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RNI No. KARBIL/2001/47147

∞¬Òûª

– IVA

Part–IVA

 

Bengaluru, Wednesda

KARNATAKA

Karnata

Notific

PREAMBLE

The Karnataka Electricity Grid C

Regulatory Commission in exercis

with clause (zp) of sub-section (2)

down the rules, guidelines and st

Intra-State Transmission system

most secure, reliable, economic a

Operation with the Inter-State Tra

per the provisions of the Indian

generation and supply of electricit

NOTIFICATION

In exercise of powers conferred un

of sub-section (2) of Section 181

enabling it in this behalf, the K

following regulations.-

1. Short title, extent and comm

These Regulations shall

(Karnataka Electricity Grid

These Regulations shall co

Karnataka.

(i)

These regulations sha

notified along with KED

1.1Introduction

The Karnataka Power System

STU, SLDC, DISCOMs and

transmission, distribution and

namely:-

(a) Generating stati

(b) Transmission or

ª∞ «Ò∏Â

 

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A ELECTRICITY REGULATORY COMMISSIO

aka Electricity Grid Code (KEGC), 2015

cation No. M/28/14 Dated //-//- 2015

SECTION-1

GENERAL

Code (KEGC), is a Regulation made by the

se of powers under clause (h) of subsection

of Section 181 of the Act. The Karnataka Ele

tandards to be followed by various persons a

to plan, develop, maintain and operate the

and efficient manner, so as to meet the requ

ansmission system of the Southern Regional

Electricity Grid Code while facilitating heal

ty.

nder clause (h) of sub-section (1) of Section 8

1 of the Electricity Act, 2003 (36 of 2003),

Karnataka Electricity Regulatory Commiss

mencement

be called the Karnataka Electricity Re

d Code) Regulations, 2015.

ome into force from the date of publication in

all supersede the Karnataka Electricity Gri

DC which came into effect from 26.01. 2006.

is a conglomeration of a number of agencie

other users. Power system means all a

d supply of electricity and includes one or

ions;

r main transmission lines;

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**12,,,-

e Karnataka Electricity

n (1) of Section 86 read

ectricity Grid Code lays

and participants in the

e power system, in the

uirements of Integrated

Grid/ National Grid as

lthy competition in the

86 read with clause (zp)

, and all other powers

sion hereby makes the

egulatory Commission

n the official Gazette of

id Code (KEGC), 2005

es viz Generators, CTU,

aspects of generation,

more of the following,

(d) Tie-lines;

(e)Load despatch activities;

(f) Mains or distribution mains;

(g) Electric supply-lines;

(h) Overhead lines;

(i) Service lines;

(j) Works;

1.2Objective

The KEGC Covers a single set of technical and commercial rules, encompassing all the Utilities

connected to/or using the intra-State transmission system (In-STS) and provides the following:

Defines the relationship between the various Users of the Intra-State transmission system

(In-STS), State and Area Load Despatch Centers.

Facilitation of the optimal operation of the Intra-State grid.

To ensure that the transmission system within the State is operated in an efficient

and reliable manner.

ii.

To ensure electricity fed into the grid from the generators within and outside the

State reaches to the DISCOMs or the end consumers and facilitates open access

facility to the consumers.

iii.

To maintain the frequency, interruptions and harmonics within the stipulated

limits.

Facilitation of coordinated and optimal maintenance planning of generation and

transmission facilities in the intra-State grid.

Facilitation of development and planning of economic and reliable intra-State grid in

coordination with the National / Regional Grid.

Facilitation of integration of renewable energy sources by specifying the technical and

commercial conditions.

1.3 Scope

The Users namely, STU, SLDC, ALDCs, DISCOMs and Generators are required to abide by the

principles and procedures defined in the KEGC in so far as they apply to that party.

1.4Structure of the KEGC

This KEGC comprises of following chapters:

Section -1

General

SECTION-2

Definitions

SECTION-3

Management of Grid Code and Role of various Organizations

SECTION-4

Planning Criteria for Intra-State Transmission

SECTION-5

Grid Connectivity

SECTION-6

Operation Planning

SECTION-7

Cross Boundary Safety

SECTION-8

Scheduling and Despatching

SECTION-9

Protection and Metering

SECTION-10

Miscellaneous

Issue of orders and practice directions

ANNEXURES

SECTION-2

DEFINITIONS

2. Definitions

(I)

In these Regulations unless the context otherwise requires:

2.1

Act means the Electricity Act, 2003, as amended from time to time;

2.2

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, such as but not limited to active power support for

load following, reactive power support, black start;

2.3

Area Load Despatch Centre (ALDC) means the centre as established by the STU to

carry out the instructions of SLDC for controlling system operation in its jurisdiction

and performing all duties assigned to it as stated in this Karnataka Electricity

Regulatory Commission Grid Code (KEGC);

2.4

Automatic Voltage Regulator (AVR) means a continuously acting automatic

excitation control system to control the voltage of a Generating Unit measured at the

generator terminals;

2.5

Backing Down means reduction of generation by a generating unit on instructions

from SLDC/ SRLDC;

2.6

Beneficiary means a licensee who has a share in an Inter-State Generating Station

(ISGS) and/or Intra-State Generating Station (In-SGS);

2.7

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 Power

Exchange from a specified point of injection to a specified point of drawal for a fixed or

varying quantum of power (MW) for a specified period;

2.8

Black Start Procedure means the procedure to recover the grid from partial or a

total blackout in the State;

2.9

BIS means the Bureau of Indian Standards;

2.10

Bulk Consumer means any Consumer who avails supply at voltage of 33 kV and /or

above;

2.11

Capacitor means an electrical facility provided for generation of reactive power;

2.12

Captive Power 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 co-operative society

or association of persons for generating electricity primarily for use of members of such

co-operative society or association;

2.13

CERC means the Central Electricity Regulatory Commission;

2.14

CEA TheCentral Electricity Authorityof India (CEA) is a statutory organisation

constituted under section 70(1) of theElectricityAct 2003.

2.15

Central Generating Station (CGS) means the generating station owned by the

companies that are owned or controlled by the Central Government;

2.16

Central Transmission Utility (CTU) means any Government Company which the

Central Government may so notify under sub-section (1) of Section 38 of the Act;

2.17

Collective Transaction means a set of transactions discovered in power exchange

through anonymous, simultaneous competitive bidding by buyers and sellers;

2.18

Commission means the Karnataka Electricity Regulatory Commission (K.E.R.C.);

2.19

Connection Agreement means an Agreement between STU, intra-State transmission

licensee(s) other than STU (if any) and any person setting out the terms relating to a

connection to and/or use of the Intra- State Transmission System;

2.20

Connection Point means a point at which a plant (generating station or a substation

or bulk consumer) and associated equipment connects to the Transmission System;

2.21

Connectivity means the state of getting connected to the Intra-State transmission

system by a generating station, including a captive generating plant, a bulk consumer or

Intra- State transmission licensee;

2.22

Control Area means 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;

2.23

Control Person means a person identified as having technical capability and

responsibility for cross boundary safety under Regulation 7 of this Grid Code.

2.24

Demand means the demand of Active Power in MW and Reactive Power in MVAr of

electricity.

2.25

Despatch Schedule means the ex-power plant net MW and MWh output of a

generating station, scheduled to be exported to the Grid from time to time;

2.26

Data Acquisition System (DAS) means a system provided to record the sequence of

operations in real time, of the relays/equipment as well as the measurement of pre-

selected system parameters;

2.27

Disturbance Recorder (DR) means a device provided to record the behavior of the

preselected digital and analog values of the system parameters during an event

(including a few cycles of pre-fault condition);

2.28

Drawal Schedule means the summation of the station-wise ex-power plant drawal

schedules from all ISGS and In-SGS and drawal from / injection to the DISCOMs (State

grid) consequent to long term, medium term and short term open access transactions;

⁴

2.29

Entitlement means a share of a beneficiary (in MW / MWh) in the installed

capacity/output capability of an Inter-State Generating Station (ISGS) and/or Intra-

State Generating Station (In-SGS);

2.30

Entity means the person who is in the control area of SLDC and whose metering and

energy accounting is done within the state;

2.31

Event means an unscheduled or unplanned occurrence on a Grid including faults,

incidents and breakdowns;

2.32

Event Logging Facilities means a device provided to record the chronological

sequence of operation, of the relays and other equipments;

2.33

Ex-Power Plant Schedule means net MW/MWh output of a generating station, after

deducting auxiliary consumption and transformation losses within the generating

station;

2.34

Fault Locator (FL) means a device provided at the end of a transmission line to

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

2.35

Flexible Alternating Current Transmission System (FACTS) means power

electronics based system and other static equipment that provide a control of one or

more AC transmission system parameters to enhance controllability and increase power

transfer capability;

2.36

Force Majeure means any event which is beyond the control of the persons 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 affects the

performance by a person such as the following including but not limited to :-

Acts of God, natural phenomena, floods, droughts, earthquakes and epidemics;

ii.

Enemy acts of any Government domestic or foreign, war declared or undeclared,

hostilities, priorities, quarantines, embargoes;

iii.

Riot or Civil Commotion;

iv.

Grids failure not attributable to the person.

2.37

Forced Outage means an outage of a Generating Unit or a transmission facility due to

a fault or other reasons which has not been planned;

2.38

Generation Schedule means a dispatch schedule of a generating station.

2.39

Good Utility Practices mean 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;

2.40

Governor Droop means 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 restricted or free governor action to change its output from zero to full load;

2.41

Grid Standards means the standards specified by the Authority (CEA) under clause

(d) of the Section 73 of the Act;

2.42

Gaming in relation to these regulations, shall mean an intentional mis-declaration of

declared capacity by any generating station or seller in order to make an undue

commercial gain through Charge for Deviations;

2.43

Independent Power Producer (IPP) means a generating company not owned/

controlled by the Central/State Government;

2.44

Indian Electricity Grid Code (IEGC) means the regulations specified by the CERC in

exercise of powers under clause (h) of subsection (1) of Section 79 read with clause (g) of

sub-section (2) of Section 178 of the Act;

2.45

Indian Standards (IS) Those standards and specifications approved by the Bureau of

Indian Standards(BIS);

2.46

Interconnecting Transformers (ICTs) means Transformers connecting lines of

different voltage;

2.47

Inter-State Generating Station (ISGS) means a Central generating station or other

generating station, in which two or more states have shares or have contracts to buy

power ;

2.48

Inter-State Transmission System (ISTS) includes any system for the conveyance of

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

another State:

(i)

The conveyance of electricity across the territory of an intervening State as well as

conveyance within the State which is incidental to such inter-state transmission of

energy;

⁵

(ii) The transmission of electricity within the territory of the State on a system built,

owned, operated, maintained or controlled by CTU;

2.49

Intra-State Generating station (In-SGS) means a Generating station located within

the geographical area of the State of Karnataka;

2.50

Intra-State Transmission System (In-STS) means a system of Transmission Lines

and substations built, owned, operated and maintained or controlled by the STU or a

transmission licensee for conveyance of electricity within the territory of the State;

2.51

Karnataka Electricity Grid Code (KEGC) means the Regulations specifying the

philosophy and the responsibilities for planning, developing and operation of the

Karnataka Power System;

2.52

Karnataka Electricity Distribution Code (KEDC) or Distribution Code means the

Regulations specifying the philosophy and the responsibilities for planning, developing

and operation of the Distribution System;

2.53

Lean Period refers to that period in a day/Month/Year when the electrical power

demand is low;

2.54

Licensee means a person who has been granted a licence under Section 14 of the Act;

2.55

Light Load means the simultaneous minimum demand of the system occurring

under specific time duration (e.g. annual, monthly, daily etc);

2.56

Long term Access means the right to use the intra-State transmission and

distribution system as defined in the KERC (Open Access) Regulations, 2004, as

amended from time to time;

2.57

Long-term customer means a person who has been granted long-term access in the

State;

2.58

Main Protection means the protection equipment or system expected to have priority

in initiating either a fault clearance or an action to terminate an abnormal condition in

the power system;

2.59

Maximum Continuous Rating (MCR) means the maximum continuous output in MW

at the generator terminals guaranteed by the manufacturer at rated parameters;

2.60

Medium-term Open Access means the right to use intra- State transmission and

distribution system from any generating station for a period exceeding three months but

less than three years.

2.61

Medium-term customer means a person who has been granted a medium-term open

access;

2.62

National Grid means the entire inter-connected electric power network of the country;

2.63

Net Drawal Schedule means the drawal schedule of a DISCOM after deducting the

apportioned transmission losses (estimated);

2.64

NLDC means the National Load Despatch Centre established under sub-section (1) of

Section 26 of the Act;

2.65

Open Access means the non-discriminatory provision for the use of transmission lines

or distribution system or associated facility with such lines or system by any licensee or

consumer or a person engaged in generation in accordance with the regulations specified

by the Commission;

2.66

Operation means a scheduled or planned action relating to the operation of a System;

2.67

Operation Coordination Sub-Committee (OCC) means a sub-committee of RPC with

members from all the regional entities which decide the operational aspects of the

Regional Grid;

2.68

Operating range means the operating range of frequency and voltage as specified

under the Operating Code;

2.69

Outage means a total or partial reduction in availability due to repair and

maintenance of the transmission or distribution or generation facility or defects in the

auxiliary system;

2.70

Partial Grid Disturbances means a shutdown of part of the system, resulting in

failure of power supply to that part of the system;

2.71

Peak Load means the simultaneous maximum demand of the system occurring

under specific time duration (e.g. annual, monthly, daily etc);

2.72

Power grid means the Power Grid Corporation of India Limited which has been

notified as CTU;

2.73

Power Exchange means the power exchange which has been granted registration in

accordance with CERC (Power Market Regulations), 2010 as amended from time to time;

⁶

2.74

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;

2.75

Regional Power Committee (RPC) means a Committee established by resolution by

the Central Government for a specific region for facilitating the integrated operation of

the power systems in that region;

2.76

Regional Energy Account (REA) means a regional energy account prepared on

monthly basis by the RPC Secretariat for the billing and settlement of Capacity Charge,

Energy Charge and Transmission charges;

2.77

Regional Grid means the entire synchronously connected electric power network of

the concerned Region;

2.78

Regional Load Despatch Centre (RLDC) means the Centre established under sub-

section (1) of Section 27 of the Act;

2.79

Short-term Open Access means open access for a period up to three months;

2.80

Spinning Reserve means 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;

2.81

Standing Committee for Transmission Planning means a Committee constituted by

the CEA to discuss, review and finalize the proposals for expansion or modification in

the ISTS and associated intra-state systems;

2.82

State Load Despatch Centre (SLDC) means the Centre established under subsection

(1) of Section 31 of the Act;

2.83

State Transmission Utility (STU) means the Government Company specified as such

by the State Government under sub-section (1) of Section 39 of the Act;

2.84

Static VAR Compensator (SVC) means an electrical facility designed for the purpose

of dynamically generating or absorbing Reactive Power;

2.85

Supervisory Control and Data Acquisition (SCADA) means the communication links

and data processing systems which provide information to enable implementation of

requisite supervisory and control access.

2.86

Surge Impedance Loading means the unity power factor load over a resistive line

such that series reactive loss (I

2X) along the line is equal to shunt capacitive gain (V

2Y);

2.87

Switching over-voltages means over-voltages generated during switching of lines,

transformers and reactors etc., having wave fronts 250/2500 micro second;

2.88

System Stability means a stable power system is one in which synchronous

machines, when perturbed, will either return to their original state if there is no change

in exchange of power or will acquire new state asymptotically without losing

synchronism. Usually the perturbation causes a transient that is oscillatory in nature,

but if the system is stable the oscillations will be damped;

2.89

Temporary over-voltages means the power frequency over-voltages produced in a

power system due to sudden load rejection, single phase to ground faults, etc.,;

2.90

Time Block means block of 15 minutes each for which Special Energy Meters record

values of specified electrical parameters with first time block starting at 00.00 Hrs;

2.91

Transmission Licence means a Licence granted under Section 14 of the Electricity

Act, 2003 to transmit electricity;

2.92

Transmission Planning Criteria means the policy, standards and guidelines issued

by the CEA for the planning and design of the Transmission system;

2.93

Transmission Reliability Margin (TRM) means 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;

⁷

2.94

‘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 drawal minus its total

scheduled drawal.

2.95

User means a person such as a Generating Company including Captive Generating

Plant or Transmission Licensee (other than the Central Transmission Utility and State

Transmission utility) or Distribution Licensee or Bulk Consumer, whose electrical plant

is connected to the In-STS at a voltage level 33 kV and above.

(II) Words and expressions used and not defined herein these Regulations but defined in the Act

or any Regulations made under the act shall have the meaning assigned to them under the

Act or Regulations.

SECTION-3

MANAGEMENT OF GRID CODE AND ROLE OF VARIOUS ORGANIZATIONS

3.1 INTRODUCTION:

3.1.1 The Karnataka Power Transmission Corporation Limited (KPTCL), which is the State

Transmission Utility (STU), that also holds the Transmission Licence required to implement

and ensure compliance with the Karnataka Electricity Grid Code (KEGC), herein after called

GRID CODE, and to carry out periodic review and seek for amendments of the same. A Review

Panel shall be constituted by the STU, as required in this Section, comprising of the

representatives of the Users of the Transmission System.

3.1.2 No change in this GRID CODE, however small or big, shall be made without being deliberated

upon and agreed to by the GRID CODE Review Panel and approved by the Commission.

3.1.3 The STU will be responsible for managing and implementing the GRID CODE for discharging

its obligations with the Users. The STU will not be, however, required to incur any

expenditure on account of travel etc., of any other member of the panel other than its own

representative.

3.2 OBJECTIVE:

3.2.1 The objective of this Section is to define the method of management of GRID CODE

documents, implementing any changes/modifications required and the responsibilities of the

constituents (Users) to effect the change.

3.3 GRID CODE REVIEW PANEL:

3.3.1 The Chairperson of the Grid Code Review panel shall be an Engineer of the STU not below the

rank of Chief Engineer (Electricity). The Member Secretary of the Panel shall also be

nominated by the STU. The Panel shall consist of the following members on the

recommendations of the heads of the respective organizations:

Chief Engineer of the State Load Despatch Centre (SLDC)

One Chief Engineer or General Manager of the Karnataka Power Corporation Limited

(KPCL).

One senior representative from the Southern Regional Power Committee (SRPC).

One representative at senior executive level from the National Thermal Power

Corporation Limited (NTPC).

One representative at senior executive level from the Power Grid Corporation of India

Limited (PGCIL).

One representative at senior executive level from the Southern Regional Load

Despatch Centre (SRLDC).

One representative at senior executive level from each Distribution & Retail Supply

Licensee.

One representative at senior executive level from each of the IPPs feeding the

Karnataka State Power Grid and feeding not less than 50 MW.

One representative from all the IPPs and CPPs of small Power Plants of less than 50

MW capacity on rotation basis.

3.3.2 Any other member can be co-opted as a member of the Panel when directed by the

Commission.

3.3.3 The functioning of the Panel shall be coordinated by the STU. The Member Secretary

nominated by the STU shall be the convener.

3.3.4 The STU shall inform all the Users, the names and addresses of the Panel Chairperson and

the Member Secretary at least seven days before the first meeting of the Panel. Any

subsequent changes shall also be informed to all the users by the STU. Similarly, each User

shall inform the names and designations of their representatives to the Member Secretary of

the Panel, at least three days before the first Panel meeting, and shall also inform the

Member Secretary in writing regarding any subsequent changes.

⁸

3.4 FUNCTIONS OF THE REVIEW PANEL:

3.4.1 The functions of the Review Panel are as follows:

(a) Maintenance of the GRID CODE and its working under continuous scrutiny and review.

(b) Consideration of all requests for review made by any User and publication of their

recommendations for changes to the GRID CODE together with reasons for such

changes.

(d) Examination of the problems raised by any User.

(e) Ensuring that the changes/modifications proposed in the GRID CODE are consistent and

compatible with Indian Electricity Grid Code (IEGC).

(f) Analysis of major grid disturbances soon after their occurrence.

(g) Review the progress of the committee formed for coordination and monitoring of

protection functions for the entire grid.

The Review Panel may hold as much number of meetings as required subject to the condition that at

least one meeting shall be held in every three months. Sub-meetings may be held by the STU with

the User to discuss individual requirements and with groups of Users to prepare proposals for Panel

meeting for taking a decision.

3.5 REVIEW AND REVISIONS:

3.5.1 The Users seeking any amendment to the Grid Code shall send written requests to the

Member Secretary of the panel with a copy to the Commission. If the request is sent to the

Commission directly, the same shall be forwarded to the STU. The STU shall, in consultation

with the Distribution & Retail Supply Licensees, Generating Companies, Central

Transmission Utility (CTU), SRLDC and such other persons as the Commission may direct,

review the GRID CODE provisions after proper examination.

3.5.2 All the comments received from the members of the Panel shall be scrutinized and compiled

by the STU. These comments, along with comments of STU shall be sent to all the members

for their response in favour or otherwise, for the proposed change/modification. If necessary,

the STU shall convene a meeting of the Panel for deliberations. The Member Secretary shall

present all the proposed revisions of the Grid Code to the Panel for its consideration.

3.5.3 Based on the response received, the STU shall finalize its recommendation regarding the

proposed modification / amendment and submit the same along with all the related

correspondence to the Commission for approval. The KERC shall approve the same after

holding a Public Hearing.

3.5.4 The STU shall send the following reports to the Commission at the conclusion of each review

meeting of the Panel:

Reports on the outcome of such review.

ii.

Any proposed revision to the Grid Code as the STU reasonably thinks necessary for

achievement of the objectives referred to in the relevant paragraphs.

iii.

All written representations and objections submitted by the Users at the time of review.

3.5.7 The STU shall keep copies of the Grid Code with the latest amendments and shall make it

available at a reasonable cost to any person requiring it.

3.6 Non-Compliance

i. If any user fails to comply with any provision of the Grid Code the user shall inform the

SLDC and Grid Code Review Panel without delay the reasons for its non-compliance and

shall remedy its non-compliance promptly.

ii. SLDC shall bring the non compliance to the notice of the Commission.

(iii)

Consistent failure to comply with the Grid Code provisions may lead to disconnection

of the users plant and / or facilities.

3.7 Code Responsibilities

i. In discharging its duties under the Grid Code, STU shall rely on information which shall

be furnished by the Users.

ii. STU shall not be held responsible for any consequences that arise from its

reasonable and prudent actions on the basis of such information.

3.8 Confidentiality

STU shall not, other than as required by the Grid Code, disclose such information to any

person other than Central or State Government and the Commission without the prior

written consent of the provider of the information.

3.9 Dispute Settlement Procedures

3.9.1. In the event of any dispute regarding interpretation of any part/section of the Grid Code

provision between any User and STU, the matter may be referred to the Commission for

its decision. The Commissions decision shall be final and binding.

⁹

3.9.2. In the event of any conflict between any provision of the Grid Code and any contract or

agreement between STU and Users, the provision(s) of the Grid Code shall prevail.

3.10 Directives

Any directions issued by the State Government under section 37 of the Electricity Act

2003, shall be promptly informed to the Commission and all Users by STU.

ii.

Any directives issued by the Commission from time to time shall be complied with by

STU and all Users.

3.11 Compatibility with Indian Electricity Grid Code

This Grid Code is consistent/compatible with the IEGC. However, in matters relating to inter-

State transmission, if any provision of the State Electricity Grid Code is inconsistent with the

provisions of the IEGC, then the provisions of IEGC as notified by CERC shall prevail.

3.12 Role of various Organizations

3.12.1 Role of SLDC

In accordance with Section 32 of the Electricity Act, 2003, the State Load Despatch Centre

(SLDC) shall have the following functions:

(i)

The State Load Despatch Centre shall be the apex body to ensure integrated operation of

the power system in the State.

(ii) The State Load Despatch Centre shall ,

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 the State;

monitor grid operations;

keep accounts of the quantity of electricity transmitted through the State Grid;

exercise supervision and control over the intra-State transmission system; and

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 Grid Code.

(iii) The following are contemplated as exclusive functions of SLDC:

Data acquisition and supervisory control, state estimation, security analysis.

System Operation and control of the state grid covering contingency analysis,

contingency ranking and operational plan on real time basis by conducting operational

load flow studies using real time data.

Furnishing feedback to STU on planning, on the issues of transmission strengthening,

system protection requirement, congestion /bottlenecks.

Responsible for conducting demand forecast within the State, LGBR analysis, outage

planning coordination & operation and analysis of the grid security.

Scheduling/ Re-scheduling of Generation.

System restoration following grid disturbances.

Metering and data collection of the energy transaction within the State Grid.

Compiling and furnishing data pertaining to system operation.

Operation of state Deviation Settlement Mechanism (DSM) pool account, state reactive

energy account and other functions as directed by the Commission.

Display transmission line loadings, critical lines with contingent conditions and inform in

writing to the STU on the transmission bottlenecks for remedial measures with a copy to

the Commission.

Display of power map with power flow in the critical lines.

(iv)

In accordance with Section 33 of the Electricity Act, 2003, the State Load Despatch Centre

in the State may give such directions and exercise such supervision and control as may be

required for ensuring the integrated grid operations and for achieving the maximum

economy and efficiency in the operation of power system in the State. Every licensee,

generating company, generating station, sub-station and any other person connected with

the operation of the power system shall comply with the directions issued by the State

Load Despatch Centre under subsection (1) of Section 33 of the Electricity Act, 2003. The

State Load Despatch Centre shall comply with the directions of the Regional Load Despatch

Centre.

(v)

In case of inter-state bilateral and collective short-term open access transactions having a

state utility or an intra-state entity as a buyer or a seller, SLDC shall accord concurrence

or no objection or a prior standing clearance, as the case may be, in accordance with the

Central Electricity Regulatory Commission (Open Access in Inter-State Transmission)

Regulations, 2008, amended from time to time.

3.12.2 Role of ALDC :

The Area Load Despatch centre shall:

comply with the directions of SLDC.

coordinate in outage management.

assist SLDC to ensure integrated operation of the power system in the State grid.

assist SLDC for monitoring the grid operations within its control area.

assist SLDC for supervision and control over the intra-State Transmission system, within

its area and be responsible for carrying out real time operation.

keep accounts of the quantity of electricity transmitted through its control area.

3.12.3 Role of STU:

Section 39 of the Electricity Act, 2003, outlines that the functions of the State Transmission

Utility (STU) shall be,-

to undertake transmission of electricity through intra-State transmission system and

inter State transmission under bilateral agreements;

to discharge all functions of planning and co-ordination relating to intra-State

transmission system with,

i) Central Transmission Utility;

ii) State Governments;

iii) Generating Companies;

iv) Regional Power Committees;

v) Central Electricity Authority (CEA);

vi) Licensees;

vii) Any other person notified by the State in this behalf;

to ensure development of an efficient, congestion free, reliable, coordinated and

economical system of intra-State transmission lines for smooth flow of electricity from a

generating station to the load centers;

to provide non-discriminatory open access to its transmission system for use by,

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 State 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 State Commission .

3.14

UNTIL A GOVERNMENT COMPANY OR ANY AUTHORITY OR CORPORATION IS NOTIFIED

BY THE STATE GOVERNMENT, THE STATE TRANSMISSION UTILITY SHALL OPERATE

THE STATE LOAD DESPATCH CENTRE.

SECTION 4

PLANNING CRITERIA FOR INTRA-STATE TRANSMISSION

This section specifies the technical and design criteria and procedures to be adopted by STU for the

planning and development of the Transmission System within its boundary.

4.1 Introduction

In accordance with Section 39(2)(b) of the Electricity Act, 2003, the State Transmission Utility

(STU) shall discharge all functions of planning and coordination relating to intra-State

transmission system with Central Transmission Utility, State Governments, Generating

Companies, Regional Power Committees, Central Electricity Authority (CEA), licensees and

any other person notified by the State Government in this behalf.

ii.

In accordance with Section 39(2) (d) of the Electricity Act, 2003, the State Transmission Utility

(STU) shall inter-alia provide non-discriminatory open access to its transmission system for

use by

(a) Any licensee or generating company on payment of the transmission charges; or

(b) any consumer as and when such open access is provided by the State Commission under

sub-section (2) of Section 42, on payment of the transmission charges and a surcharge

thereon, as may be specified by the State Commission.

iii.

In accordance with Section 40 of the Electricity Act, 2003, the STU shall build, maintain and

operate an efficient, coordinated and economical intra- State transmission system and inter-

alia provide non-discriminatory open access to its transmission system for use by

(a) any licensee or generating company on payment of the transmission charges; or

(b) any consumer as and when such open access is provided by the State Commission under

sub-Section (2) of Section 42, on payment of the transmission charges and a surcharge

thereon, as may be specified by the State Commission.

iv.

In accordance with Section 3 (4) of the Electricity Act, 2003, CEA shall inter-alia prepare

a National Electricity Plan in accordance with the National Electricity Policy and notify

such plan once in five (5) years. In accordance with Section 3 (5) of the Electricity Act,

2003, CEA may review or revise the National Electricity Plan in accordance with the

National Electricity Policy.

In accordance with Section 73 (a) of the Electricity Act, 2003, CEA is responsible to

advise the Central Government on the matters relating to the National Electricity Policy,

formulate short-term and perspective plans for development of the electricity system and

co-ordinate the activities of planning agencies for optimal utilization of resources to sub -

serve the interests of the national economy and to provide reliable and affordable

electricity for all consumers.

vi.

The Planning Section specifies the philosophy and procedures to be applied in planning

of the Intra-State Transmission System (In-STS) and the links to Regional Grid.

4.2 Objective

The objective of Planning criteria are as follows:

(a) To specify the principles, procedures and criteria which shall be used in the planning and

development of the Intra-State Transmission System (In-STS) and the links to Regional

Grid.

(b) To promote co-ordination amongst all Users, STU, CTU, RLDC, CEA in any proposed

planning and development of the In-STS.

RPC, and CEA for planning and development of the In-STS gird.

4.3 Scope

The Planning Criteria applies to STU, all users connected to and/or using and involved in developing

the In-STS.

4.4 Perspective Plan

4.4.1 The Transmission Licensee shall file for Commissions approval a Perspective Plan on 1st

April of the year preceding the first year of the Control period. The Perspective Plan shall be

for a period of five years coinciding with the 5 year plan period of the Country and thereafter

shall be for a period of 5 years in future. The Perspective Plan for the Control Period shall

inter alia contain the consolidated load forecast submitted by all the Distribution

Licensees, Generation Plan and a Capital investment Plan. This shall be in accordance with

the Practice Directions issued by the Commission in respect of Capital Investment programme

and also consistent with the Regulations on Load Forecast. Further, the Transmission

Licensee shall also revise the Perspective Plan every year taking into consideration of the

changes occurred during the previous year and submit to the Commission as a Rolling Plan.

Load forecasting shall be carried out as per the KERC (Load Forecast) Regulations, 2009, not-

inconsistent with the above Regulations the following may be adhered to. The Load

forecasting shall be the primary responsibility of the Distribution Licensee within his area of

supply. The Distribution Licensees shall determine the peak load and energy forecasts of their

areas for each of the succeeding years and submit the same annually by 31st January, to

STU. These shall include the details of demand forecasts, data methodology and assumptions

on which the forecasts are based. The peak load and energy forecasts shall be made for the

overall area of supply. The annual peak load forecast shall also be made for each Connection

Point / Interface Point with the Transmission System. The peak load requirement at each

Connection Point / Interface Point will essentially ensure that the STU may determine the

corrective measures to be taken to maintain the capacity adequacy in the Transmission

System up to the Connection Point /Interface Point. This will facilitate the Transmission

Licensee to develop the compatible Transmission System. However, if the Distribution

Licensee receives power at a number of Connection Points / Interface Points in a compact

area, which are interconnected in a ring, then such a Distribution Licensee shall forward the

overall long term demand forecast for the overall area of supply as well as at each Connection

Point / Interface Point with the variation or tolerance, as mutually discussed and agreed upon

with the STU. These forecasts shall be updated annually and also whenever major changes

are made in the existing system. Wherever these forecasts take into consideration demands

for power exceeding 5 MW by a single consumer, the Distribution Licensee shall personally

satisfy himself regarding the materialisation of such a demand.

4.4.2 The STU shall also review the methodology and assumptions used by the Distribution

Licensees in making the load forecasts, in consultation with them. The resulting overall

forecast will form the basis of planning for expansion of Transmission System, which will be

carried out by STU. To maintain the reliability of the interconnected regional power systems,

all participants must comply with the planning criteria/guidelines of CEA as updated from

time to time.

