CEA Releases 2026 Manual on Transmission Planning Criteria

The Central Electricity Authority (CEA), under the Ministry of Power, has revised its Manual on Transmission Planning Criteria, 2026, introducing provisions for 1,150 kV high-voltage alternating current transmission, renewable energy integration, battery energy storage systems and grid stability.

Effective October 15, 2026, the revised manual will apply to all new transmission systems planned after that date. Existing and already planned systems may also be reviewed against the revised criteria, with additional strengthening undertaken wherever required.

The revision aims to address changing requirements of India's electricity network amid rising power demand, increasing renewable energy capacity and the need for reliable, secure and economical transmission infrastructure. The updated provisions cover transmission planning, network modelling, system studies, reliability standards, substation capacity, reactive power management and project implementation procedures.

The 2026 edition incorporates provisions for 1,150 kV high-voltage alternating current transmission, updated conductor parameters and revised models and typical parameters for voltage-source converter high-voltage direct current (VSC-HVDC) systems. It also includes modelling provisions for wind and solar farms, battery energy storage systems (BESS), renewable energy technologies and static synchronous compensators (STATCOM).

The revision involved consultations and technical deliberations with several power-sector organisations. In the acknowledgement, CEA Chief Engineer Bhagwan Sahay Bairwa thanked CEA Chairperson Ghanshyam Prasad and Member (Power Systems) V.K. Singh for their guidance and support during the preparation and finalisation of the manual. Contributions from POWERGRID, GRID-INDIA and Central Transmission Utility of India Ltd (CTUIL) were also acknowledged, along with the efforts of CEA officers involved in the technical work.

The CEA first issued its Manual on Transmission Planning Criteria in 1985, when the planning philosophy focused on regional self-sufficiency. It was revised in 1994 following experience gained from operating 220 kV and 400 kV systems. The Electricity Act, 2003 brought significant changes through the unbundling of State Electricity Boards, the introduction of open access in transmission and the liberalisation of generation. The criteria were reviewed again in 2013 after the regional grids were synchronously interconnected in December that year.

The Ministry of Power subsequently notified the Electricity (Transmission System Planning, Development and Recovery of Inter-State Transmission Charges) Rules, 2021, introducing General Network Access (GNA) and requiring transmission planning to match generation and load growth while avoiding unnecessary investment. The manual was updated in March 2023, effective April 1, 2023, followed by the addition of a chapter on planning procedures in January 2025.

The revised criteria distinguish between the Inter-State Transmission System (ISTS) and the Intra-State Transmission System (Intra-STS), emphasising coordinated development of both networks. Under Section 73(a) of the Electricity Act, 2003, the CEA coordinates transmission planning. The criteria primarily cover ISTS, Intra-STS and dedicated transmission lines down to 66 kV, including planning philosophy, data requirements, reliability standards, modelling, system studies, substations and reactive power management.

Transmission planning must reflect the network access requirements of states and generators under the GNA framework. Transmission customers and utilities are expected to communicate their requirements sufficiently in advance to account for infrastructure development timelines. Hydro project evacuation planning must be undertaken on a river-basin basis. In congested urban and semi-urban areas and difficult terrain, utilities may consider higher voltage levels, multi-circuit towers and other technologies to optimise right-of-way and costs. The PM Gati Shakti National Master Plan platform is to be used to help avoid or minimise crossings involving railways, highways, forests, restricted areas, Great Indian Bustard zones, defence installations, airports and habitats.

State Transmission Utilities (STUs) will act as nodal agencies for Intra-STS planning and serve as the single point of contact for ISTS planning. Critical consumers, including railways, metro rail systems, airports, refineries, underground mines, steel plants, smelters, hospitals and data centres, should plan interconnections with 100 per cent redundancy and, wherever possible, two independent supply sources.

For ISTS studies, the network may generally be modelled down to 220 kV, with modelling extended to 132 kV wherever necessary, including in parts of the North Eastern Region, Uttarakhand, Himachal Pradesh and Sikkim. Intra-STS planning may extend down to 66 kV. Actual network data should be used wherever available, while standard parameters in the manual's annexures may be adopted where data is unavailable. Planning scenarios must account for peak and low demand, high and low wind generation, varying hydro availability, high or zero solar generation and combinations of these conditions.

Peak demand forecasts are to be based on the latest CEA Electric Power Survey, adjusted for actual load growth over the preceding five years. Seasonal and time-of-day variations must also be considered. STUs are required to provide seasonal maximum and minimum demand in megawatts (MW) and megavolt-amperes reactive (MVAr). Reactive power forecasts and generator capability curves are required for steady-state and transient-state studies. The manual identifies typical implementation periods of three to five years for transmission elements, two to three years for augmentation of capacitors, reactors and transformers, and four to five years for new transmission lines or substations. Studies should generally consider at least a three-year planning horizon.

For system strengthening, new transmission additions may be planned with a 10 per cent margin in thermal loading limits for lines and transformers and 15 per cent for inter-regional links. A voltage margin of approximately plus or minus 2 per cent may be considered during planning. Transformer taps are generally to remain at nominal positions in planning studies.

