Logo of the Central Electricity Regulatory Commission (CERC). The logo is circular with a black border. Inside the border, the text 'C. E. R. C.' is written in a semi-circle at the bottom. At the top, there is a Sanskrit motto. In the center, there is a stylized black and white illustration of a balance scale, symbolizing justice and regulation.
Central Electricity Regulatory Commission
3rd & 4th Floor, Chanderlok Building,
36, Janpath, New Delhi- 110001
Web- www.cercind.gov.in
Ph: 91-11-23353503 Fax: 91-11-23753923
| Clause | Title | Page No. |
|---|---|---|
| Glossary and Definitions | 1 | |
| Chapter 1: | General | |
| 1.1 | Introduction | 8 |
| 1.2 | Objective | 8 |
| 1.3 | Scope | 9 |
| 1.4 | Structure of the IEGC | 9 |
| 1.5 | Non-Compliance | 11 |
| Chapter 2 : Role of various Organizations and their linkages | ||
| 2.1 | Introduction | 13 |
| 2.2 | Role of NLDC | 13 |
| 2.3 | Role of RLDC | 14 |
| 2.4 | Role of RPC | 15 |
| 2.5 | Role of CTU | 16 |
| 2.6 | Role of CEA | 17 |
| 2.7 | Role of SLDC | 18 |
| 2.8 | Role of STU | 18 |
| Chapter 3: Planning Code for Inter State Transmission | ||
| 3.1 | Introduction | 20 |
| 3.2 | Objective | 21 |
| 3.3 | Scope | 21 |
| 3.4 | Planning Philosophy | 21 |
| 3.5 | Planning Criterion | 23 |
| 3.6 | Planning Data | 24 |
| 3.7 | Implementation of Transmission Plan | 24 |
| Chapter 4 : Connection Code | ||
| 4.1 | Introduction | 25 |
| 4.2 | Objective | 25 |
| 4.3 | Scope | 25 |
| 4.4 | Procedure for Connection | 26 |
| 4.5 | Connection Agreement | 26 |
| 4.6 | Important Technical Requirements for Connectivity to the Grid | 26 |
| 4.7 | International Connections to ISTS | 28 |
| 4.8 | Schedule of Assets of Regional Grid | 29 |
| 4.9 | Connectivity of Renewable Energy Generating Stations to the Grid | 29 |
| 5.1 | Operating Philosophy | 33 |
| 5.2 | System Security Aspects | 34 |
| 5.3 | Demand Estimation for Operational Purposes | 39 |
| 5.4 | Demand Management | 39 |
| 5.5 | Periodic Reports | 41 |
| 5.6 | Operational Liaison | 42 |
| 5.7 | Outage Planning | 43 |
| 5.8 | Recovery Procedures | 45 |
| 5.9 | Event Information | 46 |
| 6.1 | Introduction | 48 |
| 6.2 | Objective | 48 |
| 6.3 | Scope | 48 |
| 6.4 | Demarcation of Responsibilities | 49 |
| 6.5 | Scheduling and Despatch procedures | 55 |
| 6.6 | Reactive Power and Voltage Control | 61 |
| Sl. | Item | Definition |
|---|---|---|
| 1 | Act | The Electricity Act, 2003 as amended from time to time. |
| 2 | Ancillary Services | "Ancillary Services" in power system (or grid) operation means support services necessary to support the power system (or grid) operation in maintaining power quality, reliability and security of the grid, eg. active power support for load following, reactive power support, black start, etc |
| 3 | Automatic Voltage Regulator (AVR) | A continuously acting automatic excitation control system to control the voltage of a Generating Unit measured at the generator terminals. |
| 4 | Available Transmission Capability (ATC) | The transfer capability of the inter-control area transmission system available for scheduling commercial transactions (through long term access, medium term open access and short term open access) in a specific direction, taking into account the network security. Mathematically ATC is the Total Transfer Capability less Transmission Reliability Margin. |
| 5 | Beneficiary | A person who has a share in an ISGS is beneficiary of the respective ISGS. |
| 6 | Bilateral Transaction | A transaction for exchange of energy (MWh) between a specified buyer and a specified seller, directly or through a trading licensee or discovered at power exchange through anonymous bidding, from a specified point of injection to a specified point of drawal for a fixed or varying quantum of power (MW) for any time period during a month |
| 7 | Black Start Procedure | The procedure necessary to recover from a partial or a total blackout. |
| 8 | Bulk Power Transmission Agreement (BPTA) | The commercial agreement between the transmission licensee and a long term customer for the provision of transmission services. |
| 9 | BIS | The Bureau of Indian Standards. |
| 10 | Capacitor | An electrical facility provided for generation of reactive power. |
| 11 | Capacity factor | The ratio of maximum generation in MW to sum of installed capacity of individual WTGs in the Wind Farm |
| 12 | Central Generating Station | The generating stations owned by the companies owned or controlled by the Central Government |
| 13 | Central Transmission Utility (CTU) | Central Transmission Utility means any Government company, which the Central Government may notify under sub-section (1) of Section 38 of the Act. |
| 14 | Collective Transaction | A set of transactions discovered in power exchange through anonymous, simultaneous competitive bidding by buyers and sellers |
| 15 | Congestion | "Congestion" means a situation where the demand for transmission capacity exceeds the Available Transmission Capability; |
| 16 | Connection Agreement | An Agreement between CTU, inter-state transmission licensee other than CTU (if any) and any person setting out the terms relating to a connection to and/or use of the Inter State Transmission System. |
| 17 | Connection Point | A point at which a Plant and/ or Apparatus connects to the Transmission /Distribution System. |
| 18 | Connectivity | For a generating station, including a captive generating plant, a bulk consumer or an inter-State transmission licensee means the state of getting connected to the inter-State transmission system; |
| 19 | Control Area | A control area is an electrical system bounded by interconnections (tie lines), metering and telemetry which controls its generation and/or load to maintain its interchange schedule with other control areas whenever required to do so and contributes to frequency regulation of the synchronously operating system. |
| 20 | Demand | The demand of Active Power in MW and Reactive Power in MVAR of electricity unless otherwise stated. |
| 21 | Demand response | Reduction in electricity usage by end customers from their normal consumption pattern, manually or automatically, in response to high UI charges being incurred by the State due to overdrawal by the State at low frequency, or in response to congestion charges being incurred by the State for creating transmission congestion, or for alleviating a system contingency, for which such consumers could be given a financial incentive or lower tariff |
| 22 | Despatch Schedule | The ex-power plant net MW and MWh output of a generating station, scheduled to be exported to the Grid from time to time. |
| 23 | Disturbance Recorder (DR) | A device provided to record the behaviour of the pre-selected digital and analog values of the system parameters during an Event. |
| 24 | Data Acquisition System (DAS) | A device provided to record the sequence of operation in time, of the relays/equipments/system parameters at a location. |
| 25 | Drawal Schedule | The summation of the station-wise ex-power plant |
| drawal schedules from all ISGS and drawal from regional grid consequent to other long term access, medium term and short term open access transactions. | ||
| 26 | DVC | The Damodar Valley Corporation established under sub-section (1) of Section 3 of the Damodar Valley Corporation Act, 1948. |
| 27 | Entitlement | Share of a beneficiary (in MW / MWh) in the installed capacity/output capability of an ISGS. |
| 28 | Event | An unscheduled or unplanned occurrence on a Grid including faults, incidents and breakdowns. |
| 29 | Event Logging Facilities | A device provided to record the chronological sequence of operations, of the relays and other equipment. |
| 30 | Ex-Power Plant | Net MW/MWh output of a generating station, after deducting auxiliary consumption and transformation losses. |
| 31 | Fault Locator (FL) | A device provided at the end of a transmission line to measure/ indicate the distance at which a line fault may have occurred. |
| 32 | Flexible Alternating Current Transmission System(FACTS) | A power electronic based system and other static equipment that provide control of one or more AC transmission system parameters to enhance controllability and increase power transfer capability. |
| 33 | Force Majeure | Any event which is beyond the control of the persons involved which they could not foresee or with a reasonable amount of diligence could not have foreseen or which could not be prevented and which substantially affect the performance by person such as but not limited to :- a) Acts of God, natural phenomena, including but not limited to floods, droughts, earthquakes and epidemics; b) Acts of any Government domestic or foreign, including but not limited to war declared or undeclared, hostilities, priorities, quarantines, embargoes; c) Riot or Civil Commotion d) Grid's failure not attributable to the person. |
| 34 | Forced Outage | An outage of a Generating Unit or a transmission facility due to a fault or other reasons which has not been planned. |
| 35 | Generating Company | Generating Company means any company or body corporate or association or body of individuals, whether incorporated or not, or artificial juridical person, which owns or operates or maintains a generating station. |
| 36 | Generating Unit | An electrical Generating Unit coupled to a turbine within a Power Station together with all Plant and |
| Apparatus at that Power Station which relates exclusively to the operation of that turbo-generator. | ||
| 37 | Good Utility Practices | Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period which could have been expected to accomplish the desired results at a reasonable cost consistent with good business practices, reliably, safely and with expedition. |
| 38 | Governor Droop | In relation to the operation of the governor of a Generating Unit, the percentage drop in system frequency which would cause the Generating Unit under restricted/free governor action to change its output from zero to full load. |
| 39 | Grid Standards | Grid Standards specified by the Authority under clause (d) of the Section 73 of the Act. |
| 40 | Extra High Voltage (EHV) | Where the voltage exceeds 33,000 volts under normal conditions, subject, however, to the percentage variation allowed by the Authority. |
| 41 | Independent Power Producer (IPP) | A generating company not owned/ controlled by the Central/State Government. |
| 42 | Indian Electricity Grid Code (IEGC) or Grid Code | Regulation describing the philosophy and the responsibilities for planning and operation of Indian power system specified by the Commission in accordance with sub section 1(h) of Section 79 of the Act. |
| 43 | Inter-State Generating Station (ISGS) | A Central generating station or other generating station, in which two or more states have shares |
| 44 | Inter State Transmission System (ISTS) | Inter-State Transmission System includes i) Any system for the conveyance of electricity by means of a main transmission line from the territory of one State to another State ii) The conveyance of energy across the territory of an intervening State as well as conveyance within the State which is incidental to such inter-state transmission of energy (iii) The transmission of electricity within the territory of State on a system built, owned, operated, maintained or controlled by CTU. |