4.4.3 The STU shall forecast the demand for power within the area of supply for each of the

succeeding years and provide to the Commission, the details of demand forecasts, data,

methodology and assumptions, on which the forecasts are based. Based on these forecasts

and in coordination with the various agencies identified under section 39 (2) (b) of the

Electricity Act 2003, STU shall be responsible to prepare and submit a long- term perspective

plan to the Commission for the compatible intra-State transmission system expansion to meet

the future demand. The planning shall be in conformity with the national perspective for

Power Generation and Transmission Plan prepared by the CEA. This compatible intra-State

transmission plan shall also include provision for reactive compensation needed for the

Transmission System.

4.4.4 The STU shall be responsible for integrating the load forecasts submitted by each of the

Distribution Licensees and determining the five-year load forecast on long-term perspective

basis load forecasts for the State. For determining the requirements for the entire State, an

appropriate diversity factor from the data available for the previous years shall have to be

chosen. STU shall satisfy itself regarding the probability of materialisation of bulk loads of

consumers with demands above 5 MW in consultation with the Distribution Licensees

concerned. The STU shall extend full support to CTU to finalise the annual planning

corresponding to a five-year forward term for identification of a major inter-State

Transmission System including inter-regional schemes, which shall fit in with the long-term

plan developed by CEA.

4.4.5 The STU shall furnish the requisite planning data to CTU by 31st March every year, to enable

CTU to formulate and finalise the plan by 30th September each year, for the next five years.

4.5 Planning Philosophy:

(a) CEA would formulate Perspective Transmission Plan for inter-State transmission system

and STU would formulate perspective plan for 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 the

time of the day variations. In formulating perspective transmission plan, the

transmission requirement for evacuating power from renewable energy sources would

also be taken care of. The transmission system required for open access would also be

taken into account in accordance with National Electricity Policy so that congestion in

system operation is minimized.

(b) The STU shall carry out planning process from time to time as per the requirement for

identification of intra-State transmission system including transmission system

associated with Generation Projects, strengthening of intra-State transmission system to

absorb / evacuate power from the ISTS in coordination with CTU to optimize the

utilization of the Integrated Transmission network. While planning schemes, the following

shall be considered in addition to the data of authenticated nature collected from and in

consultation with users by the STU:

Perspective plan formulated by CEA.

ii.

Electric Power Survey of India published by the CEA.

iii.

Transmission Planning Criteria and guidelines issued by the CEA.

iv.

Operational feedback from RPCs.

Operational feedback from RLDC/SLDC.

vi.

Central Electricity Regulatory Commission (Grant of Connectivity, Long-term

Access and Medium-term Open Access in inter-State Transmission and related

matters) Regulations, 2009, amended from time to time.

vii.

Renewable energy capacity addition plan issued by the Ministry of New and

Renewable Energy Sources (MNRES), Govt. of India and the State Agency

(KREDL).

viii.

Feedback from CTU on the LTOA granted to ISGS, IPPs and bulk consumers.

system strengthening schemes need of which may arise to overcome the constraints in

power transfer and to improve the overall performance of the grid.

(d) All Users, CTU, In-SGS and Karnataka Renewable Energy Development Limited (KREDL)

and Users shall supply to the STU, the desired planning data from time to time to enable

them to formulate and finalize its plan.

(e) As voltage management plays an important role in intra-State transmission of energy,

special attention shall be accorded, by STU and Users for adequate compensation for

active and reactive power management considering various technological options such as

Static VAr Compensators (SVC etc).

(f)

In case Long Term access Applications require any strengthening in the intra-State

transmission system to absorb/evacuate power within the State, the applicant shall

coordinate with the STU. STU shall augment the intra-State transmission system in a

reasonable time to facilitate absorption / evacuation.

(g) Based on plans prepared by the CTU, STU shall have to plan their systems to further

evacuate power from ISTS and to optimize the use of the integrated Transmission

network.

(h) The inter-State Transmission system and associated intra-State transmission system are

complementary and inter dependent and planning of one affects the others planning and

performances. Therefore, the associated intra-State transmission system shall also be

discussed and reviewed before implementation during the discussion for finalizing the

ISTS proposal.

4.6 Planning Criteria:

4.6.1 General Philosophy:

The Central Electricity Authority is responsible for preparation of perspective generation and

transmission plans and for coordinating the activities of planning agencies as provided under

Section 73(a) of the Electricity Act 2003. The Central Transmission Utility (CTU) is responsible

for development of an efficient and coordinated inter-State transmission system (ISTS).

Similarly, the State Transmission Utility (STU) is responsible for development of an efficient

and coordinated intra-State transmission system (In-STS). The ISTS and In-STS are

interconnected and together constitute the electricity grid. It is, therefore, imperative that there

should be a uniform approach to transmission planning for developing a reliable National

transmission system.

The planning criteria detailed herein are primarily meant for planning of Intra-State

Transmission System (In-STS) down to 66kV level, including the dedicated transmission

lines.

4.6.2 Applicability

This planning criteria shall be applicable from the date this Grid Code is published in the

Gazette.

This criteria shall be used for all new transmission systems planned after the above date.

The existing and already planned In-STS may be reviewed with respect to the provisions

of this planning criteria. Wherever required and possible, additional system shall be

planned to strengthen the system to meet the revised criteria. Till implementation of the

additional system, suitable defense mechanisms should be put into place.

4.6.3 Planning Philosophy and General Guidelines

The long term applicants seeking transmission service are required to pose their end-to-

end requirements well in advance, considering time required for implementation of the

transmission project, to the STU so as to make-available the requisite transmission

capacity and minimise situations of congestion and stranded assets.

The transmission customers are also required to provide a basis for their transmission

requirement such as size and completion schedule of their generation facility, demand

based on EPS and their commitment to bear transmission service charges.

Planning of transmission system for evacuation of power from hydro projects shall be

done river basin wise considering the identified generation projects and their power

potential.

In case of highly constrained areas like congested urban / semi-urban area, very difficult

terrain etc., the transmission corridor may be planned by taking long term perspective of

optimizing the right-of-way and cost. This may be done by adopting higher voltage levels

for final system and operating one level below in the initial stage, or by using multi-

circuit towers for stringing circuits in the future, or using new technology such as HVDC,

GIS, GIL (Gas Iinsulated Lines), Monopoles, HV UG cables and HTLS conductors etc.

In accordance with Section 39 of the Electricity Act, the STU shall act as the nodal

agency for In-STS planning in coordination with distribution licensees and intra-State

generators connected/to be connected in the State grid. The STU shall be the single point

contact for the purpose of In-STS planning and shall be responsible on behalf of all the

intra-State entities, for evacuation of power from their States generating stations,

meeting requirements of DISCOMs and drawing power from ISTS commensurate with the

ISTS Plan.

Normally, the various intra-State entities shall be supplied power through the intra-State

network. Only under exceptional circumstances, the load serving intra-State entity may

be allowed direct inter-connection with ISTS on recommendation of STU provided that

such an entity would continue as intra-State entity for the purpose of all jurisdictional

matters including energy accounting. Under such situation, this direct interconnection

may also be used by other intra-State entity(s).

Further, State Transmission Utilities (STUs) shall coordinate with urban planning

agencies, Special Economic Zone (SEZ) developers, and industrial developers etc., to keep

adequate provision for transmission corridor and land for new substations for their long

term requirements.

The system parameters and loading of system elements shall remain within prescribed

limits. The adequacy of the transmission system should be tested for different feasible

load-generation scenarios as detailed subsequently in this document.

The system shall be planned to operate within permissible limits both under normal as

well as after more probable credible contingency as detailed in subsequent paragraphs of

this Grid Code. However, the system may experience extreme contingencies which are

rare, and the system may not be planned for such rare contingencies. To ensure security

of the grid, the extreme/rare but credible contingencies should be identified from time to

time and suitable defense mechanism, such as - load shedding, generation rescheduling,

islanding, system protection schemes, etc., may be worked out to mitigate their adverse

impact.

The planned transmission capacity would be finite and there are bound to be congestions

if electricity is sought to be transmitted in quantum and direction not previously

planned.

The following options may be considered for planning of the transmission network. The

choice shall be based on cost, reliability, right-of way requirements, transmission losses,

down time (in case of up-gradation and re-conductoring options) etc.,

Addition of new transmission lines/ substations to avoid overloading of existing

system including adoption of next higher voltage.

ii.

Application of FACTS devices namely, Series Capacitors and phase-shifting

transformers in existing and new transmission systems to increase power transfer

capability.

iii.

Up-gradation of the existing AC transmission lines to higher voltage using same

right-of-way.

iv.

Re-conductoring of the existing AC transmission line with higher ampacity

conductors.

Use of multi-voltage level and multi-circuit transmission lines.

vi.

Use of narrow base towers and pole type towers in semi-urban / urban areas

keeping in view cost and right-of-way optimization.

vii.

Use of HVDC transmission both conventional and voltage source convertor

(VSC) based.

viii.

Use of GIS / Hybrid switchgear (for urban, coastal, polluted areas etc) �se of

EHV cables and any other appropriate upcoming technologies.

Critical loads such as - railways, metro rail, airports, refineries, underground mines,

steel plants, smelter plants, hospitals etc., shall plan their interconnection with the grid,

with 100% redundancy and as far as possible from two different sources of supply, in

coordination with the concerned STU.

Appropriate communication system for the new sub-stations and generating stations may

be planned by the STU and implemented by licensees as well as generation developers so

that the same is ready at the time of commissioning.

4.6.4 Criteria for steady-State and transient-State behavior

General principles

The transmission system shall be planned considering the following general principles:

In normal operation (N-0) of the grid, with all the elements to be available in service, it

is required that all the system parameters like voltages, loadings, frequency should

remain within permissible normal limits.

The grid may however be subjected to disturbances and it is required that loss of any one

element (N-1 or single contingency condition), all the system parameters like voltages,

loadings, frequency shall be within permissible normal limits.

However, after suffering one contingency, grid is still vulnerable to experience second

contingency, though less probable (N-1-1), wherein some of the equipment may be

loaded up to their emergency limits. To bring the system parameters back within their

normal limits, load shedding/re-scheduling of generation may have to be applied either

manually or through automatic system protection schemes (SPS). Such measures shall

generally be applied within one and a half hour (1) after the disturbance.

ii) Permissible normal and emergency limits

Normal thermal ratings and normal voltage limits represent equipment limits that can be

sustained on continuous basis. Emergency thermal ratings and emergency voltage limits

represent equipment limits that can be tolerated for a relatively short time which may be

one hour to two hour depending on design of the equipment. The normal and emergency

ratings to be used in this context are given below:

(i)

The loading limit for a transmission line shall be its thermal loading limit. The

thermal loading limit of a line is determined by design parameters based on ambient

temperature, maximum permissible conductor temperature, wind speed, solar

radiation, absorption coefficient, emissivity coefficient etc. In India, all the above

factors and more particularly ambient temperatures in various parts of the country

are different and vary considerably during various seasons of the year.

However, during planning, the ambient temperature and other factors are assumed to

be fixed, thereby permitting margins during operation. Generally, the ambient

temperature may be taken as 45

o Celsius; however, in some places like hilly areas

where ambient temperatures are less, the actuals may be taken. The maximum

permissible thermal line loadings for different types of line configurations, employing

various types of conductors are as per CEA Planning Criteria 2013.

(ii) Design of transmission lines with various types of conductors should be based on

conductor temperature limit, right-of-way optimization, losses in the line, cost and

reliability considerations etc.

(iii) The loading limit for an inter-connecting transformer (ICT) shall be its name plate

rating.

(iv) The emergency thermal limits for the purpose of planning shall be 110% of the

normal thermal limits.

Voltage limits

(i)

The steady-state voltage limits are given below. However, at the planning stage a

margin as specified at Paragraph: 4.6.5 (II) H (d) may be kept in the voltage limits.

Voltage( kV rms)

Normal rating

Emergency rating

Nominal

Maximum

Minimum

Maximum

Minimum

765

800

728

800

713

400

420

380

420

372

220

245

198

245

194

110

121

123

72.5

(ii) Temporary over voltage limits due to sudden load rejection:

i) 800kV class system 1.4 p.u. peak phase to neutral (653 kV = 1 p.u.)

ii) 420kV class system 1.5 p.u. peak phase to neutral (343 kV = 1 p.u.)

iii) 245kV class system 1.8 p.u. peak phase to neutral (200 kV = 1 p.u.)

iv) 145kV class system 1.8 p.u. peak phase to neutral (118 kV = 1 p.u.)

v) 123kV class system 1.8 p.u. peak phase to neutral (100 kV = 1 p.u.)

vi) 72.5kV class system 1.9 p.u. peak phase to neutral (59 kV = 1 p.u.)

(iii) Switching over voltage limits

i) 800kV class system 1.9 p.u. peak phase to neutral (653 kV = 1 p.u.)

ii) 420kV class system 2.5 p.u. peak phase to neutral (343 kV = 1 p.u.)

Reliability criteria

(i)

Criteria for system with no contingency (N-0) the system shall be tested for all the

load-generation scenarios as given in this document at Paragraph: 4.6.5 (II) D to F.

(ii) For the planning purpose all the equipment shall remain within their normal thermal

loadings and voltage ratings.

(iii) The angular separation between adjacent nodes or substations (buses) shall not

exceed 30 degree.

Criteria for single contingency (N-1)

Steady-state :

(a)

All the equipment in the transmission system shall remain within their normal

thermal and voltage ratings after a disturbance involving loss of any one of the

following elements (called single contingency or N-1 condition), but without load

shedding / rescheduling of generation:

Outage of a 110 kV or 66 kV single circuit,

Outage of a 220kV or 230kV single circuit,

Outage of a 400kV single circuit,

Outage of a 400kV single circuit with fixed series capacitor (FSC),

Outage of an Inter-Connecting Transformer (ICT),

Outage of a 765kV single circuit,

Outage of one pole of HVDC bipole.

(b)

The angular separation between adjacent buses under (N-1) conditions shall not

exceed 30 degree.

Transient-state :

Usually, perturbation causes a transient that is oscillatory in nature, but if the

system is stable the oscillations will be damped. The system is said to be stable in

which synchronous machines, when perturbed, will either return to their original

state if there is no change in exchange of power or will acquire new state

asymptotically without losing synchronism. The transmission system shall be stable

after it is subjected to one of the following disturbances:

(a) The system shall be able to survive a permanent three phase to ground fault on a

765kV line close to the bus to be cleared in 100 milliseconds.

(b) The system shall be able to survive a permanent single phase to ground fault on

a 765kV line close to the bus. Accordingly, single pole opening (100 ms) of the

faulted phase and unsuccessful re-closure (dead time 1 second) followed by 3-pole

opening (100 ms) of the faulted line shall be considered.

400kV line close to the bus to be cleared in 100 ms.

(d) The system shall be able to survive a permanent single phase to ground fault on a

400kV line close to the bus. Accordingly, single pole opening (100 ms) of the

faulted phase and unsuccessful re-closure (dead time 1 second) followed by 3-pole

opening (100 ms) of the faulted line shall be considered.

(e) In case of 220kV / 110 /66kV networks, the system shall be able to survive a

permanent three phase fault on one circuit, close to a bus, with a fault clearing

time of 100 ms (5 cycles) assuming 3-pole opening.

(f)

The system shall be able to survive a fault in HVDC convertor station, resulting in

permanent outage of one of the poles of HVDC Bipole.

(g) Contingency of loss of generation: The system shall remain stable under the

contingency of outage of single largest generating unit or a critical generating unit

(choice of candidate critical generating unit is left to the transmission planner).

Criteria for second contingency (N-1-1)

Under the scenario where a contingency as defined at Paragraph: 4.6.4 (v)i(a) has

already happened, the system may be subjected to one of the following subsequent

contingencies (called N-1-1 condition):

(a) The system shall be able to survive a temporary single phase to ground fault on a

765kV line close to the bus. Accordingly, single pole opening (100 ms) of the

faulted phase and successful re-closure (dead time 1 second) shall be considered.

(b) The system shall be able to survive a permanent single phase to ground fault on a

400kV line close to the bus. Accordingly, single pole opening (100 ms) of the

faulted phase and unsuccessful re-closure (dead time 1 second) followed by 3-pole

opening (100 ms) of the faulted line shall be considered.

permanent three phase fault on one circuit, close to a bus, with a fault clearing

time of100 (5 cycles) assuming 3-pole opening.

(d) In the N-1-1 contingency condition as stated above, if there is a temporary fault,

the system shall not lose the second element after clearing of fault but shall

successfully survive the disturbance.

(e) In case of permanent fault, the system shall loose the second element as a result

of fault clearing and thereafter, shall asymptotically reach to a new steady state

without losing synchronism. In this new state the system parameters (i.e. voltages

and line loadings) shall not exceed emergency limits, however, there may be

requirement of load shedding/rescheduling of generation so as to bring system

parameters within normal limits.

Criteria for generation radially connected with the grid

For the transmission system connecting generators or a group of generators radially

with the grid, the following criteria shall apply:

(a) The radial system shall meet N-1 reliability criteria as given at Paragraph:

4.6.4(iv) 1) & 2) for both the steady-state as well as transient-state.

(b) For subsequent contingency i.e., N-1-1 (of Paragraph: 4.6.4 (IV) 3) only

temporary fault shall be considered for the radial system.

contingency causes disconnection of such generator/group of generators from

the main grid, the remaining main grid shall asymptotically reach to a new

steady-state without losing synchronism after loss of generation. In this new

state the system parameters shall not exceed emergency limits, however, there

may be requirement of load shedding / rescheduling of generation so as to bring

system parameters within normal limits.

4.6.5 Criteria for simulation and studies

System studies for transmission planning

The system shall be planned based on one or more of the following power system studies,

as per requirements:

Power Flow Studies

ii.

Short Circuit Studies

iii.

Stability Studies (including transient stability ** and voltage stability)

iv.

EMTP studies (for switching / dynamic over-voltages, insulation coordination, etc)

(** Note: The candidate lines, for which stability studies may be carried out, may be

selected through results of load flow studies. Choice of candidate lines for transient

stability studies are left to transmission planner. Generally, the lines for which the angular

difference between its terminal buses is more than 20 degree after contingency of one

circuit may be selected for performing stability studies.)

II.

Power system model for simulation studies

Consideration of voltage level

For the purpose of planning of the Intra-STS System, the transmission network may be

modeled down to 66kV level or up to the voltage level which is not in the jurisdiction of

DISCOM. The STUs may also consider modeling smaller generating units (below 50MW

capacity) if required.

B. Time Horizons for transmission planning

From concept to commissioning of transmission elements generally takes three to five years;

about three years for augmentation of capacitors, reactors, transformers etc., and about four

to five years for new transmission lines or substations. Therefore, system studies for firming

up the transmission plans may be carried out with 3-5 year time horizon.

ii.

Endeavour shall be to prepare base case models corresponding to load generation scenarios

for a 5 year time horizon. These models may be tested applying the relevant criteria

mentioned in this manual.

C. Load - generation scenarios

The load-generation scenarios shall be worked out so as to reflect in a pragmatic manner the

typical daily and seasonal variations in load demand and generation availability.

D. Load demands

Active power (MW)

The system peak demands (State-wise, regional and national) shall be based on the

latest Electric Power Survey (EPS) report of CEA. However, the same may be

moderated based on actual load growth of past three (3) years.

The load demands at other periods (seasonal variations and minimum loads) shall be

derived based on the annual peak demand and past pattern of load variations. In the

absence of such data, the season-wise variation in the load demand may be taken as

given below:

Sl No

Season/ Scenario

Region-wise Demand Factors (%)

NER

Summer peak Load (S-PL)

100

Summer Light Load (S-LL)

Monsoon peak Load (M-LL)

Monsoon Light Load (M-LL)

Winter Peak Load (W-PL)

100

Winter Peak Load (W-LL)

While doing the simulation, if the peak load figures are more than the peaking

availability of generation, the loads may be suitably adjusted substation-wise to

match with the availability. Similarly, while doing the simulation, if the peaking

availability is more than the peak load, the generation despatches may be suitably

reduced, to the extent possible, such that, the inter-regional power transfers are high.

From practical considerations the load variations over the year shall be considered as

under:

Annual Peak Load

ii.

Seasonal variation in Peak Loads for Winter, Summer and Monsoon

iii.

Seasonal Light Load (for Light Load scenario, motor load of pumped storage

plants shall be considered)

The sub-station wise annual load data, both MW and MVAr shall be provided by the

DISCOMS.

ii) Reactive power (MVAr)

Reactive power plays an important role in EHV transmission system planning and

hence forecast of reactive power demand on an area-wise or substation-wise basis is

as important as active power forecast. This forecast would obviously require adequate

data on the reactive power demands at the different substations as well as the

projected plans for reactive power compensation.

For developing optimal In-STS, the DISCOMs must clearly spell out the substation-

wise maximum and minimum demand in MW and MVAr on seasonal basis. In the

absence of such data the load power factor at 110kV and 66kV voltage levels may be

taken as 0.95 lag during peak load condition and 0.98 lag during light load condition.

The DISCOMS shall provide adequate reactive compensation at the feeder level to

bring power factor close to unity at 110kV and 66kV voltage levels.

E. Generation Despatches and modeling

For planning of new transmission lines and substations, the peak load scenarios

corresponding to summer, monsoon and winter seasons may be studied. Further, the

light load scenarios (considering pumping load where pumped storage stations exist)

may also be carried out as per requirement.

For evolving transmission systems for integration of wind and solar generation

projects, high wind/solar generation injections may also be studied in combination

with suitable conventional Despatch scenarios. In such scenarios, the Intra-State

generating station of the RES purchasing State may be backed-down so that impact

of wind generation on the ISTS grid is minimum. The maximum generation at a

wind/solar aggregation level may be calculated using capacity factors as per the

norms given in Table below:

Voltage

level

/Aggregation

level

110kV

66kV

Individual wind/

Solar farm

220kV

400kV

State as a

Whole

Capacity

Factor

(%)

80%

75%

70%

60%

As per this Grid Code, it is the responsibility of each SLDC to balance its load and

generation and stick to the schedules. Accordingly, it follows that in case of variation

in generation from Renewable Energy Source (RES) portfolio, the State should

backdown/ ramp-up its conventional (thermal/hydro) generation plants or revise

their drawal schedule from ISGS plants and stick to the revised schedule. The Intra-

State generating station should be capable of ramping-up/backing-down based on

variation in RES generation, so that the impact of variability in RES on the ISTS grid

is minimum.

Further to address the variability of the wind/solar projects, other aspects like

reactive compensation, forecasting and establishment of renewable energy control

centers may also be planned by SLDC/STUs.

Special area Despatches:

Special Despatches corresponding to high agricultural load with low power factor,

wherever applicable.

Complete closure of a generating station close to a major load centre.

In case of thermal units (including coal, gas/diesel and nuclear based) the minimum

level of output (ex-generation bus, i.e., net of the auxiliary consumption) shall be

taken as not less than 70% of the rated installed capacity. If the thermal units are

encouraged to run with oil support, they may be modeled to run up to 25% of the

rated capacity.

It shall be the duty of all the generators to provide technical details such as machine

capability curves, generator, exciter, governor, PSS parameters etc., for modeling of

their machines for steady-state and transient-state studies, in the format sought by

STU.

G. Short circuit studies

The short circuit studies shall be carried out using the classical method with flat pre-

fault voltages and sub-transient reactance (Xd) of the synchronous machines.

MVA of all the generating units in a plant may be considered for determining

maximum short-circuit level at various buses in system. This short-circuit level may

be considered for substation planning.

Vector group of the transformers shall be considered for doing short circuit studies

for asymmetrical faults. Inter-winding reactances in case of three winding

transformers shall also be considered. For evaluating the short circuit levels at a

generating bus (11kV, 13.8 kV, 21kV etc.), the unit and its generator transformer

shall be represented separately.

Short circuit level both for three phase to ground fault and single phase to ground

fault shall be calculated.

The short-circuit level in the system varies with operating conditions, it may be low

for light load scenario compared with for peak load scenario, as some of the plants

may not be on-bar. For getting an understanding of system strength under different

load-generation / export-import scenarios, the MVA of only those machines shall be

taken which are on bar in that scenario.

H. Planning margins

In a very large interconnected grid, there can be unpredictable power flows in real

time due to imbalance in load-generation balance in different pockets of the grid. This

may lead to overloading of transmission elements during operation, which cannot be

predicted in advance at the planning stage. This can also happen due to delay in

commissioning of a few planned transmission elements, delay/ abandoning of

planned generation additions or load growth at variance with the estimates. Such

uncertainties are unavoidable and hence some margins at the planning stage may

help in reducing impact of such uncertainties. However, care needs to be taken to

avoid stranded transmission assets. Therefore, at the planning stage following

planning margins may be provided:

Against the requirement of Long Term Access sought, the new transmission lines

emanating from a power station to the nearest grid point may be planned considering

overload capacity of the generating stations in consultation with generators.

The new transmission additions required for system strengthening may be planned

keeping a margin of 10% in the thermal loading limits of lines and transformers (refer

Paragraph: 4.6.4 (ii) above).

At the planning stage, a margin of about + 2% may be kept in the voltage limits (as

given at Paragraph: 4.6.4 (ii)(f), above) and thus the voltages under load flow studies

(for N-0 and N-1 steady-state conditions only) may be maintained within the limits

given below:

Voltage (kVrms) (after planning margins)

Nominal

Maximum

Minimum

765

785

745

400

412

388

220

240

203

110

119

102

In planning studies all the transformers may be kept at nominal taps and on Load

Tap Changer (OLTC) may not be considered. The effect of the taps should be kept as

operational margin.

For the purpose of load flow studies at planning stage, the nuclear generating units

shall normally not run at leading power factor. To keep some margin at planning

stage, the reactive power limits (Qmax and Qmin) for generator buses may be taken

as:

Type of

generating unit

Qmax

Qmin

Nuclear units

Qmax= 0.50 x Pmax

Qmin= (-)0.10 x Pmax

Thermal Units

(other than

Nuclear)

Qmax= 0.50 x Pmax

Qmin= (-)0.10 x Pmax

Hydro units

Qmax= 0.40 x Pmax

Qmin= (-)0.20 x Pmax

Notwithstanding above, during operation, following the instructions of the System Operator,

the generating units shall operate at leading power factor as per their respective capability

curves.

4.6.6 Additional planning criteria and guidelines

Reactive power compensation

Requirement of reactive power compensation like shunt capacitors, shunt reactors (bus

reactors or line reactors), static VAr compensators, fixed series capacitor, variable series

capacitor (thyristor controlled) or other FACTS devices shall be assessed by appropriate

studies.

Shunt capacitors

(1) Reactive Compensation shall be provided as far as possible in the low voltage systems

with a view to meet the reactive power requirements of load close to the load points,

thereby avoiding the need for VAr transfer from high voltage system to the low voltage

system.

(2) It shall be the responsibility of the respective distribution licensees to bring the load

power factor as close to unity as possible by providing shunt capacitors at

appropriate places in their system. Reactive power flow through 400/220kV or

220/110(or 66) kV ICTs, shall be minimal. Wherever voltage on HV side of such an

ICT is less than 0.975 pu no reactive power shall flow down through the ICT.

Similarly, wherever voltage on HV side of the ICT is more than 1.025 pu no reactive

power shall flow up through the ICT. These criteria shall apply under the N-0

conditions.

Shunt reactors

(1) Switchable bus reactors shall be provided at EHV substations for controlling voltages

within the limits (defined in the Paragraph: 4.6.4(ii)(f) without resorting to switching-

off of lines. The bus reactors may also be provided at generation switchyards to

supplement reactive capability of generators. The size of reactors should be such that

under steady state condition, switching on and off of the reactors shall not cause a

voltage change exceeding 5%. The standard sizes (MVAr) of reactors are:

Voltage Level

Standard sizes of reactors ( in MVAr)

400kV ( 3-ph units)

50, 63, 80 and 125 (rated at 420kV)

765kV ( 1-ph units)

80 and 110 (rated at 800kV)

Fixed line reactors may be provided to control power frequency temporary over-

voltage (TOV) after all voltage regulation action has taken place within the limits as

defined in Paragraph: 4.6.4 (ii)(g) under all probable operating conditions.

(2) Line reactors (switchable/ controlled/ fixed) may be provided if it is not possible to

charge EHV line without exceeding the maximum voltage limits given in Paragraph:

4.6.4 (ii)(f). The possibility of reducing pre-charging voltage of the charging end shall

also be considered in the context of establishing the need for reactors.

(3) Guideline for switchable line reactors: The line reactors may be planned as switchable

wherever the voltage limits, without the reactor(s), remain within limits specified for

TOV conditions given at Paragraph: 4.6.4 (ii)(g).

Static VAr compensation (SVC)

Static VAr Compensation (SVC) shall be provided where found necessary to damp the power

swings and provide the system stability under conditions defined in the Paragraph: 4.6.4(iii)

on Reliability Criteria. The dynamic range of static compensators shall not be utilized under

steady state operating condition as far as possible.

4.6.7 Substation planning criteria

(1) The requirements in respect of EHV sub-stations in a system such as the total load to be

catered by the sub-station of a particular voltage level, its MVA capacity, number of feeders

permissible etc., are important to the planners so as to provide an idea to them about the

time for going in for the adoption of next higher voltage level sub-station and also the

number of substations required for meeting a particular quantum of load. Keeping these in

view the following criteria have been laid down for planning an EHV substation:

(2) The maximum short-circuit level on any new substation bus should not exceed 80% of the

rated short circuit capacity of the substation. The 20% margin is intended to take care of the

increase in short-circuit levels as the system grows. The rated breaking current capability of

switchgear at different voltage levels may be taken as given below:

Voltage Level

Rated Breaking capacity

66 kV

25kA/31.5kA

110 kV

25kA/31.5kA

220 kV

31.5 kA/40kA

400 kV

50kA/63kA

765 kV

40kA/50kA

Measures such as splitting of bus, series reactor, or any new technology may also be adopted

to limit the short circuit levels at existing substations wherever they are likely to cross the

designed limits without sacrificing the operational flexibility and grid security.

(3) Rating of the various substation equipments shall be such that they do not limit the loading

limits of connected transmission lines.

(4) Effort should be to explore possibility of planning a new substation instead of adding

transformer capacity at an existing substation when the capacity of the existing sub-station

has reached levels as given in column (B) in the following table. The capacity of any single

sub-station at different voltage levels shall not normally exceed as given in column (C) in the

following table:

Voltage Level (A)

Transformer Capacity

Existing capacity (B)

Maximum Capacity (C)

765 kV

6000 MVA

9000 MVA

400 kV

1260 MVA

2000 MVA

220 kV

320 MVA

500 MVA

110 kV

150 MVA

250 MVA

66kV

85 MVA

120 MVA

(5) While augmenting the transformation capacity at an existing substation or planning a new

substation the fault level of the substation shall also be kept in view. If the fault level is low

the voltage stability studies shall be carried out.

(6) Size and number of interconnecting transformers (ICTs) shall be planned in such a way that

the outage of any single unit would not overload the remaining ICT(s) or the underlying

system.

(7) A stuck breaker condition shall not cause disruption of more than four feeders for the 220kV

system and two feeders for the 400kV system and 765kV system.

Note In order to meet this requirement it is recommended that the following bus switching

scheme may be adopted for both AIS and GIS and also for the generation switchyards:

220kV

Double Main or Double Main & Transfer scheme with

a maximum of eight (8) feeders in one section

400kV and 765kV One and half breaker scheme

4.6.8 Additional criteria for wind and solar projects

(1) The capacity factor for the purpose of maximum injection to plan the evacuation system,

both for immediate connectivity with the In-STS and for onward transmission requirement,

may be taken as given below:

Voltage

level/

Aggregation level

110kV/66kV /Individual

wind /Solar farm

220kV

400kV

State

a whole

Capacity Factor (%)

80%

75%

70%

60%

(2) The N-1 criteria may not be applied to the immediate connectivity of wind/solar farms with

the In-STS grid i.e., the line connecting the farm to the grid and the step-up transformers at

the grid station.

(3) The wind generating stations connected at voltage level of 66kV and above shall remain

connected to the grid when the voltage at the interconnection point or any or all phases dips

a level of 85% of the nominal voltage (i.e., the wind generators should be capable to have low

voltage ride through facility).

(4) As the generation of energy at a wind farm is possible only with the prevalence of wind, the

thermal line loading limit of the lines connecting the wind machine(s)/farm to the nearest

grid point may be assessed considering 12 km/hour wind speed.

(5) The wind and solar farms shall maintain a power factor of 0.98 (absorbing) at their grid

inter-connection point for all Despatch scenarios by providing adequate reactive

compensation and the same shall be assumed for system studies.

(6) The Harmonic current injection from a generating station shall not exceed the limits specified

in IEEE standard 519.

