New Delhi: The Central Electricity Authority (CEA) has brought 1,150 kilovolt (kV) alternating current (AC) power lines into India’s transmission planning rules. This is the highest voltage level the rules cover, one step above 765 kV. CEA has also made data centres and hospitals critical loads, which must arrange a full backup connection to the grid. Both changes are part of the Manual on Transmission Planning Criteria, 2026, which took effect on October 15.
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The manual is the rulebook that central and state transmission agencies follow when they plan new power lines and substations. CEA said the criteria had been “revised again” to include “the provision for 1,150 kV high voltage AC transmission system.” The revision also added ways to represent wind farms, solar parks and battery storage in the computer studies planners use to test the grid.
Hospitals and data centres now sit on the manual’s list of critical loads, alongside railways, airports and refineries. “Critical loads such as - railways, metro rail, airports, refineries, underground mines, steel plants, smelter plants, hospitals, data centre, etc shall plan their interconnection with the grid, with 100 percent redundancy and as far as possible from two different sources of supply,” the manual said.
In practice, a facility on this list needs a second connection that can carry its entire demand on its own. If one line fails, the other keeps the lights on. Where possible, the two connections should draw power from two separate sources. The 2023 version of the manual carried the same requirement, but its list ended at smelter plants.
The manual also included a separate way to simulate how data centres draw power from the grid. It described this as the “Power Electronic Reconnecting Composite (PERC) model for data centre load.” Planners may use it in their studies when actual data from a site is not available, the manual said.
The manual tests the grid against a standard called N-1. “The grid may however be subjected to outage / loss of an element and it is required that after loss of an element (‘N-1’ or single contingency), all the system parameters like voltages, loadings, frequency shall be within permissible normal limits,” it said.
Put simply, N stands for all the lines, transformers and other equipment in the grid. N-1 means the same grid with any one of them out of action. The grid must keep running normally after losing any single piece, and no other line may become overloaded as a result.
Under the 2026 manual, losing a single 1,150 kV line is one of the failures the grid must absorb this way. It must do so “without load shedding / rescheduling of generation,” the manual said. In other words, consumers should face no power cuts, and grid operators should not have to change which power plants are running.
The manual also set out the faults these lines must survive. “The system shall be able to survive a permanent three phase to ground fault on a 1,150 kV line close to the bus to be cleared in 100 ms,” it said. This describes a short circuit in which all three wires of a line touch the ground near a substation. Protection equipment must cut the faulty line within a tenth of a second, and the rest of the grid must stay stable.
The manual set a similar test for a fault on a single wire. The grid must remain stable even if an automatic attempt to reconnect that wire fails and the whole line has to be shut, according to the manual.
Normal voltage on these lines is to stay between 1,200 kV and 1,090 kV. A single 1,150 kV substation should not normally have more than 12,600 megavolt-amperes (MVA) of transformers, the equipment that steps power down to lower voltages. The corresponding limit at 765 kV is 9,000 MVA, the manual said.
The new rules govern lines planned after October 15, but the manual also addressed networks that are already built or planned. “The existing and already planned transmission systems may be reviewed with respect to the provisions of these planning criteria. Wherever required and possible, additional system may be planned to strengthen the existing system.
Till implementation of the additional system, suitable defence mechanisms may be put in place,” it said.
Elsewhere, the manual listed the defence mechanisms it had in mind. They include load shedding, which means planned power cuts, and changing which plants generate power. They also include islanding, in which part of the grid is cut off to keep it running, and automatic protection schemes.
Under the manual, N-1 “may not be applied” to the line connecting a renewable energy (RE) project to the grid. This means a single solar or wind project does not need a backup line to the nearest grid substation.
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The relaxation does not cover RE projects with storage “which are firm in nature and fully dispatchable.” These are projects that can supply power on demand. Nor does it apply to RE generation “of more than 1000 MW after considering the capacity factor,” according to the manual. The 1,000 MW threshold is measured against the power a project is expected to deliver at its peak, not its installed capacity.
The manual explained inertia as the energy stored in the large spinning generators of coal, gas, hydro and nuclear plants. “In the grid, it gives the system operator a chance to respond to power plant failures giving other systems time to respond and rebalance supply and demand,” it said. Solar panels do not provide this cushion. “With the high penetration of renewable energy sources like wind and solar power and gradual reduction/decommissioning of conventional generators, total system inertia of grid would decline,” the manual said.
Planners must now work out how fast the grid’s frequency would fall if the largest power station or the largest consumer suddenly dropped off. They are to test this for the period when inertia is lowest. The manual said this is “usually the highest RE penetration period or lowest demand period.”
The limit is set so that “the 1st stage Under Frequency Load Shedding (UFLS) doesn’t get triggered and frequency remains 0.1 Hz above 1st stage of UFLS,” the manual said. Under-frequency load shedding is the automatic power cut the grid triggers when frequency falls too low. The rule is designed to keep a sudden plant failure from setting off those cuts.
Battery storage and synchronous condensers “can provide fast response to arrest the frequency decline and help restore the frequency,” according to the manual. A synchronous condenser is a machine that spins like a generator without producing power, which helps hold voltage steady and adds inertia. Such machines “may be planned” near large renewable energy complexes, the manual said.
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It also pointed to old thermal plants as candidates for conversion. “As many gas and coal-based synchronous generators approach the end of their life, the retiring of a plant can possibly create a reactive power deficit at the local network, which may impact voltage stability. The conversion of the existing generator to a synchronous condenser can be potentially economical and effective,” the manual said. Put simply, shutting a plant can leave the local grid short of the support that keeps voltage steady. Converting its generator into a condenser could keep that support in place.
The manual also set out how planners should assume storage behaves. Batteries are taken to charge fully during the day peak, which the manual described as “Solar max i.e. afternoon.” They then supply power during the evening peak. Pumped storage plants, which pump water uphill and release it to generate power, are assumed to follow the same daily cycle.
For the country as a whole, the manual took the summer afternoon as the point of highest annual demand. It put the summer evening peak at 98 percent of that level.