| 45 | IEC | The International Electro technical Commission. |
| 46 | Licensee | Licensee means a person who has been granted a license under Section 14 of the Act. |
| 47 | Load | The MW/MWh consumed by a utility/ installation. |
| 48 | Long –term Access | The right to use the inter-State transmission system for a period exceeding 12 years but not exceeding 25 years |
| 49 | Long-term customer | A person who has been granted long-term access and includes a person who has been allocated |
| central sector generation that is electricity supply from a generating station owned or controlled by the Central Government | ||
| 50 | Maximum Continuous Rating (MCR) | The maximum continuous output in MW at the generator terminals guaranteed by the manufacturer at rated parameters. |
| 51 | Medium-term Open Access | The right to use the inter- State transmission system for a period exceeding 3 months but not exceeding 3 years |
| 52 | Medium-term customer | A person who has been granted medium-term open access |
| 53 | Multi –part tariff | Tariff with at least two components of tariff , viz. capacity charge and energy charge |
| 54 | National Grid | 'National Grid' means the entire inter-connected electric power network of the country |
| 55 | Net Drawal Schedule | The drawal schedule of a beneficiary after deducting the apportioned transmission losses (estimated). |
| 56 | NLDC | 'National Load Despatch Centre' means the Centre established under sub-section (1) of Section 26 of the Act |
| 57 | Operation | A scheduled or planned action relating to the operation of a System. |
| 58 | Operation Co-ordination Sub-Committee (OCC) | A sub-committee of RPC with members from all the regional entities which decides the operational aspects of the Regional Grid. |
| 59 | Operating range | The operating range of frequency and voltage as specified under the operating code (Chapter-5) |
| 60 | Pool Account | Regional account for (i) payments regarding unscheduled-interchanges (UI Account) or (ii) reactive energy exchanges (Reactive Energy Account) (iii) Congestion Charge (iv) Renewable Regulatory charge, as the case may be |
| 61 | POWERGRID | Power Grid Corporation of India Limited which has been notified as CTU. |
| 62 | Power Exchange | 'Power Exchange' means the power exchange which have been granted registration in accordance with CERC Power Market Regulations, 2010 and as amended from time to time |
| 63 | Power System | Power System means all aspects of generation, transmission, distribution and supply of electricity and includes one or more of the following, namely: (a) generating stations; (b) transmission or main transmission lines; (c) sub-stations; (d) tie-lines; (e) load despatch activities; |
| (f) mains or distribution mains; (g) electric supply lines; (h) overhead lines; (i) service lines; (j) works. |
||
| 64 | Reactor | An electrical facility specifically designed to absorb Reactive Power. |
| 65 | Regional Entity | 'Regional entity' means such persons who are in RLDC control area and whose metering and energy accounting is done at the regional level. |
| 66 | Regional Power Committee (RPC) | "Regional Power Committee" means a Committee established by resolution by the Central Government for a specific region for facilitating the integrated operation of the power systems in that region. |
| 67 | RPC Secretariat | The Secretariat of the RPC. |
| 68 | Regional Energy Account (REA) | A regional energy account, for the billing and settlement of 'Capacity Charge', 'Energy Charge', 'UI Charge' and 'Reactive Charge'. |
| 69 | Regional Grid | The entire synchronously connected electric power network of the concerned Region. |
| 70 | Regional Load Despatch Centre (RLDC) | 'Regional Load Despatch Centre' means the Centre established under sub-section (1) of Section 27 of the Act. |
| 71 | Share | Percentage share of a beneficiary in an ISGS either notified by Government of India or agreed through contracts and implemented through long term access |
| 72 | Short-term Open Access | Open Access for a period up to one (1) month at one time |
| 73 | Spinning Reserve | Part loaded generating capacity with some reserve margin that is synchronized to the system and is ready to provide increased generation at short notice pursuant to despatch instruction or instantaneously in response to a frequency drop. |
| 74 | Standing Committee for Transmission Planning | A Committee constituted by the CEA to discuss, review and finalise the proposals for expansion or modification in the ISTS and associated intra-state systems. |
| 75 | SEB | The State Electricity Board including the State Electricity Department. |
| 76 | SERC | State Electricity Regulatory Commission |
| 77 | State Load Despatch Centre (SLDC) | 'State Load Despatch Centre' means the Centre established under subsection (1) of Section 31 of the Act. |
| 78 | State Transmission | 'State Transmission Utility' means the Board or the Government Company specified as such by the |
| Utility (STU) | State Government under sub-section (1) of Section 39 of the Act. | |
| 79 | Static VAR Compensator (SVC) | An electrical facility designed for the purpose of generating or absorbing Reactive Power. |
| 80 | Technical Co-ordination Committee (TCC) | The committee set up by RPC to coordinate the technical and commercial aspects of the operation of the regional grid. |
| 81 | Time Block | Block of 15 minutes each for which Special Energy Meters record values of specified electrical parameters with first time block starting at 00.00 Hrs. |
| 82 | Total Transfer Capability (TTC) | 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. |
| 83 | Transmission License | A License granted under Section 14 of the Act to transmit electricity. |
| 84 | Transmission Planning Criteria | The policy, standards and guidelines issued by the CEA for the planning and design of the Transmission system. |
| 85 | Transmission Reliability Margin (TRM) | The amount of margin kept in the total transfer capability necessary to ensure that the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions |
| 86 | Unscheduled Interchange (UI) | In a time block for a generating station or a seller means its total actual generation minus its total scheduled generation and for a beneficiary or buyer means its total actual drawal minus its total scheduled drawal |
| 87 | User | A person such as a Generating Company including Captive Generating Plant or Transmission Licensee (other than the Central Transmission Utility and State State Transmission utility) or Distribution Licensee or Bulk Consumer, whose electrical plant is connected to the ISTS at a voltage level 33kV and above. |
The Indian Power System is a conglomeration of a number of agencies. Power system means all aspects of generation, transmission, distribution and supply of electricity and includes one or more of the following, namely:-
The Indian Electricity Grid Code (IEGC) is a regulation made by the Central Commission in exercise of powers under clause (h) of sub-section (1) of Section 79 read with clause (g) of sub-section (2) of Section 178 of the Act. The IEGC also lays down the rules, guidelines and standards to be followed by various persons and participants in the system to plan, develop, maintain and operate the power system, in the most secure, reliable, economic and efficient manner, while facilitating healthy competition in the generation and supply of electricity.
The IEGC brings together a single set of technical and commercial rules, encompassing all the Utilities connected to/or using the inter-State transmission system (ISTS) and provides the following:
common basis of operation of the ISTS, applicable to all the Users of the ISTS.
This IEGC contains the following:
This chapter contains objective and Scope etc of IEGC
This chapter defines the functions of the various Organizations as are relevant to IEGC.
This Chapter provides the guidelines to be adopted in the planning and development of bulk power transfer and associated ISTS. The Planning Code lays out the detailed information exchange required between the planning agencies and the various participants of the power system for load forecasting, generation availability, and power system planning etc. for the future years under study. The Planning Code stipulates the various criteria to be adopted during the planning process.
This chapter specifies minimum technical and design criteria to be complied with by any user, STU and CTU connected to the system or seeking connection to the ISTS, to maintain uniformity and quality across the system. This includes procedure for connection to the ISTS
This Chapter describes the operational philosophy to maintain efficient, secure and reliable Grid Operation and contains the following sections.
This section describes the general security aspects to be followed by generating companies and all Regional Entities of the Grid.
This section details the procedures to estimate the demand by the distribution licensees for their systems / SLDCs in their control area for the day/week/month/year ahead, which shall be used for operational planning.
This section identifies the methodology to be adopted for demand control by each SEB/SLDC/Distribution Licensee/ bulk consumer depending on frequency of the grid and power shortage.
This section provides various provisions for reporting of the operating parameters of the grid such as frequency profile etc.
This section sets out the requirement for the exchange of information in relation to normal operation and/or events in the grid.
This section indicates procedure for outage planning.
This section contains the procedures to be adopted following a major grid disturbance, for black start and resynchronization of islands, etc.
This section indicates the procedure by which events are reported and the related information exchange requirements etc.
This section deals with the procedure to be adopted for scheduling and Despatch of generation of the Inter-State Generating Stations (ISGS) and scheduling for other transactions through long-term access, medium-term and short-term open access including complementary commercial mechanisms, on a day-ahead and intra-day basis with the process of the flow of information between the ISGS, National Load Despatch Centre (NLDC), Regional Load Despatch Centre (RLDC), Power Exchanges and the State Load Despatch Centres (SLDCs), and other concerned persons .
(i) The Regional Power Committee (RPC) in the region shall continuously monitor the instances of non-compliance of the provisions of IEGC and deliberate on the ways in which such cases of non-compliance are prevented in future by building consensus.
(ii) RLDCs shall report to the Commission, through petition, instances of serious violation of any of the provisions of the IEGC and incidences of persistent non-compliance of the directions of the RLDCs issued in order to exercise supervision and control required for ensuring stability of grid operations and for achieving the maximum economy and efficiency in the operation of the power system in the region under its control.
(iii) The Commission may initiate appropriate proceedings upon
receipt of report of RLDCs referred to in (ii) above.
(iv) In case of non-compliance of any provisions of the IEGC by NLDC, RLDC, SLDC or RPC, the matter may be reported by any person to the CERC through petition.