4.6.9 Guidelines for Planning HVDC Transmission System

(1) The option of HVDC bipole may be considered for transmitting bulk power over long distance

based on techno economic criteria. HVDC transmission may also be considered in the

transmission corridors that have AC lines carrying heavy power flows (total more than 5000

MW) to control and supplement the AC transmission network.

(2) The ratio of fault level in MVA at any of the convertor station (for conventional current

source type), to the power flow on the HVDC bipole shall not be less than 3.0 under any of

the load-generation scenarios given under Paragraph:4.6.5 (ii) (C) to (F) and contingencies

given at Paragraph: 4.6.4(iv), above.

Further, in areas where multiple HVDC bipoles are feeding power (multi in feed), the

appropriate studies be carried at planning stage so as to avoid commutation failure.

4.6.10 Guidelines for voltage stability

(1) Voltage Stability Studies: These studies may be carried out using load flow analysis to arrive

at the knee point of Q-V curve which represents the horizontal 'distance' of the knee point to

the zero-MVAr vertical axis measured in MVAr is, therefore, an indicator of the proximity to

the voltage collapse.

(2) Each bus shall operate above Knee Point of Q-V curve under all normal as well as the

contingency conditions as discussed above. The system shall have adequate margins in

terms of voltage stability.

4.7 Planning Data

Under this Planning Code, the State Generating Companies / IPPs / licensees are to supply data

in accordance with the detailed procedures mentioned in the Karnataka Electricity Regulatory

Commission (Terms and conditions for Open Access) Regulations, 2004 as amended from time to

time.

SECTION 5

GRID CONNECTIVITY

5.1 Introduction

All Users connected to, or seeking connection to In-STS shall comply with Central Electricity

Authority (Technical Standards for Connectivity to the Grid) Regulations, 2007 which specifies the

minimum technical and design criteria and Karnataka Electricity Regulatory Commission (Terms

and Conditions for Open Access) Regulations, 2004 as amended from time to time.

5.2 Objective

The objective of the Gird Connectivity is as given below:

a) To ensure the safe operation, integrity and reliability of the grid.

b) That the basic rules for connectivity are complied with in order to treat all users in a non-

discriminatory manner.

c) Any new or modified connections, when established, shall neither suffer unacceptable

effects due to its connectivity to the In-STS nor impose unacceptable effects on the system

of any other connected User or Transmission Licensee and Distribution Licensees.

d) To make aware in advance the procedures for connectivity to In-STS and also the

standards and condition of the system to be integrated to the grid to any person seeking a

new connectivity to the grid.

5.3 Scope

The connectivity criteria is applicable to all Users connected to or seeking connection to the InSTS,

All such entities shall abide by the CEA (Technical Standards for connectivity to the Grid)

Regulations, 2007, in order to ensure that the integrated grid is not adversely affected.

5.4 Procedure for connection

A User seeking to establish new or modified arrangement of connection to or for use of In-STS, shall

submit an application in the standard format (prepared by STU and approved by KERC) to STU in

case the connection is sought to intra-State transmission system and respective ESCOM in case the

connection is sought at distribution system.

The STU shall process the application for grant of connectivity in accordance with these

regulations

5.5

Connection Agreement

A connection agreement, or the offer for a connection agreement shall include (but not

limited) within its terms and conditions the following:

(i) A condition requiring both Agencies to comply with the Grid Code.

(ii) Details of connection technical requirements and commercial arrangements

(iii) 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.

(iv) A Site Responsibility Schedule (Annexure-I).

(v) General Philosophy, Guidelines etc on protection and telemetry.

(vi) Requirement with respect to Harmonics, Direct current (DC) injection and Flicker (as per

CEA (Technical Standards for Connectivity to the Grid) Regulations, 2007, amended from

time to time).

The Connection agreement with above terms and conditions shall be signed by the applicant

not-inconsistent with CEA (Technical Standards for Connectivity to the Grid) Regulations,

2007, amended from time to time and the Karnataka Electricity Regulatory Commission

(Terms and conditions for Open Access) Regulations, 2004 as amended from time to time.

Model connection agreement:

(i) The standard connection agreement shall be prepared by the STU and submitted to the

Commission for approval, within a month from the date of publishing of Grid Code in

the official Gazette of Karnataka.

(ii) The approved format shall be made available for the prospective users of the Grid and

shall be hosted on STUs website.

5.6 Site responsibility schedule

1. For every connection to the State Transmission System for which a connection agreement is

required, STU shall prepare a schedule of equipment with information supplied by the

respective Users. This schedule, called Site Responsibility Schedule shall indicate the

following for each item of equipment installed at the connection site.

Ownership of the equipment

ii.

Responsibility for control of equipment

iii.

Responsibility for maintenance of equipment

iv.

Responsibility for operation of equipment

Responsibility for all matters relating to safety of persons and site.

vi.

Management of the site.

The format to be used in the preparation of Site Responsibility Schedule is given in Annexure-I

5.7 System Performance

1. All equipment connected to the State Transmission System shall be of such design and

construction that enable STU to meet the requirement of standards of performance to meet

the grid standard.

2. Installation of all electrical equipment shall comply with Rules which are in force for the time

being and will be replaced by new Rules made under the Electricity Act, 2003.

3. For every new / modified connection sought, the STU shall specify the connection point,

technical requirements and the voltage to be used, along with metering, tele-metering and

protection requirements as specified in the Metering Code and Protection Code.

4. Insulation coordination of the Users equipment shall conform to the applicable values as

specified by STU from time to time out of those applicable as per Indian Standards / Code of

Practices. Rupturing capacity of the switchgear shall not be less than that specified by STU

from time to time.

5. Protection schemes and metering schemes shall be as detailed in the Protection Code and

Metering Code.

5.8 State Grid Connection Points / Interface points

1. State Generating Stations (SGS)

(i) Voltage may be 400/220/110/66/33 kV or as agreed with STU.

(ii) Unless specifically agreed with STU, the Connection Point with generating station shall be

the terminal isolator provided just before the outgoing gantry of the feeders/evacuation

lines.

(iii) SGS shall operate and maintain all terminals, communication and protection equipment

provided within the generating station.

(iv) The provisions for the metering between generating station and STU system shall be as per

the Metering Code.

(v) Respective Users shall maintain their equipment from the outgoing feeders gantry onwards

emanating from generating station.

(vi) All entities embedded within the State Grid system and interfacing the intra-State

transmission system shall provide adequate and reliable communication facility so that

SLDC is able to record in its SCADA system the MW/ MVAR flows, bus voltages at all the

interface points with the intra-State system.

2. Distribution Licensee

(i) Voltage may be LV side of power transformer i.e., 33 kV or 11 kV or as agreed with STU. For

EHV consumers directly connected to transmission system, voltage may be 400kV /220 kV/

110 kV/66kV.

(ii) Unless specifically agreed with Distribution Licensee, the Connection Point with STU

shall be the terminal isolator provided just before the outgoing gantry of the feeder to

Distribution Licensee or individual EHV consumer as the case may be, from STU sub-

station

STU shall operate and maintain all terminals, communication and protection equipment

provided within its sub-station. The provisions for the metering between STU and

Distribution Licensees system shall be as per the Metering Code. Respective Users shall

maintain their equipment beyond the outgoing gantry of feeders emanating from STU

sub-station onwards.

3. Southern Regional Transmission System

The Connection, protection scheme, metering scheme and the voltage shall be in accordance

with the provisions of IEGC.

4. Independent Power Producers (IPPs), Captive Power Plants (CPPs), Extra High

Voltage (EHV) Consumers and Open Access Consumers.

(i) Voltage may be 400/220/110/66 kV or as agreed with STU.

(ii) When IPPs, CPPs, EHV Consumers or the Open Access Consumers own sub-stations, the

Connection Point shall be the terminal isolator provided just before the gantry of

outgoing/incoming feeder in their premises.

5.9 Important Technical Requirements for Connectivity to the Grid

5.9.1 Reactive Power Compensation

a) Reactive Power compensation and/or other facilities shall be provided by Users connected

to In-STS avoiding the need for exchange of reactive power to/from In-STS and to

maintain In-STS voltage within the specified range.

b) The person already connected to the grid shall also provide additional reactive

compensation as per the quantum and time frame decided by SLDC. The Users /

Transmission Licensees / Distribution Licensees shall provide information to SLDC

regarding the installation and healthiness of the reactive compensation equipment on

regular basis. SLDC shall regularly monitor the status in this regard.

5.9.2 Data and Communication Facilities

Reliable and efficient communication systems (for speech, data and protection

requirements) shall be provided to facilitate necessary information exchange, by all Users,

and the STU for supervision/control/protection of the grid by the SLDC, under normal and

abnormal conditions. All Users shall provide Systems to telemeter power system

parameters such as flow (active and reactive power), voltage and status of switches/

transformer taps etc., in line with interface requirements and other guidelines made

available to users by SLDC. The associated communication system and other required

facilities at their respective end to facilitate data flow up to appropriate data collection

point on STUs system shall also be established by the concerned User, Transmission

Licensee / Distribution Licensees as specified by the STU in the Connection Agreement.

5.9.3 System Recording Instruments

Recording instruments such as Data Acquisition System, Disturbance Recorder, Event

Logging Facilities, Fault Locator etc., shall be provided and shall always be kept in working

condition in the In-STS for recording of dynamic performance of the system.

All disturbance recording and event logging facilities and the numerical relays shall be

provided with time synchronization facility for global common time reference.

5.9.4 Responsibilities for safety

STU and all users shall be responsible for safety in accordance with the Central Electricity

Authority (Technical Standards for Connectivity to the Grid) Regulations, 2007, the

Karnataka Electricity Regulatory Commission (the terms and Condition for Open Access)

Regulations, 2004, as amended from time to time and CEA (Technical Standards for

Construction of Electric plants and Electric Lines) Regulations 2010 and Measures Relating

to Safety and Electric Supply) Regulations, 2010.

5.9.5 Cyber Security

All Users and STU shall have in place, a cyber security framework as specified in Information

Technology Act, 2000 amended from time to time to identify the critical cyber assets and

protect them so as to support reliable operation of the Grid.

5.10 Schedule of assets of the State Grid

STU, other transmission licensees granted licence by the Commission and Generators shall

maintain the schedule of their assets and host the same in their respective websites. The

same shall be submitted to the Commission as and when called for.

SECTION -6

OPERATION PLANNING

6.0 Operating Criteria

This Part describes the operational philosophy to maintain efficient, secure and reliable Grid and

contains the following sections.

(a) Operating Philosophy

(b) System Security Aspects

This section describes the general security aspects to be followed by generating companies,

STU, intra-State transmission licensee, bulk consumers and all other Users of the In-STS.

6.1 Operating philosophy.

(a) All users connected with In-STS shall comply with this Operating Criteria and the directions

issued by SLDC, to ensure integrated grid operation and for achieving the maximum

economy and efficiency in the operation of the power system.

(b) A set of detailed operating procedures for the State Grid shall be developed and maintained

by the SLDC in consultation with the concerned persons for guidance of the staff of SLDC

and the same shall be consistent with this Grid Code and IEGC to facilitate compliance with

the requirement of the Grid Code and IEGC.

Transmission and Distribution Companies shall be manned round the clock by qualified and

adequately trained and certified personnel.

6.2 System Security Aspects

STU and all Users shall endeavor to operate their respective power systems and power

stations in an integrated manner at all times.

ii.

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

except

under an emergency, and conditions in which such isolation would prevent a total grid

collapse and / or would enable early restoration of power supply,

for safety of human life,

when serious damage to a costly equipment is imminent and such isolation would

prevent it,

When such isolation is specifically instructed by SLDC /ALDC.

Complete synchronization of the grid shall be restored as soon as the conditions again

permit it. The restoration process shall be supervised by SLDC, in co-ordination with RLDC.

iii.

A list of important elements of the State grid which shall not be deliberately opened or

removed from service at any time, except when specifically instructed by SLDC or with

specific and prior clearance of SLDC (List of such important grid elements on which the

above stipulations apply will be prepared by the SLDC in consultation with the RLDC,

CTU and STUs as per provisions of Indian Electricity Grid Code) shall be available on the

website of SLDC. 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.

iv.

Any tripping, whether manual or automatic, of any of the above elements of State grid

shall be precisely intimated to the SLDC 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.

Maintenance of their respective power system elements shall be carried out by users,

and STU in accordance with the provisions in the Central Electricity Authority (Grid

Standards) Regulations, 2010.

Any prolonged outage of 400kV and above power system elements, which forms the

National Transmission Grid, is causing or likely to cause danger to the grid or sub-

optimal operation of the grid, shall be regularly monitored by SLDC. SLDC shall report

such outages to RLDC for onward transmission to RPC. STU and Transmission licensee

shall make all reasonable efforts to restore such elements as per action plan to be

finalized and intimated by RPC as per provisions of IEGC.

The Planned /Scheduled outages of the power system elements pertaining to the State

grid shall be carried out by STU in concurrence with the SLDC duly informing the RLDC

for secured operation of the Grid.

vi.

Governor Action

(i) Governor action for all Generators of different capacity, thermal, hydro, gas and

renewable generating units shall be operated as per the provisions of IEGC.

a) Thermal generating units of 200 MW and above

Hydro units of 10 MW and above

The Restricted Governor Mode of Operation (RGMO) shall essentially have the following

features:

(a) There should not be any reduction in generation in case of improvement in grid

frequency below the upper limit fixed by CERC from time to time (for example if

grid frequency changes from 49.8 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 Maximum Continuous

Rating (MCR) of the unit subject to machine capability.

(b) Ripple filter of +/- 0.03 Hz. shall be provided so that small changes in frequency

are ignored for load correction, in order to prevent governor hunting.

in operation as specified above, the RLDC shall be immediately advised about

the reason and duration of such operation. All governors shall have a droop

setting between 3% and 6%.

(ii)

All other generating units including those with pondage upto 3 hours, Gas turbine

/ Combined Cycle Power Plants, wind and solar generators shall be exempted from

clause 6.2 vi and following clauses vii, viii and ix till the situation is reviewed.

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

vii.

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 and no dead bands and/or time

delays shall be deliberately introduced except as specified in para 6.2(vi) above.

viii.

All thermal 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 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 Regional grid) only after obtaining the

permission of SLDC / RLDC. The SLDC can also direct a generator to come to its

technical minimum in line with CEA/CERC Notifications from time to time depending on

the grid situation.

ix.

The recommended rate for changing the governor setting, i.e., supplementary control for

increasing or decreasing the output (generation level) for all generating units, irrespective

of their type and size, would be one (1.0) per cent per minute or as per manufacturers

limits. However, if frequency falls below the limit specified by CERC from time to time, all

partly loaded generating units shall pick up additional load at a faster rate, according to

their capability. All generators shall inform the SLDC on the Governor status as and

when required and also submit the performance analysis of RGMO to SLDC for

verification.

Except under an emergency, or to prevent an imminent damage to costly equipment, no

Generator shall suddenly reduce his generating unit output without prior intimation to

and consent of the SLDC, particularly when frequency is falling or is below the limit

specified by CERC from time to time. Similarly, no User / Distribution Licensee shall

cause a sudden variation in its load without prior intimation to and consent of the SLDC.

The extent of sudden reduction in Generator output / sudden variation of load by User /

Distribution Licensee shall be determined by SLDC. In the event of any inconsistency in

this provision from that of the IEGC, the provisions of IEGC shall prevail.

xi.

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 the Central Electricity Authority (Grid Standards) Regulations, 2010.

xii.

All generating units shall normally have their automatic voltage regulators (AVRs) in

operation. 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 of such operation, and obtain its permission. Power System

Stabilizers (PSS) in AVRs of generating units (wherever provided), shall be properly tuned

by the respective generating unit owner duly reporting the AVR and PSS functional

availability to SLDC and SLDC shall undertake to do random test to ascertain the

functionality of AVR and PSS.

xiii.

Provision of protections and relay settings shall be coordinated periodically throughout

the Regional grid, as per a plan to be separately finalized by the Protection sub-

Committee of the SRPC. SRPC will prepare islanding schemes and ensure its

implementation in accordance with the Central Electricity Authority (Grid Standards)

Regulations, 2010. All Users shall ensure that installation and operation of protection

system shall comply with the provisions of the Central Electricity Authority (Grid

Standards) Regulations, 2010.

xiv.

SLDC shall ensure that all Users take all possible measures to ensure that the grid

frequency always remains within the frequency band specified by the CERC from time to

time.

xv.

All distribution licensees and STU shall provide automatic under-frequency and df/dt

relays for load shedding in their respective systems, to arrest frequency decline that

could result in a collapse/disintegration of the grid, as per the plan separately finalized

by the concerned RPC and shall ensure its effective application to prevent cascade

tripping of generating units in case of any contingency. All distribution licensees, STU

and SLDC shall ensure that the above under-frequency and df/dt load shedding /

islanding schemes are always functional. The provisions of the CEA Regulations

regarding under frequency and df/dt relays shall be complied with. All Distribution

licensees and STU shall abide by the decisions of SRPC regarding action to be taken to

get the required load relief from under frequency and df/dt relays by STU or SLDC. The

required relief available at the set (under) frequency shall be monitored on a

continuous basis by SLDC.

xvi.

All Users, STU/SLDC shall also facilitate identification, installation and commissioning of

System Protection Schemes (SPS) (including inter-tripping and run-back) finalized by the

SRPC Forum in the power system to operate the transmission system closer to their

limits and to protect against situations such as voltage collapse and cascade tripping,

tripping of important corridors/flow-gates etc., Such schemes finalized by the concerned

SRPC forum shall always be kept in service. Any SPS is to be taken out of service; only

with consultation with RLDC after indicating reason and duration of anticipated outage

from service.

xvii.

Procedures shall be developed and documented for recovery from partial/total collapse of

the grid in accordance with the Central Electricity Authority (Grid Standards)

Regulations, 2010 and to periodically update the same in accordance with their

requirements given under Regulation 14. These procedures shall be followed by all the

Users and STU/SLDC to ensure consistent, reliable and quick restoration.

xviii.

Each User, distribution licensee, STU and SLDC shall provide and maintain adequate

and reliable communication facility with redundancy internally and with other Users /

STU / ALDCs / SLDC to ensure exchange of data/information necessary to maintain

reliability and security of the grid. Wherever possible, redundancy and alternate path

shall be maintained for communication along important routes, e.g., ALDC to SLDC.

xix.

All the Users, Distribution licensees / ALDCs / STU shall send information / data

including disturbance recorder/sequential event recorder output to SLDC within 24

Hours for purpose of analysis of any grid disturbance/event. No User / distribution

licensee / ALDCs / SLDC / STU shall block any data / information required by the SLDC

and SRPC/SRLDC for maintaining reliability and security of the grid and for analysis of

an event.

xx.

All Users, Distribution licensees and STU shall provide adequate voltage control

measures through automatic under voltage relays as finalized in consultation with SRPC,

to prevent voltage collapse and shall ensure its effective application to prevent voltage

collapse/ cascade tripping Voltage fluctuation limits and voltage wave-form quality shall

be maintained as specified in the Central Electricity Authority (Grid Standards)

Regulations, 2010, and amendments from time to time.

xxi.

Special requirements for Renewable Energy

System Operator (SLDC) shall make all efforts to evacuate the available Solar, mini-hydel,

co-generation and wind power and other Renewable Energy (RE) sources and treat the

plants as must-run stations. However, SLDC may instruct such generator to back down

generation in case grid security or safety of any equipment or personnel is likely to be

endangered and Renewable Energy (RE) sources shall comply with the same. For this,

Data Acquisition System facility shall be provided by the generator for transfer of

information to the SLDC.

SLDC may direct a wind farm to curtail its VAR drawal/injection in case the security

of grid or safety of any equipment or personnel is endangered.

ii.

During the wind generator start-up, the wind generator shall ensure that the reactive

power drawal (inrush currents in case of induction generators) shall not affect the

grid performance.

6.3 Demand Estimation for Operational Purpose

Load forecasting shall be carried as per the KERC (load forecast) Regulations, 2009, and not-

inconsistent with the above Regulations the following may be adhered to:

(a) The distribution licensee shall formulate a long term demand forecast considering the

previous financial years as base and projecting the demand for the succeeding 5 years.

(b) It shall be the responsibility of all distribution licensees to fully co-operate with STU in

preparation of demand forecast for the entire State.

st April to 31

March by 1

st January of each year on a financial year ahead basis. This shall be

updated for every month subsequently in the previous month on a month ahead basis

and in the previous day on a day ahead basis as required by STU/SLDC.

(d) The long term demand estimation/ load forecast (for more than one year) shall be done

by STU and SLDC shall be provided with a copy of the same as and when it is finalized.

(e) Based on the data furnished by the distribution licensees, STU shall make monthly peak

and lean period demand estimates for year ahead and daily peak and lean period demand

estimates for the month ahead and furnish the same to SLDC.

(f)

The distribution Licensee shall provide SLDC on day ahead basis, at 9.00 Hrs each day

their estimated demand for each 15 minute block for the ensuing day. Distribution

licensee shall also provide SLDC estimates of loads that may be shed, when required, in

discreet blocks with details of arrangements of such load shedding.

(g) The SLDC would update demand forecast (in MW as well as KWh) on quarterly, monthly,

weekly and ultimately on daily basis which would be used in the day ahead scheduling.

(h) Based on such demand estimation for daily/weekly/monthly/yearly basis SLDC will

prepare load generation balance plan for that year. The SLDC shall carry out this

demand estimate for operational planning purposes.

(i)

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 SLDC and shall also

maintain historical data base for demand estimation.

(j)

SLDC shall carry out its own demand estimation 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

estimation.

(k) To

carry

out

demand

estimation

for

operational

purposes

daily//weekly/monthly/yearly basis, mechanisms and facilities at SLDC shall be created

to facilitate online estimation of demand for daily operational use for each 15 minutes

block.

(l)

The SLDC shall take in to account the wind energy forecasting to estimate the active and

reactive power availability.

(m) Based on its demand estimation 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. SLDC shall plan demand

management measures like load shedding, power cuts, etc. and shall ensure that the

same is implemented by the distribution licensees.

(n) All distribution licensees shall abide by the demand management measures of the SLDC

and shall also maintain historical database for demand estimation.

6.4 Demand Management

6.4.1 Introduction

This Section is concerned with the provisions to be made by SLDC / ALDCs 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 frequency,

voltage levels beyond normal operating limit, or thermal overloads, etc.) or over drawal of power

vis--vis of the regional entities beyond the limits mentioned in the Regulations of CERC from

time to time.

6.4.2 Demand Disconnection

(a) SLDC / ALDCs / Distribution licensees and bulk consumers shall initiate action to

reduce the drawal by their control area, from the grid, within the net drawal schedule

whenever the system frequency falls below frequency specified by CERC from time to

time.

(b) The SLDC / ALDCs / Distribution licensee and bulk consumers shall ensure that

requisite load shedding is carried out in their control area so that there is no over drawal

when frequency below the limit specified by CERC from time to time.

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.

(d) The SLDC through respective ALDCs / 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 over drawal in order to comply with clause

6.4.2 (a) and (b) above. A Report detailing the scheme and periodic reports on progress of

implementation of the schemes shall be sent to the Commission by the SLDC.

(e) 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 identified at the SRPC level. 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 ALDCs / Distribution

licensee/s or bulk consumer connected to the In-STS to decrease drawal of its control

area by a desired quantum. Such directions of SLDC shall immediately be acted upon

and the respective Agencies shall send compliance report immediately after compliance of

these directions to SLDC.

(f)

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

withdrawal of congestion shall be in accordance with the Central Electricity Regulatory

Commission (Measures to relieve congestion in real time operation) Regulations, 2009.

(g) The measures taken by the Users, Distribution licensee or bulk consumer shall not be

withdrawn as long as the frequency remains at a level lower than the limits specified in

clauses 6.4.2 (a) & (b) above or congestion continues, unless specifically permitted by the

SLDC.

6.5 Load Crash

6.5.1 In the event of load crash in the system due to weather disturbances or any other reason,

the situation would be controlled by SLDC by the following methods in descending

priorities:

Lifting of the load restrictions, if any.

ii.

Exporting the power to neighboring regions/ States provided the same does not endanger

the security of the ISTS.

iii.

Backing down of thermal stations with a time lag of 5-10 minutes for short period in merit

order.

iv.

Closing down of hydel units (subject to non-spilling of water and effect on irrigation)

keeping in view the inflow of water into canals and safety of canals/hydel channels.

6.5.2 While implementing the above, the system security aspects should not be violated

as per the provisions in Section 5.2 of IEGC.

6.6 Operational Liaison

6.6.1 Introduction

(a) This Grid Code sets out the requirements for the exchange of information in relation to

Operations and/or Events on the total grid system which have or will have an effect on:

The ISTS in the Region

The system of a User and STU

The Operational liaison function is a mandatory built-in hierarchical function of the

SLDC, STU, ALDC, DISCOMs and Users, to facilitate quick transfer of information to

operational staff. It will correlate the required inputs for optimization of decision making

and actions.

6.6.2 Procedure for Operational Liaison

Operations and events on a User/STU system:

Before any operation is carried out by a User, STU or transmission licensee shall obtain

permission of the SLDC, and give details of the operation to be carried out. In case such

operation is likely to have impact on other regions, the RLDC of those Regions shall also

be informed.

ii.

All planned outages shall be communicated to SLDC by the 20

th of the previous month so

as to enable SLDC to study the impact and communicate to SRPC before 25

th of previous

month for outage coordination approval.

iii.

Immediately following an event, the User, STU, transmission licensee or DISCOM shall

inform the SLDC about the event. All operational instructions given by SLDC shall have

unique codes which shall be recorded and maintained as specified in the Central

Electricity Authority (Grid Standards) Regulations, 2010.

6.7 Outage Planning

6.7.1 Introduction

This Section sets out the procedure for preparation of outage schedules for the

elements of the State grid in a coordinated and optimal manner keeping in view the

Regional system operating conditions and the balance of generation and demand.

(List of elements of grid covered under these stipulations shall be prepared and be

available with SLDC).

The generation output and transmission system should be adequate after taking into

account the outages to achieve the security standards.

Annual outage plan for the EHV transmission system in the State will be prepared in

advance for the financial year by the SLDC in consultation with SRPC and reviewed

during the year on quarterly and monthly basis.

All Users, STU and transmission licensee(s) shall follow these annual outage plans. 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, co-generation plants and its

associated evacuation network shall be planned during off season. For Ex: 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.

6.7.2 Objective

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, irrigational requirements.

To minimise surplus or deficits, if any, in the system requirement of power and

energy and help operate system within Security Standards.

To manage the transmission element outages of the State grid without adversely

affecting the grid operation but taking into account the Generation Outage Schedule,

outages of User/STU/CTU systems and maintaining system security standards.

6.7.3 Outage Planning Process

a) The SLDC will be primarily responsible for finalization of the Annual Load Generation

Balance Report (LGBR) and the annual outage plan for the following financial year by

st December of each year. The LGBR will be prepared for peak as well as off-peak

scenarios.

b) The STU, transmission licensees, IPPs, and other generating stations shall provide to

the SLDC their proposed outage plan in writing for the next financial year by 31st

October of each year. These shall contain identification of each generating

unit/transmission line/ICT etc., the preferred date for each outage and its duration,

and where there is flexibility, the earliest start date and latest finishing date. SLDC

shall prepare LGBR for its control area, for peak as well as off-peak scenario, by 31

December for the next financial year and submit the same to the Commission. The

annual plans for managing deficits/surpluses in the control area shall clearly be

indicated in the LGBR submitted by SLDCs to KERC.

c) The draft LGBR and draft outage plan shall be uploaded by the SLDC on its website.

The final outage plan and the final LGBR shall be intimated by SLDC to Users, STU,

CTU, RLDC and other generating stations connected to the In-STS by 31

st December

of each year for implementation.

The above annual outage plan will be reviewed by SLDC on quarterly and monthly

basis in coordination with all parties concerned, and adjustments made wherever

found to be necessary.

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 clear the planned outage after conducting necessary studies.

SLDC is authorized to defer the planned outage in case of any of the following, taking

into account the statutory requirements:

i. Grid disturbances

ii. System isolation

iii. Partial Black out in the State

iv. Any other event in the system that may have an adverse impact on the system

security by the proposed outage.

The detailed generation and transmission outage programmes shall be based on the

latest annual outage plan (with all adjustments made to date).

Each User and STU shall obtain the final approval from SLDC / RLDC prior to

availing an outage.

6.8 Contingency planning

6.8.1 Introduction

a. This Section describes the steps in the recovery process to be followed by all users in

the event of total or partial blackouts of the State/ Regional transmission system

b. The objective of contingency planning is to design the responsibility of all users to

achieve the fastest recovery in the event of the State transmission system or Regional

system block out, taking in to account essential loads, generator capabilities and

system constraints.

6.8.2 Contingency planning procedure

1. SLDC shall be prepared to efficiently handle the following types of contingency and

restoration of the system back into steady state

Partial system blackout in the State grid due to multiple tripping of the Transmission

lines emanating from major generating stations/main receiving stations.

Total blackout in the State /Region.

Partial grid disturbances resulting in formation of islands and system split.

2. In case of partial blackout in the State / Regional grid, priority is to be given for early

restoration of generating units which have tripped. Startup power for such generating

stations shall be extended through shortest possible route and within shortest possible time

from adjoining substations/ generating stations where the

supply is available.

Synchronizing facility at all generating stations and 220 kV and above substations shall be

available.

3. In case of total regional black out, SLDC In-charge shall co-ordinate and follow the

instructions of SRLDC for early restoration of the entire grid. Start-up power to the thermal

stations shall be given by the hydel stations or through inter-State supply, if available. All

possible efforts shall be made to extend the hydel supply to the thermal power stations

through shortest transmission network so as to avoid high voltage problem due to low

load conditions. For safe and fast restoration of supply, SLDC shall formulate the proper

sequence of operation for major generating units, lines, transformers and load

within the State in consultation with SRLDC. The sequence of operation shall include

opening, closing/tripping of circuit breakers, isolators, on-load tap-changers etc.

6.9 Recovery Procedures

a) Detailed plans and procedures for restoration after partial/total blackout of In-STS

will be finalized by the SLDC/STU in coordination with the RLDC. The procedure will

be reviewed, confirmed and/or revised once every subsequent year. Mock trial runs of

the procedure for different subsystems shall be carried out by the SLDC / STU at

least once every six months under intimation to SRLDC. Diesel Generator sets for

black start shall be tested on weekly basis and test report shall be sent to SLDC on a

quarterly basis.

b) 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.

c) 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.

All communication channels required for restoration process shall be used for

operational communication only, till grid normalcy is restored.

All Users shall pay special attention to implement the instructions of SLDC and to

carry out the recovery procedures so that secondary collapse due to undue haste or

inappropriate loading is avoided.

Despite the urgency of the situation, careful, prompt and complete logging of all

operations and operational messages shall be ensured by all Users to facilitate

subsequent investigation in to the incident and efficiency of the restoration process.

Such investigation shall be conducted promptly after the incident and discussed in

the (Protection Coordination Committee) PCC Forum of SPRC and placed before the

Grid Code Review Panel in its next meeting.

6.10 Operational Event/ Accident Reporting

6.10.1 Introduction

This Section covers the details of requirement for the exchange of information relating to

operations and/or events in the total system, including the southern grid which have or

may have an operational effect on:

(i)

The Karnataka Grid in case of an operation and/or event occurring on a user system.

(ii) A user system in case of an operation and/ or event in the transmission system the

procedure for issue of warnings in the event of a risk of serious and wide spread

disturbances on the whole or part of Karnataka State power grid is set out in this

Section.

(iii) This section applies to SLDC, STU and all entities embedded within the State power

system that is under the control and supervision of SLDC.

6.10.2

Objective

The objective of this Section is to define the events/ incidents to be reported, the

reporting route to be followed and the information to be supplied to ensure a

consistent approach in reporting of incidents and accidents in the State

Transmission System.

6.10.3

Reportable Events

Any of the following events that could affect the State Transmission System requires

reporting:

Exceptionally high / low system voltage or frequency.

Serious equipment problem relating to major circuit breaker, transformer or bus

bar.

Loss of major Generating Unit, system split, State Transmission System breakaway or

Black Start.

Tripping of Transmission Lines, ICTs (Inter connecting transformer) and capacitor

banks.

Major fire incidents.

Force-Majeure condition like flooding or lightning etc.

Major failure of protection.

Equipment and Transmission Line overload.

Accidents-Fatal and Non-Fatal.

Load Crash / Loss of Load

Excessive Drawal deviations.

Minor equipment alarms.

The last two reportable incidents are typical examples of those which are of lesser

consequence, but which still affect the State Transmission System and can be reasonably

classed as minor. They will require corrective action but may not warrant management

reporting until these are repeated for sufficient time.

