Full Text
REGD. No. D. L.-33004/99
The Gazette of India
CG-DL-E-12072023-247252
EXTRAORDINARY
PART III—Section 4
PUBLISHED BY AUTHORITY
No. 488] NEW DELHI, TUESDAY, JULY 11, 2023/ASHADHA 20, 1945
CENTRAL ELECTRICITY REGULATORY COMMISSION
PREAMBLE
New Delhi, the 29th May, 2023
No. L-1/265/2022/CERC.--The term "Grid" has been defined in sub-section 32 of Section 2 of the
Electricity Act, 2003 (the Act) to mean the high voltage backbone system of inter-connected transmission lines, sub-
stations and generating plants. The Central Commission has been vested with the functions under clause (h) of sub-
section (1) of Section 79 of the Act to specify the Grid Code having regard to the Grid Standards. Clause (d) of
Section 73 of the Act mandates the Central Electricity Authority to specify the Grid Standards for operation and
maintenance of the transmission lines. Further, clause (i) of sub-section (1) of Section 79 of the Act enjoins upon the
Central Commission to specify and enforce the standards with respect to the quality, continuity and reliability of
services by the licensees. Sub-Section 2 of Section 28 of the Act provides that the Regional Load Despatch Centre
shall comply with such principles, guidelines and methodologies in respect of wheeling and optimum scheduling and
despatch of electricity as the Central Commission may specify in the Grid Code. Clause (e) of sub-section (3) of
Section 28 of the Act provides that the Regional Load Despatch Centre shall be responsible for carrying out real time
operations for grid control and despatch of electricity within the region through secure and economic operation of the
regional grid in accordance with the Grid Standards and the Grid Code. Sub-Section (1) of Section 26 of the Act
provides that National Load Despatch Centre shall be established at the national level for optimum scheduling and
despatch of electricity among the Regional Load Despatch Centres. Sub-Section (1) of Section 29 of the Act provides
that the Regional Load Despatch Centre shall give such directions and exercise such supervision and control as may
be required for ensuring the stability of the grid operation and for achieving the maximum economy and efficiency in
the operation of the power system in the region under its control. Sub-section (2) of Section 29 of the Act mandates
that 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 Regional Load Despatch Centre under
sub-section (1). Sub-Section (3) of Section 29 provides that all directions issued by the Regional Load Despatch
Centres to the transmission licensee of State transmission lines or any other licensee of the State or generating
company (other than those connected with inter-State transmission System) or sub-station in the State shall be issued
through the State Load Despatch Centre which shall ensure compliance with such directions by the concerned
generating company or the licensee or sub-station. Sub-Section (3) of Section 33 of the Act provides that the State
Load Despatch Centre shall comply with the directions of the Regional Load Despatch Centre. Sub-section (4) of
Section 29 of the Act provides that the Regional Power Committee in the region may, from time to time, agree on
matters concerning the stability and smooth operation of the integrated grid and economy and efficiency of the power
system within the region. While Section 38 and Section 39 deal with the functions of the Central Transmission Utility
and State Transmission Utility respectively, Section 40 and Section 42 deal with the duties of the transmission
licensees and distribution licensees respectively. Therefore, the Act envisages and assigns specific roles and functions
to Central Electricity Authority, Regional Power Committees, Central Transmission Utility, National Load Despatch
Centre, Regional Load Despatch Centres, State Transmission Utilities, State Load Despatch Centres, generating
companies and licensees and any other person connected with the operation of the power system in order to achieve
real time operation and control of the grid and optimum scheduling and dispatch of electricity within the regions and
amongst the regions as well as within the States for not only for ensuring secure, economic and stable operation of the
grid but also for achieving maximum economy and efficiency of the power system.
Accordingly, the Grid Code hereinafter specified by the Central Commission contains the provisions
regarding the roles, functions and responsibilities of the concerned statutory bodies, generating companies, licensees,
and any other person connected with the operation of the power systems within the statutory framework envisaged in
the Act and the Rules and Notifications issued by the Central Government.
Under clause (h) of sub-section (1) of Section 86 of the Act, the State Commissions are mandated to specify
the State Grid Codes consistent with the Grid Code specified by the Central Commission under clause (h) of sub-
section (1) of Section 79 of the Act. This has been duly recognized by the Honble Supreme Court in its judgement
dated 17.8.2007 in Civil Appeal No. 2104 of 2006 in the matter of Central Power Distribution Company & Others Vs
Central Electricity Regulatory Commission.
Keeping in view the mandate and statutory framework as envisaged in the Act for stable, reliable and secure
grid operation in order to achieve maximum economy and efficiency of the power system, the Grid Code apart from
the provisions relating to the role of various statutory bodies and organizations and functional linkages among them,
contains extensive provisions pertaining to (a) reliability and adequacy of resources; (b) technical and design criteria
for connectivity to the grid including integration of new elements, trial operation and declaration of commercial
operation of generating stations and inter-State transmission systems; (c) protection setting and performance
monitoring of the protection systems including protection audit; (d) operational requirements and technical
capabilities for secure and reliable grid operation including load generation balance, outage planning and system
operation; (e) unit commitment, scheduling and despatch criteria for physical delivery of electricity; (f) integration of
renewables; (g) ancillary services and reserves; and (g) cyber security etc.
NOTIFICATION
In exercise of powers conferred under clause (h) of sub-section (1) of Section 79 read with clause (g) of sub-section
(2) of Section 178 of the Electricity Act, 2003 (36 of 2003), and all other powers enabling it in this behalf, the Central
Electricity Regulatory Commission hereby specifies the Grid Code as under:
CHAPTER1
PRELIMINARY
1. SHORT TITLE, EXTENT AND COMMENCEMENT
(1) These regulations may be called the Central Electricity Regulatory Commission (Indian Electricity Grid
Code) Regulations, 2023.
(2) These regulations shall come into force from such date as the Central Commission may notify:
Provided that different dates may be appointed for commencement of different regulations.
2. SCOPE AND EXTENT OF APPLICATION
(1) These regulations shall apply to: all users, State Load Despatch Centres, Renewable Energy Management
Centres, Regional Load Despatch Centres, National Load Despatch Centre, Central Transmission Utility,
State Transmission Utilities, licensees, Regional Power Committees, Settlement Nodal Agencies, Qualified
Coordinating Agencies and Power Exchanges to the extent applicable.
(2) For the purpose of these regulations, Damodar Valley Corporation (DVC) shall be treated as a regional entity
and a separate control area. The DVC Load Despatch Centre shall perform functions of an SLDC for the
control area of DVC.
(3) The generating stations of the Bhakra Beas Management Board (BBMB) and Sardar Sarovar Project (SSP)
shall be treated as regional entities and their generating units shall be scheduled and despatched by
respective RLDC in coordination with BBMB or Narmada Control Authority, as the case may be, having
due regard to the irrigation and drinking requirements of the participating States.
(4) Any country inter-connected with the National Grid or Regional Grid shall be treated as a separate control
area.
3. DEFINITIONS
(1) In these regulations, unless the context otherwise requires:
Sl.No. Particulars Definition
1. ,,Act
2. ,,Alert State means the Electricity Act, 2003;
3.
,,Ancillary Services means the state in which the operational parameters of the power
4.
5. system are within their respective operational limits, but a single
6.
n-1 contingency leads to violation of system security;
in relation to power system operation, means the services
necessary to support the grid operation in maintaining power
quality, reliability and
security of the grid and includes Primary Reserve Ancillary
Service, Secondary Reserve
Ancillary Service, Tertiary Reserve Ancillary Service, active
power support for load
following, reactive power support, black start and such other
services as defined in these regulations;
,,Ancillary Services Regulations Means the Central Electricity Regulatory Commission (Ancillary
or ,,AS Regulations Services) Regulations, 2022;
,,Associated Transmission shall have the same meaning as defined in the GNA Regulations;
System or ,,ATS
,,Area Control Error or ,,ACE shall be as specified under clause (11) of Regulation 30 of these
regulations;
7. ,,Automatic Generation Control means a mechanism that automatically adjusts the generation of a
or ,,AGC control area to maintain its interchange schedule plus its share of
frequency response;
8. ,,Automatic Voltage Regulator or means a continuously acting automatic excitation control system
,,AVR to control the voltage of a generating unit measured at the
generator terminals;
9. ,,Auxiliary Energy Consumption shall have the same meaning as defined in the Tariff Regulations;
10. ,,Available Transfer Capability or means available power transfer capability across control areas or
,,ATC across regions or between ISTS and state network or between
cross-border interconnections declared by the concerned load
despatch centre for scheduling transactions in a specific direction
with due consideration for the network security. Mathematically,
ATC is the Total Transfer Capability less Transmission
Reliability Margin;
11. ,,Available Capacity shall have the same meaning as defined in the DSM Regulations;
12. ,,Beneficiary means a person who has a share in an ISGS in terms of sub-clause
(117) of this clause;
13. ,,Bilateral Transaction means a transaction, other than collective transaction, for
exchange of power between a specified buyer and a specified
seller directly or through a trading licensee or at a Power
Exchange;
14. ,,Blackout State means a condition at a specific time where a part or all the
operations of the power system have got suspended;
15. ,,Black Start Procedure means the procedure necessary to recover from a partial or a total
blackout in the region;
16. ,,Bulk Consumer shall have the same meaning as defined in CEA Technical
Standards for Connectivity;
17. ,,Buyer means a person purchasing electricity through a transaction
scheduled through inter-State transmission system in accordance
with these regulations;
18. ,,Captive Generating Plant shall have the same meaning as defined in the Act;
19. ,,CEA Grid Standards means the Central Electricity Authority (Grid Standards)
Regulations, 2010;
20. ,,CEA Technical Standards for means the Central Electricity Authority (Technical Standards for
Sl.No. Particulars Definition
21. Communication Communication System in Power System Operation)
22. ,,CEA Technical Standards for Regulations, 2020;
23. Connectivity means the Central Electricity Authority (Technical Standards for
24. ,,CEA Technical Standards for Connectivity to the Grid) Regulations, 2007;
25. Construction means the Central Electricity Authority (Technical Standards for
26. ,,Central Generating Station Construction of Electrical Plants and Electric Lines) Regulations,
27. ,,Central Transmission Utility or 2010;
28. ,,CTU means the generating station owned by a company owned or
29. ,,Cold Start controlled by the Central Government;
30. means any government company, which the Central Government
,,Collective Transaction may notify under sub-section (1) of Section 38 of the Act;
31. ,,Commission in relation to steam turbine means start up after a shutdown
,,Communication System period exceeding 72 hours (turbine metal temperatures below
32. approximately 40% of their full load values);
,,Congestion shall have the same meaning as defined in the Central Electricity
33. Regulatory Commission (Power Market) Regulations, 2021;
34. ,,Connectivity Agreement means the Central Electricity Regulatory Commission referred to
35. in sub-section (1) of Section 76 of the Act;
,,Connectivity shall have the same meaning as defined in the Central Electricity
36. Regulatory Commission (Communication System for inter-State
37. ,,Control Area transmission of electricity) Regulations, 2017;
means a situation where the demand for transmission capacity or
38. ,,Control Centre power flow on any transmission corridor exceeds its Available
39. Transfer Capability;
,,Date of Commercial Operation means an agreement between CTU and any other person(s)
or ,,COD setting out the terms and conditions relating to connection to
,,Declared Capacity or ,,DC and/or use of the Inter-State Transmission System in terms of
GNA Regulations and as specified in Regulation 9 of these
,,Demand regulations;
,,Demand Response means the state of getting connected to the inter-State
transmission system by a generating station including a captive
,,Despatch Schedule generating plant, a bulk consumer or an Inter-State Transmission
licensee, in terms of the GNA Regulations;
,,DSM Regulations 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 and contributes to regulation of frequency as
specified in these regulations;
includes NLDC or RLDC or REMC or SLDC or Area LDC or
Sub-LDC or DISCOM LDC including main and backup Centres,
as applicable;
shall have the same meaning as specified under Regulation 27 of
these regulations;
in relation to a generating station means, the capability to deliver
ex-bus electricity in MW declared by such generating station in
relation to any time-block of the day as defined in the Grid Code
or whole of the day, duly taking into account the availability of
fuel or water, and subject to further qualification as per provisions
of Chapter-7 of these regulations;
means the demand of active power in MW and reactive power in
MVAr;
means variation in electricity usage by the end consumers or by a
control area manually or automatically, on standalone or
aggregated basis, in response to the system requirements as
identified by the concerned load despatch centre;
means the ex-power plant net MW and MWh output of a
generating station, for a time block, scheduled to be injected to
the Grid from time to time;
means the Central Electricity Regulatory Commission (Deviation
Settlement Mechanism and related matters) Regulations, 2022;
Sl.No. Particulars Definition
40. ,,Disturbance Recorder or ,,DR
41. means a device for recording the behavior of the pre-selected
42. ,,Data Acquisition System or
43. ,,DAS digital and analog values of the system parameters during an
44. ,,Drawal Schedule
45. event;
46. ,,DVC
means a system for recording the sequence of operation in time,
47. ,,Emergency State
48. of the relays or equipment as well as the measurement of pre-
49. ,,Energy Charge
50. ,,Energy Storage System or selected system parameters;
51. ,,ESS
52. means the summation of the station-wise ex-power plant drawal
53. ,,Event
,,Event Logging Facilities schedules from all ISGS and drawal from or injection to regional
54. ,,Ex-Power Plant
55. ,,Fault Locator or ,,FL grid under GNA and T-GNA;
56.
,,Flat frequency control means the Damodar Valley Corporation established under sub-
57.
,,Flat tie-line control section (1) of Section 3 of the Damodar Valley Corporation Act,
58.
,,Flexible Alternating Current 1948;
Transmission System or
,,FACTS means the state in which one or more operational parameters are
,,Flow-gate outside their operating limit or many of the equipment connected
,,Forced Outage to the grid are operating above their respective loading limit;
Free Governor Mode of
Operation Means the energy charge for the generating stations whose tariffs
are determined by the Commission under Section 62 of the Act.
in relation to the electricity system, means a facility where
electrical energy is converted into any form of energy which can
be stored, and subsequently reconverted into electrical energy and
injected back into the grid;
means an unscheduled or unplanned occurrence in the grid
including faults, incidents and breakdowns;
means a device for recording the chronological sequence of
operations, of the relays and other equipment;
means net MW or MWh output of a generating station, after
deducting auxiliary consumption and transformation losses;
means a device installed at the end of a transmission line to
measure or indicate the distance at which a line fault may have
occurred;
means a mechanism for correcting ACE by factoring in only the
frequency deviation and ignoring the deviation of net actual
interchange from net scheduled interchange;
means a mechanism for correcting ACE by factoring in only the
deviation of net actual interchange from net scheduled
interchange ignoring frequency deviation;
means a power electronics based system and other static
equipment that provide control of one or more AC transmission
system parameters to improve power system stability, enhance
controllability and increase power transfer capability of
transmission systems;
means a group of parallel transmission line (s), outage of which
may lead to cascade tripping or separation of systems or loss of
generation complex or loss of load centre;
means an outage of a generating unit or a transmission facility
due to a fault or any other reasons which have not been planned;
Means the mode of operation of governor where machines are
loaded or unloaded directly in response to grid frequency i.e
machine unloads when grid frequency is more than 50 Hz and
loads when grid frequency is less than 50 Hz. The amount of
loading or unloading is proportional to the governor droop.
,,Frequency Response means automatic, sustained change in the
Characteristics or ,,FRC power consumption by load or output of the generators that
occurs immediately after a
change in the load-generation balance of a control area and which
is in a direction to
oppose any change in frequency. Mathematically it is equivalent
to
FRC = Change in Power (P) / Change in Frequency (f);
,,Frequency Response Obligation means the minimum frequency response a control area has to
Sl.No. Particulars Definition
59. provide in the event of any frequency deviation;
60. or ,,FRO means the ratio of actual frequency response with frequency
61. response obligation;
62. ,,Frequency Response means the ability of the transmission system to maintain stable
frequency in the normal state and after being subjected to a
63. Performance or ,,FRP disturbance;
64. means the time at which the bidding for a specific delivery
65. ,,Frequency Stability period closes at the power exchange and no further bidding or
66. modification of already placed bids can take place for the said
67. ,,Gate Closure delivery period.
68.
,,Generating Unit means
69. a) an unit of a generating station (other than those covered in
70. ,,GNA Regulations
71. ,,GNA Grantee sub-clauses (b) and (c) of this clause) having electrical
72. ,,Governor Droop generator coupled to a prime mover within a power station
73. together with all plant and apparatus at the power station
74. ,,Grid Security which relate exclusively to operation of that turbo-generator , ;
,,Hot Start b) an inverter along with associated photovoltaic modules and
,,Inertia other equipment in respect of generating station based on solar
photo voltaic technology;
,,Infirm Power c) a wind turbine generator with associated equipment, in respect
of generating station based on wind energy;
Intermediary Procurer d) in respect of RHGS, combination of hydro generator under
sub-clause (a); or solar generator under sub-clause (b) or wind
,,Inter-State Generating generator under sub-clause (c) of this clause;
Station or ,,ISGS means the Central Electricity Regulatory Commission
(Connectivity and General Network Access to the inter-State
,,Inter-State Transmission System Transmission System) Regulations, 2022;
or ,,ISTS
means a person who has been granted GNA or is deemed to have
,,Load been granted GNA under GNA Regulations;
,,Maximum Continuous Rating or in relation to the operation of the governor of a generating unit
,,MCR means the percentage drop in system frequency which would
cause the generating unit under governor action to change its
output from no load to full load;
means the power systems capability to retain a normal state or to
return to a normal state as soon as possible, and which is
characterized by operational security limits;
in relation to steam turbine, means the start up after a shutdown
period of less than 10 hours (turbine metal temperatures below
approximately 80% of their full load values);
means the contribution to the capability of the power system to
resist changes in frequency by means of an inertial response from
a generating unit, network element or other equipment that is
coupled with the power system and synchronized to the
frequency of the power system;
means the electricity injected into the grid prior to the date of
commercial operation of a unit of the generating station;
shall have the same meaning as defined in Electricity
(Amendment) Rules, 2022
means a central generating station or any other generating station
having a scheme for generation and sale of electricity in more
than one state;
shall have the same meaning as defined in sub-section (36) of
Section 2 of the Act;
means the active, reactive or apparent power consumed by a
utility/installation of consumer;
means the maximum continuous output in MW at the generator
terminals guaranteed by the manufacturer at rated parameters;
Sl.No. Particulars Definition
75. ,,Merit Order means the order of ranking of available electricity generation in
76. ascending order from least energy charge to highest energy
,,Minimum Turndown Level charge to be used for deciding despatch instructions to minimize
77. the overall cost of generation;
78. means the minimum output power expressed in percentage of
79. maximum continuous power rating that the generating unit can
80. sustain continuously; to be on bar and includes minimum power
81. level as defined in CEA (Flexible Operation of Coal based
82. Thermal Power Generating Units) Regulations, 2023
83.
84. ,,Nadir Frequency means minimum frequency after a contingency in case of
85. generation loss and maximum frequency after a contingency in
,,National Grid case of load loss;
86. means the entire inter-connected electric power network of the
,,National Load Despatch Centre country;
87. or ,,NLDC means the centre established under sub-section (1) of Section 26
88. ,,Near Miss Event of the Act;
89. means an incident of multiple failures that has the potential to
cause a grid disturbance, power failure or partial collapse but
90. does not result in a grid disturbance;
91.
,,Net Drawal Schedule means the drawal schedule of a regional entity which is the
,,Net Injection Schedule algebraic sum of all its transactions through the inter-State
,,Normal State transmission system at ISTS periphery after deducting the
transmission losses;
means the injection schedule of a regional entity which is the
algebraic sum of all its transactions through the inter-State
transmission system at ISTS periphery;
means the state in which the operational parameters of the power
system are within their respective operational limits and
equipments are within their respective loading limits;
,,Off-Bar Declared Capability means the difference between Declared Capacity and On-Bar
,,On-Bar Declared Capacity Declared Capacity in MW;
in relation to a generating station means the capability to deliver
,,On-Bar Installed Capacity ex-bus electricity in MW from the units on-bar declared by such
generating station in relation to any time block of the day or
,,Operation Co-ordination Sub- whole of the day, duly taking into account the availability of fuel
Committee or ,,OCC and water and subject to further qualification in the relevant
,,Operational Parameters regulations;
means the summation of name plate capacities or the capacities as
approved by the Commission from time to time, of all units of the
generating station in MW which are on- bar. In case of a
combined cycle module of a gas or liquid fuel-based stations, the
installed capacity of steam turbine shall be in proportion to the
on-bar capacity of gas turbines of the module;
means a sub-committee of RPC which deliberates and decides the
operational aspects of the regional grid;
means the parameters for system security as specified by the
system operator including frequency, voltage at station-bus,
angular separation, damping ratio, short circuit level, inertia;
,,Pool Account means Deviation and Ancillary Service Pool Account as
defined in the DSM Regulations, where the following
transactions shall be accounted:
i. deviations and ancillary services
ii. reactive energy exchanges
iii. congestion charge;
,,Pooling Station means the ISTS grid sub-station where pooling of generation of
connected individual generating stations is done for interfacing
with the next higher voltage level;
,,Power System shall have the same meaning as defined in sub-section (50) of
Section 2 of the Act
Sl.No. Particulars Definition
92. ,,Primary Reserve means the maximum quantum of power which will immediately
come into service through governor action of the generator or
93. ,,Protection Co-ordination Sub- frequency controller or through any other resource in the event of
94. Committee sudden change in frequency as specified in clause (10) of
,,Qualified Coordinating Agency Regulation 30 of these regulations;
95. or ,,QCA means a sub-committee of RPC with members from all the
96. regional entities which decides on the protection aspects of the
97. ,,Ramp Rate regional grid;
98. ,,Rate of Change of Frequency or means the lead generator or any authorized agency on behalf of
99. ,,df/dt REGS or RHGS (as per GNA Regulations) including Energy
100. ,,Reference contingency Storage Systems connected to one or more pooling station(s) for
101. coordinating with concerned load despatch centre for scheduling,
102. ,,Regional Entity operational coordination and deviation settlement;
,,Regional Power Committee or means rate of change of a generating station output expressed in
103. ,,RPC %MW per minute;
104. ,,Restorative State means the time derivative of the power system frequency which
105. ,,Regional Energy Account or negates short term transients and therefore reflects the actual
106. ,,REA change in synchronous network frequency;
107. ,,Regional Transmission Account means the maximum positive power deviation occurring
or ,,RTA instantaneously between generation and demand and considered
108. for estimation of reserves;
109. ,,Regional Grid means the entitiy which is in the RLDC control area and whose
110. ,,Regional Load Despatch Centre metering and energy accounting is done at the regional level;
or ,,RLDC shall have the same meaning as defined under sub-section (55) of
111. ,,Renewable Energy Generating Section 2 of the Act.
Station or REGS means a condition in which control action is being taken to
"Renewable Hybrid Generating reconnect the system elements and to restore system load;
Station" or "RHGS" means account of energy and other parameters issued by the
,,Resilience respective RPC for the purpose of billing and settlement of
charges of ISGS and other users of the concerned region;
,,SCED Account means accounts of transmission issued by the RPC for the
,,SCED Compensation Charge purpose of billing and settlement of transmission charges of
ISTS in the concerned region in accordance with the Sharing
,,Secondary Reserve Regulations;
means the high voltage backbone system of inter-connected
,,Secondary Reserve Ancillary transmission lines, sub-stations and generating plants in a region;
Service or ,,SRAS means the Centre established under sub-section (1) of Section
27 of the Act;
means a generating station based on a renewable source of energy
with or without Energy Storage System and shall include
Renewable Hybrid Generating Station;
means a generating station based on hybrid of two or more
renewable source(s) of energy with or without Energy Storage
System, connected at the same inter-connection point;
means the ability to withstand and reduce the magnitude or
duration of disruptive events, which includes the capability to
anticipate, absorb, adapt to, or rapidly recover from such an
event;
means a bank account from where all payments to and from the
generating station(s) on account of SCED schedules flows.
means the charge declared by a generating station other than the
generating station whose tariff is determined by the Commission
under Section 62 of the Act, for participation in SCED;
means the maximum quantum of power which can be activated
through secondary control signal by which injection or drawal or
consumption of an SRAS provider is adjusted in accordance with
Ancillary Service Regulations;
means the Ancillary Service comprising SRAS-Up and SRAS-
Down, which is activated and deployed through secondary
control signals;
Sl.No. Particulars Definition
112. ,,Secondary Reserve Ancillary
113. Service Provider or ,,SRAS means an entity which provides SRAS-Up or SRAS-Down
114. Provider service in accordance with Ancillary Service Regulations;
115. ,,Security Constrained Economic
116. Despatch or ,,SCED Means optimised despatch of generating units subject to
operational and technical limits of generation and transmission
117. ,,Security Constrained Unit facilities as specified in these regulations;
Commitment or ,,SCUC means committing generating units while respecting limitations
118. of the transmission system and unit operating characteristics as
119. ,,,,Seller specified in these regulations;
120. means a person, including a generating station, supplying
121. ,,Settlement Nodal Agency or electricity through a transaction scheduled in accordance with
122. ,,SNA these regulations;
123. means the nodal agency as notified by Ministry of Power,
124. ,,Share Government of India for each neighboring country for settlement
125. of grid operation related charges in terms of Central Electricity
126. ,,Sharing Regulations Regulatory Commission (Cross Border Trade of Electricity)
127. Regulations, 2019;
,,State Load Despatch Centre or means percentage or MW entitlement of a beneficiary in an
128. ,,SLDC ISGS either notified by Government of India or agreed between
,,State Transmission Utility or the generating company and beneficiary through contracts and
129. ,,STU implemented through GNA or TGNA, as the case may be;
130. means the Central Electricity Regulatory Commission (Sharing of
,,System Constraint Inter-State Transmission Charges and Losses) Regulations, 2020;
131. means the Centre established under sub-section (1) of Section 31
,,System State of the Act;
means the board or the government company specified as such
,,Tariff Regulations by the concerned State Government under sub-section (1) of
section 39 of the Act;
,,Technical Co-ordination means a situation in which there is a need to prepare and activate
a remedial action in order to respect operational security limits;
Committee or ,,TCC means the operational state of the power system in relation to the
operational security limits which can be normal state, alert state,
,,Tertiary Reserve emergency state, extreme emergency state and restorative state;
means the Central Electricity Regulatory Commission (Terms and
,,Tie-line bias control Conditions of Tariff) Regulations, 2019;
means the sub-committee set up by the respective RPC to
,,Time Block coordinate the technical and commercial aspects of the operation
of the regional grid;
,,Total Transfer Capability or means the quantum of power which can be activated in order to
,,TTC take care of contingencies and to cater to the need for replacing
secondary reserves;
,,Transmission Planning Criteria means a mechanism of correcting ACE by factoring in deviation
,,Transmission Reliability Margin of net actual interchange from net scheduled interchange as well
or ,,TRM as frequency deviation;
means block of duration as specified by the Commission for
,,Trial Operation or ,,Trial Run which energy meters record values of specified electrical
parameters with first time block starting at 00.00 Hours, presently
of fifteen (15) minutes duration;
means the amount of electric power that can be transferred
reliably over the inter-control area transmission system under a
given set of operating conditions considering the effect of
occurrence of the worst credible contingency;
means the criteria issued by CEA for transmission system
planning;
means the amount of margin earmarked in the total transfer
capability to ensure that the interconnected transmission network
is secure under a reasonable range of uncertainties in system
conditions;
shall have the same meaning as specified in Regulation 22 or
Regulation 23 of these regulations, as applicable;
Sl.No. Particulars Definition
132. ,,User means and includes generating company, captive generating
plant, energy storage system, transmission licensee including
133. ,,Voltage Stability deemed transmission licensee, distribution licensee, solar park
developer, wind park developer, wind-solar photo voltaic hybrid
134. ,,Warm Start system, or bulk consumer which is or whose electrical plant is
connected to the grid at voltage level 33 kV and above;
135. ,,WS Seller means the ability of a transmission system to maintain steady
acceptable voltages at all nodes in the transmission system in the
normal situation and after being subjected to a disturbance;
means the start up after a shutdown period between 10 hours and
72 hours (turbine metal temperatures between approximately 40%
to 80% of their full load values) in relation to steam turbine;
shall have the same meaning as defined in the DSM Regulations.
(2) Words and expressions used in these regulations that are not defined herein but defined in the Act or other
regulations of the Commission shall have the meaning as assigned to them under the Act or the said
regulations of the Commission.
(3) Reference to any Acts, Rules and Regulations shall include amendments or consolidation or re-enactment
thereof.
CHAPTER 2
RESOURCE PLANNING CODE
4. GENERAL
(1) This chapter covers the integrated resource planning including demand forecasting, generation resource
adequacy planning and transmission resource adequacy assessment, required for secure grid operation.
(2) The planning of generation and transmission resources shall be for reliably meeting the projected demand in
compliance with specified reliability standards for serving the load with optimum generation mix with a
focus on integration of environmentally benign technologies after taking into account the need, inter alia, for
flexible resources, storage systems for energy shift and demand response measures for managing the
intermittency and variability of renewable energy sources.
5. INTEGRATED RESOURCE PLANNING
(1) The integrated resource planning shall include:
(a) Demand forecasting as detailed in clause (2) of this Regulation;
(b) Generation resource adequacy planning to meet the projected demand as detailed in clause (3) of this
Regulation; and
(c) Transmission resource planning as detailed in clause (4) of this Regulation
(2) Demand Forecasting:
(i) Each distribution licensee within a State shall estimate the demand in its control area including the
demand of open access consumers and factoring in captive generating plants, energy efficiency
measures, distributed generation, demand response, in different time horizons, namely long-term,
medium term and short-term. The demand estimation shall be done using trend method, time series,
econometric methods or any state of the art methods and shall include daily load curve (hourly basis)
for a typical day of each month.
(ii) STU or such other agency as may be designated by the State Commission, based on the demand
estimates of the distribution licensees of the concerned State as per sub-clause (i) of this clause and in
co-ordination with all the distribution licensees, shall estimate, in different time horizons, namely
long-term, medium term and short-term, the demand for the entire State duly considering the diversity
of the State.
(iii) Forum of Regulators may develop guidelines for demand estimation by the distribution licensees for
achieving consistency and statistical accuracy by taking into consideration the factors such as
economic parameters, historical data and sensitivity and probability analysis.
(3) Generation Resource Adequacy Planning:
(a) After the demand estimation as per clause (2) of this Regulation, each distribution licensee shall
(i) assess the existing generation resources and identify the additional generation resource
requirement to meet the estimated demand in different time horizons, and
(ii) prepare generation resource procurement plan.
(b) Assessment of the existing generation resources shall be done with due regard to their capacity
contribution to meet the peak demand of the distribution licensee and the state.