(v) Notwithstanding anything contained in other clauses of this regulation, the Commission, may also take suo-motu action against any person, in case of non-compliance of any provisions of the IEGC.
2.2.1 According to notification dated 2nd March 2005, by the Ministry of Power, Government of India, under Section 26(2) of the Act NLDC has following functions. This would also include such other functions assigned by the Government of India through resolutions issued from time to time:
(a) supervision over the Regional Load Despatch Centers.
(b) scheduling and despatch of electricity over inter-regional links in accordance with grid standards specified by the Authority and grid code specified by Central Commission in coordination with Regional Load Despatch Centers.
(c) coordination with Regional Load Despatch Centers for achieving maximum economy and efficiency in the operation of National Grid.
(d) monitoring of operations and grid security of the National Grid.
(e) supervision and control over the inter-regional links as shall be required for ensuring stability of the power system under its control.
(f) coordination with Regional Power Committees for regional outage schedule in the national perspective to ensure optimal utilization of power resources.
(g) coordination with Regional Load Despatch Centers for the energy accounting of inter-regional exchange of power.
(h) coordination for restoration of synchronous operation of national grid with Regional Load Despatch Centers.
(i) coordination for trans-national exchange of power.
(j) providing operational feed back for national grid planning to the Authority and the Central Transmission Utility.
(k) levy and collection of such fee and charges from the generating companies or licensees involved in the power system, as shall be specified by the Central Commission.
(l) dissemination of information relating to operations of transmission system in accordance with directions or regulations issued by Central Electricity Regulatory Commission and the Central Government from time to time."
2.3.1 According to sections 28 and 29 of Electricity Act, 2003, the functions of RLDCs are as follows:
safe, secure and integrated operation of the regional grid or in relation to any direction given by the Regional Load Despatch Centre, it shall be referred to Central Commission for decision. However, pending the decision of the Central Commission, the directions of the Regional Load Despatch Centre shall be complied with by the State Load Despatch Centre or the licensee or the generating company, as the case may be.
coordinate planning of maintenance of generating machines of various generating companies of the region including those of interstate generating companies supplying electricity to the Region on annual basis and also to undertake review of maintenance programmed on monthly basis.
2.5.1 In accordance with the section 38 of Electricity Act, 2003, the functions of the Central Transmission Utility (CTU) shall be –
(1) (a) to undertake transmission of electricity through inter-State transmission system;
(b) to discharge all functions of planning and co-ordination relating to inter-State transmission system with-
(c) to ensure development of an efficient, co-ordinated and economical system of inter-State transmission lines for smooth flow of electricity from generating stations to the load centres;
(d) to provide non-discriminatory open access to its transmission system for use by-
i) any licensee or generating company on payment of the transmission charges; or
(2) Until a Government company or authority or corporation is notified by the Central Government, the Central Transmission Utility shall operate the Regional Load Despatch Centre.
2.5.2 CTU shall not engage in the business of generation of electricity or trading in electricity.
2.5.3 In case of Inter-state Transmission System, Central Transmission Utility shall be the nodal agency for the connectivity, long-term access and medium –term open access . The procedure formulated by CTU and approved by CERC and modalities in regard to connectivity, long-term access and medium-term open access shall be in accordance with the Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-State Transmission and related matters) Regulations, 2009, as amended from time to time.
Investigation for the purposes of generating or transmitting or distributing electricity.
2.7.1 In accordance with section 32 of Electricity Act, 2003, the State Load Despatch Centre (SLDC) shall have following functions:
2.7.2 In accordance with section 33 of the Electricity Act, 2003, the State Load Despatch Centre in a State may give such directions and exercise such supervision and control as may be required for ensuring the integrated grid operations and for achieving the maximum economy and efficiency in the operation of power system in that State. Every licensee, generating company, generating station, sub-station and any other person connected with the operation of the power system shall comply with the directions issued by the State Load Despatch Centre under sub-section (1) of Section 33 of the Electricity Act, 2003. 2.7.3 The State Load Despatch Centre shall comply with the directions of the Regional Load Despatch Centre.
2.7.3 In case of inter-state bilateral and collective short-term open access transactions having a state utility or an intra-state entity as a buyer or a seller, SLDC shall accord concurrence or no objection or a prior standing clearance, as the case may be, in accordance with the Central Electricity Regulatory Commission (Open Access in inter-state Transmission) Regulations, 2008, amended from time to time.
2.8.1 Section 39 of the Electricity Act, 2003, outlines that the functions of the
State Transmission Utility (STU) shall be –
This Chapter comprises various aspects of Planning relating to Inter-State transmission systems.
i) In accordance with Section 38(2)(b) of Electricity Act, 2003, the Central Transmission Utility (CTU) shall discharge all functions of planning and co-ordination relating to inter-State transmission system in coordination with State Transmission Utility, Central Government, State Governments, Generating Companies, Regional Power Committees, Central Electricity Authority (CEA), licensees and any other person notified by the Central Government in this behalf.
ii) In accordance with Section 38(2)(d) of Electricity Act, 2003, the Central Transmission Utility (CTU) shall inter-alia provide non-discriminatory open access to its transmission system for use by
iii) Similarly, in accordance with Section 39(2)(b) of Electricity Act, 2003, the State Transmission Utilities (STUs) shall discharge all functions of planning and coordination relating to intra-State transmission system with Central Transmission Utility, State Governments, Generating Companies, Regional Power Committees, Central Electricity Authority (CEA), licensees and any other person notified by the State Government in this behalf.
iv) In accordance with Section 39(2)(d) of Electricity Act, 2003, the State Transmission Utility (STU) shall inter-alia provide non-discriminatory open access to its transmission system for use by –
v) In accordance with Section 40 of Electricity Act, 2003, the transmission licensee shall inter-alia provide non-discriminatory open access to its transmission system for use by
(a) any licensee or generating company on payment of the transmission charges; or
vi) In accordance with Section 3 (4) of Electricity Act, 2003, CEA shall inter-alia prepare a National Electricity Plan in accordance with the National Electricity Policy and notify such plan once in five (5) years. In accordance with Section 3 (5) of Electricity Act, 2003, CEA may review or revise the National Electricity Plan in accordance with the National Electricity Policy.
The objectives of Planning Code are as follows:
The Planning Code applies to CTU, other Transmission licensees, Inter-State Generating Station (ISGS), connected to and/or using and involved in developing the ISTS. This Planning Code also applies to Generating Companies, IPPs, SEBs/STUs and /licensees, regarding generation and/or transmission of energy to/from the ISTS.
updated to take care of the revisions in load projections and generation scenarios considering the seasonal and the time of the day variations.
(b) The CTU shall carry out planning process from time to time as per the requirement for identification of major inter-State transmission system including inter-regional schemes which shall fit in with the perspective plan developed by CEA. While planning schemes, the following shall be considered in addition to the data of authenticated nature collected from and in consultation with users by CTU:
(c) Addition in transmission system shall be planned in accordance with the Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-state Transmission and related matters) Regulations ,2009.
(d) In addition to the major inter-State transmission system, the CTU shall plan, from time to time, system strengthening schemes, need of which may arise to overcome the constraints in power transfer and to improve the overall performance of the grid. The inter-State transmission proposals including system strengthening scheme identified on the basis of the planning studies would be discussed, reviewed and finalized in the meetings of Regional Standing Committees for Transmission Planning constituted by CEA, in consultation with the Regional entities, RPC, CEA and the RLDC and action may be taken by CTU on the basis of Power Purchase Agreements (PPAs) signed with the beneficiaries. In cases where PPAs have not yet been signed, CTU may approach CERC for the regulatory approval in accordance with Central Electricity Regulatory Commission (Grant of Regulatory Approval for Capital Investment to CTU for execution of Inter-State Transmission Scheme) Regulations, 2010 .
(e) All , STUs and users will supply to the CTU, the desired planning data from time to time to enable to formulate and finalize its plan.
(f) As voltage management plays an important role in inter-state transmission of energy, special attention shall be accorded, by CTU, for planning of capacitors, reactors, SVC and Flexible Alternating Current Transmission Systems (FACTS), etc. Similar exercise shall be done by STU for intra-State transmission system to optimize the utilisation of the integrated transmission network.
(g) Based on Plans prepared by the CTU, State Transmission Utilities (STU) shall have to plan their systems to further evacuate power from the ISTS and to optimize the use of integrated transmission network.
(h) In case Long Term Access Applications require any strengthening in the intra-State transmission system to absorb/evacuate power beyond ISTS, the applicant shall coordinate with the concerned STU. STU shall augment the intra-state transmission system in a reasonable time to facilitate the interchange of such power.
(i) The Inter-State Transmission System and associated intra-State transmission system are complementary and inter-dependent and planning of one affects the other's planning and performance. Therefore, the associated intra-State transmission system shall also be discussed and reviewed before implementation during the discussion for finalizing ISTS proposal indicated at 3.4 (c) above.
single system infeed without loss of stability.
Detailed planning data consist of additional, more detailed data not normally expected to be required by CTU to assess the impact of User development on the ISTS. This data shall be furnished by the Users of ISTS as and when requested by CTU.
The actual program of implementation of transmission lines, Inter-connecting Transformers, reactors/capacitors and other transmission elements will be determined by CTU in consultation with the concerned users and STUs. The completion of these works, in the required time frame, shall be ensured by CTU through the concerned persons
CTU, STU and users connected to, or seeking connection to ISTS shall comply with Central Electricity Authority (Technical Standards for connectivity to the Grid) Regulations, 2007 which specifies the minimum technical and design criteria and Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-state Transmission and related matters) Regulations, 2009. Connection Code given in the subsequent clauses of this chapter specify some of the essential features of the above two referred regulations.