6.10.4 Reporting Procedure

1. Reporting Time for events and accidents

All reportable incidents occurring on lines and equipment of 33 kV and above and all

the lines on which there is the inter user flow affecting the State Transmission System

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.

The reporting User should submit a written confirmation to SLDC within one hour

of such oral report.

If the reporting incident is of major nature then the reporting User shall submit an

initial written report within two hours to SLDC. This has to be further followed up

by the submission of a comprehensive report within 24 hours of the submission of

the initial written report.

In other cases the reporting User shall submit a report within 5 (five) days to

SLDC.

2. SLDC shall call for a report from any User on any reportable incident affecting

other Users and STU, in case the same is not reported by such User whose equipment

might have

been

the source

of the reportable incident. The above shall not

relieve any User from the obligation to report events in accordance with Central Electricity

Authority (Measures Relating to Safety and Electric Supply) Regulations, 2010. The format

of such a report shall be as agreed by the State Grid Code Review Panel, but will typically

contain the following information:

Location of incident.

ii.

Date and time of incident.

iii.

Plant or equipment involved.

iv.

Details of relay indications with nature of fault implications.

Antecedent conditions like line flows, bus voltage, generation and demand supplies

and quantum interrupted and duration if applicable.

vi.

Amount of generation lost if applicable and its duration.

vii.

Brief description of incident.

viii.

weather condition during the incident.

ix.

Estimate of time to return to service.

Name of Organization.

xi.

Possibility of alternate arrangement of supply.

6.10.5

Reporting Form

The standard reporting form other than for accidents shall be as agreed from time to

time by the Grid Code Review Panel. A typical form is attached (APPENDIX-E).

6.10.6

Major Grid Incidence

(a)

Following a major grid incident, SLDC and other Users shall co-operate to

enquire and establish the cause of such failure and make appropriate

recommendations. SLDC shall report the occurrence of such major grid

failure to the SRPC \ Commission in writing as well as SRLDC immediately

for information and shall submit the enquiry report to the Commission within two

months of the incident. Analysis of major grid disturbance in the Intra-State

Power System soon after their occurrence shall be done by a Protection sub-

Committee constituted by STU. If the disturbance is of major nature the SRPC

will also conduct detailed analysis of the incident. The User, the generator, the

ESCOM and the STU shall furnish required data to SRPC.

(b)

Periodic Reports STU/Transmission licensee shall send a weekly report to

SLDC on the performance of their respective systems which should cover the

following information:

(i) Voltage profile at all Substations 66kV/110kV and above.

(ii) Average, maximum, minimum demand (both MW and MVAR) met at such

Substations.

(iii) Quantum and duration of load shed, with reasons.

(iv) Outage of major elements.

(v) Network constraints.

(vi) Daily energy consumed and energy exchanged by the DISCOM.

(c)

The SLDC shall post on its website a monthly performance report of the State as

a whole covering:

(i) Hourly demand met and generation for peak and minimum demand met on

every day. Also the average daily off-peak and peak demands met.

(ii) Daily average consumption.

(iii) Station wise daily maximum, minimum and average generation (MW), together

with daily energy generation.

(iv) Instances of non-compliance of the State Grid Code.

(v) Progress of construction of new generating units, lines and transformers.

(vi) Details of generation and transmission outages during the month.

6.10.7 Warnings

(i)

An oral warning shall be issued by SLDC and confirmed in writing as well, to the STU/

Transmission Licensee and the users, who may be affected when SLDC knows that there is

a risk of widespread and serious disturbance to the whole, or part of the total system.

(ii) Provided that sufficient time is available, the warning shall contain such information as

the SLDC considers reasonable, to explain the nature, extent of the anticipated

disturbance, to the user and STU/ Transmission Licensee, provided that such information

is available to SLDC.

(iii) Each user and STU/ Transmission Licensee, on receipt of such a warning, shall take

necessary steps to warn the operational staff and maintain their plant and apparatus in

the condition in which it is best able to withstand the anticipated disturbance for the

duration of the warning.

(iv) Scheduling and despatch may be affected during the period covered by such a warning.

6.10.8 Loss of communication with SLDC

(i)

In the event of loss of communication with SLDC, the provision made as above shall not

apply; instead, the following provision shall apply:

(ii) Each generating station shall continue to operate in accordance with the last despatch

instruction issued by SLDC, but shall use all reasonable endeavours to maintain the

system frequency at the target of 50 Hz, plus or minus 0.05 Hz by monitoring frequency,

until such time the new despatch instructions are received from SLDC.

6.10.9 Major Failure

Whenever a major failure takes place, STU/ Transmission Licensee and other users shall

cooperate, inquire and establish the cause of the failure and produce appropriate

recommendations. The STU shall submit the inquiry report to the Grid Code Review Panel.

Based on the analysis of report, the panel shall suggest modifications to the Grid Code, if

any, within two months of the incident to the Commission for approval.

6.10.10

Accident Reporting

Report of accidents shall be in accordance with the Section 161 of the Electricity Act,

2003 and the Rules framed thereunder. Reporting of accident and failure of supply or

transmission of electricity shall be in the specified form to the Commission and the

Electrical Inspector.

SECTION -7

CROSS BOUNDARY SAFETY

7.1 Introduction

This Section specifies the requirements for safe working practices for maintenance of

equipment 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.

7.2 Objective

The objective of this Section is to achieve an agreement on the principles of safety as

specified in the Central Electricity Authority (Measures Relating to Safety and Electric

Supply) Regulations, 2010, when working across the inter user boundary between one User

and another User.

7.3 Designated Officers/ Control Persons.

STU and all Users shall nominate suitable authorized persons to be responsible for

the co-ordination of safety across their boundary. These persons shall be referred to as

Designated Officer(s) (or control person(s).

7.4 Procedure

STU shall issue a list of Designated Officers (names, designations and telephone

numbers) to all Users who have a direct inter user boundary with STU or other Users.

This list shall be updated promptly whenever there is change of name, designation or

telephone number.

All Users with a direct inter user boundary with STU or other User system shall issue

a similar list of their Designated Officers to STU or other User(s), which shall be

updated promptly whenever there is a change in the list.

Whenever work across a cross boundary / an inter-user boundary is to be carried,

the Designated Officer of the User including STU itself, wishing to carry out work

shall personally contact the other relevant Designated Officer. If the Permit to Work

(PTW)/ Line Clear permit cannot be obtained personally, the Designated Officers shall

contact through telephone and exchange Code words to ensure correct identification

of both agencies.

Should the work extend over more than one shift, the Designated Officer shall ensure

that the relief Designated Officer is fully briefed on the nature of the work and the

code words in operation.

The Designated Officer(s) 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.

SLDC shall be the nodal agency in real time for clearing outages. STU and All users

shall approach SLDC for executing the maintenance work. Work shall not commence

until the Designated Officer of the User including STU itself, wishing to carry out the

work, is satisfied that all the safety precautions have been established. This

Designated Officer shall issue agreed safety documentation (PTW)/ line clear permit

to the working party to allow work to commence. The PTW /LCP in respect of

specified EHV lines and other interconnections shall be issued with the

consent of SLDC.

When work is completed and safety precautions are no longer required, the

Designated Officer who has been responsible for the work being carried out shall

make direct contact with the other Designated Officer to return the PTW/LCP. Return

of PTW in respect of specified EHV lines and interconnections shall be informed to

SLDC.

The equipment shall only be considered as suitable for connecting back to service

when all safety precautions are confirmed as removed, by direct communication

using code word contact between the two Designated Officers, and after ensuring that

the return of agreed safety documentation (PTW /LCP) from the working party has

taken place with prior approval of SLDC.

STU shall develop an agreed written procedure for inter-user boundary safety and

continually update it.

10.

Any dispute concerning inter-user boundary safety shall be resolved at the level of

STU, if STU is not a party. In case STU is a party, the dispute shall be referred to Grid

Code Review Panel and then to KERC.

7.5 Special Consideration

For inter-user boundary between STU and other Users circuits, all Users shall

comply with the agreed safety rules, which must be in accordance with Safety

Regulations or Rules framed under the Act.

Each Designated Officer shall maintain a legibly written safety logbook, in

chronological order, of all operations and messages relating to safety coordination

sent and received by him. All safety logs shall be retained for a period of not less than

10 years.

Each of the Distribution licensees connected to the transmission system shall

maintain an updated map of distribution system pertaining to the area fed by each

substation and exhibit the same in respective substation. The same shall be uploaded

in their websites.

7.6 Safety Standard and Line clear Permit:

7.6.1 Introduction

This Section sets out the procedure for the record of the Line Clear Permit and sets

guidelines for ensuring safety from electrical hazards to consumers, general public

and working personnel.

7.6.2 Objective

The main objective of this Section is to ensure safety to the working personnel of

STU/ Transmission Licensee and users and maintenance of proper records for the

issue of Line Clear Permits for allowing working personnel to carry out the works

safely.

7.6.3 Safety Standards

The Central Electricity Authority (Measures Relating to Safety and Electric Supply)

Regulations, 2010, issued separately formulates the precautions to be taken for

ensuring safety to the general public, consumers of electricity and the workmen. This

forms an integral part of the Grid Code and STU/ Transmission Licensee and all the

users shall comply with this standard.

STU/ Transmission Licensee shall prepare his own safety manual for the

Transmission Lines, substations based on this standard. For the guidance of the shift

operators, Operation and Maintenance Manuals for each substation shall be prepared

by the Licensee. These manuals shall contain all the maintenance and operation

schedules, based on the recommendations of the manufacturers of the various

equipment installed in the substation. These manuals shall be periodically reviewed

based on the experience gained and replacement of equipment. A maintenance

respective substations. These shall be updated as and when the maintenance work is

carried out and shall be periodically reviewed by the appropriate higher authority in

whose control the substation falls. Similar registers shall be maintained for the

Transmission Lines.

The Operation Manual shall clearly contain the details of isolation and earthing to be

provided for allowing work on the equipment. The Single Line Diagram (SLD) of the

substation indicating the positions of various isolating devices shall be prominently

displayed in the station. Charts showing the clearances from live parts (section

clearance) for working on the isolated equipment where workmen are allowed to work

shall be displayed prominently at each substation.

The danger boards as stipulated in the Central Electricity Authority (Measures

Relating to Safety and Electric Supply) Regulations, 2010 and in relevant Indian

Standards shall be displayed at the places approachable by the general public.

Regular maintenance shall be carried out on all the Transmission Lines in

accordance with IS: 5613 and or relevant standards and records of all these shall be

maintained. Wherever possible, hot line checking and replacement of failed insulators

shall be made before and after every monsoon.

All the equipment in the receiving stations and substations shall be maintained in

good condition as per the manufacturers' manuals and relevant Indian and/or

International Standards wherever available. The relays and circuit breakers shall be

checked for their proper operations whenever these are taken out for maintenance

purposes. The station batteries shall be maintained in good working condition by

carrying out routine checks and maintenance works. The DC system provided in all

these stations shall be properly maintained with no appreciable leakage current. An

online monitoring system for monitoring of leakage and detection of ground faults

shall be provided.

7.7 Format of Line Clear Permit (LCP)

The form under Annexure III and designated as requisition for Line Clear Permit shall

be used by the requesting safety coordinator, who is an authorized person. The form

under Annexure IV and designated as check list for Line Clear Permit and Line Clear

Permit shall be used at the time of issue of Line Clear Permit. The form under Annexure

V and designated as Line Clear Return shall be used for the return of the Line Clear

Permit after the work for which the Line Clear Permit was taken, is completed.

SECTION- 8

SCHEDULING AND DESPATCHING

8.1 Introduction

This part sets out the:

a) Demarcation of responsibilities between various Intra-State entities and SLDC in

Scheduling and Despatch;

b) The procedure for Scheduling and Despatch;

c) The reactive power and voltage control mechanism;

d) Complementary commercial mechanisms

8.2 Objective

This code deals with the procedures to be adopted for scheduling of the net injection/

drawals of Intra-State entities concerned on a day ahead basis with the modality of the flow

of information among the SLDC, ALDCs and Intra-State entities. The procedure for

submission of capability declaration by each Intra-State Generating Station (In-SGS) and

submission of requisition / drawal schedule by other State entities is intended to enable

SLDC to prepare the Despatch Schedule for each Generating station and drawal schedule for

each DISCOM. It also provides methodology of issuing real time Despatch / drawal

instructions and rescheduling, if required, to Intra-State entities along with the commercial

arrangement for the deviations from schedules, as well as, mechanism for reactive power

pricing. The methodology for scheduling and despatch of wind and solar generating plant

shall be as per the KERC (Forecasting, Scheduling, Deviation settlement and related matters

for wind and solar Generation sources) Regulations, issued and amended from time to time.

8.3 Scope

This code will be applicable to STU, SLDC, ALDCs, In-SGS, Distribution Licensees / Intra-

State entities, including generators/ captive generating plant/ IPPs, wind and solar

generating stations and other concerned persons in the State grid.

8.4 Demarcation of responsibilities:

The SLDC shall coordinate the scheduling of all such generating stations in the State, which

are not scheduled by RLDC under CERC Regulations as notified from time to time. The

SLDC shall also be responsible for such generating stations for:

real time monitoring of the stations operation;

ii.

checking that there is no gaming in its availability declaration;

iii.

revision of availability declaration and injection schedule;

iv.

switching instructions;

metering and energy accounting ;

vi.

issuance of deviation (as per DSM) accounts in its control area;

vii.

collections / disbursements of deviation (as per DSM) payments in its area;

viii.

Outage planning etc,.

2. Scheduling of a generating station supplying power to any State other than the host State

will be as provided in the Scheduling and Despatch Code of the IEGC.

3. The Regional grids will be operated as power pools with decentralized scheduling and

despatch, in which the States shall have operational autonomy, and SLDC shall have the

total responsibility for

scheduling / despatching States own generation (including generation of its

embedded licensees),

ii.

regulating the demand of its control area,

iii.

scheduling the drawal from the ISGS (within its share in the respective plants

expected capability)

iv.

permitting inter-State long term access, medium term and short term open access

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

regulating the net drawal of its control area from the regional grid in accordance with

the respective regulations of the CERC and

vi.

regulating the net drawal /injection of each DISCOM, Users of its control area as per

the schedules.

4. The system of each regional entity shall be treated and operated as a notional control area.

The algebraic summation of scheduled drawal from ISGS and from contracts through long

term access, medium-term and shortterm open access arrangements shall provide the

drawal schedule of each regional entity, and this shall be determined in advance on day-

ahead basis. The regional entities shall regulate their generation and/or consumers load

so as to maintain their actual drawal from the regional grid close to the above schedule.

Similarly, the SLDC shall regulate the generation and load in its control area, so as to

maintain its actual drawal close to its schedule from all the sources. Deviation, if any,

from the drawal schedule, shall be within the limits specified by the Central Electricity

Regulatory

Commission

(Deviation

Settlement

Mechanism

and

matters)

Regulations, 2014 for inter-State players and as per the limits specified by the KERC

(forecasting, scheduling, deviation settlement and related matters for wind and solar

generation sources) regulations, issued and amended from time to time for intra-State

players and it shall not cause system parameters to deteriorate beyond permissible limits

and shall not lead to unacceptable line loading. Such deviation from net drawal schedule

shall be priced through the deviation (as per DSM) mechanism as specified by the Central

Commission and State Commission from time to time.

5. The SLDC and distribution licensee(s) shall always endeavour to restrict the net drawal of

the State from the grid to within the drawal schedules, whenever the system frequency is

below the lower limit as specified by the CERC (IEGC) Regulations 2010 and its

amendments from time to time. The concerned Distribution Licensee, User, SLDC shall

ensure that their automatic demand management scheme mentioned in clause 5.4.2 of

IEGC, acts to ensure that there is no over drawal below frequency band limit as specified

by the CERC (IEGC) Regulations, 2010, and its amendments from time to time. If the

automatic demand management scheme has not yet been commissioned or not working,

then action has to be taken as per manual demand management scheme to ensure zero

over drawal when frequency is below the lower limit as specified by the CERC (IEGC)

Regulations, 2010, and its amendments issued from time to time.

6. The SLDC / STU / Distribution Licensees shall regularly carry out the necessary exercises

regarding short-term demand estimation for the State / area to enable them to plan in

advance as to how they would meet their consumers load without overdrawing from the

drawal schedule.

7. The In-SGS, other generating stations and sellers shall be responsible for power

generation/power injection generally according to the daily schedules advised to them by

the SLDC on the basis of the contracts/ requisitions received from the SLDC / buyers /

Power Exchanges.

8. The In-SGS would normally be expected to generate power according to the daily

schedules advised to them. The In-SGS may also deviate from the given schedules within

the limits specified in the DSM Regulations of CERC, depending on the plant and system

conditions. In particular, they may be allowed to generate beyond the given schedule under

deficit conditions as long as such deviations do not cause system parameters to deteriorate

beyond permissible limits and/or do not lead to unacceptable line loading. Deviations, if

any, from the ex-power plant generation schedules shall be appropriately priced in

accordance with DSM Regulations of CERC. In addition, deviations, from schedules

causing congestion, shall also be priced in accordance with the Congestion Charge

Regulations of CERC. The treatment of injection of infirm power by generating stations

during testing shall be in accordance with the Central Electricity Regulatory Commission

(Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-State

Transmission and related matters) Regulations, 2009, and the Central Electricity

Regulatory

Commission

(Deviation

Settlement

Mechanism

and

matters)

Regulations, 2014, and amendments issued from time to time.

9. Provided that when the frequency is higher than 50.05 Hz, the actual net injection shall not

exceed the scheduled despatch for that time block. Also, while the frequency is above the

limit as specified by the CERC (IEGC) Regulations 2010 and its amendments from time to

time, the In-SGS may (at their discretion) backdown without waiting for an advice from

SLDC / RLDC to restrict the frequency rise. When the frequency falls below limit as

specified by the CERC (IEGC) Regulations 2010 and its amendments from time to time, the

generation at all In-SGS (except those on peaking duty) shall be maximized, at least upto

the level to which can be sustained, without waiting for an advice from SLDC / RLDC

subject to the condition that such increase does not lead to unacceptable line loading or

system parameters to deteriorate beyond permissible limit.

10. However, notwithstanding the above, the SLDC may direct the DISCOMs / In-SGS to

increase/decrease their drawal/generation in case of contingencies e.g. overloading of

lines/transformers, abnormal voltages, threat to system security. Such directions shall

immediately be acted upon. In case the situation does not call for very urgent action, and

SLDC has some time for analysis, it shall be checked whether the situation has arisen

due to deviations from schedules, pursuant to short-term open access. These shall be got

terminated first, before an action, which would affect the scheduled supplies to the long

term and medium term customers is initiated.

11. For all outages of generation and transmission system, which may have an effect on the

regional grid, SLDC shall cooperate with other Regional entities to coordinate the action

to be taken through Operational Coordination Committee (OCC) for outages foreseen

sufficiently in advance and through RLDC (in all other cases), as per procedures finalized

separately by OCC. In particular, outages requiring restriction of ISGS generation and/or

restriction of ISGS share which the State can receive and curtailment of other long term

transactions shall be planned carefully to achieve the best optimization.

12. The In-SGS shall make an advance declaration of ex-power plant MW and MWh

capabilities foreseen for the next day, i.e., from 00:00 hrs to 24:00 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 generating stations

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 Administrative Price Mechanism

(APM) gas, Re-gasified-liquid natural gas (RLNG) and liquid fuel separately, and these

shall be scheduled separately.

13. While making or revising its declaration of capability, except in case of Run of the River

(with up to three hour pondage) hydro stations, the In-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.

14. It shall be incumbent upon the In-SGS 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 In-

SGS to explain the situation with necessary backup data.

15. The In-SGS shall be required to demonstrate the declared capability of its generating

station as and when asked by the State Load Despatch Centre. In the event of the In-SGS

failing to demonstrate the declared capability, such reduction in capacity shall be

informed by SLDC to the respective DISCOM who has PPA with such generator and the

concerned DISCOM shall reduce the capacity charges on pro-rata basis due to the

generator as a measure of penalty.

16. 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.

17. The STU or Transmission licensee shall install special energy meters (SEM) on all inter-

face points with the Distribution Licensees and other identified points between

Distribution Licensees for recording of actual net MWh interchanges and MVArh drawals.

The installation, operation and maintenance of special energy meters shall be in

accordance with the CEA (Installation and Operation of Meters) Regulations, 2006 and

amendments issued from time to time. All concerned entities (in whose premises the

special energy meters are installed) shall take weekly meter readings and transmit them

to the SLDC by scheduled time.

18. The operating log books of the generating station shall be available for review by the Grid

Code Review panel, Regional Power Committee and KERC. These books shall keep record

of machine operation and maintenance.

19. Hydro generating stations are expected to respond to grid frequency changes and inflow

fluctuations. The hydro generating stations shall be free to deviate from the given

schedule without causing grid constraint and a compensation for difference between the

actual net energy supply by the hydro generating station and the scheduled energy (ex-

bus) over day shall be made by the SLDC in the day ahead schedule for the 4

th day (day

plus 3).

20. SLDC shall periodically review the actual deviation from the Despatch and net drawal

schedules being issued, to check whether any of the inter-State or Intra-State entities are

indulging in unfair gaming or collusion. In case any such practice is detected, the matter

shall be reported to the KERC and CERC for further investigation.

8.5 Scheduling and Despatch procedure:

Scheduling and Despatch procedure including long-term access, medium- term and short-

term open access (to be read with provisions of Open Access Regulations as amended from

time to time). The scheduling procedure for medium-term open access transactions shall

be similar to the scheduling procedure for long-term access transactions and is as given

below:

1. All inter-State generating stations (ISGS) of the Southern Region and all intra-State

generating stations (In-SGS) of the State shall be duly listed on the SLDC web-site. The

station capacities and allocated /contracted Shares of different beneficiaries shall also

be listed out.

2. The State shall be entitled to a MW despatch upto (foreseen ex-power plant MW

capability for the day) x (States Share in the stations capacity) for all such stations in

case of ISGS and entitled to a MW despatch upto the foreseen ex-power plant MW

capability for the day from the In-SGS. In case of hydro-electric stations, there would

also be a limit on daily MWh despatch equal to (MWh generation capacity for the day) X

(States Share in the stations capacity) in case of ISGS and a limit on daily MWh

despatch equal to the MWh generation capacity for the day from In-SGS.

3. By 08 hours every day, the In-SGS shall inform the SLDC, the station-wise ex-power

plant MW and MWh capabilities foreseen for the next day, i.e., from 00:00 hrs to 24:00

hrs of the following day.

4. The above information of the foreseen capabilities of the In-SGS with corresponding MW

and MWh entitlements of the State, will be compiled by the SLDC every day for the next

day, and advised to the beneficiaries by 10.00 hours. The SLDC shall review it vis--vis

the foreseen load pattern and the States own generating capability including bilateral

exchanges, if any, and advise the RLDC by 15 hours its drawal schedule for each of the

ISGS in which the State has shares, long-term, medium-term bilateral interchanges

and approved short term bilateral interchanges.

5. Scheduling of collective transaction:

a. The individual transactions for State Utilities/intra-State entities shall be scheduled by

the SLDC. Power Exchange(s) will send the detailed breakup of each point of injection

and each point of drawal within the State to SLDC after receipt of acceptance from

NLDC. Power Exchange(s) will ensure necessary coordination with SLDC for scheduling

of the transactions.

b. Timeline for above activities will be as per detailed procedure for Scheduling of

Collective Transaction issued in accordance with the CERC (Open access in inter-

State transmission) Regulations, 2008 and the KERC[Terms and Conditions forOpen

Access]Regulations, 2004 as amended from time to time.

The

SLDC

shall

inform

any

modifications/changes

made

drawal

schedule/foreseen capabilities, if any, to RLDC by 22.00 hours or preferably earlier.

7. The declaration of the generating capability by hydro In-SGS shall include limitation on

generation during specific time periods, if any, on account of restriction(s) on water use

due to irrigation, drinking water, industrial, environmental considerations etc. The SLDC

shall periodically check that the generating station is declaring the capacity and energy

sincerely, and is not manipulating the declaration.

8. Since variation of generation in run-of-river power stations shall lead to spillage, these

shall be treated as must-run stations. All renewable energy power plants, except for

biomass power plants and non-fossil fuel based cogeneration plants whose tariff is

determined by the KERC shall be treated as MUST RUN power plants and shall not be

subjected to merit order despatch principles. Provided that, in case of low load

conditions, the SLDC shall regulate the generation of Renewable energy power plants to

maintain Grid security.

9. Run-of-river power station with pondage and storage type power stations are designed to

operate during peak hours to meet system peak demand. Maximum capacity of the

station declared for the day shall be equal to the installed capacity including overload

capability, if any, minus auxiliary consumption, corrected for the reservoir level. The

State Load Despatch Center shall ensure that generation schedules of such type of

stations are prepared and despatched for optimum utilization of available hydro energy

except in the event of specific system requirements / constraints.

10. The schedule finalized by the SLDC for hydro generating station, shall normally be such

that the scheduled energy for a day equals the total energy (ex-bus) expected to be

available on that day, as declared by the generating station, based on foreseen/planned

water availability/release. It is also expected that the total net energy actually supplied

by the generating station on that day will equal the declared total energy, in order that

the water release requirement is met.

11. While finalizing the above daily despatch schedules for the In-SGS, SLDC shall ensure

that the same are operationally reasonable, particularly in terms of ramping-

up/ramping-down rates and the ratio between minimum and maximum generation

levels.

12. While finalizing the drawal and despatch schedules as above, the SLDC shall also check

that the resulting power flows do not give rise to any transmission constraints. In case

any impermissible constraints are foreseen, the SLDC shall moderate the schedules to

the required extent. Any changes in the scheduled quantum of power which are too fast

or involve unacceptably large steps may be converted into suitable ramps by the SLDC.

13. In the event of bottleneck in evacuation of power due to any constraint, outage, failure or

limitation in the transmission system, associated switchyard and substations owned by

the State Transmission Utility or any other transmission licensee involved in intra-State

transmission (as certified by the SLDC) necessitating reduction in generation, the SLDC

shall revise the schedules which shall become effective from the 4

th time block, counting

the time block in which the bottleneck in evacuation of power has taken place to be the

first one. Also, during the first, second and third time blocks of such an event, the

scheduled generation of the In-SGS shall be deemed to have been revised to be equal to

actual generation, and the scheduled drawals of the beneficiaries shall be deemed to have

been revised accordingly.

14. In case of any grid disturbance, scheduled generation of all the In-SGS and scheduled

drawal of all the Distribution Companies shall be deemed to have been revised to be

equal to their actual generation/drawal for all the time blocks affected by the grid

disturbance. Certification of grid disturbance and its duration shall be done by the SLDC

/ RLDC.

15. Revision of declared capability by the In-SGS(s) having two part tariff with capacity

charge and energy charge (except hydro stations) and requisition by Distribution

Licensees 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 4

time block, counting the time block in which the request for revision has been received in

the RLDC to be the first one. Provided that SLDC may allow revision, of the declared

capacity (DC) at 6 hourly intervals effective form 00:00, 06:00,12:00 and 18:00 hours in

case of Run-of-the-River (ROR) and pondage based hydro generating stations, if there is

large variation of expected energy (MWh) for the day compared to previous declaration.

16. Notwithstanding anything contained in Regulation 8.5.15 of this Code, in case of forced

outage of a unit of a generating station (having generating capacity of 100 MW or more)

and selling power under Short Term bilateral transaction (excluding collective

transactions through power exchange), the generator or electricity trader or any other

agency selling power from the unit of the generating station shall immediately intimate

the outage of the unit along with the requisition for revision of schedule and estimated

time of restoration of the unit, to the SLDC. The schedule of beneficiaries, sellers and

buyers of power from this generating unit shall be revised accordingly. The revised

schedules shall become effective from the 4

th time block, counting the time block in which

the forced outage is declared to be the first one. The SLDC shall inform the revised

schedule to the seller and the buyer. The original schedule shall become effective from

the estimated time of restoration of the unit. However, the transmission charges as per

original schedule shall continue to be paid for two days. Provided that the schedule of the

buyers and sellers shall be revised after forced outage of a unit, only if the source of

power for a particular transaction has clearly been indicated during short-term open

access application and the said unit of that generating station goes under forced outage.

Provided also that, the provision of this sub-regulation in respect of revision of schedule

of electricity is applicable to traders and any other agencies (except the generating

station).

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.

17. If, at any point of time, the SLDC observes that there is need for revision of the schedules

in the interest of better system operation, it may do so on its own, and in such cases, the

revised schedules shall become effective from the 4

th time block, counting the time block

in which the revised schedule is issued by the SLDC as to be the first one.

18. To discourage frivolous revisions, SLDC may, at its sole discretion, refuse to accept

schedule/capability changes of less than two (2) percent 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.

Provided that in case of gas based In-SGS, for optimum utilization of gas, this shall be

permitted, i.e., in case of tripping of a unit, this gas may be diverted to another unit

using the same gas.

19. The State Load Despatch Centre shall also formulate the procedure for meeting

contingencies both in the long run and in the short run (daily scheduling).

20. Special dispensation for scheduling of wind and solar generation:

(i) Scheduling of Wind and Solar power generation plants would have to be done for the

purpose of computing deviation where the sum of generation capacity of such plants

are clubbed at a Pooling Station and connected through a line(s) at the connection

point to the transmission or distribution system is 10 MW and above and connection

point is 33 KV and above, and where PPA has not yet been signed. For capacity and

voltage level below this, as well as for old Wind farms (A wind farm is collection of

wind turbine generators that are connected to a common connection point commonly

known as Pooling Station), it could be mutually decided between the Wind Generator

and the transmission or distribution utility, as the case may be, if there is no existing

contractual agreement to the contrary. The schedule by wind power generating

stations (excluding collective transactions) may be revised by giving advance notice to

SLDC. The revisions by wind power generating stations and solar power generating

stations shall be effective from 4

th time block, the first being the time-block in which

notice was given. There may be one revision for each time slot of 1.5 hours starting

from 00:00 hours of a particular day subject to a maximum of 16 revisions during the

day or as specified in KERC (Forecasting, Scheduling, Deviation settlement and

related matters for wind and solar Generation sources) Regulations, issued and

amended from time to time.

(ii) The schedule of solar generation shall be given by the generator based on availability

of the generator, weather forecasting, season and normal solar generation curve and

shall be vetted by the SLDC. If SLDC is of the opinion that the schedule is not

realistic, it may ask the solar generator to modify the schedule.

(iii) SLDC shall maintain the record of schedule from renewable power generating

stations based on type of renewable energy sources i.e., wind or solar from the point

of view of grid security. While scheduling generating stations in the State, system

operator shall aim at utilizing available wind and solar energy fully.

21. Generation schedules and drawal schedules issued/revised by the State Load Despatch

Centre shall become effective from designated time block irrespective of communication

success.

22. For any revision of scheduled generation, including post facto deemed revision, there

shall be a corresponding revision of scheduled drawals of the beneficiaries.

23. A procedure for recording the communication regarding changes to schedules duly

taking into account the time factor shall be evolved by the SLDC.

24. When for the reason of transmission constraints e.g. congestion or in the interest of grid

security, it becomes necessary to curtail power flow on a transmission corridor, the

transactions already scheduled may be curtailed by the State Load Despatch Centre.

25. The short-term customer shall be curtailed first followed by the medium term customers,

which shall be followed by the long-term customers and amongst the customers of a

particular category, curtailment shall be carried out on pro-rata basis.

26. After the operating day is over at 24:00 hours, the schedule finally implemented during

the day (taking into account all before-the-fact changes in despatch schedule of

generating stations and drawal schedule of the ESCOMs and other users) shall be

issued by the SLDC. These schedules shall be the data for commercial accounting. The

average ex-bus capability for each ISGS shall also be worked out based on all before-

the-fact advice to SLDC.

27. Collective Transaction through Power Exchange(s) would normally be curtailed

subsequent to the Short Term Bilateral Transaction(s).

28. RLDC will curtail a Transaction at the periphery of the Regional Entities. SLDC shall

further incorporate the curtailment of intra-State Entities to implement the curtailment.

29. while availability declaration by the In-SGS 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 decimal at each control area boundary for each of the transactions, to have a

resolution of 0.01 MW and 0.01 MWh.

8.6

Reactive Power and Voltage Control

8.6.1 Reactive power compensation should ideally be provided locally, by generating Reactive

Power as close to the Reactive Power consumption as possible. The beneficiaries are

therefore expected to provide local VAr compensation/generation, such that they do not

draw VArs from the state grid, particularly under low-voltage conditions. However,

considering the present limitations, this is not being insisted upon. Instead, to discourage

VAr drawals by beneficiaries, VAr exchanges with Intra-State Transmission System shall

be priced as follows:

(a) The beneficiary pays for VAr drawal when voltage at the metering point is below

97%,

(b) The beneficiary gets paid for VAr return when voltage is below 97%,

(d) The beneficiary pays for VAr return when voltage is above 103%.