(c) Generation resource procurement planning (specifying procurement from resources under State
control area and regional control area) shall be undertaken in different time horizons, namely long-
term, medium term and short-term to ensure
(i) adequacy of generation resources and
(ii) planning reserve margin (PRM) taking into account loss of load probability and energy not served
as specified by CEA.
(d) In order to ensure optimum and least cost generation resource procurement planning, each distribution
licensee shall give due consideration to the factors such as its share in the state, regional and national
coincident peak; seasonal requirement and possibility of sharing generation capacity seasonally with
other States. For this purpose, each STU or such other agency as may be designated by the State
Commission, on behalf of the distribution licensees in the State shall provide to NLDC every year, the
details regarding demand forecasting, assessment of existing generation resources and such other
details as may be required for carrying out a national level simulation for generation resource
adequacy for States.
(e) Based on the information received under sub-clause (d) of this clause and after considering inter alia
the national level planning reserve margin, share of each State in the regional and national coincident
peak, seasonal requirements of States and possibility of sharing generation capacity seasonally among
States, NLDC shall carry out a simulation, to assist the States in drawing their optimal generation
resource adequacy plan. While carrying out the simulation, NLDC shall also take into consideration
the information related to demand estimation, generation planning and related matters as available
with CEA. The simulation carried out by NLDC for this purpose shall be considered merely as an aid
to the distribution licensees in the respective States in their exercise of generation resource adequacy
planning and the distribution licensees shall be responsible for all commercial decisions on generation
resource procurement.
(f) After considering the demand forecasting and the generation resource procurement planning carried
out based on the principles specified under this Regulation, each distribution licensee shall ensure
demonstrable generation resource adequacy for such period as specified by the respective SERC.
Failure of a distribution licensee to meet the generation resource adequacy target approved by the
SERC shall render the concerned distribution licensee liable for payment of resource adequacy non-
compliance charge as may be specified by the respective SERC.
(g) For the sake of uniformity in approach and in the interest of optimality in generation resource
adequacy in the States, FOR may develop a model Regulation stipulating inter alia the methodology
for generation resource adequacy assessment, generation resource procurement planning and
compliance of resource adequacy target by the distribution licensees.
(4) Transmission resource adequacy assessment
(a) CTU shall undertake assessment and planning of the inter-State transmission system as per the
provisions of the Act and shall inter alia take into account:
(i) adequate power transfer capability across each flow-gate;
(ii) import and export capability for each control area;
(iii) import and export capability between regions; and
(iv) cross-border import and export capability.
(b) STU shall undertake assessment and planning of the intra-State transmission system as per the
provisions of the Act and shall inter alia take into account:
(i) import and export capability across ISTS and STU interface; and
(ii) adequate power transfer capability across each flow-gate.
CHAPTER 3
CONNECTION CODE
6. GENERAL
(1) This chapter covers the technical and design criteria for connectivity, procedure and requirements for
physical connection and integration of grid elements.
(2) The connectivity to the ISTS shall be granted by CTU in accordance with the GNA Regulations.
(3) Users seeking to get connected to the ISTS for the first time through a new or modified power system
element shall fulfill the requirements and follow the procedures specified under this Code prior to obtaining
the permission of the NLDC or RLDC or SLDC, as the case may be. Transmission licensees including
deemed transmission licensees or cross-border entities shall comply with the technical requirements
specified under this Connection Code prior to being allowed by NLDC or RLDC or SLDC to energize a
new or modified power system element.
(4) After grant of connectivity and prior to the declaration of commercial operation, the tests as specified under
Chapter-5 of these regulations shall be performed.
7. COMPLIANCE WITH EXISTING RULES AND REGULATIONS
(1) All Users connected to or seeking connection to the grid shall comply with all the applicable regulations as
enacted or amended from time to time, such as:
(a) Central Electricity Authority (Technical Standards for Connectivity to the Grid) Regulations, 2007;
(b) Central Electricity Authority (Technical Standards for Construction of Electrical Plants and Electric
Lines) Regulations, 2010;
(c) Central Electricity Authority (Measures Relating to Safety & Electric Supply) Regulations, 2010;
(d) Central Electricity Regulatory Commission (Communication System for Inter-State Transmission of
Electricity) Regulations,2017;
(e) Central Electricity Authority (Installation and Operation of Meters) Regulations, 2006;
(f) Central Electricity Regulatory Commission (Connectivity and General Network Access to the inter-
State Transmission System) Regulations, 2022;
(g) Central Electricity Regulatory Commission (Fees and Charges for Regional Load Despatch Centres)
Regulations, 2019;
(h) Central Electricity Authority (Technical Standards for Communication System in Power System
Operation) Regulations, 2020;
(i) Central Electricity Regulatory Commission (Furnishing of Technical Details by the Generating
Companies) Regulations, 2009.
(j) Central Electricity Authority (Grid Standards) Regulations, 2010.
(k) Central Electricity Authority (Cyber Security in Power Sector) Guidelines, 2021.
(l) Central Electricity Authority (Flexible Operation of Coal based Thermal Power Generating Units)
Regulations, 2023
(m) Any other regulation and standard as specified from time to time.
8. PROCEDURE FOR CONNECTION
(1)The grant of connectivity to the ISTS by the CTU shall be governed by the GNA Regulations.
(2) NLDC, in coordination with RPCs and RLDCs after due consultation of stakeholders, shall prepare a
detailed procedure covering modalities for first time energization and integration of new or modified power
system element and submit for approval of the Commission. The procedure shall specify requirements for
integration with the grid such as protection, telemetry and communication systems; metering; statutory
clearances; modelling data requirements for system studies and timeline for submission of data for system
study.
(3) Post completion of all physical arrangements of connectivity and necessary site tests, the concerned user
shall request the RLDC for permission of first time energization in the specified format as per the procedure
published by NLDC.
(4) SLDC shall prepare procedure for first time energization of new or modified power system elements to
intra-State transmission system. In the absence of such procedure of SLDC, the NLDC procedure shall
apply for the elements of 220 kV and above (132 kV and above in case of North Eastern region).
9. CONNECTIVITY AGREEMENT
(1) In case of users seeking connectivity to the ISTS under GNA Regulations, Connectivity Agreement shall be
signed between such users and CTU. In case of multiple transmission licensees connected at same station,
the Site Responsibility Schedule including the responsibility for operation & protection coordination and
data sharing among the licensees, shall be specified in the Connectivity Agreement.
(2) In case of an inter-State transmission licensee, Connectivity Agreement shall be signed between such
licensee and CTU after the award of the project and before physical connection to ISTS.
(3) In case of intra-State transmission system getting connected to inter-State transmission system,
Connectivity Agreement shall be signed between intra-State transmission licensee, CTU and inter-State
transmission licensee after the award of the project and before physical connection to ISTS.
10. TECHNICAL REQUIREMENTS
(1) NLDC or RLDC, as the case may be, in consultation with CTU, STU or SLDC, as the case may be, shall
carry out a joint system study six (6) months before the expected date of first energization of a new power
system element to identify operational constraints, if any. In case of constraints, CTU, NLDC or RLDC, as
the case may be and SLDC shall identify measures for facilitating the integration of the element, subject to
grid security. The connectivity grantee, transmission licensee and SLDC/STU shall furnish all technical
data including that of its embedded generators and other elements to the CTU and NLDC or RLDC, as the
case may be, for necessary technical studies.
(2) Similar exercise shall be done by SLDC in consultation with STU for the intra-state system, and
specifically for elements of 220 kV and above (132 kV and above in case of North Eastern region).
(3) NLDC shall publish a detailed Procedure covering modalities for carrying out interconnection studies.
11. DATA AND COMMUNICATION FACILITIES
(1) Reliable speech and data communication systems shall be provided to facilitate necessary communication,
data exchange, supervision and control of the grid by the NLDC, RLDC and SLDC in accordance with the
CERC (Communication System for Inter-State Transmission of Electricity) Regulations, 2017 and the CEA
Technical Standards for Communication.
(2) The associated communication system to facilitate data flow up to appropriate data collection point on CTU
system including inter-operability requirements shall also be established by the concerned user as specified
by CTU in the Connectivity Agreement.
(3) All users, STU and participating entities in case of cross-border trade shall provide, in coordination with
CTU, the required facilities at their respective ends as specified in the connectivity agreement. The
communication system along with data links provided for speech and real time data communication shall be
monitored in real time by all users, CTU, STU, SLDC and RLDC to ensure high reliability of the
communication links.
CHAPTER 4
PROTECTION CODE
12. GENERAL
(1) This chapter covers the protection protocol, protection settings and protection audit plan of electrical systems.
(2) There shall be a uniform protection protocol for the users of the grid:
(a) for proper co-ordination of protection system in order to protect the equipment/system from abnormal
operating conditions, isolate the faulty equipment and avoid unintended operation of protection system;
(b) to have a repository of protection system, settings and events at regional level;
(c) specifying timelines for submission of data;
(d) to ensure healthiness of recording equipment including triggering criteria and time synchronization; and
(e) to provide for periodic audit of protection system.
13. PROTECTION PROTOCOL
(1) All users connected to the integrated grid shall provide and maintain effective protection system having
reliability, selectivity, speed and sensitivity to isolate faulty section and protect element(s) as per the CEA
Technical Standards for Construction, the CEA Technical Standards for Connectivity, the CEA (Grid
Standards) Regulations, 2010, the CEA Technical Standards for Communication and any other applicable
CEA Standards specified from time to time.
(2) Back-up protection system shall be provided to protect an element in the event of failure of the primary
protection system.
(3) RPC shall develop the protection protocol and revise the same, after review from time to time, in
consultation with the stakeholders in the concerned region, and in doing so shall be guided by the
principle that minimum electrical protection functions for equipment connected with the grid shall be
provided as per the CEA Technical Standards for Construction, the CEA Technical Standards for
Connectivity, the CEA Technical Standards for Communication, the CEA (Grid Standards) Regulations,
2010, the CEA (Measures relating to Safety and Electric Supply) Regulations, 2010, and any other CEA
standards specified from time to time.
(4) The protection protocol in a particular system may vary depending upon operational experience. Changes in
protection protocol, as and when required, shall be carried out after deliberation and approval of the
concerned RPC.
(5) Violation of the protection protocol of the region shall be brought to the notice of concerned RPC by the
concerned RLDC or SLDC, as the case may be.
14. PROTECTION SETTINGS
(1) RPCs shall undertake review of the protection settings, assess the requirement of revisions in
protection settings and revise protection settings in consultation with the stakeholders of the respective
region, from time to time and at least once in a year. The necessary studies in this regard shall be
carried out by the respective RPCs. The data including base case (peak and off-peak cases) files for
carrying out studies shall be provided by RLDC and CTU to the RPCs:
(2) All users connected to the grid shall:
(a) furnish the protection settings implemented for each element to respective RPC in a format as
prescribed by the concerned RPC;
(b) obtain approval of the concerned RPC for (i) any revision in settings, and (ii) implementation of new
protection system;
(c) intimate to the concerned RPC about the changes implemented in protection system or protection
settings within a fortnight of such changes;
(d) ensure correct and appropriate settings of protection as specified by the concerned RPC.
(e) ensure proper coordinated protection settings.
(3) RPCs shall:
(a) maintain a centralized database and update the same on periodic basis in respect of their respective
region containing details of relay settings for grid elements connected to 220 kV and above (132 kV
and above in NER). RLDCs shall also maintain such database.
(b) carry out detailed system studies, once a year, for protection settings and advise modifications /
changes, if any, to the CTU and to all users and STUs of their respective regions. The data required to
carry out such studies shall be provided by RLDCs and CTU.
(c) provide the database access to CTU and NLDC and to all users, RLDC, SLDCs, and STUs of the
respective regions. The database shall have different access rights for different users.
(4) The changes in the network and protection settings of grid elements connected to 220kV and above (132 kV
and above in NER) shall be informed to RPCs by CTU and STUs, as the case may be.
(5) The elements of network below 66kV and radial in nature which do not impact the National Grid may be
excluded as finalized by the respective RPC.
15. PROTECTION AUDIT PLAN
(1) All users shall conduct internal audit of their protection systems annually, and any shortcomings identified
shall be rectified and informed to their respective RPC. The audit report along with action plan for
rectification of deficiencies detected, if any, shall be shared with respective RPC for users connected at 220
kV and above (132 kV and above in NER).
(2) All users shall also conduct third party protection audit of each sub-station at 220 kV and above (132 kV
and above in NER) once in five years or earlier as advised by the respective RPC.
(3) After analysis of any event, each RPC shall identify a list of substations / and generating stations where
third-party protection audit is required to be carried out and accordingly advise the respective users to
complete third party audit within three months.
(4) The third-party protection audit report shall contain information sought in the format enclosed as
Annexure-1. The protection audit reports, along with action plan for rectification of deficiencies detected, if
any, shall be submitted to the respective RPC and RLDC or SLDC, as the case may be, within a month of
submission of third party audit report. The necessary compliance to such protection audit report shall be
followed up regularly in the respective RPC.
(5) Annual audit plan for the next financial year shall be submitted by the users to their respective RPC by 31st
October. The users shall adhere to the annual audit plan and report compliance of the same to their
respective RPC.
(6) Users shall submit the following protection performance indices of previous month to their respective RPC
and RLDC on monthly basis for 220 kV and above (132 kV and above in NER) system, which shall be
reviewed by the RPC:
(a) The Dependability Index defined as
where,
Nc is the number of correct operations at internal power system faults and
Nf is the number of failures to operate at internal power system faults.
(b) The Security Index defined as
Where,
Nc is the number of correct operations at internal power system faults
Nu is the number of unwanted operations.
(c) The Reliability Index defined as
Where,
Nc is the number of correct operations at internal power system faults
Ni is the number of incorrect operations and is the sum of Nf and Nu
(7) Each user shall also submit the reasons for performance indices less than unity of individual element wise
protection system to the respective RPC and action plan for corrective measures. The action plan will be
followed up regularly in the respective RPC.
(8) In case any user fails to comply with the protection protocol specified by the RPC or fails to undertake
remedial action identified by the RPC within the specified timelines, the concerned RPC may approach the
Commission with all relevant details for suitable directions.
16. SYSTEM PROTECTION SCHEME (SPS)
(1) SPS for identified system shall have redundancies in measurement of input signals and communication
paths involved up to the last mile to ensure security and dependability.
(2) For the operational SPS, RLDC or NLDC, as the case may be, in consultation with the concerned RPC(s)
shall perform regular load flow and dynamic studies and mock testing for reviewing SPS parameters &
functions, at least once in a year. RLDC or NLDC shall share the report of such studies and mock testing
including any short comings to respective RPC(s). The data for such studies shall be provided by CTU to
the concerned RPC, RLDC and NLDC.
(3) The users and SLDCs shall report about the operation of SPS immediately and detailed report shall be
submitted within three days of operation to the concerned RPC and RLDC in the format specified by the
respective RPCs.
(4) The performance of SPS shall be assessed as per the protection performance indices specified in these
Regulations. In case, the SPS fails to operate, the concerned User shall take corrective actions and submit a
detailed report on the corrective actions taken to the concerned RPC within a fortnight.
17. RECORDING INSTRUMENTS
(1) All users shall keep the recording instruments (disturbance recorder and event logger) in proper working
condition.
(2) The disturbance recorders shall have time synchronization and a standard format for recording analogue and
digital signals which shall be included in the guidelines issued by the respective RPCs.
(3) The time synchronization of the disturbance recorders shall be corroborated with the PMU data or
SCADA event loggers by the respective RLDC. Disturbance recorders which are non- compliant shall be
listed out for discussion at RPC.
CHAPTER 5
COMMISSIONING AND COMMERCIAL OPERATION CODE
18. GENERAL
This chapter covers aspects related to (i) drawl of startup power from and injection of infirm power into the grid,
(ii) trial run operation (iii) documents and tests required to be furnished before declaration of COD, (iv)
requirements for declaration of COD.
19. DRAWAL OF START UP POWER AND INJECTION OF INFIRM POWER
(1) A unit of a generating station including unit of a captive generating plant that has been granted
connectivity to the inter-State Transmission System in accordance with GNA Regulations shall be allowed
to inter-change power with the grid during the commissioning period, including testing and full load
testing before the COD, after obtaining prior permission of the concerned Regional Load Despatch Centre:
Provided that the concerned Regional Load Despatch Centre while granting such permission shall keep
grid security in view.
(2) The period for which such inter-change shall be allowed shall be as follows:-
(a) Drawal of start-up power shall not exceed 15 months prior to the expected date of first
synchronization and one year after the date of first synchronization; and
(b) Injection of infirm power shall not exceed one year from the date of first synchronization.
(3) Notwithstanding the provisions of clause (2) of this Regulation, the Commission may allow extension of
the period for inter-change of power beyond the stipulated period on an application made by the generating
station at least two months in advance of the completion of the stipulated period:
(4) Drawal of start-up power shall be subject to payment of transmission charges as per the Sharing
Regulations;
(5) The charges for deviation for drawal of start up power or for injection of infirm power shall be as per the
DSM Regulations;
(6) Start-up power shall not be used by the generating station for construction activities;
(7) The onus of proving that the interchange of infirm power from the unit(s) of the generating station is for
the purpose of pre-commissioning activities, testing and commissioning, shall rest with the generating
station, and the concerned RLDC shall seek such information on each occasion of the interchange of power
before COD. For this, the generating station shall furnish to the concerned RLDC relevant details, such as
those relating to the specific commissioning activity, testing, and full load testing, its duration and the
intended period of interchange. The generating station shall submit a tentative plan for the quantum and
time of injection of infirm power on day ahead basis to the respective RLDC.
(8) In the case of multiple generating units of the same generating station or multiple generating stations
owned by different entities connected at a common ISTS interface point, RLDC shall ensure segregation of
firm power from generating units that have achieved COD from power injected or drawn by generating
units which have not achieved COD through appropriate accounting of energy.
(9) RLDC shall stop the drawl of the start-up Power in the following events:
(a) In case, it is established that the start-up power has been used by the generating station for
construction activity;
(b) In the case of default in payment of monthly transmission charges, charges under RLDC Fees and
Charges Regulations and deviation charges under the DSM Regulations.
20. DATA TO BE FURNISHED PRIOR TO NOTICE OF TRIAL RUN
(1) The following details, as applicable, shall be furnished by each regional entity generating station to the
concerned RLDC, RPC and the beneficiaries of the generating station, wherever identified, prior to notice of
trial run:
TABLE 1: DETAILS TO BE FURNISHED BY GENERATING ENTITY PRIOR TO TRIAL RUN
Description Units
Installed Capacity of generating station MW
Installed Capacity of generating station MVA
MCR MW
Number x unit size No x MW
Time required for cold start Minute
Time required for warm start minute
Time required for hot start Minute
Time required for combined cycle operation under cold conditions Minute
Time required for combined cycle operation under warm conditions Minute
Ramping up capability % per minute
Ramping down capability % per minute
Minimum turndown level % of MCR
Minimum turndown level MW (ex-bus)
Inverter Loading Ratio (DC/AC capacity)
Name of QCA (where applicable) Metre
Full reservoir level (FRL) Metre
Design Head Metre
Minimum draw down level (MDDL) M3/ MW
Water released at Design Head MW
Unit-wise forbidden zones
21. NOTICE OF TRIAL RUN
(1) The generating company proposing its generating station or a unit thereof for trial run or repeat of trial run
shall give a notice of not less than seven (7) days to the concerned RLDC, and the beneficiaries of the
generating stations, including intermediary procurers, wherever identified:
Provided that in case the repeat trial run is to take place within forty eight (48) hours of the failed trial run,
fresh notice shall not be required.
(2) The transmission licensee proposing its transmission system or an element thereof for trial run shall give a
notice of not less than seven days to the concerned RLDC, CTU, distribution licensees of the region and the
owner of the inter-connecting system.
(3) The concerned RLDC shall allow commencement of the trial run from the requested date or in the case of
any system constraints, not later than seven (7) days from the proposed date of the trial run. The trial run
shall commence from the time and date as decided and informed by the concerned RLDC.
(4) A generating station shall be required to undergo a trial run in accordance with Regulation 22 of these
regulations after completion of Renovation and Modernization for extension of the useful life of the project
as per the Tariff Regulations.
22. TRIAL RUN OF GENERATING UNIT
(1) Trial Run of the Thermal Generating Unit shall be carried out in accordance with the following provisions:
(a) A thermal generating unit shall be in continuous operation at MCR for seventy-two (72) hours on
designated fuel:
Provided that:
(i) short interruption or load reduction shall be permissible with the corresponding increase in
duration of the test;
(ii) interruption or partial loading may be allowed with the condition that the average load during
the duration of the trial run shall not be less than MCR, excluding the period of interruption
but including the corresponding extended period;
(iii) cumulative interruption of more than four (4) hours shall call for a repeat of trial run.
(b) Where, on the basis of the trial run, a thermal generating unit fails to demonstrate the unit capacity
corresponding to MCR, the generating company has the option to de-rate the capacity of the
generating unit or to go for a repeat trial run. If the generating company decides to de-rate the unit
capacity, the de-rated capacity in such cases shall not be more than 95% of the demonstrated
capacity, to cater for primary response.
(2) Trial Run of Hydro Generating Unit shall be carried out in accordance with the following provisions:
(a) A hydro generating unit shall be in continuous operation at MCR for twelve (12) hours:
Provided that-
(i) short interruption or load reduction shall be permissible with a corresponding increase in
duration of the test;
(ii) interruption or partial loading may be allowed with the condition that the average load during
the duration of trial run shall not be less than MCR excluding period of interruption but
including the corresponding extended period;
(iii) cumulative interruption of more than four (4) hours shall call for a repeat of trial run;
(iv) if it is not possible to demonstrate the MCR due to insufficient reservoir or pond level or
insufficient inflow, COD may be declared, subject to the condition that the same shall be
demonstrated immediately when sufficient water is available after COD:
Provided that if such a generating station is not able to demonstrate the MCR when sufficient
water is available, the generating company shall de-rate the capacity in terms of sub-clause (b)
of this clause, and such de-rating shall be effective from COD.
(b) Where, on the basis of the trial run, a hydro generating unit fails to demonstrate the unit capacity
corresponding to MCR, the generating company shall have the option to either de-rate the capacity or
go for a repeat trial run. If the generating company decides to de-rate the unit capacity, the de-rated
capacity in such cases shall not be more than 90% of the demonstrated capacity to cater for primary
response.
(3) Trial Run of Wind / Solar / ESS / Hybrid Generating Station
(a) Trial run of the solar inverter unit(s) shall be performed for a minimum capacity aggregating to
50 MW:
Provided that in the case of a project having a capacity of more than 50 MW, the trial run for the
balance capacity shall be performed in a maximum of four instalments with a minimum capacity of
5 MW:
Provided further that the trial run for solar inverter unit(s) aggregating to less than 50 MW for entities
covered under clause (e) of Regulation 4.1 of the GNA Regulations, shall be allowed for the capacity
for which Connectivity has been granted to such entity.
(b) Successful trial run of a solar inverter unit(s) covered under sub-clause (a) of this clause shall mean
the flow of power and communication signal for not less than four (4) hours on a cumulative basis
between sunrise and sunset in a single day with the requisite metering system, power plant controller,
telemetry and protection system in service. The generating company shall record the output of the
unit(s) during the trial run and shall corroborate its performance with the temperature and solar
irradiation recorded at site during the day and plant design parameters:
Provided that:
(i) the output below the corroborated performance level with the solar irradiation of the day
shall call for a repeat of the trial run;
(ii) if it is not possible to demonstrate the rated capacity of the plant due to insufficient solar
irradiation, COD may be declared subject to the condition that the same shall be
demonstrated immediately when sufficient solar irradiation is available after COD, within
one year from the date of COD:
Provided that if such a generating station is not able to demonstrate the rated capacity when
sufficient solar irradiation is available after COD, the generating company shall de-rate the
capacity in terms of sub-clause (h) of clause (3) of this Regulation.
(c) Trial run of a wind turbine(s) shall be performed for a minimum capacity aggregating to 50 MW:
Provided that in the case of a project having a capacity of more than 50 MW, the trial run for wind
turbine(s) above the capacity of 50 MW shall be performed in batch sizes of not less than 5 MW:
Provided further that the trial run for wind turbine(s) aggregating to less than 50 MW for entities
covered under clause (e) of Regulation 4.1 of the GNA Regulations, shall be allowed for the capacity
for which Connectivity has been granted to such an entity.
(d) Successful trial run of a wind turbine(s) covered under sub-clause (c) of this clause shall mean the
flow of power and communication signal for a period of not less than continuous four (4) hours during
periods of wind availability with the requisite metering system, power plant controller, telemetry and
protection system in service. The generating company shall record the output of the unit(s) during the
trial run and corroborate its performance with the wind speed recorded at the site(s) during the day and
plant design parameters:
Provided that-
(i) the output below the corroborated performance level with the wind speed of the day shall
call for a repeat of the trial run;
(ii) if it is not possible to demonstrate the rated capacity of the plant due to insufficient wind
velocity, COD may be declared subject to the condition that the same shall be demonstrated
immediately when sufficient wind velocity is available after COD, within one year from
the date of COD:
Provided that if such a generating station is not able to demonstrate the rated capacity when
sufficient wind velocity is available after COD, the generating company shall de-rate the
capacity in terms of sub-clause (h) of clause (3) this Regulation.
(e) Successful trial run of a standalone Energy Storage System (ESS) shall mean one (1) cycle of charging
and discharging of energy as per the design capabilities with the requisite metering, telemetry and
protection system being in service.
(f) Successful trial run of a pumped storage plant shall mean one (1) cycle of turbo-generator and
pumping motor mode as per the design capabilities up to the rated water drawing levels with the
requisite metering, telemetry and protection system being in service.
(g) Successful trial run of a hybrid system shall mean successful trial run of each individual source of the
hybrid system in accordance with the applicable provisions of these regulations.
(h) Where, on the basis of the trial run, solar / wind / storage / hybrid generating station fails to
demonstrate its rated capacity, the generating company shall have the option to either go for a repeat
trial run or de-rate the capacity subject to a minimum aggregated de-rated capacity of 50 MW or 5
MW, as the case may be.
(i) Notwithstanding the provisions contained in this Regulation, where Power purchase Agreement
provides for a specific capacity that can be declared COD, trial run shall be allowed for such capacity
in terms of such Power purchase agreement.
23. TRIAL RUN OF INTER-STATE TRANSMISSION SYSTEM
(1) Trial run of a transmission system or an element thereof shall mean successful energisation of the
transmission system or the element thereof at its nominal system voltage through interconnection with the
grid for a continuous twenty-four (24) hours flow of power and communication signal from the sending end
to the receiving end and with the requisite metering system, telemetry and protection system:
Provided that under exceptional circumstances and with the prior approval of CEA, a transmission
element can be energized at lower nominal system voltage level.
Provided further that the RLDC may allow anti-theft charging where the transmission line is not
carrying any power.
24. DOCUMENTS AND TESTS PRIOR TO DECLARATION OF COMMERCIAL OPERATION
(1) Notwithstanding the requirements in other standards, codes and contracts, for ensuring grid security, the
tests as specified in the following clauses shall be scheduled and carried out in coordination with NLDC
and the concerned RLDC by the generating company or the transmission licensee, as the case may be, and
relevant reports and other documents as specified shall be submitted to NLDC and the concerned RLDC
before a certificate of successful trial run is issued to such a generating company or the transmission
licensee, as the case may be.
(2) All thermal generating stations having a capacity of more than 200 MW and hydro generating stations
having a capacity of more than 25 MW shall submit documents confirming the enablement of automatic
operation of the plant from the appropriate load despatch centre by integrating the controls and tele-
metering features of their system into the automatic generation control in accordance with the CEA
Technical Standards for Construction and the CEA Technical Standards for Connectivity.
(3) Documents and Tests Required for Thermal (coal/lignite) Generating Stations:
(a) The generating company shall submit the following OEM documents, namely (i) startup curve for boiler
and turbine including starting time of unit in cold, warm and hot conditions, (ii) capability curve of
generator, (iii) design ramp rate of boiler and turbine.
(b) The following tests shall be performed:
(i) Operation at a load of fifty five (55) percent of MCR as per the CEA Technical Standards for
Construction for a sustained period of four (4) hours.
(ii) Ramp-up from fifty five (55) percent of MCR to MCR at a ramp rate of at least one (1) percent of
MCR per minute, in one step or two steps (with stabilization period of 30 minutes between two
steps), and sustained operation at MCR for one (1) hour.
(iii) Demonstrate overload capability with the valve wide open as per the CEA Technical Standards
for Construction and sustained operation at that level for at least five (5) minutes.
(iv) Ramp-down from MCR to fifty five(55) percent of MCR at a ramp rate of at least one (1) percent
of MCR per minute, in one or two steps (with stabilization period of 30 minutes between two
steps).
(v) Primary response through injecting a frequency test signal with a step change of ± 0.1 Hz at 55%,
60%, 75% and 100% load.
(vi) Reactive power capability as per the generator capability curve as provided by OEM considering
over-excitation and under-excitation limiter settings and prevailing grid condition.
(4) Documents and Tests Required for Hydro Generating Stations including Pumped Storage Hydro
Generating Station:
(a) The generating company shall submit OEM documents for the turbine characteristics curve indicating
the operating zone(s) and forbidden zone(s). In order to demonstrate the operating flexibility of the
generating unit, it shall be operated below and above the forbidden zone(s).
(b) The following tests shall be performed considering the water availability and head:
(i) Primary response through injecting a frequency test signal with a step change of ± 0.1 Hz for
various loadings within the operating zone.
(ii) Reactive power capability as per the generator capability curve considering over-excitation and
under-excitation limiter settings.
(iii) Black start capability, wherever feasible.
(iv) Operation in synchronous condenser mode wherever designed.
(5) Documents and Test Required for Gas Turbine based Generating Stations:
(a) The generating company shall submit OEM documents for (i) starting time of the unit in cold, warm
and hot conditions (ii) design ramp rate.
(b) The following tests shall be performed:
(i) Primary response through injecting a frequency test signal with a step change of ± 0.1 Hz for
various loadings within the operating zone.
(ii) Reactive power capability as per the generator capability curve considering over-excitation and
under-excitation limiter settings.
(iii) Black start capability up to 100 MW capacity, wherever feasible.
(iv) Operation in synchronous condenser mode wherever designed.
(6) Documents and Tests Required for the Generating Stations based on wind and solar resources:
(a) The generating company shall submit a certificate confirming compliance with CEA Technical
Standards for Connectivity in accordance with sub-clause (a) of clause (4) of Regulation 26 of these
regulations.
(b) Type test report for Fault Ride through Test (LVRT and HVRT) for units commissioned after the
specified date as per CEA Technical Standards for Connectivity mandating LVRT and HVRT
capability shall be submitted.
(c) The following tests shall be performed at the point of interconnection:
(i) Frequency response of machines as per the CEA Technical Standards for Connectivity.
(ii) Reactive power capability as per OEM rating at the available irradiance or the wind energy, as the
case may be.