The Connection Code also covers some of the technical standards for connection to the grid of wind and solar generating facilities, so far not covered under the CEA (Technical Standards for connectivity to the Grid). As and when the CEA notifies Technical Standards for connectivity to the grid for such sources of power, those would prevail. Most of the wind and solar energy sources are presently connected and in future are likely to be connected to the STU or the State's distribution utility. However, keeping in view the variable nature of generation from such sources and the effect such variability has on the grid at large, and in view of the large-scale integration of such sources into the grid envisaged in view of the Government of India's thrust on renewable sources of energy, technical standards for connectivity of these sources, which would be the same whether connected to the State power system or to the ISTS, have been specified in this Connection Code.
The objective of the code is as given below::
The Connection code applies to CTU,STU and all users connected to or seeking connection to the ISTS and wind and solar generating stations connected to or seeking connectivity to the ISTS or STU or State distribution system. The Connection conditions does not apply to Generating Units embedded in the intra-State systems, and not connected to the ISTS. All distribution utilities shall also abide by the CEA (Technical Standards for connectivity to the Grid) Regulations,2007, in order to ensure that the integrated grid is not adversely affected.
The CTU shall process the application for grant of connectivity in accordance with these regulations
Connection agreement shall be signed by the applicant in accordance with the Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-state Transmission and related matters) Regulations,2009. This agreement includes, among others:
reliability, selectivity and sensitivity.
The fault clearance time when all equipments operate correctly, for a three phase fault (close to the bus-bars) on user's/STU's/CTU's equipment directly connected to ISTS and for a three phase fault (close to the bus-bars) on ISTS connected to user's equipment, shall not be more than
by STUs, and users connected to ISTS as far as possible in the low voltage systems close to the load points thereby avoiding the need for exchange of Reactive Power to/from ISTS and to maintain ISTS voltage within the specified range.
Reliable and efficient speech and data communication systems shall be provided to facilitate necessary communication and data exchange, and supervision/control of the grid by the RLDC, under normal and abnormal conditions. All users, STUs and CTU shall provide Systems to telemeter power system parameter such as flow, voltage and status of switches/ transformer taps etc. in line with interface requirements and other guideline made available by RLDC. The associated communication system to facilitate data flow up to appropriate data collection point on CTU's system, shall also be established by the concerned user or STU as specified by CTU in Connection Agreement. All users/STUs in coordination with CTU shall provide the required facilities at their respective ends as specified in the Connection Agreement.
Recording instruments such as Data Acquisition System/Disturbance Recorder/Event Logging Facilities/Fault Locator (including time synchronization equipment) shall be provided and shall always be kept in working condition in the ISTS for recording of dynamic performance of the system. All users, STUs and CTU shall provide all the requisite recording instruments and shall always keep them in working condition..
CTU/STU and the concerned users shall be responsible for safety in accordance with Central Electricity Authority (Technical Standards for connectivity to the Grid) Regulations, 2007 , Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-state Transmission and related matters) Regulations, 2008 and CEA (Safety Requirements for construction, operation and maintenance of electrical and electric lines) Regulations, 2008..
The procedure for international Connection to ISTS and the execution of agreement for the same shall be determined by CTU in consultation with CEA and Ministry of Power (MOP).
CTU shall submit annually to CERC by 30th September each year a schedule of transmission assets, which constitute the Regional Grid as on 31st March of that year indicating ownership on which RLDC has operational control and responsibility.
If connected at distribution level, it along with fluctuating load, may even out fluctuations that get reflected on to the transmission system.
If a group of renewable generators are connected at the transmission level of the State, then the fluctuations of generation of various renewable generators would be evened out to get reflected as lesser fluctuations over the STU system at higher voltage level.
Following features are mandated for connectivity of wind turbines at a connection point of 33 kV and above, if the collective capacity of the wind generator at the connection point exceeds 10 MW and where PPA has not yet been tied up.
(Explanation: -During system operations, grid operator in extreme conditions may ask the wind farms to limit the power injection into the grid.)
that Wind farms shall maintain power factor between 0.95 lagging and 0.95 leading at the connection point.
The Wind generating machines shall have the operating region as shown in Figure given below during system faults. Wind farms can be disconnected if the operating point falls below the line in the Figure .
A graph showing Voltage (kV) on the Y-axis versus Time (ms) on the X-axis. The Y-axis has two marked points: Vpf and Vf. The X-axis has marked points at 0, T, and 3000. A solid line represents the minimum voltage threshold for fault ride-through. It starts at Vpf at time 0, drops vertically to Vf, remains constant at Vf until time T, then rises linearly to Vpf at time 3000, and finally levels off. The area above this line is shaded with diagonal lines and labeled 'Must not trip'. A vertical dashed line is drawn at time T, and a horizontal dashed line is drawn at Vpf.
Figure: Fault ride through characteristics
Where,
$V_f$ = 15% of Nominal System voltage
$V_{pf}$ = Minimum voltages ( 80% of Nominal System Voltage)
The fault clearing time for various system nominal voltage levels is given in the following Table
Table: Fault clearing time and voltage limits
| Nominal system voltage (kV) | Fault clearing time, T(ms) | $V_{pf}$ (kV) | $V_f$ (kV) |
|---|---|---|---|
| 400 | 100 | 360 | 60.0 |
| 220 | 160 | 200 | 33.0 |
| 132 | 160 | 120 | 19.8 |
| 110 | 160 | 96.25 | 16.5 |
| 66 | 300 | 60 | 9.9 |
During fault ride-through, the Wind turbine generators (WTGs) in the wind farm shall have the capability to meet the following requirements:
(Explanation: Wind farms connected to high voltage transmission system must stay connected when a voltage dip occurs in the grid, otherwise, the sudden disconnection of a large amount of wind power may contribute to the voltage dip, with adverse consequences. Wind farms must remain connected when the voltage dip profile is above the line shown in the figure. The per unit voltage at the point of connection to the grid is shown in the vertical axis and the duration (seconds) of the fault in the horizontal axis. This code requires Fault Ride-Through (FRT) capability during voltage drops in Transmission System to 15% of nominal voltage during 300 ms with recovery up to 80% of nominal voltage after 3 sec, with the slope shown in figure given above)
v) Wind turbine generator protection
iv) load unbalance (negative sequence) protection
v) differential protection for the grid connecting transformer
vi) capacitor bank protection
vii) tele-protection channels (for use with distance protection) between the grid connection point circuit breaker and user connection point circuit breaker
vi) Wind farms shall have communication channel which is continuously available to system operator.
vii) Data Acquisition System facility shall be provided for transfer of information to concerned SLDC and RLDC
viii) Lightning protection of WTG system shall be according to IEC TR 61400-24 "Wind turbine generator systems – Part 24: Lightning protection."
ix) Wind turbine grounding systems shall follow the recommendations of IEC TR 61400-24 (section 9).
x) The grid connecting transformer configuration shall be designed to provide:
The preferred configuration of the grid connecting transformer is delta connection on the wind farm side and grounded wye connection on the transmission system (grid) side. Delta connection on the high voltage side of the grid connecting transformer is not permitted. Alternate transformer configuration including wye-wye or wye-wye with a delta connected tertiary is also acceptable for the grid connecting transformer. If the wind farm is directly getting connected to the existing utility substation, the standard practice of utility shall be followed.
(Explanation: -
The purpose of prohibiting delta connection on the high voltage side of the grid connecting transformer is to block the harmonics current and to detect the earth faults on the grid side. )
(a) The primary objective of integrated operation of the National/ Regional grids is to enhance the overall operational reliability and economy of the entire electric power network spread over the geographical area of the interconnected system. Participant utilities shall cooperate with each other and adopt Good Utility Practice at all times for satisfactory and beneficial operation of the National/Regional grid.
(b) Overall operation of the National / inter-regional grid shall be supervised from the National Load Despatch Centre (NLDC). Operation of the Regional grid shall be supervised from the Regional Load Despatch Centre (RLDC). The roles of NLDC, RLDC and RPC shall be in accordance with the provisions made in Chapter-2 of the IEGC.
(c) All persons shall comply with this Operating Code, for deriving maximum benefits from the integrated operation and for equitable sharing of obligations.
(d) All licensee, generating company, generating station and any other person connected with the operation power system shall comply with the directions issued by the respective RLDC /SLDC to ensure integrated grid operation and for achieving the maximum economy and efficiency in the operation of the power system.
(e) A set of detailed operating procedures for the National grid shall be developed and maintained by the NLDC in consultation with the RLDCs, for guidance of the staff of the NLDC and it shall be consistent with IEGC to enable compliance with the requirement of this IEGC.
(f) A set of detailed operating procedures for each regional grid shall be developed and maintained by the respective RLDC in consultation with the regional entities for guidance of the staff of RLDC. and shall be consistent with IEGC to enable compliance with the requirement of this IEGC.
(g) A set of detailed operating procedures for each state grid shall be developed and maintained by the respective SLDC in consultation with the concerned persons for guidance of the staff of SLDC. and shall be consistent with IEGC to enable compliance with the requirement of this IEGC.
h) The control rooms of the NLDC, RLDC, all SLDCs, power plants, substation of 132 kV and above, and any other control centres of all regional entities shall be manned round the clock by qualified and adequately trained personnel. Training requirements may be notified by the Commission from time to time, by orders.
affected by it) as specified in the detailed operating procedure by NLDC.
a) Thermal generating units of 200 MW and above,
Software based Electro Hydraulic Governor (EHG) system : 01.04.2010
Hardware based EHG system 01.06.2010
b) Hydro units of 10 MW and above 01.04.2010
a) There should not be any reduction in generation in case of improvement in grid frequency below 50.0 Hz. ( for example if grid frequency changes from 49.3 to 49.4 Hz. then there shall not be any reduction in generation). Whereas for any fall in grid frequency, generation from the unit should increase by 5% limited to 105 % of the MCR of the unit subject to machine capability.
b) Ripple filter of +/- 0.03 Hz. shall be provided so that small changes in frequency are ignored for load correction, in order to prevent governor hunting.
c) Mechanical Hydraulic Governor (MHG) shall adopt suitable scheme to implement the feature given at (a) above at the earliest possible.
turbine/Combined Cycle Power Plants and Nuclear Power Stations shall be exempted from Sections 4.6.2 (c)& (d), 5.2 (f), 5.2 (g), 5.2 (h) and 5.2 (i) till the Commission reviews the situation.