8.6.2 The charge/payment for VArs shall be at a nominal paise/kVArh rate as may be specified

by the Central Electricity Regulatory Commission from time to time for inter-State

transactions, and will be between the beneficiary and the State Pool Account for VAr

interchanges.

Notwithstanding the above, SLDC may direct a beneficiary to curtail its VAr

drawal/injection in case the security of grid or safety of any equipment is endangered.

8.6.3 The SLDC may issue direction to any generator within the State to increase Var

generation/absorption up to the machine capability limit. In general, the beneficiaries

shall endeavour to minimize the VAr drawal at an interchange point when the voltage at

that point is below 95% of the rated voltage and shall not return VAr when the voltage is

above 105%. Transformer taps at the respective drawal points may be changed to control

the VAr interchange as per the beneficiarys request to SLDC, but only at reasonable

intervals. A beneficiary may also request the SLDC for increase/decrease of VAr

generation at a generating station for addressing a voltage problem.

8.6.4 Switching in/out of all bus and line reactors throughout the state grid shall be carried out

as per instructions of SLDC. Tap changing on all transformers in STU system shall also be

done as per SLDCs instructions. The SLDC shall monitor the working of shunt capacitor

banks installed in the substations of STU or transmission licensee and Distribution

substation and direct them to switch in/out as and when required.

8.6.5 The generating station shall change generator-transformer taps and generate/absorb

Reactive Power as per the instructions of the SLDC, within capability limits of the

respective generating units, that is, without sacrificing the active generation required at

that time. No payments shall be made to the generating companies for such VAr

generation/absorption.

8.6.6 VAr exchanges directly between two beneficiaries on the interconnecting lines generally

addresses or causes 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:

(i) The two concerned beneficiaries may mutually agree not to have any

charge/payment for VAr exchanges between them on an interconnecting line,

(ii) 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 the KERC for VAr exchanges with the state transmission system. If

the agreed scheme requires any additional metering, the same shall be arranged

by the concerned beneficiaries,

(ii) The computation and payments for such VAr exchanges shall be effected as

mutually agreed between the two beneficiaries.

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 VI shall be applied.

SECTION- 9

PROTECTION AND METERING

9.1

General Protection Requirements

STU, In-SGS, other embedded generators, ESCOMs and other bulk consumers shall abide by

the provisions contained in Section 6 of the CEA (Technical Standards for Connectivity to the

Grid) Regulations, 2007.

Protection system shall be designed to reliably detect faults on various abnormal

conditions and provide an appropriate means and location to isolate the equipment or

system automatically. The protection system must be able to detect power system

faults within the protected zone.

ii.

Every element of the power system shall be protected by a standard protection system

having the required reliability, selectivity, speed, discrimination and sensitivity. Where

failure of a protective relay in the requesters system has substantial impact on the

grid, it shall connect an additional protection as backup protection besides the main

protection.

iii.

Notwithstanding the protection systems provided in the grid, the requester and user

shall provide requisite protections for safeguarding his system from the faults

originating in the grid.

iv.

Special protection scheme such as under-frequency relay for load shedding, voltage

instability, angular instability, generation backing down or islanding schemes may also

be required to be provided to avert system disturbances.

Protection co-ordination issues shall be finalized by the Regional Power Committee.

vi.

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

unless it is covered by the appropriate protection aimed at reliability, selectivity, speed

and sensitivity. The guidelines mentioned in the manual on protection of generators,

generator transformers, and 220 kV and 400 kV networks vide publication No. 274 &

296 of C.B.I.P and relevant Standards shall be kept in view.

vii.

All the generating companies and Distribution Licensees shall cooperate with the STU

and Transmission Licensee(s) to ensure correct and appropriate settings of protection

to achieve effective, discriminatory isolation of faulty line/equipment within the target

clearance times specified elsewhere in this Standard.

viii.

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

without consultation and agreement of all affected users. In case the protection has

been bypassed and/or disconnected by agreement due to any cause, the same should

be rectified and protection restored to normal conditions, as quickly as possible. If

agreement has not been reached, the electrical equipment shall be isolated forthwith.

9.2

Protection System Studies

A dedicated group is required to be constituted and trained by STU, transmission licensee (s)

and all Users to carry out computer aided studies for relay settings. It is also recommended

that for settings of critical transmission lines and corridors, the relay setting calculations be

validated by simulations on the Real Time Digital Simulator (RTDS) available with CPRI and

PGCIL.

STU may appoint a reputed consultant to carry out studies (in which manpower from STU

will also involve and get trained) to determine the relay settings for the complete network and

also carry out the settings at site in coordination with the CTU and STUs with time-bound

target for one time and the same shall be continued in house by STU.

9.3

Protection System Management:

In addition to technical issues related to protection, the management issues related to

protection system need to be addressed. In order to comprehensively address the protection

issues in the STU, transmission licensee (s) and all Users, following are the

recommendations.

9.3.1 Establishing Protection Application Department:

STU, transmission licensee(s) and all Users shall establish a Protection Application

Department with adequate manpower and skill set.

The protection system skill set is gained with experience, resolving various practical

problems, case studies, close interaction with the relay manufacturers and field

engineers.

Therefore, it is proposed that such people should be nurtured to have a long standing

career growth in the Protection Application Department.

The STU shall Constitute a committee containing experts in the field of protection,

indicated below for coordination and monitoring of protection functions for the entire

grid, duly making the required studies for the protective relay settings.,

The Committee shall be headed by an Engineer not below the Rank of Chief

Engineer Electrical, to conduct review meeting at least once in 3 months.

The Sub-Committee may be headed by the respective Superintending Engineers of

the protection Circles who will conduct review meeting once in every month and

bring the issues to the main Protection Committee for deliberation and decisions.

9.3.2 Relay Setting Calculations

The protection group should do periodic relay setting calculations as and when

necessitated by system configuration changes. A relay setting approval system should be

in place.

Relay setting calculations also need to be revisited whenever the minor configuration or

loading, changes in the system due to operational constraints. Feedback from the

field/substations on the performance of the relay settings should be collected and

settings should be reviewed and corrected if required.

Creating and maintaining data base of relay settings: Data regarding settings of relays in

their network should be compiled by the CTU and STUs and furnished to the RLDC and

SLDC respectively and a copy should also be submitted to RPC for maintaining the data

base.

9.3.3 Co-ordination with system study group, system planning group and other

Stakeholders

STU, transmission licensee (s) and all Users shall develop a strong system study group

with adequate manpower and skill-set that can carry out various system studies required

for arriving at system related settings in protection system in addition to others studies.

The Protection Application Department should closely work in coordination with the STU,

transmission licensee (s) and all Users system study group, system planning group, the

system operation group.

Wherever applicable, it should also co-ordinate and work with STU, transmission licensee (s)

and all Users to arrive at the proper relay setting calculations for the system as a whole. The

interface point relay setting calculations at CTU-STU, STU- DISCOMs, STU-GEN Companies,

CTU-GEN Companies and also generator backup relay setting calculations related to system

performance should be periodically reviewed and joint concurrence should be arrived.

The approved relay settings should be properly documented. Any un-resolved issues among

the stakeholders should be taken up with the RPC and resolved.

9.3.4 Simulation testing for checking Dependability and Security of Protection System for

Critical lines and series compensated Lines

The protection system for critical lines, all series compensated lines along with

interconnected lines should be simulated for intended operation under normal and abnormal

system conditions and tested for the dependability and security of Protection system. The

RTDS facilities available in the country like at CPRI, POWERGRID and other places should

be made use of by the STU, transmission licensee(s) and all Users of the Grid for this

purpose.

The network model should be periodically updated with the system parameters, as and when

network changes are incorporated.

9.3.5 Adoption of Relay Setting and Functional verification of Setting at site

The Protection Application Department shall ensure through field testing group that the

final relay settings are exactly adopted in the relays at field.

There should be clear template for the setting adoption duly authorized and approved by

the field testing in-charge.

No relay setting in the field shall be changed without proper documentation and approval

by the Protection Application Department.

The Protection Application Department shall periodically verify the implemented setting at

site through an audit process.

Protection application department should also maintain a log of all protection operations.

This record will be assets record and assist in future upgradation of protection system.

9.3.6 Storage and Management of Relay settings

With the application of numerical relays, increased system size and volume of relay setting,

associated data to be handled is enormous. It is recommended that utilities shall evolve

proper storage and management mechanism (version control) for relay settings.

Along with the relay setting data, IED configuration file should also be stored and managed.

9.3.7 Root Cause Analysis of Major Protection Tripping (Multiple Element Outages) along

with corrective & Improvement Measures

The routine tripping of transmission lines, transformers and generating units are

generally analyzed by the field protection personnel. For every tripping, a trip report

along with an associated DR and event logger file shall be generated. However, for major

tripping in the system, it is recommended that the protection application department

shall perform the root cause analysis of the event.

The root cause analysis shall address the cause of a fault, any mal-operation or non-

operation of relays, protection scheme etc.

The root cause analysis shall identify corrective and improvement measures required in

the relay setting, protection scheme or any other changes to ensure system security,

reliability and dependability of the protection system.

The Protection Application Department shall keep proper records of corrective and

improvement actions taken.

9.3.8 Performance Indices: Dependability & Security of Protection System

The key performance indices should be calculated on yearly basis on the dependability and

security of protection system as brought out in CBIP manual.

9.3.9 Periodic Protection Audit

Periodic audit of the protection system shall be ensured by the Protection Application

Department.

The audit shall broadly cover the three important aspect of protection system, namely the

philosophy, the setting, the healthiness of Fault Clearing System.

All the generating companies, STU, transmission licensee (s) and all Users shall co-operate

with Regional Power Committee to conduct protection audits and shall attend to the defects/

shortcomings/ observations of such protection audit on the advice of RPC.

9.3.10 Regular Training and Certification

The members of the Protection Application Department shall undergo regular training to

enhance & update their skill sets.

ii.

The training modules shall consist of system studies, relaying applications, testing &

commissioning of relays and Certification of protection system is strongly

recommended.

9.4

Fault Clearance Time

From stability considerations, 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, shall be as specified in the CEA (Grid Standards) Regulations, 2010, amended

from time to time as shown below:

Voltage Class

Target Clearance Time

400kV

100 milliseconds

220kV

160 milliseconds

For 110kV/66kV 350 msec is suggested instead of 160 msec in view of non-availability of

carrier protection, zone-2 faults will get cleared after the set time delay. For 110kV/66kV

lines, zone-2 time delay of 300 msec, if Local Breaker Backup (LBB) is available in the next

bus and time delay of 200 msec if LBB is not available, may be adopted.

9.5

Generator Protection Requirements

All generating units and all associated electrical equipment of the generating company

connected to the Transmission System shall be protected by adequate protection, as per the

CEA (Technical Standards for Connectivity to the Grid) Regulations, 2007 and CBIP manual

on Protection of Generators, Generator Transformers and 220kV and 400 kV networks vide

publication 274 (revised), so that, the Transmission System does not suffer due to any

disturbances originating at the generating unit. In case of inconsistency in protection aspects

between CEA and CBIP, the provisions of CEA shall prevail.

9.6

Transmission Line Protection Requirements

Every HV/EHV/UHV line emanating from a generating station or a substation or a switching

station shall necessarily have distance protection along with other protection as per the

Central Electricity Authority (Technical Standards for Connectivity to the Grid) Regulations,

2007 and CBIP manual on Protection of Generators, Generator Transformers and 220kV and

400 kV networks vide publication 274 (revised).

(a) 400 kV lines: - These lines shall have two main distance protections, viz. Main I and

Main II with permissive inter-trip for remote earth fault. Three zone numerical non-

switched distance protection with permissive inter-trip for accelerated tripping at remote

end in case of zone 2 fault as Main I protection shall be provided. Main II protection shall

be similar fast protection using direction comparison relay scheme. In addition to the

above, single pole tripping and single shot single pole auto reclosing after an adjustable

dead time shall be provided for single phase to ground faults. Three pole tripping and no

auto reclose for multiphase faults. In addition to the above, back-up protection with OCR

and EFR shall be provided.

(b) 220 kV lines: - These lines shall have Main I and Main II protection which are of

different manufacture or whose characteristics are based on different algorithms with

permissive inter-trip for remote earth fault. Three zone numerical non-switched distance

protection, with permissible inter-trip shall be provided in Main I or Main II. DEF

functionality shall be enabled for covering high resistive faults. The same shall be

coordinated with zone protection and Auto reclose timings.

Single pole tripping and Single Shot Three Pole Auto-reclosing with adjustable dead-time

shall be provided for the stability of the power system for single phase to ground faults.

For multiphase faults three pole tripping with no auto reclose shall be provided.

inter-trip for accelerated tripping at the remote end in case of zone 2 protection shall be

provided as main protection. The back-up will be directional three-phase over current

and earth fault protection.

(d) Differential protection for short transmission lines less than 10 km distance: The

recommendation of SRPC to provide differential protection using fiber optic/any other

reliable communication channel between the two ends as one of the main protection and

distance protection with reduced zone one setting as main two protections for short

220kV lines less than 10 Km line and 110/66kV lines of length less than 5 Km is to be

adopted by STU to have a reliable protection for EHV lines.

(e) Continuity of ground wires: - Ground wires help to reduce the apparent tower footing

resistance. It is to be noted that all HV/EHV and UHV lines need one or more than one

ground wire at a certain height above the conductor to provide the desired shielding. The

continuity of such ground wires above the entire length of the transmission lines is

necessary to have effective line protection. The tower footing impedance parameters are

required to be kept as low as practically feasible and may need special measures like

counter poises and other known methods of reducing the footing impedance.

(f)

Busbar Protection: - Adequate busbar protection for the station busbar sections in all

400 kV and 220 kV class substations shall be provided.

(g) Local Breaker Backup Protection (LBB): - In the event of any circuit breaker failing to

trip on receipt of trip command from protective relays, all circuit breakers connected to

the bus section to which the faulty circuit breaker is connected are required to be tripped

with a time delay of 200milli seconds.

(h) Recommendations for provisions of auto-reclosing.

Single phase high speed auto-re closure (HSAR) at 400 kV and 220 kV lines including the

lines emanating from Generating Stations with a dead time of 1000 milli second is

recommended for adoption.

Note: Recommended methodology for relay settings for uncompensated and compensated

lines, use of system studies to analyse distance relay behaviour, maintaining operation of

power station auxiliary system of nuclear power plants, coordination between system study

group and protection engineers and simulation studies are presented in the annexure-VII &

VIII onwards which shall be referred to by the STU and Users.

General Information of the substation details for facilitating protection audit which should

indicate the details of instrument transformers, availability of Protection System, substation

protection and monitoring equipment, DC supply, line protection, transformer protection and

reactor protection as shown in annexure -IX.

The check list to enable audit of practices followed in protection application & criteria used

for setting calculations in 220kV, 400kV & 765kV substations shall be used as per the

annexure XI.

9.7 Power Transformer Protection requirements

a. 400 kV and 220 kV class Power Transformers: - These shall be provided with

differential protection, restricted earth fault protection, over flux protection, Bucholtz

protection, PRV, oil and winding temperature protection along with IDMT over current

protection and earth fault protection as backup protection for HV & LV and non-

directional over current protection for tertiary winding. Over fluxing relays shall be

provided on transformers having rating more than 100MVA capacity. Appropriate fire

protection for all power transformers as per CBIP/CEA specifications shall be provided.

b. 110 kV and 66 kV class power transformers: These shall have differential protection,

restricted earth fault protection, Bucholtz protection, and winding/oil temperature

protection. They shall also have directional over current as back-up protection with an

instantaneous element. In addition to the above, pressure relief valves/diaphragms shall

be provided for all the power transformers. Appropriate fire protection for all the power

transformers as per CBIP/CEA specifications shall be provided.

c. Distribution System: For smaller transformers of HV class on the distribution system,

differential protection shall be provided for 5 MVA capacities and above, along with back-

up time lag over current and earth fault protection with directional feature for parallel

operation. Transformers of capacity less than 5 MVA shall be protected by time lag over

current, earth fault and instantaneous restricted earth fault relays. In addition, all such

transformers shall be provided with gas operated relays, winding and oil temperature

protection.

d. Distribution Lines: All the 33 kV and 11 kV lines at Connection Points/ Interface Points

shall be provided with a minimum of over current and earth fault relays.

e. Plain Radial Feeders: Non-directional over current and earth fault relays with suitable

settings to obtain discrimination between adjacent relay settings.

f. Parallel/Ring Feeders: Directional time lag over current and earth fault relay.

g. Inadvertent Flow: - When two systems are operating in parallel with floating tie-line, it

may not be possible to have tie-line absolutely floating because of dynamics of network

parameters and there will be a flow of energy from one system to another system. Such

inadvertent flow shall be accounted for the purpose of commercial billing.

9.8 Metering

Meters shall be provided as specified in the Central Electricity Authority (Installation and

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

SECTION- 10

Miscellaneous

Issue of orders and practice directions

Subject to the provisions of the Electricity Act, 2003 and these Regulations, the Commission may,

from time to time, issue orders and practice directions with regard to the implementation of the

Regulations and procedures to be followed.

10.1 Power to remove difficulties

(i)

In case of any difficulty in giving effect to any of the provisions of these regulations, the

Commission may by general or special order, direct the Open Access Customers, generators

and the licensees to take suitable action, not being inconsistent with the provisions of the

Electricity Act, 2003, which appears to the Commission to be necessary or expedient for the

purpose of removing the difficulty.

(ii) The Open Access Customers, generators and the licensees may make an application to the

Commission and seek suitable orders to remove any difficulties that may arise in

implementation of these Regulations.

10.2 Power to amend:

The Commission may from time to time add, vary, alter, modify or amend any

provisions of these Regulations after following the necessary procedures.

The Commission may by general or special order, for reasons to be recorded in writing, and after

giving an opportunity of hearing the parties likely to be affected by grant of relaxation, may relax

any of the provisions of these Regulations on its own motion or on an application made before it

by an interested person.

By order of the Commission

Secretary

KARNATAKA ELECTRICITY REGULATORY COMMISSION

ANNEXURE-I

SITE RESPONSIBILITY SCHEDULE

Name of Power Station / Sub Station:

Site Owner:

Site Manager:

Tel. Number:

Fax Number:

Item of

Plant /

Apparatus

Plant

Owner

Safety

responsibility

Control

responsibility

Operation

responsibility

Maintenance

responsibility

remarks

_____KV

Switchyard

All

equipment

including

bus bars

feeders

Generating

units

ANNEXURE-II

INCIDENT REPORTING

First report

Date:______

Time:______

S.N

Item

Details

Date and time of incident

Location of incident

Type of incident

System parameters before the incident (voltage, frequency, flows,

generation etc.)

Relay indications received and performance of protection

Damage to equipment

Supplies interrupted and duration, if applicable

Amount of generation lost, if applicable

Possibility of alternate supply arrangement

Estimate of time to return to service

Cause of incident

Any other relevant information and remedial action taken

Recommendations for future improvement / repeat incident

Name of the organization

ANNEXURE-III

Requisition for Line Clear Permit (Clause No. 7.7 )

Date

Time ..

I Mr/Ms. ---------------------- request Line Clear Permit on the following HT/EHT line/equipment

HV/EHV Apparatus/Line Identification:

Details of works to be carried out:

Estimated time required for completion:

Name and Signature .

. .

(Requesting Safety Coordinator) (In-charge of crew)

Designation .

Date .

(For use in substation from where Line Clear Permit will be issued)

(a) Line Clear Permit issued:

Yes/No

(b) Number and date of issue

(Code No.):

(d) Date & time of return:

(e) Remarks: see check list LCP - H

Receipt of LCP

I have received confirmation from .. (Name of issuing safety coordinator) at

.(location) that the safety precautions have been established and the

instructions will not be issued at his location for their removal until his LCP-H is cancelled.

Name and Signature

(Requesting safety coordinator)

In charge of the crew at ..(time) on (date)

(To be printed on the reverse of LCP-H: Checklist of Line Clear Permit)

Conditions:

(a) This permit is valid only for working in the feeder/equipment mentioned herein and not in any

other feeder/equipment.

(b) Only authorised persons are allowed to work on feeders/equipment for which the permit has

been issued.

(d) Before touching any part of the feeder/equipment, the same should be earthed at two points on

either side through standard discharge rods connected with good earth. Temporary earthing may

only be removed after completion of all works and after all the men have come down from the

feeder/equipment.

(e) Work should be so planned that the Line Clear is returned before or at the time indicated. If

unavoidable delay is anticipated, advance information should be given to the location from where

the Line Clear is issued.

(f) Before return of the Line Clear, it should be ensured that all the men, materials, tools/tackles

etc., on the line have returned and reported that all temporary earths are removed. There should

also be a check on the material, tools and plant issued for the work to ensure that nothing is left

behind on the line or equipment.

(g) Only authorised persons should return Line Clear.

(h) In case the Line Clear cannot be returned in person, the same may be returned to the Line Clear

Issuing Authority over telephone by naming the code words assigned and the telephone number

which is used for naming the code words assigned. In case two or more different code words are

issued to the two or more persons in whose favour the permit is given, those persons must jointly

return the Line Clear by naming their own code words. The Line Clear Return will not be deemed to

be accepted unless returned by all these persons.

(i) The Line Clear issuing authority should go over the checklist of Line Clear Return before

accepting it.

(j) If Line clear is returned over telephone, the Line Clear return form duly filled and signed should

be sent to the Line Clear issuing authority by post immediately for record.

(k) Control person should keep all the required data of LCP issued and LCR received. He should

monitor and keep specific note in the log sheet when more than one LCP are issued on same line/

equipment/bay along with code words.

<<<<<<>>>>>>

Annexure IV

Check list for Line Clear Permit and Line Clear Permit (Clause No. 7.7)

LCP-H Number. DatedTime..................

Check List of the Line Clear Permit:

(a) Name of location for which line clear is issued

(b) Reference and authority requisitioning Line Clear: (Indicate original LCP-G number including

suffix and prefix)

(d) Sources from which the line/equipment is charged

(e) Number/name of circuit breaker/isolating switch open at each of above sources

(f) Whether confirmed that the line is disconnected at both ends

(g) Whether line is earthed at both ends

(h) Whether circuit breaker truck removed in case of indoor switchgear controlling the

feeder/equipment for which line clear is given

(i) Whether fuses of control supply voltage of the circuit breaker/isolating switches controlling the

feeder/equipment for which line clear is given are removed and kept in safe custody

(j) Time of issue of Line Clear Permit and LCP-G No.

(k) Name of requesting safety coordinator on whom LCP-G is issued

(l) Approximate time for returning LCP-G as ascertained from the requesting coordinator

Name and Signature..

(Issuing Safety Coordinator)

Designation.

Line Clear Permit

LCP - G No. I, Mr/Ms.------------- (Issuing Safety Coordinator) do hereby issue

permission to Mr/Ms.-------------- (Requesting Safety Coordinator) for carrying out works as per

requisition No..date..time ........

The EHV/ HV Line/equipment herein described is declared safe. The permission is subject to the

conditions given in LCP-F.

Name and Signature..

(Person issuing Line Clear Permit)

Designation.

<<<<<<>>>>>>

Annexure V

Line Clear Return (Clause No.7.7 )

LCP - I Number. Date .Time..............

LCP-H No.. Dated. I, Mr/Ms. --------------- hereby return the LCP No. -----at -------

(time) for the following HT/EHT Line/Apparatus.

I declare that all the crew who were sent on work have been withdrawn, temporary earth(s) removed,

all repair tools and materials checked and the feeders/equipments mentioned below are safe to be

energised.

(a) HV/EHV Apparatus/Line Identification:

(b) Safety precaution no longer required:

achieved]

(d) Earthing [State location at which earthing was established and identify each point of earthing

(e) Details of work done

Check list to be ticked off:

(a) Whether all men withdrawn: Yes/No

(b) Whether all temporary earth removed: Yes/No

(d) Code Number (If used when Line Clear is returned over phone) -----------------

Name and Signature.

(Requesting Safety Coordinator)

Designation

In-charge of Crew ------------------------

(Designation)

<<<<<<>>>>>>

Annexure VI

Payment for Reactive Energy Exchanges on Lines Owned By Individual Entities (Clause No.

8.6.6)

Case- 1: Interconnecting line owned by Entity A

Metering Point: Substation of Entity B

Case- 2: Interconnecting line owned by Entity B

Metering Point: Substation of Entity A

Entity B pays to Entity A for

(i)

Net VArh received from Entity A while voltage is below 97%

(ii)

Net VArh supplied to Entity A while voltage is above 103%

Note: Net VArh and net payment may be positive or negative

Case- 3: Interconnecting line jointly owned by Entity A & B

Metering Point: Substations of Entity - A & Entity - B

Entity A

Entity B

Entity A

Entity 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) State-B pays to State-A for X1 or X3, whichever is smaller in magnitude, and

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

Note:

Net VArh and net payment may be positive or negative.

In case X1 is positive and X3 is negative, or vice-versa, there would be no payment under (i)

above.

In case X2 is positive and X4 is negative, or vice-versa, there would be no payment under (ii)

above.

<<<<<<>>>>>>

Annexure-VII

(Page 1/8)

RECOMMENDED METHODOLOGY FOR RELAY SETTINGS OF UNCOMPENSATED TRANSMISSION

LINES

1. ZONE-1 REACH SETTING:

Zone-1: To be set to cover 80% of protected line length. Set zero sequence compensation

factor KN as (Z0 Z1) / 3Z1.

Where:

Z1= Positive sequence impedance of the protected line

Z0 = Zero sequence impedance of the protected line

Note: With this setting, the relay may overreach when parallel circuit is open and grounded

at both ends. This risk is considered acceptable.

2. ZONE-2 REACH SETTING:

Zone-2: To be set to cover the next 20% of length of principal line section plus 50% of

shorter adjacent line to take care of under reaching due to mutual coupling effect. Set KN as

(Z0 Z1) / 3Z1.

Sometimes impedance so selected might enter the next voltage level. However, un-selectivity

in the Zone-2 grading is generally not to be expected when in-feeds exist at the remote sub-

station as they reduce the overreach considerably.

This holds good for majority of the cases, however, for certain cases, where in-feed from

other feeder at the local bus is not significant, Zone-2 of remote end relay may see the fault

at lower voltage level. Care has to be taken for all such cases by suitable time delay.

3. ZONE-3 REACH SETTING:

Zone-3 distance protection can offer time-delayed remote back-up protection for an adjacent

transmission circuit. To achieve this, Zone-3 distance elements must be set according to the

following criteria where possible.

Zone-3 to be set to cover the next 20% of the length of principal line section plus 100% of

longest adjacent line.

Annexure-VII

(Page 2/8)

However, in such case where Zone-3 reach is set to enter into next lower voltage level, Zone-

3 timing shall be coordinated with the back-up protection (Directional over current and

earth fault relay) of power transformer. Where such coordination cannot be realized, it is

recommended to carry out simulation studies for relay reach and time coordination and

suitable solution may be devised. Some of the typical solution can be application of back up

distance protection for power transformer, duplicated protection for downstream 220kV

feeders or special protection scheme logic. Similar issues, if encountered for Zone-2 reach

setting, should also be addressed in the above manner.

RESISTIVE REACH SETTING

For phase to ground faults, resistive reach should be set to give maximum coverage

considering fault resistance, arc resistance & tower footing resistance. It has been

considered that ground fault would not be responsive to line loading.

For Zone-1 resistive reach, attention has to be given to any limitations indicated by

manufacturer in respect of resistive setting vis-a-vis reactance setting to avoid overreach due

to remote in-feed. It is recommended to study the impact of remote end in-feed for expected

power flow and fault resistance on the extent of overreach. This is particularly important for

short lines.

In case of phase to phase fault, resistive reach should be set to provide coverage against all

types of anticipated phase to phase faults subject to check of possibility against load point

encroachment considering minimum expected voltage and maximum load expected during

short time emergency system condition.

It is recommended that all the distance relays should have quadrilateral / polygon

characteristic. For relays having Mho characteristic, it is desirable to have load

encroachment prevention characteristic or a blinder.

In the absence of credible data regarding minimum voltage and maximum load expected for

a line during emergency system condition, following criteria may be considered for deciding

load point encroachment:

•

Maximum load current (Imax) may be considered as 1.5 times the thermal rating of

the line or 1.5 times the associated bay equipment current rating (the minimum of the

bay equipment individual rating) whichever is lower. (Caution: The rating considered is

approximately 15 minutes rating of the transmission facility).

•

Minimum voltage (Vmin) to be considered as 0.85pu (85%).

Due to in-feeds, the apparent fault resistance seen by relay is several times the actual value.

This should be kept in mind while arriving at resistive reach setting for Zone-2 and Zone-3.

Annexure-VII

(Page 3/8)

5. ZONE-2 TIMER SETTING:

A Zone-2 timing of 0.4 seconds (considering LBB time of 200mSec, CB open time of 60ms,

resetting time of 30ms and safety margin of 60ms) is recommended. However, if a long line is

followed by a short line, then a higher setting (typically 0.6second) may be adopted on long line

to avoid indiscriminate tripping through Zone-2 operation on both lines.

For special cases, following shall be the guiding philosophy:

Since Zone-2 distance protection is set to overreach the circuit it is intended to protect, it will

also be responsive to faults within adjacent power system circuit. For this reason the time delay

for Zone2 back-up protection must be set to coordinate with clearance of adjacent circuit

faults, within reach, by the intended main protection or by breaker fail protection.

The following formula would be the basis for determining the minimum acceptable Zone-2 time

setting:

tZ2 > tMA + tCB + tZ2reset + tS

Where:

tZ2 =

Required Zone-2 time delay

tMA =

Operating time of slowest adjacent circuit main protection or Circuit Local back-up

for faults within Zone-2 reach

tCB =

Associated adjacent circuit breaker clearance time

tZ2reset = Resetting time of Zone-2 impedance element with load current present

tS = Safety margin for tolerance (e.g. 50 to 100ms)

Unequal lengths of transmission circuit can make it difficult to meet the Zone-2 secondary

reach setting criterion. In such cases it will be necessary to co-ordinate Zone-2 with longer

time delay. The time tMA in equation must be the adjacent circuit Zone-2 protection operating

time.

6. ZONE-3 TIMER SETTING

Zone-3 timer should be set so as to provide discrimination with the operating time of relays

provided in subsequent sections with which Zone-3 reach of relay being set, overlaps. Typical

recommended Zone-3 time is 0.8 to 1.0 second.

For Special cases, where co-ordination between long and short lines is required, following

formula would be the basis for determining the minimum acceptable Zone-3 time setting:

tZ3 > tMA + tCB + tZ3reset + tS

Where:

tZ3 = Required Zone-3 time delay

tMA = Operating time of slowest adjacent circuit local back-up protection

tCB = Associated adjacent circuit breaker clearance time

tZ3reset = Resetting time of Zone-3 impedance element with load current present

tS =

Safety margin for tolerance (e.g. 50 to 100milliseconds)

Annexure-VII

(Page 4/8)

7. LOAD IMPEDANCE ENCROACHMENT

With the extended Zone-3 reach settings, that may be required to address the many under

reaching factors already considered, load impedance encroachment is a significant risk to long

lines of an interconnected power system. Not only the minimum load impedance under expected

modes of system operation be considered in risk assessment, but also the minimum impedance

that might be sustained for seconds or minutes during abnormal or emergency system

conditions. Failure to do so could jeopardize power system security.

Ideal solution to tackle load encroachment may be based on the use of blinders or by suitably

setting the resistive reach of specially shaped impedance elements or by use of polygon type

impedance elements.

It is recommended that all the distance relays should have quadrilateral / polygon

characteristic. For relays having Mho characteristics, it is desirable to have load encroachment

prevention characteristics or a blinder.

In the absence of credible data regarding minimum voltage and maximum load expected for a

feeder during emergency system condition, following criteria may be considered for deciding

resistive reach / blinder setting to prevent load point encroachment:

•

Maximum load current (Imax) may be considered as 1.5 times the thermal rating of the line

or 1.5 times the associated bay equipment current rating ( the minimum of the bay

equipment individual rating) whichever is lower. (Caution: The rating considered is

approximately 15 minutes rating of the transmission facility).

•

Minimum voltage (Vmin) to be considered as 0.85pu (85%).

•

For setting angle for load blinder, a value of 30 degree may be adequate in most cases.

For high resistive earth fault where impedance locus lies in the Blinder zone, fault clearance

shall be provided by the back-up directional earth fault relay.

