement conforming to Protection and Metering Chapter of
the OGC (i.e. Chapters 9 & 10)

Relay setting coordination shall be done at State level by the Protection Co-ordination
committee of the STU as specified under Section 5.2(13) and 9.4 of the OGC.

Details of all protection system installed shall be provided by STU.

4.9 GENERATING UNITS AND POWER STATIONS

(1) A Generating Unit shall be capable of continuously supplying its normal rated active/
reactive output within the system frequency and voltage variation range indicated at
section 4.7 above, subject to the design limitations specified by the manufacturer
(within limit of Regulations).
(2) A Generating Unit shall be provided with an AVR, protective and safety devices, as
set out in Connection Agreements.
(3) Each Generating Unit shall be fitted with a turbine speed governor having an overall
droop characteristic within the range of 3% to 6% subject to design limitations
specified by the manufacturer, which shall always be in service.
(4) Each Generating Unit shall be capable of instantaneously increasing output by 5%
when the frequency falls limited to 105% MCR (Maximum Continuous Rating).
Ramping back to the previous MW level (in case the increased output level cannot be
sustained) shall not be faster than 1% per minute.
(5) Apart from the above required specified in point 1 to 4, all generating unit supplying
power to state GRID, shall comply with CEA (Technical Standards for Connectivity
to the Grid) Regulations 2007 and the amendments thereto.
(6) For existing Power Stations, the equipment for data transmission and
communications shall be owned and maintained by the Licensee i.e. STU, unless
alternative arrangements are mutually agreed.

For new Power Stations, the equipment for data transmission and communications
shall be owned and maintained by the respective generator.
 -40-

4.10 REACTIVE POWER COMPENSATION

(1) Reactive power compensation and/or other facilities should be provided by

Transmission Licensee and Distribution Licensees as far as possible in the low
voltage systems close to the load points thereby avoiding the need for exchange of
reactive power to/from State Transmission System and to maintain Transmission
System voltage within the specified range.
(2) Line reactors may be provided to control temporary over voltage within the limits as
set out in Connection Agreements.
(3) The additional reactive compensation to be provided by the User shall be indicated
by Transmission Licensee in the Connection Agreement for implementation.
(4) The user already connected to the grid shall also provide additional reactive
compensation as per the quantum and time frame decided by respective STU in
consultation with SLDC. The Users and Distribution Licensee shall provide
information to STU and SLDC regarding the installation and healthiness of the
reactive compensation equipment on regular basis. STU shall regularly monitor the
status in this regard.

4.11 DATA 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 SLDC, under normal and abnormal conditions. All Agencies including CGS
who are allowed open access 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 the nearest SCADA Interface Point
of the Transmission Licensee. The associated communication system to facilitate data
flow up to the nearest SCADA Interface Point of the Transmission Licensee, as the case
may be, shall also be established by the concerned Agency as agreed by STU in
Connection Agreement. All Agencies in coordination with STU shall provide the
required facilities at their respective ends and the nearest SCADA Interface Point of the
Transmission Licensee as agreed in the Connection Agreement. However, the SCADA
communication facilities should be made available in every 220 KV grid S/S by OPTCL.

4.12 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 State Transmission System for recording of dynamic performance of the system.
Users shall provide the entire requisite recording instruments as stated in the Connection
Agreement according to the agreed time schedule and shall always keep them in
working condition.

4.13 RESPONSIBILITIES FOR OPERATIONAL SAFETY

(1) Site Responsibility Schedule
STU and the concerned Users shall be responsible for safety in accordance with Central
Electricity Authority (Technical Standards for connectivity to the Grid) Regulations, 2007,
Odisha Electricity Regulatory Commission (Terms and Conditions for Open Access)
Regulation, 2005, Central Electricity Authority ( Measures relating to Safety and
Electricity Supply) Regulations, 2010 and CEA “Safety requirements for Construction,
Operation and Maintenance of electrical Plants and Electrical Lines, Regulation 2011” and
the respective amendments thereof.
 -41-

STU/Transmission Licensee and other Users concerned shall be responsible for safety as
indicated in Site Responsibility Schedules for each Connection Point.

(a) For every connection to the Transmission System for which a Connection
Agreement is required, a schedule of equipment shall be prepared by
the Transmission Licensee with information supplied by the respective Users.
This schedule, called a Site Responsibility Schedule, shall state the following for
each item of equipment installed at the connection site:
(i) The ownership of Plant/Apparatus
(ii) The responsibility for control of Plant/Apparatus.
(iii) The responsibility for maintenance of Plant/Apparatus.
(iv) The responsibility for operation of Plant/Apparatus
(v) The manager of the site.
(vi) The responsibility for all matters relating to safety of persons at site.

An illustrative Site Responsibility Schedule is provided at Appendix-II to

Chapter-4.

(b) The User owning the connection site shall provide reasonable access and other
required facilities to another User whose equipment is installed at the connection
site for installation, operation and maintenance, etc.

(c) The format, principles and basic procedure to be used in the preparation of Site
Responsibility Schedules shall be formulated by STU and shall be provided to
each Agency/regional constituents for compliance.

(d) All Agencies connected to or planning to connect to STS would ensure providing
of RTU and other communication equipment, as specified by STU, for sending
real-time data to the nearest SCADA Interface Point of the Transmission
Licensee at least before date of commercial operation of the generating stations or
sub-station/line being connected to STS.

(2) Single Line Diagrams

(a) Single Line Diagram shall be furnished for each Connection Point by the
connected Users to SLDC. These diagrams shall include all HV/EHV 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/EHV Apparatus and related plant.

(b) Whenever any equipment has been proposed to be changed, then concerned User
shall intimate the necessary changes to Transmission Licensee and to all
concerned. When the changes are implemented, changed Single Line Diagram
shall be circulated by the User to SLDC/STU/Transmission Licensee.

(3) Site Common Drawings

(a) 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 User to STU/Transmission
Licensee.
 -42-

(b) The detailed drawings for the portion of the Agency and STU/Transmission
Licensee at each Connection Point shall be prepared individually and copies shall
be handed over to other party.
(c) If any change in the drawing is found necessary, the details will be furnished to
other party as soon as possible.

4.14 SCHEDULE OF ASSETS OF STATE GRID

STU/Transmission Licensee shall submit annually to OERC by 30th September each year
a schedule of transmission assets, which constitute the State grid as on 31st March of that
year indicating ownership on which SLDC has operational control and responsibility.

4.15 CYBER SECURITY

All utilities shall have in place, a cyber security framework to identify the critical cyber
assets and protect them so as to support reliable operation of the grid.

4.16 CONNECTION POINT

(1) Generator (including CGP)

Voltage may be 33 kV and above. The Connectivity of User (consumer) or

Generator including CGP at 33 KV or at any higher voltage level should be
decided mutually on techno-commercial analysis and system study. The
Connectivity at 33 KV may normally be allowed for any Generator including
CGP upto 25 MW for dedicated line (tie line) and upto 15 MW in case of non-
dedicated (non-tie) line. Unless specifically agreed with the Transmission
Licensee the Connection Point shall be the outgoing feeder gantry of Power
Station switchyard. Metering point shall be at the outgoing feeder. All the
terminal communication, protection and metering equipment owned by the
generator within the perimeter of the generator‟s site should be maintained by the
generator. From the outgoing feeder gantry onwards, the Transmission Licensee
shall maintain all electrical equipment.

(2) Distribution Company

Voltage may be 33/11 kV or as agreed with the Transmission Licensee. The

Connection Point shall be the outgoing feeder gantry of the Transmission
Licensee‟s sub-station. The metering point shall be at the outgoing feeder. The
Transmission Licensee shall maintain all the terminal, communication, protection
and metering equipment within the premises of the Transmission Licensee. From
the outgoing feeder gantry onwards, the respective Distribution Company shall
maintain all electrical equipment.

(3) Eastern Regional Transmission System

For the Eastern Regional Transmission System, the connection, protection

scheme, metering scheme, metering point and the voltage shall be in accordance
with the mutual agreement between Power Grid and the State Transmission
Licensee.
 -43-

(4) Bulk Power Consumers

Voltage may be 400/220/132/33 kV or as agreed with the Transmission Licensee

and Bulk Power Consumers‟ own sub-stations. The Connection Point shall be the
feeder gantry on their premises. The metering point shall be at the Transmission
Licensee‟s sub-station or as agreed with the Transmission Licensee.

4.16 DATA REQUIREMENTS

Users shall provide the Transmission Licensee with data for this Chapter as
specified in the Data Registration Chapter.

4.17 APPENDIX OF CHAPTER-4

Model Connection Agreement- Annexure-I to Chapter-4
General format for Site Responsibility Schedule- Annexure-II to Chapter-4.
 -44-

ANNEXURE-I TO CHAPTER-4

CONNECTION AGREEMENT
(Refer Section-4.5)

THIS AGREEMENT for connection to and use of Transmission System of ________________

___________ (Name of the Transmission Licensee) is made this . . . . day of . . . . . . . . . month
of . . . . . . . . . . year.
BETWEEN
[1] ---------------------------------------------------------------------------------------(Name of the
Transmission Licensee) whose registered office is at -------------------------------------------
-----------------------------------------------------------------------------------------------------------
---------------------------------------------------------, AND
[2] …………………………………………. (Name of the company) whose registered office
is at ……………………………………………… (detailed address) therein after called
“User”

WHEREAS
[A] -----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
--------------------------(Name and address of the Transmission Licensee) is a
Transmission Licensee granted by the OERC as per the provision of the Electricity Act,
2003 (here after called as the „Act‟) agreed to execute a Connection Agreement for the
purpose export/import of power at 400/220 kV/132 kV to -------------------------------------
-------------------------------------------------------------------- (Name of the User)
[B] ………………………………………………………………………(Name of the
Distribution Company (the User) is the holder of the Orissa Distribution Licence,
(No………..) issued by OERC vide order dated------------------------.
[C] …………………………………………………………………………… (Name of the
User i.e. Generator / CGP / Bulk Power Consumer) is the holder of the authorization
issued by the State Government / Central Government / CERC / OERC vide order
No………………. dated.

NOW IS HEREBY AGREED AS FOLLOWS

(i) Grid Code Compliance

It is agreed that the User ………………………… and --------------------------------------

----(the Transmission Licensee) will abide by the provisions of the Odisha Grid Code
(OGC)/Indian Electricity Grid Code (IEGC) in force for the purpose of availing/
evacuating power from/to ------------------------------------------(the Transmission
Licensee) and to maintain a connectivity with the Transmission System network of ---
---------------------------------------(the Transmission Licensee).

(ii) Terms of agreement

(a) This agreement shall be deemed to have commenced from and shall continue
until it is terminated. In case of any differences or disagreements between the
Transmission Licensee and the User in regard to any changes required from
time to time to the terms of this agreement the same shall be resolved amicably
failing which the matters shall be referred to the OERC and the Commission‟s
decision shall be final and binding.
 -45-

(b) The term of this Agreement shall stand modified or terminated automatically
as per the Regulations which OERC may issue from time to time in
accordance with the functions and powers of the Commission under the Act.
As soon as practicable following any Regulation of the Commission which has
the effect of modifying the terms of this Agreement, the Transmission
Licensee shall prepare a revised version of this agreement, incorporating the
modified term and following Agreement between the Transmission Licensee
and User that the revised version accurately reflects the relevant Regulation,
the User shall execute the revised version.

(c) No User shall assign the Agreement or transfer or part with the benefits under
the Agreement in favour of any other person/User without the express consent
or approval of the Transmission Licensee.

(d) Any connection, which has been unauthorisedly transferred or parted with,
shall be liable for disconnection after expiry of a seven days notice calling for
explanation and considering the explanation submitted by him.

(e) The User agrees to bear the cost of stamp duty and all cost incidental to the
execution of this agreement in full.

(iii) Details of Connection

(a) System of supply voltage:

(b) Total contract demand:
(c) Phasing of the contract demand:
(d) Connection details:
(LILO arrangement of transmission line with a switching station/from a bay
of an existing grid substation of the Transmission Licensee) (Details to be
mentioned)
(e) Details of reactive power compensation arrangement:
(f) Details of the scheme of the switching station/bay
i. Bus-bar arrangement: Three bus system/Two bus system/main and
transfer bus system, Bus-bar type
ii. Provision for future expansion
(g) Captive Generating Plant:
i. Rated capacity:
ii. Rated voltage level of generation:
iii. Quantum of surplus power to be evacuated:
iv. Details of the connectivity with the Transmission Licensee‟s network:
v. Mode of communication connectivity with the nearest SCADA Interface
Point of the Transmission Licensee: Telephone/Fax/ Carrier
communication/ Broad Band Communication/Internet/other developed
mode of communication.
Transmission Licensee shall provide SCADA Interface in every 220 KV grid
S/S.
(h) Communication arrangement: The User shall be required to provide voice and
other communication facility as decided by SLDC.
(i) Metering Arrangement: The User shall provide meters for accounting and
audit purposes as per the standard specified by CEA.
 -46-

[Details of operational/commercial (tariff) metering scheme to be provided.]

Detail data are to be provided as per Chapter-12 (DATA REGISTRATION)
of the State Grid Code (OGC).
(j) Other Charges:
The operation and maintenance charges of the transmission line details to be
indicated, 400/220 kV/132 kV feeder bay (nos. of bays and location of grid
substation to be indicated), 400/220 kV/132 kV switching station (details of
bays etc. to be indicated) shall be governed by the provisions contained in
Chapter-12.
i. Entry Charges and Exit Charges as fixed by the Transmission Licensee &
approved by OERC to be paid where appropriate.
ii. Capital related payment arising from necessary reinforcement or extension
of the System is to be paid.
(k) Site Responsibility Schedule:
The site responsibility schedule is annexed at Annexure-II to Chapter-4, of
the State Grid Code (OGC):
(l) Protection Scheme:
Protection scheme shall be provided in the User‟s system to protect the grid
from the faults originating in their system and so also for safeguarding their
system from the fault originating from the Transmission System. The
protection scheme of the User‟s system shall have the prior approval of
OPTCL.
i. Transmission line protection scheme: (please indicate the general
philosophy of the scheme)
ii. 220 kV / 132 kV feeder bay protection scheme: (please indicate the
general philosophy of the scheme)
iii. General protection scheme adopted for the switching station: (please
indicate the general philosophy of the scheme).
iv. Any other protection scheme provided:

(m) Documents forming part of this agreement:

i. Annexure-I: Data to be provided as per Chapter-12 of the OGC.
ii. Annexure-II: Attested copies of the Transmission Licensee permission
letter no __________, date _______________.
iii. Annexure-II (to Chapter-4): Site Responsibility Schedule.
iv. Detail of procedure necessary for Site Access, Site Operational
Activities and maintenance Standards for equipments of the
STU/Transmission Licensee at STU/Transmission Licensee premises
and vice versa as Annexure-II.

AS WITNESS the hands of the Parties hereto or their duly authorized representative on this
……………… day of month of ………………. Year

SIGNED BY SIGNED BY

For & on behalf of For & on behalf of

User the Transmission Licensee

WITNESSES: 1) 1)
2) 2)
Bhubaneswar
Date: The …………….. Day of …………..Month of …………….. Year
 ANNEXURE-II TO CHAPTER-4
Ref: Section-4.13 (1)(a)
CONNECTION CONDITIONS
SITE RESPONSIBILITY SCHEDULE

Name of Power Station/Sub-station: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Site Owner: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Tel. Number: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fax Number: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Safety Control Operation Maintenance
Item of Plant/Apparatus Plant Owner Responsibility Responsibility Responsibility Responsibility Remarks
1 2 3 4 5 6 7
... ……. KV Switchyard
All equipment including bus bars
Feeders

Generating Units
 - 48 -

CHAPTER- 5
OPERATING CODE FOR STATE GRID

5.1 OPERATING POLICY

(1) The primary objective of integrated operation of the State grid is to enhance the
overall operational economy and reliability of the entire electric power network
spread over the geographical area of the State. Users shall cooperate with each
other and adopt good utility practice at all times for satisfactory and beneficial
operation of the State grid.

(2) Overall operation of the State grid shall be supervised from the SLDC. The role
of SLDC, STU/Transmission Licensee and Distribution Licensees shall be in
accordance with the provisions made in Chapter-2 of the OGC.

(3) All Users shall comply with this Operating Code, for deriving maximum benefits
from the integrated operation and for equitable sharing of obligations.

(4) All licensees, generating company, generating station and any other person
connected with the operation power system shall comply with the directions
issued by the SLDC to ensure integrated grid operation and for achieving the
maximum economy and efficiency in the operation of the power system.

(5) A set of detailed internal System Operational Procedures for State grid shall be
developed and maintained by the SLDC in consultation with the Users for
guidance and it shall be consistent with OGC to enable compliance with the
requirement of this OGC.

(6) The control rooms of the SLDC, power plants, substation of 132 kV and above,
and any other control centres of all Users shall be manned round the clock by
qualified and adequately trained personnel.

5.2 SYSTEM SECURITY ASPECTS

(1) All Users shall endeavour to operate their respective Power Systems and Power
Stations in synchronism with each other at all times, such that the entire system
within the State operates as one integrated system.
(2) No part of the grid shall be deliberately isolated from the rest of the State grid,
except
(a) Under an emergency and conditions in which such isolation would prevent a total
grid collapse and/or would enable early restoration of power supply,
(b) for safety of human life
(c) When serious damage to a costly equipment is imminent and such isolation
would prevent it,
(d) When such isolation is specifically instructed by SLDC, complete
synchronization of grid shall be restored as soon as the conditions again permit it.
The restoration process shall be supervised by SLDC, as per operating procedures
separately formulated by SLDC.
 - 49 -

(3) No important element of the State grid shall be deliberately opened or removed
from service at any time, except when specifically instructed by SLDC or with
specific and prior clearance of SLDC. The list of such important grid elements on
which the above stipulations apply shall be prepared by the SLDC in consultation
with the Users and be available at the website of SLDC. This list shall have to be
notified by SLDC from time to time specifying the scheduled power flow and
operational security margin. In case of opening / removal of any important
element of the grid under an emergency situation, the same shall be
communicated to SLDC at the earliest possible time after the event. SLDC shall
inform the opening/removal of the important elements of the state grid, to RLDC
and to the concerned Regional Entities (whose grid would be affected by it) as
specified in the detailed operating procedure by RLDC/NLDC.