If any of these generating units is required to be operated without its governor in operation as specified above, the RLDC shall be immediately advised about the reason and duration of such operation. All governors shall have a droop setting of between 3% and 6%.
System Stabilizers (PSS) in AVR's of generating units (wherever provided), shall be got properly tuned by the respective generating unit owner as per a plan prepared for the purpose by the CTU/RPC from time to time. CTU /RPC will be allowed to carry out checking of PSS and further tuning it, wherever considered necessary.
RPC Secretariat shall carry out periodic inspection of the under frequency relays and maintain proper records of the inspection. RPC in consultation with RLDC shall decide and intimate the action required by Regional entities/STUs to get required load relief from Under Frequency and Df/Dt relays. All Regional entities/STUs / Licensee shall abide by these decisions.
and reliable communication facility internally and with other users/STUs /RLDC/SLDC to ensure exchange of data/information necessary to maintain reliability and security of the grid. Wherever possible, redundancy and alternate path shall be maintained for communication along important routes, e.g., SLDC to RLDC.
| Voltage – (kV rms) | ||
|---|---|---|
| Nominal | Maximum | Minimum |
| 765 | 800 | 728 |
| 400 | 420 | 380 |
| 220 | 245 | 198 |
| 132 | 145 | 122 |
(s) All users and STU shall provide adequate voltage control measures as finalized by RPC.
(t) Special requirements for wind generators
iv. Under any emergency (faults in the vicinity of wind farms, loss of any of the wind farm equipment, faults within the wind farms) the wind farm operator's prime priority shall be the grid security and shall act accordingly as per the instruction of RLDC/ SLDC.
This section is concerned with the provisions to be made by SLDCs to effect a
reduction of demand in the event of insufficient generating capacity, and inadequate transfers from external interconnections to meet demand, or in the event of breakdown or congestion in intra-state or inter-state transmission system or other operating problems (such as frequency, voltage levels beyond normal operating limit, or thermal overloads , etc. ) or overdrawl of power vis-à-vis of the regional entities beyond the limits mentioned in UI regulation of CERC
conditions depending upon the severity of the overdrawal. The concerned SLDC shall ensure immediate compliance with these directions of RLDC and send a compliance report to the concerned RLDC.
5.5.1 a) A weekly report covering performance of the national/integrated grid in previous week shall be prepared by NLDC . Such weekly report shall be available on the website of the NLDC concerned for at least 12 weeks. A monthly report covering performance of the national/integrated grid shall be prepared by NLDC and shall be sent to CERC, CEA , RLDCs and RPCs.
b) A daily report covering the performance of the regional grid shall be prepared by each RLDC and shall be put on its website. This report shall also cover the wind power generation and injection in to grid.
c) A weekly report shall be issued by RLDC to all Regional entities of the Region, NLDC and RPC Secretariat and shall cover the performance of the Regional grid for the previous week. Such weekly report shall also be available on the website of the RLDC concerned for at least 12 weeks.
The weekly reports shall contain the following:-
(a) Frequency profile
(b) Voltage profile of important substations and sub-stations
normally having low voltages
(c) Major Generation and Transmission Outages
(d) Transmission Constraints
(e) Instances of persistent/significant non-compliance of IEGC.
(f) Instances of congestion in transmission system
(g) Instances of inordinate delays in restoration of transmission elements and generating units
The above generally relates to notifying of what is expected to happen or what has happened and not the reasons why.
(a) Operations and events on the Regional grid
Immediately following an event on Regional grid, the RLDC will inform each user/STU/CTU, whose system may, or will, experience an operational effect following the event, and give details of what has happened in the event [but not the reasons why].
(b) Operations and events on a user/STU/CTU Regional entity's system.
Before any operation is carried out on a user/STU/CTU system, the user's/STU/CTU will inform the RLDC, in case the Regional grid may, or will, experience an Operational effect, and give details of the operation to be carried out. In case such operation is likely to have impact on other regions, the RLDC of those Regions shall also be informed through NLDC
energy. Outage of wind generator should be planned during lean wind season, outage of solar, if required during the rainy season and outage of run-of-the-river power plant in the lean water season.
This section is applicable to NLDC, RLDC, SLDCs, CTU, STU and all users
the RLDC for implementation.
a) Detailed plans and procedures for restoration of the regional grid under partial/total blackout shall be developed by RLDC in consultation with NLDC, all user, STU, SLDC, CTU and RPC Secretariat and shall be reviewed / updated annually.
b) Detailed plans and procedures for restoration after partial/total blackout of each user's/STU/CTU system within a Region, will be finalized by the concerned user's/STU/CTU in coordination with the RLDC. The procedure will be reviewed, confirmed and/or revised once every subsequent year. Mock trial runs of the procedure for different sub-systems shall be carried out by the users/CTU/STU at least once every six months under intimation to the RLDC.
c) List of generating stations with black start facility, inter-State/inter-regional ties, synchronizing points and essential loads to be restored on priority, shall be prepared and be available with NLDC, RLDC and SLDC.
d) The RLDC is authorized during the restoration process following a black out, to operate with reduced security standards for voltage and frequency as necessary in order to achieve the fastest possible recovery of the grid.
e) All communication channels required for restoration process shall be used for operational communication only, till grid normalcy is restored.
This section deals with reporting procedures in respect of events in the system to all users/STU/CTU, RPC Secretariat and NLDC/RLDC/SLDC. The reporting procedure shall be in accordance with the relevant CEA Regulations.
The objective of this section is to define the incidents to be reported, the reporting route to be followed and information to be supplied to ensure consistent approach to the reporting of incidents/events.
This section covers all users, STU,CTU, RPC Secretariat, NLDC, RLDCs and SLDCs.
Any of the following events require reporting by RLDC/ users, STU,CTU:
RLDC orally, the users, STU,CTU /SLDC will give a written report to RLDC in accordance with this section. RLDC in turn give a report to NLDC.
(b) Written Reporting of Events by RLDC to users, STU,CTU. In the case of an event which was initially reported by RLDC to users, STU,CTU SLDC/NLDC orally, the RLDC will give a written report to the users, STU,CTU /SLDC/NLDC in accordance with this section.
(c) Form of Written Reports:
A written report shall be sent to NLDC or RLDC or a users, STU,CTU /SLDC, as the case may be, in the reporting formats as devised by the appropriate load despatch Centre and will confirm the oral notification together with the following details of the event:
This Chapter sets out the
This code deals with the procedures to be adopted for scheduling of the net injection / drawals of concerned regional entities on a day ahead basis with the modality of the flow of information between the NLDC / RLDCs / SLDCs/Power Exchange and regional entities. The procedure for submission of capability declaration by each ISGS and submission of requisition / drawal schedule by other regional entities is intended to enable RLDCs to prepare the despatch schedule for each ISGS and drawal schedule for each regional entity. It also provides methodology of issuing real time despatch/drawal instructions and rescheduling, if required, to regional entities along with the commercial arrangement for the deviations from schedules, as well as, mechanism for reactive power pricing. This code also provides the methodology for re-scheduling of wind and solar energy on three (3) hourly basis and the methodology of compensating the wind and solar energy rich State for dealing with the variable generation through a Renewable Regulatory charge. The provisions contained in this chapter are without prejudice to the powers conferred on RLDC under sections 28 and 29 of the Electricity Act, 2003
This code will be applicable to NLDC, RLDC/SLDCs, ISGS, Distribution Licensees/SEBs/STUs/ regional entities, Power Exchanges, wind and solar generating stations and other persons in the National and Regional grid.
The scheduling and despatch procedure for the generating stations of
Bhakra Beas Management Board (BBMB) shall be as per the procedure formulated by the Northern Regional Load Despatch Centre (NRLDC) in consultation with BBMB.
Similarly, the scheduling and despatch procedure for the generating stations of Sardar Sarovar Project (SSP) shall be as per the procedure formulated by the Western Regional Load Despatch Centre (WRLDC) in consultation with Narmada Control Authority (NCA).
(Explanation: If the share for the host state is 30% and that outside the host state is 40% then the RLDC shall do the scheduling; if on the other hand share for the host State is 40% and outside the host State, it is 30% then the SLDC shall coordinate the scheduling).
(iv) RLDC shall coordinate the scheduling if the share inside and outside the host State is the same.
notional control area. The algebraic summation of scheduled drawal from ISGS and from contracts through a long – term access, medium -term and short –term open access arrangements shall provide the drawal schedule of each regional entity, and this shall be determined in advance on day-ahead basis. The regional entities shall regulate their generation and/or consumers' load so as to maintain their actual drawal from the regional grid close to the above schedule. If regional entities deviate from the drawal schedule, within the limit specified by the CERC in UI Regulations as long as such deviations do not cause system parameters to deteriorate beyond permissible limits and/or do not lead to unacceptable line loading, such deviations from net drawal schedule shall be priced through the Unscheduled Interchange (UI) mechanism.
The SLDC, STU and users shall always endeavour to restrict their net drawal from the grid to within their respective drawal schedules, whenever the system frequency is below 49.7 Hz. The concerned user/STU /SLDC shall ensure that their automatic demand management scheme mentioned in clause 5.4.2 acts to ensure that there is no over drawl when frequency falls to 49.5 Hz. and also to ensure that there is no overdrawl when frequency is 49.5 Hz. or below. If the automatic demand management scheme has not yet been commissioned, then action has to be taken as per manual demand management scheme to ensure zero overdrawl when frequency falls to or is below 49.5 Hz.