8. ZONE-4 SUBSTATION LOCAL BACKUP PROTECTION SETTINGS

Zone-3 distance protection is usually targeted to provide only remote back-up protection. In

such a case, the distance relay may be provided with an additional zone of reverse-looking

protection (e.g. Zone-4) to offer substation-local back-up protection. The criterion for setting

Zone-4 reverse reach would be as under.

•

The Zone-4 reverse reach must adequately cover expected levels of apparent bus bar fault

resistance, when allowing for multiple in feeds from other circuits. For this reason, its

resistive reach setting is to be kept identical to Zone-3 resistive reach setting.

With a reverse reach setting of less than the Zone-1 reach of distance protection for the shortest

line connected to the local bus bar, the Zone-4 time delay would only need to co-ordinate with

bus bar main protection fault clearance and with Zone-1 fault clearance for lines out of the

same substation. For this reason this can be set according to the Zone-3 time.

Annexure-VII

(Page 5/8)

9. USE OF SYSTEM STUDIES TO ANALYSE DISTANCE RELAY BEHAVIOUR

Often during system disturbance conditions, due to tripping of one or more trunk lines, some

lines get overloaded and the system voltage drops. During such conditions the back-up distance

elements may become susceptible to operation due to encroachment of impedance locus in to

the distance relay characteristic.

While the ohmic characteristic of a distance relay is independent of voltage, the load is not

generally constant-impedance. The apparent impedance presented to a distance relay, as the

load voltage varies, will depend on the voltage characteristic of the load. If the low voltage

situation resulted from the loss of one or more transmission lines or generating units, there may

be a substantial change in the real and reactive power flow through the line in question. The

combination of low voltage and worsened phase angle may cause a long set relay to operate

undesirably either on steady state basis, or in response to recoverable swings related to the

initiating event.

The apparent impedance seen by the relay is affected by in-feeds, mutual coupling and therefore

the behavior of distance relay during various system condition needs to be studied wherever

necessary to achieve proper relay coordination.

It is desirable and hence recommended that system studies are conducted using computer-

aided tools to assess the security of protection by finding out trajectory of impedance in various

zones of distance relay under abnormal or emergency system condition on case-to-case basis

particularly for critical lines / corridors.

In addition, the settings must be fine-tuned, simulating faults using Real Time Digital Simulator

on case-to-case basis particularly for critical lines / corridors.

Such facilities available at CPRI, POWERGRID or elsewhere in the country should be used for

protection related studies.

10. DIRECTIONAL PHASE OVER CURRENT PROTECTION

Directional phase over current relays are still being used as back-up protection for 220kV

transmission lines by many utilities. In view of time coordination issues and increased fault

clearance time in the event of failure of main distance protection, it is recommended that for all

220kV lines also main-1 and main-2 protections similar to 400kV lines be provided.

11.DIRECTIONAL GROUND OVER CURRENT PROTECTION (DEF) SETTINGS

Normally this protection is applied as a supplement to main protection when ground fault

currents may be lower than the threshold of phase over current protection. It might also be

applied as main protection for high resistance faults.

The ground over current threshold should be set to ensure detection of all ground faults, but

above any continuous residual current under normal system operation. Continuous residual

current may arise because of following:

•

Unbalanced series impedances of untransposed transmission circuits

•

Unbalanced shunt capacitance of transmission circuits.

•

Third harmonic current circulation.

Annexure-VII

(Page 6/8)

Various types of directional elements may be employed to control operation of ground over

current (zero sequence over current) protection response. The most common approach is to

employ Phase angle difference between Zero sequence voltage and current, since the relaying

signals can easily be derived by summing phase current signals and by summing phase voltage

signals from a suitable voltage transformer.

However, this method is not suitable for some applications where transmission lines

terminated at different substations, run partially in parallel. In such cases following type of

directional control is recommended to be used for the directional earth fault relay.

Relative phase of negative sequence voltage and current

To ensure proper coordination, operating time must be set according to following criteria:

The DEF protection should not operate when the circuit local backup protection of remote end

clears a fault in an adjacent circuit i.e. DEF should be coordinated with the remote end LBB.

12.POWER SWING BLOCKING FUNCTION

While the power-swing protection philosophy is simple, it is often difficult to implement it in a

large power system because of the complexity of the system and the different operating

conditions that must be studied. There are a number of options one can select in implementing

power-swing protection in their system. Designing the power system protection to avoid or

preclude cascade tripping is a requirement of modern day power system. Below we list two

possible options:

12.1. Block all Zones except Zone-I

This application applies a blocking signal to the higher impedance zones of distance relay and

allows Zone 1 to trip if the swing enters its operating characteristic. Breaker application is

also a consideration when tripping during a power swing. A subset of this application is to

block the Zone 2 and higher impedance zones for a preset time (Unblock time delay) and allow

a trip if the detection relays do not reset.

In this application, if the swing enters Zone 1, a trip is issued, assuming that the swing

impedance entering the Zone-1 characteristic is indicative of loss of synchronism. However, a

major disadvantage associated with this philosophy is that indiscriminate line tripping can

take place, even for recoverable power swings and risk of damage to breaker.

Annexure-VII

(Page 7/8 )

12.2. Block All Zones and Trip with Out of Step (OOS) Function

This application applies a blocking signal to all distance relay zones and order tripping if the

power swing is unstable using the OOS function (function built in modern distance relays or

as a standalone relay). This application is the recommended approach since a controlled

separation of the power system can be achieved at preselected network locations. Tripping

after the swing is well past the 180 degree position is the recommended option from CB

operation point of view.

Normally all relay are having Power swing Un-block timer which unblocks on very slow power

swing condition (when impedance locus stays within a zone for a long duration). Typically the

Power swing un-blocking time setting is 2sec.

However, on detection of a line fault, the relay has to be de-blocked.

12.3. Placement of OOS trip Systems

Out of step tripping protection (Standalone relay or built-in function of Main relay) shall be

provided on all the selected lines. The locations where it is desired to split the system on out

of step condition shall be decided based on system studies.

The selection of network locations for placement of OOS systems can best be obtained through

transient stability studies covering many possible operating conditions.

Till such studies are carried out and Out-of-Step protection is enabled on all identified lines, it is

recommended to continue with the existing practice of Non-Blocking of Zone-I on Power Swing as

mentioned under Option-12.1 above. However, it should be remembered that with this practice

the line might trip for a recoverable swing and it is not good to breakers.

It is strongly recommended that, the required studies must be carried out at the earliest possible

time (within a timeframe of one year) to exercise the option-12.2 & 12.3 above.

13.LINE OVERVOLTAGE PROTECTION

FOR 400kV LINES: Low set stage (Stage-I) may be set in the range of 110% - 112% (typically

110%) with a time delay of 5 seconds. High set stage (Stage-II) may be set in the range 140% -

150% with a time delay of 100milliseconds.

FOR 765kV LINES: Low set stage (Stage-I) may be set in the range of 106% - 109% (typically

108%) with a time delay of 5 seconds. High set stage (Stage-II) may be set in the range 140% -

150% with a time delay of 100milliseconds.

However, for over voltage Stage-I protection, a time grading of 1 to 3 seconds may be provided

between overvoltage relays of double circuit lines. Grading on overvoltage tripping for various

lines emanating from a station may be considered and same can be achieved using voltage as

well as time grading. Longest timed delay should be checked with expected operating time of

Over-fluxing relay of the transformer to ensure disconnection of line before tripping of

transformer.

It is desirable to have Drop-off to pick-up ratio of overvoltage relay better than 97% (Considering

limitation of various manufacturers relay on this aspect).

Annexure-VII

(Page 8/8)

14.LINE DIFFERENTIAL PROTECTION

Many transmission lines are now having OPGW or separate optic fiber laid for the

communication. Wherever such facilities are available, it is recommended to have the line

differential protection as Main-I protection with distance protection as backup (built-in Main

relay or standalone). Main-II protection shall continue to be distance protection. For cables and

composite lines, line differential protection with built in distance back up shall be applied as

Main-I protection and distance relay as Main-II protection. Auto-reclose shall be blocked for

faults in the cables.

15.MAINTAINING OPERATION OF POWER STATION AUXILIARY SYSTEM OF NUCLEAR POWER

PLANTS:

Depression of power supply voltages for auxiliary plant in some generating stations may reduce

the station output. Maintenance of full generation output may be a critical power system

security factor. In the case of nuclear plant, auxiliary power supplies are also a major factor in

providing full nuclear plant safety and security.

The potential loss of system generation or the potential challenges to nuclear plant safety

systems may be factors which will dictate the longest acceptable clearance times for

transmission circuit faults in the vicinity of a power station. This should be further taken up

with utilities of nuclear plants and this and any other requirements should be understood and

addressed.

16. COORDINATION BETWEEN SYSTEM STUDY GROUP AND PROTECTION ENGINEERS

For quite a few cases where system behavior issues are involved it is recommended that power

system study group is associated with the protection engineers. For example power swing locus,

out of step tripping locations, faults withstands capability, zone2 and zone3 overlap reach

settings calculations are areas where system study group role is critical/ essential.

*****

Annexure-VIII

(Page 1/4 )

RECOMMENDED METHODOLOGY FOR RELAY SETTINGS OF SERIES COMPENSATED

TRANSMISSION LINES:

Following phenomenon associated with the protection of Series compensated lines require special

attention:

VOLTAGE AND CURRENT INVERSION

1.1.

Voltage inversion on Series Compensated line:

In this case the voltage at the relay point reverses its direction. This phenomenon is

commonly called as voltage inversion. Voltage inversion causes false decision in

conventional directional relays. Special measures must be taken in the distance relays to

guard against this phenomenon.

1.2.

Current inversion on Series Compensated line:

Fault

current

will

lead

source

voltage

degrees

XC>

+XL1

Current inversion causes a false directional decision of distance relays (voltage memories

do not help in this case). [Here XC is reactance of series capacitor, XS is source reactance

and XL1 is reactance of the line]

Current inversion influences operation of distance relays and therefore they cannot be

applied without additional logic for the protection of series compensated lines when

possibility of current inversion exists. Performance of directional comparison protections,

based on residual (zero sequence) and negative sequence currents are also affected by

current inversion. It is therefore, recommended to check the possibility of current inversion

through system studies at the planning stage itself.

LOW FREQUENCY TRANSIENTS

Series capacitors introduce oscillations in currents and voltages in the power systems, which

are not common in non-compensated systems. These oscillations have frequencies lower than

the rated system frequency and may cause delayed increase of fault currents, delayed operation

of spark gaps as well as delayed operation of protective relays.

Low frequency transients have in general no significant influence on operation of line current

differential protection as well as on phase comparison protection. However they may

significantly influence the correct operation of distance protection in two ways:

-They increase the operating time of distance protection, which may in turn influence

negatively the system stability

-They may cause overreaching of instantaneous distance protection zones and this way

result in unnecessary tripping on series compensated lines.

It is recommended to reduce the reach setting by a safety factor (Ks) to take care of possible

overreach due to low frequency oscillations.

Annexure- VIII

(Page 2/4)

MOV INFLUENCE AND APPARENT IMPEDANCE

Metal oxide varistors (MOV) are used for capacitor over-voltage protection. In contrast to spark

gaps, MOVs carry current when the instantaneous voltage drop across the capacitor becomes

higher than the protective voltage level in each half-cycle. Extensive studies have been done by

Bonneville Power Administration in USA to arrive at a non-linear equivalent circuit for a series

connected capacitor using an MOV. The composite impedance depends on total fault current

and protection factor kp.

The latter is defined by equation.

MOV

Where UMOV is voltage at which MOV starts to conduct theoretically and UNC is voltage across

the series capacitor when carrying its rated nominal current

This should be considered while relay setting.

IMPACT OF SC ON PROTECTIVE RELAYS OF ADJACENT LINES

Voltage inversion is not limited only to the buses and to the relay points close to the series

compensated line. It can spread deep into the network and this way influence the selection of

protection devices (mostly distance relays) at remote ends of the lines adjacent to the series

compensated circuit, and sometimes even deeper in the network. Estimation of their influence

on performances of existing distance relays of adjacent lines must be studied. In the study, it is

necessary to consider cases with higher fault resistances, for which spark gaps or MOVs on

series capacitors will not conduct at all.

If voltage inversion is found to occur, it may be necessary to replace the existing distance relays

in those lines with distance relays that are designed to guard against this phenomenon.

MULTI CIRCUIT LINES

Two parallel power lines both series compensated running close to each other and ending at the

same busbar at both ends can cause some additional challenges for distance protection due to

the zero sequence mutual impedance. The current reversal phenomenon can also raise

problems from the protection point of view, particularly when the power lines are relatively short

and when permissive overreach schemes are used.

Influence of zero sequence mutual impedance

Zero sequence mutual impedance ZM0 will not significantly influence the operation of distance

protection as long as both circuits are operating in parallel and all precautions related to

settings of distance protection on series compensated line have been considered. Influence of

parallel line switched off & earthed at both ends, on the operation of distance protection on

single operating circuit is well known.

Annexure- VIII

(Page 3/4)

The presence of series capacitor additionally exaggerates the effect of zero sequence mutual

impedance between two circuits. The effect of zero sequence mutual impedance on possible

overreaching of distance relays is increased further compared to case of non-compensated lines.

This is because while the series capacitor will compensate self-impedance of the zero sequence

network the mutual impedance will be same as in the case of non-compensated double circuit

lines. The reach of under reaching distance protection zone 1 for phase to earth measuring loops

must further be reduced for such operating conditions.

Zero sequence mutual impedance may also disturb the correct operation of distance protection

for external evolving faults during auto reclosing, when one circuit is disconnected in one phase

and runs in parallel during dead time of single pole auto reclosing cycle. It is recommended to

study all such operating conditions by dynamic simulations in order to fine tune settings of

distance relays.

DIRECTIONAL RESIDUAL OVERCURRENT PROTECTION

All basic application considerations, characteristic for directional residual over-current

protection on normal power lines apply also to series compensated lines with following additions.

Low fault currents are characteristic of high resistive faults. This means that the fault currents

may not be enough to cause voltage drops on series capacitors that would be sufficient to start

their over-voltage protection. Spark gaps may not flash over in most cases, and metal oxide

varistors (MOVs) may not conduct any significant current. Series capacitors may remain fully

inserted during high resistive earth faults.

Local end directional residual OC protection:

The directional relay operates always correctly for reverse faults. VT located between bus and

capacitor generally does not influence directional measurement. But in case VT is located

between line and capacitor it may influence correct operation: While reverse faults are detected

correctly the forward operation is dependent on system conditions. Additional zero sequence

source impedance can be added into relay circuits to secure correct directional measurement.

Remote end directional residual OC protection:

In this case the current can be reduced to extremely low values due to low zero sequence

impedance at capacitor end. Further the measured residual voltage can be reduced to very low

value due to low zero sequence source impedance and/or low zero sequence current. Zero

sequence current inversion may occur at the capacitor end (dependent on fault position).

Directional negative sequence OC protection too may face very similar conditions.

Adaptive application of both the above OC protection principles can be considered wherever

required to get the desired result.

Annexure- VIII

(Page 4/4)

DISTANCE PROTECTION SETTINGS GUIDELINES

Basic criteria applied for Z1 & Z2 reach settings are :

•

Zone-1 should never overreach for the fault at remote bus

•

Zone-2 should never under reach for fault on protected line

•

Permissive overreach (POR) schemes are usually applied

Distance protection Zone 1 shall be set to

Zone-1 is set usually at 80% of Ks x

(

)

⋅

−

Where X11 is reactance

between CT and capacitor and X12 is reactance between capacitor and remote end Bus, Xc is

reactance of capacitor and KS is safety factor to prevent possible overreaching due to low

frequency (sub-harmonic) oscillations. These setting guidelines are applicable when VT is

installed on the bus side of the capacitor. It is possible to remove XC from the above equation in

case VT is installed on line side , but it is still necessary to consider the safety factor.

Alternatively, Zone-1 is set at 80% of line impedance with a time delay of

100 millisecond. POR Communication scheme logic is modified such that relay trips

instantaneously in Zone-1 on carrier receive. ( For remote end relay of the line looking

into series capacitor)

Zone-2 is set to 120 % of uncompensated line impedance for single circuit line. For

double circuit lines, special considerations are mentioned at Section B-5 above.

Phase locked voltage memory is used to cope with the voltage inversion. Alternatively, an

intentional time delay may be applied to overcome directionality problems related to

voltage inversion.

Special consideration may be required in over voltage stage-I (low set) trip setting for

series compensated double circuit lines. It has been experienced that in case of tripping

of a heavily loaded circuit, other circuit experience sudden voltage rise due to load

transfer. To prevent tripping of other circuit on such cases, over-voltage stage-I setting

for series compensated double circuit lines may be kept higher at 113%.

SIMULATION STUDIES

System studies, Use of real Time digital simulators, Tests using EMTP files are very important

when applying protections for series compensated lines. It is recommended to carry out such

studies specific to each line.

*****

Annexure-IX

(Page 1/9)

General Information:

1. Name of Sub-station

2. Date of first commissioning

3. Type of Bus Switching Scheme:

4. Whether SLD collected or Not:

Audit Team:

1. .

2. .

3. .

(1) Instrument Transformer

( To be filled for each one of them)

A. Current transformer (C T)

Location of CT

Date of CT ratio Test Testing

Test Results

Core I

Core

III

Core IV

Core V

Core VI

Ratio Adopted

Ratio measured

iii

error calculated

Knee point voltage

B. Capacitive voltage transformer (C V T)

Location of CVT

Date of Testing

CVT ratio Test

Core I

Core II

Core III

Ratio Adopted

Ratio measured

iii

error calculated

Location of CVT

Date of Testing

CVT ratio Test

Core I

Core II

Core III

Ratio Adopted

Ratio measured

iii

error calculated

Annexure- IX

(Page 2/9)

(2) Availability of Protection System

A. Bus Bar relay

765kV

400kV

220kV

Make and Model of Bus Bar relay

ii)

Whether stability checks done or

not

iii)

Date of testing

iv)

Remarks (if any)

B. Sub-station protection and monitoring Equipment

System

LBB

(Make &

Model)

Functi

onal

(Yes /

No)

Date of

last

testing

Event

Logger

(Make &

Model)

Functio

nal

(Yes /

No)

Synchroniz

ing Facility

Available

or not

Synchro

Check Relay

(Make &

Model)

Setting of

Synchro

check

Relay

765kV

System

II)

400kV

System

III

)

220kV

System

Annexure- IX

(Page 3/9)

C. Transmission Line Protection

Line-1

(name of

line)

Main-I

Protection

(Make and

Model)

Functio

nal

(Yes /

No)

Date

testing

Main-II

Protection

(Make and

Model)

Functi

onal

(Yes /

No)

Date of

testing

LBB

Protection

(Make and

Model)

Funct

ional

(Yes /

No)

Date of

testing

PLCC/

Protection

coupler

(Make and

Model)

Functio

nal

(Yes /

No)

(Make &

Model)

Function

(Yes / No)

Time

Synch.

Unit

(Make &

Model)

/ Not OK

Line-2

(name of

line)

Main-I

Protection

(Make and

Model)

Functio

nal

(Yes /

No)

Date

testing

Main-II

Protection

(Make and

Model)

Functi

onal

(Yes /

No)

Date of

testing

LBB

Protection

(Make and

Model)

Funct

ional

(Yes /

No)

Date of

testing

PLCC/

Protection

coupler

(Make and

Model)

Functio

nal

(Yes /

No)

(Make &

Model)

Function

(Yes / No)

Time

Synch.

Unit

(Make &

Model)

/ Not OK

Line-3

(name of

line)

Main-I

Protection

(Make and

Model)

Functio

nal

(Yes /

No)

Date

testing

Main-II

Protection

(Make and

Model)

Functi

onal

(Yes /

No)

Date of

testing

LBB

Protection

(Make and

Model)

Funct

ional

(Yes /

No)

Date of

testing

PLCC/

Protection

coupler

(Make and

Model)

Functio

nal

(Yes /

No)

(Make &

Model)

Function

(Yes / No)

Time

Synch.

Unit

(Make &

Model)

/ Not OK

Line-4

(name of

line)

Main-I

Protection

(Make and

Model)

Functio

nal

(Yes /

No)

Date

testing

Main-II

Protection

(Make and

Model)

Functi

onal

(Yes /

No)

Date of

testing

LBB

Protection

(Make and

Model)

Funct

ional

(Yes /

No)

Date of

testing

PLCC/

Protection

coupler

(Make and

Model)

Functio

nal

(Yes /

No)

(Make &

Model)

Function

(Yes / No)

Time

Synch.

Unit

(Make &

Model)

/ Not OK

Annexure- IX

(Page 4/9)

D. Transformer Protection

ICT-1 (name of

ICT)

Differential

Protection

(Make

Model)

REF

Protection

(Make

Model)

Back-up

Over

Current

Protection

(Make & Model)

Over

Flux

Protection

(Make & Model)

Other

protection

Bucholtz /

PRD

LA Rating

HV Side

Rating

Side

OTI/WTI

Indication

working or not

Date of last

testing

ICT-3 (name of

ICT)

Differential

Protection

(Make

Model)

REF

Protection

(Make

Model)

Back-up

Over

Current

Protection

(Make & Model)

Over

Flux

Protection

(Make & Model)

Other

protection

Bucholtz /

PRD

LA Rating

HV Side

Rating

Side

OTI/WTI

Indication

working or not

Date of last

testing

ICT-3 (name of

ICT)

Differential

Protection

(Make

Model)

REF

Protection

(Make

Model)

Back-up

Over

Current

Protection

(Make & Model)

Over

Flux

Protection

(Make & Model)

Other

protection

Bucholtz /

PRD

LA Rating

HV Side

Rating

Side

OTI/WTI

Indication

working or not

Date of last

testing

Differential

Protection

(Make

Model)

REF

Protection

(Make

Model)

Back-up

Over

Current

Protection

(Make & Model)

Over

Flux

Protection

(Make & Model)

Other

protection

Annexure- IX

(Page 5/9)

E. Reactor Protection

Reactor-1 (name

of Line/Bus

Reactor)

Differential

Protection

(Make

Model)

REF Protection

(Make & Model)

Back-up

Over

Impedance

Protection

(Make & Model)

Over

Flux

Protection

(Make

Model)

Other

protection

Bucholtz /

PRD

LA Rating HV

Side

OTI/WTI

Indication

working or not

Date of last testing

Reactor-2 (name

of Line/Bus

Reactor)

Differential

Protection

(Make

Model)

REF Protection

(Make & Model)

Back-up

Over

Impedance

Protection

(Make & Model)

Over

Flux

Protection

(Make

Model)

Other

protection

Bucholtz /

PRD

LA Rating HV

Side

OTI/WTI

Indication

working or not

Date of last testing

Reactor-3 (name

of Line/Bus

Reactor)

Differential

Protection

(Make

Model)

REF Protection

(Make & Model)

Back-up

Over

Impedance

Protection

(Make & Model)

Over

Flux

Protection

(Make

Model)

Other

protection

Bucholtz /

PRD

LA Rating HV

Side

OTI/WTI

Indication

working or not

Date of last testing

Annexure- IX

(Page 6/9)

(3) Line Parameter

Line-1

Line-2

Line-3

Line-4

Line-5

Name of Line

Line length (km)

Line Parameters

( In Ohms/Per

KM/Per Phase

Primary value)

R0M

X0M

Relay setting

Adopted

Please enclose the settings for all lines, transformers, Reactors

and Bus Bars as Annexure-I

Recommen

ded

Please enclose the settings for all lines, transformers, Reactors

and Bus Bars as Annexure-II

(4) DC Supply

220 /110 V DC-I

220 /110 V DC-II

48 V DC-I

48 V DC-II

Measured voltage (to be

measured

farthest

Panel

Positive to Earth

ii.

Negative to Earth

No. of Cells Per Bank

Availability

Battery

Charger

Yes/No

Annexure- IX

(Page 7/9)

(5) Circuit Breakers

Make

and

Model

Status of

Breaker

Available

or Not

No.of

trip/close

coil &

healthiness

PIR

(Available

or Not)

Date of

Last

Timing

taken

Remarks

(If any)

765kV System

765kV bay-1

765kV bay-2

iii

765kV bay-3

765kV bay-4

765kV bay-5

400kV System

400kV bay-1

400kV bay-2

iii

400kV bay-3

400kV bay-4

400kV bay-5

400kV bay-6

220kV System

220kV bay-1

220kV bay-2

iii

220kV bay-3

220kV bay-4

220kV bay-5

Annexure- IX

(Page 8/9)

(6) Availability of Auxiliary Supply

Auxiliary Supply-1: Source of supply : ....

Reliability of supply: ...

Average trippings per month:

...

Auxiliary Supply-2: Source of supply : ....

Reliability of supply: ...

Average trippings per month:

...

..

DG Set-1:

Make

Rating ...

Weather on Auto or Manual

Fuel Level ...

DG Set-1:

Make

Rating ...

Weather on Auto or Manual

Fuel Level ...

..

Annexure- IX

(Page 9/9)

(7) Availability of UFR Relay

Make

Setting

(8) Availability of DF/DT Relay

Make

Setting

(9) Special System Protection Scheme (SPS)

Available (Yes/No)

Verification ..

(10)

Status of corrective actions based on Tripping Analysis

....

(11)

Any other observation/ comments

.....

*****

Annexure-X

CHECK LIST TO ENABLE AUDIT OF PRACTICES FOLLOWED IN PROTECTION APPLICATION

& CRITERIA USED FOR SETTING CALCULATIONS IN 220KV, 400KV & 765KV SUBSTATIONS

CHECK-LIST:

Check list for different protected objects & elements in fault clearance system are as under:

(put mark in the appropriate box )

A. Transmission Lines (OHL and Cables)

Independent Main-I and Main-II protection (of different make OR different

type) is provided with carrier aided scheme

YES

Are the Main-I & Main-II relays connected to two separate DC sources (Group-

A and Group-B)

YES

Is the Distance protection (Non-switched type, suitable for 1-ph & 3-ph

tripping) as Main1 and Main2 provided to ensure selectivity & reliability for

all faults in the shortest possible time

YES

Is both main-I & Main-II distance relay are numerical design having

Quadrilateral or Polygon operating characteristic

YES

In the Main-I / Main-II Distance protection, Zone-I is set cover 80% of the

protected line section

YES

In the Main-I / Main-II distance protection, Zone-2 is set cover 120% of the

protected line section in case of Single circuit line and 150% in case of Double

circuit line

YES

In the Main-I / Main-II distance protection, Zone-3 is set cover 120% of the

total of protected line section plus longest line at remote end as a minimum.

YES

Resistive reach for Ground fault element set to give maximum coverage

considering fault resistance, arc resistance & tower footing resistance. ( In

case, It is not possible to set the ground fault and phase fault reaches

separately, load point encroachment condition imposed on Phase fault

resistive reach shall be applied)

YES

Resistive reach for Phase fault element set to give maximum coverage subject

to check of possibility against load point encroachment considering minimum

expected voltage and maximum load.

YES

10.

In case of short lines, is manufacturers recommendation considered in

respect of resistive setting vis a vis reactance setting to avoid overreach.

YES

Is Zone-2 time delay of Main-I / Main-II distance relay set to 0.350 seconds ?

In case any other value has been set for Zone-II timer, kindly specify the value

and justification thereof.

YES

Is Zone-3 timer is set to provide discrimination with the operating time of

relays at adjacent sections with which Zone-3 reach of relay is set to overlap.

Please specify the Zone-3 time set.

YES

13.

Is Zone-4 reach set in reverse direction to cover expected levels of apparent

bus bar fault resistance, when allowing for multiple in feeds from other

circuits?

YES

14.

Is reverse looking Zone-4 time delay set as Zone-2 time delay?

YES

15.

Is Switch on to fault (SOTF) function provided in distance relay to take care of

line energisation on fault?

Whether SOTF initiation has been implemented using hardwire logic

In case of Breaker and half switching scheme, whether initiation of line SOTF

from CB closing has been interlocked with the other CB

YES

16.

Whether VT fuse fail detection function has been correctly set to block the

distance function operation on VT fuse failure

YES

17.

Is the sensitive IDMT directional E/F relay (either separate relay or built-in

function of Main relay) for protection against high resistive earth faults?

YES

18.

Is additional element (Back-up distance) for remote back-up protection

function provided in case of unit protection is used as Main relay for lines?

YES

19.

In case of Cables, is unit protection provided as Main-I & Main-II protection

with distance as back-up.

YES

20.

Are the line parameters used for setting the relay verified by field testing

YES

21.

Is Two stages Over-Voltage protection provided for 765 & 400kV Lines?

Do you apply grading in over-voltage setting for lines at one station.

Please specify the setting values adopted for:

Stage-I : (typical value - 106 to 112 % , delay : 4-7 Sec)

Stage-II: (typical value - 140 to 150%, delay: 0 to 100msec.)

YES

22.

Is 1-ph Auto reclosing provided on 765, 400 & 220kV lines? Please specify

the set value:

Dead time: (typical 1 Sec)

Reclaim time: (typical 25 Sec)

YES

23.

Is the Distance communication. Scheme Permissive Over Reach (POR) applied

for short lines and Permissive Under Reach (PUR) applied for long lines?

If any other communication scheme has been applied, please provide the

detail with justification thereof.

YES

24.

Is the Current reversal guard logic for POR scheme provided on Double circuit

lines?

YES

25.

In case the protected line is getting terminated at a station having very low

fault level i.e. HVDC terminal, whether week end-infeed feature has been

enabled in respective distance relay or not

YES

26.

In case of protected line is originating from nuclear power station, are the

special requirement (stability of nuclear plant auxiliaries) as required by them

has been met

YES

27.

What line current , Voltage and Load angle have been considered for Load

encroachment blinder setting and what is the resultant MVA that the line can

carry without load encroachment.

(In the absence of Load encroachment blinder function, this limit shall be

applied to Zone-3 phase fault resistive reach.)

Angle:

28.

What are the Zones blocked on Power swing block function:

Setting for Unblock timer: (typical 02 second)

Out of Step trip enabled

Z1 / Z2 / Z3 / Z4

Time:

YES

29.

Whether the location of Out of step relay has been identified on the basis of

power system simulation studies

YES

30.

Is Disturbance recorder and Fault locator provided on all line feeder ?

Whether standalone or built in Main relay

Whether DR is having automatic fault record download facility to a

central PC

Whether DR is time synchronised with the GPS based time synchronising

equipment

Whether DR analog channels contain line phase & neutral current and

line phase & neutral voltage.

Whether DR digital channel as a minimum contain the CB status, Main-I

& II trip status, LBB trip status, Over-voltage trip status, Stub protn trip

status, Permissive and direct carrier receive status, Line reactor trip

status.

YES

Standalone / built-in

YES

31.

Does the Setting document for the numerical relays (IED) contain all the

settings for all functions that are used and indicates clearly the functions

not used (to be Blocked / Disabled). Are all default settings validated or

revised settings given in the setting document?

YES

B. Power Transformers

Do you use Group A and Group B protections connected to separate DC

sources for power transformers

YES

Do you follow CBIP guideline (274 & 296) for protection setting of transformer

YES

Do you use duplicated PRD and Bucholtz initiating contact for power

transformers at 765kV and 400kV levels

YES

Do you classify transformer protections as below in groups: Group A

Group B

• Biased differential relay Restricted earth fault (REF) relay

•PRD , WTI Buchholz Protection, OTI

• Back up Protection(HV) Back up Protection(MV)

• Over fluxing protection(HV) Over fluxing protection(MV)

YES

Group A or B

In case of Breaker & half switching scheme, whether CT associated with Main

& Tie Breakers are connected to separate bias winding of the low impedance

Biased differential protection in order to avoid false operation due to dissimilar

CT response.

YES

Is Restricted earth fault (REF) protection used a high impedance type

YES

Are Main protection relays provided for transformers are of numerical design.

YES

Are directional over current & earth fault relays provided as back-up

protection of Transformer are of numerical design.

Do the back-up earth fault relays have harmonic restrain feature

YES

Is Fire protection system (HVW type) )/N2 fire extinguisher system provided for

power transformer and functioning

YES

10.

Is the Disturbance recorder provided for Transformer feeder

Whether standalone or built in Main relay

Whether DR is having automatic fault record download facility to a central

Whether DR is time synchronised with the GPS time synchronising

equipment

YES

Standalone/built-in

YES

11.

Does the Setting document for the numerical relays (IED) contain all the

settings for all functions that are used and indicates clearly the functions not

used (to be Blocked / Disabled). Are all default settings validated or revised

settings given in the setting document?