Provided that the generating company may submit offline simulation studies for the specified
tests, in case testing is not feasible before COD, subject to the condition that tests shall be
performed within a period of one year from the date of achieving COD.
(7) Documents and Tests Required for Energy Storage Systems:
(a) The ESS shall submit a certificate confirming compliance with the CEA Technical Standards for
Connectivity in accordance with sub-clause (a) of clause (4) of Regulation 26 of these regulations.
(b) The following tests shall be performed at the point of interconnection:
(i) Power output capability in MW and energy output capacity in MWh.
(ii) Frequency response of ESS.
(iii) Ramping capability as per design.
(8) Documents and Tests Required for HVDC Transmission System:
(a) The transmission licensee shall submit technical details including operating guidelines such as filter
bank requirements at various operating loads and monopolar/ or bipolar configuration, reactive power
controller, run-back features, frequency controller, reduced voltage mode of operation, circuit design
parameters and power oscillation damping, as applicable.
(b) The following tests shall be performed:
(i) Minimum load operation.
(ii) Ramp rate.
(iii) Overload capability, subject to grid condition.
(iv) Black start capability in the case of Voltage source convertor (VSC) HVDC wherever feasible.
(v) Dynamic Reactive Power Support (in the case of VSC based HVDC)
(8) Documents and Tests Required for SVC or STATCOM
(a) The transmission licensee shall submit technical particulars including a single line diagram, V/I
characteristics, the rating of coupling transformer, the rating of each VSC, MSR and MSC branch,
different operating modes, the IEEE standard Model, Power Oscillation Damping (POD) enabled and
tuned (if not, then reasons for the same) and the results of an Offline simulation-based study to
validate the performance of POD.
(b) The following tests shall be performed to validate the full reactive power capability of SVC and
STATCOM in both directions i.e. absorption as well as injection mode:
(i) POD performance test.
(ii) dynamic performance testing:
Provided that the transmission licensee may submit offline simulation studies for the specified
tests, in case the conduct of tests is not feasible before COD, subject to the condition that tests
shall be performed within a period of one year from the date of achieving COD.
25. CERTIFICATE OF SUCCESSFUL TRIAL RUN
(1) In case any objection is raised by a beneficiary in writing to the concerned RLDC with a copy to all
concerned regarding the trial run within two (2) days of completion of such trial run, the concerned RLDC
shall, within five (5) days of receipt of such objection, in coordination with the concerned entity and the
beneficiaries, decide if the trial run was successful or if there is a need for a repeat trial run.
(2) After completion of a successful trial run and receipt of documents and test reports as per Regulation 24 of
these regulations, the concerned RLDC shall issue a certificate to that effect to the concerned generating
station, ESS or transmission licensee, as the case may be, with a copy to their respective beneficiary(ies) and
the respective RPC, within three days.
26. DECLARATION BY GENERATING COMPANY AND TRANSMISSION LICENSEE
(1) Thermal Generating Station
(a) The generating company shall certify that:
(i) The generating station or unit thereof meets the relevant requirements and provisions of the
CEA Technical Standards for Construction, CEA Technical Standards for Connectivity, CEA
Technical Standards for Communication, Central Electricity Authority (Measures relating to
Safety and Electricity Supply) Regulations,2010, CEA (Flexible operation of thermal power
plants) Regulations,2023 and these regulations, as applicable.
(ii) The main plant equipment and auxiliary systems including the balance of the plant such as the
fuel oil system, coal handling plant, DM plant, pre-treatment plant, fire-fighting system, ash
disposal system and any other site specific system have been commissioned and are capable of
full load operation of the units of the generating station on a sustained basis.
(iii) Permanent electric supply system including emergency supplies and all necessary
instrumentation, control and protection systems and auto loops for full load operation of the
unit has been put into service.
(b) The certificates required under sub-clause (a) of this clause shall be signed by the authorized
signatory not below the rank of CMD or CEO or MD of the generating company and shall be
submitted to the concerned RLDC and to the Member Secretary of the concerned RPC before the
declaration of COD.
(2) Hydro Generating Station
(a)The generating company shall certify that:
(i) The generating station or unit thereof meets the requirement and relevant provisions of the CEA
Technical Standards for Construction, CEA Technical Standards for Connectivity, CEA
Technical Standards for Communication, Central Electricity Authority (Measures relating to
Safety and Electricity Supply) Regulations,2010 and these regulations, as applicable.
(ii) The main plant equipment and auxiliary systems including the drainage de-watering system,
primary and secondary cooling system, LP and HP air compressor and firefighting system have
been commissioned and are capable of full load operation of units on a sustained basis.
(iii) Permanent electric supply systems including emergency supplies and all necessary
Instrumentations Control and Protection Systems and auto loops for full load operation of the
unit are put into service.
(b) The certificates required under sub-clause (a) of this clause shall be signed by the authorized signatory
not below the rank of CMD or CEO or MD of the generating company and shall be submitted to the
concerned RLDC and to the Member Secretary of the concerned RPC before the declaration of COD.
(3) Transmission system
(a) The transmission licensee shall submit a certificate signed by the authorized signatory not below the
rank of CMD or CEO or MD of the company to the concerned RLDC and to the Member Secretary of
the concerned RPC before declaration of COD that the transmission line, sub-station and
communication system conform to the CEA Technical Standards for Construction, CEA Technical
Standards for Connectivity, CEA Technical Standards for Communication, Central Electricity
Authority (Measures relating to Safety and Electricity Supply) Regulations,2010 and these regulations
and are capable of operation to their full capacity.
(4) Wind, Solar, Storage, and Hybrid Generating Station
(a) The generating station based on wind and solar resources, the ESS and the hybrid generating station
shall submit a certificate signed by the authorized signatory not below the rank of CMD or CEO or
MD to the concerned RLDC and to the Member Secretary of the concerned RPC before declaration of
COD, that the said generating station or the ESS as the case may be, including main plant equipment
such as wind turbines or solar inverters or auxiliary systems, as the case may be, has complied with all
relevant provisions of CEA Technical Standards for Connectivity, CEA Technical Standards for
Communication, Central Electricity Authority (Measures relating to Safety and Electricity Supply)
Regulations,2010 and these regulations.
27. DECLARATION OF COMMERCIAL OPERATION (DOCO) AND COMMERCIAL OPERATION DATE (COD)
(1) A generating station or unit thereof or a transmission system or an element thereof or ESS may declare
commercial operation as follows and inform CEA, the concerned RLDC, the concerned RPC and its
beneficiaries:
(a) Thermal Generating Station or a unit thereof
(i) The commercial operation date in the case of a unit of the thermal generation station shall be the
date declared by the generating company after a successful trial run at MCR or de-rated capacity
as per sub-clause (b) of clause (1) of Regulation 22 of these regulations, as the case may be, and
submission of a declaration as per clause (1) of Regulation 26 of these regulations.
(ii) In the case of the generating station, the COD of the last unit of the generating station shall be
considered as the COD of the generating station.
(b) Hydro Generating Station
(i) The commercial operation date in the case of a unit of the hydro generating station including a
pumped storage hydro generating station shall be the date declared by the generating station after
after a successful trial run at MCR or de-rated capacity as per sub-clause (b) of clause (2) of
Regulation 22 of these regulations, as the case may be, and submission of a declaration as per
clause (2) of Regulation 26 of these regulations.
(ii) In the case of the generating station, the COD of the last unit of the generating station shall be
considered as the COD of the generating station.
(c) Transmission System
(i) The commercial operation date in the case of an Inter-State Transmission System or an element
thereof shall be the date declared by the transmission licensee on which the Transmission System or
an element thereof is in regular service at 0000 hours after successful trial operation for transmitting
electricity and communication signals from the sending end to the receiving end as per Regulation
23 and submission of a declaration as per clause (3) of Regulation 26 of these regulations :
Provided that the commercial operation date of a transmission element that is a part of the
Associated Transmission System (ATS) shall be declared only after a successful trial run of the last
element of the said ATS:
Provided further that where only some of the transmission elements of the ATS have achieved
a successful trial run and the Connectivity grantee under GNA Regulations seeks commercial
operation of such elements for utilization by such grantee and is agreed upon by the Central
Transmission Utility, the commercial operation date of such transmission elements of the ATS may be
declared by the transmission licensee as per this Regulation:
Provided also that where only some of the transmission element(s) of the ATS have achieved a
successful trial run and if the operation of such transmission elements is certified by the concerned
Regional Power Committee(s) for improving the performance, safety and security of the grid, the
commercial operation date of such transmission element(s) of the ATS may be declared by the
transmission licensee as per this Regulation:
Provided also that in case a transmission system or an element thereof executed under regulated
tariff mechanism is prevented from regular service on or after the scheduled COD for reasons not
attributable to the transmission licensee or its supplier or its contractors but is on account of the delay
in commissioning of the concerned generating station or in commissioning of the upstream or
downstream transmission system of other transmission licensee, the transmission licensee shall
approach the Commission through an appropriate petition along with a certificate from the CTU to the
effect that the transmission system is complete as per the applicable CEA Standards, for approval of
the commercial operation date of such transmission system or an element thereof:
Provided also that in the case of inter-State Transmission System executed through Tariff
Based Competitive Bidding, the transmission licensee may declare deemed COD of the ISTS in
accordance with the provisions of the Transmission Service Agreement after obtaining (a)a certificate
from the CTU to the effect that the transmission system is complete as per the specifications of the
bidding guidelines and applicable CEA Standards and (b) no load charging certificate from the
respective RLDC, where no load charging is possible.
(ii) The COD of a transmission element of the transmission system under Tariff Based Competitive
Bidding shall be declared only after the declaration of the COD of all the pre-required transmission
elements as per the Transmission Services Agreement:
Provided that in case any transmission element is required in the interest of the power system
as certified by the concerned RPC(s), the COD of the said transmission element may be declared prior
to the declaration of the COD of its pre-required transmission elements.
(d) Communication System
Date of commercial operation in relation to a communication system or an element thereof shall mean
the date declared by the transmission licensee from 0000 hours of which a communication system or
element thereof shall be put into service after completion of the site acceptance test including transfer
of voice and data to the respective control centres as certified by the respective Regional Load
Despatch Centre.
(e) Generating Stations based on Wind and Solar resources; ESS and Hybrid Generating Station
(i) The commercial operation date in the case of units of a renewable generating station aggregating
to 50 MW and above or such other limit as specified in clause (3) of Regulation 22 of these
regulations, shall mean the date declared by the generating station after undergoing a successful
trial run as per clause (3) of Regulation 22 of these regulations, submission of declaration as per
clause (4) of Regulation 26 of these regulations, and subject to fulfilment of other conditions, if
any, as per PPA.
(ii) In the case of a generating station as a whole, the commercial operation date of the last unit of the
generating station shall be considered as the COD of the generating station.
(2) Scheduling of the generating station or unit thereof shall start from 0000 hours of D+2 (where D is the
Commercial Operation Date of the said generating station or unit thereof).
CHAPTER 6
OPERATING CODE
28. OPERATING PHILOSOPHY
(1) All entities, such as NLDC, RLDCs, SLDCs, CTU, STUs, RPCs, power exchanges, QCAs, SNAs,
licensees, generating stations, and other grid connected entities shall at all times function in coordination
to ensure integrity, stability and resilience of the grid and achieve economy and efficiency in the
operation of power system.
(2) Operation of the State grid shall be monitored by the respective SLDC. Operation of the regional grid
shall be monitored by the respective RLDC. Operation of the National grid shall be monitored by
NLDC.
(3) Detailed Operating Procedures for the National grid shall be developed, maintained and updated by
NLDC in consultation with RLDCs and relevant stakeholders and shall be kept posted on NLDCs
website.
(4) Detailed Operating Procedures for each regional grid shall be developed, maintained and updated by
respective RLDCs in consultation with NLDC, concerned RPC and regional entities and shall be kept
posted on the respective RLDCs website.
(5) Detailed Operating Procedures for each State grid shall be developed, maintained and updated by the
SLDCs, consistent with the Detailed Operating Procedures of respective RLDC.
(6) NLDC, RLDCs and SLDCs shall have qualified operating personnel manning the control room round the
clock.
(7) Every generating station, and transmission substation of 110 kV and above shall have a control room
manned by qualified operating personnel round the clock. Alternatively, the same may be operated round
the clock from a remotely located control room, subject to the condition that such remote operation does
not result in a delay in the execution of any switching instructions and information flow:
Provided that a transmission licensee owning a transmission line but not owning the connected
substation, shall have a coordination centre functioning round the clock, manned by qualified personnel
for operational coordination with the concerned load despatch centres and equipped to carry out the
operations as directed by concerned load despatch centres.
(8) SNA and QCA shall have coordination centres functioning round the clock, manned by qualified
personnel for operational coordination with the concerned load despatch centres and generating stations.
ESS and Bulk Consumers, which are regional entities shall have coordination centres functioning round
the clock and manned by qualified personnel for operational coordination with the concerned load
despatch centres.
29. SYSTEM SECURITY
(1) All users shall operate their respective power systems in an integrated manner at all times in coordination
with the concerned load despatch centres.
(2) Isolation, Taking out of service and Switching off an element of the grid:
(a) No element(s) of the grid shall be isolated from the grid, except (i) during an emergency as per
the Detailed Operating Procedure(s) of NLDC or RLDC or SLDC, as the case may be, where
such isolation would prevent a total grid collapse or would enable early restoration of power
supply; (ii) for the safety of human life; (iii) when serious damage to a critical equipment is
imminent and such isolation would prevent it; and (iv) when such isolation is specifically
instructed by NLDC or RLDC or SLDC, as the case may be. Any such isolation shall be
reported to the respective RLDC or SLDC within the next 15 minutes.
(b) Each RLDC, in consultation with the concerned RPCs, users, SLDCs, shall prepare a list of
important elements in the regional grid, including those in the State grids that are critical for
regional grid operation and shall make the said list available to all concerned.
(c) An important element of the grid as listed at sub-clause (b) of this clause can be taken out of
service only after prior clearance of the concerned RLDC, except in emergencies as per the
Detailed Operating Procedure(s) of NLDC or RLDC or SLDC, as the case may be. RLDC shall
inform the opening or removal of any such important element (s) of the regional grid to NLDC,
the concerned RPCs and the concerned regional entities who are likely to be affected, as
specified in the Detailed Operating Procedure of RLDC or NLDC.
(d) In case of switching off or tripping of any of the important elements of the regional grid under
emergency conditions or otherwise, it shall be intimated immediately by the users with
available details (i) to SLDC if the element is within the control area of SLDC, who in turn
shall intimate the concerned RLDC and (ii) to RLDC if the element is within the control area of
RLDC, who in turn will intimate the concerned SLDC(s). The reasons for such switching off or
tripping to the extent determined and the likely time of restoration shall also be intimated within
half an hour. The concerned RLDC or SLDC and the users shall ensure restoration of such
elements within the estimated time of restoration as intimated.
(e) The isolated, taken out or switched off elements shall be restored as soon as the system
conditions permit. The restoration process shall be supervised by the concerned Load Despatch
Centre, in coordination with NLDC, concerned RLDC(s) and SLDC(s) in accordance with the
system restoration procedures of NLDC and RLDC(s).
(3) Maintenance of grid elements shall be carried out by the respective users in accordance with the
provisions of the CEA Grid Standards. Outage of an element that is causing or likely to cause danger to
the grid or sub-optimal operation of the grid shall be monitored by the concerned RLDC. RLDC shall
report such outages to RPC and RPC shall issue suitable instructions to restore such elements in a
specified time period.
(4) Except in an emergency, or when it becomes necessary to prevent imminent damage to critical
equipment, no user shall suddenly reduce its generating unit output by more than 100 (one hundred) MW
[20 (twenty) MW in the case of NER] without prior permission of the respective RLDC.
(5) Except in an emergency, or when it becomes necessary to prevent imminent damage to critical
equipment, no user shall cause a sudden variation in its load by more than 100 (one hundred) MW
without the prior permission of the respective RLDC.
(6) All generating units shall have their automatic voltage regulators (AVRs), Power System Stabilizers
(PSSs), voltage (reactive power) controllers (Power Plant Controller) and any other requirements in
operation, as per the CEA Technical Standards for Connectivity. If a generating unit with a capacity
higher than 100 (hundred) MW is required to be operated without its AVR or voltage controller in
service, the generating station shall immediately inform the concerned RLDC of the reasons thereof and
the likely duration of such operation and obtain its permission.
(7) The tuning of AVR, PSS, Voltage Controllers (PPC) including for low and high voltage ride through
capability of wind and solar generators or any other requirement as per CEA Technical Standards for
Connectivity shall be carried out by the respective generating station:
- at least once every five (5) years;
- based on operational feedback provided by the RLDC after analysis of a grid event or disturbance;
and
- in case of major network changes or fault level changes near the generating station as reported by
NLDC or RLDC(s), as the case may be.
- in case of a major change in the excitation system of the generating station.
(8) Power System Stabilizers (PSSs), AVRs of generating units and reactive power controllers shall be
properly tuned by the generating station as per the plan and the procedure prepared by the concerned
RPC. In case the tuning is not complied with as per the plan and procedure, the concerned RLDC shall
issue notice to the defaulting generating station to complete the tuning within a specified time, failing
which the concerned RLDC may approach the Commission under Section 29 of the Act.
(9) Provisions of protection and relay settings shall be coordinated periodically throughout the regional grid,
as per the plan finalized by the respective RPC in accordance with the Protection, Testing and
Commissioning Code of these regulations.
(10) RPCs shall prepare the islanding schemes in accordance with the CEA Grid Standards for identified
generating stations, cities and locations and ensure their implementation. The islanding schemes shall
be reviewed and augmented depending on the assessment of critical loads at least once a year or earlier,
if required.
(11) Mock drill of the islanding schemes shall be carried out annually by the respective RLDCs in
coordination with the concerned SLDCs and other users involved in the islanding scheme. In case mock
drill with field testing is not possible to be carried out for a particular scheme, simulation testing shall
be carried out by the respective RLDC.
(12) All distribution licensees, STUs and bulk consumers shall provide automatic under-frequency relays
(UFR) and df/dt relays for load shedding in their respective systems to arrest frequency decline that
could result in grid failure as per the plan given by the RPCs from time to time. The default UFR
settings shall be as specified in Table-2 below:
Table 2: Default UFR Settings
Sr. No. Stage of UFR Operation Frequency (Hz)
1 Stage-1 49.40
2 Stage-2 49.20
3 Stage-3 49.00
4 Stage-4 48.80
Note 1: All states (or STUs) shall plan UFR settings and df/dt load shedding schemes depending on their local load
generation balance in coordination with and approval of the concerned RPC.
Note 2: Pumped storage hydro plants operating in pumping mode or ESS operating in charging mode shall be
automatically disconnected before the first stage of UFR.
The load shedding for each stage of UFR operation, in percentage of demand or MW shall be as finalised by
the respective RPCs.
(13) The following shall be factored in while designing and implementing the UFR and df/dt relay
schemes:
(a) The under-frequency and df/dt load shedding relays are always functional.
(b) Demand disconnection shall not be set with any time delay in addition to the operating time of
the relays and circuit breakers.
(c) There shall be a uniform spatial spread of feeders selected for UFR and df/dt disconnection.
(d) SLDC shall ensure that telemetered data of feeders (MW power flow in real time and circuit
breaker status) on which UFR and df/dt relays are installed is available at its control centre.
SLDC shall monitor the combined load in MW of these feeders at all times. SLDC shall share
the above data with the respective RLDC in real time and submit a monthly exception report to
the respective RPC. RLDC shall inform SLDCs as well as the concerned RPC on a quarterly
basis, durations during the quarter when the combined load in MW of these feeders was below
the level considered while designing the UFR scheme by the RPC. SLDC shall take corrective
measures within a reasonable period and inform the respective RLDC and RPC, failing which
suitable action may be initiated by the respective RPC.
(e) RPC shall undertake a monthly review of the UFR and df/dt scheme and also carry out random
inspection of the under-frequency relays. RPC shall publish such a monthly review along with
an exception report on its website.
(f) SLDC shall report the actual operation of UFR and df/dt schemes and load relief to the
concerned RLDCs and RPCs and publish the monthly report on its website.
(14) NLDC, RLDCs, SLDCs, CTU, STUs or users may identify the requirement of System Protection
Schemes (SPS) (including inter-tripping and run-back) in the power system to operate the transmission
system within operating limits and to protect against situations such as voltage collapse, cascade
tripping and tripping of important corridors/flow-gates. Any such SPS at the intra-regional level shall
be finalized by the concerned RPC. SPS at the inter-regional and cross-border levels shall be finalized
by the NLDC in coordination with the concerned RPCs. SPS shall be installed and commissioned by
the concerned users. SPS shall always be kept in service. If any SPS at the intra-regional level is to be
taken out of service, the permission of the concerned RLDC shall be required. If any SPS at the inter-
regional and cross-border levels is to be taken out of service, permission of NLDC shall be required.
(15) NLDC, RLDCs, SLDCs, and users shall operate in a manner to ensure that the steady state grid voltage
as per the CEA Grid Standards remains within the following operating range:
TABLE 3 : VOLTAGE RANGE
Voltage (kV rms)
Nominal Maximum Minimum
765 800 380
207*
400 420 198
230* 245* 99
220 245 30
132 145
110 121
66 72
33 36
*As per CEA Manual on Transmission Planning Criteria, 2023.
(16) NLDC, RLDCs and SLDCs, as the case may be, shall take appropriate measures to control the voltage as
per their operating procedures.
(17) The concerned users shall implement defence mechanisms as finalized by the respective RPCs to
prevent voltage collapse and cascade tripping.
(18) All defense mechanisms shall always be in operation and any exception shall be immediately intimated
by the concerned user to the concerned RLDC and SLDCs along with the reasons and the likely
duration of such exception. The concerned user shall also obtain permission from the concerned RLDC
or SLDC, as applicable.
30. FREQUENCY CONTROL AND RESERVES
(1) The National Reference Frequency shall be 50.000 Hz and the allowable band of frequency shall be
49.900-50.050 Hz. The frequency shall be measured with a resolution of +/-0.001 Hz by NLDC, RLDCs
and SLDC and such frequency data measured every second shall be archived by RLDCs.
(2) The NLDC, RLDC and SLDC shall endeavour that the grid frequency remains close to 50.000 Hz and in
case frequency goes outside the allowable band, ensure that the frequency is restored within the
allowable band of 49.900-50.050 Hz at the earliest.
(3) All users shall adhere to their schedule of injection or drawl, as the case may be, and take such action as
required under these regulations and as directed by NLDC or respective RLDCs or respective SLDCs so
that the grid frequency is maintained and remains within the allowable band.
Reserves
(4) There shall be reserves as under:
(a) Primary, Secondary and Tertiary reserves:
(i) Primary, Secondary and Tertiary reserves shall be deployed for the purpose of frequency
control, reducing area control error and relieving congestion.
(ii) The response under Primary reserve shall be provided as per these regulations.
(iii) Secondary reserves including automatic generation control and demand response shall be
deployed by the control area as per these regulations or the Ancillary Services Regulations
or the respective regulations on Ancillary Services of the State, as the case may be.
(iv) Tertiary reserves shall be deployed by the control area as per these regulations or the
Ancillary Services Regulations or the respective regulations on Ancillary Services of the
State, as the case may be.
(b) Black Start reserves:
Generating stations having black start capability, ESS and HVDC Station based on VSC shall
be identified by NLDC and RLDCs in consultation with SLDC(s) at the inter-State level and by
SLDC at the State level, to act as black start reserves.
(c) Voltage Control reserves:
Voltage Control reserves shall be deployed for controlling the voltage at a bus or sub-system
through reactive power injection or drawl.
(5) The reserves shall be operated as Ancillary Services, namely (a) Primary Reserve Ancillary Service
(PRAS); (b) Secondary Reserve Ancillary Service (SRAS); (c) Tertiary Reserve Ancillary Service
(TRAS); (d) Black Start Ancillary Services; and (e) Voltage Control Ancillary Services.
(6) The mechanism of procurement and deployment of PRAS shall be as specified in these regulations or in
the Ancillary Services Regulations, as the case may be.
(7) The mechanism of procurement, deployment and payment of SRAS and TRAS shall be as specified in
the Ancillary Services Regulations.
(8) The primary response of the generating units shall be verified by the Load Despatch Centres (LDCs)
during grid events. The concerned generating station shall furnish the requisite data to the LDCs within
two days of notification of reportable event by the NLDC.
Control Hierarchy
(9) Inertia:
The power system shall be operated at all times with a minimum inertia to be stipulated by NLDC so that
the minimum nadir frequency post reference contingency stays above the threshold set for under
frequency load shedding (UFLS). To maintain the minimum inertia, the NLDC may, if required, bring
quick start synchronous generation on bar and reschedule generation including curtailment of wind, solar
and wind-solar hybrid generation, in coordination with the respective RLDCs and SLDCs. The
compensation for such quick start synchronous generation shall be included in the procedure to be
prepared by NLDC and approved by the Commission.
(10) Primary Control:
(a) Primary control is local automatic control in a generating unit or energy storage system or demand
side resource for the purpose of adjusting its active power output or consumption, as the case may
be, in response to frequency excursion. Primary control is the immediate automatic control
implemented through turbine speed governors or frequency controllers.
(b) Primary control shall be provided by the Primary Reserves Ancillary Service (PRAS).
(c) The minimum quantum of PRAS required for reference contingency shall be declared by NLDC at
the start of each financial year.
(d) The generating stations and units thereof shall have electronically controlled governing systems or
frequency controllers in accordance with the CEA Technical Standards for Connectivity and are
mandated to provide PRAS. The generating stations and units thereof with governors shall be
under Free Governor Mode of Operation.
(e) NLDC may also identify other resources such as ESS and demand resource to provide PRAS for
which PRAS Providers shall be compensated in accordance with the Ancillary Services
Regulations.
(f) The minimum All India target frequency response characteristics (FRC) shall be estimated and
based on such target FRC, the frequency response obligation of each control area shall be assessed
by NLDC as per Annexure-2, giving due consideration to generation and load within each control
area and details as given in Table 4 under sub-clause(g) of this clause. The same shall be informed
to all control areas by 15tthof March every year for the next financial year.
(g) All the generating units shall have their governors or frequency controllers in operation all the time
with droop settings of 3 to 6 % (for thermal generating units and WS Seller) or 0-10% (for hydro
generating units) as specified in the CEA Technical Standards for Connectivity
(h) The primary response requirement shall be as mentioned in Table 4.
TABLE 4 : PRIMARY RESPONSE OF VARIOUS TYPES OF GENERATING UNITS
Fuel/ Source Minimum unit size/Capacity Up to
Coal/Lignite Based 200 MW and above ±5% of MCR
±10% of MCR
Hydro 25 MW and above
Gas based Gas Turbine above 50 MW ±5% of MCR
(corrected for ambience
WS Seller (commissioned Capacity of Generating station more than 10 MW
after the date as specified and connected at 33 kV and above temperature)
in the CEA Technical As per CEA Technical Standards
Standards for for Connectivity
Connectivity)
Provided that:
1. WS Sellers commissioned after the date as specified in CEA Technical Standards for Connectivity shall
have the option to provide primary response individually through ESS or through a common ESS
installed at its pooling station.
2. Nuclear generating stations and hydro generating stations (with pondage up to 3 hours or Run of the
river projects) shall be exempt from mandatory primary response. They may provide the primary
response to the extent possible, considering the safety and security of machines and humans.
(i) All generating stations mentioned in Table-4 (under sub-clause (g) of this clause) shall have the
capability of instantaneously picking up to a minimum of 105% of their operating level and up to
105% or 110% of their MCR, as the case may be, when the frequency falls suddenly and thus
providing primary response whenever conditions arise.
Any generating station not complying with the above requirements shall be kept in operation
(synchronized with the regional grid) only after obtaining the permission of the concerned
RLDC.
(j) All generating stations, including the WS seller mentioned in Table-4 (under sub-clause (g) of
this clause) shall have the capability of reducing output at least by 5% or 10%, as applicable, of
their operating level and up to 5% or 10% of their MCR, as applicable, limited to the minimum
turndown level when the frequency rises above the reference frequency and thus providing
primary response, whenever condition arise. Any generating station not complying with the
above requirements shall be kept in operation (synchronized with the regional grid) only after
obtaining permission from the concerned RLDC.
(k) The normal governor action shall not be suppressed in any manner through load limiter,
Automatic Turbine Run-up System (ATRS), turbine supervisory control or coordinated control
system and no time delays shall be deliberately introduced. In the case of a renewable energy
generating unit, a reactive power limiter or power factor controller or voltage limiter shall not
suppress the primary frequency response within its capabilities. The inherent dead band of a
generating unit or frequency controller shall not exceed +/- 0.03 Hz.
The governor shall be set with respect to a reference frequency of 50.000 Hz and response
outside the dead band shall be with respect to a total change in frequency.
(l) The thermal and hydro generating units shall not resort to Valve Wide Open (VWO) operation to
make available margin for providing governor action.
(m) The PRAS shall start immediately when the frequency deviates beyond the dead band as
specified in sub-clause (k) of this clause and shall be capable of providing its full PRAS capacity
obligation within 45 seconds and sustaining at least for the next five (5) minutes.
(n) Each control area shall assess its frequency response characteristics and share the assessment
with the concerned RLDC along with high resolution data of at least 1 (one) second for regional
entity generating stations and energy storage systems and 10 (ten) seconds for the state control
area.
(o) The concerned RLDC shall calculate actual frequency response characteristics of all the control
areas within its region. The performance of each control area in providing frequency response
characteristics shall be calculated for each reportable event as per Annexure-2.
(p) The NLDC in consultation with RLDCs shall calculate the actual frequency response
characteristics at national level by factoring in the FRC of all regions and shall also calculate the
FRC for cross border control areas.
(q) NLDC, RLDCs and SLDCs shall grade the median Frequency Response Performance annually,
considering at least 10 reportable events. In case the median Frequency Response Performance is
less than 0.75 as calculated as per Annexure-2, NLDC, RLDCs, SLDCs, as the case may be, after
analyzing the FRP shall direct the concerned entities to take corrective action. All such cases
shall be reported to the concerned RPC for its review.
(11) Secondary Control:
(a) Secondary control is a centralized automatic function to regulate the generation or load in a
control area to restore the frequency within the allowable band or replenish deployed primary
reserves.
(b) Secondary Control shall be provided by a generating station or an entity having energy storage
resource or an entity capable of providing demand response, on a standalone or aggregated basis,
connected to an inter-State transmission system or an intra-State transmission system, as a
Secondary Reserve Ancillary Service (SRAS) Provider, as specified in the Ancillary Services
Regulations.
(c) Secondary control signals shall be automatically generated from NLDC and shall be transmitted
to SRAS Providers through the concerned RLDC exercising the control area jurisdictions for
desired automated response when the Area Control Error (ACE) for each region goes beyond the
minimum threshold limit of ±10 MW, which may be reviewed from time to time based on the
review of the performance of SRAS.