(4) Any tripping, whether manual or automatic, of any of the above elements of State
grid shall be precisely intimated by the Users to SLDC 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. SLDC shall inform the
opening/removal of the important elements of the state grid to RLDC and to the
concerned Regional Entities (whose grid would be affected by it) as specified in
the detailed operating procedure by NLDC/RLDC.

(5) Any prolonged outage of power system elements of any User, which is causing or
likely to cause danger to the grid or sub-optimal operation of the grid shall
regularly be monitored by SLDC. SLDC shall report such outages to Power
System Operational Co-ordination Committee/GCC/ERPC. Power System
Operational Co-ordination Committee shall finalise action plan and give
instructions to restore such elements in a specified time period. Maintenance of
their respective power system elements shall be carried out by users, STUs and
CTU in accordance with the provisions in Central Electricity Authority (Grid
Standards) Regulations, 2010.

(6) All thermal generating units of 200 MW and above and all hydro units of 10 MW
and above, which are synchronized with the grid, irrespective of their ownership
shall have their governors in normal operation at all times. Such generating units
(except those with upto three hours pondage) shall be operated under restricted
governor mode of operation. The restricted governor mode of operation shall
essentially have the following features:

a. There should not be any reduction in generation in case of improvement in

grid frequency below 50.05 Hz. (for example if grid frequency changes from
49.90 to 49.95 Hz. then there shall not be any reduction in generation).

Whereas for any fall in grid frequency, generation from the unit should
increase by 5% limited to 105 % of the MCR of the unit subject to machine
capability.
 - 50 -

b. Ripple filter of +/- 0.03 Hz. shall be provided so that small changes in
frequency are ignored for load correction, in order to prevent governor
hunting.

(7) All other generating units including the pondage upto 3 hours, Gas
turbine/Combined Cycle Power Plants, wind and solar generators and Nuclear
Power Stations shall be exempted from Sections 5.2(6), 5.2 (9), 5.2 (10) and 5.2
(11) till review of the situation by appropriate Commission.

Provided that if a generating unit cannot be operated under restricted governor

mode operation, then it shall be operated in free governor mode operation with
manual intervention to operate in the manner required under restricted governor
mode operation.

(8) If any Generating Unit of 200 MW and above and all hydro units of 10 MW and
above, is required to be operated without its governor in normal operation, the
SLDC shall be immediately advised about the reason and duration of such
operation. All governors shall have a droop of between 3% and 6%.

(9) 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.

(10) All Generating Units of 200 MW and above and all hydro units of 10 MW and
above, 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 to 105% and 110% of their MCR, respectively, 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 not complying with the above requirements shall be kept in
operation (synchronized with the State grid) only after obtaining the permission
of SLDC. However, SLDC can make up the corresponding short fall in spinning
reserve by maintaining an extra spinning reserve on the other Generating Units of
the State.

(11) 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 & size would be 1% per minute or as
per manufacturer‟s limits.

(12) Except under an emergency or to prevent an imminent damage to a costly

equipment, no User shall suddenly reduce his generating unit output / injection
by more than 30MW without prior intimation to and consent of the SLDC.
Similarly, no User shall cause a sudden variation in its drawl by more than
30MW without prior intimation to and consent of the SLDC.
 - 51 -

(13) Provision of protections and relay settings shall be coordinated periodically

throughout the State grid, as per a plan to be separately finalized by the
Protection Co-ordination Committee of the STU. All users shall ensure that
installation and operation of protection system shall comply with the provisions
of Central Electricity Authority (Grid Standards) Regulations, 2010.

(14) All Users shall take all possible measures to ensure that the grid frequency
always remains within the “49.90-50.05 Hz” band.

(15) All Users 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 tripping, tripping
of important corridors/flow-gates etc. Such schemes would be finalized by the
Protection Co-ordination Committee of the STU and shall be kept in service.
SLDC shall be promptly informed in case any of these are taken out of service
along with the reason and duration of anticipated outage from service.

(16) Procedures shall be developed to recover from partial/total collapse of the grid
and periodically updated in accordance with Central Electricity Authority (Grid
Standards) Regulations, 2010 and with the requirements given under section 5.9.
These procedures shall be followed by all the Users to ensure consistent, reliable
and quick restoration.

(17) STU shall provide adequate and reliable communication facility internally and
with other Generators/Distribution Licensees/Users 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 i.e. SLDC to STU / Sub-LDC / DSOCC.

(18) The Users shall send information/data including Disturbance Recorder

/sequential event recorder output etc., within 24 hours to SLDC for purpose of
analysis of any grid disturbance/event. No Users shall block any data/information
required by the SLDC for maintaining reliability and security of the grid and for
analysis of an event.

5.3 FREQUENCIES AND VOLTAGE MANAGEMENT AND REACTIVE POWER

PRICING

(1) Introduction

Section-5.3 describes the method by which all Users of the Transmission System shall
co-operate with the Transmission Licensee in contributing towards effective control of
the system frequency and managing the voltage of the Transmission System.

The Transmission Licensee‟s system normally operates in synchronism with the Central
Synchronous Power System (in which all regions are connected). ERLDC is the Apex
Body for operation of Eastern Regional Grid. The constituents of the Eastern Region are
required to follow the instructions of ERLDC for safe and secure operation of the
Regional Grid. SLDC shall accordingly instruct State Generating Units and CGPs to
 - 52 -

regulate generation/export and hold reserves of active and reactive power, within their
respective declared parameters. SLDC shall also regulate load and bilateral exchange as
may be necessary to meet this objective.

Transmission System voltage levels can be affected by regional operation. High voltages
generally occur during high frequency and vice versa, therefore system frequency
regulation must be recognised as an important method of voltage control. The
Transmission Licensee shall optimise voltage management by adjusting transformer taps
to the extent available and switching of circuits/reactors and other operational steps.
SLDC will instruct Generating Units and CGPs to regulate MVAr generation within their
declared parameters. SLDC shall also instruct Distribution Companies to regulate
demand if necessary.

(2) Objective

The objectives of this Section are as below-

(i) to define the responsibilities of all Users in contributing to frequency
management.
(ii) to define the actions required enabling the Transmission Licensee to maintain
Transmission System voltages and frequency within acceptable levels in
accordance with IEGC, CEA guidelines, and Transmission Planning and Security
Standards, as appropriate.

(3) Frequency Management

(i) SLDC in co-ordination with ERLDC shall make all possible efforts to ensure that
the grid frequency always remains within the 49.90 to 50.05 Hz band. Any
frequency deviation beyond the normal range shall be jointly identified by SLDC
and ERLDC and appropriate action taken.

(ii) The SLDC/Distribution Licensee shall always endeavour to restrict the net-drawl
from the grid within the drawl schedule keeping the deviations from the schedule
within the limits specified in the appropriate Regulation. The concerned
Distribution Licensees/User, SLDC shall ensure that the Automatic Demand
Management Scheme mentioned in Clause 5.5(2) acts to ensure that there is no
over-drawl. SLDC shall explore and utilise internal generation capacity and then
requisite load shedding as agreed with Distribution Companies, shall be carried
out in the state by SLDC to maintain the net drawl schedule within the deviation
limit.

(b) Responsibilities

SLDC shall monitor actual Drawl against scheduled Drawl and regulate internal
generation/demand to maintain this schedule. Generators, CGPs and bilateral Agencies
shall follow the despatch instructions issued by SLDC. Distribution companies and
bilateral Agencies shall co-operate with SLDC in managing load on instruction from
SLDC as required.
 - 53 -

(c) Falling frequency

(i) All Users 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 finalised by the
Protection Co-ordination Sub-Committee of the ERPC and shall ensure its
effective application to prevent cascade tripping of Generating Units in case of
any contingency. All Users shall ensure that the above under frequency and df/dt
load shedding/islanding schemes are functional. However, in case of extreme
contingencies, these relays may be temporarily kept out of service with prior
consent of SLDC, which shall independently check and keep a record of its
findings.
(ii) Protection Co-ordination Committee of the STU shall carry out periodic
inspection of the under frequency relays and maintain proper records of the
inspection. Protection Co-ordination Committee of the STU shall decide and
intimate the action required by distribution licensee and STUs to get required
load relief from Under Frequency and Df/Dt relays. All distribution licensee and
STUs shall abide by these decisions. SLDC shall keep a comparative record of
expected load relief and actual load relief obtained in Real time system operation.
A monthly report on expected load relief vis-a-vis actual load relief shall be sent
to the Protection Co-ordination Committee of the STU and the OERC.

(d) Rising frequency

Under rising frequency conditions, SLDC shall take appropriate action to issue
instructions to generators/ CGPs, in co-ordination with ERLDC, to arrest the
rising frequency and restore frequency within normal range.

When the frequency is higher than 50.05 Hz, the actual net injection shall not
exceed the scheduled despatch for that block.

(4) Voltage Management

(i) The Transmission Licensee shall carry out load flow studies from time to time to
predict where voltage problems may be encountered and to identify appropriate
measures to ensure that voltages remain within the defined limits. On the basis of
these studies SLDC shall instruct generators and CGPs to maintain specified
voltage levels at interconnecting points.

(ii) The Transmission Licensee shall co-ordinate with the distribution companies to
determine voltage levels at the External Inter Connection Points with distribution
companies. Distribution companies shall participate in voltage management by
regulating their Drawal as may be required. The Distribution Company shall
endeavour to minimize the VAr drawal at an External Inter Connection Point.

(iii) SLDC shall continuously monitor 400/220/132 kV voltage levels at strategic sub-
stations. SLDC in consultation with ERLDC may issue directions for Switching
in/out of all 400 kV bus and line Reactors throughout the grid / tap changing on
all 400/220 kV ICTs shall also be done as per ERLDC conveyed through SLDC.
 - 54 -

In case of persistent voltage problem SLDC will interact with ERLDC for
remedial measure.

(iv) SLDC shall, in co-ordination with ERLDC, regulate voltage levels so that there is
minimal reactive drawl from regional Transmission System.

(v) In general, the Beneficiaries shall endeavour to minimize the VAr drawl 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%. Auto Transformer taps at the
respective drawl points may be changed to control the VAr interchange as per a
Beneficiaries‟ request to the SLDC, but only at reasonable intervals.

(vi) The SLDC shall take appropriate measures to control Transmission System
voltages, which may include but not be limited to transformer tap changing and
use of MVAr reserves with Generating Units and CGPs within technical limits
agreed to between the Transmission Licensee and Generating Units/CGPs.

(vii) Generators and CGPs shall inform SLDC of their reactive reserve capability
promptly on request.

(viii) Generators shall make available to SLDC the up-to-date capability curves for all
Generating Units, as detailed in Chapter-4, indicating any restrictions, to allow
accurate system studies and effective operation of the Transmission System.
CGPs shall similarly furnish the net reactive capability that will be available for
export to/ import from Transmission System.

(ix) 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 size is required to be operated without its AVR in service,
the SLDC 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 STU from
time to time. STU will be allowed to carry out checking of PSS and further
tuning it, wherever considered necessary.

(x) All Users shall make all possible efforts to ensure that the grid voltage always
remains within the following Operating Range.
----------------------------------------------------------------
VOLTAGE – (KV rms)
----------------------------------------------------------------
Nominal Maximum Minimum
765 800 728
400 420 380
220 245 198
132 145 122
33 36 30
----------------------------------------------------------------
 - 55 -

(xi) All Users shall also facilitate identification, installation and commissioning of
system protection schemes in the Power System to protect against situations such
as voltage collapse and cascading. Such schemes would be finalized by the PCC
of STU.

(xii) All users shall ensure that temporary over voltage due to sudden load rejection
and the maximum permissible values of voltage unbalance shall remain within
limits specified under Central Electricity Authority (Grid Standards)
Regulations, 2010.

(5) Reactive Power Pricing Policy

(i) 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 drawls by Beneficiaries, VAr
exchanges with State Transmission System shall be priced as follows:
- The Beneficiary pays for VAr drawl 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 drawl when voltage is above 103%
- The Beneficiary pays for VAr return when voltage is above 103%

Provided that there should be no charge /payment for VAr drawl / return by a
Beneficiary on its own line emanating directly from a SGS.

(ii) The charge/payment for VArs, shall be at a nominal paise/kVArh rate as may be
specified by Commission from time to time, and will be between the Beneficiary
and the State pool account for VAr interchanges.

(iii) Notwithstanding the above, SLDC may direct a Beneficiary to curtail its VAr
drawl/injection in case the security of grid or safety of any equipment is
endangered.

(iv) The SGS shall generate/absorb reactive power as per instructions of SLDC,
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.

(v) 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 State
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:
 - 56 -

(a) The two concerned Beneficiaries may mutually agree not to have any
charge/payment for VAr exchanges between them on an interconnecting
line.

(b) 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 OERC for VAr exchanges with STS. If the agreed
scheme requires any additional metering, the same shall be arranged by
the concerned Beneficiaries.

(c) 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-I to Chapter-5 shall be applied. The per KVArh rate shall be as
specified by OERC for VAr exchanges with State Transmission System.

(d) The computation and payments for such VAr exchanges shall be affected
as mutually agreed between the two Beneficiaries.

(6) Special requirements for Solar/ wind generators

(i) SLDC shall make all efforts to evacuate the available solar and wind power and
treat as a must-run station. However, System operator may instruct the solar
/wind generator to back down generation on consideration of grid security or
safety of any equipment or personnel is endangered and Solar/ wind generator
shall comply with the same. For this, Data Acquisition System facility shall be
provided for transfer of information to concerned SLDC
(a) SLDC may direct a wind farm to curtail its VAr drawl/injection in case
the security of grid or safety of any equipment or personnel is
endangered.
(b) During the wind generator start-up, the wind generator shall ensure that
the reactive power drawl (inrush currents in case of induction generators)
shall not affect the grid performance.

(7) General

Close co-ordination between Users and the SLDC shall exist at all times for the purposes
of effective frequency and voltage management.

5.4 DEMAND ESTIMATION FOR OPERATIONAL PURPOSES

(1) Introduction

(a) This Section describes the procedures/responsibilities of the SLDC for demand
estimation for both Active Power and Reactive Power.
(b) The demand estimation is to be done on daily/weekly/monthly/ yearly basis for
current year for load - generation balance planning. The SLDC shall carry out
system studies for operational planning purposes using this demand estimate.
(Please refer Annexure II, III, IV and V to Chapter-5)
 - 57 -

(c) SLDC shall carry out its own demand estimation (MW, MVA and MWh) from
the historical data and weather forecast data from time to time. All distribution
licensees and other concerned persons shall provide relevant data and other
information as required by SLDC for demand estimate.
(d) While the demand estimation for operational purposes is to be done on a daily/
weekly/monthly basis initially, mechanisms and facilities at SLDC shall be
created at the earliest to facilitate on-line estimation for daily operational use for
each 15 minutes block.
(e) SLDC shall take into account the wind energy forecasting to meet the active and
reactive power requirement.

(2) Objective

(a) The objective of this procedure is to enable the SLDC 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.

(3) Procedure

The SLDC shall develop methodologies/mechanisms for daily / weekly / monthly / yearly
demand estimation (MW, MVAr and MWh) for operational purposes. Based on this
demand estimate and the estimated availability from different sources, SLDC shall plan
demand management measures like load shedding, power cuts, etc. and shall ensure that
the same is implemented by the distribution licensees. All distribution licensees shall
abide by the demand management measures of the SLDCs and shall also maintain
historical database for demand estimation.

(4) Demand Estimation

(a) Demand estimation is necessary both in the long time scale to ensure adequate
system plant margins and ratings and in the shorter time scale to assist with
frequency control (see Scheduling and Despatch Code Chapter).

(b) Distribution companies and other Agencies involved in bilateral exchanges shall
provide to the SLDC their estimates of demand/export for Active power (MW),
Reactive power (MVAr) and Energy consumption (MU) at each connection /
External Interconnection Point on daily / weekly / monthly basis (Formats as per
Annexures II, III, IV and V respectively). The distribution companies shall
intimate to the SLDC the methodology used in producing their forecasts.

(c) The SLDC shall use this data

(i) to assist in determination of the generation schedule for next day;

(ii) to determine the most onerous conditions affecting constraints and voltage
performance for next week;
(iii) to check outage Plan viability for peak and Lean Periods for next month.
 - 58 -

(d) (i) The data shall be in the form of 96 blocks (15 minutes) period averaged
demand figure for that day, the weekly / monthly data shall be in the
form of 24 hourly averaged demand figures for that week/month and
yearly data shall be in the form of month wise energy requirement for the
year. All the above data shall be in respect of each inter connection point.

(ii) The demand /export estimates provided by the distribution companies and
other Users involved in bilateral exchanges shall be updated as necessary
and sent each month to the SLDC 15 days ahead on same daily / weekly /
monthly basis.

(iii) The demand estimates shall be further updated and sent to SLDC in
accordance with the provision of Chapter- 6, Scheduling and Despatch.

(iv) The SLDC shall make its own demand forecast using hourly demand
summation of each sub-station and CGP import / export figures provided
under Chapter-7 or by using suitable computer program, to compare with
demand estimates provided by Users.