YES

C. Shunt Reactors

Do you use Group A and Group B protections connected to separate DC

sources for reactors

YES

Do you follow CBIP guideline (274 and 296) for protection setting of reactors

YES

Do you use duplicated PRD and Bucholtz initiating contact for Reactors at

765kV and 400kV levels

YES

Do you classify Reactor protections as below in groups:

Group A Group B

• Biased differential relay

• (High impedance type] R.E.F Protection

• PRD , WTI Buchholz Protection, OTI

• Back up impedance O/C & E/F relay

protection

YES

Group A or B

In case of Breaker & half switching scheme, whether CT associated with Main

& Tie Breakers are connected to separate bias winding of the low impedance

Biased differential protection in order to avoid false operation due to dissimilar

CT response.

YES

Is Restricted earth fault (REF) protection used a high impedance type

YES

Are Main & back-up protection relays provided for Reactor are of numerical

design.

YES

Is Fire protection system (HVW type)/N2 fire extinguisher system provided for

Reactor and functioning

YES

Is the Disturbance recorder and Fault locator provided on all the Shunt

Reactors used in 765 kV, 400 kV substations?

Whether standalone or built in Main relay

Whether DR is having automatic fault record download facility to a central

YES

Standalone/built-in

YES

10.

Does the Setting document for the numerical relays (IED) containall the

settings for all functions that are used and indicates clearly the functions not

used (to be Blocked / Disabled). Are all default settings validated or revised

settings given in the setting document?

YES

D. Bus bars

Bus Bar protection for 765, 400 & 220kV buses is provided

YES

Duplicated Bus bar protection is provided for 765kV and 400kV buses

YES

CBIP guideline for Protection (274 and 296) settings is followed

YES

In an existing substation if CTs are of different ratios, is biased type bus

protection provided.

YES

In stations where single bus bar protection is provided, is backup provided

by reverse looking elements of distance relays or by second zone elements of

remote end distance relays?

YES

In case of GIS where burn through time of SF6 is shorter than remote back

up protection is the bus bar protection duplicated irrespective of voltage

level?

YES

Since it is difficult to get shutdowns to allow periodic testing of bus

protection, numerical bus protections with self-supervision feature is an

answer. Is this followed?

YES

Does the Setting document for the numerical relays (IED) contain all the

settings for all functions that are used and indicates clearly the functions

not used (to be Blocked / Disabled). Are all default settings validated or

revised settings given in the setting document?

YES

E. Disturbance Recorder (DR) and Event Logger (EL)

Is the Disturbance recorder and Fault locator provided on all line

feeders of 765, 400 & 220kV substations?

Whether standalone or built in Main relay

Whether DR is having automatic fault record download facility to a

central PC

Whether Central PC for DR , EL are powered by Inverter (fed from

station DC)

YES

Standalone / built-in

YES

Whether DR is having the following main signals for lines:

Analogue signals:

•

From CT: IA, IB, IC, IN

•

From VT: VAN, VBN, VCN

•

From Aux. VT: V0

Digital Signals

•

Main 1 Carrier receive

•

Main 1 Trip

•

Line O/V Stage I / Stage II

•

Reactor Fault Trip

•

Stub Protection Operated.

•

Main II Trip

•

Main II Carrier Receive

•

Direct Trip CH I / II

•

CB I Status (PH-R, Y & B)

•

CB II Status (PH R, Y & B)

•

Bus bar trip

•

Main / Tie CB LBB Operated

•

Main / Tie Auto-reclose operated.

DR for Transformer / Reactor feeder should contain analog channel like

input currents & voltage. Binary signal include all protection trip input,

Main & Tie CB status, LBB trip

YES

Whether substation (765, 400 , 220kV) is having Event logger facility

(standalone or built-in-SAS)

YES

Whether GPS based time synchronizing equipment is provided at the

substation for time synchronizing of Main relays / DR/ Event logger / SAS/

PMU / Line Current Differential Relays

YES

Circuit Breakers

Is breaker fail protection ( LBB / BFR) provided for all the Circuit Breakers

at 220kV , 400kV & 765kV rating

YES

For Circuit Breaker connected to line feeder / transformer feeder, whether

operation of LBB / BFR sends direct trip signal to trip remote end breaker ?

YES

For lines employing single phase auto reclosing, Is start signal from

protection trip to LBB / BFR relay is given on single phase basis?

YES

Is separate relay provided for each breaker and the relay has to be connected

from the secondary circuit of the CTs associated with that particular

breaker?

YES

Is LBB relay provided with separate DC circuit independent from Group-A

and Group-B Protections?

YES

Is the LBB initiation provided with initiating contact independent of CB trip

relay contact?

YES

Is Separation maintained between protective relay and CB trip coil DC

circuit so that short circuit or blown fuse in the CB circuit will not prevent

the protective relay from energizing the LBB scheme?

YES

Is LBB relay initiated by Bus bar protection in addition to other fault sensing

relays, since failure of CB to clear a bus fault would result in the loss of

entire station if BFP relay is not initiated?

YES

10.

Is tripping logic of the bus bar protection scheme used for LBB protection

also?

YES

11.

Are the special considerations provided to ensure proper scheme operation

by using Circuit Breaker contact logic in addition to current detectors in

cases breaker-fail relaying for low energy faults like buckholz operation?

YES

12.

Are the Current level detectors set as sensitive as the main protection?

(Generally setting of 0.2 A is commonly practiced for lines and transformers)

YES

13.

Is timer set considering breaker interrupting time, current detector reset

time and a margin? (Generally a timer setting of 200ms has been found to be

adequate)

YES

14.

Is the back-up fault clearance time is shorter than the operating time of the

remote protections (distance relay Zone-2) ?

YES

15.

Is the breaker failure protection provided with two steps (First stage retrip

own CB, Second stage- Trip all associated CBs). This mitigates unwanted

operation of breaker failure protection during maintenance and fault tracing.

YES

16.

Is the breaker failure protection hardware provided is separate from line

/transformer feeder protection?

YES

G. Communication systems

Do you use PLCC for tele-protection of distance relays at 765, 400 &

220kV feeders

Specify type of coupling

Whether redundant PLCC channels provided for 400 & 765kV lines

Specify number of PLCC channels per circuit :

Whether dependability & security of each tele-protection channel

measured & record kept?

YES

(Ph-Ph / Ph-G/ Inter-

ckt)

YES

( One / two)

YES

In case you use OPGW for tele-protection, are they on geographically

diversified route for Main-I and Main-II relay?

Whether dedicated fiber is being used for Main-I / Main-II relay or

multiplexed channel are being used.

YES

Dedicated /

multiplexed

H. Station DC supply systems

Do you have two separate independent DC system (220V or 110V)

(Source-A and Source-B)

YES

Do you have two independent DC system (48V) for PLCC

(source-A and source-B)

YES

There is no mixing of supplies from DC source-A and DC source-B

YES

Whether the protection relays and trip circuits are segregated into two

independent system fed through fuses from two different DC source

YES

Whether Bay wise distribution of DC supply done in the following way:

Protection

CB functions

Isolator / earth switch functions

Annunciation / Indications

Monitoring functions

YES

Whether following has been ensured in the cabling:

Separate cables are used for AC & DC circuits

Separate cables are used for DC-I & DC-II circuits

Separate cables are used for different cores of CT and CVT outputs

to enhance reliability & security

YES

Is guidelines prescribed in CBIP manual 274 & 296 followed in general

YES

PERFORMANCE INDICES

Is there a system of periodically measuring Dependability & Security

of Protection system (as given in CBIP manual 296) and recorded

YES

Is there a system of periodically measuring Dependability of

switchgear associated with Protection system and recorded

YES

Is there a process of Root cause analysis of unwanted tripping events

YES

Are improvement action like revision of relay setting, better

maintenance practices, modernising & retrofitting of switching &

protection system taken based on above data?

YES

Is attention also given to DC supply system, tele-protection

signaling, healthiness of tripping cables, terminations etc. in order to

improve the performance of fault clearance system

YES

ADDITIONAL CHECKS FOR SERIES COMPENSATED LINES

What is the operating principle of Main protection employed

Distance

Line Current

differential

Are both main-I & Main-II distance relay are numerical design

YES

Are both main-I & Main-II distance relay suitable for Series

compensated lines

YES

Are POR tele-protection scheme employed for distance relays

YES

Position of Line VT provided on series compensated line

Between

Capacitor

and

line

Between

Capacitor

and

Bus

What is the under reaching (Zone 1) setting used in teleprotection

schemes (Local & Remote end)

% of line

length

Rationale:

What is the overreaching (Zone 2) setting in used teleprotection

schemes

% of line

length

Rationale:

What kinds of measurement techniques are used to cope with

voltage inversion?

Phase locked

voltage memory

Intentional time

delay

Other, specify:

Whether system studies carried out to check the possibility of

current inversion due to series compensation

YES

10.

Whether any system studies conducted to find the impact of series

compensation on the performance of protections installed on

adjacent lines? If yes, how many lines were found to be affected ?.

Pl. specify ________________

YES

If YES, are the affected protections on adjacent lines changed /

setting revised after the introduction of series compensation?

YES

12.

Is dynamic simulation done to fine tune settings of distance relay

installed on series compensated double circuit lines?

YES

13.

Whether performance of directional earth fault relay verifies by

simulation studies

YES

14.

When is flashover of spark gaps expected?

For protected line

Faults up to

ohms

For external

faults an adjacent

lines

15.

Whether measures taken for under/overreach problems at sub-

harmonic oscillations?

YES

16.

Whether MOV influence considered while setting the distance relay

reach

YES

17.

Have you experienced any security problems (Relay mal-operation)

with high frequency transients caused by

Flashover of spark gaps

Line energisation

Other, specify:

YES

18.

If YES, how the above problem has been addressed?

__________________

---------------------------

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∞¬Òûª

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RNI No. KARBIL/2001/47147

∞¬Òûª

– IVA

Part–IVA

 

Bengaluru, Wednesd

NO.LD 247 LET

In exercise of the powers co

Construction Workers (Regulation

No. 27 of 1996), the Government

makes the following draft rules f

(Regulation of Employment and C

of persons likely to be affected th

into consideration after thirty day

Any objections or suggest

persons with respect to the said

considered by the State Govern

Additional Chief Secretary to Gov

Veedhi, Bengaluru- 560 001.

1. Title and commence

Construction Workers' (Regulation

Amendment) Rules, 2015.

(2) They shall come into fo

2. Amendment of rule 3

(Regulation of Employment and C

to as the said rules), for sub rule (

(8) The Beneficiary shall

authority, for each year.

3. Amendment of rule 4

shall be omitted.

ª∞ «Ò∏Â

 

 !

day, February 3, 2016 (Magha 14, Shaka Vars

LABOUR SECRETARIAT

NOTIFICATION

T 2015, Bangalore, dated: 02

nd February 2

onferred by sections 22, 27, 40 and 62 of th

n of Employment and Conditions of Service) A

of Karnataka, in consultation with the expe

further to amend the Building and Other

Conditions of Service) (Karnataka) Rules, 20

hereby and notice is hereby given that the sa

ys from the date of its publication in the Offic

tions which may be received by the State G

d draft before the expiry of the period sp

nment. Objections and suggestions may

vernment, Labour Department, Vikasa Soud

DRAFT RULES

ement.- (1) These rules may be called the

n of Employment and Conditions of Service

orce from the date of their publication in the

39.- In rule 39 of the Building and Other

Conditions of Service) (Karnataka) Rules, 200

(8), the following shall be substituted, namel

l submit the Living Certificate Form XII

43.- In rule 43 of the said rules, in sub r

Â√¿Ê

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sha 1937)

$% &

No. 215

2016.

he Building and Other

Act, 1996 (Central Act

ert Committee, hereby

Construction Workers

06 for the information

aid draft will be taken

cial Gazette.

Government from any

pecified above will be

be addressed to the

dha, Dr.B.R.Ambedkar

e Building and other

e) (Karnataka) (Second

Official Gazette.

Construction Workers

06 (hereinafter referred

ly:-

A to the sanctioning

rule (2), for clause (a),

4. Amendment of rule 45.- In rule 45 of the said rules, in sub rule (2), for clause (a),

shall be omitted.

5. Amendment of rule 47.- In rule 47 of the said rules, in sub-rule (4), the following shall

be substituted, namely:-

(4) The Board shall grant an amount of Rs.3,00,000/- (Rupees Three lakh only) to

the nominee/dependant as the case may be of the deceased beneficiary and out of this rupees

Three lakh, an amount of Rs.1,50,000/- (Rupees One lakh fifty thousand only) shall be

invested by the Board in the Post office monthly income scheme in the name of the

nominee/dependant in order to secure a monthly income to them and the balance of

Rs.1,50,000/- (Rupees One lakh fifty thousand only) shall be paid by the Board to the

nominee/dependant of the deceased. In the case of Permanent total disablement

(incapacitation), the Board shall grant an amount of Rs.3,00,000/- (Rupees Three lakh only)

or such proportionate percentage of the compensation of Rs.3,00,000/- (Rupees Three lakh

only) in case of permanent partial disablement suffered by the applicant in proportion to the

percentage of disability mentioned in the medical certificate issued by the doctor of the

Government hospital or the recognized private hospital or recognized RSBY hospital.

6. Amendment of rule 47A.- In rule 47A of the said rule,-

(1) in sub-rule (1), for the letters and figures Rs.50,000/-, the letters and figures

"Rs.1,00,000/-" shall be substituted;

(2) in sub-rule (2)-,

(i) in clause (a) and (b), for the words "the Building or other Construction work is situated

has collapsed" occurring in two places, the words "due to such accident during the

course of his / her employment in any construction activity" shall be substituted.

(ii) in clause (c), for the words "incident of collapse of a building", the words "incident of

accident during the course of employment in any construction activity" shall be

substituted.

(3) in sub-rule (3), for the letters, figures, brackets and words Rs.50,000/-(Rupees Fifty

thousand only) to the dependents of the deceased unregistered building worker and an amount of

Rs.10,000/- (Rupees ten thousand only), the letters, figures, brackets and words " Rs.1,00,000/-

(Rupees one lakh only) to the dependents of the deceased unregistered building worker and an

amount of Rs.20,000/- (Rupees Twenty thousand only), shall be substituted.

By order and in the name of the Governor of Karnataka,

S.N.RAMAKRISHNA

Under Secretary to Government,

Labour Department.

 !"#$

RNI No. KARBIL/2001/47147

∞¬Òûª

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Bengaluru, Wednesda

NO. UDD 2

The draft of the Karnatak

Regulations, 2015, which the Gov

conferred by section 13E of the K

427 of the Municipal Corporation

1964 is hereby published as req

persons likely to be affected there

consideration after thirty days from

Any objection and suggest

person with respect to the said

considered by the State Governme

to Government, Urban Developme

1. Title, commencemen

Karnataka Installation of new Tele

(2) They shall come into for

(3) Notwithstanding anyth

the provisions of these regulations

2. Definitions.- In these re

(a) Act means the Karnat

1963);

(b) Sanctioning Authority

Commissioners of city Municip

Panchayaths and Panchayat D

Development Authority areas shal

new Tele Communication Infrast

issued by Government of India fro

ª∞ «Ò∏Â

 

 ! 

ay, Febuary 24, 2016 (Palguna 5, Shaka Vars

URBAN DEVELOPMENT SECRETARIAT

NOTIFICATION

11 GEL 2014 (P), Bangalore, dated: 24.02

ka installation of new Telecommunication

vernment of Karnataka proposes to make in

Karnataka Town and Country Planning Act,

ns Act, 1976 and Section 325 of the Karnata

quired by section 13E of the said Act, for

eby and notice is hereby given that the said

m the date of its publication in the official G

tion, which may be received by the State

d draft before the expiry of the period sp

ent. Objections and suggestions may be add

ent Department, Vikasa Soudha, Bangalore -

DRAFT REGULATIONS

nt and application.- (1) These Regulatio

ecommunication Infrastructure Towers Regu

rce from the date of their final publication in

hing contained in the zoning regulation of an

s shall apply to all local planning areas in th

egulations, unless the context otherwise requ

taka Town and Country Planning Act, 1961

y means the Commissioners of Municip

al councils, Chief Officer of Town Muni

Development Officers of Gram Panchay

ll be competent to accord permission for clea

tructure Towers (TIT) following these regu

om time to time in their respective jurisdictio

∏Â√¿Ê

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No. 318

2.2016

Infrastructure Towers

n exercise of the powers

1961 read with section

aka Municipalities Act,

the information of the

draft will be taken into

Gazette.

Government from any

pecified above, will be

dressed to the Secretary

- 560001.

ons may be called the

ulations, 2015.

n the official Gazette.

ny Local Planning area

he State.

uires,-

(Karnataka Act 11 of

pal Corporations, The

icipal councils, Town

yaths falling in Urban

arance of installation of

ulations and guidelines

on;

or Roof Top Tower (RTT) or Roof Top Poles (RTP) or Cell Phone Tower (CPT), Antenna fixtures,

Fabricated antenna, Tower to install the telephone lines and transmission towers. But it shall not

include the Antennas installed for domestic purpose, namely Television Antennas or Dish Antennas.

3. Essentiality of Permit.- No person shall erect or re-erect any non-Governmental

telecommunication infrastructure tower or telecommunication pole structures or accessory rooms or

make alteration or cause the same to be done without obtaining a separate permission for each such

tower or telecommunication pole structures from the Sanctioning Authority.

4. General guidelines for location of Telecommunication Infrastructure Tower.- (1)

Location of Telecommunication infrastructure towers is governed by radio frequency system adopted

therefore as far as possible residential areas shall be avoided. However where it is not possible to

avoid residential areas, permission from the sanctioning Authority for installation on roof top of a

building shall be considered.

(2) First preference shall be given to the location of tower in commercial areas or other public

areas.

(3) In residential areas, Telecommunication Infrastructure Towers shall be located in open

spaces or community buildings in the locality.

(4) Where it is not possible to locate Telecommunication Infrastructure Towers as in sub-

regulation (3) above, the Telecommunication Infrastructure Towers shall be permitted on the roof

top of residential buildings subject to the condition that a structural safety certificate from a

certified Structural Engineer has been obtained.

5. Submission of application for Permit.- Application for permit shall be submitted to the

Sanctioning Authority along with following Plans and Documents.-

(1) Location Plan.- (scale 1:1000) three copies of the Location Plan shall show the site with

reference to the surrounding existing developments duly showing the access and

approach to the site or building wherein the tower or room is proposed;

(2) Site Plan.- (scale 1:100) three copies of the Site Plan shall show plot dimensions, access

street width, details of existing structures within the plot with their uses, height, and

number of floors, set-back from the plot boundaries and between them; proposed tower

and ancillary structures.

(3) Structural Stability Certificate. one copy (original) of Structural Stability Certificate

along with height of the tower shall be submitted in respect of the Telecommunication

Infrastructure Tower and room and also the building over which it shall be erected. The

Structural Stability Certificate shall be obtained from a registered or a retired Structural

Engineer of the Central or State Government Service or Quasi-Government Organization

registered as a Structural Engineer;

(4) Copy of Sanctioned Plan of the Building and Occupancy Certificate issued by the

Sanctioning Authority;

(5) Ownership Document - One copy (attested) to prove the ownership of the building or

site;

(6) Lease Agreement Deed or Consent Agreement deed.- One copy (attested) signed by

the applicant and the owner of the site or building;

(7) Drawing of tower with complete details including the specifications of foundations and

design parameters;

(8) Height of the tower along with its elevation (MSL);

(9) In case the tower is in the vicinity or adjoining to high or low tension line- then its

distance from the same shall be clearly indicated in the drawings;

(10) The weight of Tower or antenna in Metric tonnes;

(11) Indemnity Bond (original) to take care of any loss or injury that may occur due to

accident caused to neighbours by the tower (including a declaration to the effect that the

applicant shall take special precaution for fire safety and lightning and he shall be

solely responsible for paying all kinds of compensation and damages and would be

responsible for any civil or criminal case arising there from;

(12) No objection Certificate issued by the Karnataka State Fire Services Department;

(13) Copy of certificate issued by Automotive Research Association of India (ARAI) to the

manufacturers of the DG sets [The DG sets used shall be as per the provisions under

Environment (protection) Act, 1986 and the Noise pollution (Regulation and Control)

Rules, 2000] is to be submitted by the Telecom Service Providers for Infrastructure

Providers;

(14) Copy of SACFA clearance or copy of SACFA application for the said location submitted to

WPC wing of DoT with registration number as WPC acknowledgement along with

undertaking that in case of any objection or rejection, TSPs or IPs shall take corrective

actions or remove the tower; and

(15) Acknowledgement receipt issued by TERM Cells (DoT) or the self certificate submitted by

Telecom Service Provider/ Infrastructure Provider in respect of Mobile tower/BTS (ground

based/roof Top or pole or wall mounted) in the format as prescribed by TEC, DoT,

establishing or certifying that all general public areas around the tower shall be within

safe EMR exposure limit as per peak traffic measurement after the antennae starts

radiating.

6. Scrutiny and Disposal of Application.- (1) The Sanctioning Authority shall verify and

may issue or refuse the permit, not later than forty five days from the date of receipt of application

along with the plans and documents as under regulation 4. In case of refusal, the reasons for the

same shall be clearly mentioned.

(2) The permit issued shall be a work permit and the construction or erection of

telecommunication tower or telecommunication pole structures or accessory rooms essential for the

use of such tower or pole structures shall be completed within two years from the date of issue of

such permit.

(3) The period of the permit shall be extended for a further period of two year if an application

for the same is submitted to the Sanctioning Authority, within the valid period of the permit duly

paying 25% of the prescribed fee and charges and in the prescribed form duly attaching the original

permit in these regulations.

7. Restriction to erect Telecommunication Infrastructure Towers.-

(1) Water Bodies: (i) No building or Telecommunication Infrastructure Tower shall be allowed

in the bed of water bodies like river or nala and in the Full Tank Level (FTL) of any lake, pond, kunta

lands. Unless and otherwise stated, the area and the Full Tank Level (FTL) of a Lake or Kunta shall

be reckoned as measured and as certified by the Irrigation Department (Water Resources

Department).

(ii) Telecommunication Infrastructure Tower shall not be erected within,-

(a) 6 meters from the boundary of the River.

(b) 5 meters from the boundary of Lakes or Tanks or Kuntas of area 10.00 Ha and above.

(d) 5 meters from the defined boundary of Canal, Nala, Storm Water Drain of width more than

10.00 meters and 3.00 meters from the defined boundary of Canal, Nala, Storm Water Drain

of width up to 10meters.

⁴

(2)

Railways:

The

distance

between

the

Railway

Property

Boundary

and

the

Telecommunication Infrastructure Tower shall be 30m as per Indian Railways Works Manual or as

per no objection certificate given by the Railway Authorities.

(3) Electrical Lines: The Right -of-way widths recommended for Electrical lines of various

Transmission Voltage are as indicated in the table below:-

(i) Right-of way (ROW) for Electrical lines.-

Sl.

No.

Transmission voltage

Width of the Right-of-way (ROW)

in meters

11 kV

7.0

33 kV

15.0

66 kV

18.0

110 kV

22.0

132 kV

27.0

220 kV

35.0

400 kV

52.0

(ii) Distance of site from Electric Lines.- No Telecommunication Infrastructure Tower shall be

allowed to be erected or re-erected or any additions or alterations made to Telecommunication

Infrastructure Tower in a site within the distance quoted below in accordance with the current

Electricity Rules and its amendments from time to time between the building and any overhead

electric supply line;

Vertically in mtrs.

Horizontally in

mtrs.

Low and medium voltage lines and

service lines

2.5

1.2

High

voltage

lines

upto

and

including 33,000 V.

3.7

2.0

iii

Extra high voltage lines beyond

33000 V.

3.7 (plus 0.3m for

every

additional

33,000 V. or part

thereof )

2.0 (plus 0.3m for

every

additional

33,000 V. or part

thereof )

(4) In the reserved forest or forest areas: for erecting the Towers, NOC from the Forest

Department shall be submitted.

(5) Heritage, Religious and Other Structures: (i) In case of Sites located within the

distance up to 100meters from protected monuments as notified under the Ancient Monuments and

Archeological sites and Remains Act 1958 (central Act 24 of 1958) or the Karnataka Ancient and

Historical monuments and Archeological sites and Remains Act, 1961 (Karnataka Act 7 of 1962) no

building or Telecommunication Infrastructure Tower is allowed;

(ii) For the Sites located within distance of above 100meters and up to 200meters from the

protected monuments, the construction of one Telecommunication Infrastructure Tower is allowed

only after obtaining prior permission from the Competent Authority.

(iii) Erection of Telecommunication Infrastructure Tower shall not be allowed within a distance

of 100m from the school, hospital, buildings and religious buildings or any other prescribed

buildings by the Government from time to time.

(iv) In case of Wall Mounted or Pole mounted Antenna, the antenna shall be mounted at least 5

meters above ground level or road level on flyovers.

8. Basic requirements to erect Telecommunication Infrastructure Towers.- (i) Set

Backs of Room or Tower:

(a) The minimum setback for the accessory room or ground based tower shall be as required

under the approved zoning Regulations of Local Planning Areas subject to the condition that it shall

⁵

be a minimum of 3m all-round, after leaving the road widening portion if any. If it is roof top

installation the tower shall have minimum 3m distance from the boundary of the building edge;

(b) In addition to the distance specified above, set back required for road widening proposed

in any of the Master Plan or Zonal Development Plan or Town Planning Scheme or Road

Development Plan or any other scheme sanctioned by the Government or Execution Authority shall

also be provided.

Provided that no portion of the telecommunication Infrastructure tower pole structure or

accessory room shall project or over hang into the neighboring plots.

Provided further that additional distance from boundary abutting the road and other

boundaries of the plot proportionate to increase in height shall not be necessary for the

telecommunication Infrastructure tower or pole structures or accessory rooms or for the building

over which they are proposed.

(ii) Accessory rooms:

(a) Accessory rooms such as equipment rooms, shelters or Generator rooms essential for the service

shall be permitted along with a telecommunication tower or telecommunication pole structures or

separately, if a request is made in the application and plans or drawings of the rooms are attached

either along with the application for permit or separately;

(b) The cabin may be made with any material but the area of such cabin shall not exceed 15 Square

Meters;

sound-proof cabin;

(d) Every construction or installation of ancillary necessary for the telecommunication system shall

conform to the relevant rules applicable to such construction or installation and license or permit

required under such rules shall also be obtained.

(e) The telecommunication tower or ancillary structures shall not prevent or block the access, exit or

entry or reduce the width of such access, exit or entry of building or in no way badly affect the safety

measures or amenities provided in the building in which it is erected.

(iii) Sharing of Sites: The Telecom Operators may share the towers for fixing their respective

antennas. The same are however, required to adhere to the prescribed technical requirements, so as

to curtail multiplicity of towers as well as to optimize the use of the existing ones. As sharing of

antennas on a single tower increases the effects of EMR (Electromagnetic radiations) manifold the

height of the tower shall be increased.

(iv) Installations:

(a) In order to avoid any eventuality due to thunder storm, lightning

conductors shall be installed.

(b) Generator set installed at the tower site to cater to the power

requirements of the antenna shall conform to the noise and emission norms as prescribed

by the Karnataka State Pollution Control Board.

(v) Protective Wall:

(a)

Every tower erected on the ground and through which electric power is transmitted or

passed shall be provided with protective wall or grill at a distance of one meter from any

point of the base.

(b)

The wall or grill shall have a minimum of 1.20m height and shall be kept

under lock and key, if provided with door.

(vi). Protection from lightning: Every telecommunication Infrastructure tower shall be provided

with sufficient protection against lightning, conforming to I.S. 2303-1969-Code of Practice, as

amended from time to time.

⁶

(vii). Warning lights:

(a) Every telecommunication tower shall be provided with two Aviation Warning Lights (ANL) each at

40m and 70m height from the ground level and one at the top, the two lights at 40m height shall be

fixed in one set of opposite corners and that at 70m height shall be fixed at the other set of opposite

corners.

(viii). Damage and liability: The applicant and owner shall be responsible for the structural

stability of the telecommunication Infrastructure tower and the building in which it is erected and

for any damage caused due to inadequate safety measures.

(ix). Building to be authorized: Erection of any telecommunication Infrastructure tower or pole

structures or accessory rooms shall be permitted only on buildings with valid permissions and

Occupancy Certificate obtained from the Local Body.

(x) Completion Certificate:

(a) After completion of the work of the telecommunication tower or pole structure and accessory

rooms as per permit, the applicant and the engineer shall submit to the Sanctioning Authority

completion certificate as in Appendix-A along with a certificate of structural safety or stability of the

tower and the building, if the tower or pole is constructed over a building.

(b) The Sanctioning Authority shall, if satisfied that the work has been completed as per permit,

issue use certificate as in Appendix-B allotting a number, on the basis of which the authorities

concerned shall allow power connection, etc. for use of the service.

(xi). Unauthorized Telecom Infrastructure Towers: The Sanctioning Authority shall take

necessary action on unauthorized Telecom Infrastructure Towers erected without valid permissions

or Completion Certificate, as per the Act provisions duly following the procedure.

Provided that the Radiation norms given by the Department of Telecommunications (DOT) have

to be strictly followed by all Tower Infrastructure Service Providers and limit the Power Emissions or

Radiations. All the complaints regarding radiation and radiation related technical details are being

dealt by TERM cell of Department of Telecommunications (DOT) and any citizen can approach the

concerned TERM Cell of Department of Telecommunications (DOT) with regard to grievance on any

issues relating to radiation.

9. Fee structure.- The fee to be levied while issuing the permit for installation of

Telecommunication Infrastructure Tower shall be as per the table-1 below:-

Table-1

Fee structure for installation of telecommunication infrastructure tower

Sl.

No.

Jurisdiction

One time Prescribed fee

per tower

Bruhat Bangalore Mahanagara Palike

Rs. 50,000

Corporations of the City other than Bruhat

Bangalore Mahanagara Palike

Rs. 40,000

City Municipal Councils

Rs. 30,000

Town Municipal Councils

Rs.20,000

Town Panchayaths

Rs.15,000

Gram Panchayaths

Rs.10,000

The property owner shall pay property taxes as per relevant rules.

By order and in the name of the Governor of Karnataka

Y. GOPAL

Under Secretary to Government,

Urban Development Department (MA-2).

APPENDIX- A

⁷

(See rule 8 (x)(a))

COMPLETION CERTIFICATE BY ARCHITECT, ENGINEER etc.

Certified that the development or re-development of land or construction or reconstruction or

alteration or addition of building or erection of telecommunication tower or pole structure or work

has been supervised by me and has been completed as per the approved plan and permit

No.dated..

Signature

Name and address of Architect or Building Designer or Engineer or Town Planner or

Supervisor Reg No.:

Place:

Date:

COMPLETION CERTIFICATE BY THE OWNER

(See rule 8 (x)(a))

Certified that the development or redevelopment of land or construction or reconstruction or

alteration or addition of building or erection of telecommunication tower or pole structure has been

completed or partially completed as per the approved plan and permit No...

dated..

(Signature)

Name and address of owner:

Place:

Date:

APPENDIX-B

(See rule 8 (x)(b))

OCCUPANCY CERTIFICATE OR USE CERTIFICATE

Certified that the construction or reconstruction or alteration or addition of building or erection of

telecommunication tower or pole structure or work under the permit No.

dated..issued to.... and supervised by..has

been inspected by me and that the work executed is in accordance with the permit and that the

building or tower or pole structure is now fit for occupation or use.

Place:

Date :

(Seal and Signature of Sanctioning Authority)

By Order and etc,

 !""#$

RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Thursday

No. UDD 1

The draft of the followi

Accounting and Budgeting Rule

exercise of the powers conferr

Municipalities Act 1964 ( Karnat

section (1) of section 323 of the sa

and notice is hereby given that th

the date of publication in the Karn

The Karnataka Municipali

rule 1 states that, The Karnataka

to the municipalities listed in sch

Government subsequently notifi

Municipalities Act, 1964. Once

Accounts Rules, 1965 shall not b

mentioned rule, the newly formed

Karnataka state government are

Accounting & Budgeting Rules 2

Any objection or suggestion

with respect to the said draft befo

the State Government. Any object

Government, Urban Development

Bangalore-560001.

1. Title and Commencement:-

1) These rules may be c

(Amendment) Rules 2015.

2) They shall come in to for

ª∞ «Ò∏Â

 

y, February 25, 2016 (Palguna 6, Shaka Vars

URBAN DEVELOPMENT SECRETARIAT

NOTIFICATION

14 GEL 2016(P), Bengaluru Dated: 25.02.

ng rules further to amend The Karna

es 2006, which the Government of Karnata

red by sub section (4) and section 32

taka Act 22 and 1964) is hereby published

aid Act, for the information of persons likely

he said draft will be taken into consideration

nataka official Gazette.

ities Accounting and Budgeting Rules 2

a Municipalities Accounting and Budgeting R

hedule 1 to these rules and to such municip

fies under sub section (4) of section 3

these rules become applicable, the Kar

be applicable in respect of those municipal

d municipalities through the final gazette no

being brought under the purview of the Ka

2006 and with all its amendments.

n which may be received by the State Govern

ore the expiry of the period specified abov

tion or suggestion may be addressed to the

t Department, 4

th Floor, Vikasa Soudha, Dr.