Provided that as and when the bi-directional communication system of SRAS providers with
RLDCs is fully established, secondary control signals shall be automatically generated from the
respective RLDC.
(d) ACE of each State or Regional control area, shall be auto calculated at the control centre of
NLDC or RLDC or SLDC, as the case may be, based on telemetered values, and external inputs,
namely, the Frequency Bias Coefficient and Offset referred to in sub-clauses (e) and (f)
respectively of this clause as per the following formula:
ACE = (Ia - Is) - 10 * Bf * (Fa - Fs) + Offset
Where,
Ia = Actual net interchange in MW (positive value for export)
Is = Scheduled net interchange in MW (positive value for export)
Bf = Frequency Bias Coefficient in MW/0.1 Hz (negative value)
Fa = Actual system frequency in Hz
Fs = Schedule system frequency in Hz
Offset = Provision for compensating measurement error
(e) Frequency Bias Coefficient (Bf) shall be assessed and declared by NLDC in coordination with
RLDC for each region. Frequency Bias Coefficient (Bf) shall be assessed and declared by SLDC
for each State. Frequency Bias Coefficient shall normally be based on the median Frequency
Response Characteristics (FRC) observed during the previous financial year of each control area
and refined from time to time.
(f) Offset shall be used to account for measurement errors and shall be decided by NLDC or RLDC
or SLDC, as the case may be, for its respective control area.
(g) Secondary control may be operated under tie-line bias control, flat frequency control or flat tie-
line control mode depending on grid requirements:
Provided that Secondary control may be suspended due to system maintenance or grid
security or for any other reasons to be recorded in writing:
Provided further that NLDC in coordination with RLDC and SLDC shall lay down in the
Detailed operating procedure after stakeholder consultation, the conditions during which a
particular mode shall be chosen and shall document the reasons for operating in a particular
mode:
Provided also that the coordinated operation of AGC by the nested control areas shall be
adopted based on mutually agreed protocols.
(h) Schedule system frequency (Fs) shall be a reference frequency of 50 Hz unless otherwise specified
by NLDC under certain conditions to be recorded in writing.
(i) RLDCs and SLDCs shall compute the ACE of the respective regional or state control area in real
time based on telemetered data. ACE data shall be archived at an interval of 10 seconds or less.
RLDCs shall share the data with NLDC. SLDC shall share the data with the concerned RLDC and
NLDC.
(j) The SRAS Providers shall start responding to SRAS signals within thirty (30) seconds of receipt of
the signal and shall be capable of providing the entire SRAS capacity obligation within fifteen (15)
minutes and sustaining it at least for the next thirty (30) minutes. The secondary reserves shall be
gradually replaced by tertiary reserves within 30 minutes.
(k) With due regard to the requirement of planning reserve margin and resource adequacy referred to in
Chapter 2 of these regulations and based on the following methodologies, the secondary reserve
capacity requirements shall be estimated by RLDCs for their respective regional control areas:
The positive and negative secondary reserve capacity requirements for any control area for a calendar
year shall be equal to the 99 percentile of positive and negative ACE respectively of that control area
during the previous financial year (Detailed Procedure shall be as per Annexure-3 to these
regulations, which may be reviewed as and when considered necessary),
OR
The secondary reserve capacity requirement for any control area shall be equal to the 110 % of the
largest unit size in the respective regional control area or state control area plus load forecast error
plus wind forecast error plus solar forecast error during the previous calendar year.
OR
Such other methodology as may be stipulated by NLDC after obtaining the due approval of the
Commission.
(l) Unless otherwise specified by the concerned SERC, the methodology specified in sub-clause (k) of
this clause shall be adopted by the SLDCs to estimate the secondary reserve capacity requirement in
their respective control areas.
(m) The reserve capacity requirement as per the methodology mentioned in sub-clauses (k) and (l) of this
clause shall be estimated by each RLDC and SLDC respectively by 15th January every year for the
next financial year and submitted to NLDC.
(n) All India secondary reserve capacity requirement for the regional control area and the State control
area shall be estimated by NLDC based on reference contingency and other factors such as forecast
errors.
(o) NLDC shall allocate such All India secondary reserves capacity, to be maintained at regional control
area and at State control area, based on the estimated reserves as per sub-clauses (k) and (l) of this
clause and publish the information on its website by 25th January every year.
(p) NLDC through RLDCs shall re-assess the quantum of requirement of secondary reserves required at
the state control area three days before the day of scheduling and communicate the same to the
respective SLDC.
(q) Each State control area shall ensure the availability of the quantum of secondary reserve at the State
control area with due regard to the secondary reserves estimated and allocated for that State as
published by NLDC in terms of sub-clauses (o) and (p) of this clause, and inform the same to the
concerned RLDC and NLDC two days before the day of scheduling. The modalities for information
exchange and timelines in this respect shall be as per the detailed procedure to be issued by NLDC.
(r) NLDC through RLDCs shall re-assess the quantum of the requirement for secondary reserves at the
regional level with due regard inter alia to the secondary reserves maintained at State control area
and the need to replenish primary reserves two days before the day of scheduling inter alia to
identify reserves to be brought on bar under SCUC (in terms of Regulation 46 of these regulations).
(s) As specified in the Ancillary Services Regulations, NLDC through RLDCs shall further re-assess
the quantum of the requirement for secondary reserve at the regional level on day ahead basis and
also on a real time basis.
(t) If a State falls short of maintaining secondary reserve capacity as allocated to it in terms of sub-
clauses (o) or (p) of this clause, whichever is lower, the NLDC through RLDC shall procure such
Secondary reserve capacity on behalf of the State under advance intimation to the concerned State
and allocate the cost of procurement of such capacity to that State based on the methodology as per
the detailed procedure to be issued by the NLDC after approval of the Commission.
(u) NLDC, RLDC, SLDC shall indicate the shortfall in secondary reserves, if any, and announce
emergency alerts for such periods.
(v) Secondary reserves shall be procured by the NLDC from a generating station or an entity having
energy storage resources or an entity capable of providing demand response, on a standalone or
aggregated basis, connected to an inter-State transmission system or an intra-State transmission
system in accordance with the Ancillary Services regulations.
(w) All thermal generating stations having a capacity of more than 200 MW and hydro generating
stations having a capacity of more than 25 MW shall make arrangements to enable automatic
operation of the plant from the appropriate load despatch centre by integrating the controls and
telemetering features of their system into the automatic generation control in accordance with the
CEA Technical Standards for Construction and the CEA Technical Standards for Connectivity. The
communication system shall be established in accordance with the CEA Communication
Regulations.
(x) All renewable energy generating stations and ESS shall be equipped with the facility to control
active power injection in accordance with the CEA Connectivity Standards and the communication
system shall be established in accordance with the CEA Technical Standards for Communication.
(y) SRAS shall have a bi-directional communication system along with metering and SCADA
telemetry in place as per the requirements stipulated in the Detailed Procedure issued under the
Ancillary Service Regulations.
(12) Tertiary Control:
(a) Tertiary reserve requirement for the regional control area and the State control area, shall be estimated
by NLDC with due regard inter alia to the requirement of planning reserve margin and resource
adequacy as referred to in Chapter 2 of these regulations, so as to take care of contingencies and to
cater to the need for replacing secondary reserves estimated as per clause (11) of this Regulation by
25th January every year, which will be implemented for the next financial year from 1st April onwards
by the respective control areas.
(b) NLDC shall allocate such tertiary reserve capacity, to be maintained at regional control areas and state
control areas, based on the estimated reserves as per these regulations and publish the information on its
website by 25th January every year.
(c) NLDC through RLDCs shall re-assess the quantum of requirements for tertiary reserves required at
the state control area three days before the day of scheduling and communicate the same to the
respective SLDC.
(d) Each State control area shall ensure the availability of the quantum of tertiary reserve at the State
control area with due regard to the tertiary reserves estimated and allocated for that State as published
by NLDC in terms of sub-clauses (b) and (c) of this clause, and inform the same to the concerned
RLDC and NLDC two days before the day of scheduling. The modalities for information exchange and
timelines in this respect shall be as per the detailed procedure to be issued by NLDC.
(e) Each State control area shall ensure availability of the quantum of tertiary reserve at the State control
area on day ahead basis with due regard to the tertiary reserves estimated and allocated for that State
by NLDC in terms of sub-clause (b) and (c) of this clause, and inform the same to the concerned
RLDC and the NLDC.
(f) NLDC through RLDCs shall re-assess the quantum of requirements for tertiary reserve at the regional
level with due regard to the estimation inter alia of tertiary reserves maintained at State control area
and the need to replace secondary reserves, three days before the day of scheduling inter alia to
identify reserves to be brought on bar under SCUC (in terms of Regulation 46 of these regulations).
(g) As specified under the Ancillary Services Regulations, NLDC through RLDCs shall further re-assess
the quantum of the requirement for tertiary reserve at regional level on day ahead basis and also on a
real time basis.
(h) If a State falls short of maintaining tertiary reserve capacity as allocated to it in terms of sub-clauses (b)
or (c) of this clause , whichever is lower, the NLDC through RLDCs shall procure such tertiary reserve
capacity on behalf of the said State under advance intimation to the concerned State and allocate the
cost of procurement of such capacity to that State based on the methodology as per the detailed
procedure to be issued by the NLDC after approval of the Commission.
(i) Tertiary reserves shall be procured by the NLDC from a generating station or an entity having energy
storage resourced or an entity capable of providing demand response, on a standalone or aggregated
basis, connected to an inter-State transmission system or an intra-State transmission system in
accordance with the Ancillary Services regulations.
(j) Tertiary reserves to be provided by the TRAS provider shall be capable of providing TRAS within
fifteen (15) minutes of despatch instructions from RLDC or SLDC, as the case may be, and shall be
capable of sustaining the service for at least the next 60 minutes. TRAS shall be activated and
deployed by the appropriate load despatch center on account of the following events:
i. To replenish the secondary reserve, in case the secondary reserve has been deployed
continuously in one direction for fifteen (15) minutes for more than 100 MW (20 MW in the
case of NER) or in respect of a State such other volume limit as may be specified by the
respective SERC;
ii. Generation unit or transmission line outages;
iii. Any such other event affecting the grid security.
(k) The quantum of reserves procured by each State control area shall be communicated to the concerned
RLDC.
(l) The modalities for information exchange and timelines in respect of tertiary reserves shall be as per
detailed procedure prepared by NLDC.
(13) The control area wise performance of SRAS, TRAS providers shall be evaluated in accordance with the
Detailed Procedure prepared by NLDC.
31. OPERATIONAL PLANNING
(1) Time Horizon
(a) Operational planning shall be carried out in advance by NLDC, RLDCs and SLDCs within their
respective control areas with Monthly and Yearly time horizons in co-ordination with CTU, RPCs
or STUs, as applicable.
(b) Operational planning shall be carried out in advance by NLDC, RLDCs and SLDCs within their
respective control areas on Intra-day, Day Ahead, Weekly time horizons.
(c) RLDCs in consultation with NLDC shall issue procedures and formats for data collection to carry
out:
(i) Operational planning analysis,
(ii) Real-time monitoring,
(iii) Real-time assessments.
(d) SLDC may also issue procedures and formats for data collection for the above purposes.
(2) Demand Estimation
(a) Each SLDC shall carry out demand estimation as part of operational planning after duly factoring in
the demand estimation done by STU as part of resource adequacy planning referred to in Chapter 2
of these regulations. Demand estimation by SLDC shall be for both active power and reactive
power incidents on the transmission system based on the details collected from distribution
licensees, grid-connected distributed generation resources, captive power plants and other bulk
consumers embedded within the State.
(b) Each SLDC shall develop methodology for daily, weekly, monthly, yearly demand estimation in
MW and MWh for operational analysis as well as resource adequacy purposes. Each SLDC, while
estimating demand may utilize state of the art tools, weather data, historical data and any other data.
For this purpose, all distribution licensees shall maintain a historical database of demand.
(c) The demand estimation by each SLDC shall be done on day ahead basis with time block wise
granularity for the daily operation and scheduling. In case SLDC observes a major change in
demand in real time for the day, it shall immediately submit the revised demand estimate to the
concerned RLDC for demand estimate correction.
(d) Each SLDC shall submit node-wise morning peak, evening peak, day shoulder and night off-peak
estimated demand in MW and MVA on a monthly and quarterly basis for the nodes 110 kV and
above for the preparation of scenarios for computation of TTC and ATC by the concerned RLDC
and NLDC.
(e) SLDC shall also estimate peak and off-peak demand (active as well as reactive power) on a weekly
and monthly basis for load - generation balance planning as well as for operational planning
analysis, which shall be a part of the operational planning data. The demand estimates mentioned
above shall have granularity of a time block. The estimate shall cover the load incident on the grid
as well as the net load incident taking into account embedded generation in the form of roof-top
solar and other distributed generation.
(f) The entities such as bulk consumers or distribution licensees that are directly connected to ISTS
shall estimate and furnish such a demand estimate to the concerned RLDC.
(g) Based on the demand estimate furnished by the SLDCs and other entities directly connected to
ISTS, each RLDC shall prepare the regional demand estimate and submit it to the NLDC. NLDC,
based on regional demand estimates furnished by RLDCs, shall prepare national demand estimate.
(h) Timeline for submission of demand estimate data by SLDCs or other entities directly connected to
ISTS, as applicable, to the respective RLDC and RPC shall be as follows:
Daily demand estimation TABLE 5 : TIMELINE FOR DEMAND ESTIMATION
Weekly demand estimation 10:00 hours of previous day
Monthly demand estimation First working day of previous week
Yearly demand estimation Fifth day of previous month
30th September of the previous year
(i) SLDCs, RLDCs and NLDC shall compute forecasting error for intra-day, day-ahead, weekly,
monthly and yearly forecasts and analyse the same in order to reduce forecasting error in the future.
The computed forecasting errors shall be made available by SLDCs, RLDCs and NLDC on their
respective websites.
(3) Generation Estimation
(a) The modalities of generation estimation by entities shall be as per the Procedure referred to in sub-
clause (c) of clause (1) of Regulation 31 of these regulations.
(b) RLDC shall forecast generation from wind, solar, ESS and Renewable Energy hybrid generating
stations that are regional entities and SLDC shall forecast generation from such sources that are
intra-state entities, for different time horizons as referred to in clause (1) of Regulation 31 of these
regulations for the purpose of operational planning.
(4) Adequacy of Resources
(a) SLDCs shall estimate and ensure the adequacy of resources, identify generation reserves, demand
response capacity and generation flexibility requirements with due regard to the resource adequacy
framework as specified under Chapter 2 of these regulations.
(b) SLDCs shall furnish time block-wise information for the following day in respect of all intra-state
entities to the concerned RLDC who shall validate the adequacy of resources with due regard to the
following:
(i) Demand forecast aggregated for the control area;
(ii) Renewable energy generation forecast for the control area;
(iii) Injection schedule for intra-State entity generating station;
(iv) Requisition from regional entity generating stations;
(v) Secondary and planned procurement through Tertiary reserve requirement;
(vi) Planned procurement of power through other bilateral or collective transactions, if any.
32. OUTAGE PLANNING
(1) Outage planning shall be prepared for the grid elements in a coordinated and optimal manner keeping in view
the system operating conditions and grid security. The coordinated generation and transmission outage
plan for the national and regional grid shall take into consideration all the available generation resources,
demand estimates, transmission constraints, and factor in water for irrigation requirements, if any. To
optimize the transmission outages of the national and regional grids, to avoid grid operation getting
adversely affected and to maintain system security standards, the outage plan shall also take into account
the generation outage schedule and the transmission outage schedule.
(2) Annual outage plan shall be prepared as follows:
(a) Annual outage plan of grid elements under regional control area and identified elements of State control
areas under sub-clause (b) of clause (2) of Regulation 29 of these regulations, shall be prepared in advance
for the financial year by the RPCs in consultation with the users, respective SLDCs, RLDCs and NLDC
and reviewed before every quarter and every month.
(b) Annual outage plan shall be prepared in such a manner as to minimize the overall downtime,
particularly where multiple entities are involved in the outage of any grid element(s).
(c) The outage plan of hydro generation plants, REGS and ESS and its associated evacuation network
shall be prepared with a view to extracting maximum generation from these sources.
Example: Outage of wind generator may be planned during lean wind season. Outage of solar generator, if
required, may be planned during the rainy season. Outage of hydro generator may be planned during the
lean water season.
(d) Protection relay related outages, auto-re-closure outages and SPS testing outages shall be planned
on a monthly basis with the prior permission of the concerned RPC, which shall consult the
concerned RLDC & NLDC.
(3) Outage Planning Process shall be as follows:
(a) RPCs shall prepare and finalize the annual outage plan for the next financial year in respect of grid
elements of their respective regional grid,
(b) RPCs shall prepare Load Generation Balance Report (LGBR) for the respective region based on the
LGBR submitted by SLDCs for their respective states and the data submitted by the regional entity
generating stations, inter-State transmission licensees and other entities directly connected to ISTS in
such format as may be stipulated by the RPCs and shall prepare annual outage plan for generating units
and transmission elements in their respective region after carrying out necessary system studies in order
to ensure system security and resource adequacy.
(c) RPCs shall finalize the outage plans in consultation with the NLDC and respective RLDCs. The final
outage plan and the final LGBR shall be intimated to NLDC, concerned RLDC, Users, STUs, CTU and
the generating stations connected to the ISTS. The final outage plan and the final LGBR shall be made
available on the websites of the respective users, RPCs, RLDCs and NLDC.
(d) The timeline for Outage Planning Process shall be as follows:
TABLE 6 : TIMELINE FOR OUTAGE PLANNING PROCESS
Activity Agency Cut-off date
STUs, transmission 31st October
Submission of proposed outage plan for the next financial year to RPC licensees, generating 31st October
with the earliest start date and latest finishing date stations and other entities 30th November
directly connected to ISTS 31st December
Submission of LGBR of the control area to RPC for both peak and
off-peak scenarios SLDC
Publishing draft LGBR and draft outage plan of regional grid for next
financial year on the concerned RPCs website for inviting suggestions, RPC
comments, objections of stakeholders.
Publishing final LGBR and final outage plan of regional grid for next RPC
financial year on the concerned RPCs website
(e) The annual outage plan shall be reviewed by RPC on a monthly and quarterly basis in coordination with
all the parties concerned, and adjustments or additions of new outages shall be made wherever necessary.
(f) All users, CTU and STUs, licensees shall follow the annual outage plan. If any deviation is required, the
same shall be allowed only with the prior permission of the concerned RPC, which shall consult the
concerned RLDC and NLDC.
(g) Each user shall obtain the final clearance from NLDC or the concerned RLDC, prior to the planned
outage of any grid element. The clearance shall also be obtained from SLDC for a grid element of the
State Control areas. All deviations from the outage plan shall be uploaded on the RPC website.
(h) In case of grid disturbances, system isolation, partial black-out in a State or any other event in the system
that may have an adverse impact on the system security due to a proposed outage,
(i) NLDC, RLDC or SLDC, as the case may be, shall have the authority to defer the planned
outage;
(ii) SLDC, RLDC or NLDC, as the case may be, before giving clearance of the planned outage
may conduct studies again.
(4) To facilitate coordinated planned outages of grid elements, a common outage planning procedure shall be
formulated by each RPC in consultation with the NLDC, concerned RLDC and concerned users.
33. OPERATIONAL PLANNING STUDY
(1) Based on the operational planning analysis data, operational planning study shall be carried out by
various agencies for time horizons as under:
TABLE 7 : TIME HORIZON FOR OPERATIONAL PLANNING STUDY
Time horizon of operational Agency Means for carrying out study
planning study
NLDC, RLDC and SLDC For various operating conditions using
Real time and Intra-day NLDC, RLDC, and SLDC online/offline SCADA/EMS system
NLDC, RLDC, and SLDC For various operating conditions using offline tools
Day-ahead RPC For various operating conditions using offline tools
Weekly For various operating conditions using offline tools
Monthly/Yearly
(2) SLDCs, RLDCs and NLDC shall utilize network estimation tool integrated in their EMS and SCADA
systems for the real time operational planning study. All users shall make available at all times real time
error free operational data for the successful execution of network analysis using EMS/SCADA. Failure
to make available such data shall be immediately reported to the concerned SLDC, the concerned RLDC
and NLDC along with a firm timeline for restoration. The performance of online network estimation
tools at SLDC and RLDC shall be reviewed in the monthly operational meeting of RPC. Any telemetry
related issues impacting the online network estimation tool shall be monitored by RPC for their early
resolution.
(3) SLDCs shall perform day-ahead, weekly, monthly and yearly operational studies for the concerned State
for:
(a) assessment and declaration of total transfer capability (TTC) and available transfer capability
(ATC) for the import or export of electricity by the State. TTC and ATC shall be revised from
time to time based on the commissioning of new elements and other grid conditions and shall be
published on SLDC website with all the assumptions and limiting constraints;
(b) planned outage assessment;
(c) special scenario assessment;
(d) system protection scheme assessment;
(e) natural disaster assessment; and
(f) any other study relevant in operational scenario.
(4) RLDCs and NLDC shall perform day-ahead, weekly, monthly and yearly operational studies for:
(a) assessment of TTC and ATC at inter-regional, intra-regional, and inter-state levels;
(b) planned outage assessment;
(c) special scenario assessment;
(d) system protection scheme assessment;
(e) natural disaster assessment; and
(f) any other study relevant to operational scenarios
(5) RLDC shall assess intra-regional and inter-state level TTC and ATC and submit them to NLDC. NLDC
shall declare TTC and ATC for import or export of electricity between regions including simultaneous
import or export capability for a region, and cross-border interconnections 11 (Eleven) months in
advance for each month on a rolling basis. TTC and ATC shall be revised from time to time based on the
commissioning of new elements and other grid conditions and shall be published on the websites of the
NLDC and respective RLDCs with all the assumptions and limiting constraints.
(6) Operational planning study shall be done to assess whether the planned operations shall result in
deviations from any of the system operational limits defined under these regulations and applicable CEA
Standards. The deviations, if any, shall be reviewed in the monthly operational meeting of RPC and
significant deviations shall be monitored by RPC for early resolution.
(7) NLDC, RLDCs, RPCs and SLDCs shall maintain records of the completed operational planning study,
including date specific power flow study results, the operational plan and minutes of meetings on
operational study.
(8) NLDC, RLDCs, RPCs and SLDCs shall have operating plans to address potential deviations from
system operational limit identified as a result of the operational planning study. These operating plans
shall be communicated to users in advance so that they can take corrective measures. In case any user is
unable to adhere to such an operating plan, it shall inform the respective SLDC, RLDC and NLDC in
advance with detailed reasons and explanations for the non-adherence. These detailed reasons and
explanations shall be discussed in the monthly operation sub-committee of the respective region and a
quarterly report shall be submitted by the respective RPC to the Commission and CEA.
(9) Each SLDC shall undertake a study on the impact of new elements to be commissioned in the intra-state
system in the next six (6) months on the TTC and ATC for the State and share the results of the studies
with RLDC.
(10) Each RLDC shall undertake a study on the impact of new elements to be commissioned in the next six
(6) months in (a) the ISTS of the region and (b) the intra-state system on the inter-state system and
share the results of the studies with NLDC.
(11) NLDC shall undertake study on the impact of new elements to be commissioned in the next six (6)
months in (a) inter-regional system, (b) cross-border link and (c) intra-regional system on the inter-
regional system.
(12) NLDC, RLDCs and SLDCs shall compare the results of the studies of the impact of new elements on
the system and transfer capability addition with those of the interconnection and planning studies by
CTU and STUs, and any significant variations observed shall be communicated to CEA, RPCs, CTU
and STUs for immediate and long-term mitigation measures.
(13) Defense mechanisms like system protection scheme, load-rejection scheme, generation run-back,
islanding scheme or any other scheme for system security shall be proposed by the concerned user or
SLDC or RLDC or NLDC and shall be deployed as finalized by the respective RPC.
34. SYSTEM RESTORATION
(1) Based on the template issued by NLDC, SLDC of each State and the RLDC of each region shall prepare
restoration procedures for the grid for their respective control areas, which shall be updated every year
by the concerned SLDC and RLDC taking into account changes in the configuration of their respective
power systems.
(2) Each RLDC, in consultation with the NLDC, CTU, and the concerned STUs, SLDCs, users and RPC,
shall prepare detailed procedures for restoration of the regional grid under partial and total blackouts
which shall be reviewed and updated annually by the concerned RLDC.
(3) Detailed procedures for restoration post partial and total blackout of each user system within a region
shall be prepared by the concerned user in coordination with the concerned SLDC, RLDC or NLDC, as
the case may be. The concerned user shall review the procedure every year and update the same. The
user shall carry out a mock trial run of the procedure for different sub-systems including black-start of
generating units along with grid forming capability of inverter based generating station and VSC based
HVDC black-start support at least once a year under intimation to the concerned SLDC and RLDC.
Diesel generator sets and other standalone auxiliary supply source to be used for black start shall be
tested on a weekly basis and the user shall send the test reports to the concerned SLDC, RLDC and
NLDC on a quarterly basis.
(4) Simulation studies shall be carried out by each user in coordination with RLDC for preparing, reviewing
and updating the restoration procedures considering the following:
(a) Black start capability of the generator;
(b) Ability of black start generator to build cranking path and sustain island;
(c) Impact of block load switching in or out;
(d) Line/transformer charging;
(e) Reduced fault levels;
(f) Protection settings under restoration condition.
(5) The thermal and nuclear generating stations shall prepare themselves for house load operation as per
design. The concerned user and SLDC shall report the performance of house load operation of a
generating station in the event where such operation was required.
(6) NLDC, RLDC and SLDC shall identify the generating stations with black start facility, grid forming
capability of inverter based generating stations, house load operation facility, inter-State or inter-regional
ties, synchronizing points and essential loads to be restored on priority.
(7) During the restoration process following a blackout, SLDC, RLDC and NLDC are authorized to operate
with reduced security standards for voltage and frequency and may direct the implementation of such
operational measures, namely, suspension of secondary or tertiary frequency control, power market
activities, defense schemes, reduced governor droop setting as necessary, in order to achieve the fastest
possible recovery of the grid.
(8) All communication channels required for restoration process shall be used for the operational
communication only till the grid normalcy is restored.
(9) Any entity extending black start support by way of injection of power as identified in clause (6) of this
Regulation shall be paid for actual injection @ 110 % of the normal rate of charges for deviation in
accordance with DSM Regulations for the last block in which the grid was available. The procedure in
this regard shall be prepared by NLDC in consultation with stakeholders and approved by the
Commission.
35. REAL TIME OPERATION
(1) System state
Power system shall be categorized under normal, alert, emergency, extreme emergency and restoration
state depending on the type of contingencies and value of operational parameters of the power system by
RLDC, NLDC or SLDC, as the case may be.
(a) Normal state
Power system shall be categorized under normal state when the power system is operating with
operational parameters within their respective operational limits and equipment are within their
respective loading limits. Under normal state, the power system is secure and capable of
maintaining stability under contingencies defined in the CEA Transmission Planning Criteria.
(b) Alert state
Power system shall be categorized under alert sate when the power system is operating with
operational parameters within their respective operational limits, but a single contingency (,,N-
1) leads to a violation of security criteria. The power system remains intact under such alert
state. However, whenever the power system is under alert sate, the system operator shall take
corrective measures to bring it back to a normal state.
(c) Emergency state
Power system shall be categorized under emergency state when the power system is operating
with operational parameters outside their respective operational limits or equipment are above
their respective loading limits. Emergency state can arise out of multiple contingencies or any
major grid disturbance in the system. The power system remains intact under such emergency
state. However, whenever the power system is under emergency sate, the system operator, to
bring back the power system to alert/normal state shall take corrective measures such as:
- extreme measures such as load shedding, generation unit tripping, line tripping or
closing,
- emergency control action such as HVDC Control, Excitation Control, HP-LP Bypass,
tie line flow rescheduling on critical lines, and
- automated action such as system protection scheme, load curtailment scheme and
generation run-back scheme.
(d) Extreme Emergency state
Power system shall be categorized under extreme emergency state if the control actions taken
during the emergency state are not able to bring the system either to an alert state or a normal
state and operational parameters are outside their respective operational limits or equipments
are critically loaded. Extreme emergency state may arise due to high impact low frequency
events like natural disasters. The power system may or may not remain intact (splitting may
occur) and extreme events like generation plant tripping, bulk load shedding, under frequency
load shedding (UFLS) and under voltage load shedding (UVLS) operation may occur.
(e) Restorative State
Power system shall be categorized under restorative state when control action is being taken to
reconnect the system elements and restore system load. The power system transits from a
restorative state to either an alert state or a normal state, depending on the system conditions.
(2) Each RLDC in consultation with NLDC and SLDCs shall carry out the study for the concerned region
and based on historical data and grid incidences evolve detailed criteria to categorise the power system
in terms of the above states. The detailed criteria shall be included in the respective Detailed Operating
Procedure to be issued by RLDCs and NLDC.
(3) NLDC, RLDCs or SLDCs, as the case may be, shall maintain the grid in the normal state by taking
suitable measures. In case the power system moves away from the normal state, appropriate measures
shall be taken to bring the system back to the normal state. In case the power system has moved to an
extreme emergency state, appropriate LDCs shall take emergency action and initiate restorative
measures immediately.
(4) Procedure to be followed during an event
(a) in the case of an event on the intra-State transmission system that may significantly impact the
inter-State transmission system, the concerned SLDC shall immediately inform the RLDC;
(b) in the case of an event on the inter-State transmission system or relating to a regional entity, the
concerned entity shall immediately inform the RLDC.
(c) immediately following an event on the regional grid, the RLDC shall inform the concerned
users and the concerned SLDC of the necessary action to be taken.
(d) any warning in respect of system security issued by NLDC or RLDC or SLDC shall be taken
note of immediately by the concerned users who shall take the necessary action to withstand the
said event or to minimize its effect.
(5) Operational coordination
(a) For operational coordination, each inter-State transmission licensee, generating station, QCA
and SNA shall have a control centre or coordination centre for round the clock coordination as
specified in clauses (7) and (8) of Regulation 28 of these regulations.
(b) Any planned operation activity in the ISTS system [such as generating unit synchronization or
de-synchronization, transmission element opening or closing (including breakers), protection
system outage, SPS outage and testing etc.] shall be done by taking operational code from
RLDC or NLDC, as the case may be. The operational code shall have validity period of sixty
(60) minutes from the time of issue. In case such operation activity does not take place within
the validity period of the code, the entity shall obtain a fresh operational code from RLDC or
NLDC, as the case may be.
36. DEMAND AND LOAD MANAGEMENT
(1) The demand and load shall be managed for ensuring grid security.
(2) SLDC, in coordination with STU and Distribution Licensee (s), shall develop Automatic Demand
Management scheme with emergency controls at SLDC.