(v) SLDC shall notify a Contact Person who shall be responsible for day
ahead demand forecast. The official and residential telephone numbers
of the Contact Person shall be intimated to all the distribution companies.
Similarly all the distribution companies shall notify the Contact Person
with telephone numbers and intimate SLDC. In case of change of
Contact Person, it should be intimated to SLDC and vice versa.

(vi) Distribution companies shall provide to SLDC estimates of load that may
be shed, when required, in discrete blocks with the details of the
arrangements of such load shedding.

(vii) While the demand estimation for operational purposes is to be done on a

daily/weekly/monthly basis initially, mechanisms and facilities at SLDC
shall be created at the earliest to facilitate on-line estimation for daily
operational use.

(viii) All data shall be collected in accordance with procedures agreed between
the SLDC and each User.

(ix) SLDC shall maintain a database of State demand on a fifteen minutes

basis.

5.5 DEMAND MANAGEMENT

(1) Introduction

This Section is concerned with the provisions to be made by SLDC to effect a reduction
of demand in the event of insufficient generating capacity, and inadequate transfers from
external interconnections to meet demand, or in the event of breakdown or congestion in
intra-state or inter-state transmission system or other operating problems (such as
 - 59 -

frequency, voltage levels beyond normal operating limit, or thermal overloads etc. or
overdrawl of power by the licensee and open access consumers beyond the limits
mentioned in UI regulation) on any part of the grid.

(2) Manual Demand Disconnection

(a) Distribution Licensees, bulk power consumer and other Users shall endeavour to
restrict their net drawl from the grid to within their respective Drawl Schedules.
The SLDC/ distribution licensee and bulk power consumer shall ensure that
requisite load shedding is carried out in its control area so that there is no
overdrawl.

(b) Each User/STU/SLDC shall formulate contingency procedures and make

arrangements that will enable demand disconnection to take place, as instructed
by the SLDC, under normal and/or contingent conditions. These contingency
procedures and arrangements shall regularly be / updated by User/STU and
monitored by SLDC. SLDC may direct any User/STU to modify the above
procedures/arrangement, if required, in the interest of grid security and the
concerned User/STU shall abide by these directions.

(c) The SLDC through STU/Distribution Licensees shall also formulate and
implement state-of-the-art demand management schemes for automatic demand
management like rotational load shedding, demand response (which may include
lower tariff for interruptible loads) etc. to reduce overdrawl in order to comply
para 5.5.2 (a) . A Report detailing the scheme and periodic reports on progress of
implementation of the schemes shall be sent to the Commission by the concerned
SLDC.

(d) In order to maintain the frequency within the stipulated band and maintaining the
network security, the interruptible loads shall be arranged in four groups of loads,
for scheduled power cuts/load shedding, loads for unscheduled load shedding,
loads to be shed through under frequency relays/df/dt relays and loads to be shed
under any System Protection Scheme. These loads shall be grouped in such a
manner, that there is no overlapping between different Groups of loads. In case of
certain contingencies and/or threat to system security, the SLDC may direct any
Users/distribution licensee or bulk consumer connected to the GRID to decrease
its drawl by a certain quantum. Such directions shall immediately be acted upon.
Concerned User shall send compliance report immediately after compliance of
these directions to SLDC.

(e) To comply with the direction of RLDC, SLDC may direct any User/distribution
licensee/bulk consumer connected to the STU to curtail drawl from grid. SLDC
shall monitor the action taken by the concerned entity and ensure the reduction of
drawl from the grid.

(f) SLDC shall devise standard, instantaneous, message formats in order to give
directions in case of contingencies and /or threat to the system security to reduce
deviation from schedule by the users at different overdrawal/ underdrawal/ over
 - 60 -

injection/ under injection conditions depending upon the severity. The Users shall
ensure immediate compliance with these directions of SLDC.

(g) All Users, distribution licensee or bulk consumer shall comply with direction of
SLDC and carry out requisite load shedding or backing down of generation in
case of congestion in transmission system to ensure safety and reliability of the
system. The procedure for application of measures to relieve congestion in real
time as well as provisions of withdrawl of congestion shall be in accordance with
Central Electricity Regulatory Commission (Measures to relieve congestion in
real time operation) Regulations, 2009.

(h) The measures taken to reduce the Users drawl from the grid shall not be
withdrawn as long as the frequency/voltage remains at a level lower than limits or
the congestion continues, unless specifically permitted by the SLDC.

5.6 PERIODIC REPORTS

(1) Daily Report

A daily report covering the performance of the State Grid shall be prepared by
SLDC based on the inputs received from the Users and shall be put on the
website.

(2) Weekly Reports

A weekly report shall be issued by SLDC to all Users, which shall cover the performance
of the State grid for the previous week. Such weekly report shall also be available on the
website of the SLDC for at least 12 weeks. The weekly report shall contain the
following:

(i) Frequency profile

(ii) Voltage profile of important substations and sub-stations normally having
low /high voltages
(iii) Major Generation and Transmission Outages
(iv) Transmission Constraints
(v) Instances of persistent/significant non-compliance of OGC.
(vi) Instances of congestion in transmission system
(vii) Instances of inordinate delays in restoration of transmission elements and
generating units
(viii) Non-compliance of instructions of SLDC by User/distribution licenses /
bulk consumers, to curtail drawl resulting in non-compliance of
IEGC/OGC.

(3) Other Reports

(a) The SLDC shall prepare a quarterly report and shall issue to all the Users, 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 Users, and the Users responsible for causing the
constraints.
 - 61 -

(b) The SLDC shall also provide information/report, which can be called for by Users
in the interest of smooth operation of the State Transmission System.

5.7 OPERATIONAL LIAISON

(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:
 The State Transmission System
 The State Generating Stations
 The system of an User

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 SLDC and Users, to facilitate quick transfer of information to operational
staff. It will correlate the required inputs for optimisation of decision-making and
actions.

(2) Procedure for Operational Liaison

(a) Operations and events on the State Grid

(i) Before any operation is carried out on State grid, the SLDC will inform
each User, whose system may, or will, experience an operational effect,
and give details of the operation to be carried out.
(ii) Immediately following an event on State grid, the SLDC will inform each
User, 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 User’s system.

(i) Before any operation is carried out on a User‟s system, the User will
inform the SLDC, in case the State grid may, or will, experience an
operational effect, and give details of the operation to be carried out.
(ii) Immediately following an event on an User‟s system, the User will inform
the SLDC, in case the State 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.
(iii) Forced outages of important network elements in the grid shall be closely
monitored by GCC. GCC shall send a monthly report of prolonged outage
of generators or transmission facilities to the Commission.
 - 62 -

5.8 OUTAGE PLANNING

(1) Introduction
This Section describes the process by which the Transmission Licensee carries out the
planning of Transmission System outages, including interface co-ordination with Users.
(a) This also sets out the procedure for preparation of outage schedule for the element
of the State grid in a coordinated and optimal manner keeping in view the State
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 SLDC).
(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 SLDC
and reviewed during the year on quarterly and monthly basis.

If any deviation is required the same shall be with prior permission of SLDC. The
outage planning of run-of-the-river hydro plant, wind and solar power plant and its
associated evacuation network shall be planned to extract maximum power from
these renewable sources of energy. Outage of wind generator should be planned
during lean wind season, outage of solar, if required during the rainy season and
outage of run-of-the river hydro power plant in the lean water season.

(2) Objective

(a) To produce a coordinated generation and transmission outage programme for the
State Grid considering all the available resources and taking into account
transmission constraints, as well as, irrigation 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 optimise the transmission outages of the elements of the State Grid without
adversely affecting the grid operation but taking into account the Generation
Outage Schedule, outages of Distribution Licensees /STU systems and maintaining
system security standards.

(3) Scope

This Section is applicable to all Users including SLDC, Distribution Licensees, STU,
other transmission Licensees and SGS.

(4) Outage planning Process

(a) The SLDC shall be responsible for analysing the outage schedule given by all
Users, preparing a draft annual outage schedule and finalization of the annual
outage plan for the following financial year by 31st January of each year.

(b) All Distribution Licensees / STU, SGS shall provide SLDC their proposed outage
programmes in writing for the next financial year by 1st of August of each year.
 - 63 -

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) SLDC shall then come out with a draft outage programme for the next financial
year before 30th November of each year for the State 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) SLDC shall inform this draft outage programme to ERPC in writing by 30th
November for each financial year.

(e) ERPC will than come out with a draft outage programme for the next financial year
by 31st December of each year for the regional grid.

(f) The final outage plan shall be intimated to all regional constituents and RLDC for
implementation latest by 31st January of each year as mutually decided in ERPC
forum.

(g) SLDC shall interact with all Users as necessary to review and optimise the draft
plan, agree to any changes and produce an acceptable co-ordinated generation and
transmission outage plan by 1st February each year.

(h) SLDC shall release the finally agreed transmission outage plan, which takes
account of regional and User requirements, to all Users by 1st March each year.

(i) The above annual outage plan shall be reviewed by SLDC on quarterly and
monthly basis in consultation with ERLDC and Users who shall be informed by
SLDC any proposed changes. SLDC shall review the monthly outage plan,
generation schedule and other operational aspects related to system operation in the
monthly Power System Operational Co-ordination committee meeting.

(j) In case of emergency in the system, viz., loss of generation, break down of
transmission line affecting the system, grid disturbances; system isolation SLDC
may conduct studies again before clearance of the planned outage.

(k) SLDC is authorized to defer the planned outage in case of any of the following,
taking into account the statutory requirements:
 Major grid disturbances (Total black out in State)
 System isolation
 Partial Black out in the State.
 Any other event in the system that may have an adverse impact on the system
security by the proposed outage.

(l) The detailed generation and transmission outage programmes shall be based on the
latest annual outage plan (with all adjustments made to date).
 - 64 -

(m) Users‟ requests for additional Outages will be considered by SLDC and
accommodated to the extent possible.

(n) SLDC shall inform Users promptly of any changes that affect them.
(o) Each STU/SGS/Distribution Licensee shall obtain the final approval from SLDC
prior to availing an outage.

(5) Release of Circuit and Generation Units included in Outage Plan

Notwithstanding provision in any approved outage plan, no cross boundary circuits or

Generating Unit of a generator shall be removed from service without specific release
from SLDC. This restriction shall not be applicable to individual Generating Unit of a
CGP.

Once an outage has commenced, if any delay in restoration is apprehended, User

concerned shall inform SLDC promptly together with revised estimation of restoration
time.

(6) Data Requirements

Users shall provide SLDC with data for this Section as specified in the Data Registration
Chapter- 12 of this OGC.

5.9 RECOVERY PROCEDURES

(1) Detailed plans and procedures for restoration of the State grid under partial/total
blackout shall be developed by SLDC in consultation with all Users and shall be
reviewed / updated annually.

(2) Detailed plans and procedures for restoration after partial / total blackout of
Transmission System will be finalised by the STU in coordination with the
SLDC. 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 SLDC in co-ordination with the STU & Generator at least
once every six months.

(3) List of Generating Stations with Black Start facility, synchronizing points and
essential loads to be restored on priority, shall be prepared and be available with
SLDC.

(4) The SLDC 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.

(5) All communication channels required for restoration process shall be used for
operational communication only, till grid normalcy is restored.
 - 65 -

5.10 EVENT INFORMATION

(1) Introduction

This Section deals with reporting procedures in writing of reportable events in the system
to all Users/STU and SLDC. The reporting procedure shall be in accordance with the
relevant CEA Regulations.

(2) Objective

The objective of this section is to define the incidents to be reported, the reporting route
to be followed and the information to be supplied to ensure a consistent approach to the
reporting of incidents /events.

(3) Scope

This Section covers all Users and SLDC.

(4) Responsibility

(a) The SLDC shall be responsible for reporting events to the Users/ERLDC/OERC.

(b) SLDC shall be responsible for collection and reporting of all necessary data to
Users for monitoring, reporting and event analysis.

(5) Reportable Events

(a) Any of the following events require reporting by SLDC / STU/ Users:
(i) Violation of security standards.
(ii) Grid indiscipline.
(iii) Non-compliance of SLDC‟s instructions.
(iv) System islanding/system split
(v) State black out/partial system black out
(vi) Protection failure on any element of the State systems.
(vii) Power System instability
(viii) Tripping of any element of the State grid.
(ix) Sudden load rejection by any User as a reportable event

(b) Typical examples of reportable incidents that could affect the state Transmission
System are the following:

(i) Exceptionally high/low system voltage or frequency.

(ii) Serious equipment problem, e.g. major circuit, transformer or bus bar.
(iii) Loss of major Generating Unit.
(iv) Transmission System breakaway or Black Start.
(v) Major fire incidents.
(vi) Equipment and transmission line overload.
(vii) Excessive Drawl deviations.
(viii) Minor equipment alarms.
 - 66 -

The last two reportable incidents are typical examples of those, which are of
lesser consequence, but which still affect the Transmission System and can be
reasonably classed as minor. They will require corrective action but may not
warrant management reporting until a later, more reasonable time.

(6) Reporting Procedure

(a) All reportable incidents occurring in lines and equipment of 11 kV and above at
grid sub-stations shall promptly be reported orally by the User whose equipment
has experienced the incident (The Reporting User) to any other significantly
affected Users and to SLDC.

(b) Within 1 (one) hour of being informed by the Reporting User, SLDC may ask for
a written report on any incident.

(c) If the reporting incident cannot be classed as minor then the Reporting User shall
submit an initial written report within two hours of asking for a written report by
SLDC. This has to be further followed up by the submission of a comprehensive
report within 48 hours of the submission of the initial written report.

In other cases the Reporting User shall submit a report within 5 (five) working
days to SLDC.

(d) In the case of an event occurring in EHV system and generating equipment which
was initially reported by STU / Transmission Licensee/ State Generator, SLDC
will give a written report to ERLDC as stipulated in IEGC.

(e) SLDC may call for a report from any User on any reportable incident affecting
other Users and the licensee in case the same is not reported by such User whose
equipment might have been source of the reportable incident.

The above shall not relieve any User from the obligation to report events in
accordance with the IE Rules.

(7) Form of Written Reports:

A written report shall be sent to SLDC, and will confirm the oral notification together
with the following details of the event:
 Time and date of event
 Location
 Plant and/or Equipment directly involved
 Description and cause of event
 Antecedent conditions
 Demand and/or Generation (in MW) interrupted and duration of interruption
 All Relevant system data including copies of records of all recording
instruments including Disturbance Recorder, Event Logger, DAS etc.
 Sequence of tripping with time.
 Details of Relay Flags.
 Remedial measures.
 Estimate of time to return to service.
 Name of originator.
 - 67 -

The standard reporting form other than for accidents shall be as per the Annexure-VI to
Chapter- 5 of the OGC.

(8) Major Failure

Following a major failure, the Transmission Licensee and other Users shall co-operate to
inquire and establish the cause of such failure and produce appropriate recommendations.
The Transmission Licensee shall report the major failure to the Commission immediately
for information and shall submit the enquiry report to the Commission within 2(two)
months of the incident.

(9) Accident Reporting

Reporting of accidents shall be in accordance with the IE Rules, 1956, Rule 44-A read
with CEA (Measures relating to Safety and Electric Supply) Regulation, 2010. In both
fatal and non-fatal accidents, the report shall be sent to the Electrical Inspector in the
prescribed form.
 - 68 -

Annexure-I
[Refer section 5.3(6)]

PAYMENT FOR REACTIVE ENERGY EXCHANGES

ON BENEFICIARY OWNED LINES

Case – 1: Interconnecting line owned by Beneficiary - A

Metering Point: Substation of Beneficiary- B

Beneficiary A Beneficiary B

Case – 2: Interconnecting line owned by Beneficiary - B

Metering point: Substation of Beneficiary-A

Beneficiary A Beneficiary B

Beneficiary -B pays to Beneficiary -A for

(i) Net VArh received from Beneficiary -A while voltage is below 97%,
and
(ii) Net VArh supplied to Beneficiary -A while voltage is above 103%
Note: Net VArh and net payment may be positive or negative
 - 69 -

Case – 3: Interconnecting line is jointly owned by Beneficiary-A and–B.

Metering points: Substations of Beneficiary-A and Beneficiary-B

Beneficiary A Beneficiary B

S/S-A S/S-B

Net VArh exported from S/S-A, while voltage < 97% = X1

Net VArh exported from S/S-A, while voltage > 103% = X2

Net VArh imported at S/S-B, while voltage < 97% = X3

Net VArh imported at S/S-B, while voltage > 103% = X4

(i) Beneficiary-B pays to Beneficiary-A for X1 or X3, whichever is smaller in

magnitude, and

(ii) Beneficiary-A pays to Beneficiary-B for X2 or X4, whichever is smaller in

magnitude.

Note:

1. Net VArh and net payment may be positive or negative.

2. In case X1 is positive and X3 is negative, or vice-versa, there would be no

payment under (i) above.