The SLDCs/STUs /Distribution Licensees shall regularly carry out the necessary exercises regarding short-term demand estimation for their respective States/area, to enable them to plan in advance as to how they would meet their consumers' load without overdrawing from the grid.
The ISGS , other generating stations and sellers shall be responsible for power generation/power injection generally according to the daily schedules advised to them by the RLDC/SLDC on the basis of the contracts/ requisitions received from the SLDCs/buyers/Power Exchanges.
The ISGS would normally be expected to generate power according to the daily schedules advised to them. The ISGS may also deviate from the given schedules within the limits specified in the CERC UI Regulations of CERC, depending on the plant and system conditions. In particular, they may be allowed to generate beyond the given schedule under deficit conditions as long as such deviations do not cause system parameters to deteriorate beyond permissible limits and/or do not lead to unacceptable line loading. Deviations, if any, from the ex-power plant generation schedules shall be appropriately priced in accordance with UI Regulations. In addition, deviations, from schedules causing congestion, shall also be priced in accordance with the Congestion Charge Regulations. of CERC
Provided that when the frequency is higher than 50.2 Hz, the actual net injection shall not exceed the scheduled despatch for that time block. Also, while the frequency is above 50.2 Hz, the ISGS may (at their discretion) back down without waiting for an advice from RLDC to restrict the frequency rise. When the frequency falls below 49.7 Hz, the generation at all ISGS (except those on peaking duty) shall be maximized, at least upto the level to which can be sustained, without waiting for an advice from RLDC.
However, notwithstanding the above, the RLDC may direct the SLDCs/ISGS/other regional entities to increase/decrease their drawal/generation in case of contingencies e.g. overloading of lines/transformers, abnormal voltages, threat to system security. Such directions shall immediately be acted upon. In case the situation does not call for very urgent action, and RLDC has some time for analysis, it shall be checked whether the situation has arisen due to deviations from schedules, pursuant to short-term open access. These shall be got terminated first, before an action, which would affect the scheduled supplies to the long term and medium term customers is initiated in accordance with Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-state Transmission and related matters) Regulations, 2009.
For all outages of generation and transmission system, which may have an effect on the regional grid, all Regional entities shall cooperate with each other and coordinate their actions through Operational Coordination Committee (OCC) for outages foreseen sufficiently in advance and through RLDC (in all other cases), as per procedures finalized separately by OCC. In particular, outages requiring restriction of ISGS generation and/or restriction of ISGS share which a beneficiary can receive and curtailment of other long term transactions shall be planned carefully to achieve the best optimization.
The regional entities shall enter into separate joint/bilateral agreement(s) to identify the beneficiary's shares in ISGS (based on the allocations by the Govt. of India, where applicable), scheduled drawal pattern, tariffs, payment terms etc. All such agreements shall be filed with the concerned RLDC(s) and RPC, Secretariat, for being considered in scheduling and regional energy accounting. Any bilateral agreements between buyer and seller for scheduled interchanges on long-term, medium-term basis shall also specify the interchange schedule, which shall be duly filed with CTU and CTU shall inform RLDC and SLDC, as the case may be about these agreements in accordance with Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-state Transmission and related matters) Regulations, 2009.
All other regional entities should abide by the concept of frequency-linked load despatch and pricing of deviations from schedule, i.e., unscheduled interchanges. All regional entities should normally be operated according
to the standing frequency-linked load despatch guidelines issued by the RLDC, to the extent possible, unless otherwise advised by the RLDC/SLDC.
The ISGS shall make an advance declaration of ex-power plant MW and MWh capabilities foreseen for the next day, i.e., from 0000 hrs to 2400 hrs. During fuel shortage condition, in case of thermal stations, they may specify minimum MW, maximum MW, MWh capability and declaration of fuel shortage. The generating stations shall also declare the possible ramping up / ramping down in a block. In case of a gas turbine generating station or a combined cycle generating station, the generating station shall declare the capacity for units and modules on APM gas, RLNG and liquid fuel separately, and these shall be scheduled separately.
While making or revising its declaration of capability, the ISGS shall ensure that the declared capability during peak hours is not less than that during other hours. However, exception to this rule shall be allowed in case of tripping/re-synchronisation of units as a result of forced outage of units.
It shall be incumbent upon the ISGS to declare the plant capabilities faithfully, i.e., according to their best assessment. In case, it is suspected that they have deliberately over/under declared the plant capability contemplating to deviate from the schedules given on the basis of their capability declarations (and thus make money either as undue capacity charge or as the charge for deviations from schedule), the RLDC may ask the ISGS to explain the situation with necessary backup data.
The ISGS shall be required to demonstrate the declared capability of its generating station as and when asked by the Regional Load Despatch Centre of the region in which the ISGS is situated. In the event of the ISGS failing to demonstrate the declared capability, the capacity charges due to the generator shall be reduced as a measure of penalty.
The quantum of penalty for the first mis-declaration for any duration/block in a day shall be the charges corresponding to two days fixed charges. For the second mis-declaration the penalty shall be equivalent to fixed charges for four days and for subsequent mis-declarations, the penalty shall be multiplied in the geometrical progression
The CTU shall install special energy meters on all inter connections between the regional entities and other identified points for recording of actual net MWh interchanges and MVARh draws. The installation, operation and maintenance of special energy meters shall be in accordance with Central Electricity Authority (Installation and Operation of Meters) Regulations, 2006. All concerned entities (in whose premises the special energy meters are installed) shall take weekly meter readings and transmit them to the RLDC by Tuesday noon.
The RLDC shall be responsible for computation of actual net injection / drawal of concerned regional entities, 15 minute-wise, based on the above meter readings. The above data along with the processed data of meters shall be forwarded by the RLDC to the RPC secretariat on a weekly basis by each Thursday noon for the seven day period ending on the previous Sunday mid-night, to enable the latter to prepare and issue the Unscheduled inter-change (UI) account. All computations carried out by RLDC shall be open to all regional entities for checking/verifications for a period of 15 days. In case any mistake/omission is detected, the RLDC shall forthwith make a complete check and rectify the same.
The operating log books of the generating station shall be available for review by the Regional Power Committee. These books shall keep record of machine operation and maintenance.
Any generation from the ISGS other than hydro generating stations and renewable energy generating stations up to 105% of the declared capacity in any time block of 15 minutes and averaging up to 101% of the average declared capacity over a day shall not be construed as gaming, and the generator shall be entitled to UI charges for such excess generation above the scheduled generation (SG) in accordance with UI Regulations of CERC.
For any generation from the ISGS other than hydro generating stations beyond the prescribed limits, the Regional Load Despatch Centre shall investigate so as to ensure that there is no gaming. Generating stations shall be entitled to recover the Unscheduled Interchange charges only if the investigation establishes that there is no gaming. If gaming is found by the Regional Load Despatch Centre, the corresponding Unscheduled Interchange charges payable to the generating station on account of such extra generation shall be reduced to zero and the amount shall be adjusted in UI pool account of the Regional Entities in the ratio of their capacity share in the generating station.
Hydro generating stations are expected to respond to grid frequency changes and inflow fluctuations. The hydro generating stations shall be free to deviate from the given schedule without indulging in gaming and causing grid constraint and a compensation for difference between the actual net energy supply by the hydro generating station and the scheduled energy (ex-bus) over day shall be made by the concerned Regional Load Despatch Centre in the day ahead schedule for the 4th day (day plus 3). If gaming is found by the Regional Load Despatch Centre, the corresponding Unscheduled Interchange charges payable to the generating station on account of such extra generation shall be reduced to zero and the amount shall be adjusted in UI pool account of the beneficiaries in the ratio of their capacity share in the generating station.
RLDC shall periodically review the actual deviation from the despatch and net drawal schedules being issued, to check whether any of the other regional entities are indulging in unfair gaming or collusion. In case any such practice is detected, the matter shall be reported to the Member
Secretary, RPC for further investigation/action.
NLDC shall be responsible for scheduling and despatch of electricity over inter-regional links in accordance with the grid code specified by Central Commission in coordination with Regional Load Despatch Centers. NLDC shall be responsible for coordination with Regional Load Despatch Centers for the energy accounting of inter-regional exchange of power. NLDC shall also be responsible for coordination for trans-national exchange of power.
NLDC shall develop a procedure for scheduling of collective transaction through Power Exchanges, scheduling of inter-regional power exchanges including HVDC setting responsibility and power exchanges of the country with other countries., ,
All inter-State generating stations (ISGS) shall be duly listed on the respective RLDC and SLDC web-sites. The station capacities and allocated/contracted shares of different beneficiaries shall also be listed out.
Each State shall be entitled to a MW despatch up to (foreseen ex-power plant MW capability for the day) x (State's share in the station's capacity) for all such stations. In case of hydro-electric stations, there would also be a limit on daily MWh despatch equal to (MWh generation capacity for the day)X (State's share in the station's capacity).
By 9 AM every day, the ISGS shall advise the concerned RLDC, the station-wise ex-power plant MW and MWh capabilities foreseen for the next day, i.e., from 0000 hrs to 2400 hrs of the following day.