(3) Whenever the power system is in an alert state or emergency state as assessed by SLDC or advised by
RLDC.
(a) the respective distribution licensee or bulk consumer under the regional control area shall abide
by the directions of the RLDC to secure the system, and extreme measures like load shedding
may be carried out as a last resort.
(b) the respective distribution licensee under state control area shall abide by the directions of
SLDC to secure the system, and extreme measures like load shedding may be carried out as a
last resort.
(c) SLDC or RLDC through SLDC may direct distribution licensees or bulk consumers directly
connected to STU, to restrict drawal from the grid or curtail load to ensure the stability of the
grid:
Provided that load shedding shall be resorted to after the demand response option has been
exhausted.
(d) The load disconnected, if any, shall be restored as soon as possible on clearance from SLDC, in
coordination with RLDC if required, after the system has been normalized.
37. POST DESPATCH ANALYSIS
(1) Operational analysis
(a) NLDC, RLDCs and SLDCs shall analyse the following:
(i) Pattern of demand met, under drawls and over drawls, frequency profile, voltage and tie-line
flows, angular spread, area control error, reserve margin, load and RE forecast errors, ancillary
services despatched, transmission congestion and (n-1) violations;
(ii) Generation mix in terms of source and station wise generation;
(iii) Irregular pattern in any of the system parameters mentioned in sub-clauses (a)(i) and (a)(ii) of
this clause and reasons thereof; and
(iv) Extreme weather events or any other event affecting grid security.
(b) Such analysis shall be disclosed on their respective websites in formats issued by NLDC.
(c) RLDCs shall prepare a quarterly report that shall bring out the system constraints, reasons for not
meeting the requirements, if any, of security standards and quality of service, along with details of
actions taken, including by those responsible for causing disturbances in the system parameters.
(d) RLDCs shall also provide such a report to the concerned RPC.
(e) For the purpose of analysis and reporting, telemetered data shall be archived with a granularity of
not more than five (5) minutes and higher granularity for special events. Such data shall be stored by
SLDCs, RLDCs and NLDC for at least fifteen (15) years and reports shall be stored for twenty-five
(25) years for operational analysis.
(2) Event reporting
Event reporting shall make available adequate data to facilitate event analysis.
(a) Immediately following an event (grid disturbance or grid incidence as defined in the CEA Grid
Standards) in the system, the concerned user or SLDC shall inform the RLDC through voice
message.
(b) Written flash report shall be submitted to RLDC and SLDC by the concerned user within the time
line specified in Table 8 below.
(c) Disturbance Recorder (DR), station Event Logger (EL), Data Acquisition System (DAS) shall be
submitted within the time line specified in Table 8 below.
(d) RLDC shall report the event (grid disturbance or grid incidence) to CEA, RPC and all regional
entities within twenty-four (24) hours of receipt of the flash report.
(e) After a complete analysis of the event, the user shall submit a detailed report in the case of grid
disturbance or grid incidence within one (1) week of the occurrence of event to RLDC and RPC.
(f) RLDCs and NLDC (for events involving more than one region) shall prepare a draft report of
each grid disturbance or grid incidence including simulation results and analysis which shall be
discussed and finalized at the Protection sub-committee of RPC as per the timeline specified in
Table-8 below.
TABLE 8 : REPORT SUBMISSION TIMELINE
Grid Event^ Flash report Disturbance Detailed Draft Discussion in
(Classification) submission record and report and report protection
station event submission
Sr. deadline log submission data deadline committee meeting
No. (users/ submission (RLDC/ and final report
SLDC) deadline NLDC)
(users/ deadline submission deadline
SLDC) (users/ (RPC)
SLDC)
1 GI-1/GI-2 8 hours 24 hours +7 days +7 days +60 days
8 hours 24 hours +7 days +7 days +60 days
2 Near miss event 8 hours 24 hours +7 days +7 days +60 days
8 hours 24 hours +7 days +21 days +60 days
3 GD-1 8 hours 24 hours +7 days +30 days +60 days
4 GD-2/GD-3
5 GD-4/GD-5
^The classification of Grid Disturbance (GD)/Grid Incident (GI) shall be as per the CEA Grid Standards.
(g) The implementation of the recommendations of the final report shall be monitored by the
protection sub-committee of the RPC. NLDC shall disseminate the lessons learnt from each event
to all the RPCs for necessary action in the respective regions.
(h) Any additional data such as single line diagram (SLD) of the station, protection relay settings,
HVDC transient fault record, switchyard equipment and any other relevant station data required
for carrying out analysis of an event by RPC, NLDC, RLDC and SLDC shall be furnished by the
users including RLDC and SLDC, as the case may be, within forty- eight (48) hours of the
request. All users shall also furnish high-resolution analog data from various instruments
including power electronic devices like HVDC, FACTS, renewable generation (inverter level or
WTG level) on the request of RPCs, NLDC, RLDCs or SLDCs.
(i) Triggering of STATCOM, TCSC, HVDC run-back, HVDC power oscillation damping,
generating station power system stabilizer and any other controller system during any event in the
grid shall be reported to the concerned RLDC and RPC if connected to ISTS and to the concerned
SLDC if connected to an intra-state system. The transient fault records and event logger data shall
be submitted to the concerned RLDC or SLDC within 24 hours of the occurrence of the incident.
Generating stations shall submit 1 second resolution active power and reactive power data
recorded during oscillations to the concerned RLDC or SLDC within 24 hours of the occurrence
of the oscillations.
(j) A monthly report on events of unintended operation or non-operation of the protection system
shall be prepared and submitted by each user [owner of important elements as identified at sub-
clause (b) of clause (2) of Regulation 29 of these regulations] to the concerned RPC and RLDC
within the first week of the subsequent month.
38. PERIODIC REPORTS
(1) Daily and monthly reports covering the performance of the integrated grid shall be prepared by NLDC.
(2) Daily and monthly reports covering the performance of the regional grid shall be prepared by each
RLDC based on the inputs received from SLDCs and users.
(3) The reports shall, inter-alia, contain the following:
(i) Frequency profile;
(ii) Source wise generation for each control area;
(iii) Drawal from the grid and area control error;
(iv) Demand met (peak, off-peak and average);
(v) Demand/Energy unserved in MW and MWh;
(vi) Instances and quantum of curtailment of renewable energy;
(vii) Voltage profile of important substations and sub-stations normally having low or high voltage;
(viii) Major generation and transmission outages;
(ix) Constraints and instances of congestion in the transmission system;
(x) Instances of persistent/significant non-compliance with the Grid Code;
(xi) Status of reservoirs.
(4) The NLDC shall prepare a quarterly report providing operational feedback for grid planning and re-
optimization and submit it to the CTU and CEA and upload it on its website.
39. REACTIVE POWER MANAGEMENT
(1) All users shall endeavour to maintain the voltage at the interconnection point in the range specified in the
Grid Code.
(2) All generating stations shall be capable of supplying reactive power support so as to maintain power
factor at the point of interconnection within the limits of 0.95 lagging to 0.95 leading as per the CEA
Connectivity Standard Regulations.
(3) All generating stations connected to the grid shall generate or absorb reactive power as per instructions
of the concerned RLDC or SLDC, as the case may be, within the capability limits of the respective
generating units, where capability limits shall be as specified by the OEM.
(4) The reactive interchange of the users shall be measured and monitored by the SLDC and the RLDC.
(5) NLDC, RLDCs or SLDCs may direct the users about reactive power set-points, voltage set-points and
power factor control to maintain the voltage at interconnection points.
(6) NLDC, RLDCs and SLDCs shall assess the dynamic reactive power reserve available at various
substations or generating stations under any credible contingency on a regular basis based on technical
details and data provided by the users, as per the procedure specified by NLDC.
(7) NLDC, RLDCs and SLDCs shall take appropriate measures to maintain the voltage within limits, inter-
alia, using the following facilities, and the facility owner shall abide by the instructions of NLDC,
RLDCs and SLDCs:
(i) shunt reactors,
(ii) shunt capacitors (excluding HVDC automatic control),
(iii) TCSC,
(iv) VSC based HVDC,
(v) synchronous/non-synchronous generator voltage control including inverter based reactive
power support,
(vi) synchronous condenser,
(vii)static VAR compensators (SVC), STATCOM and other FACTS devices,
(viii) transformer tap change: generator transformer and inter-connecting transformer,
(ix) HVDC power order or HVDC controller selection to optimise filter bank.
(8) Reactive power facility shall be in operation at all times and shall not be taken out without the
permission of the concerned RLDC or SLDC.
(9) Periodic or seasonal tap changing of inter-connecting transformers and generator transformers shall be
carried out to optimize the voltages, subject to technical feasibility, and where ever necessary, other
options such as tap staggering may be carried out in the network.
(10) Hydro and gas generating units having this capability shall operate in synchronous condenser mode
operation as per instructions of the RLDC or SLDC of the respective control area. Standalone
synchronous condenser units shall operate as per the instructions of RLDC or SLDC, as per the
respective control area. The compensation for such synchronous condenser mode operation shall be
included in the procedure to be submitted by NLDC and approved by the Commission.
(11) Any commercial settlement for reactive power shall be governed as per the regulatory framework
specified in Annexure-4 until the same is separately notified as part of the CERC Ancillary Services
Regulations.
(12) If voltages are outside the limit as specified in clause (15) of Regulation 29 of these regulations and the
means of voltage control set out in clause (7) of this Regulation are exhausted, SLDCs, RLDCs or
NLDC shall take all reasonable actions necessary to restore the voltages so as to be within the relevant
limits including switching ON or OFF of lines considering the security of the system.
40. PERIODIC TESTING
(1) There shall be periodic tests, as required under clause (3) of this Regulation, carried out on power system
elements for ascertaining the correctness of mathematical models used for simulation studies as well as
ensuring desired performance during an event in the system.
(2) General provisions
(a) The owner of the power system element shall be responsible for carrying out tests as specified
in these regulations and for submitting reports to NLDC, RLDCs, CEA and CTU for all
elements and to STUs and SLDCs for intra-State elements.
(b) All equipment owners shall submit a testing plan for the next year to the concerned RPC by
31st October to ensure proper coordination during testing as per the schedule. In case of any
change in the schedule, the owners shall inform the concerned RPC in advance.
(c) The tests shall be performed once every five (5) years or whenever major retrofitting is done.
If any adverse performance is observed during any grid event, then the tests shall be carried out
even earlier, if so advised by SLDC or RLDC or NLDC or RPC, as the case may be.
(d) The owners of the power system elements shall implement the recommendations, if any,
suggested in the test reports in consultation with NLDC, RLDC, CEA, RPC and CTU.
(3) Testing requirements
The following tests shall be carried out on the respective power system elements:
TABLE 9 : TESTS REQUIRED FOR POWER SYSTEM ELEMENTS
Power System Tests Applicability
Elements
(1) Real and Reactive Power Capability assessment. Individual Unit of
Synchronous (2) Assessment of Reactive Power Control Capability as per CEA rating 100MW and
Generator above for
Technical Standards for Connectivity Coal/lignite, 50MW
Non synchronous and above gas turbine
Generator (3) Model Validation and verification test for the complete and 25 MW and
(Solar/Wind) above for Hydro.
Generator and Excitation System model including PSS.
Applicable as per
(4) Model Validation and verification of Turbine/Governor and CEA Technical
Standards for
Load Control or Active Power/ Frequency Control Functions. Connectivity.
(5) Testing of Governor performance and Automatic Generation
Control.
(1) Real and Reactive Power Capability for Generator
(2) Power Plant Controller Function Test
(3) Frequency Response Test
(4) Active Power Set Point change test.
Power System Tests Applicability
Elements
(5) Reactive Power (Voltage / Power Factor / Q) Set Point change To all ISTS HVDC
HVDC/FACTS as well as Intra-State
Devices test HVDC/FACTS, as
applicable
(1) Reactive Power Controller (RPC) Capability for
HVDC/FACTS
(2) Filter bank adequacy assessment based on present grid
condition, in consultation with NLDC.
(3) Validation of response by FACTS devices as per settings.
41. CAPACITY BUILDING AND CERTIFICATION
Capacity building, skill upgradation, and certification of the personnel deployed in load despatch centres
shall be done periodically under an institutional framework through accredited certifying agency (ies).
CHAPTER 7
SCHEDULING AND DESPATCH CODE
42. INTRODUCTION
This chapter deals with the procedure for scheduling injection and drawal of power by the regional entities
and the modalities for exchange of information, including scheduling for intra-state and cross-border entities
transacting power through the Inter-State Transmission System. This chapter also covers provisions with
respect to control area jurisdiction.
43. CONTROL AREA JURISDICTION OF LOAD DESPATCH CENTER
(1) The national grid shall be demarcated into Regional and State control areas and each control area shall
be under the jurisdiction of RLDC or SLDC, as the case may be.
(2) The RLDCs shall be responsible for optimum scheduling and despatch of electricity, monitoring of real
time grid operations and management of the reserves, including energy storage systems and demand
response within their control area, supervision and control over the inter-state transmission systems,
processing of interface energy meter data and coordinating the accounting and settlement of regional
pool account.
(3) The SLDCs shall be responsible for optimum scheduling and despatch of electricity, monitoring of real
time grid operations and management of the reserves including energy storage systems and demand
response within its State control area, supervision and control over the intra-State transmission system,
processing of interface energy meter data and coordinating the accounting and the settlement of State
pool account, as may be specified by the appropriate State Commission.
(4) The entities connected exclusively to the inter-State transmission system shall be under the control area
jurisdiction of RLDCs for scheduling and despatch of electricity for such entities.
(5) The entities connected exclusively to the intra-State transmission systems shall be under the control area
jurisdiction of SLDCs for scheduling and despatch of electricity.
(6) Entities connected to both inter-State transmission systems and intra-State transmission systems shall be
under the control area jurisdiction of RLDC, if more than or equal to 50% of the quantum of connectivity
is with ISTS, and if more than 50% of the quantum of connectivity is with intra-State transmission
system, it shall be under the control area jurisdiction of SLDC.
(7) In case an entity is connected to both inter-State transmission systems and intra-State transmission
systems, the load despatch centre responsible for scheduling such entities shall coordinate with the
concerned RLDC or SLDC, as the case may be, for ensuring grid security.
(8) Unless otherwise decided by the Commission, the entities that have already declared COD as on the date
of coming into force of these regulations, shall continue to remain under the control area of the SLDC or
the RLDC, as the case may be, as existing before the date of coming into force of these regulations:
Provided that the control area jurisdiction of generating stations of DVC that have already achieved
COD as on coming into force of these regulations shall be as per Clause (9) of this regulation.
(9) Control Area jurisdiction of the generating station of DVC and other entities connected to the DVC
system
(i) The control area of the generating stations of DVC which are connected to the transmission
lines of inter-State transmission licensees including those owned and operated by DVC which
are included in monthly transmission charges under the Sharing Regulations shall be under
control area jurisdiction of RLDC;
(ii) The control area of the generating stations which are exclusively connected to the transmission
system owned and controlled by DVC but are not included in monthly transmission charges
under Sharing Regulations shall be under control area jurisdiction of DVC LDC;
(iii) The control area of the generating stations which are connected to transmission system covered
under both sub-clause (i) and (ii), shall be within the jurisdiction of RLDC if more than or equal
to 50% of the quantum of connectivity is with transmission system covered under sub-clause (i)
of this clause and in other cases will be under the control area of jurisdiction of DVC LDC.
(iv) The control area of entities other than generating stations connected to the DVC system shall be
governed in terms of sub-clauses (i) to (iii) of this clause.
(10) Notwithstanding anything contained in clauses (1) to (8) of this Regulation, the Commission may, on its
own motion or on the application made by a grid connected entity, grant approval for a change in the
control area jurisdiction of such an entity.
44. RESPONSIBILITIES OF LOAD DESPATCH CENTRES
(1) The Regional Load Despatch Centre, in discharge of its functions under the Act, shall be responsible for
the following, within its regional control area:
(a) Forecasting of demand based on the inputs from SLDCs (under clause 2 of Regulation 31 of these
regulations) and other regional entities for each time block on a day-ahead and intraday basis.
(b) Forecasting of generation from wind and solar generating stations, which are regional entities, for
each time block on day-ahead and intraday basis:
Provided that such forecasts may be used by the wind and solar generating stations at their own risk
and discretion, along with all commercial liabilities arising out of them. .
(c) Scheduling of electricity within the region which includes:
(i) Injection and drawal schedules for regional entities, cross-border entities, in accordance with
the contracts;
(ii) Incorporation of schedules for regional entities under collective transactions;
(iii) Incorporation of schedules under the Ancillary Services Regulations.
(iv) optimisation of scheduling inter-alia through Security Constrained Economic Despatch
(SCED);
(d) Secure operation of the grid by:
(i) Balancing demand and supply to minimize Area Control Error (ACE);
(ii) Maintaining and despatching reserves in accordance with these regulations and Ancillary
Services Regulations.
(e) Assessment of transmission capability for inter-State transmission system for secure operation of the
grid including but not limited to:
(i) Assessment of TTC and ATC for inter-regional, intra-regional and inter-State levels for its
region and submit it to the NLDC.
(ii) Assessment of TTC and ATC for import or export of electricity for a State in coordination
with the concerned SLDC and submit to NLDC.
(iii) Assessment of TTC and ATC shall be done on a continuous basis at least three(3) months in
advance and revised based on contingencies from time to time.
(f) Publication of TTC and ATC, as finalised by NLDC, with all the assumptions and constraints on its
website.
(g) Running a Security Constraint Unit Commitment (SCUC) for regional entity generating stations.
(2) The National Load Despatch Centre, in discharge of its functions under the Act, shall be responsible for
the following:
(a) Optimum scheduling and despatch of electricity over inter-regional links amongst Regional Load
Despatch Centres;
(b) Coordination with Regional Load Despatch Centres for the energy accounting of inter-regional
exchange of power;
(c) Coordination and scheduling of cross-border exchange of power;
(d) Coordination of the set-points of all HVDCs within the country and cross-border HVDC
interconnections;
(e) Finalising the TTC and ATC with all assumptions and limitations based on inputs received from
RLDCs and publishing the same on its website, at least three (3) months in advance, and revising
them based on contingencies from time to time.
(f) Finalising SCED and SCUC through RLDCs, and publishing the same on its website;
(g) Furnishing availability of transmission corridors to the Power Exchange(s) for day ahead and real
time collective transactions and, in case of congestion, allocating available transmission corridors
among the Power Exchange(s) in the ratio of initial unconstrained market clearing volume in the
respective Power Exchange(s) or as specified by the Commission from time to time.
(3) The State Load Despatch Centre in discharge of its functions under the Act and for stable, smooth and
secure operation of the integrated grid, shall be responsible for the following in its control area:
(a) Forecasting demand for its control area under clause 2 of Regulation 31 of these regulations for each
time block on day-ahead and intra-day basis;
(b) Forecasting of generation from wind and solar generating stations under its jurisdiction for each
time block on day-ahead and intra-day basis:
Provided that such forecasts may be used by the wind and solar generating stations at their own risk
and discretion along with all commercial liabilities arising out of it;
(c) Scheduling and despatch for the entities in the State control area in accordance with contracts;
(d) Balancing demand and supply to minimize Area Control Error (ACE) for the State;
(e) Maintaining and despatching reserves.
(f) Declaring Total Transfer Capability and Available Transfer Capability in respect of import and
export of electricity of its control area with inter-State transmission systems in coordination with the
Central Transmission Utility, State Transmission Utility, and concerned RLDC and revising the
same from time to time based on grid conditions. Assessment of TTC and ATC shall be done on a
continuous basis at least three (3) months in advance and revised based on contingencies from time
to time.
(4) Damodar Valley Corporation shall carry out the responsibilities in their respective control area, in
accordance with clause 3 of this Regulation, for the stable, smooth, and secure operation of the
integrated grid.
(5) Bhakra Beas Management Board and Narmada Control Authority shall coordinate with the concerned
RLDC for scheduling and despatch of their generating stations.
(6) Settlement Nodal Agency shall coordinate with the concerned RLDC and NLDC for scheduling,
despatch, and settlement for its control area.
45. GENERAL PROVISIONS
(1) Details of regional entity generating stations to be published by RLDC
(a) RLDCs shall publish a list of all regional entity generating stations within their control area, which
shall be updated quarterly on their website along with details such as station capacity, allocated
share of beneficiaries, contracted quantum by buyers, and balance available capacity.
(b) RLDCs shall also publish details, as applicable, for regional entity generating stations other than
renewable generating stations, as submitted by such generating stations in accordance with
Regulation 20 of these regulations.
(c) RLDC shall publish the details, as applicable, for all regional entity renewable generating stations as
submitted by such generating stations in accordance with Annexure-6.
(2) The regional entity generating stations and the entities participating in Ancillary Services must be
capable of receiving the load set point signals from the RLDCs or the NLDC as per CEA Technical
Standards for Connectivity, or in terms of Ancillary Service Regulations, as applicable.
(3) List of Drawee Regional Entities:
RLDCs shall update on a quarterly basis the list of all drawee regional entities within their respective
control area and post the same on their websites along with the allocated or contracted quantum from all
entities, excluding the intra-State entities within their control area.
(4) Entitlement of a buyer and beneficiary:
(a) In cases of allocation of power from a central generating station by the Central Government, each
beneficiary shall be entitled to MW despatch out of the declared capacity of such a generating
station, in proportion to its share allocation.
(b) For all other cases not covered under sub-clause (a) of this Clause, the buyer shall be entitled to MW
despatch out of the declared capacity of regional entity generating station as per its contracts.
(c) The entitlement from the regional entity generating station shall be rounded off up to two (2)
decimal points for the purposes of scheduling and accounting.
(5) Requirement for Commencement of Scheduling:
(a) The following documents shall be submitted to the respective RLDC by the seller or the buyer, as
the case may be, before commencement of the scheduling of transactions under GNA or T-GNA, as
the case may be:
(i) Document in support of the grant of GNA or Connectivity, by the sellers and the buyers, as
applicable;
(ii) Document in support of the effective date of GNA by the sellers and the buyers
(iii) Request for consideration under Regulation 22.4 of the GNA Regulations, if applicable.
(iv) Grant of T-GNA with an effective date, by the buyers;
(v) Declaration by the sellers and the buyers about the existence of valid contracts for the
transactions.
(vi) Copies of the valid contracts signed by the sellers and the buyers, for transactions other than
collective transactions.
(b) In case of allocation of power from the central generating stations by the Central Government, the
concerned RLDC shall obtain the share allocation of each beneficiary issued by RPC.
(c) The copy of contracts once submitted by sellers and buyers need not be submitted again before
every scheduling request and the copy of the contract can be linked with a unique ID by RLDC for
reference before scheduling request:
Provided that in case of any change in terms of the contract or termination of contract, the seller as
well as the buyer shall inform the same, along with a copy of the modified contract, as applicable,
within a day, to the respective RLDC
(6) Adherence to Schedule:
Each regional entity shall regulate its generation or demand or both, as the case may be, so as to adhere
to the schedule of net injection into or net drawal from the inter-State transmission system.
(7) Area Control Error:
The concerned Load Despatch Centre and other drawee regional entities shall keep their Area Control
Error close to zero (0) by rescheduling, deploying reserves and automatic demand management scheme.
(8) Declaration of Declared Capacity by Regional entity generating stations
(a) The regional entity generating station other than the WS seller shall declare ex-bus Declared
Capacity limited to 100% MCR less auxiliary power consumption, on day ahead basis as per the
provisions of Regulation 49 of these regulations:
Provided that the hydro generating stations may declare ex-bus Declared Capacity more than 100%
MCR less auxiliary power consumption limited to overload capability in terms of sub-clause (a) of
clause (10) of this Regulation during high inflow periods:
Provide further that a high inflow period for this purpose shall be notified by the respective RPC.
(b) Regional entity WS Seller shall declare the available capacity on day ahead basis, as per the
provisions of Regulations 49 of these regulations. The regional entity with generating stations other
than WS sellers may be required to demonstrate the declared capacity of their generating stations as
and when directed by the concerned RLDC. For this purpose, RLDC, in coordination with SLDC
and the beneficiaries, shall schedule the regional entity generating station up to its declared capacity
as declared on day ahead basis.
(c) The schedule issued by the RLDC shall be binding on the beneficiaries for such testing of the
declared capacity of the regional entity generating station. In case the generating station fails to
demonstrate the declared capacity, it shall be treated as a mis-declaration for which charges shall be
levied on the generating station by RPC as follows:
The charges for the first mis-declaration for a block or multiple blocks in a day shall be the charges
corresponding to two days fixed charges at normative availability. For the second mis-declaration,
the charges shall correspond to four days fixed charges at normative availability, and for
subsequent mis-declarations, the charges shall increase in a geometric progression over a period of a
month.
(9) Ramping Rate to be Declared for Scheduling:
(a) The regional entity generating station shall declare the ramping rate along with the declaration of
day-ahead declared capacity in the following manner, which shall be accounted for in the
preparation of generation schedules:
(i) Coal or lignite fired plants shall declare a ramp up or ramp down rate of not less than 1% of ex-
bus capacity corresponding to MCR on bar per minute;
(ii) Gas power plants shall declare a ramp up or ramp down rate of not less than 3% of ex-bus
capacity corresponding to MCR on bar per minute;
(iii) Hydro power plants shall declare a ramp up or ramp down rate of not less than 10% of ex-bus
capacity corresponding to MCR on bar per minute;
(iv) Renewable Energy generating stations shall declare a ramp up or ramp down rate as per CEA
Connectivity Standards.
(10) Optimum Utilization of Hydro Energy:
(a) During high inflow and water spillage conditions, for Storage type generating station and Run-of-
River Generating Stations with or without Pondage, the declared capacity for the day may be up to
the installed capacity plus overload capability (up to 10% or such other limit as certified by the
OEM and approved by CEA) minus auxiliary consumption, corrected for the reservoir level. In case,
the overload capability of such a station is more than 10% as approved, such a station shall declare
the overload capability in advance.
(b) During high inflow and water spillage conditions, the concerned RLDC shall allow scheduling of
power from hydro generating stations for overload capability up to 10% of Installed Capacity or any
other limit as per sub-clause (a) of this clause without the requirement of additional GNA for such
overload capacity, subject to the availability of margins in the transmission system.
(11) Scheduling of WS seller and ESS by QCA:
(a) The regional entity renewable energy generating station(s) or Projects based on energy storage
system(s) connected at a particular ISTS substation or at multiple ISTS substations located in a
State may appoint a QCA on their behalf to coordinate and facilitate scheduling for such
generating stations or energy storage system(s). The responsibility of QCA is listed at Annexure-6
to these regulations.
(b) NLDC shall submit a procedure for aggregation of pooling stations for the purpose of combined
scheduling and deviation settlement for wind or solar or renewable hybrid generating stations that
are regional entities, within six (6) months of notification of these regulations for approval of the
Commission.
(c) The QCA shall be registered with the concerned RLDC.
(d) QCA registered with the concerned RLDC shall, on behalf of wind, solar or renewable hybrid
generating stations or Energy Storage System shall:
(i) Coordinate and facilitate scheduling of power with the concerned RLDC; and;
(ii) Undertake commercial settlement of deviations with the concerned RLDC in accordance with
the DSM Regulations.
(iii) Submit a copy of the consent to the concerned RLDC certifying that QCA shall undertake all
operational and commercial responsibilities on behalf of generating stations as per the CERC
Regulations.
(e) The concerned wind, solar or renewable hybrid generating stations including energy storage
systems shall indemnify the RLDC for any act of commission or omission on the part of QCA
including compliance with the Grid Code and settlement of its financial liability in the pooled
account.
(f) Contract between the generating stations and QCA shall invariably contain provisions for internal
dispute resolution, and any disputes arising between the generating stations and QCA shall be
settled in accordance with the said mechanism.
(12) Minimum turndown level for regional entity thermal generating stations:
The minimum turndown level for operation in respect of a unit of a regional entity thermal generating
station shall be 55% of the MCR of the said unit or such other minimum power level as specified in the
CEA (Flexible Operation of coal based Thermal Generating Units) Regulations, 2023, as amended from
time to time, whichever is lower:
Provided that the Commission may fix through an order a different minimum turndown level of
operation in respect of specific unit(s) of a regional entity thermal generating station:
Provided further that such generating station on its own option may declare a minimum turndown level
below the minimum turndown level specified in this clause:
Provided also that the regional entity thermal generating stations whose tariffs are determined under
Section 62 or Section 63 of the Act, shall be compensated for part load operation, that is, for generation
below the normative level of operation, in terms of the provisions of the contract entered into by such
generating stations with the beneficiaries or buyers, or in the absence of such provision in the contract,
as per the mechanism to be specified by the Commission through separate regulations or through Order:
Provided also that till the mechanism of part load compensation is notified by the Commission, the
mechanism in this regard already in force under the Central Electricity Regulatory Commission (Indian
Electricity Grid Code) Regulations, 2010 shall continue to be in operation.
(13) Scheduling of Inter-Regional and Cross-Border Transactions
(a) NLDC shall prepare a schedule for cross-border exchange of power, which shall be on a net of the
country basis;
(b) NLDC shall coordinate scheduling and despatch of electricity over inter-regional links with
concerned RLDCs.
(14) A generating station or ESS or a drawee entity shall be allowed to schedule injection or drawal only up
to its effective GNA quantum and T-GNA quantum, as applicable, in accordance with the GNA
Regulations.
(15) For meeting its power requirements during non-generation hours, whether before or after COD, a
generating station, including renewable energy generating station, shall enter into a valid contract with
a seller or distribution licensee or through power exchange:
Provided that where the generating station including a renewable energy generating station is unable to
enter into a contract for the drawal of power during non-generation hours, it may draw power from
ISTS on payment of deviation charges as per the DSM Regulations.
46. SECURITY CONSTRAINED UNIT COMMITMENT (SCUC)
(1) The objective of Security Constrained Unit Commitment (SCUC) is to commit a generating station or unit
thereof, for the maximisation of reserves in the interest of grid security, without altering the entitlements and
schedule of the buyers of the said generating station in the day ahead time horizon.
(2) Reserves shall be procured and deployed in accordance with the Ancillary Services Regulations, and SCUC
shall supplement such procurement of reserves under certain conditions, as specified in this Regulation.
(3) SCUC shall be undertaken if the NLDC, in coordination with RLDCs and based on an assessment of the
power system condition, anticipates that there is likely to be a shortage of reserves despite efforts made to
procure such reserves in accordance with the Ancillary Services Regulations.
(4) The SCUC may be undertaken on day ahead basis, in respect of the regional entity generating stations or
units thereof, for which tariffs are determined under section 62 of the Act, as per the following process:
(a) By 1400 Hrs of D-1 day, ,,D being the day of delivery, NLDC in coordination with RLDCs shall
publish a tentative list of generating stations or units thereof, which are likely to be scheduled below
the minimum turndown level of the respective stations for some or all the time blocks of the D day,
based on beneficiary requisitions and initial unconstrained bid results of DAM in the power
exchanges, received till 1300 Hrs of the D-1 day.
