13.5 GW of Transmission Auctioned: EAR and DSU Gaps in Line and Substation Contracts

Mercom India reported on 3 September 2026 that RECPDCL had named the winners of a 7.5 GW renewable transmission auction and a 6 GW solar transmission auction. That is 13.5 GW of evacuation capacity moving from tender to construction, inside a much larger queue: Mercom reported on 28 August 2026 that solar leads a 248 GW renewable and storage grid connectivity pipeline expected to become operational between August 2026 and 2031.

The procurement route decides who carries the risk. Under tariff based competitive bidding, the developer does not win a construction contract. The bid process coordinator incorporates a special purpose vehicle, assembles the initial approvals and authorisations, and transfers the shares of that SPV to the bidder quoting the lowest levelised transmission charge. What the winner acquires is a company holding a transmission service agreement, a scheduled commercial operation date, and a tariff that does not move if the route turns out to be harder than the bid assumed.

That structure pushes almost every variance onto the SPV's balance sheet. Cost overrun is not passed through, and schedule slippage attracts liquidated damages under the transmission service agreement while delaying the start of the charge that services the debt. Sponsors and lenders reach for erection all risks and delay in start-up to absorb some of that variance, then find that a line and substation package behaves very differently under those two policies from the generation projects most Indian brokers place more often.

A generation project is a compact site. The values sit inside a fence, the fire scenario in the main block sets the probable maximum loss, and one site visit covers the exposure. A transmission package has the opposite shape. A 400 kV double circuit line runs for hundreds of kilometres across several districts, several hundred towers, farmland, riverbeds, forest stretches and road crossings, and terminates in one or two substations that hold a large share of the contract value in a handful of transformers, reactors and switchgear bays.

That geometry changes four things:

• Value distribution. Most of the line's value is thinly spread along the route, while the substation concentrates it. The sum insured split between the two packages should follow that, because the rating and deductibles that fit one do not fit the other.
• Probable maximum loss. The credible large loss on a line is not one tower. It is a cluster brought down by a single storm cell, or a cascade running along the corridor from one failure. On the substation side it is a transformer or switchgear fire.
• Exposure to the elements. There is no roof over a line under construction. Foundations sit open through a monsoon, stringing runs are exposed to wind, and part-erected towers are at their weakest before full bolt torque and bracing are in place.
• Attritional loss. Pilferage of tower angle steel, theft of conductor drums from remote stores, and third-party damage at road crossings produce a claim frequency no fenced generation site sees.

Ask any transmission developer what put the last project behind schedule and the answer is rarely a physical loss. It is right of way. Tower footing compensation disputes with landowners, crop compensation claims during stringing season, village-level objections that stop a crew for weeks, route diversions around habitation, and forest and wildlife clearances that hold up a stretch while the rest of the line sits finished either side of it.

None of that is insurable, for a structural reason. Delay in start-up cover, whether written as DSU on the project policy or as advance loss of profits, responds only to delay caused by physical loss or damage that would itself be payable under the material damage section. A line stopped for eleven months at a forest boundary with every tower intact produces a total loss of revenue for that period and a nil claim.

The discipline is to split the schedule risk register in two before the placement: delay causes that trace to an insured peril, and delay causes that do not. Only the first can be priced into a DSU indemnity period.

Erection all risks is the right base product, and on a transmission package it has to cover two very different works under one policy. Section I responds to physical loss or damage to the contract works: tower foundations and stub setting, tower erection, conductor and earthwire stringing, insulators and hardware, substation civil works, and the transformers, reactors, circuit breakers and gas insulated switchgear that arrive at the substation.

The grants that decide whether the policy earns its premium sit around that core:

1. Testing and commissioning. The substation is where the most valuable equipment is energised for the first time. The testing period, and specifically the hot testing period for transformers and reactors, must match the charging sequence, and the extension must attach to the equipment being tested rather than only to the civil works.
2. Maintenance and defects liability. Extended maintenance cover, responding to damage in the defects liability period from a cause on site during construction, matters more on a line than on a plant: defective foundations and under-torqued joints reveal themselves in the first storm season after handover.
3. Third-party liability. A line under construction crosses roads, railways, canals and other utilities, so the Section II limit should be set against a credible incident at a crossing, not a percentage of contract value.
4. Free issue material. Where the developer supplies conductor, towers or transformers to the contractor, that value has to sit inside the declared contract price or be added by endorsement, or the average clause bites on the largest loss the policy will see.
5. Offsite storage. Tower parts, conductor drums and hardware sit in stores along the route for months, and sublimits written for a compact site are too small for a dispersed network.

Sums insured should be on a reinstatement basis with an escalation provision, because a line awarded on a fixed levelised tariff has no way to absorb steel and conductor price movement between bid and construction.

The loss that defines transmission underwriting is a line of towers on the ground after a convective storm. Pre-monsoon squall lines and downbursts put short-duration wind loads on a narrow track, and a corridor crossing that track can lose several towers in minutes. Towers under erection are the most exposed: the design wind capacity assumes a completed structure with full bracing and conductor tension.