The above information of the foreseen capabilities of the ISGS and the corresponding MW and MWh entitlements of each State, shall be compiled by the RLDC every day for the next day, and advised to all beneficiaries by 10 AM. The SLDCs shall review it vis-à-vis their foreseen load pattern and their own generating capability including bilateral exchanges, if any, and advise the RLDC by 3 PM their drawal schedule for each of the ISGS in which they have shares, long-term and medium-term bilateral interchanges, approved short-term bilateral interchanges.
a. NLDC shall indicate to Power Exchange(s), the list of interfaces/control areas/regional transmission systems on which unconstrained flows are required to be advised by the Power Exchange(s) to the NLDC. Power Exchange(s) shall furnish the interchange on various interfaces/control areas/regional transmission systems as intimated by NLDC. Power Exchange(s) shall also furnish the information of total drawal and injection in
each of the regions. Based on the information furnished by the Power Exchanges, NLDC shall check for congestion. In case of congestion, NLDC shall inform the Exchanges about the period of congestion and the available limit for scheduling of collective transaction on respective interface/control area/transmission systems during the period of congestion for Scheduling of Collective Transaction through the respective Power Exchange. The limit for scheduling of collective transaction for respective Power Exchange shall be worked out in accordance with CERC directives. Based on the application for scheduling of Collective Transaction submitted by the Power Exchange(s), NLDC shall send the details (Scheduling Request of Collective Transaction) to different RLDCs for final checking and incorporating them in their schedules. After getting confirmation from RLDCs, NLDC shall convey the acceptance of scheduling of collective transaction to Power Exchange(s). RLDCs shall schedule the Collective Transaction at the respective periphery of the Regional Entities.
b. The individual transactions for State Utilities/intra-State Entities shall be scheduled by the respective SLDCs. Power Exchange(s) shall send the detailed break up of each point of injection and each point of drawal within the State to respective SLDCs after receipt of acceptance from NLDC. Power Exchange(s) shall ensure necessary coordination with SLDCs for scheduling of the transactions.
c. Timeline for above activities will be as per detailed procedure for Scheduling of Collective Transaction issued in accordance with CERC( Open-access in inter-state transmission) Regulations, 2008 and as amended from time to time.
The SLDCs may also give standing instructions to the RLDC such that the RLDC itself may decide the best drawal schedules for the States.
By 6 PM each day, the RLDC shall convey:
(i) The ex-power plant “despatch schedule” to each of the ISGS, in MW for different time block, for the next day. The summation of the ex-power plant drawal schedules advised by all beneficiaries shall constitute the ex-power plant station-wise despatch schedule.
(ii) The “net drawal schedule” to each regional entity, in MW for different time block, for the next day. The summation of the station-wise ex-power plant drawal schedules from all ISGS and drawal from regional grid consequent to other long term access, medium term and short-term open access transactions, after deducting the transmission losses (estimated), shall constitute the regional entity-wise drawal schedule.
The SLDCs/ISGS shall inform any modifications/changes to be made in drawal schedule/foreseen capabilities, if any, to RLDC by 10 PM or preferably earlier.
The hydro electric generation stations are expected to respond to grid frequency changes and inflow fluctuations. They would, therefore, be free to deviate from the given schedule as long as they do not indulge in gaming and do not cause a grid constraint. As a result, the actual net energy supply by a hydro generating station over a day may differ from scheduled energy (ex-bus) for that day. A compensation shall then be made by the concerned load despatch centre in the day ahead schedule for the 4th day (day plus 3). The quantum of energy which could not be despatched by the hydro station due to transmission constraints shall also be adjusted in the 4th day schedule of the generating station.
The declaration of the generating capability by hydro ISGS should include limitation on generation during specific time periods, if any, on account of restriction(s) on water use due to irrigation, drinking water, industrial, environmental considerations etc. The concerned Load Despatch Centre shall periodically check that the generating station is declaring the capacity and energy sincerely, and is not manipulating the declaration with the intent of making undue money through UI.
Since variation of generation in run-of-river power stations shall lead to spillage, these shall be treated as must run stations. All renewable energy power plants except for biomass power plants with installed capacity of 10 MW and above, and non-fossil fuel based cogeneration plants, whose tariff is determined by the CERC shall be treated as 'MUST RUN' power plants and shall not be subjected to 'merit order despatch' principles.
Run-of-river power station with pondage and storage type power stations are designed to operate during peak hours to meet system peak demand. Maximum capacity of the station declared for the day shall be equal to the installed capacity including overload capability, if any, minus auxiliary consumption, corrected for the reservoir level. The Regional Load Despatch Centers shall ensure that generation schedules of such type of stations are prepared and the stations despatched for optimum utilization of available hydro energy except in the event of specific system requirements/constraints.
The schedule finalized by the concerned load despatch centre for hydro generating station, shall normally be such that the scheduled energy for a day equals the total energy (ex-bus) expected to be available on that day, as declared by the generating station, based on foreseen/planned water availability/release. It is also expected that the total net energy actually supplied by the generating station on that day would equal the declared total energy, in order that the water release requirement is met. While the 15-minute wise, deviations from schedule would be accounted for as Unscheduled Interchange (UI), the net energy deviation for the whole day, if any, shall be additionally accounted for as shown in the illustration.
Suppose the foreseen/expected total energy (ex-bus) for Day-1 is E1, the scheduled energy is S1, actual net energy (metered) is A1 and energy that could not be despatched due to transmission constraint is C1, all in ex-bus
MWh. Suppose the expected energy availability for Day 4, as declared by the generator, is E4. Then, the schedule for day4 shall be drawn up such that the scheduled energy for Day 4, shall be
$S4=E4+(A1-(E1-C1))$ , Similarly,
$S5= E5+(A2-(E2-C2))$ ,
$S6=E6+(A3-(E3-C3))$ , $S7=E7+(A4-(E4-C4))$ , and so on."
While finalizing the above daily despatch schedules for the ISGS, RLDC shall ensure that the same are operationally reasonable, particularly in terms of ramping-up/ramping-down rates and the ratio between minimum and maximum generation levels. A ramping rate of upto 200 MW per hour should generally be acceptable for an ISGS and for a regional entity (50 MW in NER), except for hydro-electric generating stations which may be able to ramp up/ramp down at a faster rate.
While finalizing the drawal and despatch schedules as above, the RLDC shall also check that the resulting power flows do not give rise to any transmission constraints. In case any impermissible constraints are foreseen, the RLDC shall moderate the schedules to the required extent, under intimation to the concerned regional entities. Any changes in the scheduled quantum of power which are too fast or involve unacceptably large steps, may be converted into suitable ramps by the RLDC.
In the event of bottleneck in evacuation of power due to any constraint, outage, failure or limitation in the transmission system, associated switchyard and substations owned by the Central Transmission Utility or any other transmission licensee involved in inter-state transmission (as certified by the RLDC) necessitating reduction in generation, the RLDC shall revise the schedules which shall become effective from the 4th time block, counting the time block in which the bottleneck in evacuation of power has taken place to be the first one. Also, during the first, second and third time blocks of such an event, the scheduled generation of the ISGS shall be deemed to have been revised to be equal to actual generation, and the scheduled drawals of the beneficiaries shall be deemed to have been revised accordingly.
In case of any grid disturbance, scheduled generation of all the ISGS and scheduled drawal of all the beneficiaries shall be deemed to have been revised to be equal to their actual generation/drawal for all the time blocks affected by the grid disturbance. Certification of grid disturbance and its duration shall be done by the RLDC.
Revision of declared capability by the ISGS(s) (except hydro stations) and requisition by beneficiary(ies) for the remaining period of the day shall also be permitted with advance notice. Revised schedules/declared capability in such cases shall become effective from the 6th time block, counting the time block in which the request for revision has been received in the RLDC to be the first one. Provided that RLDC may allow only one revision, in case of Run
of the River (ROR) and pondage based hydro generating stations, if there is large variation of expected energy (MWh) for the day compared to previous declaration.
Notwithstanding anything contained in Regulation 6.5(18), in case of forced outage of a unit, for those stations who have a two part tariff based on capacity charge and energy charge for long-term contracts, the RLDC shall revise the schedules on the basis of revised declared capability. The revised declared capability and the revised schedules shall become effective from the 4th time block, counting the time block in which the revision is advised by the ISGS to be the first one.
If, at any point of time, the RLDC observes that there is need for revision of the schedules in the interest of better system operation, it may do so on its own, and in such cases, the revised schedules shall become effective from the 4th time block, counting the time block in which the revised schedule is issued by the RLDC to be the first one.
To discourage frivolous revisions, an RLDC may, at its sole discretion, refuse to accept schedule/capability changes of less than two (2) percent of previous schedule/capability. The schedule of thermal generating stations indicating fuel shortage while intimating the Declared Capacity to the RLDC shall not be revised except in case of forced outage of generating unit.
The Regional Load Despatch Centre shall also formulate the procedure for meeting contingencies both in the long run and in the short run (Daily scheduling).
Scheduling of wind and solar power generation plants would have to be done where the sum of generation capacity of such plants connected at the connection point to the transmission or distribution system is greater than 10 MW and connection point is 33 KV and above, where PPA has not yet been signed. For capacity and voltage level below this, as well as far old wind farms, it could be mutually decided between the Wind Generator and the transmission or distribution utility, as the case may be. The schedule by such wind and solar power generating stations supplying inter-state power under long-term access and medium-term and short-term open access may be revised by giving advance notice to RLDC. Such revisions by wind and solar power generating stations shall be effective from 6th time-block ,the first being the time –block in which notice was given. There may be maximum of 8 revisions for each 3 hour time slot starting from 00:00 hours during the day. Concerned RLDC and SLDC shall maintain the record of schedule from renewable power generating stations based on type of renewable energy sources i.e wind or solar from the point of view of grid security. While scheduling generating stations in a region, system operator shall aim at utilizing available wind and solar energy fully.
Generation schedules and drawal schedules issued/revised by the Regional Load Despatch Centre shall become effective from designated time block irrespective of communication success.
For any revision of scheduled generation, including post facto deemed revision, there shall be a corresponding revision of scheduled drawals of the beneficiaries.
A procedure for recording the communication regarding changes to schedules duly taking into account the time factor shall be evolved by the Central Transmission Utility.
When for the reason of transmission constraints eg. congestion or in the interest of grid security, it becomes necessary to curtail power flow on a transmission corridor, the transactions already scheduled may be curtailed by the Regional Load Despatch Centre.