(b) Beneficiaries of such stations, whose units are likely to be scheduled below minimum turndown level
for some or all time blocks of the D day, shall be permitted to revise their requisitions from such
stations by 1430 Hrs of D-1 day, in order to enable such units to be on bar. The revised requisition
from the said generating stations, once confirmed by the beneficiaries by 1430 Hrs of D-1 day, shall
be final and binding after 1430 Hrs of D-1 day and further reduction in drawal schedule shall not be
allowed from such stations except in cases when the generating stations remain above minimum turn-
down level.
(c) After 1430 Hrs, the NLDC in coordination with RLDCs shall prepare the final list of such generating
units that are likely to go below their minimum turndown level and such generating units shall be
stacked as per merit order, that is, in the order of the lowest energy charge to the highest energy
charge. The generating units so identified shall be considered for undertaking SCUC.
(d) If the NLDC in coordination with the RLDCs, after considering the bid results as finalized and
available from DAM-AS, anticipates shortfall of reserves in D day due to (i) extreme variation in
weather conditions; (ii) high load forecast; (iii) the requirement of maintaining reserves on regional
or all India basis for grid security; (iv) network congestion, NLDC may schedule incremental energy
from the generating units in the list referred to in sub-clause (c) of this clause , so as to bring such
units to their minimum turndown level in order to maximize availability of on-bar units, by 1500
Hrs. of D-1 day and update the list on the respective RLDC website:
Provided that in respect of such generating station or unit thereof which has been brought to its
minimum turndown level by the NLDC under this clause, downward revision by the beneficiary shall
not be allowed.
(e) The NLDC shall indicate the quantum of URS power to be kept as reserves, in the generation station
or unit thereof brought under SCUC, and such quantum of power identified as reserves shall not be
available for scheduling by the beneficiary or for sale by the generating station through the energy
market. The quantum of power over and above the identified quantum of reserves may be
rescheduled by the beneficiary(ies) or scheduled by way of selling in the market.
(f) In order to maintain load generation balance consequent to scheduling of incremental generation as
per sub-clause (d) of this clause, the NLDC in coordination with RLDCs, shall make commensurate
reduction in generation from the on-bar generating station(s), subject to technical constraints, starting
with the highest energy charge and SCED compensation charge in the stack of generating stations
maintained for the purpose of SCED in accordance with these regulations.
(g) The generating station from which incremental energy has been scheduled as per sub-clause (d) of
this clause shall be paid from the Deviation and Ancillary Services Pool Account, for the energy
charge equivalent to the incremental energy scheduled, and the generating station from which
reduction in generation has been directed as per sub-clause (f) of this clause shall pay back to the
Deviation and Ancillary Services Pool Account, the energy charge equivalent to the decremental
energy. Compensation for part load operation of a generating station or unit thereof brought on bar
under SCUC shall be paid from the Deviation and Ancillary Services Pool Account.
(h) The URS power over and above the minimum turn down level, available after declaration of RTM
results, in the generating station or unit thereof, brought on-bar under sub-clause (d) of this clause
shall be deemed to be available for use as SRAS or TRAS or both in terms of the Ancillary Services
Regulations
(i) All the generating stations identified under SCUC shall be available on bar, and in the event of such
stations or units thereof being on Unit Shut Down (USD), the time to start a unit under different
conditions such as HOT, WARM and COLD and minimum time for which it shall be brought on bar,
shall be as specified in the Detailed Procedure to be prepared by NLDC and approved the
Commission.
(j) The generating stations other than those whose tariffs are determined under Section 62 of the Act
may opt to participate in SCUC as per the Detailed Procedure to be prepared by NLDC and approved
by the Commission.
(5) SCUC three days in advance under certain circumstances:
(a) In case NLDC anticipates based on assessment that adequate reserves may not be available on D-1
Day or D-day either under day ahead SCUC or under Ancillary Services Regulations, it may also
carry out SCUC three (3) days in advance of the actual day of scheduling for the regional entity
generating stations. NLDC, through RLDC shall advise the regional entity generating station or
unit(s) thereof to commit the unit by 1000 Hrs of D-2 day under cold start condition. The criteria for
assessment of adequacy or inadequacy of reserves and identification of the generating stations or
units thereof for SCUC three days in advance, shall be stipulated in the Detailed Procedure by NLDC
after obtaining approval of the Commission.
(b) NLDC shall announce the requirement of SCUC three days in advance on its website by specified
time on "D-3 " day as per the Detailed Procedure.
(c) All regional entity generating stations shall declare DC for ,,D day within 2 hours of announcement
by NLDC, for consideration under three-day ahead SCUC.
(d) The results of SCUC along with time to commit unit (s) on bar shall be informed by NLDC to
RLDCs for onward information to the generating stations. RLDC shall ensure that intimation is sent
to the generating station sufficiently in advance keeping in view its start-up time.
(e) The generating stations shall bring unit (s) accordingly.
(f) The generating stations or units committed through such SCUC shall be provided the schedule
above or up to minimum turn down level. Corresponding schedule for drawal shall be adjusted
against requisition from the beneficiaries and the balance through security constrained economic
dispatch (SCED) on the D day.
(g) The provisions of sub-clauses (e) to (j) of clause (4) of this Regulation shall also apply for the
generating stations or units thereof committed under SCUC three days in advance.
47. UNIT SHUT DOWN (USD)
(1) The generating stations or units thereof, identified by NLDC in co-ordination with RLDCs, as per sub-
clause (c ) of clause (4) of Regulation 46 of these regulations, but not brought on bar under SCUC, shall
have the option to operate at a level below the minimum turn down level or to go under Unit Shut Down
(USD).
(2) In case a generating station, or unit thereof, opts to go under unit shut down (USD), the generating company
owning such generating station or unit thereof shall fulfil its obligation to supply electricity to its
beneficiaries who had made requisition from the said generating station prior to it going under USD, by
arranging supply either (a) by entering into a contract(s) covered under the Power Market Regulation; or (b)
by arranging supply from any other generating station or unit thereof owned by such generating company
subject to honouring of rights of the original beneficiaries of the said generating station or unit thereof from
which supply is arranged; or (c) through SCED subject to the stipulation under sub-clause (a)(vi) of clause
(2) of Regulation 49 of these regulations, the details of which shall be provided in the Detailed Procedure to
be specified by NLDC in this regard.
(3) In case of emergency conditions, for reasons of grid security, a generating station or unit thereof, which is
under USD may be directed by NLDC to come on bar, and in such event the generating station or unit
thereof shall come on bar under hot, warm and cold conditions as per the time period to be specified in the
detailed procedure under sub-clause (i) of clause (4) of Regulation 46 of these regulations.
(4) Once a generating station is brought on bar as per clause (3) of this Regulation, it shall be treated as a unit
under SCUC and scheduled and compensated as per Regulation 46 of these regulations.
48. SCHEDULING FROM ALTERNATE SOURCE OF POWER BY A GENERATING STATION
(1) A generating station may supply power from alternate source in case of (i) USD in terms of clause (1) of
Regulation 47 of these regulations or (ii) forced outage of unit(s) or (iii) a generating station other than REGS
replacing its scheduled generation by power supplied from REGS irrespective of whether such identified
sources are located within or outside the premises of the generating station or at a different location.
(2) The methodology for scheduling of power from alternate sources covered under sub -clauses (i) and (ii) of
clause (1) of this regulation shall be as per the following steps:
(a) The generating station may enter into contract with alternate supplier under bilateral transaction or
collective transaction.
(b) In case of bilateral transaction, the generating station shall request RLDC to schedule power from
such alternate supplier to its beneficiaries which shall become effective from 7th or 8th time blocks,
as the case may be, in terms of clause (4) of Regulation 49 of these regulations.
(c) The power scheduled from alternate supplier shall be reduced from the schedule of the generating
station.
(d) In case of alternate supply is arranged through collective transactions, the transacted quantum shall
be reduced from the scheduled generation of the generating station.
(e) The generating station may also request the concerned RLDC to arrange alternate supply through
SCED, in accordance with provisions contained under sub-clause (a)(vi) of clause (2) of Regulation
49 of these regulations.
(f) The generating station shall not be required to pay the transmission charges and losses for such
purchase of power to supply to the buyer from alternate sources.
(3) The methodology for scheduling of power from alternate sources covered under sub -clause (iii) of clause (1)
of this regulation, shall be as per the following steps:
(a) The generating station shall enter into contract with REGS for supply of power from alternate
sources.
(b) The generating station shall request RLDC to schedule power from such alternate source to its
beneficiaries which shall become effective from 7th or 8th time blocks, as the case may be, in terms
of clause (4) of Regulation 49 of these regulations.
(c) The power scheduled from alternate source shall be reduced from the schedule of the generating
station.
(d) The generating station shall not be required to pay the transmission charges and losses for such
purchase and supply from alternate sources to the buyer.
(e) In case of a generating station whose tariff is determined by the Commission under Section 62 of the
Act, supply of power by such generating station to its buyer from an alternate source, in terms of
sub-clauses (a) to (d) of this clause, shall be subject to sharing of net savings as specified in the
Tariff Regulations:
Provided that until a provision is made in the Tariff Regulations, sharing of net savings shall be in
accordance with the detailed procedure to be prepared by NLDC and approved by the Commission.
(f) In case of a generating station other than whose tariff is determined by the Commission under
Section 62 of the Act, supply of power by such generating station to its buyer from an alternate
source in terms of sub-clauses (a) to (d) of this clause shall be in accordance with the contract with
the buyer and in the absence of a specific provision in the contract, in terms of mutual consent
including on sharing of net savings between the generating station and the buyer.
49. PROCEDURE FOR SCHEDULING AND DESPATCH FOR INTER-STATE TRANSACTIONS
(1) The following scheduling related activities shall be carried out daily for regional entities, on day ahead basis,
,,D-1 day, for supply of power on ,,D day, as follows:
(a) Declaration of Declared Capacity by generating stations:
(i) The generating station based on coal and lignite shall submit the following information for 0000
hours to 2400 hours of the ,,D day, by 6 AM on ,,D-1 day:
(a) Time block-wise On-bar Declared Capacity (MW) for on-bar units;
(b) Time block-wise Off-bar Declared Capacity (MW) for off-bar units;
(c) Time block-wise Ramp up rate (MW/min) for on-bar capacity;
(d) Time block-wise Ramp down rate (MW/min) for on-bar capacity;
(e) MWh capability for the day;
(f) Minimum turndown level (MW) and in percentage (%) of ex-bus capacity on-bar;
(ii) The generating station based on hydro energy shall submit the following information for 0000
hours to 2400 hours of the ,,D day, by 6 AM on ,,D-1 day:
(a) Time block-wise ex-bus declared capacity;
(b) MWh capability for the day;
(c) Ex-bus peaking capability in MW and MWh;
(d) Time block-wise Ramp up rate (MW/min) for on-bar capacity;
(e) Time block-wise Ramp down rate (MW/min) for on-bar capacity;
(f) Unit-wise forbidden zones in MW and percentage (%) of ex-bus installed capacity;
(g) Minimum MW and duration corresponding to requirement of water release for
irrigation, drinking water and other considerations.
(h) Unit wise maximum MW along with probable combination of unit maximum in case
adequate water is not available.
(iii) The generating station based on gas or combined cycle generating station shall submit the
following for 0000 hours to 2400 hours of the ,,D day, by 6 AM on ,,D-1 day:
(a) Time block-wise On-bar Declared Capacity (DC) for the station in MW separately for each
fuel such as domestic gas, RLNG or liquid fuel and On-bar units;
(b) Time block wise Off-bar Declared Capacity (MW) and off-bar units;
(c) MWh capability (fuel-wise) for the next day;
(d) Time block wise Ramp up rate (MW/min) for on-bar capacity;
(e) Time block wise Ramp down rate (MW/min) for on-bar capacity;
(f) Minimum turndown level (MW) and in percentage (%) of ex-bus capacity on-bar.
(iv) The regional entity renewable energy generating station, individually or represented by a lead
generator or QCA, shall submit aggregate available capacity of the pooled generation and
aggregate schedule along with contract-wise breakup for each time block for 0000 hours to 2400
hours of the ,,D day, by 6 AM on ,,D-1 day. The source wise breakup of aggregate available
capacity of the pooled generation shall also be furnished.
(v) ESS including pumped storage plant, individually or represented by the lead ESS or QCA on their
behalf, shall submit aggregate available capacity of the pooled generation and aggregate schedule
along with contract-wise breakup for each time-block for 0000 hours to 2400 hours of the ,,D day,
by 6 AM on ,,D-1 day.
(vi) The availability declaration by regional entity generating station shall have a resolution of two
decimal (0.01) MW and three decimal (0.001) MWh.
(b) Entitlement of each beneficiary or buyer:
(i) For generating station, where the Central Government has allocated power, each State shall be
entitled to a MW despatch up to the States Share in the stations declared capacity (including On-
bar Declared Capacity and Off-bar Declared Capacity) for the day. Accordingly, based on
declared capacity of such generating station, RLDC shall declare entitled share of each
beneficiary or buyer for 0000 hours to 2400 hours of the ,,D day, by 7 AM on ,,D-1 day.
(ii) The generating station other than those having allocation of power by the Central Government
shall indicate the declared capacity along with respective share of the beneficiary(ies) or buyers in
accordance with the contracts entered with them. Based on the declared capacity of such
generating station and share of the beneficiaries or buyers as indicated by such generating station,
RLDC shall declare share of each beneficiary or buyer for 0000 hours to 2400 hours of the ,,D
day, by 7 AM on ,,D-1 day.
(c) The mutually agreed requisition for scheduling of intra-State entities shall be as submitted by the
regional entity buyers or regional entity sellers in accordance with the contracts entered between them by
7 AM on ,,D-1 day.
(d) The requisition for cross-border schedule along with its breakup from various sources shall be submitted
by the Settlement Nodal Agency (SNA) for 0000 hours to 2400 hours of the ,,D day, by 8 AM on ,,D-1
day;
(e) Each SLDC shall intimate the quantum of secondary and tertiary reserves in the State control area for the
,,D day by 8 AM of ,,D-1 day.
(f) Requisition of schedule by the buyers which are GNA grantees:
(i) Based on the entitlement declared in accordance with sub-clause (b) of clause (1) of this Regulation,
SLDC on behalf of the intra-State entities which are drawee GNA grantees, shall furnish time block-
wise requisition for drawal to the concerned RLDC in accordance with the contracts, by 8 AM of
,,D-1 day.
(ii) Other drawee GNA grantees which are regional entities shall furnish time block-wise requisition for
drawal to the concerned RLDC in accordance with contracts, by 8 AM of ,,D-1 day.
(iii) The SLDC on behalf of the intra-State entities which are drawee GNA grantees, as well as other
drawee GNA grantees while furnishing time block-wise requisition under this Regulation shall
subject to technical constraints, duly factor in merit order of the generating stations with which it
has entered into contract(s):
Provided that the renewable energy generating stations shall not be subjected to merit order
despatch, and subject to technical constraints shall be requisitioned first followed by requisition
from other generating stations in merit order.
(g) Allocation of corridors by RLDC for GNA grantees
(i) RLDC shall check if drawl schedules as requisitioned by drawee GNA grantees can be allowed
based on available transmission capability:
Provided that in case of constraint in transmission system, the available transmission corridor shall
be allocated to the drawee GNA grantees in proportion to their GNA within the region or from
outside region, depending upon the transmission constraint, whether it is within the region or from
outside the region, as the case may be. The same shall be intimated to drawee GNA grantees by 8.15
AM on ,,D-1 day.
(ii) Drawee GNA grantees shall revise their requisition for drawl schedule based on availability of
transmission corridors for such grantee by 8.30 AM on ,,D-1 day.
(iii) RLDC shall issue final drawl schedules and injection schedules for drawee and injecting GNA
grantees by 9 AM on ,,D-1 day.
(iv) For the purpose of "Use of GNA by other GNA grantees" as specified in the GNA Regulations, the
GNA shared with other entity shall considered as GNA of the new entity.
(h) In case a generating station other than REGS intends to replace its schedule by power supplied from
REGS, it shall intimate the quantum and source of power by which it intends to replace the power
already scheduled under this Regulation by 9.15 am on ,,D-1 day.
(i) RLDC shall incorporate by 9.45 am of ,,D-1 day, the request from such generating station, in the
injection schedule of the REGS and the said generating station, and the drawal schedule of the buyer.
(j) Requisition of schedule by T-GNA grantees
(i) Based on the entitlement or otherwise, SLDC on behalf of intra-State entities which are T-GNA
grantees, shall furnish time block-wise requisition for drawl, to the concerned RLDC in accordance
with contracts by 9.15 AM of ,,D-1 day.
(ii) Other drawee T-GNA grantees who are regional entities, shall furnish time block-wise requisition
for drawl to concerned RLDC in accordance with contracts by 9 AM of ,,D-1 day.
(iii) Allocation of corridors by RLDC for T-GNA grantees: RLDC shall check if drawl schedules as
requisitioned by T-GNA grantees can be granted based on available transmission capability after
allocating corridors to the GNA grantees.
Provided that in case of constraint in transmission system, the available transmission corridor shall
be allocated to the T-GNA grantees in proportion to their T-GNA.
(iv) RLDC shall issue final drawl schedules for T-GNA grantees by 9.45 AM of ,,D-1 day.
(k) RLDC shall release the balance corridors after finalisation of schedules for GNA and T-GNA grantees
for day ahead collective transactions.
(l) The generating station whose tariff is determined under Section 62 of the Act, may sell its un-
requisitioned surplus as available at 9.45 AM in the day ahead market, unless the consent is withheld by
the beneficiary or buyer in writing. The sharing of net savings shall be as per provisions of Tariff
Regulations and until a provision is made in the Tariff Regulations, in accordance with the detailed
procedure to be prepared by NLDC and approved by the Commission.
(m) Scheduling of collective transactions:
(i) Power Exchange(s) shall open bidding window for day ahead collective transactions and TRAS
from 10.00 AM to 11AM of ,,D-1 day.
(ii) The power exchange shall submit the day-ahead provisional trade schedules along with net power
interchange of each bid area and region to NLDC by 11.45 AM of ,,D-1 day.
(iii) NLDC shall validate the same from system security angle and inform the power exchange with
revisions required, if any, due to transmission congestion or any other system constraint by 12.15
PM of ,,D-1 day.
(iv) The power exchange shall submit the final trade schedules to NLDC for regional entities and to
SLDC for intra-State entities by 1.00 PM of ,,D-1 day.
(n) RLDC shall release balance corridors after finalisation of schedules under day ahead collective
transactions by 1.00 PM of ,,D-1 day.
(o) RLDC shall process exigency applications received till 1 PM of ,,D-1 day for the ,,D day by 2 PM of
,,D-1 day.
(p) RLDC shall update the availability of balance transmission corridors, if any, after finalisation of
schedules for exigency applications by 2.00 PM of ,,D-1 day on its website. The balance transmission
corridor may be utilised by GNA grantees by way of revision of schedule, under any contract within its
GNA or for exigency applications or in real time market on first cum first serve basis.
(q) Procedure for scheduling of transaction in Real-time market (RTM):
(i) All the entities participating in the real-time market including TRAS may place their bids and offers
on the Power Exchange(s) for purchase and sale of power.
(ii) The window for trade in real-time market for day (D) shall open from 22.45 hrs to 23.00 hrs of (D-1)
for the delivery of power for the first two time-blocks of 1st hour of day (D) i.e., 00.00 hrs to 00.30
hrs, and will be repeated every half an hour thereafter.
(iii) NLDC shall indicate to the Power Exchange(s) the available margin on each of the transmission
corridors before the gate closure.
(iv) The power exchanges shall clear the real-time bids from 23.00 hrs till 23.15 hrs of ,,D-1 day based
on the available transmission corridor and the buy and sell bids for the real time market (RTM) for
the specified duration and intimate the cleared bids to NLDC by 23.15 hrs, for scheduling.
(r) NLDC shall finalise schedules under RTM, SCED and Ancillary Services by 23.30 hrs. of ,,D-1 day
and RLDC shall publish the final schedules for dispatch by 23.35 hrs. of ,,D-1day.
(s) TRAS shall be procured in accordance with Ancillary services Regulations along with bidding for
collective transactions, RTM or any other mechanism as per these regulations or Ancillary services
Regulations.
(t) Issuance of day-ahead schedule:
RLDC shall convey the following for the next day to all regional and other entities involved in inter-state
transactions after each step of finalisation of schedules for GNA grantees and T-GNA grantees:
(i) The ex-power plant schedule to each of the regional entity generating station, in MW for different
time blocks along with breakup of schedule for each beneficiary or buyer.
(ii) The "net drawal schedule" for each regional entity in MW for each time block, along with break-
up of (a) schedule from each of the sellers, (b) schedule of injection to ISTS and (c) injection or
drawal schedule under collective transaction
(iii) All requisitions and schedules shall be rounded off to the nearest two decimals at each control
area boundary for each of the transaction and shall have a resolution of 0.01 MW.
(u) Issue of schedules by SLDC:
(i) SLDCs shall take into account the schedule released by the concerned RLDC for their intra-State
entities and finalise the intra-State schedule.
(ii) Power Exchange(s) shall furnish the detailed break up of each point of injection and each point of
drawal within each State to respective SLDCs after receipt of acceptance from NLDC. Power
Exchange(s) shall ensure necessary coordination with SLDCs for scheduling of the transactions.
(2) Additional factors to be considered while finalising schedule
(a) Security Constrained Economic Despatch (SCED)
(i) The objective of Security Constrained Economic Despatch (SCED) is to optimise generation
despatch after gate closure in the real time market and after finalisation of schedules under
RTM, by incrementing generation from the generating stations with cheaper charge and
decrementing commensurate generation from the generating station with higher charge, after
considering the operational and technical constraints of generation and transmission facilities.
(ii) NLDC shall be the nodal agency for implementing Security Constrained Economic Despatch
(SCED) through RLDCs for the generating stations connected to inter-State transmission
system which are willing to participate under SCED.
(iii) The generating stations which are willing to participate in SCED shall declare the energy
charge, or the SCED Compensation Charge (after factoring in the likely changes in fuel cost
and part load compensation, if any), as applicable, to NLDC on weekly basis.
(iv) NLDC shall prepare a consolidated stack of URS available in such generating stations from the
lowest energy charge and SCED Compensation Charge to the highest energy charge and SCED
Compensation Charge in each time block. After gate closure in the real time market, the
generating stations so identified shall be instructed and despatched for SCED Up in the order of
the lowest charge and to the highest charge, after taking into account ramp up or ramp down
rate, response time, transmission congestion and such other parameters as stipulated in the
Detailed Procedure. Corresponding to the incremental generation under SCED Up, instruction
and despatch for SCED Down shall be given to the generating stations in the order of the
highest charge to the lowest charge, subject to ramp up or ramp down rate, response time,
transmission congestion and such other parameters as stipulated in the Detailed Procedure.
(v) Part load compensation for reduction in schedule on account of SCED, in respect of a
generating station or unit thereof whose tariff is determined under Section 62 of the Act shall be
paid from the savings in the SCED Account. Part load compensation for reduction in schedule
of a generating station or unit thereof other than those whose tariffs are determined under
Section 62 of the Act shall be factored in by such generating station while declaring the SCED
Compensation Charge and shall not be paid separately.
(vi) Arrangement of power by a regional entity generating station participating in SCED to meet
schedules below minimum turndown level:
a. In case a regional entity generating station gets schedule below minimum turndown
level and wishes to arrange power scheduled by its buyers through SCED, it shall
submit consent to NLDC before gate closure for arranging the scheduled power for such
generating station through SCED.
b. NLDC shall consider the drawal schedules in respect of such generating station, under
SCED subject to availability of scope of optimisation, that is, if the energy charge or
SCED Compensation Charge, as applicable, of such generating station is higher than
that of the marginal generating station in the stack prepared under and after completion
of step at sub-clause (iv) of this clause, and also subject to the condition the entire
drawal schedule against such generating station can be accommodated under SCED.
c. The settlement of energy charge and SCED Compensation Charges shall be in
accordance with sub-clauses (viii) to (x) of this clause.
(vii) The deviation in respect of such generating stations shall be settled with reference to their
revised schedule. The increment or decrement of generation under SCED shall not form part of
schedule considered under ancillary services for such generating stations.
(viii) The schedule of beneficiaries shall not be changed on account of SCED. Buyers or beneficiaries
shall continue to pay the charges for the scheduled energy directly to the generating station(s)
participating in the SCED.
(ix) NLDC shall open a separate bank account called ,,SCED Account. All payments to and from
the generating station(s) on account of SCED schedules shall flow from and to the said ,,SCED
Account.
(x) For any increment in the generation schedule on account of SCED, the participating generator
shall be paid from the ,,SCED Account at the rate of its energy charge or SCED
Compensation Chargedeclared upfront by the generator. For any decrement in the generation
schedule on account of SCED, the participating generator shall pay to the ,,SCED Account at
the rate of energy charge or SCED Compensation Charge, as applicable.
The net saving to the generating stations shall be shared between the beneficiaries or buyers
and the generating stations as per the detailed Procedure to be prepared by NLDC within two
months of the notification of these regulations after stakeholder consultation and seeking
approval of the Commission.
(xi) In case of reduction in generation under SCED on account of SCUC as per Regulation 46 of
these regulations, the generating station from which reduction in generation has been directed
shall pay back to the Deviation and Ancillary Service Pool Account at the energy charge or
SCED Compensation Charge, as the case may be, equivalent to the decremented energy due to
SCUC. The compensation for such case for a generating station whose tariff is determined
under Section 62 of the Act, shall also be adjusted from Deviation and Ancillary Service Pool
Account.
(b) Margins for primary response:
For the purpose of ensuring primary response, RLDCs and SLDCs, as the case may be, shall not
schedule the generating station or unit(s) thereof beyond ex-bus generation corresponding to 100%
of the Installed capacity of the generating station or unit(s) thereof. The generating station shall not
resort to Valve Wide Open (VWO) operation of units, whether running on full load or part load, and
shall ensure that there is margin available for providing governor action as primary response.
In case of gas or liquid fuel-based units, suitable adjustment in Installed Capacity shall be made by
RLDCs and SLDCs, as the case may be, for scheduling in due consideration the prevailing ambient
conditions of temperature and pressure vis-a-vis site ambient conditions on which installed capacity
of the generating station or unit(s) thereof have been specified:
Provided that the hydro generating stations shall be permitted to schedule ex-bus generation
corresponding to 110% of the installed capacity or any other overload capability as allowed under
sub-clause (a) of clause (10) of Regulation 45 of these regulations, during high inflow periods to
avoid spillage:
(3) Power to revise schedules:
(a) Curtailment of scheduled transactions for grid security:
(A) When for the reason of transmission constraints or in the interest of grid security, it becomes
inevitable to curtail power flow on a transmission corridor, the transactions already scheduled may
be curtailed with immediate effect by the Regional Load Despatch Centre (keeping in view the
transaction which is likely to relieve the threat to grid security) as follows:
(i) Transactions under T-GNA shall be curtailed first followed by transactions under GNA.
(ii) Transactions under T- GNA shall be curtailed in the following order:
(I) Within transactions under T-GNA, bilateral transactions shall be curtailed first followed
by collective transactions under day ahead market followed by collective transactions
under real time market;
(II) Within bilateral transactions under T-GNA, curtailment shall be done first from
generation sources other than wind, solar, wind-solar hybrid and run of the river hydro
plants with up to three hours pondage (in case of excess water leading to spillage), pro
rata based on their T-GNA quantum;
(III) The generation from wind, solar, wind-solar hybrid and run of the river hydro plants
with up to three hours pondage (in case of excess water leading to spillage) shall be
curtailed pro rata based on T-GNA, after curtailment of generation from other sources,
within T-GNA.
(IV) Collective transactions under day ahead market shall be curtailed after curtailment of
bilateral transactions under T-GNA.
(V) Collective transactions under real time market shall be curtailed after curtailment of
collective transactions under day ahead market.
(iii) Transactions under GNA shall be curtailed in the following order:
(I) Within transactions under GNA, curtailment shall be done first from generation sources
other than wind, solar, wind-solar hybrid and run of the river hydro plants with up to
three hours pondage (in case of excess water leading to spillage), on pro rata basis based
on their GNA quantum.
(II) The generation from wind, solar, wind-solar hybrid and run of the river hydro plants with
up to three hours pondage (in case of excess water leading to spillage) shall be curtailed
pro rata based on their GNA quantum, after curtailment of generation from other sources,
within GNA.
(iv) RLDC or SLDC, as the case may be, shall publish a report of such incidents on its website.
(B) NLDC shall publish, from time to time on its website, the operational limits of parameters for
maintenance of grid security for the information and compliance of users of the grid. The
curtailment of schedule shall be carried out only in case violation of the operational limits.
(b) In the event of bottleneck in evacuation of power due to outage, failure or limitation in the transmission
system or any other constraint necessitating reduction in generation, the RLDC shall revise the schedules:
Provided that generation and drawal schedules revised by the Regional Load Despatch Centre shall become
effective from 7th block or 8th block depending on time block in which schedule has been revised as first
time block.
(c) In case of contingencies such as critical loading of lines, transformers, abnormal voltages or threat to
system security, the following steps as considered necessary, may be taken by RLDC:
(i) Issue directions to concerned entities to adhere to the schedules;
(ii) Deployment of ancillary services;
(iii) Switching on/off pump storage plants operating in pumping mode;
(iv) Despatching emergency demand response measures;
(v) Direct the SLDCs or other regional entities to increase or decrease their drawal or
injection by revising their schedules and such directions shall be immediately acted upon.
(d) Whenever RLDC revises final schedules due to reasons of grid security or contingency, brief reasons
shall be informed immediately to the concerned entity followed by a detailed explanation to be
posted on RLDC website within 24 hours.
(e) Any verbal directions by RLDC shall be confirmed in writing as soon as possible latest within
twenty four hours.
(4) Revision of schedules on request of buyers which are GNA grantees:
(a) SLDCs on behalf of intra-state entities, regional entity ESSs as drawee entities, beneficiaries,
regional entity buyers or cross-border buying entities may revise their schedules under GNA as per
sub-clauses (b) and (c) of this clause in accordance with their respective contracts:
Provided that scheduled transactions under T-GNA once scheduled cannot be revised other than in
case of forced outage as per clause (7) of this Regulation.
(b) The request for revision of scheduled transaction for ,,D day, shall be allowed subject to the
following:
(i) Request of buyers for upward revision of schedule from the generating station whose tariff
is determined under Section 62 of the Act shall be allowed starting 2 PM on ,,D-1 day,
only in respect of the remaining available quantum of un-requisitioned surplus in such
generating stations, after finalization of schedules under day ahead market.
(ii) Request of buyers for downward revision of schedule from the generating stations, whose
tariff is determined under Section 62 of the Act shall be allowed in any time block subject
to the provision relating to SCUC under Regulation 46 of these regulations.