DRAFT RULES

called The Karnataka Municipalities Acco

rce with effect from 1

st day of April 2016.

∏Â√¿Ê

 !"#

sha 1937)

$% !!

No. 323

.2016

ataka Municipalities

aka propose to make in

23 of the Karnataka

d as required by sub

y to be affected thereby

n after thirty days from

006, sub-rule 3 under

Rules 2006 shall apply

palities that the State

23 of the Karnataka

rnataka Municipalities

lities. On par with this

otification made by the

arnataka Municipalities

nment from any person

e will be considered by

Principal Secretary to

B.R. Ambedkar Veedi,

unting and Budgeting

2. The schedule 1 of Karnataka Municipalities Accounting and Budgeting Rules 2006 shall

be added with the List of municipalities as mentioned below. This will be in continuation

with the existing 213 Municipalities.

Serial

Urban Local Bodies Names

Serial

Urban Local Bodies Names

214

Aminagad Town Panchayath

243

Jigani Town Municipal Council

215

Belagali Town Panchayath

244

Nayakanahatti Town Panchayath

216

Kamatagi Town Panchayath

245

Kotekar Town Panchayath

217

Hagaribommanahalli Town Municipal Council

246

Vitla Town Panchayath

218

Kurekuppa Town Municipal Council

247

Malebennuru Town Municipal Council

219

Kurugodu Town Municipal Council

248

Guttal Town Panchayath

220

Kudathini Town Panchayath

249

Karatagi Town Municipal Council

221

Mariyammanahalli Town Panchayath

250

Bhagyanagar Town Panchayath

222

Harugeri Town Municipal Council

251

Kanakagiri Town Panchayath

223

Mugalkhod Town Municipal Council

252

Kukanur Town Panchayath

224

Munavalli Town Municipal Council

253

Tavaragera Town Panchayath

225

Ugar Khurd Town Municipal Council

254

Maski Town Municipal Council

226

Ainapur Town Panchayath

255

Balaganur Town Panchayath

227

Arabhavi Town Panchayath

256

Kavitala Town Panchayath

228

Boragaon Town Panchayath

257

Sirawar Town Panchayath

229

Chennamman Kittur Town Panchayath

258

Turvihal Town Panchayath

230

Chinchali Town Panchayath

259

Bidadi Town Municipal Council

231

Examba Town Panchayath

260

Kaup Town Municipal Council

232

Kabbur Town Panchayath

261

Jali Town Panchayath

233

Kallolli Town Panchayath

262

Almel Town Panchayath

234

Kankanawadi Town Panchayath

263

Chadachana Town Panchayath

235

M.K Hubballi Town Panchayath

264

Devarahipparagi Town Panchayath

236

Mallapur P G Town Panchayath

265

Kolhar Town Panchayath

237

Naganur Town Panchayath

266

Managuli Town Panchayath

238

Shedbal Town Panchayath

267

Nalatawad Town Panchayath

239

Hebbagodi City Municipal Council

268

Nidagundi Town Panchayath

240

Attibele Town Municipal Council

269

Kakkera Town Municipal Council

241

Bommasandra Town Municipal Council

270

Kembhavi Town Municipal Council

242

Chandapura Town Municipal Council

By Order and in the name of the Governor of Karnataka,

Y. GOPAL

Under Secretary to Government,

Urban Development Department (MA-2)

 !""#$

RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Friday,

BANGALORE W

No.BWSSB/C/C

THE BANGALORE WATER SUPPL

In exercise of the powers

Sewerage Act, 1964 (Karnataka A

with the approval of the Governme

2015, dated 7.01.2016, the Ba

following Regulations, the draft o

section (2) of Section 88 of the sai

13.01.2016 duly published in Pa

namely,-

1. Title and Commencem

Supply and Sewerage (Rain Water

(2) They shall come into for

2. Substitution of regul

Sewerage (Rain Water harvesting)

“8. Levy of Additional Wa

residential building fails to provid

as notified under section 72A of

percent of the total water and

additional charges of fifty perc

harvesting structure is provided to

ª∞ «Ò∏Â

 

February 26, 2016 (Palguna 7, Shaka Varsha

WATER SUPPLY AND SEWERAGE BOARD, B

NOTIFICATION

CAO-S/4136/2015-16, Bangalore Dated: 25

LY AND SEWERAGE (RAIN WATER HARVE

REGULATIONS, 2015

conferred by Section 72-A and 88 of Banga

Act 36 of 1964) and all other power enablin

ent of Karnataka accorded in Government O

ngalore Water Supply and Sewerage Boa

of the said Regulations having been publishe

id Act, in Notification No.BWSSB/CH/CAO-S

art-IV A, pages 56 of the Karnataka Gaze

ment.- (1) These regulations may be called

r Harvesting) (Amendment) Regulations, 2015

rce from the date of their final publication in

ation 8.- For regulation 8 of the Bangal

Regulations, 2010, the following shall be su

ater and Sanitary Charges.- (1) Where the

de rain water harvesting structure in the bui

the Act, there shall be levied an additional

sanitary charges for the first three mont

cent of the total water and sanitary charg

o the building.

∏Â√¿Ê

 !"

a 1937)

#$ !%

No. 324

BANGALORE

5.02.2016

ESTING) (AMENDMENT)

alore Water Supply and

ng it in this behalf, and

Order No. UDD 191 MNI

ard hereby makes the

ed as required by sub-

S/3525/2015-16 dated

ette, dated 13.01.2016

d the Bangalore Water

n the Official Gazette.

lore Water Supply and

ubstituted, namely:-

Owner or Occupier of a

ilding within such date

l charges of twenty-five

ths and thereafter an

ges till the rain water

RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Friday,

BANGALORE W

No.BWSSB/C/CAO

THE BANGALORE W

In exercise of powers conf

Sewerage Act, 1964 ( Karnataka

with previous approval of the Stat

:7.01.2016, the Bangalore Wat

regulations further to amend to th

Regulations having been previou

Bangalore Water Supply and

S/3526/2015-16 dated 13.01.201

1. Title and Commencem

Supply (Amendment) Regulations,

(2) They shall come into for

2. Amendment of regula

after referred as the said regulatio

(i) in sub-regulation

(a) for the Table, the

SL.

No.

Natu

Residential building

Multistoried building

Group Housing or Vil

All types of Non-resid

(b) in clause (d) for the wo

and words “108 sq. mtrs and abov

“(j) In case of three and m

above the entire building attracts

apartments”

(ii) after sub regulation (3),

ª∞ «Ò∏Â

 

February 26, 2016 (Palguna 7, Shaka Varsha

WATER SUPPLY AND SEWERAGE BOARD, B

NOTIFICATION

O-S/4137/2015-16, Bangalore Dated: 25.0

WATER SUPPLY (AMENDMENT) REGULATIO

ferred by Sections 31, 61 and 88 of Banga

Act 36 0f 1964) and all other powers enablin

te Government vide Government Order No.UD

ter Supply and Sewerage Board hereby

he Bangalore Water Supply Regulations, 196

usly published as required by sub-section

Sewerage Act, 1964, vide Notification

16 in the Part III of Karnataka Gazette date

ment.- (1) These regulations may be called

, 2015.

rce from the date of their publication in the o

tion 5.- In the Bangalore Water Supply Regu

on) in regulation 5.-

n (3),-

e following shall be substituted, namely:-

“TABLE

ure of Buildings

Rate of

on tota

Rs. 250/

g or Residential Apartment or

llas etc.,

Rs. 400/

dential and Commercial building

Rs. 600/

ords, figures and symbol “more than 30 X

ve” shall be substituted ;

wing shall be inserted, namely:-

more houses are constructed on a site meas

pro-rate charges at the rates applicable to M

, the following shall be inserted, namely:-

∏Â√¿Ê

 !"

a 1937)

#$ !%

No. 325

BANGALORE

02.2016

ONS, 2015

alore Water Supply and

ng it in this behalf and

DD 94 MNI 2015 dated

makes the following

65, the draft of the said

n (2) of Section 88 of

NoBWSSB/CH/CAO-

ed 13.01.2016 namely,-

d the Bangalore Water

official Gazette.

ulations, 1965, (here in

f prorate charges

al built up area

/- per Sq. mtrs

40” the figures, letters

suring 108 sq.mtrs and

Multistoried residential

"5.4 Production of Occupancy Certificate.-

(a) In case of Multistoried residential and Non-residential buildings excluding ground floor +

2 floor, for water and sanitary connection, the applicant shall produce Occupancy Certificate issued

by the Bruhat Bangalore Mahanagara Palike or Local Authorities an evidence to show that his

application for occupancy is not refused by the Commissioner, Bruhat Bangalore Mahanagara Palike

with thirty days of his application before sanction.

(b) In case of non-production of documents specified in clause (a) applicant in respect of

domestic connection, temporary water and sanitary connection may be sanctioned subject to

additional levy of fifty percent of total water and sanitary charges.

of non-domestic connection, temporary water and sanitary connection may be sanctioned subject to

additional levy of hundred percent of the total water and sanitary charges.”

3. Substitution of regulation 28.- For regulation 28 of the said of regulations, the following

shall be substituted namely:-

“28. Water Meter Services Charges.- For every mater installed in a premises the meter

services charges shall be levied every month in addition to the charges for actual water

consumed.

The meter service charges are as follows:

TABLE - I

Sl.

No.

Bore Size

(In mm)

Domestic rate

(in) (Rs.)

Partial Non

Domestic (in) (Rs.)

Non-Domestic

Rate (in) (Rs.)

30-150 at the

rate specified in

table II

50-175 as specified in

table III

100

150

200

300

500

750

500

750

1000

750

1000

1250

100

1500

125

1750

150

2000

3000

200

3000

4000

5000

250

3500

5000

6000

300

4000

6000

7000

400

5000

7000

8000

Water Meter service charges for 15 MM Domestic Connection

TABLE - II

Consumption Block

Kilo Litres

Meter Charges for Month

(In Rs.)

0 - 8

8 - 25

25 - 50

Above 50

150

Water meter service charges for 15mm Non-Domestic connection

TABLE - III

Consumption

Block

Kilo Litres

Meter Charges

for Month

(In Rs.)

0 - 10

11 - 25

26 - 50

100

51 - 75

125

76 - 150

175

”

4. Amendment of regulation 36.- In regulation 36 of the said regulations,-

(i) under the heading I Water Supplied,-

(a) for the word “corporation” the words “Bruhat Bengaluru Mahanagar palike” Shall

be Substituted;

(b) for the table the following shall be Substituted namely:-

“TABLE

Domestic – Section 36(1) filtered Water

Consumption

Rate per 1000 litres

Sl.

No.

Slab-wise consumption of water

(In Kilo Litres)

Tariff

(in Rs.)

MINIMUM

0 - 8

56.00

(@ Rs.7.00 per Kilo Litres)

8 - 25

11.00

25 - 50

26.00

Above 50

45.00

(and the calculations shall be rounded off to the nearest rupee.)”

(ii) for the heading I-A and the entries relating there to the following shall be substituted

namely:-

“I-A. Water Tariff for consumption of Bulk Domestic Consumers for High- Rise or Multistoried

Buildings or Central and State Government Housing Complexes Villas or Individual Group Housing

and other Bulk Consumers:

Sl.

No.

Other Bulk Consumers

Water Tariff (Rs.

Per Kilo Litres)

Bulk Domestic Consumers for High-Rise or Multistoried Buildings or

Apartments or Central and State Government Housing Complexes

Villas or Individual Group Housing

Kanakapura Bulk Supply

Agara Grama Panchayat

Bruhat Bengaluru Mahanagara Palike Jurisdiction other than

erstwhile 7 City Municipal Councils and 1 Town Municipal Councils

area

”

(iii) under the heading III,-

(A) In item (a), for the figures and word “Rs 9.00 per” and “Rs. 39 per” the figures and

word “Rs 15.00 per” and “Rs 60.00 per” shall respectively be substituted;

(B) In item (b), for the figures and word “Rs 15.00 per” and “Rs 44.00 per figures and

word “Rs 25.00 per” “Rs 90.00 per” shall respectively be substituted.

(iv) under the heading IV water supplied Non Domestic.-

(A) In item (c), for the words “and poultry forms” the words “poultry farms and

slaughters houses;” shall be substituted.

(B) In item (r), for the tables the following tables shall be substituted, namely:-

⁴

“TABLE – I

Sl.

No.

Slab-wise consumption of

water (In Kilo Litres)

Tariff per Kilo

Litres (in Rs.)

MINIMUM

0 - 10

500.00

50.00

10 - 25

57.00

25 - 50

65.00

50 - 75

76.00

Above 75

87.00

“TABLE – II

NON-DOMESTIC TARIFF

Sl.No

Nature of Sector

Water Tariff

(in Rs. Per Kilo Litres)

III

Industries

90.00

III(a)

Bidadi Industrial Area (KIADB)

90.00

Lorry Loads

Rs.540.00(per Load)

Swimming Pools

90.00

BIAL

90.00

VedavijnanaMahaVidyaPeeta, Kanakapura

Road,

Jain

Internationnal

Residential

School Kanakapura Taluk

60.00

Note.- The calculations to be rounded to the nearest Rupee.”

(v) under the heading ‘V’ Raw Water Supplied, item (d) and the entries relating thereof shall

be omitted;

(vi) the heading ‘VII’ and the entries relating theeof shall be omitted;

(vii) under the heading ‘VIII’ for the figures ‘50’ the figures “100” shall be substituted;

(viii) under the heading ‘IX Recoiled Water’, after item (ii), the following shall be inserted

namely:-

“(iii) Rs. 20/- per Kilo Litres for supply of tertiary treated water to Government Department

and Government under takings.”

5. Insertion of new regulation 55A.- After regulation 55 of the said regulations, the

following shall be inserted, namely:-

“55-A. penalty of pro-rate charges for unauthorized connections.-Whoever obtains the

unauthorized water supply or sanitary connections or both by any means from the water supply

pipelines of the Board or sanitary connections to the sewerage system of the Board in contravention

of the provisions of the Act and Regulations made there under shall be liable to pay upto 50% of the

pro-rata charges payable as penalty as indicated in the table below:

TABLE

Number of years of unauthorized

Water or sanitary connection

Amount of Penalty

Up to 1 year

20% of Pro-rata charges

From 1 year up to 2 years

30% of Pro-rata charges

From 2 years up to 3 years

40% of Pro-rata charges

3 years and above

50% of Pro-rata charges

Note: The period of taking unauthorized connection may be determined on the basis of sanction of

electricity to the building or any other documents evidencing occupation of the building.”

By order,

Chief Administrative Officer cum Secretary,

Bangalore Water Supply and Sewerage Board

 !"#$

RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Friday,

BANGALORE W

NO:BWSSB/C/C

THE BANGALORE

In exercise of the powers

Sewerage Act, 1964 (Karnataka A

with previous approval of the St

dated: 7.01.2016, the Bangalore

regulations further to amend to

Regulations having been previou

Bangalore Water Supply and

S/3527/2015-16, dated 13.01.2

namely,-

1. Title and Commencem

(Amendment) Regulations, 2015.

(2) They shall come into for

2. Amendment of regul

(hereinafter referred to as said reg

(1) in sub-regulation (b), f

substituted;

(2) in sub-regulation (d), f

guidelines", the words and figur

Regulations, 1965" shall be substi

(3) in sub-regulation (e),-

(i)

in item (i), for the

shall be substituted

(ii)

in item (ii),-

ª∞ «Ò∏Â

 

February 26, 2016 (Palguna 7, Shaka Varsha

WATER SUPPLY AND SEWERAGE BOARD, B

NOTIFICATION

CAO-S/4138/2015-16, Bangalore Dated: 2

E SEWERAGE (AMENDMENT) REGULATIONS

conferred by Section 84 and 88 of Bangal

Act 36 of 1964) and all other powers enablin

tate Government vide Government Order N

Water Supply and Sewerage Board hereb

the Bangalore Sewerage Regulations, 1974

usly published as required by sub-section

Sewerage Act, 1964 vide Notification N

016 in the Part III of Karnataka Gazett

ment.- (1) These regulations may be called th

rce from the date of publication in the officia

lation 2.- In the Bangalore Water Sewera

gulations), in regulation 2,-

for the word "charges", the words "sanitary p

for the words and figures "as per section 16

res "as under the regulation 5.3 of the Ba

ituted;

e letters and figures "Rs.30/-", the letters a

∏Â√¿Ê

 !"

a 1937)

#$ !

No. 326

BANGALORE

25.02.2016

S, 2015

lore Water Supply and

ng it in this behalf and

No.UDD 192 MNI 2015

by makes the following

4, the draft of the said

n (2) of Section 88 of

No. BWSSB/CH/CAO-

te dated 13.01.2016 ,

he Bangalore Sewerage

al Gazette.

age Regulations, 1974

point charges" shall be

6 of the Act as per the

angalore Water Supply

and figures "Rs.100/-"

(a) for the letters and figures "Rs.50/-", the letters and figures "Rs.100/-" shall be

substituted;

(b) for the letters, figures, symbol and word "Rs 50 x No.", the letters, figures, symbol

and word "Rs.100 x No." shall be substituted;

(iii)

in item (iii), for the letters and figures "Rs.300/-", the letters and figures "Rs.500/-"

shall be substituted;

(iv)

in item (iv), for the letters and figures "Rs.300/-", the letters and figures "Rs.500/-"

shall be substituted.

(4) in sub-regulation (f),-

(i) under the heading "I. Domestic connection",-

(a) for item (1) and (2) and the entries relating thereo, the following shall be

substituted, namely:-

"(1) Where consumption of water is 0 to 8000 litres the sanitary charges shall be at

Rs.14.00 flat rate per connection.

(2) Where consumption of water is above 8000 litres, at

rate of 25% of water charges payable per month."

(b) item (3) shall be omitted.

(i)

in sub-item (a), for the figures "20%", the figures and symbol "25%"

shall be substituted;

(ii)

in sub-item (b), for the figures "50/-", the figures "100/-" shall be

substituted;

(iii)

in sub-item (c), for the figures "50/-", the figures "100/-" shall be

substituted;

(ii) under the heading "II.Non-domestic connection", for the figures and symbol "20% of water

charges", the figures and words "25% of water charges" shall be substituted.

(5) in sub-regulation (g),-

(i)

for the heading "(i) Domestic connection" and the entries relating thereto, the

following shall be substituted, namely:-

"(i) Domestic connection,- Rs. 100/- per month individual house or

per apartment"

(ii) under the heading "Non-domestic connection",-

(a) in item (1), for the letters and figures "Rs.300/-", the letters and figures "Rs.500/-"

shall be substituted;

(b) for item (2), the following shall be substituted, namely:-

"(2) (a) Darshini Hotels, cafeteria and coffee Bars Rs.1000/- per month;

(b) All kind of Hotels other than Hotels in clause (a) and star Hotels Rs.2000/-

per month"

"and more than 100 rooms Rs.20,000/- per month".

(d) for item (5) and (6), the following shall be substituted, namely:-

"(5) Star Hotels (All kinds of star).-

Sl.No.

Number of Rooms

Amount

Less than 50 rooms

Rs.10000/- per month

51 - 100 rooms

Rs.15000/- per month

More than 100 rooms

Rs.20000/- per month

(6) Shopping malls.-

Sl.No.

Type of Shopping Malls

Amount

Shopping Malls having theatres

Rs.25000/- per month

Shopping Malls without theatre

Rs.5000/- per month

Super Bazars Rs.1000/- per month

(e) in item (10), for the letters and figures "Rs.1000/-", the letters and figures "Rs.2000/-

" shall be substituted;

(f)

after item (10), the following shall be inserted, namely:-

"(11)HOSPITALS:

(a) Without beds :Rs. 2500/- per month.

(b) Beds up to 50 :Rs. 5000/- per month.

and Up to 100 :Rs.7500/- per month.

(d) Beds more than

101 and above : Rs.10000/- per month.

(e)Dispensary, Clinic : Rs.100/- per month.

(12) HOSTELS:

(a) Paying guest accommodation Rs.1000/- per month

(b) Hostels with non-domestic water supply Rs.1000/- per month"

3. Insertion of new regulation 4A.- After regulation 4 of the said regulations, the following

shall be inserted, namely:-

“4A. Adoption of dual piping system and providing modular Sewage Treatment

Plants.- (1) Any Owner, occupier or builder who after commencement of these regulations

constructs any buildings consisting of twenty or more houses or apartments or flats within the

Board jurisdiction shall provide modular sewage or grey water treatment plant (STP/GWTP) within

its premises and dual piping system one for toilet flushing purpose and the other for all other

purposes. Only treated water from the installed STP/GWTP shall be used for toilet flushing purpose

in such buildings.

(2) Any owner or occupier of an existing buildings consisting of twenty or more houses or

apartments or flats within the Board jurisdiction shall provide dual piping system and modular

sewage or grey water treatment plant (STP/GWTP) within its premises, within the date specified by

the Board. Only treated water from the STP/GWTP installed within its premises shall be used for

toilet flushing purposes after the date specified by the Board.

RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Friday,

PERSONEL

NO: DPAR

In the guidelines governi

appended to the Government Or

DPAR 203 HGG 2013, dt:30.01.2

on official duty, after the words C

No. 16 at para 3 (a), the following

16 (A) Chairman of

Sabha and Lok Sab

ª∞ «Ò∏Â

 

February 26, 2016 (Palguna 7, Shaka Varsha

L AND ADMINISTRATIVE REFORMS SECRE

ADDENDUM

R 31 HGG 2016, Bangalore, Dated: 24.02.

ing the extension of State Hospitality to t

rder No: DPAR 554 HGG 2005, dt: 22.04.2

2014, under the heading “State Guests” wh

Chairman of the Estimates committee, Lok S

shall be inserted.

f the Parliamentary Committees / Select C

bha,

By order and in the name of the Go

Dr. B.S. MANJUNATHA

Under Secretary to Gove

D.P.A.R(STATE PROT

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a 1937)

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No. 327

ETARIAT

.2016

the visiting dignitaries

2006 & Addendum No:

hen they visit the State

Sabha appearing in Sl.

Committees of Rajya

overnor of Karnataka,

A SWAMY

ernment-1,

TOCOL).

RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Friday,

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RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Saturday

No. LD 93

The draft of the Karnataka

of Employees State Insurance

Government of Karnataka propos

section 3, read with section 8 of t

1990) is hereby published as req

information of all persons likely t

draft will be taken into consid

Official Gazette.

Any objection or sugges

person with respect to the said

considered by the State Governme

Secretary to Government , Depa

1.Title and commenceme

(Absorption of Contract Doctor

Medical Services) (Special) Rule

(2) They shall come into

2. Definitions.- (1) In the

(a) “ Contract Doctor”

in the Department

Insurance Medica

Director, ESIS Me

not less than one y

of these rules;

(b) ‘Schedule’ means

ª∞ «Ò∏Â

 

 ! 

y, February 27, 2016 (Palguna 8, Shaka Vars

LABOUR SECRETARIAT

NOTIFICATION

LSI 2013, Bangalore, Dated: 26-02-2016

a Civil Services (Absorption of Contract Doc

Scheme Medical Services) (Special), Ru

ses to make in exercise of powers conferred

the Karnataka State Civil Services Act, 1978

quired by clause (a) of sub-section (2) of th

to be affected thereby and notice is hereby

deration after fifteen days from the date o

stion which may be received by the State

d draft, before the expiry of the period sp

ent. Objections and suggestions may be add

artment of Labour, Vikasa Soudha, Banga

DRAFT RULES

ent.- (1) These rules may be called the Ka

rs in the Department of Employees Sta

es, 2016.

force from the date of their publication in t

ese rules, unless the context otherwise requi

” means, a Doctor who has passed MBBS

t of Employees State Insurance Schem

al Officer on contract basis by the Stat

dical Services as the case may be and who h

year and continues to work as such on the d

Schedule appended to these rules;

∏Â√¿Ê

"#$

ha 1937)

%& ##

No. 336

ctors in the department

ules, 2016, which the

by sub-section (1) of

8 (Karnataka Act 14 of

he said section, for the

y given that the said

of its publication in the

e Government from any

pecified above, will be

dressed to the Principal

alore-560 001.

arnatak Civil Services

ate Insurance Scheme

the official gazette.

ires,-

Degree and appointed

e Medical Services as

te Government or the

has served as such for

date of commencement

(2) Other words and expressions used in these rules, but defined shall have the

same meaning respectively assigned to them in Karnataka Civil Services (General Recruitment)

Rules, 1977.

3. Absorption of Contract Doctors appointed in the Department of Employees

State Insurance Scheme Medical Services into the State Civil Services.- Notwithstanding

anything contained in the Karnataka Civil Services (General Recruitment) Rules, 1977 or the

Department of Employees State Insurance Scheme Medical Services (Recruitment) Rules, 2010 or

any other rules made or deemed to have been made under the provisions of the Karnataka Civil

Services Act, 1978 (Karnataka Act 14 of 1990), every Contract Doctor specified in column (2) of the

schedule who has completed not less than three years of service on the date of commencement of

these rules shall, with effect from the date of commencement of these rules, be absorbed , in the

category of post and pay scale specified in the columns (6) and (7) of the Schedule in the

Department of Employees State Insurance Scheme Medical Service:

Provided further that no such person shall be absorbed,-

(i)

if he was disqualified for appointment under the Karnataka Civil Services (General

Recruitment) Rules, 1977 on the date of his appointment as Doctor on Contract

basis;

(ii)

if he does not possess the minimum academic qualification , specified in the

relevant rules of recruitment applicable for recruitment to the said posts; and

(iii) in any post reserved for the persons belonging to the Scheduled Caste, or

Scheduled Tribes or other Backward Classes unless he belongs to such Caste, tribe

or backward Classes, as the case may be.

4. Pay, pension Leave and Seniority of Persons absorbed under these rules.-

Notwithstanding anything contained in the Karnataka Civil Service Rules,-

(i) the initial basic pay of Contract Insurance Medical Officer shall be fixed at the

minimum of the pay scale applicable to the category of post to which he is

absorbed under rule 3;

(ii) The service rendered by a person as Contract Insurance Medical Officer prior to the

date of absorption shall not count for the purposes of leave, Pay, Pension, seniority

and grant of Promotion as Senior Insurance Medical Officer, Chief Insurance

Medical Officer, Junior Specialist or Senior Specialist under Time Bound Advance

Scheme or for grant of selection time scale of pay.

5. Application of other rules.- The provisions of the Karnataka Civil Services Rules, the

Karnataka Civil Services (Conduct) Rules, 1966 and all other rules regulating the conditions of

service of Government Servants in so far as they are not inconsistent with the provisions of these

rules, shall apply to persons absorbed under these rules.

By order and in the name of the Governor of Karnataka

Lakshmi Devi

Desk Officer-5,

Labour Department,

(ESIS Medical Services)

SCHEDULE-1

Notification No. LD 93 LSI 2013 Bangalore Dated:26-02-2016.

(See Rule 4(1)

Sl.No.

Category of posts and scale of pay

No. Of vacancies to be filled

Minimum qualification

(1)

(2)

(3)

(4)

Insurance Medical Officer

Rs. 28100-700-28800-800-33600-900-39000-1050-45300-

1200-50100

1) Must possess MBBS Degree or equivalent qualification

from an Institution recognised by MCI / KMC

2) Must have registered in MCI / KMC

Lakshmi Devi

Desk Officer-5,

Labour Department,

(ESIS Medical Services)

SCHEDULE-1

Notification No. LD 93 LSI 2013, Bangalore Dated:26-02-2016

(See Rule 3)

Sl.

No.

Name of the IMO and

Place of working

Contract Appointment

Order No. & Date

Date of joining

Date of birth

Post to which absorbed

under these rules

Pay scale of the

post in which

absorbed

Category

(1)

(2)

(3)

(4)

(5)

(6)

(7)

(8)

Dr. Ruksana Tabassum R.

E S I Hospital, Hubli

Govt. Notification

No.LD 435 LSI 2004

Dt. 26-07-2008

11-08-2008

15-04-1979

IMO

Rs. 28100-50100

Dr. Rizwan Ahmed,

ESI Dispensary, Karkala

-- “ --

10-10-2008

01-05-1974

IMO

Rs. 28100-50100

Lakshmi Devi

Desk Officer-5,

Labour Department,

(ESIS Medical Services)

 !""#$

RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Monday,

No. RD 376

The draft of the following

was published as required by su

1964 (Karnataka Act 12 of 1964)

in Part IV-A of the Karnataka Gaz

the persons likely to be affected

Official Gazette.

Whereas the said Gazette w

And whereas no objection

within the period specified above.

Now, therefore, in exercise

Karnataka Land Revenue Act, 1

hereby makes the following rules t

1. Title and commencem

(Second Amendment) Rules, 2016

(2) They shall come into for

2. Amendment of Rule 1

referred to as the said Rules), in ru

“Provided that the applic

dimension exceeding 2400 squar

person in Form No.3A within six

Revenue (Second Amendment) Ru

ª∞ «Ò∏Â

 

 !

February 29, 2016 (Palguna 10, Shaka Varsh

REVENUE SECRETARIAT

NOTIFICATION

6 LGP 2013, Bengaluru, Dated: 29-02-201

rules further to amend the Karnataka Land

ub-section (1) of section 197 of the Karnata

in Notification No. RD 376 LGP 2013 dated

zette dated:18-01-2016 inviting objections an

thereby within fifteen days from the date o

was made available to the Public on 18-01-2

ns and suggestions have been received by

e of the powers conferred by sub-section (1

964 (Karnataka Act 12 of 1964), the Gov

to amend the Karnataka Land Revenue Rule

RULES

ment.-(1) These rules may be called the Kar

6.

rce from the date of their publication in the O

108-Q .- In the Karnataka Land Revenue Ru

ule 108-Q the following proviso shall be inse

cation for grant of land under Section 94

re feet but not more than 4000 square fee

months from the date of commencement o

ules, 2016.”

∏Â√¿Ê

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No. 337

d Revenue Rules, 1966

aka Land Revenue Act,

:18-01-2016, published

nd suggestions from all

of its publication in the

2016.

the State Government

) of section 197 of the

vernment of Karnataka

es, 1966, namely:-

rnataka Land Revenue

Official Gazette.

ules, 1966 (hereinafter

erted, namely :-

4C in respect of Site

et shall be made by a

of the Karnataka Land

RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Monday,

 

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RNI No. KARBIL/2001/47147

∞¬Òûª

– IV-A

Part– IV-A

 

Bengaluru, Monday,

URB

NO. UDD 619

Whereas the Government

619 MNX 2014 appointed a Comm

Kempanna, a retired Judge of Ho

relating to De-notification and Mo

Whereas in the above said

its report by the Commission.

Whereas the term of the

Notification bearing No. UDD 6

commission ended on 31.08.2015

Whereas the term of the c

vide Notification bearing No. UD

commission ends on 29.02.2016.

Whereas the Secretary to

bearing No. JHSKC:175/2016 req

reasons stated therein by six mon

Whereas after considering

of Karnataka hereby extend the p

Commission shall submit its repo

months from 01.03.2016.

ª∞ «Ò∏Â

 

 !

February 29, 2016 (Palguna 10, Shaka Varsh

BAN DEVELOPMENT SECRETARIAT

NOTIFICATION

9 MNX 2014, Bengaluru, Dated: 19-02-20

of Karnataka vide Nofification dated 16.08.

mission of inquiry under the Chairmanship

n’ble High Court of Karnataka to ascertain

odification in the Arkavathi Layout Scheme.

d Notification a period of six months time w

commission was extended by six months

619 MNX 2014 dated 27.02.2015 and th

commission was further extended by six mo

DD 619 MNX 2014 dated 26.08.2015 and

the above said Commission vide their prop

quested that the term of the Commission m

nths from 01.03.2016.

g the observation made in the above said pro

period for the period of six months for sub

ort to the Government as soon as possible

By Order and in the name of the

N. Narasimha M

Under Secretary to G

Urban Development D

 !"#$

∏Â√¿Ê

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ha 1937)

%& ""

No. 339

2014 bearing No. UDD

of Hon’ble Justice H.S.

the truth of the matter

was fixed for submitting

from 28.02.2015 vide

he term fixed for the

onths from 01.09.2015

the term fixed for the

posal dated 28.01.2016

may be extended for the

oposal, the Government

bmission of report. The

but not later than six

Governor of Karnataka

Murthy

Government

Department