3. In case X2 is positive and X4 is negative, or vice-versa, there would be no

payment

under(ii) above.
 - 70 -

ANNEXURE-II TO CHAPTER-5
Day ahead forecast of demand at inter-connection points {Ref- Section 5.4(1) and (4)}
To be furnished by 11:00 Hrs of current day
Name of The Distribution Company :- For Date:-
Hour/B Day> Name of S/S Name of S/S _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Name of S/S Total
lock
1 MW
MVAr
2 MW
MVAr
3 MW
MVAr
4 MW
MVAr
5 MW
MVAr
6 MW
MVAr
7 MW
MVAr
8 MW
MVAr
9 MW
MVAr
10 MW
MVAr
11 MW
MVAr
12 MW
MVAr
13 MW
MVAr
14 MW
MVAr
15 MW
MVAr
16 MW
MVAr
17 MW
MVAr
18 MW
MVAr
19 MW
MVAr
20 MW
MVAr
21 MW
MVAr
22 MW
MVAr
23 MW
MVAr
24 MW
MVAr
. MW
MVAr
96 MW
MVAr
Total (MU)

Signature of Authorised signatory

of the Licensee
 - 71 -

ANNEXURE-III TO CHAPTER-5
Weekly a head forecast of demand at inter connection points for the next week (Monday to Sunday)
To be furnished by Friday of each week
Name of The Distribution Company :- {Ref-Section 5.4(1) and (4)}
Sl. NO. Name of S/S ----> Hr 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Total
1 MW
MVAr
2 MW
MVAr
3 MW
MVAr
4 MW
MVAr
5 MW
MVAr
6 MW
MVAr
7 MW
MVAr
8 MW
MVAr
9 MW
MVAr
MW
MVAr
MW
MVAr
N MW
MVAr

Signature of Authorised signatory of

the Licensee
 - 72 -

ANNEXURE-IV TO CHAPTER-5
Month ahead forecast of demand at inter-connection points for the next month
To be furnished by 15th of current month
Name of The Distribution Company :- {Ref-Section 5.4(1) and (4)}
Sl. NO. Name of S/S ----> Hr 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Total
1 MW
MVAr
2 MW
MVAr
3 MW
MVAr
4 MW
MVAr
5 MW
MVAr
6 MW
MVAr
7 MW
MVAr
8 MW
MVAr
9 MW
MVAr
MW
MVAr
N MW
MVAr
Total MW
MVAr

Signature of Authorised signatory of

the Licensee
 - 73 -

ANNEXURE-V TO CHAPTER-5
Yearly (Month wise) requirement of Energy at inter-connection points for the next Financial Year
To be furnished by 31st December of each year {Ref-Section 5.4(1) and (4)}
Name of The Distribution Company :- For the Year- All Figures in MU
Sl. NO. Name of S/S April May June July Aug Sept Oct Nov Dec Jan Feb Mar Total
1
2
3
4
5
6
7

N
Total

Signature of Authorised signatory of

the Licensee
 - 74 -

Annexure VI to Chapter-5
[Ref: Regulation 5.9(7)]

INCIDENT REPORTING

FIRST REPORT ______________ Date: .....................

Time: ....................

1. Date and time of incident:

2. Location of incident:

3. Type of incident:

4. System parameters before the incident:

(Voltage, Frequency, Flows, Generation, etc.)

5. System parameters after the incident:

6. Network configuration before the incident:

7. Relay indications received and performance

of protection :

8. Damage to equipment :

9. Supplies interrupted and duration, :

if applicable

10. Amount of Generation lost, if applicable :

11. Estimate of time to return to service :

12. Cause of incident :

13. Any other relevant information :

14. Recommendations for future improvement/

repeat incident :

15. Name of the Organisation :

 - 75 -

CHAPTER- 6
SCHEDULING AND DESPATCH CODE
6.1 INTRODUCTION

This Chapter specifies the procedure to be adopted for the scheduling and despatch of
Generating Units to meet demand and drawl allocation requirements.

It further sets down the procedures to be followed by Users so that the SLDC can meet its
daily Drawl Schedule whilst ensuring that reactive power drawls/ returns are minimised.
This Chapter sets out the

a) Demarcation of responsibilities between Various Users and SLDC in scheduling

and despatch

b) Procedure for scheduling and despatch

c) Complementary Commercial Mechanism (Annexure-1 to Chapter 6)

6.2 OBJECTIVE

This code deals with the procedures to be adopted for scheduling of the State Generating
Stations (SGS) including ISGS so far as injection to grid and net Drawls of concerned
Users on a daily basis with the modality of the flow of information between the SGS /
SLDC/Beneficiaries of the State grid. The procedure for submission of capability
declaration by each SGS and submission of Drawl Schedule by each Beneficiary is
intended to enable SLDC to prepare the Despatch Schedule for each SGS and Drawl
Schedule for each Beneficiary. It also provides methodology of issuing real time
despatch/ drawl instructions and rescheduling, if required, to SGS and Beneficiaries
along with the commercial arrangement for the deviations from schedules, as well as,
mechanism for reactive power pricing. This code also provides the methodology for
rescheduling of wind and solar energy on three (3) hourly basis. For this, appropriate
meters and Data Acquisition System facility shall be provided for accounting of
deviation charges and transfer of information to concerned SLDC and RLDC. The
provisions contained in this chapter are without prejudice to the powers conferred on
SLDC under section 32 and 33 of the Act.

6.3 SCOPE

This Section will be applicable to SLDC, SGS, IPPs, Distribution Licensees /STUs and
other Beneficiaries in the State grid including CGPs and Open Access Customers.

6.4 DEMARCATION OF RESPONSIBILITIES

(1) (a) The State Load Despatch Centre is responsible for coordinating the
scheduling of a generating station, within the State control area. The SLDC shall
also be responsible for such generating stations for (1) real-time monitoring of the
station's operation, (2) checking that there is no gaming (gaming is an intentional
mis-declaration of a parameter related to commercial mechanism in vogue, in
 - 76 -

order to make an undue commercial gain) in its availability declaration, (3)

revision of availability declaration and injection schedule,(4) switching
instructions,(5) metering and energy accounting, (6) issuance of deviation
settlement within the control area,(7) collections/disbursement of deviation
charges, (8) outage planning etc., (9) Any other activity directed by the
Commission.

(b) The following generating stations shall come under the STS control area and
hence, SLDC shall coordinate the scheduling of the following generating
stations:

(i) The Central Generating Stations where full share is allocated to the state
irrespective of its connectivity to ISTS/STS.
(ii) If a generating station is connected only to the state Transmission
network.
(iii) If a generating station is connected both to ISTS and the State network
and the State has more than 50% share of power.
(iv) If a generating station including IPP is connected both to ISTS and the
State network and not tied up its generation with any outside State
utility on long term basis and having long term PPA with the State
irrespective of the State‟s share.

(2) The Regional grids shall be operated as loose power pools (with decentralized
scheduling and despatch), in which the State shall have full operational autonomy
and SLDC shall have the total responsibility as per following guidelines for (i)
scheduling / despatching State‟s own generation (including generation of its
embedded licensees) (ii) regulating the demand of its control area, (iii) scheduling
its drawl from the ISGS (within its share in the respective plant‟s expected
capability) (iv) permitting long term access, medium term and short term open
access transactions for embedded generators / consumers in accordance with the
contract and (v) regulating the net drawl from the regional grid.

(3) The system of the State shall be treated and operated as a notional control area.
The algebraic summation of scheduled drawl from ISGS/SGS/IPP/CGP/IPP
selling power on merchant basis and any bilateral inter-change shall provide the
Drawl Schedule of each DISCOM, and this shall be determined in advance on
day-ahead basis. While the DISCOMs would generally be expected to regulate its
generation, if any, and/or consumers‟ load so as to maintain their actual drawl
from the State grid close to the above schedule. Deviation, if any, from the drawl
schedule, shall be priced through the appropriate Mechanism specified by the
State Commission from time to time.

(4) The SLDC, distribution licensees shall always restrict the net drawl from the grid
within the drawl schedules, keeping the deviations from the schedule within the
limits specified in the Regulation. The concerned distribution licensee, user,
SLDC shall ensure that their automatic demand management scheme acts to
ensure that there is no over-drawl. If the automatic demand management scheme
has not yet been commissioned, then action shall be taken as per manual demand
management scheme to restrict the net drawl from the grid within schedules and
 - 77 -

all actions for early commissioning of Automatic Demand Management Scheme

(ADMS).

(5) The SLDC/STUs/ Distribution Licensees shall regularly carry out the necessary
exercises regarding short-term and long-term demand estimation for the State
grid to enable them to plan in advance as to how they would meet their
consumers‟ load without overdrawing from the grid.

(6) The SGS/IPP/CGP /IPP selling power on merchant basis shall be responsible for
power generation / injection generally according to the daily schedules advised
to them by the SLDC on the basis of the contracts/ requisitions received from the
Distribution licensees/LTOA/STOA consumers and beneficiaries 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 SGS, IPP, IPP selling power on merchant basis and CGP would
normally be expected to generate power according to the daily schedules advised
to them barring any inadvertent deviations. Maximum deviation allowed during
a time block shall not exceed the limits specified in the appropriate Regulation.
Such deviations should not cause system parameters to deteriorate beyond
permissible limits and should not lead to unacceptable line loading. Inadvertent
Deviations, if any, from the Ex-power Plant generation injection schedules shall
be appropriately priced in accordance with Regulations/Orders. In addition,
deviations, from schedules causing congestion, shall also be priced in accordance
with the CERC (Measure to relieve congestion in real time operation)
Regulations, 2009.

(8) Notwithstanding the above, the SLDC may direct the Distribution Licensees /
Bulk Consumers/SGS/CGP/IPP to increase/decrease their drawl/generation in
case of contingencies e.g. overloading of lines/transformers, abnormal voltages
and threat to system security. Such directions shall immediately be acted upon. In
case the situation does not call for very urgent action and SLDC has some time
for analysis, it shall be checked whether the situation has arisen due to deviations
from schedules. The corrective action shall be executed through appropriate
measures like opening of feeders, if considered necessary by SLDC, before an
action, which would affect the scheduled supplies to the long term, medium
term customers or short term customers is initiated in accordance with
CERC(Grant of Connectivity, Long Term Access & Medium Term Access in
Inter State Transmission & related matters) Regulations 2009, CERC(Open
Access in Inter State Transmission) Regulation 2008 and Odisha Electricity
Regulatory Commission (Terms and Conditions for Open Access) Regulation,
2005, as amended from time to time.

(9) For all outages of generation and Transmission System, which may have an effect
on the State grid, all Users shall cooperate with each other and coordinate their
actions through Power System Operational Coordination Committee of the SLDC
for outages foreseen sufficiently in advance and through SLDC (in all other
cases), as per procedures finalized separately by this Committee. In particular,
 - 78 -

outages requiring restriction of SGS/CGP/ IPP selling power on merchant basis/

IPP generation shall be planned carefully to achieve the best optimisation.

(10) The SGS/IPP/IPP selling power on merchant basis/CGP shall make an advance
declaration of ex-power plant MW and MWh capabilities foreseen for the next
day, i.e., from 0000 hrs to 2400 hrs. During fuel shortage condition, in case of
thermal stations, they may specify minimum MW, maximum MW, MWh
capability and declaration of fuel shortage. The SGS/IPP/ IPP selling power on
merchant basis /CGP shall also declare the possible ramping up / ramping down
in a block. In case of a gas turbine generating station or a combined cycle
generating station, the generating station shall declare the capacity for units and
modules on APM gas, RLNG and liquid fuel separately and these shall be
scheduled separately.

(11) While making or revising its declaration of capability, except in case of run-off-
river (with up to three hour pondage) hydro stations, the SGS shall ensure that the
declared capability during peak hours is not less than that during other hours.
However, exception to this rule shall be allowed in case of tripping/re-
synchronization of units as a result of forced outage of units.

(12) It shall be incumbent upon the SGS/IPP/ IPP selling power on merchant basis 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 SLDC may ask the SGS/IPP/ IPP
selling power on merchant basis to explain the situation with necessary backup
data.

(13) The SGS/IPP shall be required to demonstrate the declared capability of its
generating station as and when asked by the SLDC. In the event of the SGS/IPP
failing to demonstrate the declared capability, the capacity charges due to the
generator shall be reduced as a measure of penalty. In case of revision of
schedule of a generating unit, the schedules of all transactions under the long-
term access, medium-term open access and short-term open access (except
collective transactions through power exchange), shall be reduced on pro-rata
basis.

(14) The quantum of penalty for the first mis-declaration for any duration/block in a
day shall be the charges corresponding to two days fixed charges. For the second
mis-declaration the penalty shall be equivalent to fixed charges for four days and
for subsequent mis-declarations, the penalty shall be multiplied in the geometrical
progression over a period of a month.

(15) The STU shall install special energy meters on all inter connections between the
Users/Beneficiaries and other identified points for recording of actual net MWh
interchanges and MVArh drawls as per relevant CEA (Installation & Operation
of meters) Regulations 2006, with amendments, if any. The type of meters to be
 - 79 -

installed, metering scheme, metering capability, testing and calibration

requirements and the scheme for collection and dissemination of metered data are
detailed in Chapter-10. All concerned entities (in whose premises the special
energy meters are installed) shall fully cooperate with the STU/SLDC and extend
the necessary assistance for taking weekly meter readings by STU and
transmitting them to the SLDC.

(16) The SLDC shall be responsible for computation of actual net MWh injection of
each SGS/CGP /ISGS/ IPP selling power on merchant basis/ IPP and actual net
drawl of each Beneficiary, 15 minute-wise, based on the above meter readings.
The data shall be processed by SLDC to prepare monthly energy account, weekly
Deviation account & reactive energy account. The processed statement shall be
forwarded to GRIDCO / STU to prepare and issue the relevant invoice. All
computations carried out by SLDC/GRIDCO/STU shall be open to all
Users/Beneficiaries for checking / verifications for a period of 15 days. In case
any mistake/omission is detected, the SLDC shall forthwith make a complete
check and rectify the same.

(17) SLDC shall periodically review the actual deviation from the despatch and net
Drawl Schedules being issued, to check whether any of the Beneficiaries / ISGS /
SGS / IPP selling power on merchant basis/IPP who are allowed open access are
indulging in unfair gaming or collusion. In case any such practice is detected, the
matter shall be reported by the SLDC to Member Secretary, GCC for further
investigation/ action.

(18) Hydro Generating Stations are expected to respond to grid frequency changes and
inflow fluctuations.

(19) The operating log books of the Generating Station shall be available for review
by SLDC/GCC. These books shall keep record of machine operation &
maintenance.

6.5 SCHEDULING AND DESPATCH PROCEDURE

6.5.1 GENERATION SCHEDULING

1. All State Generating Stations (SGS) shall be duty listed on the SLDC web-site
along with their respective installed capacity.

2. All generators including IPP shall provide the fifteen minutes block MW/MV Ar
availability (00.00-24.00 hours) of their respective units, to SLDC on day ahead
basis by 10.00 hours. CGPs shall provide the fifteen minutes block import/export
figures on day ahead basis by 10.00 hours. While working out the MW/MV Ar
availability, Hydro Power Stations shall take into account their respective
reservoir levels and any other constraints and shall report the same to SLDC in
advance.
 - 80 -

3. SLDC shall obtain from ERLDC, foreseen capabilities and fifteen minutes block
MW and MWh entitlements from ISGS by 10.00 hours on day ahead basis.

4. SLDC shall review the State‟s own generating capability & entitlement from
ISGS including bilateral exchanges, if any, and advise all the Distribution
Licensees of the State, their respective entitlement, based on their percentage of
share as approved by the Commission/Government, for the next day by 11 hours.

5. All the Distribution Licensee of the State shall forward their respective drawl
schedule on day ahead basis to SLDC by 12 hours.

6. SLDC shall review its foreseen load pattern and State‟s own generating capability
including bilateral exchanges, if any and shall advise ERLDC by 15 hours its
Drawl Schedule for each of the ISGS in which the State has shares, long-term and
medium-term bilateral interchanges, approved short term bilateral interchanges.
While preparing the State‟s ISGS drawl schedule. SLDC shall take into account
of the relative commercial costs of the Generation units.

7. The SLDC may also give standing instructions to the ERLDC such that ERLDC
itself may decide the best drawl schedules for the State.

8. SLDC shall intimate the generation schedule/import schedule for the following
day to all State‟s Generators/IPP/CGPs by 16.00 hours.

9. SLDC will receive fifteen minutes block “Net Drawl Schedule” in MW from
ERLDC by 18.00 hours for the next day (00.00 hours to 24.00 hours).

10. SLDC shall prepare the 15 minutes block-wise drawl schedule for all the
Distribution Licensees for the next day considering the generation available from
various sources and drawl schedule furnished by them and their percentage of
shares. The drawl schedule of DISCOMs shall be uploaded by 18:30 hours.

11. Generators including IPP shall promptly report to SLDC, changes of Generating
Unit availability or capability, or any unexpected situation, which could affect its
operation. All CGPs shall similarly report regarding their export to the State grid.

SLDC may inform any modification/changes to be made station-wise Drawl

Schedule and bilateral interchanges/foreseen capabilities, if any, to ERLDC by
22.00 hours.

12. SLDC shall advise Users as soon as possible of any necessary rescheduling.

13. SLDC shall receive final Drawl Schedule from ERLDC by 23.00 hours. SLDC
shall prepare the final despatch schedule i.e generation schedule for generators
and drawl schedule for distribution licensees immediately thereafter.

14. SLDC shall prepare the day ahead generation schedule keeping in view the
followings :
(i) Transmission System constraints from time to time.
 - 81 -

(ii) Fifteen minutes block load requirements as estimated by SLDC.

(iii) The need to provide Operating Margins and reserves required to be
maintained.
(iv) The availability of generation from State Generators, ISGS and CGPs
together with constraints, if any, in each case.
(v) Overall economy to the licensee and customers.

15. SLDC shall instruct generators to hold capacity reserves (spinning and /or stand
by) to the agreed ERLDC/SLDC guidelines or as determined for Local conditions
(with due consideration of wastage of water/fuel as the case may be.

16. The SLDC shall also formulate the procedure for meeting contingencies both in
the long run and in the short run (Daily scheduling).

17. If at any point of time, the SLDC observes that there is need for revision of
schedules in the interest of better system operation, it may do so on its own, and
in such cases the revised schedule shall become effective from the 4 th time
block, counting the time block in which the revised schedule is issued by the
SLDC to be the first one.

Revision of declared capability by the SGS including IPP having two part tariff
having capacity charge & energy charge (except hydro stations) and requisition
by DISCOMs 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 4th time block, counting the time block in which the
request for revision has been received in the SLDC to be the first one.

18. To discourage frivolous revisions, the SLDC may, at its sole discretion refuse to
accept schedule / capability changes of less than 2% of previous schedule /
capability. The schedule of thermal generating stations indicating fuel shortage
while intimating the Declared Capacity to the SLDC shall not be revised except
in case of forced outage of generating unit.

19. Special dispensation for scheduling of wind and solar generation

I. Scheduling of wind power generation plant would have to be done where
the sum of generation capacity of such plants connected at the connection
point(called pooling stations) to the transmission or distribution system is
10 MW and connection point is 33 KV and above, for pooling stations
commissioned after 03.05.2010. For capacity and voltage level below this,
as well as for old wind farms (a wind farm is a collection of wind turbine
generators that are connected to a common connection point), it could be
mutually decided between the wind generator and the transmission and
distribution utility, as the case may be, if there is no existing contractual
agreement to the contrary. The schedule by wind power generating stations
(excluding collective transactions) may be revised by giving advance notice
to SLDC/RLDC, as the case may be. Such revisions by wind power
generating stations shall be effective from 6th time block, the first being the
time-block in which notice was given. There may be one revision for each
 - 82 -

time slot of 3 hours starting from 00:00 hours of a particular day subject to
maximum of 8 revisions during the day.
II. The schedule of solar generation shall be given by the generator, based on
availability of the generator, weather forecasting, solar insolation, season
and normal solar generation curve and shall be vetted by the SLDC in
which the generator is located and incorporated in the inter-state schedule.
If SLDC is of the opinion that the schedule is not realistic, it may ask the
solar generator to modify the schedule.
III. The SLDC shall maintain the record of the schedule from renewable power
generating stations, based on the type of renewable energy sources; i.e.
wind or solar from the point of view of grid security. While scheduling
generating stations in a region, the system operator shall aim at utilizing
available wind and solar energy fully.

20. Generation schedules and drawl schedules issued/revised by the SLDC shall
become effective from designated time block irrespective of communication
success.

21. For any revision of scheduled generation, including post facto deemed revision;
there shall be a corresponding revision of scheduled drawls of the beneficiaries.

22. A procedure for recording the communication regarding changes to schedules

duly taking into account the time factor shall be evolved by the State
Transmission Utility.

23. When for the reason of transmission constraints, such as congestion, or in the
interest of grid security, it becomes necessary to curtail power flow on a
transmission corridor; the transactions already scheduled may be curtailed by the
SLDC.

24. The short-term customer shall be curtailed first, followed by medium- term
customers, who shall be followed by the long-term customers and amongst
customers of a particular category, curtailment shall be on prorate basis.

25. 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 despatch
schedule of generating stations and drawl schedule of the DISCOMs) shall be
issued by SLDC. These schedules shall be the datum for commercial accounting.
The average ex-bus capability for each generating station shall also be worked
out, based on all before-the-fact advice to SLDC.

26. If RLDCs curtail a transaction at the periphery of the regional entities, SLDC
shall further incorporate the inter-se curtailment of intra-state entities to
implement the curtailment.

27. SLDC shall properly document all the above information; i.e. station-wise
foreseen ex-power plant capabilities advised by the generating stations, the drawl
schedules advised by intra-state entities, all schedules issued by the SLDC, and
all revisions/updating of the above.
 - 83 -

28. The procedure for scheduling and the final schedules issued by SLDC shall be
open to all intra-state entities and other inter/intra-state open access customers
entities for any checking/verification, for a period of five days. In case any
mistake/omission is detected, the SLDC shall forthwith make a complete check
and rectify the same.

29. While availability declaration by generating station shall have a resolution of one
(1) MW and one (1) MWh, all entitlements, requisitions and schedules shall be
rounded off to the nearest two decimals at each control area boundary for each of
the transaction, to have a resolution of 0.01 MW and 0.01 MWh.

(2) GENERATION DESPATCH

All generators shall regulate generation and CGPs regulate their export according to the
daily generation schedule.

All Generating Units, other than those in a CGP, will be subject to central despatch
instructions. CGPs will be subject to these instructions as applicable to their respective
exports to the licensee.

SLDC will despatch by instruction all generation and imports from CGPs according to
the fifteen minutes block day ahead generation schedule, unless rescheduling is required
due to unforeseen circumstances.

On the day of operation (00.00 to 24.00 hours), in the event of a contingency, SLDC may
revise their Drawl Schedule from any / all ISGS and Chukha Hydro Power Station within
entitlement. ERLDC will revise and issue Drawl Schedule in consultation with SLDC.
All such revisions shall be effective one hour after first advice given to ERLDC.

In absence of any despatch instructions by SLDC, State Generators and CGPs shall
generate/export according to the day ahead generation schedule.

Despatch instructions shall be in standard format. These instructions will recognise

declared availability and other parameters, which have been made available by the State
Generator to SLDC. These instructions shall include time, Power Station, Generating
Units (total export in the case of CGP) and name of operators sending and receiving the
same.

Despatch instructions may include:

(i) To switch a generator into or out of service.
(ii) Details of reserve to be carried on a unit.
(iii) To increase or decrease MVAr generation to assist with voltage profile.
(iv) To begin pre-planned Black Start procedures.
(v) To hold spinning reserve.
(vi) To hold Generating Units on standby.

(3) COMMUNICATION WITH GENERATORS

Despatch instructions shall be issued by e-mail/telephone, confirmed by exchange of
names of operators sending and receiving the same and logging the same at each end.
 - 84 -

All such oral instructions shall be complied with forthwith and written confirmation shall
be issued promptly by Fax, Teleprinter or otherwise.

6.6 ACTION REQUIRED BY GENERATORS

All generators and CGPs shall comply promptly with a despatch instruction issued by
SLDC unless this action would compromise the safety of plant or personnel.

The Generators and CGPs are required to abide by Sections 5.3 and 5.2 regarding
operation of governors and AVRs respectively.

The generator and CGPs shall promptly inform SLDC in the event of any unforeseen
difficulties in carrying out an instruction.

Generators shall immediately inform SLDC by telephone of any loss or change

(temporary or otherwise) to the operational capability of any Generating Unit which is
synchronised to the system or which is being used to maintain system reserve.
Generators shall inform SLDC any removal of AVR and/or governor from service with
reasons.

CGPs shall similarly inform any change in status affecting their ability in complying
with despatch instructions.

Generators shall not de-synchronise Generating Units, other than in respect of CGPs,
without instruction from SLDC except on the grounds of safety to plant or personnel,
which shall be promptly reported to SLDC.

Generators and CGPs shall report any abnormal voltage and frequency related operation
of Generating Units / feeders promptly to SLDC.

Generators shall not synchronise Generating Units, other than in respect of CGPs,
without instruction from SLDC. In emergency situations, the generator may synchronise
Units with the grid without prior intimation in the interest of the operation of the grid
following standing institutions developed for such purpose under “Contingency
Planning”.

Should a generator fail to comply with any of the above provisions, it shall inform SLDC
promptly of this failure.

6.7 ENHANCEMENT OF SCHEDULE AND DESPATCH PROCEDURE

Schedule and despatch procedures shall be suitably enhanced to cater to tariff agreements
as soon as any such agreement is reached with generators, IPPs, and CGPs.

6.8 DATA REQUIREMENTS

Users shall provide SLDC with data for this Section as specified in the Data Registration
Chapter.
 - 85 -

Annexure-1 to Chapter-6
{Refer Clause 6.1 (c)}
COMPLEMENTARY COMMERCIAL MECHANISMS

1. All Beneficiaries shall pay to the SGS Capacity charges corresponding to plant
availability and Energy charges for the scheduled despatch, as per the relevant
notifications and orders of OERC. The bills for these charges shall be issued by the
respective SGS to each Beneficiary on monthly basis.

2. The sum of the above two charges from all Beneficiaries shall fully reimburse the SGS
for generation according to the given Despatch Schedule. In case of a deviation from the
Despatch Schedule, the concerned SGS shall be additionally paid for excess generation
through the Deviation Mechanism. In case of actual generation falling below the given
Despatch Schedule, the concerned SGS shall pay back through the Deviation mechanism
for the shortfall in generation. In case of Generators who are allowed Open Access, the
deviation from despatch schedule shall be governed by Deviation mechanism.

3. The summation of station-wise Ex-power Plant Despatch Schedules from each ISGS
after adjustment of export to other states and transmission losses shall be treated as total
drawl schedule of the State. In case of Deviation from the schedule, the Distribution
Licensee shall be required to pay through the Deviation mechanism.

4. Energy Accounts shall be prepared on monthly basis and the statement of Deviation
charges and Reactive Energy Charges shall be prepared by the SLDC on a weekly basis
based on the data provided by the SLDC as per provisions under Section 6.4 (14) and
these shall be issued to all Beneficiaries by Tuesday for the seven-day period ending on
the previous Sunday mid-night. Payment of Deviation charges shall have a high priority
and the concerned Beneficiary shall pay the indicated amounts within 10 (ten) days of
the statement issue into a State Deviation pool account operated by the SLDC. The
Agencies who have to receive the money on account of Deviation charges would then be
paid out from the State Deviation pool account, within three (3) working days.

5. The SLDC shall also issue the weekly statement for VAr charges, to all Beneficiary who
have a net drawl/injection of reactive energy under low/high voltage conditions. These
payments shall also have a high priority and the concerned Agencies shall pay the
indicated amounts into State reactive account operated by the SLDC within 10 (ten) days
of statement issue. The Agency who has to receive the money on account of VAr charges
would then be paid out from the state reactive account, within three (3) working days.

6. If payments against the above Deviation and VAr charges are delayed by more than two
days, i.e., beyond twelve (12) days from statement issue, the defaulting Agency shall
have to pay simple interest @ 0.04% for each day of delay. The interest so collected shall
be paid to the Agency who had to receive the amount, payment of which got delayed.
Persistent payment defaults, if any, shall be reported by the SLDC to the Member
Secretary, GCC, for initiating remedial action.
 - 86 -

7. The money remaining in the state reactive account after pay-out of all VAr charges up to
31st March of every year shall be utilized for training of the SLDC/ALDC operators, and
other similar purposes which would help in improving / streamlining the operation of the
state grid, as decided by GCC from time to time.

8. In case the voltage profile of the State grid improves to an extent that the total pay-out
from the state VAr charges account for a week exceeds the total amount being paid-in for
that week, and if the State 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.

9. The SLDC shall table the complete statement of the state Deviation account and the state
Reactive Energy account in the GCC‟s Commercial Committee meeting, on a quarterly
basis, for audit by the latter.

10. All Accounting Calculations carried out by SLDC shall be open to all Agencies for any
checking/verification, for a period of 15 days. In case any mistake is detected, SLDC
shall forthwith make a complete check and notify the mistakes.

11. All 15-minute energy figures (net scheduled, actually metered and Deviation) shall be
rounded off to the nearest 0.01 MWh.

12. Complementary Commercial Mechanism for wind and solar generators shall be according
to the Indian Electricity Grid Code (IEGC), 2010 and as amended from time to time.
 - 87 -

CHAPTER-7
MONITORING OF GENERATION AND DRAWAL

7.1 INTRODUCTION

This section covers the procedure to be followed by the SLDC for monitoring the
generating output, Active and Reactive reserve capacity required for evaluation of the
performance of the generating station.

The monitoring of scheduled drawl is important to ensure that the licensee contributes
towards improving regional performance, and observes grid discipline.

7.2 OBJECTIVE

The objective of this Chapter is to define the responsibilities of all Users in the
monitoring of Generating Unit reliability and performance, and the licensee‟s
compliance with the scheduled drawl.

7.3 MONITORING PROCEDURE

(1) For effective operation of the Transmission System, it is important that a

generator‟s declared availability is realistic and that any deviations are
continually fed back to the generator to help effect improvement.

SLDC shall continuously monitor Generating Unit outputs and bus voltages.
More stringent monitoring may be performed at any time when there is reason to
believe that a generator‟s declared availability may not match the actual
availability or declared output does not match the actual output.

SLDC shall inform a generator, in writing, if the continual monitoring

demonstrates an apparent persistent or material mismatch between the despatch
instructions and the Generating Unit output or breach of the Connection
Conditions. This more stringent monitoring may be carried out by SLDC, if
agreement is not reached on the Generating Unit performance. The results of the
stringent monitoring will be reported by SLDC to the generator. Continual
discrepancies shall be resolved at appropriate level {ref- Sections 1.18 and
6.4(15)} with a view to either improving performance, providing more realistic
declarations or correcting any breach of Connection Conditions.

Generators shall provide to SLDC block-wise generation summation outputs

where no automatically transmitted metering or SCADA equipment exists. CGPs
shall provide to SLDC hourly export/import MW and MVAr.

The generator shall provide other logged readings that SLDC may reasonably
require, for monitoring purposes where SCADA data is not available.
 - 88 -

(2) Generating Unit Tripping

Generators shall promptly inform the tripping of a Generating Unit, with reasons,
to SLDC in accordance with the Operational Event/Accident Reporting Section.
The approximate and expected time of resynchronisation with grid shall be
informed to the SLDC. SLDC shall keep a written log of all such tripping,
including the reasons with a view to demonstrating the effect on system
performance and identifying the need for remedial measures.

Generators shall submit a more detailed report of Generating Unit tripping to

SLDC monthly.

(3) Monitoring of Drawl

SLDC shall continuously monitor actual MW drawl against that scheduled, by

use of SCADA equipment where available or otherwise using available metering.
SLDC shall request ERLDC and adjacent States as appropriate to provide any
additional data required to enable this monitoring to be carried out.

SLDC shall continuously monitor the actual MVAr drawl to the extent possible.
This will be used to assist in Transmission System voltage management.

(4) Data Requirements

Generators and CGPs shall submit data to SLDC as listed in Data Registration
Chapter-12, termed as Monitoring of Generation.
 - 89 -

CHAPTER-8

CROSS BOUNDARY SAFETY

8.1 INTRODUCTION

This Chapter sets down the requirements for maintaining safe-working practices
associated with cross boundary operations. It lays down the procedure to be followed
when work is required to be carried out on electrical equipment that is connected to
another User‟s system.

8.2 OBJECTIVE

The objective of this Chapter is to achieve agreement and consistency on the principles
of safety as prescribed in the Central Electricity Authority (Measures Relating to Safety
and Electric Supply) Regulations, 2010 when working across a control boundary
between the Transmission Licensee and another User.

8.3 CONTROL PERSONS

The Transmission Licensee and all Users shall nominate suitably authorised persons to
be responsible for the co-ordination of safety across that company boundary. These
persons shall be referred to as Control Persons.

8.4 PROCEDURE

The Transmission Licensee shall issue a list of Control Persons (names, designations and
telephone numbers) to all Users who have a direct control boundary with the
Transmission Licensee. This list shall be updated promptly whenever there is change of
name, designation or telephone number.

All Users with a direct control boundary with the Transmission Licensee shall issue a
similar list of their Control Persons to the Transmission Licensee, which shall be updated
promptly whenever there is a change to the Control Persons list.

Whenever work across a control boundary is to be carried out, the Control Person, of the
User (which may be the Transmission Licensee), wishing to carry out work shall directly
contact the other relevant Control Person. Code words will be agreed at the time of work
to ensure correct identification of both parties.

Contact between the Control Persons shall normally be by direct telephone. Should the
work extend over more than one shift the Control Person shall ensure that the relief
Control Person is fully briefed on the nature of the work and the code words in
operation.

The Control Persons shall co-operate to establish and maintain the precautions necessary
for the required work to be carried out in a safe manner. Both the established isolation
and the established earth shall be locked in position, where such facilities exist and shall
be clearly identified.
 - 90 -

Work shall not commence until the Control Person, of the User (which may be the
Transmission Licensee), wishing to carry out the work, is satisfied that all the safety
precautions have been established. This Control Person shall issue agreed safety
documentation to the working party to allow work to commence.

When work is completed and safety precautions are no longer required, the Control
Person who has been responsible for the work being carried out shall make direct contact
with the other Control Person to request removal of those safety precautions.

The equipment shall only be considered as suitable for return to service when all safety
precautions are confirmed as removed, by direct communication using code word
contact between the two Control Persons and return of agreed safety documentation
from the working party has taken place.

The Transmission Licensee shall develop an agreed written procedure/protocol for cross
boundary safety and continually update it.

Any dispute concerning Cross Boundary Safety shall be resolved in the Protection Co-
ordination Committee.

8.5 SPECIAL CONSIDERATIONS

All Users shall comply with the agreed safety rules, which must be in accordance with
Central Electricity Authority (Measures Relating to Safety and Electric Supply)
Regulations, 2010.

All equipment on cross boundary circuits which may be used for the purpose of safety
co-ordination and establishment of isolation and earthing, shall be permanently and
clearly marked with an identification number or name, that number or name being
unique in that sub-station. This equipment shall be regularly inspected and maintained in
accordance with manufacturer's specification.

Each Control Person shall maintain a legibly written safety log, in chronological order,
of all operations and messages relating to safety co-ordination sent and received by
himself. All safety logs shall be retained for a period of not less than 5 (five) years.
 - 91 -

CHAPTER-9
PROTECTION
9.1 INTRODUCTION

In order to safeguard an User‟s system from faults, which may occur on another User‟s
system, it is essential that certain minimum standards of protection are adopted. This
Section describes these minimum standards.

9.2 OBJECTIVE
The objective of this Chapter is to define the minimum protection requirements for any
equipment connected to the Transmission System and thereby minimise disruption due to
faults.

9.3 GENERAL PRINCIPLES

No item of electrical equipment shall be allowed to remain connected to the

Transmission System unless it is covered by appropriate protection aimed at reliability,
selectivity, speed and sensitivity. Guidelines mentioned in protection manuals of Central
Bureau of Irrigation & Power (CBI & P) may be kept in view.