(iii) Request of buyers for upward or downward revision of schedule in respect of the
generating stations other than those whose tariff is determined under Section 62 of the Act,
shall be allowed in terms of provisions of the respective contracts between the generating
stations and beneficiaries or buyers.
(c) Based on the request for revision in schedule made as per sub-clauses (a) and (b) of this clause, any
revision in schedule made in odd time blocks shall become effective from 7th time block and any
revision in schedule made in even time blocks shall become effective from 8th time block, counting
the time block in which the request for revision has been received by the RLDCs to be the first one.
(d) While finalizing the drawal and despatch schedules, in case any congestion is foreseen in the inter-
State transmission system or technical constraints of a generating station, the concerned RLDC shall
moderate the schedules as required, under intimation to the concerned regional entities.
(5) Grid disturbance of category GD-5:
(a) GD-5 occurs when forty per cent or more of the antecedent generation or load in a regional grid is
lost as defined in the CEA Grid Standards.
(b) Certification of such grid disturbance and its duration shall be done by the RLDC.
(c) Scheduled generation of all the affected regional entity generating stations supplying power under
bilateral transactions shall be deemed to have been revised to be equal to their actual generation for
all the time blocks affected by the grid disturbance. Such regional entity generating station shall pay
back the energy charges received by it for the scheduled generation revised as actual generation to
the Deviation and Ancillary Service Pool Account:
Provided that, in case the beneficiaries or buyers of such regional entity generating station are also
affected by such grid disturbance, the scheduled drawals of such beneficiaries or buyers shall be
deemed to have been revised to corresponding actual generation schedule of regional entity
generating stations:
Provided further that in case the beneficiaries or buyers of such regional entity generating station are
not affected by such grid disturbance and they continue to draw power, the scheduled drawals of
such beneficiaries or buyers shall not be revised.
(d) The scheduled generation of all the affected regional entity generating stations supplying power
under collective transactions shall be deemed to have been revised to be equal to their actual
generation. Such regional entity generating stations shall refund the charges received towards such
scheduled energy to the Deviation and Ancillary Service Pool Account.
(e) The declaration of grid disturbance shall be done by the concerned RLDC at the earliest. A notice to
this effect shall be posted at its website by the RLDC of the region in which the grid disturbance has
occurred which shall be considered as declaration of the grid disturbance by RLDC. All regional
entities shall take note of the grid disturbance and take appropriate action at their end.
(f) Energy and deviation settlement for the period of such grid disturbance causing disruption in
injection or drawal of power shall be done by the concerned RPC(s) in consultation with the
concerned RLDC(s):
Provided that generation and drawal schedules revised by the Regional Load Despatch Centre shall
become effective from 7th block or 8thblock depending on block in which schedule has been revised
as first block.
(6) The generation schedules and drawl schedules shall be accessible to the regional entities though user
credentials controlled access. After the operating day is over at 2400 hours, the schedule finally
implemented during the day (taking into account all before-the-fact changes in despatch schedule of
regional entity generating stations and drawal schedule of the States) shall be issued by the concerned
RLDC. These schedules shall be the basis for commercial accounting.
(7) Revision of Declared Capacity and schedule, shall be allowed on account of forced outage of a unit of a
generating station or ESS (as an injecting entity) only in case of bilateral transactions and not in case of
collective transaction. Such generating station or ESS (as injecting entity) or the electricity trader or any
other agency selling power from the unit of the generating station or ESS shall immediately intimate the
outage of the unit along with the requisition for revision of Declared Capacity and schedule and the
estimated time of restoration of the unit, to SLDC or RLDC, as the case may be. The schedule of
beneficiaries, sellers and buyers of power from this generating unit shall be revised on pro-rata basis for
all bilateral transactions. The revised Declared Capacity and schedules shall become effective from the
time block and in the manner as specified in clause (4) of this Regulation:
Provided that the generating station or ESS (as injecting entity) or trading licensee or any other agency
selling power from a generating station or unit(s) thereof or ESS may revise its estimated restoration
time once in a day and the revised schedule shall become effective from the 7th time block or 8th time
block as per clause (4) of this Regulation, counting the time block in which the revision is informed by
the generator or ESS to be the first one:
Provided further that the SLDC or the RLDC as the case may be, 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.
(8) In case of requirement of revision of schedule due to forecasting error, a WS seller may revise its
schedule only in case of bilateral transactions and not in case of collective transaction. Such revision of
schedule shall become effective from the time block and in the manner as specified in sub-clause (c) of
clause (4) of this Regulation.
(9) In case of requirement of revision of Declared Capacity due to forecasting error, a RoR generating
station may request for revision of its Declared Capacity and schedule only in case of bilateral
transactions and not in case of collective transaction. Such revision shall become effective from the time
block and in the manner as specified in sub-clause (c) of clause (4) of this Regulation.
(10) In the event of forced outage of a generating station or unit thereof, the generating company owning the
generating station or unit thereof shall fulfil its supply obligation to the beneficiaries which made
requisition from such generating station or unit thereof, (i) by entering into contract(s) covered under
Power Market Regulations or (ii) by arranging supply from any other generating station or unit thereof
owned by such generating company subject to honouring of rights of the original beneficiaries of the
said generating station or unit thereof from which the supply is arranged or (iii) through SCED, as
applicable.
(11) Discrepancy in schedule
(a) All regional entities, open access customers, injecting entities and drawee consumers shall closely
check their transaction Schedule and point out errors, if any, to the concerned LDC.
(b) The final schedules issued by RLDC shall be open to all regional entities and other regional open
access entities for any checking and verification, for a period of 5 days. In case any mistake or
omission is detected, the RLDC shall make a complete check and rectify the same.
(12) Energy Metering and Accounting:
(a) The CTU shall be responsible for procurement and installation of Interface Energy Meters (IEMs),
at the cost of respective entity, at all the ISTS interface points, points of connections between the
regional entities, cross border entities and other identified points for recording of actual active and
reactive energy interchanged in each time-block through those points, and its operation and periodic
calibration shall be done by the respective entity. CTU shall be responsible for replacement of faulty
meters.
(b) The installation, operation, calibration and maintenance of Interface Energy Meters (IEMs) with
automatic remote meter reading (AMR) facility shall be in accordance with the CEA Metering
Regulations 2006.
(c) The installation, operation, and maintenance of additional communication links, if any, required for
the purpose of AMR facility shall be in accordance with CEA Communications Regulations.
(d) Access to such metering data to the concerned RLDC and SLDC(s) shall be in accordance with the
CEA Metering Regulations 2006.
(e) Entities in whose premises the IEMs are installed shall be responsible for (i) monitoring the
healthiness of the CT and PT inputs to the meters, (ii) taking weekly meter readings for the seven
day period ending on the preceding Sunday 2400 hrs and transmitting them to the RLDC by
Tuesday noon, in case such readings have not been transmitted through automatic remote meter
reading (AMR) facility (iii) monitoring and ensuring that the time drift of IEM is within the limits as
specified in CEA Metering Regulations 2006 and (iv) promptly intimating the changes in CT and
PT ratio to RLDC.
(f) RLDC shall, based on the IEM readings, compute time block wise actual net injection and drawal of
regional entities and cross border entities within their control area:
Provided that the computations done by RLDCs shall be open to all regional entities and cross
border entities for a period of fifteen (15) days for checking and verification.
(g) In case any error or omission is detected by self-analysis or brought to notice by an entity, the
RLDC or RPC or NLDC, as the case may be, shall make a complete check and rectify the error
within a period of a month from date of such detection.
(h) RLDC shall forward the IEM readings and the implemented schedule to the concerned RPC on a
weekly basis by each Thursday for the preceding seven days period ending on the preceding
Sunday mid-night, to enable the latter to prepare and issue the various accounts such as Deviation
Settlement Mechanism (DSM), reactive charges, congestion charges, ancillary services, SCED, heat
rate compensation charges, and regional transmission deviation in accordance with relevant
regulations and Annexure 7 of these regulations.
(13) Inspection of Records:
The operational logs and records of the regional entity generating stations and inter-State transmission
licensees shall be available for inspection and review by the RLDCs and RPCs.
(14) Oversight of Injection and Drawal:
NLDC or RLDC, as the case may be, shall periodically review the over drawal from or under injection
into the grid. In case of persistent over drawal or under injection, the matter shall be reported to the
RPC and the Commission for necessary action.
CHAPTER 8
CYBER SECURITY
50. GENERAL
(1) This chapter deals with measures to be taken to safeguard the national grid from spyware, malware,
cyber-attacks, network hacking, procedure for security audit from time to time, upgradation of system
requirements and keeping abreast of latest developments in the area of cyber-attacks and cyber security
requirements.
(2) All users, NLDC, RLDCs, SLDCs, CTU and STUs, power exchanges, QCAs, SNAs, shall have in place,
a cyber security framework in accordance with Information Technology Act, 2000; CEA (Technical
Standards for Connectivity) Regulations, 2007; CEA (Cyber Security in Power Sector) Guidelines, 2021
and any such regulations issued from time to time, by an appropriate authority, so as to support reliable
operation of the grid.
51. CYBER SECURITY AUDIT
All users, NLDC, RLDCs, SLDCs, CTU and STUs, power exchanges, QCAs, SNAs, shall conduct Cyber
Security Audit as per the guidelines mentioned in the CEA (Cyber Security in Power Sector) Guidelines,
2021 and any other guidelines issued by an appropriate Authority.
52. MECHANISM OF REPORTING
(1) All entities shall immediately report to the appropriate government agencies in accordance with the
Information Technology Act, 2000, as amended from time to time, and CEA (Cyber Security in Power
Sector) Guidelines, 2021, in case of any cyber-attack.
(2) NLDC, RLDCs, SLDCs, RPCs and the Commission shall also be informed by such entities in case of
any instance of cyber-attack.
53. CYBER SECURITY COORDINATION FORUM
(1) The sectoral CERT (Computer Emergency Response Team) for wings of power sector, as notified by
Government of India, from time to time, shall form a Cyber Security Coordination Forum with members
from all concerned utilities and other statutory agencies to coordinate and deliberate on the cyber security
challenges and gaps at appropriate level. A sub-committee of the same shall be formed at the regional level.
(2) The sectoral CERT shall lay down rules of procedure for carrying out their activities.
CHAPTER 9
MONITORING AND COMPLIANCE CODE
54. GENERAL
This chapter deals with (a) monitoring of compliance of these regulations by various entities in the grid by
RLDCs, RPCs or any other person, (b) manner of reporting the instances of violations of these regulations
and (c) taking remedial steps or initiating appropriate action.
55. ASSESSMENT OF COMPLIANCES
The performance of all users, CTU, STUs, NLDC, RLDCs, SLDCs and RPCs, power exchanges, QCAs,
SNAs with respect to compliance of these regulations shall be assessed periodically.
56. MONITORING OF COMPLIANCE
(1) In order to ensure compliance, two methodologies shall be followed:
(a) Self-Audit
(b) Compliance Audit
(2) Self-Audit:
(a) All users, CTU, STUs, NLDC, RLDCs, RPCs and SLDCs, power exchanges, QCAs, SNAs shall
conduct annual self-audits to review compliance of these regulations and submit the reports by 31st
July of every year.
(b) The self-audit report shall inter alia contain the following information with respect to non-
compliance:
(i) Sufficient information to understand how and why the non-compliance occurred;
(ii) Extent of damage caused by such non-compliance;
(iii) Steps and timeline planned to rectify the same;
(iv) Steps taken to mitigate any future recurrence;
(c) The self-audit reports by users, QCAs, SNAs shall be submitted to the concerned RLDC or SLDC,
as the case may be.
(d) The self-audit reports by power exchanges shall also be submitted to the NLDC.
(e) The self-audit reports of NLDC, RLDCs, CTU, and RPCs shall be submitted to the Commission.
The self-audit report of SLDC and STUs shall be submitted to the concerned SERC.
(f) The deficiencies shall be rectified in a time bound manner within a reasonable time.
(g) The monitoring agency for users shall be the concerned RLDC or SLDC on the basis of their
respective control area. The monitoring agency shall track the progress of compliances of users, and
exceptional reporting for non-compliance shall be submitted to the appropriate Commission.
(h) The monitoring agency for RLDC, NLDC, CTU and RPC shall be the Commission, and for STUs
and SLDCs, shall be the concerned SERC.
(i) The Regional Power Committee (RPC) in the region shall also continuously monitor the instances of
non-compliance of the provisions of these regulations and endeavor to sort out all operational issues
and deliberate on the ways in which such cases of non-compliance shall be prevented in future. The
Member Secretary of respective RPCs may also report any unresolved issues to the Commission.
(j) The Commission may initiate appropriate proceedings upon receipt of report under sub-clauses (f)
and (h) of this clause.
(k) In case of non-compliance of any provisions of these regulations by NLDC, RLDCs, SLDCs, RPCs
and any other person, the matter may be reported by any person to the Commission through filing of
a petition.
(3) Independent Third-Party Compliance Audit:
The Commission may order independent third-party compliance audit for any user, power exchange,
QCA, SNA, CTU, NLDC, RLDC and RPC as deemed necessary based on the facts brought to the
knowledge of the Commission.
CHAPTER 10
MISCELLANEOUS
57. POWER TO RELAX
The Commission, for reasons to be recorded in writing, may relax any of the provisions of these regulations on its
own motion or on an application made before it by an affected person to remove the hardship arising out of the
operation of any of these regulations, applicable to a class of persons.
58. POWER TO REMOVE DIFFICULTY
If any difficulty arises in giving effect to the provisions of these regulations, the Commission may, on its own
motion or on an application made before it by the nodal agency, by order, make such provisions not inconsistent
with the provisions of the Act or provisions of other regulations specified by the Commission, as may appear to
be necessary for removing the difficulty in giving effect to the objectives of these regulations.
59. REPEAL AND SAVINGS
(1) Save as otherwise provided in these regulations, the Central Electricity Regulatory Commission (Indian
Electricity Grid Code) Regulations, 2010 and all subsequent amendments thereof shall stand repealed from the
date of commencement of these Regulations.
(2) Regulation 6.3B of Central Electricity Regulatory Commission (Indian Electricity Grid Code) (Fourth
Amendment) Regulations, 2016 along with Appendix-II "Mechanism for Compensation for Degradation of Heat
Rate, Aux Consumption and Secondary Fuel Oil Consumption, due to Part Load Operation and Multiple
Start/Stop of Units" as issued by CERC dated 5th May 2017 vide No. L-1/219/2017-CERC shall continue to be in
force till the regulations or Order under clause (12) of Regulation 45 of these regulations are issued.
(3) The mechanism of computing and sharing of net savings under SCED in accordance with the Order dated
31.3.2022 vide Petition No. 3/SM/2022 and other related Orders shall continue to be applicable till the Detailed
Procedure under sub-clause (a)(x) of clause (2) of Regulation 49 of these regulations is issued.
(4) Notwithstanding such repeal, anything done or any action taken or purported to have been done or taken
including any procedure, minutes, reports, confirmation or declaration of any instrument executed under the
repealed regulations shall be deemed to have been done or taken under the relevant provisions of these
regulations.
60. ISSUE OF SUO MOTO ORDERS AND DIRECTIONS
The Commission may from time to time issue suo motu orders and practice directions with regard to
implementation of these regulations and matters incidental or ancillary thereto, as the case may be.
61. TREATMENT OF THESE REGULATIONS IN CONTRACT
The provisions of these regulations or any amendments thereof shall not be treated under ,,Change in law in
any of the agreements entered into by any of the Users covered under these regulations.
HARPREET SINGH PRUTHI, Secy.
[ADVT.-III/4/Exty./270/2023-24]
ANNEXURE - 1
THIRD PARTY PROTECTION SYSTEM CHECKING & VALIDATION TEMPLATE FOR A
SUBSTATION
1. INTRODUCTION
(1) The audit reports, along with action plan for rectification of deficiencies found, if any, shall be submitted to
RPC or RLDC within a month of submission of report by auditor.
(2) The third-party protection system checking shall be carried at site by the designated agency. The agency shall
furnish two reports:
(a) Preliminary Report: This report shall be prepared on the site and shall be signed by all the parties
present.
(b) Detailed Report: This report shall be furnished by agency within one month after carrying out detailed
analysis.
2. CHECKLIST
(1) The protection system checklist shall contain information as per this Regulation.
(a) General Information (to be provided prior to the checking as well as to be included in final report):
(i) Substation name
(ii) Name of Owner Utility
(iii) Voltage Level (s) or highest voltage level?
(iv) Short circuit current rating of all equipment (for all voltage level)
(v) Date of commissioning of the substation
(vi) Checking and validation date
(vii) Record of previous trippings (in last one year) and details of protection operation
(viii) Previous Relay Test Reports
(ix) Overall single line diagram (SLD)
(x) AC aux SLD
(xi) DC aux SLD
(xii) SAS architecture diagram
(xiii) SPS scheme implemented (if any)
(b) The preliminary report shall inter-alia contain the following:
TABLE A: FORMAT OF PRELIMINARY REPORT
S. No. Issues Remarks
1 Recommendation of last protection checking and validation Status of works and pending issues if
any
2 Review of existing settings at substation Recommended Action
3 Disturbance Recorder out available for last 6 trippings (Y/N) Recommended Action
4 Chronic reason of tripping, if any Recommended Action
5 Major non-conformity/deficiency observed Recommended Action
(c) The relay configuration checklist for available power system elements at station:
(i) Transmission Line
(ii) Bus Reactor/Line Reactor
(iii) Inter-connecting Transformer
(iv) Busbar Protection Relay
(v) AC auxiliary system
(vi) DC auxiliary system
(vii) Communication system
(viii) Circuit Breaker Details
(ix) Current Transformer Details
(x) Capacitive Voltage Transformers Details
(xi) Any other equipment/system relevant for protection system operation
(d) The minimum set of points on which checking and validation shall be carried out is covered in this
clause. The detailed list shall be prepared by checking and validation team in consultation with
concerned entity, RLDC and RPC.
(i) Transmission Line Distance Protection/Differential Protection
a. Name and Length of Line
b. Whether series compensated or not
c. Mode of communication used (PLCC/OPGW)
d. Relay Make and Model for Main-I and Main-II
e. List of all active protections & settings
f. Carrier aided scheme if any
g. Status of Power Swing/Out of Step/SOTF/Breaker Failure/Broken Conductor/STUB/Fault
Locator/DR/VT fuse fail/Overvoltage Protection/Trip Circuit supervision/Auto-
reclose/Load encroachment etc.
h. Relay connected to Trip Coil-1 or 2 or both
i. CT ratio and PT ratio
j. Feed from DC supply-1 or 2
k. Connected to dedicated CT core (mention name)
l. Other requirements for protection checking and validation
(ii) Shunt Reactor & Inter-connecting Transformer Protection
a. Whether two groups of protections used (Group A and Group B)
b. Do the groups have separate DC sources
c. Relay Make and Model
d. List of all active protections along with settings
e. Status of Differential Protection/Restricted Earth Fault Protection/Back-up Directional
Overcurrent/Backup Earth fault/ Breaker Failure
f. Status of Oil Temperature Indicator/Winding Temperature Indicator/Bucholz/Pressure
Release Device etc.
g. Relay connected to Trip Coil-1 or 2 or both
h. CT ratio and PT ratio
i. Feed from DC supply-1 or 2
j. Connected to dedicated CT core (mention name)
k. Other requirements for protection checking and validation
(iii) Busbar Protection Relay
a. Busbar and redundant relay make and model
b. Type of Busbar arrangement
c. Zones
d. Dedicated CT core for each busbar protection (Yes/No)
e. Breaker Failure relay included (Yes/No), if additional then furnish make and model
f. Trip issued to both Busbar protection in case of enabling
g. Isolator indication and check relays
h. Other requirements for protection checking and validation
(iv) AC auxiliary system
a. Source of AC auxiliary system
b. Supply changeover between sources (Auto/Manual)
c. Diesel generator (DG) details
d. Maintenance plan and supply changeover periodicity in DG
e. Single Line Diagram
f. Other requirements for protection checking and validation
(v) DC auxiliary system
a. Type of Batteries (Make, vintage, model)
b. Status of battery Charger
c. Measured voltage (positive to earth and negative to earth)
d. Availability of ground fault detectors
e. Protection relays and trip circuits with independent DC sources
f. Other requirements for protection checking and validation
g. Communication system
i. Mode of communication for Main-1 and Main-2 protection
ii. Mode of communication for data and speech communication
iii. Status of PLCC channels
iv. Time synchronization equipment details
v. 7OPGW on geographically diversified paths for Main-1 and main-2 relay
vi. Other requirements for protection checking and validation
(vi) Circuit Breaker Details
a. Details and Status
b. Healthiness of Tripping Coil and Trip circuit supervision relay
c. Single Pole/Multi pole operation
d. Pole Discrepancy Relay available(Y/N)
e. Monitoring Devices for checking the dielectric medium
f. Other requirements for protection checking and validation
(vii) Current Transformer (CT)/Capacitive Voltage Transformer (CVT) Details
a. CT/CVT ID name and voltage level
b. CT/CVT core connection details
c. Accuracy Class
d. Whether Protection/Metering
e. CT/CVT ratio available and ratio adopted
f. Details of last checking and validation of CT/CVT healthiness
g. Other requirements for protection checking and validation
h. Other protections: Direction earth fault, negative sequence, over current, over voltage, over
frequency, under voltage, under frequency, forward power, reverse power, out of
step/power swing, HVDC protection etc.
3. SUMMARY OF CHECKING:
The summary shall specifically mention minimum following points:
(1) The settings and scheme adopted are in line with agreed protection philosophy or any accepted guidelines
(e.g. Ramakrishna guidelines or CBIP manual based).
(2) The deviations from the RPC protection philosophy, if any and reasons for taking the deviations shall be
recorded.
(3) All the major general deficiency shall be listed in detail along with remedial recommendations.
(4) The relay settings to be adopted shall be validated with simulation based or EMTP studies and details shall be
enclosed in report.
(5) The cases of protection maloperation shall be analysed from protection indices report furnished by concerned
utility, the causes of failure along with corrective actions and recommendations based on the findings shall be
noted in the report.
ANNEXURE - 2
GENERATION RESERVE ESTIMATION AND FREQUENCY CONTROL
4. INTRODUCTION
This procedure is in line with the sub-clause (f) of clause (10) of Regulation 30 of these regulations which requires
methodology for the following as detailed in subsequent paragraphs:
(1) Assessment of reference contingency,
(2) All India minimum target frequency response characteristics,
(3) Calculation of frequency response obligation of each control area,
(4) Criteria for reportable event,
(5) Calculation of actual frequency response characteristics of control area and
(6) Calculation of frequency response performance
5. ASSESSMENT OF REFERENCE CONTINGENCY
The reference contingency is the quantum of sudden generation or demand outage in an event. The reference
contingency shall consider quantum of generation outage based on outage of largest power plant, group of power
plants, a generation complex, or a generation pooling station, or the actual generation outage occurred in an
event during last two years, or a credible outage scenario. Similarly reference contingency shall also consider
outage of single largest load center or actual outage of load occurred in an event during last two years. To start
with reference contingency shall be considered as outage of 4500 MW which shall be revised by NLDC from
time to time. The primary reserve at All India level shall be more than the reference contingency quantum.
Therefore, minimum quantum of primary reserve shall be currently 4500 MW.
6. ALL INDIA MINIMUM TARGET FREQUENCY RESPONSE CHARACTERISTICS
(a) The all India minimum target frequency response characteristic (MW/Hz) shall be reference contingency
quantum (MW) divided by maximum steady frequency deviation (Hz) allowable for the reference contingency
event.
(b) The primary reserves shall be activated immediately (within few seconds) when the frequency deviates from 50
Hz. The safe, secure and reliable operation of grid requires that the nadir frequency should be at least 0.1 Hz
above the first stage of under frequency load shedding scheme. This implies that the nadir frequency shall be
above or 49.5 Hz (considering first stage of under frequency loading shedding setting as 49.4 Hz) for the
reference contingency event and the maximum steady state frequency deviation should not cross 0.30 Hz for the
reference contingency event.
(c) Therefore, the minimum All India target Frequency Response Characteristic currently shall be quantum of load
or generation loss in reference contingency (as defined in Section (1) above divided by frequency deviation
value of 0.3 Hz i.e. 15000 MW/Hz (4500 MW/0.3 Hz).
7. CALCULATION OF FREQUENCY RESPONSE OBLIGATION (FRO) OF EACH CONTROL AREA:
The minimum Frequency Response Obligation (FRO) of each control area in MW/Hz shall be calculated as:
FRO = (Control Area average Demand + Control Area average Generation) * minimum all
India Target Frequency Response Characteristic/ (Sum of peak or average demand of all control
areas + Sum of average generation of all control areas)
Provided FRO shall be nil in case of a control area not having any generation resources, such as Goa, DD,
DNH etc.
8. CRITERIA FOR REPORTABLE EVENT:
The frequency response characteristic (FRC) calculation shall be carried out by each control area for any load or
generation loss incident involving net change of more than 1000 MW of load or generation or a frequency
change involving 0.1 Hz or more. The event shall be notified by the NLDC.
9. CALCULATION OF ACTUAL FREQUENCY RESPONSE CHARACTERISTICS OF CONTROL AREA
(a) Frequency Response Characteristics (FRC) computations:
Frequency Response Characteristics (FRC) will be computed for all events involving a sudden 1000
MW or more load or generation loss or a step change in frequency by 0.10 Hz i.e. for all reportable
events as notified by NLDC. The FRC shall be worked out by NLDC, RLDCs and SLDCs to for each
interconnection/region/control area (including for each generating station). Each generating station shall
also compute its FRC. The following steps shall be followed for computation of FRC
(i) After every event involving a sudden 1000 MW or more load or generation loss or a step change in
frequency by 0.1 Hz, NLDC would get the PMUs frequency data. NLDC would also get the exact
quantum of load/generation lost from the RLDC of the affected region.
(ii) NLDC shall plot the frequency graph and determine the initial frequency, minimum/maximum
frequency, settling frequency and time points (points A, C and B of the Figure-A). Accordingly,
frequency difference points & corresponding time to be used for FRC calculations would be informed
to all RLDCs.
(iii) NLDC shall also work out region wise and neighboring countries (Bhutan and Nepal) FRC (Format
as per Table - B) based on 10 second Historical Data Recording (HDR) data available at NLDC and
inform all RLDCs within three (3) working days. RLDCs shall inform the SLDCs/regional entities in
their region.
(iv) RLDCs shall also work out each control area wise FRC (Format as per Table -B) based on HDR data
available at RLDCs within six (6) working days after the event.
(v) All the SLDCs shall work out FRC for all the intra-state entities (for events indicated by the Regional
Load Despatch Centres) based on the HDR available at their respective SLDCs and submit the same
to respective RLDC within six (6) working days after the event. (Format as per Table-B).
(vi) All regional entity generating stations shall also assess the FRC for their respective stations and
submit the same to respective RLDC within six (6) working days. (Format as per Table-B). The high
resolution data (1 second or better resolution) of active power generation and frequency shall also be
shared with RLDC.
(b) Input data for FRC:
(i) The data for frequency response characteristic Calculations may be taken from the real time
telemetered data recorded by the SCADA systems installed at Control Areas / Regional Load
Despatch Centres / National Load Despatch Centre.
(ii) Bad quality of data could be flagged / mentioned by the control centre(s) and reasonable
assumptions made for FRC computation. Details of these may be mentioned.
(c) Instructions for computation of FRC:
A sample frequency chart given at Figure-A with points A, B, and C labeled, depicts a typical frequency
excursion caused by a loss of a large generator in Indian power system. Point A denotes the
interconnection frequency immediately before the disturbance. Point B represents the Interconnection
frequency at the point immediately after the frequency stabilizes due to governor action but before the
contingent area takes any corrective actions, automatic or manual. Point C represents the
interconnection frequency at its maximum deviation due to the loss of generation.
FIGURE A: SAMPLE PMU FREQUENCY PLOT SHOWING RELEVANT POINTS FOR FRC CALCULATION
(d) Steps to work out frequency response characteristics of control area are as follows: -
Step-1: Actual net interchange of the control area immediately before the disturbance (Point 'A' in the figure-
A), say PA. Sign convention for net power imported into a Control Area is positive (+) and net power
exported out of a control area is negative (-).
Step-2: Actual net interchange of the control area immediately after the disturbance (Point 'B' in the figure-
A), say PB. Use the same sign convention as Step-1.
Step-3: The change in net interchange of the Control Area = (PB -PA). [For a disturbance that causes the
frequency to decrease, this value should ideally be negative. The net interchange of a control area may
be positive, if the drop in generation has occurred in that control area. Similarly, for load throw off or
frequency rise cases in a control area, the net interchange shall normally be positive except for the
Control Area, where the load throw off has taken place.]
Step-4: If the control area has suffered the loss, then Load or generation lost by the control area = PL.
Otherwise, the loss (PL) is zero. Sign convention for Load Loss is negative (-) and Generation Loss
positive (+).
Step-5: The Control Area Response P = (PB-PA) - PL
Step-6: The Frequency immediately before the disturbance = fA.
Step-7: The Frequency immediately after the disturbance = fB.
Step-8: Change in Interconnection Frequency from Point A to Point B = f = (fB - fA)
Step-9: Frequency Response Characteristic (FRC) of the Control Area = P/ f
Step-10: Frequency Response Obligation (FRO) of each control area calculated in advance as per clause 3 of
this Annexure
Step 11: Frequency Response Performance (FRP) = Actual Frequency Response Characteristic (AFRC)/
Frequency Response Obligation (FRO)
TABLE B: FRC CALCULATION SHEET TO BE USED BY ALL SLDC/RLDC/NLDC/CONTROL AREA
S. No Particulars Dimension Control Area-1 /Region
1 Actual Net Interchange before the MW
Event (Time= hh:mm:ss)
2 Actual Net Interchange after the MW
3 Event (Time= hh:mm:ss) MW
4 Change in Net Interchange (2 - 1) MW
5 Generation Loss (+) / Load Throw MW
6 off (-) during the Event Hz
7 Control Area Response (3-4) Hz
8 Frequency before the Event Hz
9 Frequency after the Event MW/Hz
Change in Frequency (7-6)
10 Frequency Response Characteristic (5 MW/Hz
/ 8)
11 Frequency Response Obligation Numeric value (up to two decimal places)
(FRO) of control area
Frequency Response Performance
(FRP)(9/10)
10. CALCULATION OF FREQUENCY RESPONSE PERFORMANCE
(a) The performance of each control area in providing frequency response characteristic shall be calculated for
each reportable event. Each control area shall separately assess their frequency response characteristic and
share with RLDC along with high resolution data of at least one (1) second for regional entity generating
stations and ten (10) second for state control area.