The definition of one occurrence

A storm system moving across a corridor over two days can be argued as one event or as several. The occurrence clause, and any hours clause attached to storm and flood, sets whether the insured absorbs one deductible or five. Where the act of God deductible is a percentage of loss, that difference can exceed the year's premium.

Defective design, series losses and the cascade

If twelve towers fail and the cause traces to a design assumption or a repeated foundation defect, the insurer will look at the defective design and workmanship exclusion and at any series loss clause treating repeated failures from one cause as a single claim with a single deductible or sublimit. Which defects clause is used matters: a wording that excludes only the defective part itself leaves resulting damage to the rest of the structure covered, while a broader form can take the whole cluster out.

Indian tower designs use tension towers at intervals so a conductor failure does not run the length of the line. Underwriters should be shown that anti-cascading provision, the wind zone of each stretch and the erection method statement. It is the difference between a four-tower loss and a forty-tower loss, and it gives them something to rate other than a sector rate.

On the transmission SPV itself, DSU arithmetic is unusually clean. Revenue is a contracted transmission charge rather than a merchant energy sale, so the monthly loss is knowable at placement: the charge foregone plus continuing fixed costs and debt service, over an indemnity period reflecting how long a damaged substation or a downed stretch takes to rebuild. No price risk and no volume forecast to argue about is why DSU on renewable and industrial projects is easier to size on a transmission asset than on the generation it evacuates.

The gap is on the other side of the connection point. A solar or wind project can be mechanically complete, tested and ready, and still earn nothing because the evacuation line is not energised. That generator's DSU will not respond, because the delay was not caused by insured physical damage to the insured property. The damage, if there was any, happened to somebody else's asset. With a 248 GW connectivity pipeline queued to 2031, this interface is a routine failure mode, and the same exposure shows up later as curtailment and grid unavailability once both assets are running.

Generators and transmission SPVs are usually insured by different sponsors, brokers and insurer panels, so nobody owns the interface unless the lenders make somebody own it. The test at financial close: name the physical event that stops your commercial operation date, then find which policy pays for it. If the answer is neither, the exposure belongs in the contingency rather than the insurance summary.

Large power transformers set the tail on every transmission schedule. They are ordered early, built to specification, moved as over-dimensional consignments, and cannot be replaced from stock. Domestic capacity is expanding against that constraint, and Mercom India reported on 1 September 2026 that Waaree Transpower is investing Rs 1.92 billion in a transformer manufacturing facility. More local capacity shortens lead times without removing the single-item dependency on any given project.

That dependency drives three decisions at placement:

• The DSU indemnity period. Set it against the realistic replacement and re-commissioning time for the longest-lead item, not the float in the contract programme. Twelve months on a substation whose transformer takes fourteen months to replace, ship, install and re-test leaves the last two months uninsured at the point the sponsor is out of contingency.
• Transit. The road move of a transformer on a multi-axle trailer is the highest-severity single transit in the project: route surveys, bridge capacity, temporary road works, and an overturn that writes off the unit. The transit and erection policies have to dovetail so there is no gap at unloading and placement on the plinth, and transit delay that pushes the commercial operation date needs marine delay in start-up cover, a separate grant from land DSU.
• Expediting and express freight. These sublimits turn a fourteen-month replacement into a nine-month one, and are routinely written at a token figure.

The same logic runs into the operating stage through machinery breakdown cover and the revenue loss after a transformer failure, which is why the substation spares policy and the insurance indemnity period should be decided together.

At the commercial operation date the risk changes shape again. The erection policy comes off, and the SPV needs a property programme on the substation, machinery breakdown on the transformers and reactors, third-party liability along the corridor, and in several geographies terrorism cover on the substation. The line is often left uninsured on the operating side because the per-tower rebuild cost is low against the deductible. That is defensible as a deliberate decision, less so on a corridor where one storm takes out twenty towers.

Revenue cover also changes basis. Transmission charges are availability-linked, so an outage cuts revenue through the availability deduction under the transmission service agreement. A business interruption section on a transmission SPV has to be written against that deduction mechanism and the availability formula, not a notional turnover figure.

A workable structure for a TBCB transmission SPV looks like this:

1. One erection all risks policy over the line and substation, with separate deductible structures for each, testing and commissioning matched to the charging sequence, extended maintenance, and offsite storage sized to the store network.
2. DSU keyed to the contracted transmission charge, with an indemnity period set by the longest-lead item and expediting sublimits that mean something.
3. A named interfacing-facility extension where the SPV's date depends on a third-party asset, and the reverse on the generation side.
4. Transit cover with delay on the transformer consignments, dovetailed with the erection policy at unloading.
5. An operating programme mapped to the availability formula before the erection policy expires.

What decides whether each of these pays sits in the policy wording: how the occurrence clause treats a storm crossing a corridor, which defects exclusion the insurer uses, and whether the DSU trigger reaches an interfacing facility. Those clauses differ across the insurers writing engineering business in India, and the differences surface at claim stage. Sarvada gives brokers and project risk managers searchable access to insurer wordings, so a transmission SPV's erection, delay and interface exposures can be matched to the clauses that respond. If you place or advise on TBCB transmission risk, Request Access to compare the wordings before the next bid.