The short-term customer shall be curtailed first followed by the medium-term customers, which shall be followed by the long-term customers and amongst the customers of a particular category, curtailment shall be carried out on pro rata basis.
After the operating day is over at 2400 hours, the schedule finally implemented during the day (taking into account all before-the-fact changes in despatch schedule of generating stations and drawal schedule of the States) shall be issued by RLDC. These schedules shall be the datum for commercial accounting. The average ex-bus capability for each ISGS shall also be worked out based on all before-the-fact advice to RLDC.
Collective Transaction through Power Exchange(s) would normally be curtailed subsequent to the Short Term Bilateral Transaction(s).
RLDCs would curtail a Transaction at the periphery of the Regional Entities. SLDC(s) shall further incorporate the inter-se curtailment of intra-State Entities to implement the curtailment.
RLDC shall properly document all above information i.e. station-wise foreseen ex-power plant capabilities advised by the generating stations, the drawal schedules advised by regional entities, all schedules issued by the RLDC, and all revisions/updating of the above.
The procedure for scheduling and the final schedules issued by RLDC, shall be open to all regional entities and other regional entities for any checking/verification, for a period of 5 days. In case any mistake/omission is detected, the RLDC shall forthwith make a complete check and rectify the same.
While availability declaration by ISGS shall have a resolution of one (1) MW and one (1) MWh, all entitlements, requisitions and schedules shall be
rounded off to the nearest two decimal at each control area boundary for each of the transaction, to have a resolution of 0.01 MW and 0.01 MWh.”
The Regional Entity except Generating Stations pays for VAR return when voltage is above 103%
Provided that there shall be no charge/payment for VAR drawal/return by a Regional Entity except Generating Stations on its own line emanating directly from an ISGS.
3 Notwithstanding the above, RLDC may direct a Regional Entity except
Generating Stations to curtail its VAr drawal/injection in case the security of grid or safety of any equipment is endangered.
In general, the Regional Entities except Generating Stations shall endeavour to minimize the VAr drawal at an interchange point when the voltage at that point is below 95% of rated, and shall not return VAr when the voltage is above 105%. ICT taps at the respective drawal points may be changed to control the VAr interchange as per a Regional Entity except Generating Stations's request to the RLDC, but only at reasonable intervals.
Switching in/out of all 400 kV bus and line Reactors throughout the grid shall be carried out as per instructions of RLDC. Tap changing on all 400/220 kV ICTs shall also be done as per RLDCs instructions only.
The ISGS and other generating stations connected to regional grid shall generate/absorb reactive power as per instructions of RLDC, within capability limits of the respective generating units, that is without sacrificing on the active generation required at that time. No payments shall be made to the generating companies for such VAr generation/absorption.
7 VAr exchange directly between two Regional Entities except Generating Stations on the interconnecting lines owned by them (singly or jointly) generally address or cause a local voltage problem, and generally do not have an impact on the voltage profile of the regional grid. Accordingly, the management/control and commercial handling of the VAr exchanges on such lines shall be as per following provisions, on case-by-case basis:
The beneficiaries shall pay to the respective ISGS Capacity charges corresponding to plant availability and/or Energy charges for the scheduled dispatch, in accordance with the relevant contracts /orders of CERC. The bills for these charges shall be issued by the respective ISGS to each beneficiary on monthly basis.
The sum of the above two charges from all beneficiaries shall fully reimburse the ISGS for generation according to the given dispatch schedule. In case of a deviation in actual generation from the dispatch schedule, the concerned ISGS shall receive or shall pay in accordance with UI regulation of CERC. Similarly, the deviation of actual drawl by any regional entity from the net drawl schedule shall be treated as UI. All 15-minute energy figures (net scheduled, actually metered and UI) shall be rounded off to the nearest 0.01 MWh. The UI charges and the modalities of settlement of UI shall be in accordance with UI Regulation of CERC .
Wind and solar energy being of variable nature, needs to be predicted with reasonable accuracy for proper scheduling and dispatching of power from these sources in the interconnected system. Hence wind and solar generation forecasting is necessary for increased penetration. Wind generation forecasting can be done on an individual developer basis or joint basis for an aggregated generation capacity of 10 MW and above connected at a connection point of 33 kV and above. . If done jointly, the wind/solar forecasting facility shall be built and operated by wind/solar developers in the area and sharing of the cost shall be mutually discussed and agreed.
The wind/solar energy forecasting system shall forecast power based on wind flow/solar insolation data at the following time intervals:
i) Day ahead forecast: Wind/solar power forecast with an interval of 15 minutes for the next 24 hours for the aggregate wind farms.
ii) The schedule by such wind and solar power generating stations supplying inter-state power under long-term access and medium-term and short-term open access may be revised by giving advance notice to RLDC. Such revisions by wind and solar power generating stations shall be effective from 6th time-block ,the first being the time –block in which notice was given. There may be maximum of 8 revisions for each 3 hour time slot starting from 00:00 hours during the day.
Example:
7 All Regional Energy Accounting calculations carried out by RPC Secretariats shall be open to all regional entities for any checking/verification for a period of 15 days. In case any mistake is detected, RPC Secretariats shall forthwith make a complete check and rectify the mistakes.
NLDC shall prepare, with prior approval of Commission, within one month of notification of these regulations, a detailed procedure for implementation of the mechanism of Renewable Regulatory Charges.
Regional Energy Accounts on monthly basis shall be prepared and issued by the RPC Secretariats for the purpose of billing and payment of various charges. Regional Energy Account for a month shall be issued in the following month based on the data provided by RLDC.
RPC Secretariats shall also issue the weekly statement for VAR charges, to all regional entities who have a net drawal/injection of reactive energy under low/high voltage conditions. These payments shall also have a high priority and the concerned regional entities and other regional entities shall pay the indicated amounts into regional reactive pool account operated by the RLDC within 10 (ten) days of statement issue, provided that the Commission may direct any entity other than RLDC to operate the regional reactive pool account. The regional entities who have to receive the money on account of VAR charges would then be paid out from the regional reactive pool account, within three(3) working days
If payments against the above VAR charges are delayed by more than two days, i.e., beyond twelve (12) days from statement issue, the defaulting regional entity shall have to 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. Persistent payment defaults, if any, shall be reported by the RLDC to the Member Secretary, RPC, for initiating remedial action.
The money remaining in the regional reactive account after pay-out of all VAR charges upto 31st March of every year shall be utilized for training of the SLDC operators, and other similar purposes which would help in improving/streamlining the operation of the respective regional grids, as decided by the respective RPC from time to time.
In case the voltage profile of a regional grid improves to an extent that the total pay-out from the regional VAR charges account for a week exceeds the total amount being paid-in for that week, and if the regional reactive account has no balance to meet the deficit, the pay-outs shall be proportionately reduced according to the total money available in the above account.
The RLDC shall table the complete statement of the regional UI account and the regional Reactive Energy account in the RPC's Commercial Committee meeting, on a quarterly basis, for audit by the latter.
Interfaces for Scheduling and UI Accounting In Inter-regional
Case – 1: Interconnecting line owned by State-A Metering Point :
Substation of State-B
Diagram for Case 1: Interconnecting line owned by State-A Metering Point. Two overlapping circles represent State A and State B. A horizontal line connects a vertical line in State A to a vertical line in State B. A meter symbol (a circle with a vertical line through it) is located on the line within the State A circle, indicating the metering point is in State A.
Case - 2: Interconnecting line owned by State-B Metering point :
Substation of State-A
Diagram for Case 2: Interconnecting line owned by State-B Metering point. Two overlapping circles represent State A and State B. A horizontal line connects a vertical line in State A to a vertical line in State B. A meter symbol (a circle with a vertical line through it) is located on the line within the State B circle, indicating the metering point is in State B.
State-B pays to State-A for
Note: Net VARh and net payment may be positive or negative
Case – 3: Interconnecting line is jointly owned by States-A and –B.
Metering points : Substations of State-A and State-B
The diagram shows two overlapping circles representing State A and State B. Inside State A, there is a vertical line labeled 'S/S-A' with a meter symbol (a circle with a diagonal line) on it. Inside State B, there is a vertical line labeled 'S/S-B' with a meter symbol on it. A horizontal line connects the two meter symbols, representing the interconnecting transmission line.
Diagram of an interconnecting line between State A and State B.
Net VARh exported from S/S-A, while voltage < 97% = $X_1$ Net VARh
exported from S/S-A, while voltage > 103% = $X_2$ Net VARh imported at
S/S-B, while voltage < 97% = $X_3$ Net VARh imported at S/S-B, while
voltage > 103% = $X_4$
(i) State-B pays to State-A for
$X_1$ or $X_3$ , whichever is smaller in magnitude, and
(ii) State-A pays to State-B for
$X_2$ or $X_4$ , whichever is smaller in magnitude. Note:
(1) Nothing in these Regulations shall be deemed to limit or otherwise affect the power of the Commission to pass such orders as may be necessary for meeting the ends of justice or to prevent the abuse of the process of the Commission.
(2) Nothing in these Regulations shall bar the Commission from adopting in conformity with the provisions of the Act, a procedure, which is at variance with any of the provisions of these Regulations including summary procedures, if the Commission, in view of the special circumstance of a matter or class of matters and for reasons to be recorded in writing, deems it necessary or expedient for so dealing with such a matter or class of matters.
(3) Nothing in these Regulations shall bar the Commission to deal with any matter or exercise any power under the Act for which no regulations have been framed, and the Commission may deal with such matters, powers and functions in a manner it thinks fit.
(4) The Commission may by general or special order, for reasons to be recorded in writing, and after giving an opportunity of hearing to the parties likely to be affected by grant of relaxation, may relax any of the provisions of these regulations on its own motion or on an application made before it by an interested person.