The EVSE hardware decision — how many stations, what charge rate, which manufacturer — gets the most attention in fleet electrification planning. The transformer capacity question, the service upgrade application, the pre-construction coordination with the serving utility: these get far less attention, and they're the reason fleet electrification projects that looked well-planned end up delayed by six to eighteen months while the utility queue processes service upgrade requests.
Utility coordination is not a bureaucratic checkbox. It is the critical path for most commercial fleet electrification projects above a modest scale. Getting it right — or at least understanding it well enough to plan around it — is what separates fleet operators who get their EVSE energized on schedule from those who discover three months into a project that the neighborhood transformer serving their depot was already near capacity.
The Service Upgrade Process
Adding significant electrical load at a commercial facility — a fleet depot adding, say, 200–400 kW of charging capacity — almost always triggers a utility service upgrade process. The scope of that upgrade depends on the existing service capacity at the facility and the capacity of the distribution infrastructure serving the area.
The process typically starts with a service upgrade application to the utility. For PGE customers in Oregon, this is a Commercial New Service or Service Upgrade application submitted through PGE's business services channel. The application describes the proposed load addition: total kW of new EVSE load, expected load profile (coincident vs. staggered, hours of operation), and the proposed service voltage level.
After submission, the utility conducts a capacity study — sometimes called a facilities study — to determine what distribution system changes are needed to support the new load. This study is where the process can slow down substantially. If the transformer serving the facility is already at or near capacity, or if the secondary distribution circuit has limited headroom, the study may find that a transformer replacement, a circuit reconfiguration, or a primary service upgrade is required. These are utility-owned assets that the utility must schedule and fund (or assess as customer contributions depending on the upgrade category) and then construct.
The timeline from service upgrade application to energized new service ranges from a few months for straightforward upgrades with available capacity to 12–18 months or more for complex upgrades requiring distribution system work. In utility service territories experiencing high volumes of EV-related service requests — which increasingly includes urban PGE territory — the queue for capacity study completions and construction work can add months to the process.
What to Submit and When
The single most important timing principle: contact the utility before you finalize the EVSE hardware design or submit permits to the building department. Utilities require a load schedule in the application — an estimate of the installed charging capacity. Submitting an application with an estimated load, getting the capacity study done, and then adjusting the EVSE design based on what the study reveals is the correct sequence. