Upgrade or not upgrade. That is the question.
The answer most operators will be given is to upgrade. But not many understand electrification well enough to know whether that advice is viable.
The advice usually comes from an electrician or a charger vendor, and it tends to sound like: “you’ll need a bigger supply,” “the DNSP will need to assess the site,” “the existing connection won’t support the new load.” It sounds technical, it sounds definitive, and most operators accept it.
Our position is that, for the majority of depots, that advice is wrong. Or, more accurately, it is incomplete. Very often, there is a managed-charging path that does not require an upgrade, yet most operators are never shown it before they commit to the slower, more expensive option.
This article walks through what a grid upgrade actually involves, when it is genuinely the right answer, and what the alternative looks like in practice.
What a grid upgrade actually involves
A grid upgrade is not a single line item. It is a programme of work that touches three different parties, two regulatory environments, and your day-to-day depot operations. The cost is measured in millions.
We have seen real upgrades land anywhere from around $5 million for a smaller, well-located site to as much as $200 million for a complex one. The figure is driven by how many vehicles you operate, your operational requirements, the location of the depot, the limitations of the local grid, and whether other large customers are already drawing on the same network capacity.
The work itself moves through six stages:
- You enquire with your Distribution Network Service Provider (DNSP).
- You submit a formal connection application with line diagrams and engineering documentation.
- The DNSP assesses available capacity and issues a connection offer, typically anywhere from ten days to eight weeks for the offer itself.
- You sign an augmentation agreement.
- Design and construction begin, which is consistently the longest stage. From the original application through to energisation, our experience is that the upstream upgrade typically takes eighteen to twenty-four months.
- Finally, the system is commissioned, the metering is updated, and the depot is energised.
It is also important to flag that the connection process is not consistent across Australia’s distribution networks. There are around 16 DNSPs nationally, and the rules, timelines, and documentation differ between them. If your depot or fleet operates across two states, you are effectively running two parallel processes.
Then there is the depot itself. Depots are already constrained for space. A grid upgrade adds excavation for cabling, switchroom works, scheduled outages for the cutover, and movement constraints that affect daily operations.
To summarise: millions of dollars, eighteen to twenty-four months, three parties, and operational disruption to a site that is already running tight. Because of that, you need to be very sure a grid upgrade is the only option before committing to it.
Why grid upgrades are the default recommendation, and when that advice is right
When an operator first explores electrification, the people they speak to, including electricians, charger distributors, and sometimes the DNSP itself, are sizing the connection against worst-case simultaneous draw.
The standard rule is straightforward: assume every vehicle plugs in at the same time, draws maximum power, and that your connection has to support that peak. By that calculation, almost every depot needs more capacity than it currently has.
Those parties are not in the business of modelling managed-charging scenarios across an entire shift pattern, and they do not usually have the tools to do so. The result is sound advice for a worst-case framing, but often the wrong starting point for most fleets.
There are, however, real cases where a grid upgrade is the right answer. Common decision factors include:
- Genuine capacity: A depot with very high vehicle counts on a small or weak existing connection, where even fully managed charging cannot deliver enough energy inside the available dwell window.
- Dwell pattern: Very short turnaround times that force DC fast charging that cannot be spread out over time.
- Bidirectional V2G: Significant two-way flow as part of the operational model.
- Existing non-charging loads: Loads that already consume the available headroom.
- Reliability and contingency: Deliberately building in spare capacity so that single-point failures elsewhere do not constrain the fleet.
Try this self-test: given the total kWh each vehicle needs per day and the dwell window available between shifts, can that energy be delivered within the existing connection’s kW limit at your installed charger capacity?
Given each vehicle needs 80 kWh per day and has a 10-hour overnight dwell window, it requires an average energy delivery rate of around 8 kW. Across a fleet of 100 vehicles, that represents roughly 800 kW of total overnight energy demand. In practice, however, intelligent charging systems stagger and throttle charging so the full load is rarely drawn simultaneously. If the required daily energy can be delivered within the site’s available charging window and existing connection limit, managed charging is likely the right starting point. If it cannot, even after realistic load management assumptions, you may be in upgrade territory.
Either way, the decision deserves a proper professional view. There are always site-specific operational needs that sit outside the description above, and getting the diagnosis right is essential.
The alternative: intelligent load management
An Energy Management System (EMS) acts as a conductor. It decides, second by second, which vehicles charge, how fast they charge, and when charging occurs, all under a hard ceiling set by your existing connection.
In practice, the system continuously monitors aggregate site headroom alongside each vehicle’s state of charge and required departure time. Vehicles on the critical path, such as the next bus out or the van that has to leave at 4:30am, get priority. Vehicles with more dwell time are throttled or deferred.
The total site draw stays under the kW limit you already have because the software, not the operator, manages it.
The same engine handles demand charges, and this is where the saving is largest and least visible. Commercial demand tariffs in Australia work on a simple principle: your monthly bill is partly driven by the highest thirty-minute window of power your site draws during the billing period.
You do not have to hit that peak repeatedly. Once is enough.
If, on the second Tuesday of the month, half the fleet plugs in within the same window and the site pulls a peak it should not have, that peak becomes the basis of what you are billed for across the whole month.
For a typical depot running around 100 AC-charging vans, a single coincident charging event can set the site’s monthly peak demand. At typical demand tariffs of roughly $10–$20 per kW per month, a peak in the 400–600 kW range can translate into a monthly demand charge of around $4,000–$12,000. Across a year, unmanaged charging at that scale routinely crosses into six figures of demand charges, most of which a properly configured EMS simply will not allow to happen.
On-site battery storage has a role, but a narrower one than most vendors present. Where the connection is constrained over short windows, but not across the full day, or where the operation genuinely requires fast charging that cannot be spread across time, on-site storage absorbs energy steadily from the grid and discharges it quickly into vehicles.
If you want to learn more, head to Beyond EV Battery as a Service.
What this means for your timeline and business case
The first important thing to consider is time. A grid upgrade typically takes eighteen to twenty-four months of upstream work before the depot can begin reliable electrified operation.
That is eighteen to twenty-four months in which you are not receiving the operational and fuel-cost benefits of the EV fleet you are already paying to procure.
Managed charging removes that wait. The depot energises against its existing connection, and the rollout moves forward at the pace of the fleet rather than the pace of the network.
The second thing is capital. Upgrades land in the millions, anywhere from around $5 million through to, in some cases, more than $200 million.
Even at the low end of that range, an avoided upgrade is the largest single line item most operators will ever remove from their electrification CapEx. Reinvested in vehicles, depot equipment, or operational reliability, that capital materially changes the shape of the programme.
Translating that into a defensible business case is what a scoping call is for. We work through five things with the operator:
- A review of the existing connection specifications and tariff structure.
- The operational data, including duty cycles and dwell times, that determine what the depot actually needs to deliver each day.
- Per-vehicle energy requirements modelled against that data.
- An optimised charging schedule that minimises the cost of energy and demand charges, stays within the site’s existing limits, and prioritises vehicle serviceability.
- A clean, side-by-side comparison of the upgrade path versus the managed path, in both cost and time.
The output is specific. If the modelling shows you do need a grid upgrade, we will say so. More often than not, it shows you do not.
The question worth asking before you commit
Before you sign the application that starts an eighteen-month, multi-million-dollar grid upgrade, ask one question: has anyone modelled the charging load for this depot using intelligent scheduling against the connection you already have?
In our experience, the answer is often no, because no one has shown the operator the alternative.
Book a scoping call → We will model your depot’s charging load and tell you honestly whether you need a grid upgrade.