Frequency Response Performance (FRP) = Actual Frequency Response Characteristic (AFRC)/ Frequency
Response Obligation (FRO)
Each control area shall be graded based on median Frequency Response Performance annually (at least 10
events) as per following criteria:
TABLE C: FREQUENCY RESPONSE CRITERIA
S. N Performance* Grading
Excellent
i. FRP 1
Good
ii. 0.85 FRP < 1 Average
Below Average
iii. 0.75 FRP <0.85
Poor
iv. 0.5 FRP < 0.75
v. FRP <0.5
*Provided that for wind/solar generating stations and state control areas with internal generation less than
100 MW or annual peak demand less than 1000 MW, the FRP grading shall be indicative only.
ANNEXURE-3
ASSESSMENT OF SECONDARY AND TERTIARY GENERATION RESERVES AT REGIONAL/STATE
LEVEL
1. Area control error (ACE) for each Control Area shall be calculated using sub-clause (d) of clause (11) of
Regulation 30 of these regulations, time block wise for the last financial year.
2. The positive ACE and negative ACE shall be separately tabulated.
3. The positive ACE shall be arranged in ascending order and 99 percentile of such ACE shall be captured.
Similarly, negative ACE shall be arranged in ascending order and 99 percentile of such ACE shall be
captured.
4. Such 99 percentile of positive and negative ACE respectively of a control area for previous financial year, is
the desired positive and negative secondary reserve capacity for such control area for next financial year.
Desired quantum of tertiary reserve of the control area shall also be equal to such estimated secondary reserve.
5. The total reserves in a region shall be algebraic sum of reserves in each state control area. However, due to
diversity within the region, the Region as a whole might need lesser reserves of secondary and tertiary
reserves. The reserve requirement shall be based on regional ACE which shall further be divided to identify
the share of each state based on 99 percentile ACE of such State control area. The All -India Total of Positive
(and Negative) secondary reserve capacity requirement on regional basis shall be equal to the reference
contingency or secondary reserve capacity requirement based on regional ACE, whichever is higher, subject
to the economic utilization of the resource available in the system while ensuring grid security.
6. The amount of reserve to be kept with each State control area as per clause (5) of this Annexure shall be
validated against the maximum unit size of the intra-state generator of that control area such that reserve
requirement is not more than unit size of maximum intra-state generator.
7. The secondary reserves for each control area obtained as per clause (5) of this Annexure shall be further
apportioned among the reserve to be kept at intra-state generation and at inter-state generation as per the
following considerations:
(1) The maximum demand and maximum internal generation for each control area.
(2) The ratio of demand met through internal generation and inter-state generation (drawl from the grid) is
calculated.
(3) The above ratio is used to apportion the secondary reserve obtained as per clause (5) of this Annexure
among the reserves to be maintained by each control area at intra-state generators and inter-state
generators.
Illustration: The maximum demand met of Punjab is 13602 MW and internal generation is 6932 MW. The
drawl from the grid is therefore 13602-6932= 6670 MW. Suppose the reserve capacity calculated for Punjab
in step-5 is 91 MW. The ratio of demand met by internal generation is 0.51(6932/13602) and by ISGS
generation is 0.49 (6670/13602). Thus reserve to be kept by Punjab in intra-state generation is 46
MW(0.51*91) and in ISGS generation is 44 MW (0.49*91).
8. For control areas having no generation or very small generation, the entire reserves capacity calculated as per
clause (5) of this Annexure for the state, shall be kept at inter-state generation.
ANNEXURE - 4
1. REACTIVE POWER COMPENSATION
(a) Reactive power compensation should ideally be provided locally, by generating reactive power as close to the
reactive power consumption as possible. The regional entities are therefore expected to provide local VAr
compensation or generation such that they do not draw VARs from the EHV grid, particularly under low-voltage
condition. To discourage VAr drawals by regional entities, VAr exchanges with ISTS shall be priced as follows:
(a) The regional entity pays for VAr drawal when voltage is below 97%
(b) The regional entity gets paid for VAr return when voltage is below 97%.
(c) The regional entity gets paid for VAr drawal when voltage is above103%.
(d) The regional entity pays for VAr return when voltage is above 103%.
Where all voltage measurements are at the interface point with ISTS.
(b) The charge for VArh shall be at the rate of 5 paise/kVArh w.e.f. the date of effect of these regulations. This rate
shall be escalated at 0.5paise/kVArh per year thereafter, unless otherwise revised.
(c) All the Inverter Based Resources (IBRs) covering wind, solar and energy storage shall ensure that they have the
necessary capability, as per CEA Connectivity Standards, all the time including non-operating hours and night
hours for solar. The active power consumed by these devices for purpose of providing reactive power support,
when operating under synchronous condenser/night-mode, shall not be charged under deviations and shall be
treated as transmission losses in the ISTS.
(d) For IBRs of capacity 50 MW and below not coming directly to the point of interconnection but through the
pooling at the Power Park Developer end, the Power Park Developer shall act as aggregator for the Reactive
Energy Charges for payments to and from the Pool Account at RLDC level. The de-pooling of Reactive Energy
charges amongst the individual wind and solar shall be done by the Power Park Developer.
(e) For any interconnecting line between two states, owned by the States, the interface points shall be treated in terms
of this Regulation for the purpose of reactive power charges.
2. ACCOUNTING AND PAYMENT FOR REACTIVE ENERGY EXCHANGES
(a) RPC Secretariat shall also issue the weekly statement for VAR charges, to all regional entities.
(b) The concerned regional entities shall pay the amounts into regional Pool Account operated by the RLDC within
10 (ten) days of issue of statement.
(c) The regional entities who have to receive the money on account of VAR charges would then be paid out from
the regional Pool Account, within two (2) working days from the receipt of payment in the Pool Account.
(d) If payments against the above VAr charges are delayed by more than two days, i.e., beyond twelve (12) days
from issue of the statement by RPC Secretariat, the defaulting regional entity shall pay simple interest @ 0.04%
for each day of delay. The interest so collected shall be paid to the regional entities who had to receive the
amount, payment of which got delayed.
(e) Persistent payment defaults, if any, shall be reported by the RLDC to the Member Secretary, RPC, for initiating
remedial action.
ANNEXURE- 5
1. REPORTING REQUIREMENTS
S. No. Entity Reporting / Study Requirement Reference Regulation of these
Responsible and Frequency regulations
1. RPC Exception report of UFR (monthly) Operating Code:
Regulation No. 29(13)(e)
Annual Outage Plan(annual) Operating Code:
Regulation No. 32(2)(a)
All India LGBR (annual) Operating Code:
Regulation No. 32 (3)(b)
Feedback Report to address potential Operating Code
violation of system operational limit Regulation No. 33(8)
(quarterly)
Final report on grid disturbance (post grid Operating Code
disturbance) Regulation No. 37(2)(f)
S. No. Entity Reporting / Study Requirement Reference Regulation of these
Responsible and Frequency regulations
2. CTU Self-audit Report Monitoring and Compliance Code
(By 31st July of every year)) Regulation No. 56(2)(a)
3. NLDC Transmission resource adequacy Resource Planning Code
assessment Regulation No. 5(4)(a)
4. RLDC Self-audit Report Monitoring and Compliance Code
(By 31st July of every year) Regulation No. 56(2)(a)
5. SLDC Assessment of frequency response Operating Code
obligation of each control area (By 15th of Regulation 30(10)(f)
STU March every year)
Operational planning (monthly/ yearly) Operating Code
6. User Regulation 31(1)(a)
Operational planning (Intra-day, Day Operating Code
Ahead, Weekly) Regulation 31(1)(b)
Forecast error (intra-day / day-ahead / Operating Code
weekly / monthly and yearly) Regulation 31(2)(i)
Operational analysis (post despatch) Operating Code:
Regulation No. 37(1)
Draft report of each grid disturbance or Operating Code:
grid incidence (post such event) Regulation No. 37(2)(f)
Daily and monthly report of integrated Operating Code:
grid performance (daily and monthly) Regulation 38(1)
Self-audit Report Monitoring and Compliance Code:
(By 31st July of every year) Regulation No. 56(2)(a)
Operational planning (monthly / yearly) Operating Code
Regulation 31(1)(a)
Operational planning (Intra-day, Day Operating Code
Ahead, Weekly) Regulation31(1)(b)
Forecast error (intra-day / day-ahead / Operating Code
weekly / monthly and yearly) Regulation 31(2)(i)
Operational analysis (post despatch) Operating Code:
Regulation No. 37(1)
Draft report of each grid disturbance (post Operating Code:
grid disturbance) Regulation No. 37(2)(f)
Regional grid performance (daily and Operating Code:
monthly) Regulation 38(2)
Details of regional entity generating Scheduling and Despatch Code:
stations (quarterly) Regulation No. 45(1)(a)
Self-audit Report Monitoring and Compliance Code:
(By 31st July of every year) Regulation No. 56(2)(a)
Exception report of UFR (monthly) Operating Code:
Regulation No. 29(13)(d)
Operational planning (monthly / yearly) Operating Code: Regulation 31(1)(a)
Operational planning (Intra-day, Day Operating Code:
Ahead, Weekly) Regulation 31(1)(b)
Forecast error (intra-day/ day-ahead Operating Code:
/weekly/monthly and yearly) Regulation 31(2)(i)
Operational analysis (post despatch) Operating Code:
Regulation No. 37(1)
Flash report and detailed report on any Operating Code:
grid disturbance (post grid disturbance) Regulation No. 37(2)
Self-audit Report Monitoring and Compliance Code:
(By 31st July of every year)) Regulation No. 56(2)(a)
Transmission resource adequacy Resource Planning Code:
assessment Regulation No. 5(4)(b)
Self-audit Report Monitoring and Compliance Code:
(By 31st July of every year)) Regulation No. 56(2)(a)
Tuning of AVR, PSS, Voltage Operating Code:
Controllers (PPC) including for low and Regulation No. 29(7)
S. No. Entity Reporting / Study Requirement Reference Regulation of these
Responsible and Frequency regulations
7. Power Exchange high voltage ride through capability Operating Code:
Flash report and detailed report on any Regulation No. 37(2)
8. QCA grid disturbance (post grid disturbance) Monitoring and Compliance Code:
Self-audit Report Regulation No. 56(2)(a)
9. SNA (By 31st July of every year)) Monitoring and Compliance Code:
Self-audit Report Regulation No. 56(2)(a)
(By 31st July of every year)) Monitoring and Compliance Code:
Self-audit Report Regulation No. 56(2)(a)
(By 31st July of every year)) Monitoring and Compliance Code:
Self-audit Report Regulation No. 56(2)(a)
(By 31st July of every year))
2. PROCEDURE TO BE SUBMITTED FOR APPROVAL OF THE CENTRAL COMMISSION, AFTER PREPARATION AND DUE
STAKEHOLDER CONSULTATION
S. Entity Drafting Responsibilities Timeline to Reference Regulation Number
No. Responsible submit to
Commission
from date of
notification of
these
regulations
1. NLDC Detailed procedure covering 60 days Connection Code:
modalities for first time Regulation No. 8(2)
energization and integration of 60 days
new or modified power system 60 days Operating Code:
elements Regulation No. 30(9)
Compensation of quick start Operating Code:
synchronous generation Regulation No. 30(11)(k)
Assessment of quantum of Operating Code:
secondary reserve capacity Regulation No. 30(11)(t),30(12)(h)
Methodology for allocation of 60 days Operating Code:
Regulation No. 34 (9)
cost of procurement of 60 days Operating Code:
60 days Regulation No. 39 (10)
Secondary/Tertiary reserve 60 days Scheduling and Despatch Code:
Regulation No. 45 (11)(b)
capacity in case of shortfall of 60 days
60 days Scheduling and Despatch Code:
reserve capacity by the State Regulation No. 46 (4)(i)
60 days Scheduling and Despatch Code:
Procedure for payment for Black Regulation No. 46 (4)(j)
start support Scheduling and Despatch Code:
Regulation No. 46 (5)(a), 46 (5)(b)
Compensation for synchronous
condenser mode operation
Procedure for aggregation of
pooling stations for the purpose
of combined scheduling and
deviation settlement for wind or
solar or renewable hybrid
generating stations
Detailed procedure to start a unit
under different conditions such
as HOT, WARM and COLD
Detailed procedure for
participation of the generating
stations other than those whose
tariffs are determined under
Section 62 of the Act opting to
participate in SCUC
Assessment of adequacy or
inadequacy of reserves and
identification of the generating
S. Entity Drafting Responsibilities Timeline to Reference Regulation Number
No. Responsible submit to
Commission
from date of
notification of
these
regulations
stations/units for SCUC
Supply from alternate REGS 60 days Scheduling and Despatch Code:
source: sharing of net savings for 60 days Regulation No. 48(3)(e)
generating stations whose tariff is
determined under Section 62 of Scheduling and Despatch Code:
the Act. Regulation No. 49(1)(l)
Sharing of net savings from sale
in day ahead collective market, Scheduling and Despatch Code:
for generating stations whose 49(2)(a)(x)
tariff is determined under Section
62 of the Act.
Detailed procedure for SCED:
sharing of net savings
3. PROCEDURE TO BE SUBMITTED FOR INFORMATION OF THE CENTRAL COMMISSION, AFTER PREPARATION AND DUE
STAKEHOLDER CONSULTATION
S. Entity Drafting Responsibilities Timeline to Regulation No.
No. Responsible submit to
1. RPC Tuning procedure for Power System Commission Operating Code:
2. NLDC Stabilizers, AVRs of generating units from date of Regulation No. 29(8)
and reactive power controllers notification of
3. RLDC Common outage planning procedure these Operating Code:
regulations Regulation No. 32(4)
Detailed Procedure covering 60 days Connection Code:
modalities for carrying out Regulation No. 10(3)
interconnection studies 60 days
Operating procedure 60 days Operating Code:
Regulation No. 28(3)
Information exchange and timelines 60 days Operating Code:
in respect of Secondary/Tertiary 60 days Regulation No. 30 (11)(q),
reserves 30(12)(d), 30(12)(l)
Detailed Procedure for evaluating 60 days Operating Code:
control area wise performance of Regulation No. 30(13)
SRAS, TRAS providers 60 days
Dynamic reactive power reserve 60 days Operating Code:
assessment Regulation No. 39 (6)
Detailed procedure for SCED 60 days Scheduling and Despatch
60 days Code:
Operating procedure 49(2)(a)(iv)
To be updated Operating Code:
Procedure for operational planning every year Regulation No. 28(4)
analysis, real-time monitoring, real- Operating Code:
time assessments and format for data Regulation No. 31 (1)(c)
submission and updating
Restoration Procedure Operating Code:
Regulation No. 34 (1), 34(2)
S. Entity Drafting Responsibilities Timeline to Regulation No.
No. Responsible submit to
4. SLDC Detailed procedure covering Commission Connection Code
modalities for first time energization from date of Regulation No. 8(4)
5. User and integration of new or modified notification of
power system elements these Operating Code:
Operating procedure regulations Regulation No. 28(5)
6 months Operating Code:
Procedure for operational planning Regulation No. 31 (1)(d)
analysis, real-time monitoring, real- 6 months
time assessments and format for data Operating Code:
submission and updating 6 months Regulation No. 34 (1)
Restoration Procedure Operating Code:
To be updated Regulation No. 34 (3)
Detailed procedures for restoration every year
post partial and total blackout of user To be reviewed
system and updated
every year
ANNEXURE-6
PROCEDURE SPECIFYING DATA, FORECASTING AND SCHEDULING FOR RENEWABLE ENERGY
GENERATING STATIONS (REGS) AT INTER-STATE LEVEL
1. INTRODUCTION
(a) This Procedure contains requirements of data submission by Renewable Energy Generating Station or QCA
on behalf of Renewable Energy Generating Station(s), prior to COD and real time and scheduling
methodology to be followed for multiple renewable energy generating station(s) connected at a pooling
station.
(b) The responsibility to provide forecast and other data and to coordinate with RLDC under this Procedure shall
be that of Qualified Coordinating Agency on behalf of all generating stations it is representing.
Provided that where Qualified Coordinating Agency is not identified, individual renewable energy generating
station or lead generator, as the case may be, shall be responsible for the same.
2. ROLE OF ENTITIES
(1) QCA or Renewable Energy Generating Station or Lead Generator
(a) The individual generating station or Lead Generator shall submit one time details to concerned RLDC as per
Appendix-I to this Annexure. Further, if there is any change in the information furnished, then the updated information shall
be shared with the concerned RLDC not later than 7 working days of such change.
(b) QCA (for the REGSs it is representing) or REGS (who are not represented through QCA) or Lead Generator shall
undertake the following activities:
(i) QCA or Lead Generator (for generating stations it is representing) shall undertake technical coordination
amongst the generators it is representing, connected at a pooling station.
(ii) Provide Available Capacity, Day ahead forecast (based on their own forecast or on the forecast done by
RLDC) and Schedule as per Appendix-II to this Annexure, through web-based application maintained by
RLDCs.
(iii) Provide real time data at turbine/inverter level and generation data at pooling station level as per Appendix-
III to this Annexure.
(iv) Provide monthly data:
a.For wind plants- average wind speed, average power generation for 15-min time block for each turbine
b. For solar plants - average solar irradiation, average power generation at 15-min time block level for
all inverters* >=1 MW
* if a solar plant uses only smaller string inverters, then data may be provided at the plant level
(v) Be responsible for metering and data collection, transmission and co-ordination with RLDC, SLDC, RPC,
CTU and other agencies as per IEGC and extant CERC Regulations.
(vi) Undertake commercial settlement for deviation as per applicable CERC Regulations.
(vii) Submit a copy of the consent to the concerned RLDC wherein it is mentioned that QCA shall undertake
all operational and commercial responsibilities on behalf of generating stations as per the CERC
Regulations.
(viii) Use Automatic meter reading technologies for transfer, analysis and processing of interface meter data.
(ix) Shall furnish the contract rate(s) along with a copy of the contract(s), for the purpose of Deviation charge
account preparation, to respective RPC.
(x) Shall comply the instruction of respective RLDCs in normal operation as well as emergency condition.
(xi) Shall establish protocol for communication with individual generators to implement the instructions of
RLDCs effectively.
(xii) Shall maintain records and accounts of the time-block wise Schedules, the Actual generation injected and
the deviation, for the polling station and individual generator(s) separately.
(xiii) Shall ensure availability of data telemetry at the turbine/inverter level to the concerned RLDC and shall
ensure the correctness of the real-time data and undertake the corrective actions, if required. The
suggested data telemetry requirement is enclosed at Appendix-III to this Annexure.
(xiv) Keep each of the RLDCs indemnified at all times and shall undertake to indemnify, defend and save the
SLDCs/RLDCs harmless from any and all damages, losses including commercial losses due to forecasting
error, claims and actions including those relating to injury to or death of any person or damage to
property, demands, suits, recoveries, costs and expenses, court costs, attorney fees, and all other
obligations by or to third parties, arising out of or resulting from the transactions undertaken by the
Generators.
(2) RLDC
(a) The concerned RLDC shall be responsible for scheduling, communication, coordination with QCA or generating
station or Lead Generator.
(b) The concerned RLDC will be responsible for processing the interface meter data and computing the net injections
at pooling station represented by each QCA or REGS or Lead Generator, as the case may be, as specified in
Appendix- IV to this Annexure.
3. FORECASTING
(1) QCA or generating station or Lead Generator shall provide the forecast to the concerned RLDC which may be
based on their own forecast or RLDCs forecast as per Appendix-II to this Annexure.
(2) QCA or generating station or Lead Generator may prepare their schedule based on the forecast done by RLDC
or their own forecast. Any commercial impact on account of deviation from schedule based on the forecast
chosen by the QCA shall be borne by the respective QCA.
4. SCHEDULING AND DESPATCH
(1) Following alternatives exist for Scheduling and Despatch for Generators within Solar / Wind /Hybrid Power
parks due to multiple generation developers within the Park injecting at various points with in the park and
ultimately injecting at interface with ISTS:
Case-1 QCA has been identified for all generating stations connected at a pooling station.
Case-2 Where QCA at a pooling station is identified for some of the generating stations but not all of
generating stations at such pooling station
Case-3 Where QCA at a pooling station is not identified following situations may arise
Case-A: The concerned RLDC shall be responsible for the scheduling, communication, coordination
with RE Generators of 50 MW and above and connected to Inter State Transmission System (ISTS).
Case-B: Lead generator shall be responsible for the coordination and communication with RLDC,
SLDC, RPC and other agencies for scheduling of RE Generators individually having less than 50
MW, but collectively having an aggregate installed capacity of 50 MW and above and connected
within the solar park.
(2) For Case-1, QCA shall be responsible for doing de-pooling of DSM charges as per the mutual agreement
between generators and QCA.
(3) For Case- 2 and Case- 3, where scheduling and accounting is to be coordinated by RLDC, a representative sketch
showing the scheduling is at Appendix-IV.
(4) The change of QCA would need a notice period of fifteen (15) days and the changeover shall take place with
effect from 0000 hours of a Monday, the first day of weekly settlement cycle.
(5) In case of any payment default by the QCA, the generators shall be liable to pay the DSM charges in proportion
to their MW capacity.
APPENDIX-I
Details to be submitted by the Wind/Solar generating stations which are regional entities/ lead generator, principal generator
Type: Wind/Solar Generator
Individual / on Behalf of Group of generators
If on Behalf of Group of generators group of thendetails of
agreement to be attached
Total Installed Capacity of Generating Station
Total Number of Units with details
Physical Address of the RE Generating Station
Whether any PPA has been signed: (Y/N) If yes ,then attach details
Connectivity Details Location/Voltage Level
Metering Details Meter No. 1. Main
2. Check
Connectivity Diagram (Please Enclose)
Static data As per attached sheet
Contact Details of the Nodal Person Name :
Designation :
Number: Landline Number, Mobile Number, Fax
Number
E - Mail Address :
Contact Details of the Alternate Nodal Person Name :
Designation :
Number: Landline Number, Mobile Number, Fax
Number
E - Mail Address :
Data to be submitted by the RE Generator / lead generator, principal generator for Wind turbine generating plants
S No Particulars
1 Type
2 Manufacturer
3 Make /Model
4 Capacity
5 COD
6 Hub height
7 Total height
8 RPM range
9 Rated wind speed
Performance Parameters
11 Rated electrical power at rated wind speed
12 Cut in speed
13 Cut out speed
14 Survival speed (Max wind speed)
15 Ambient temperature for out of operation
16 Ambient temperature for in operation
17 Survival temperature
18 Low Voltage Ride Through (LVRT) setting
19 High Voltage Ride Through (HVRT) setting
20 Lightning strength (KA & in coulombs)
21 Noise power level (db)
22 Rotor
23 Hub type
24 Rotor diameter
25 Number of blades
26 Area swept by blades
27 Rated rotational speed
28 Rotational Direction
29 Coning angle
30 Tilting angle
31 Design tip speed ratio
Blade
32 Length
33 Diameter
34 Material
35 Twist angle
Generator
36 Generator Type
37 Generator no of poles
38 Generator speed
39 Winding type
40 Rated Gen.Voltage
41 Rated Gen. frequency
42 Generator current
43 Rated Temperature of generator
44 Generator cooling
45 Generator power factor
46 KW/MW @ Rated Wind speed
47 KW/MW @ peak continuous
48 Frequency Converter
49 Filter generator side
50 Filter grid side
Transformer
51 Transformer capacity
52 Transformer cooling type
53 Voltage
54 Winding configuration
Weight
55 Rotor weight
56 Nacelle weight
57 Tower weight
58 Over speed Protection
59 Design Life
60 Design Standard
61 Latitude
62 Longitude
63 COD Details
64 Past Generation History from the COD to the date on which DAS facility provided at RLDC, if
applicable
65 Distance above mean sea level
For Solar generating Plants: Static data points:
1. Latitude
2. Longitude
3. Power Curve
4. Elevation and orientation angles of arrays or concentrators
5. The generation capacity of the Generating Facility
6. Distance above mean sea level etc.
7. COD details
8. Rated voltage
9. Details of Type of Mounting: (Tracking Technology If used, single axis or dual axis, auto or manual)
10. Manufacturer and Model (of Important Components, Such as Concentrators, Inverter, Cable, PV Module,
Transformer, Cables)
11. DC installed Capacity
12. Module Cell Technology
13. I-V Characteristic of the Module
14. Inverter Rating at different temperature
15. Inverter Efficiency Curve
16. Transformer Capacity & Rating, evacuation voltage, distance form injection point
Appendix-II
Forecast and Schedule Data to be submitted by QCA, generator-wise
FORMAT: A (to be submitted a day in advance)
15 Min time block (96 Block TIME Available Capacity Day Ahead Day Ahead
ina day) (MW) - DayAhead Forecast Schedule
(MW)
(MW)
1 00:00-00:15
2 00:15-00:30
3 00:30-00:45
4 00:45-01:00
.
Note: The forecast should ideally factor forecasting errors. As such schedule should ordinarily be same as forecast.
FORMAT: B (to be submitted on the day of actual generation, revision of availability and schedule, if
any, shall be done as per this Grid Code.
15 Min time block (96 Block TIME Day ahead Current Revised
in a day) schedule Available Schedule
(MW) Capacity (MW)
(MW)
1 00:00-00:15
2 00:15-00:30
3 00:30-00:45
4 00:45-01:00
.
APPENDIX-III
Real-time Data Telemetry requirement (Suggested List)
Wind turbine generating plants
1. Turbine Generation (MW/MVAR)
2. Wind Speed(meter/second)
3. Generator Status (on/off-line)- this is required for calculation of availability of the WTG
4. Wind Direction ( degrees from true north)
5. Voltage(Volt)
6. Ambient air temperature ( o C )
7. Barometric pressure (Pascal)
8. Relative humidity(in percent)
9. Air Density (kg/m3)
For Solar generating Plant s
1. Solar Generation unit/ Inverter-wise ( MW and MVAR )
2. Voltage at interconnection point (Volt)
3. Generator/Inverter Status (on/off-line)
4. Global horizontal irradiance (GHI)- Watt per meter square
5. Ambient temperature ( oC)
6. Diffuse Irradiance- Watt per meter square
7. Direct Irradiance- Watt per meter square
8. Sun-rise and sunset timings
9. Cloud cover-(Okta)
10. Rainfall (mm)
11. Relative humidity (%)
12. Performance Ratio
APPENDIX-IV
Block Diagram showing the case wise Scheduling and Forecasting considering a sample case
Case-I (QCA responsible for all generators):
(a) Suppose an REGS of 1000 MW capacity is developed in four blocks namely A,B,C & D of 250 MW capacity
each and is directly connected to point A1,B1,C1& D1 respectively at ISTS. Let REGSs of 50 MW each
aggregating to 250 MW (5 Nos. namely E, F, G, H & I) be connected to intermediate pooling station. REGSs
are connected to interface point E1, F1, G1, H1& I1 and thereby connected to ISTS at XX point.
(b) Suppose all the REGSs have mutually agreed to appoint a QCA for all scheduling and forecasting activities,
such QCA, shall be responsible for carrying out activities as assigned under this Code.
Case-2 (QCA responsible for some of the generators):
A. QCA is responsible for all REGS connected at Intermediate pooling station
B. QCA responsible for some REGS connected at Intermediate pooling station
In each of the above scenarios, the QCA shall be responsible for coordination of scheduling and de-pooling of DSM charges for all those
REGS that mutually agreed to appoint a QCA. The other REGS shall be required to submit their schedule as well as be liable to pay their
DSM charges.
Case-3: 50 MW and above (Phase-I &II)
A single generator of 1000 MW capacity is developing the generating station in phase-1 in four blocks namely A,B,C
& D of 250 MW capacity each and is directly connected to point A1,B1,C1& D1 respectively at ISTS. At the interface
point scheduling and forecasting shall be done by RLDC.
Phase-II- 500 MW (Separate Generator/Entities)
(a) Let multiple REGS of 50 MW each aggregating to 250 MW (5 Nos. Multiple Generator of 50 Mw each (as
separate entities), be connected to inter mediate pooling stations.
(b) REGS namely E, F, G, H & I each having the capacity of 50 MW each are connected to interface point E1, F1,
G1, H1& I1 and thereby connected to ISTS at XX point.
(c) In such a case, scheduling, accounting, forecasting for these generators needs to be segregated at point E1,
F1,G1, H1, I1. Scheduling shall be done at point P and shall be segregated at E1,F1,G1,H1,I1 by RLDC.
(d) Further there may be case where multiple generators less than 50MW (<50MW) capacity are connected to the
intermediate pooling station are stated as under:-
Case-II Below 50 MW
(e) Let us consider, multiple REGS (namely J,K,L,M,N,O&P ) collectively having an aggregate installed
capacity of 50 MW or more and are represented through a Lead Generator. Further REGS Q & R each of 100
MW are connected at Q1 & R1. All these REGS are connected to ISTS at point Z1.
(f) Scheduling and forecasting for the REGSs J,K,L,M,N,O& P shall be done at Point Z1, but need to segregated
at Point J1, K1,L1, M1, N1,O1& P1 and for REGSs Q & R needs to be segregated at Q1 and R1. In this case,
RLDC shall schedule at point Z1 and segregate at Y1,Q1& R1 . The lead generator shall provide aggregated
schedule to RLDC at Y1. Further the lead generator shall do segregation of schedules and other operational
& commercial activities for generators J,K,L,M,N,O,P at points J1, K1,L1, M1, N1,O1& P1.
ANNEXURE- 7
ACCOUNTING AND POOL SETTLEMENT SYSTEM
(1) METERING, ACCOUNTING AND SETTLEMENT SYSTEM:
(a) At the Inter State Transmission System (ISTS) level, the basic principle followed is that all settlements for
the energy scheduled before the fact are done directly between the sellers and the buyers , with the
Regional Power Committee issuing the Accounts specifying the quantum of energy scheduled. All
deviations from the schedule are settled through a regulatory Pool Account maintained by RLDCs where
only the deviation payments are handled.
(b) The settlement system shall be transparent, robust, scale-able (multi buyer/seller, inter connection with
lower and upper pool systems) and dispute-free with integrity and probity and usage of state of the art
techniques. The settlement computation details, applicable charges and operation of different regulatory
Pool Accounts shall be in accordance with various regulations of the Commission. RPCs shall standardise
the formats of various accounts.
(c) The Implemented Schedule incorporating all before-the-fact changes in schedule shall be used as a
reference for energy accounting.
(d) Energy Accounts inter-alia shall indicate Declared Capability of generating stations, Entitlements,
Requisitions, Scheduled loss, Scheduled transactions GNA and T-GNA and actual Interchange, Reactive
Power Accounts, SCED scheduled energy and any other accounts to be issued under CERC Regulations.
(e) Assumptions, if any, in the accounts shall be clearly stated in Notes to the Accounts.
(f) Each regional entity (whether generator, RE Generator, QCA (on behalf of generators), captive Power
Plant, OA customer connected at ISTS) in a region shall be a member of the regional pool and separately
accountable for deviations. For cross border transactions, the Settlement Nodal Agency (SNA) as
appointed by the Government of India would be a member of the regional pool.
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