All Users shall co-operate with the Transmission Licensee to ensure correct and
appropriate settings of protection to achieve effective and discriminatory removal of
faulty equipment within the time for target clearance specified in this Chapter.

Protection settings shall not be altered or protection bypassed and/or disconnected

without consultation and agreement of all affected Users. In the case where protection is
bypassed and / or disconnected, by agreement for any reason, then the cause must be
rectified and the protection restored to normal condition as quickly as possible. If
agreement has not been reached, the electrical equipment will be removed from service
forthwith.

There shall be provision of distance protection schemes with carrier inter tripping
between the grid s/s of the STU/Transmission licensee and the users capable of injecting
power to the transmission system. This should be used in case of Captive Generating
Plants connected to the grid and for those Users connected to the STU/Transmission
System through multiple feeders.

In case of users as indicated above distance protection schemes as per the guidelines of
Indian Standard Specification (ISS/IEC) shall have to be provided both at the grid end as
well as at the users end.

In case of all CGPs/IPPs connected to the grid substation of the Transmission Licensee,
Users capable of injecting power to the transmission system at 33 KV and above (at
STU‟s grid sub-station) shall provide Reverse Power Relays at the point of
interconnection.
 - 92 -

9.4 PROTECTION CO-ORDINATION

The STU‟s Protection Co-ordination committee shall be responsible for arranging

periodical meetings between all Users to discuss co-ordination of protection. The STU
shall investigate any mal-function of protection or other unsatisfactory protection issues.
Users shall take prompt action to correct any protection mal-function or issue as
discussed and agreed to in these periodical meetings.

Relay setting coordination shall be done at Regional level by ERPC.

9.5 FAULT CLEARANCE TIMES

From a stability consideration, the maximum fault clearance time for faults on any User‟s
system directly connected to the Transmission System, or any faults on the Transmission
System itself, are as referred at Section 4.8(3) of Chapter-4.

Slower fault clearance time for faults on an Users system may be agreed to but only if, in
the Transmission Licensee‟s opinion, system conditions allow this.

9.6 GENERATOR REQUIREMENTS

All Generating Units and all associated electrical equipment of the generator connected
to the Transmission System shall be protected by adequate protection so that the
Transmission System does not suffer due to any disturbance originating from the
Generating Unit.

9.7 TRANSMISSION LINE REQUIREMENTS

Every EHV line taking off from a Power Station or a sub-station shall have distance
protection and back up protection as mentioned below. The Transmission Licensee shall
notify Users of any changes in its policy on protection from time to time.

(a) 400 kV Lines

Three zone static non-switched distance protection with permissive inter trip for
accelerating tripping at remote end in case of a zone-2 fault as main-1 protection shall be
provided. Main-2 protection shall be similar fast protection using direction comparison
or phase comparison carrier relaying scheme. In addition to the above, single pole
tripping and single shot single pole auto-reclosing after an adjustable dead time shall be
provided. There need be no other back up protection.

(b) 220 kV Lines

Three zone static non-switched distance protection with permissive inter trip for
accelerating tripping at remote end in case of zone-2 fault as main protection is to be
provided. The back up will be three phase directional over current and earth fault
protection. One pole tripping and single shot single pole auto-reclosing with adjustable
dead time shall be provided.
 - 93 -

(c) 132 kV Lines

Three-zone static or electro-magnetic distance protection with permissive inter-trip for

accelerating tripping at remote end in case of a zone-2 fault shall be provided as main
protection. The backup will be directional three poles over current and earth fault
protection.

(1) General: - For short transmission lines alternative appropriate protection schemes
may be adopted. Relay Panels for the protection of lines of the Transmission
Licensee taking off from a Power Station shall be owned and maintained by the
Transmission Licensee. Generators shall provide space, connection facility, and
access to the Transmission Licensee, for such purpose.

(2) Review of protection system for accommodating technological up gradation shall

be carried out if it would result in efficient operation of the Power System and
decision taken shall be implemented with information to the Commission.

(3) In case of EHT consumers connected through single circuits by radial feeders there
is no scope of back feeding to the system. Hence, there is no utility of a distance
protection relay in respect of such consumers at the consumer end. However, there
is need of distance protection scheme for all EHT feeders including radial feeders
emanating from the grid substations at the grid S/S end.

(4) The distance relay can be applied for the protection of short lines, Transformer
feeders, Tee lines, double circuit lines as well as for single pole and triple pole auto
reclosing.

(5) The distance relay can be applied for 33 KV network also.

9.8 DISTRIBUTION LINE REQUIREMENTS

All 33 kV and 11 kV lines at Connection Points shall be provided with breakers having a
minimum of over current and earth fault protection with or without directional features
so that fault occurred at their end will not be reflected towards grid sub-station end. The
features are given below:

(1) Non-Parallel Radial Feeders

Non-directional time lag over current and earth fault relay with suitable settings to obtain
discrimination between adjacent relay stations.

(2) Parallel Feeders/ Ring Feeders

Directional time lag over current and earth fault relays.

 - 94 -

(3) Long Feeders/Transformer Feeders

For long feeders or transformer feeders, the relays should incorporate a high set
instantaneous element (timer, relay).

9.9 TRANSFORMER REQUIREMENTS

(1) Generating Station/ Transmission System

All windings of autotransformers and power transformers of EHV class shall be

protected by differential relays and REF relays. In addition there shall be back up time
lag over current and earth fault protection. For parallel operation such back up protection
shall have directional feature. For protection against heavy short circuits, the over current
relays should incorporate a high set instantaneous element. In addition to electrical
protection, gas operated relays, winding temperature protection and oil temperature
protection shall be provided.

(2) Distribution System

For transformers of HV class on the Distribution System differential protection shall be

provided for 5 MVA and above along with back up time lag over current and earth fault
protection (with directional feature for parallel operations). Transformers 1.6 MVA and
above and less than 5 MVA shall be protected by time lag over current, earth fault and
instantaneous REF relays. In addition all transformers 1.6 MVA and above shall be
provided with gas-operated relays, temperature protection and winding temperature
protection and oil temperature protection.

9.10 SUB-STATION BUS BAR AND FIRE PROTECTION

(1) All Users shall provide adequate bus zone protection for sub-station bus bars in
all 400 kV and 220 kV class sub-stations.

(2) Adequate precautions shall be taken and protection shall be provided against fire
hazards to all Apparatus of the Users conforming to relevant Indian Standard
Specification and / or provisions in IE Rules.

9.11 DATA REQUIREMENTS

Users shall provide the Transmission Licensee with data for this Section as specified in
the Data Registration Chapter.
 - 95 -

CHAPTER-10
METERING AND COMMUNICATION AND DATA ACQUISITION

10.1 INTRODUCTION

This Chapter specifies the minimum operational and commercial metering,

communication and data acquisition requirements to be provided by each User at the
inter-Connection Points and also at the cross boundary circuits. The Special Energy
Meters addressed at 10.6 below covers following meters of CEA (Installation and
Operation of Meters) Regulation, 2006.

(i) Interface Meters are –

(a) the meters installed at the points of interconnection with inter/intra State
Transmission System for purpose of electricity accounting and billing.
(b) the meters installed at the points of interconnection between the two licensees for
purpose of electricity accounting and billing.
(c) the meters installed at the points of interconnection with inter/intra State
Transmission System for a consumer who has been permitted open access by the
Appropriate Commission for purpose of electricity accounting and billing.
(d) the meters installed at the points of interconnection with Distribution System for
a consumer who has been permitted open access by the Appropriate Commission
for purpose of electricity accounting and billing.
(ii) Energy Accounting and Auditing Meters-
These are the meters installed to account for energy generated, transmitted,
distributed and consumed in various segments of the power system and the
energy loss.

10.2 OBJECTIVE

The objective of this Chapter is to define the minimum acceptable metering and
communication and data acquisition requirements to enable the Transmission Licensee to
manage the Transmission System in a safe and economic manner consistent with licence
requirements.

10.3 GENERATION OPERATIONAL METERING

(1) This Section specifies the facilities that shall be provided, certain practices that
shall be employed for monitoring output and response of Power Stations and
Generating Units and shall not apply to generator including CGP upto 25 MW for
dedicated line (tie line) and upto 15 MW in case of non-dedicated (non-tie) line.
(2) The generator shall install operational metering to the STU specification so as to
provide operational information for both real time and recording purposes in
relation to each Generating Unit at each Power Station in respect of:
(i) Bus Voltage
(ii) Frequency
(iii) MW
(iv) MVAr
and other additional data as agreed between the Transmission Licensee and
generator.
 - 96 -

(3) All current transformers and voltage transformers used in conjunction with
operational metering shall conform to relevant Indian Standard Specifications or
the relevant IEC, of accuracy class 0.5 and of suitable rating to cater to the meters
and the lead wire burdens.

(4) Metering shall be calibrated, so as to achieve overall accuracy of operational

metering in the limits as agreed between the licensee and generator. Records of
calibration shall be maintained for reference and shall be made available to the
licensee upon request. Calibration standards and norms are to be followed.

(5) Generators shall furnish recorded data of all electrical measurements and events
recorded by the operational metering to the licensee at least once in a week or
more often if required.

10.4 TRANSMISSION SYSTEM OPERATIONAL METERING

(1) This Section specifies the facilities that shall be provided, certain practices that
shall be employed for monitoring electrical supply and load characteristic at each
sub-station.

(2) The licensee shall install operational metering so as to provide operational

information for both real time and recording purposes in relation to each feeder,
transformer and compensation device at each sub-station in respect of:

(i) Bus Voltage

(ii) Frequency
(iii) MW
(iv) MVAr
(v) Power Factor
(vi) Current.

10.5 SUPERVISORY CONTROL AND DATA ACQUISITION (SCADA)

(1) The Licensee shall install and make operative an operational metering data
collection system under SCADA for storage, display and processing of
operational metering data. All Users shall make available outputs of their
respective operational meters to the SCADA interface equipment.

(2) The data collection, storage and display centre of the STU shall be the State Load
Despatch Centre at Bhubaneswar.

10.6 REGULATORY REQUIREMENTS OF SPECIAL ENERGY METERS

(1) Special energy meters (i.e. including export/import meters for CGPs and meters
for the start up power exchange for the generators) of a uniform technical
specification shall be provided on the electrical periphery of each Beneficiary, to
determine its actual net interchange with the State grid. Each interconnection
shall have one (1) Main meter. In addition, Standby/check meters shall be
 - 97 -

provided such that correct computation of net interchange of a Beneficiary 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 sections. 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: 3 element 4
wires or Model C: 2 element, 3 wire) or 5A (model-B : 3 element, 4 wire or
Model D : 2 element 3 wire). 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 transmitted during each successive 15-minute block, up to 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.
(vii) Any other information agreed to between parties /decided by the
Commission.

(4) The meters shall store all the above listed data in their memories for a period
minimum of thirty-five (35) days. The data older than (35) days shall get erased
automatically with due back up and dump. 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. The meter shall be suitable for transmitting the data to remote
location using appropriate communication medium.

(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 and C, the energy shall be computed directly in CT and VT secondary
quantities, and indicated in watt-hours. In model-B and model D, 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 accuracy as per class 2 of IEC-62053-23 or better. In model-A or
model C, the VAr and VArh computation shall be directly in CT and VT
secondary qualities. In model-B or model D, the above quantities shall be
displayed and recorded as one-fifth of those computed in CT and VT secondary
quantities. There shall be two reactive energy registers, one for the period when
 - 98 -

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 bus bars, 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 minimum 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.

(11) The Main Meter and Check meter shall be connected to same core of CTs and
VTs.

(12) All metering equipment shall be of proven quality, fully type-tested, individually
tested and accepted by the STU before despatch from manufacturer‟s work.

(13) In-situ functional checking and rough testing of accuracy shall be carried out for
all meters once a year by the STU, with portable test equipment complying with
IEC-60736, for type and acceptance testing of energy meters of 1.0 class.

(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.
 - 99 -

(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 STU,
keeping in view various guidelines in this regard.

(16) Meters shall be tested and calibrated at such interval as specified in the CEA
(Installation and Operation of Meters) Regulations, 2006 or such period as
mutually agreed between generator and the licensee according to guidelines
provided in relevant Indian Standard Specification or relevant IEC as applicable.
Records of meter calibration test shall be maintained for future reference.

(17) A procedure shall be drawn up between the licensee and generators, and between
the licensee and Power Grid covering summation, collection, processing of tariff
meter readings, at various connection sites. This may be revised from time to
time as necessary.

(18) The ownership and responsibility of maintenance and testing of meters shall be as
mutually agreed between the Users and the licensees.

(19) CEA (Installation and Operation of Meters) Regulations, 2006 may please be
referred and adopted which provide for type, standards, ownership, location,
accuracy class, installation, operation, testing and maintenance, access, sealing,
safety, meter reading and recording, meter failure or discrepancies, anti-
tampering features, quality assurance, calibration and periodical testing of meters,
additional meters and adoption of new technologies in respect of interface meters
for correct accounting, billing and audit of electricity.

10.6 COMMUNICATION

Independent dedicated communication links for voice communication, for written

communication and for data acquisition shall be installed by the STU/ Transmission
licensee between all Power Stations, Transmission System sub-stations and SLDC. In
addition, similar links between adjacent Transmission System sub-stations shall be
established. Communication shall be available by dialling discrete numbers and also
through Hot line by lifting the telephone hand set. Hot line links shall be established by
the Transmission Licensee between Power Station / important sub-station and SLDC.

10.8 DATA ACQUISITION

(1) For effective control of the Transmission System, the SLDC needs real time data
as follows:
(i) MW generated in each Power Station.
(ii) MW draw from External Interconnection.
(iii) MVAr generated or absorbed in each Power Station.
(iv) MVAr imported or exported from External Interconnection.
(v) Voltage in all system buses.
(vi) Frequency in Transmission System.
(vii) MW & MVAr flow in each transmission line.
 - 100 -

(2) Generators shall provide necessary transducers for the transmission of the above
data to SLDC.
(3) The Transmission Licensee shall similarly provide necessary transducers in their
system for the transmission of the above data to SLDC.

(4) The SLDC shall establish a suitable data transfer link between SLDC and
ERLDC for the exchange of operational data.

10.9 PROCEDURE FOR COMMUNICATION AND DATA TRANSMISSION

The procedure for regulating technical standards for connectivity to the Grid,
establishment of voice and data communication to SLDC outlining inter responsibility,
accountability and recording of day-to-day communication and data transmission on
operational matters is as per the “procedure for provisions of voice and data
communication facilities”(approved by OERC) and notified by OPTCL in extraordinary
Odisha Gazette No.485 dt.29.03.2012.

Data Requirement

The licensee and Users shall furnish metering data to each other, as applicable and as
detailed in Data Registration Chapter.

10.10 Application of CEA Regulations –

The provisions of the Regulations framed by Central Electricity Authority (CEA) under
Section 55(1), 73(e) and 177(2)(c) of the Electricity Act, 2003 as amended from time to
time, shall be applicable with regard to installation and operation of meters. In case there
is any inconsistency between CEA Regulations and this Code, the former shall prevail.

10.11 Application of IEGC Regulations and Manual on Transmission Planning Criteria

of CEA –

The provisions of the IEGC Regulations framed by CERC under section 79(i)(h) read
with 178(2)(g) of the Electricity Act as amended from time to time and orders, if any, on
this matter by CERC shall be applicable. In case there is any inconsistency between
IEGC and this Code the former shall prevail. The Manual on Transmission Planning
criteria of CEA and amendment thereto shall also be applicable.
 - 101 -

CHAPTER-11
MANAGEMENT OF THE ODISHA GRID CODE

11.1 MANAGEMENT OF OGC

The OGC shall be specified by the OERC as per section 86 (1) (h) of the Act. Any
amendments to OGC shall also be specified by OERC only.

(1) The OGC and its amendments shall be finalized and notified adopting the
prescribed procedure followed for regulations issued by OERC.

(2) The requests for amendments to / modifications in the OGC and for removal of
difficulties shall be addressed to Secretary, OGC, for periodic consideration,
consultation and disposal.

Such amendments/modifications suggested shall be finalized after obtaining

opinions from all Users of the State Grid.

(3) Any dispute or query regarding interpretation of OGC may be addressed to

Secretary, OERC and clarification issued by the OERC shall be taken as final and
binding on all concerned.

(4) The OERC shall specify the OGC for operation of the State Transmission System
as per section 86 (1) (h) of the Act, ensuring that they are consistent with the
IEGC.

11.2 GRID COORDINATION COMMITTEE (GCC)

(1) A Grid Coordination Committee shall be constituted by the STU within 30

(thirty) days from the date of notification of these Regulations.

(2) The Grid Coordination Committee shall be responsible for the following matters,
namely-
(i) Facilitating the implementation of these Regulations and the rules and
procedures developed under the provisions of these Regulations;
(ii) Assessing and recommending remedial measures for issues that might
arise during the course of implementation of provisions of these
Regulations and the rules and procedures developed under the provisions
of these Regulations;
(iii) Periodical review of the OGC, in accordance with the provisions of the
Act and these Regulations;
(iv) Analyse any major grid disturbance soon after its occurrence,
(v) Examining problems raised by the Users.
(vi) Investigate / take action in case any Beneficiary is indulging in unfair
gaming or collusion after getting reported from SLDC.
(vii) Initiate remedial action against persistent default payment of Deviation/
UI and VAr charges reported by SLDC.
 - 102 -

(viii) Decide utilisation of money remaining in the State reactive account (Refer
Clause 7 of Complementary Commercial Mechanisms)
(ix) Audit the complete statement of the State Deviation/ UI and the State
Reactive Energy account tabled by SLDC by its Commercial Committee
(a sub-committee of GCC).
(x) Such other matters as may be directed by the Commission from time to
time.