The manual requires power-flow, short-circuit, stability and Total Transfer Capability (TTC) or Available Transfer Capability (ATC) studies. Electromagnetic transient (EMT) and system-inertia studies may also be undertaken where required. Stability assessments must cover rotor-angle, transient and voltage stability, while EMT studies may examine temporary and switching overvoltages, ferroresonance, subsynchronous resonance and insulation coordination. System-inertia studies are considered important as renewable energy penetration increases and conventional generating units retire. The rate of change of frequency must be assessed during low-inertia periods, taking generation and load contingencies into account.

The revised criteria specify that the system should remain within normal operating limits following a single contingency, or N-1 event, without load shedding or generation rescheduling. Under N-1-1 conditions, where a second contingency follows an initial outage, equipment may operate at emergency limits, and load shedding or generation rescheduling may be required within one hour. Emergency thermal limits for planning are set at 120 per cent of normal thermal limits for one hour and 110 per cent for two hours. The manual also establishes voltage and transient performance requirements for systems ranging from 66 kV to 1,150 kV. Specific exceptions to N-1 requirements are provided for certain renewable energy connections, including firm, fully dispatchable projects with storage and renewable generation exceeding 1,000 MW after consideration of capacity factors.

Substation capacity limits have also been prescribed. For load-serving substations, the limits are 12,600 MVA at 1,150 kV, 12,600 MVA at 765 kV, 9,000 MVA at 400 kV, 5,000 MVA at 220 kV, 1,000 MVA at 132 kV and 500 MVA at 66 kV. For generation-pooling substations, the limits are 9,000 MVA at 765 kV, 2,500 MVA at 400 kV, 1,000 MVA at 220 kV, 500 MVA at 132 kV and 160 MVA at 66 kV. Substations serving both generation and load are classified as load-serving substations. The maximum short-circuit level at a new substation bus should not exceed 80 per cent of the rated short-circuit capacity of its equipment, leaving a 20 per cent margin for future growth.

Reactive power management provisions cover shunt capacitors and reactors, static VAr compensators, series compensation, flexible AC transmission system devices and synchronous condensers. Synchronous condensers may be planned near large renewable energy complexes for dynamic voltage support, while shunt capacitors should be installed close to load centres. Utilities are expected to improve load power factors as close to unity as practicable.

Additional provisions cover renewable and hybrid projects, nuclear power stations, HVDC transmission, protection settings, resilience and right-of-way optimisation. Nuclear stations should have two independent start-up power sources, with angular separation kept within 10 degrees wherever possible. HVDC transmission may be considered for bulk power transfers exceeding 2,000 MW over distances preferably greater than 700 km, as well as corridors where AC transmission carries more than 5,000 MW. For conventional HVDC converter stations, the ratio of fault level in MVA to power flow on the bipole must not be below 3.0 under the specified scenarios.

The manual also calls for Zone-3 protection settings to avoid unwanted tripping under extreme line loading, defined using 120 per cent of the thermal current loading limit and a voltage of 0.9 per unit. Right-of-way requirements may be reduced through steel poles, narrow-base and multi-circuit towers, multi-voltage lines, insulated cross-arms, XLPE cables, gas-insulated lines, re-conductoring, higher-capacity conductors, series compensation and HVDC technology. Economic assessments should consider project costs, annual transmission charges and their impact on existing aggregate transmission charges.

Under the planning procedure, the CEA will prepare a rolling short-term transmission plan annually for up to five years and a ten-year perspective plan every alternate year. The CEA will consult CTU, STUs, the Ministry of New and Renewable Energy, Regional Power Committees, SECI, grid operators, generators and other stakeholders. The CTU will prepare annual rolling five-year ISTS plans, while STUs will develop intra-state implementation plans in consultation with distribution companies, generators, system operators and state governments.

The CEA's annual planning schedule includes data collection by April 30, preparation of a draft report by July 31, stakeholder consultations during August and September, and finalisation between November 30 and December 31. CTU planning will follow two cycles, from April to September and October to March, while STUs are expected to finalise their plans by September 30.

Project approval will follow the 2021 rules and the prescribed responsibilities of the National Committee on Transmission (NCT), CTU and Central Government. Under the revised terms of reference described in the manual, the NCT will recommend ISTS projects costing more than Rs 500 crore to the Ministry of Power, including the proposed implementation mode through tariff-based competitive bidding or the regulated tariff mechanism. It will approve projects costing between Rs 100 crore and Rs 500 crore, or within applicable prescribed limits, under intimation to the ministry. Projects costing up to Rs 100 crore, or within the applicable prescribed limit, will be approved by CTUIL under intimation to the NCT and the ministry.

Approved competitive-bidding projects will be allocated to bid process coordinators through Gazette notification, while regulated-tariff projects will be allocated to CTU. Bid process coordinators must submit survey reports within 60 days of the NCT meeting. Intra-state transmission projects exceeding the threshold prescribed by the respective State Electricity Regulatory Commission are to be developed through competitive bidding in accordance with the Tariff Policy.

The revised manual provides a framework for transmission planning as India accommodates rising electricity demand, greater renewable energy integration and changing grid technologies, with the objective of improving reliability, security and the economic utilisation of transmission infrastructure.