(3) The Grid Coordination Committee shall comprise of the following members:

(i) One member of the SLDC;

(ii) One member from State Transmission Utility i.e. OPTCL;
(iii) One member to represent the each of the generating companies in the
State namely OHPC, OPGC and NTPC (TTPS);
(iv) One member to represent the Transmission Licensees in the State, other
than the STU;
(v) One member to represent each of the Distribution Licensees in the State;
(vi) One member to represent GRIDCO;
(vii) One member to represent the Trading Licensees in the state, (other than
GRIDCO);
(viii) One representative of Captive Generating Plants from the State having
installed capacity more than 100 MW;
(ix) One representative of PGCIL;
(x) One representative from ERLDC;
(xi) One representative from Electrical Inspectorate.
(xii) One representative from OERC as an observer, and
(xiii) Such other persons as may be nominated by the Commission.

(4) The Members of the Committee shall elect a Chairman from among themselves
for a period of one year after which a new Chairman will be elected for next year.

Provided that the STU shall nominate some of its senior officers as Member
Secretary.

Provided further that the STU shall, in coordination with SLDC, facilitate and
manage the functioning of the (GCC).

(5) The members of the (GCC); shall be selected as follows:

(i) The concerned Director of STU, having the responsibility of looking after
technical activities of STU shall be the member referred to in Section 11.2
(3)(ii) above;
(ii) the member referred to in Section11.2 (3) (i) above, shall be the head of
SLDC;
(iii) the members referred to in clauses (iii), (iv), (v), (vi) and (vii) of Section
11.2 (3) above shall be nominated by their respective organizations;
(iv) Organizations referred under Sections 11.2(3)(iv), (vii) and (viii) will be
selected in rotation from among all such organizations in the State. The
term of each such member, selected in rotation, shall be one (1) year.
 - 103 -

Provided that the members nominated by each of the organisation to the above
Committee shall be holding a senior position in their respective organisations.

(6) As SLDC would be represented as one of the member of the Committee, the
decisions of the Committee arrived by consensus regarding operation of the State
Grid and scheduling and dispatch of electricity will be followed by SLDC subject
to direction of the Commission, if any.

(7) The Committee shall have a secretariat of its own which will be headed by the
Member Secretary of the Committee. The Member Secretary as well as other
staff for the secretariat shall be provided by the STU in the manner as decided by
the Committee.

(8) The Committee will frame its own rules of business for the conduct of its meeting
and other related matters.

(9) The Committee may constitute its sub-committees as deemed necessary for
efficient functioning. It may also set up, if required, Groups/Committees of
eminent experts to advise on issues of specific nature.

(10) The Committee shall meet at least once in a quarter and at such other time as may
be considered necessary.
 - 104 -

CHAPTER-12

DATA REGISTRATION
12.1 INTRODUCTION

This Chapter contains a list of all data required by the Transmission Licensee which is to
be provided by Users and data required by Users to be provided by the Transmission
Licensee at times specified in the OGC. Other Chapters of the OGC contain the
obligation to submit the data and defines the times when data is to be supplied by Users.

12.2 OBJECTIVE

The objective of this Chapter is to list all the data required to be provided by Users to the
Transmission Licensee and vice versa, in accordance with the provisions of the OGC.

12.3 RESPONSIBILITIES

All Users are responsible for submitting up-to-date data to the Transmission Licensee in
accordance with the provisions of the OGC.

All Users shall provide the Transmission Licensee with the name, address and telephone
number of the person responsible for sending the data.

The Transmission Licensee shall inform all Users of the name, address and telephone
number of the person responsible for receiving data.

The Transmission Licensee shall provide up-to-date data to Users as provided in the
relevant schedule of the OGC.

Responsibility for the correctness of data rests with the concerned Users providing the
data.

12.4 DATA CATEGORIES AND STAGES IN REGISTRATION

Data as required to be exchanged have been listed in the Appendices (see Section 12.8)
of this chapter under various categories with cross- reference to the concerned chapter.

12.5 CHANGES TO USERS DATA

Whenever any User becomes aware of a change to any items of data, which is registered
with the Transmission Licensee, the User must promptly notify the Transmission
Licensee of the changes. The Transmission Licensee on receipt of intimation of the
changes shall promptly correct the database accordingly. This shall also apply to any
data complied by the Transmission Licensee regarding to its own system.

12.6 DATA NOT SUPPLIED

Users are obliged to supply data as referred to in the individual chapter of the OGC and
listed out in the Data Registration Chapter Appendices. In case any data is missing and
 - 105 -

not supplied by any User, the Transmission Licensee may, acting reasonably, if and
when necessary, estimates such data depending upon the urgency of the situation.
Similarly in case any data is missing and not supplied by the Transmission Licensee, the
concerned User may, acting reasonably, if and when necessary, estimates such data
depending upon urgency of the situation. Such estimates will in each case, be based upon
corresponding data for similar plant or Apparatus or upon such other information, the
User or the Transmission Licensee, as the case may be, deems appropriate.

12.7 SPECIAL CONSIDERATIONS

The Transmission Licensee and any other User may at any time make reasonable request
for extra data as necessary.

12.8 APPENDICES

APPENDIX SUBJECT

A STANDARD PLANNING DATA

B DETAILED PLANNING DATA
C OPERATIONAL PLANNING DATA
D PROTECTION DATA
E METERING DATA
 - 106 -

APPENDIX- A
DATA REGISTRATION
STANDARD PLANNING DATA
REFERENCE TO:
CHAPTER 3 SYSTEM PLANNING
CHAPTER-4 CONNECTION CONDITION

A.1 STANDARD PLANNING DATA (GENERATION)

A.1.1 THERMAL (COAL / FUEL LINKED)

A.1.1.1 GENERAL

i. Site Give location map to scale showing roads, railway

lines, transmission lines, rivers and reservoirs if any.
ii. Coal linkage/ Fuel (Like Liquid Give information on means of coal transport from
Natural Gas, Naptha etc.) coalmines in case of pithead stations or means of coal
linkage carriage if coal is to be brought from (distance). In
case of other fuels, give details of source of fuel and
their transport.
iii. Water Sources Give information on availability of water for operation
of the Power Station.
iv. Environmental State whether forest, lands mining clearance areas are
affected.
v. Site map (To Scale) Showing area required for Power Station coal linkage,
coal yard, water pipe line, ash disposal area, colony
etc.
vi. Approximate period of
construction.

A.1.1.2 CONNECTION
i. Point of Connection Give Single Line Diagram of the proposed Connection
with the system.
ii. Step up voltage for connection in
kV.
A.1.1.3 STATION CAPACITY

i. Total Power Station capacity State whether development will be carried out in phase
(MW) and if so, furnish details.
ii. No. of units & unit size MW
 - 107 -

A.1.1.4 GENERATING UNIT DATA

i. Steam Generating Unit State type, capacity, steam pressure, steam temperature
etc.
ii. Steam turbine State type, and capacity.
iii. Generator a. Type
b. Rating ( MVA)
c. Terminal voltage (kV)
d. Rated Power Factor
e. Reactive Power Capability ( MVAr) in the range
0.95 of leading and 0.85 lagging
f. Short Circuit Ratio
g. Direct axis transient reactance (% on MVA rating)
h. Direct axis sub-transient reactance ( % on MVA
rating)
i. Auxiliary Power Requirement (MW)

iv. Generator Transformer a. Type

b. Rated capacity (MVA)
c. Voltage Ratio ( HV/LV)
d. Tap change Range (+ % to - %)
Percentage Impedance (Positive Sequence
at Full load)
A.1.2 HYDRO ELECTRICAL
A.1.2.1 GENERAL
i. Site Give location map to scale showing roads, railway
lines, and transmission lines.
ii. Site map (To scale) Showing proposed dam, reservoir area, water
conductor system, fore-bay, power house etc.

iii. Submerged Area Give information on area submerged, villages

submerged, submerged forest land, agricultural land
etc.
iv. Approximate period of
construction.

A.1.2.2 CONNECTION
i. Point of Connection Give Single Line Diagram proposed connection with
the Transmission System.

ii. Step up voltage for Connection kV

A.1.2.3 STATION CAPACITY

i. Total Power Station capacity State whether development is carried out in phases and
(MW) if so furnish details.
ii. No of units & unit size MW
 - 108 -

A.1.2.4 GENERATING UNIT DATA

i. Operating Head ( in Mtr.) a. Maximum
b. Minimum
c. Average.

ii. Turbine. State Type and capacity

iii. Generator a. Type
b. Rating (MVA)
c. Terminal voltage (kV)
d. Rated Power Factor
e. Reactive Power Capability (MVAr) in the range
0.95 of leading and 0.85 of lagging
f. Short Circuit Ratio
g. Direct axis transient reactance (% on rated MVA)
h. Direct axis sub-transient reactance (% on rated
MVA)
i. Auxiliary Power Requirement (MW)

iv. Generator Transformer a. Type

b. Rated Capacity (MVA)
c. Voltage Ratio HV/LV
d. Tap change Range (+% to -%)
e. Percentage Impedance (Positive sequence at full
load).

A.2 STANDARD PLANNING DATA (TRANSMISSION)

Note: The compilation of the data is the internal matter of the Transmission Licensee, and
as such the Transmission Licensee shall make arrangements for getting the required
data from different departments of the Transmission Licensee to update its
Standard Planning Data in the format given below:

i. Name of line (Indicating Power Stations and sub-stations to be connected).

ii. Voltage of line (kV).
iii. No. of circuits.
iv. Route length (km).
v. Conductor sizes.
vi. Line parameters (pu values).
a. Resistance/km.
b. Inductance/km.
c. Susceptance/km (B/2).
vii. Approximate power flow expected MW & MVAr.
viii. Terrain of route - Give information regarding nature of terrain i.e. forest land,
fallow land, agricultural and river basin, hill slope etc.
ix. Route map (to Scale) - Furnish topographical map showing the proposed route
showing existing power lines and telecommunication lines.
x. Purpose of Connection - Reference to scheme, wheeling to other States etc.
xi. Approximate period of Construction.
 - 109 -

A.3 STANDARD PLANNING DATA (DISTRIBUTION)

A.3.1 GENERAL
i. Area map (to scale)- Marking the area in the map of Orissa for which distribution
licence is applied for.
ii. Consumer Data- Furnish categories of consumers, their numbers and connected
loads.
iii. Reference to Electrical Divisions presently in charge of the distribution.

A.3.2 CONNECTION
i. Points of Connection- Furnish Single Line Diagram showing points of
connection.
ii. Voltage of supply at points of connection
iii. Names of grid sub-station feeding the points of connection

A.3.3 LINES AND SUBSTATIONS

i. Line data- Furnish lengths of line and voltages within the Area.
ii. Sub-station data- Furnish details of 33 / 11 kV sub-stations, 11 / 0.4 kV
sub-stations, capacitor installations.

A.3.4 LOADS
i. Loads drawn at points of connection.
ii. Details of loads fed at EHV, if any. Give name of consumer, voltage of supply,
contract demand and name of Grid Sub-station from which line is drawn, length
of EHV line from Grid Sub-station to consumer's premises.

A.3.5 DEMAND DATA (FOR ALL LOADS 5 MW AND ABOVE)

i. Type of load- State whether furnace loads, rolling mills, traction loads, other
industrial loads, pumping loads etc.
ii. Rated voltage and phase.
iii. Electrical loading of equipment- State number and size of motors, types of drive
and control arrangements.
iv. Sensitivity of load to voltage and frequency of supply.
v. Maximum Harmonic content of load.
vi. Average and maximum phase unbalance of load.
vii. Nearest sub-station from which load is to be fed.
viii. Location map (to scale)- Showing location of load with reference to lines and
sub-stations in the vicinity.
A.3.6 LOAD FORECAST DATA
i. Peak load and energy forecast for each category of loads for each of the
succeeding 10 years.
ii. Details of methodology and assumptions on which forecasts are based.
iii. If supply is received from more than one Sub-station, the sub-station wise break
up of peak load and energy projections for each category of loads for each of the
succeeding 10 years along with estimated daily load curve.
iv. Details of loads 5 MW and above.
a. Name of prospective consumer.
b. Location and nature of load/complex.
 - 110 -

APPENDIX- B

DETAILED PLANNING DATA

REFERENCE TO:
CHAPTER-3 SYSTEM PLANNING
CHAPTER-4CONNECTION CONDITIONS

B.1 DETAILED PLANNING DATA (GENERATION)

PART 1. FOR ROUTINE SUBMISSION

B.1.1 THERMAL POWER STATIONS (COAL BASED)

B.1.1.1 GENERAL
i. Name of Power Station.
ii. Number and capacity of Generating Sets (MVA).
iii. Ratings of all major equipments (boilers and major accessories, turbines,
alternators, Generating Unit transformers etc.).
iv. Single Line Diagram of Power Station and switchyard.
v. Relaying and metering diagram.
vi. Neutral grounding of Generating Units.
vii. Excitation control (What type is used ? e.g. Thyristor, Fast Brush less ?).
viii. Earthing arrangements with earth resistance values.

B.1.1.2 PROTECTION AND METERING

i. Full description including settings for all relays and protection systems installed
on the Generating Unit, Generating Unit transformer, auxiliary transformer and
electrical motor of major equipment listed, but not limited to, under Sl.3
(General).
ii. Full description including settings for all relays installed on all outgoing feeders
from Power Station switchyard, tie circuit breakers, incoming circuit breakers.
iii. Full description of inter-tripping of circuit breakers at the point or points of
Connection with the Transmission System.
iv. Most probable fault clearance time for electrical faults on the User's system.
v. Full description of operational and commercial metering schemes.

B.1.1.3 SWITCHYARD
In relation to interconnecting transformers:
i. Rated MVA.
ii. Voltage Ratio.
iii. Vector Group.
iv. Positive sequence reactance for maximum, minimum, normal Tap. (% on MVA).
v. Positive sequence resistance for maximum, minimum, normal Tap. (% on
MVA).
vi. Zero sequence reactance. (% on MVA).
vii. Tap changer Range (+% to -%) and steps.
viii. Type of Tap changer. (OFF/ON).
 - 111 -

In relation to switchgear including circuit breakers, isolators on all circuits connected

to the points of Connection:
i. Rated voltage (kV).
ii. Type of circuit breaker (MOCB/ABCB/SF6).
iii. Rated short circuit breaking current (kA) 3 phase.
iv. Rated short circuit breaking current (kA) 1 phase.
v. Rated short circuit making current (kA) 3 phase.
vi. Rated short circuit making current (kA) 1-phase.
vii. Provisions of auto reclosing with details.

Lightning Arresters-
Technical data.
Communication-
Details of equipment installed at points of Connections.
Basic Insulation Level (kV)-
i. Bus bar.
ii. Switchgear.
iii. Transformer bushings.
iv. Transformer windings.

B.1.1.4 GENERATING UNITS

(a) Parameters of Generating Units:
i. Rated terminal voltage (kV).
ii. Rated MVA.
iii. Rated MW.
iv. Inertia constant (MW Sec./MVA) H.
v. Short circuit ratio.
vi. Direct axis synchronous reactance (% on MVA) Xd
vii. Direct axis transient reactance (% on MVA) X'd
viii. Direct axis sub-transient reactance (% on MVA) X"d
ix. Quadrature axis synchronous reactance (% on MVA) Xq
x. Quadrature axis transient reactance (% on MVA) X'q
xi. Quadrature axis sub-transient reactance (% on MVA) X"q
xii. Direct axis transient open circuit time constant (Sec) T'do
xiii. Direct axis sub-transient open circuit time constant (Sec) T"do
xiv. Quadrature axis transient open circuit time constant (Sec) T'qo
xv. Quadrature axis sub-transient open circuit time constant (Sec) T"qo
xvi. Stator resistance (Ohm) Ra
xvii. Stator leakage reactance (Ohm) Xl
xviii. Stator time constant (Sec).
xix. Rated field current (A).
xx. Open circuit saturation characteristic for various terminals
giving the compounding current to achieve the same.

(b) Parameters of Excitation Control System:

i. Type of excitation.
ii. Maximum field voltage.
iii. Minimum field voltage.
iv. Rated field voltage.
 - 112 -

v. Details of excitation loop in block diagrams showing transfer functions of

individual elements using IEEE symbols.
vi. Dynamic characteristics of over-excitation limiter.
vii. Dynamic characteristics of under-excitation limiter.

(c) Parameters of Governor:

i. Governor average gain (MW/Hz).
ii. Speeder motor setting range.
iii. Time constant of steam or fuel governor valve.
iv. Governor valve opening limits.
v. Governor valve rate limits.
vi. Time constant of turbine.
vii. Governor block diagram showing transfer functions of individual elements using
IEEE symbols.

(d) Operational Parameters:

i. Minimum notice required synchronising a Generating Unit from
de-synchronisation.
ii. Minimum time between synchronising different Generating Units in a Power
Station.
iii. The minimum block load requirements on synchronising.
iv. Time required for synchronising a Generating Unit for the following conditions:
a. Hot
b. Warm
c. Cold
v. Maximum Generating Unit loading rates for the following conditions:
a. Hot
b. Warm
c. Cold
vi. Minimum load without oil support (MW)

B.1.2 HYDROELECTRIC STATIONS

B.1.2.1 GENERAL
i. Name of Power Station.
ii. No. and capacity of units. (MVA)
iii. Ratings of all major equipment.
a. Turbines (HP).
b. Generators (MVA).
c. Generator Transformers (MVA).
d. Auxiliary Transformers (MVA).
iv. Single Line Diagram of Power Station and switchyard.
v. Relaying and metering diagram.
vi. Neutral grounding of generator.
vii. Excitation control.
viii. Earthing arrangements with earth resistance values.
ix. Reservoir Data.
a. Salient features
b. Type of Reservoir
(i) Multipurpose
(ii) For Power
 - 113 -

c. Operating Table with]

(i) Area capacity curves, and
(ii) Unit capability at different net heads

B.1.2.2 PROTECTION

i. Full description including settings for all relays and protection systems installed
on the Generating Unit, generator transformer, auxiliary transformer and
electrical motor of major equipment included, but not limited to those listed],
under SI.3 (General).
ii. Full description including settings for all relays installed on all outgoing feeders
from Power Station switchyard, tie breakers, incoming breakers.
iii. Full description of inter-tripping of breakers at the point or points of connection
with the Transmission System.
iv. Most probable fault clearance time for electrical faults on the User's system.

B.1.2.3 SWITCHYARD
(a) Interconnecting Transformers:
i. Rated MVA.
ii. Voltage ratio.
iii. Vector group.
iv. Positive sequence reactance for maximum, minimum and normal tap. (% on
MVA).
v. Positive sequence resistance for maximum, minimum and normal Tap (% on
MVA).
vi. Zero sequence reactance (% on MVA).
vii. Tap changer range (+% to -%) and steps.
viii. Type of tap changer. (OFF/ON).

(b) Switchgear (including circuit breakers, isolators on all circuits connected to the points
of Connection.)
i. Rated voltage (kV).
ii. Type of Breaker (MOCB/ABCB/SF6).
iii. Rated short circuit breaking current (kA) 3 phases.

(c) Lightning Arresters:

Technical data.
(d) Communications:
Details of communications equipment installed at points of Connections.

(e) Basic Insulation Level (kV):

i. Bus bar.
ii. Switchgear.
iii. Transformer bushings.
iv. Transformer windings.

B.1.2.4 GENERATING UNITS

(a) Parameters of generator

i. Rated terminal voltage (kV).
 - 114 -

ii. Rated MVA.

iii. Rated MW.
iv. Inertia constant (MW sec/MVA) H.
v. Short circuit ratio.
vi. Direct axis synchronous reactance. (% On MVA) Xd.
vii. Direct axis transient reactance (% on MVA) X'd.
viii. Direct axis sub-transient reactance (% on MVA) X"d.
ix. Quadrature axis synchronous reactance (% on MVA) Xq
x. Quadrature axis transient reactance (% on MVA) X'q
xi. Quadrature axis sub-transient reactance (% on MVA) X"q
xii. Direct axis transient open circuit time constant (Sec) T'do
xiii. Direct axis sub-transient open circuit time constant (Sec) T"do
xiv. Quadrature axis transient open circuit time constant (Sec) T'qo
xv. Quadrature axis sub-transient open circuit time constant (Sec) T"qo
xvi. Stator Resistance (Ohm) Ra
xvii. Stator leakage reactance (Ohm) Xl
xviii. Stator time constant (Sec).
xix. Rated Field current (A).
xx. Open Circuit saturation characteristics of the generator for Various terminal
voltages giving the compounding current to achieve this.
xxi. Type of Turbine.
xxii. Operating Head (Mtr.).
xxiii. Discharge with Full Gate Opening (cumecs).
xxiv. Speed Rise on total Load thrown off (%).

(b) Parameters of Excitation Control System:

As applicable to thermal Power Stations.

(c) Parameters of Governor:

As applicable to thermal Power Stations.

(d) Operational Parameter:

i. Minimum notice required synchronising a Generating Unit from
de-synchronisation.
ii. Minimum time between synchronising different Generating Units in a Power
Station.
iii.Minimum block load requirements on synchronising.

PART 2. FOR SUBMISSION ON REQUEST BY TRANSMISSUION LICENSEE

B.1.3 THERMAL POWER STATIONS

B.1.3.1 GENERAL

i. Detailed Project report.

ii. Status Report.
a. Land.
b. Coal.
 - 115 -

c. Water.
d. Environmental clearance.
e. Rehabilitation of displaced persons.
iii. Techno-economic approval by CEA.
iv. Approval of State Government/Government of India
v. Financial Tie-up.

B.1.3.2 CONNECTION

i. Reports of studies for parallel operation with the Transmission System:

a. Short circuit studies.
b. Stability studies.
c. Load flow studies.
ii. Proposed connection with Transmission System:
a. Voltage.
b. Number of circuits.
c. Point of contact

B.1.4 HYDROELECTRIC POWER STATIONS

B.1.4.1 GENERAL

i. Detailed Project Report.

ii. Status Report.
a. Topographical survey.
b. Geological survey.
c. Land.
d. Environmental clearance.
e. Rehabilitation of displaced persons.
iii. Techno-economic approval by CEA.
iv. Approval of State Government/Government of India.
v. Financial Tie-up.

B.1.4.2. CONNECTION

i. Reports of Studies for parallel operation with the Transmission System:

a. Short circuit studies.
b. Stability studies.
c. Load flow studies.
ii. Proposed connection with Transmission System:
a. Voltage.
b. Number of circuits.
c. Point of Connection.

B.2 DETAILED SYSTEM DATA (TRANSMISSION)

B.2.1 GENERAL
i. Single Line Diagram of the Transmission System down to 33 kV bus at grid Sub-
station detailing:
a. Name of Sub-station.
b. Power Station, connected.
c. Number and length of circuits.
 - 116 -

d. Interconnecting transformers.
e. Sub-station bus layouts.
f. Power transformers.
g.Reactive compensation equipment.
ii. Sub-station layout diagrams showing:
a. Bus bar layouts.
b. Electrical circuitry, lines, cables, transformers, switchgear etc.
c. Phasing arrangements.
d. Earthing arrangements.
e. Switching facilities and interlocking arrangements.
f. Operating voltages.
g. Numbering and nomenclature:
i) Transformers.
ii) Circuits.
iii) Circuit breakers.
iv) Isolating switches.

B.2.2 LINE PARAMETERS (For all circuits)

i. Designation of Line.
ii. Length of line (km)
iii. Number of circuits.
iv. Per Circuit values.
a. Operating voltage (kV).
b. Positive Phase sequence reactance (pu on 100 MVA) X1
c. Positive Phase sequence resistance (pu on 100 MVA) R1
d. Positive Phase sequence susceptance (pu on 100 MVA) B1
e. Zero Phase sequence reactance (pu on 100 MVA) Xo
f. Zero Phase sequence resistance (pu on 100 MVA) Ro
g. Zero Phase sequence susceptance (pu on 100 MVA) Bo

B.2.3 TRANSFORMER PARAMETERS (For all transformers)

i. Rated MVA.
ii. Voltage Ratio.
iii. Vector Group.
iv. Positive sequence reactance, maximum, minimum and normal (pu on 100 MVA)
Xl
v. Positive sequence, resistance maximum, minimum and normal (pu on 100 MVA)
R1
vi. Zero sequence reactance (pu on 100 MVA).
vii. Tap change range (+% to -%)and steps.
viii. Details of Tap changer (OFF/ON).

B.2.4 EQUIPMENT DETAILS (For all Sub-stations)

i. Circuit Breakers
ii. Isolating switches
iii. Current Transformers
iv. Potential Transformers
 - 117 -

B.2.5 RELAYING AND METERING

i. Relay protection installed for all transformers and feeders along with their
settings and level of co-ordination with other Users.
ii. Metering details.

B.2.6 SYSTEM STUDIES

i. Load flow studies (peak and lean load for maximum hydro and maximum thermal
generation).
ii. Transient stability studies for three-phase fault in critical lines.
iii. Dynamic Stability Studies
iv. Short circuit studies (three phase and single phase to earth)
v. Transmission and distribution losses in the system.

B.2.7 DEMAND DATA (For all Sub-stations)

i. Demand Profile (Peak and lean load)

B.2.8 REACTIVE COMPENSATION EQUIPMENT

i. Type of equipment (fixed or variable).
ii. Capacities and/or inductive rating or its Operating Range in MVAr.
iii. Details of control.
iv. Point of connection to the system.

B.3 DETAILED PLANNING DATA, DISTRIBUTION

B.3.1 GENERAL
i. Distribution map (To scale) showing all lines up to 11 kV and sub-stations
belonging to the Supplier.
ii. Single Line Diagram of Distribution System (showing distribution lines from
points of connection with the Transmission System, 33/11 kV sub-stations, 11/0.4
kV sub-stations, consumer bus if fed directly from the Transmission System).
iii. Numbering and nomenclature of lines and sub-stations (Identified with feeding
grid sub-stations of the Transmission System and concerned 33/11 kV sub-station
of Supplier).

B.3.2 CONNECTION
i. Points of connection (Furnish details of existing arrangement of connection).
ii. Details of metering points of connection.
B.3.3 LOADS
i. Connected load - Furnish consumer details, Numbers of consumers category
wise, details of loads 1 MW and above.
ii. Information on diversity of load and coincidence factor.
iii. Daily demand profile (current and forecast) on each 33/11 kV sub-station.
iv. Cumulative demand profile of Distribution System (current and forecast).
 - 118 -

APPENDIX- C
C. OPERATIONAL PLANNING DATA

C.1 OUTAGE PLANNING DATA

REFERENCE TO: CHAPTER-5 OUTAGE PLANNING

C.1.1 DEMAND ESTIMATES

Item To be Submitted By

i. Estimated consumption of energy in million units at each 31st December of

Connection / External Interconnection Point on monthly current calendar year.
basis and peak and lean demand in MW & MVAr at each
Connection / External Interconnection Point on weekly basis
for the period from April of next calendar year to March of
following calendar year.
ii. Estimated consumption of energy in MU at each connection / 15th of current month
External Interconnection Point on daily basis for month
ahead and 24 hourly averaged demand estimates in MW &
MVAr at each connection / External Interconnection Point
for each day of the month ahead. (31 daily data items for MU
for each Connection Point, 31 x 24 hourly data items for
MW and 31 x 24 hourly data items for MVAr for each
Connection Point).
iii. Fifteen minutes block averaged demand estimates in MW & 10.00 Hours every day
MVAr at each connection / External Interconnection Point
for the day ahead. (96 data items for MW and 96 data items
for MVAr at each connection / External Interconnection
Point.)

C.1.2 ESTIMATES OF LOAD SHEDDING

Item To be Submitted By
i. Details of discrete load blocks that may be shed to comply Soon after connection is
with instructions issued by SLDC when required, from each made.
Connection Point.

C.1.3 YEAR AHEAD OUTAGE PROGRAMME

(For the period April to March)

C.1.3.1 GENERATORS OUTAGE PROGRAMME

Item To be Submitted By

i. Identification of Generating Unit. 1st August each year

ii. MW, which will not be available as a result of outage. 1st August each year
iii. Preferred start date and start time or range of start dates and 1st August each year
start times and period of outage.
iv. If outages are required to meet statutory requirements, then 1st August each year
the latest date by which outage must be taken.
 - 119 -

C.1.3.2 YEAR AHEAD ERLDC'S OUTAGE PROGRAMME

(Affecting Transmission System)
Item To be Submitted By
i. MW, which will not be available as a result of outage from 31st December each year
Imports through external connections.
ii. Start date and start time and period of outage. 31st December each
year

C.1.3.3 YEAR AHEAD CGP'S OUTAGE PROGRAMME

C.1.3.4 YEAR AHEAD DISTRIBUTION COMPANY'S OUTAGE PROGRAMME

Item To be Submitted By
i. MW, which will not be available as a result of outage. 1st August each year
ii. Start date and start time and period of outage. 1st August each year
Item To be Submitted By
i. Loads in MW not available from any Connection Point. 1st August each year
ii. Identification of Connection Point. 1st August each year
iii. Period of suspension of drawl with start date and start time. 1st August each year

C.1.3.5 THE TRANSMISSUION LICENSEE’S OVERALL OUTAGE PROGRAMME

Item To be Submitted By
i. Report on proposed outage programme to ERLDC. 30th November each year
ii. Release of finally agreed outage plan. 1st March each year

C.2 GENERATION SCHEDULING DATA

REFERENCE TO: CHAPTER-6 SCHEDULE AND DESPATCH
Item To be Submitted By
i. Day ahead fifteen minutes block] MW & MVAr availability 10.00 Hours every
(00.00 - 24.00 Hours) of all generator units. day.
ii. Day ahead fifteen minutes block] MW import/export from 10.00 Hours every
CGP's. day.
iii. Status of Generating Unit excitation AVR in service (Yes/No). 10.00 Hours every
day.
iv. Status of Generating Unit speed control system. Governor in 10.00 Hours every
service (Yes/No). day.
v. Spinning reserve capability (MW) 10.00 Hours every
day.
vi. Backing down capability with/without oil support (MW) 10.00 Hours every
day.
vii. Hydro reservoir levels and restrictions 10.00 Hours every
day.
viii. Generating Units hourly summation outputs (MW) 10.00 Hours every
day.
 - 120 -

ix. Day ahead fifteen minutes block MW entitlements from Central 11.00 Hours every
sector generation and Chukha Hydro Power Station from day.
ERLDC.

C.3 CAPABILITY DATA

REFERENCE TO: CHAPTER-5 FREQUENCY AND VOLTAGE MANAGEMENT

Item To be Submitted By
i. Generators shall submit to the SLDC up-to-date On receipt of request by
capability curves for all Generating Units. the SLDC.
ii. CGPs shall submit to the licensee/SLDC net return On receipt of request by
capability that shall be available for export/import from the licensee/SLDC.
Transmission System.

C.4 RESPONSE TO FREQUENCY CHANGE

REFERENCE TO: CHAPTER-5 FREQUENCY AND VOLTAGE MANAGEMENT
i. Primary response in MW at different levels of loads ranging from minimum
generation to registered capacity for frequency changes resulting in fully opening of
governor valve.
ii. Secondary response in MW to frequency changes.

C.5 MONITORING OF GENERATION

REFERENCE TO: CHAPTER-7 - MONITORING OF GENERATION AND DRAWAL OF

POWER STATIONS OF 25 MW FOR DEDICATED LINE (TIE LINE) AND ABOVE 15 MW
FOR NON-DEDICATED (NON-TIE) LINE.

Item To be Submitted By
i. Generators shall provide hourly generation summation to To be submitted by real
SLDC. time basis
ii. CGPs shall provide hourly export/ import MW to SLDC. To be submitted by real
time basis
iii. Logged readings of generators to SLDC. As required
iv. Detailed report of Generating Unit trippings on monthly In the first week of the
basis. succeeding month

C.6 ESSENTIAL AND NON-ESSENTIAL LOAD DATA

REFERENCE TO: CHAPTER-5 CONTINGENCY PLANNING

Item To be Submitted By
i. Schedule of essential and non-essential loads on each As soon as possible after
discrete load block for purposes of load shedding. connection
 - 121 -

APPENDIX- D
D. PROTECTION DATA

REFERENCE TO:
CHAPTER-9 PROTECTION

Item To be Submitted By
i. Generators/CGPs shall submit details of protection As applicable to
requirement and schemes installed by them as referred to in Detailed Planning Data
B.1. Detailed Planning Data under sub-Section "Protection and
Metering".
ii. The licensee shall submit details of protection equipment and As applicable to
schemes installed by them as referred to in B.2. Detailed Detailed Planning Data
System Data, Transmission under sub-Section "Relaying and
Metering" in relation to connection with any User.

APPENDIX- E
E. METERING DATA
REFERENCE TO: CHAPTER-10 METERING

Item To be Submitted By
i. Generators/CGPs shall submit details of metering equipment As applicable to
and schemes installed by them as referred in B.1. Detailed Detailed Planning Data
Planning Data under sub-Section "Protection and Metering".
ii. The transmission licensee shall submit details of metering As applicable to
equipment and schemes installed by them as referred in B.2. Detailed Planning Data
Detailed System Data, Transmission under sub-Section
"Relaying and Metering" in relation to connection with any
User.

CHAPTER-13
PERIODIC REPORT

A weekly report shall be prepared and issued by SLDC to all the Users. The weekly report shall
contain the following.

(a) Frequency profile

(b) Voltage profile
(c) Major outage of Generating Unit
(d) Major outage of transmission line
(e) Grid disturbance
 - 122 -

CHAPTER-14
MISCELLANEOUS
14.1 Issue of Orders and Practice Directions
Subject to the provisions of the Electricity Act, 2003, Indian Electricity Grid Code, and
these Regulations, the Commission may from time to time issue orders and practice
directions with regard to the implementation of these Regulations and procedure to be
followed on various matters, which the Commission has been empowered by these
Regulations to determine and direct, and matters incidental or ancillary thereto.
14.2 Saving of inherent power of the Commission
(i) Subject to the provisions of the Act, Rules and Regulations, the Commission, in
special and extraordinary circumstances by recording the reasons in writing and
in public interest may make such orders as may be necessary to meet the ends of
justice.
(ii) Nothing in these Regulations shall bar the Commission from adopting in
conformity with provisions of the Act, a procedure which is at variance with any
of the provisions of these Regulations, if the Commission, in view of the special
circumstances of a matter or a class of matters, deems it just or expedient for
deciding such matter or class of matters.
(iii) Nothing in these Regulations shall, expressly or impliedly, bar the Commission
dealing with any matter or exercising any power under the Act for which no
Regulations have been framed, and the Commission may deal with such matters,
powers and functions in a manner, as it considers just and appropriate.
14.3 Powers to Remove Difficulties
If any difficulty arises in giving effect to any of the provisions of these Regulations, the
Commission may, by general or special order, do anything not being inconsistent with
the provisions of the Act, Indian Electricity Grid Code, these Regulations, which appears
to it to be necessary or expedient for the purpose of removing the difficulties.
14.4 Power to Amend
The Commission may, at any time, add, vary, alter and modify the provisions of these
Regulations through amendments.
By order of the Commission

(K.L. Panda)
SECRETARY I/C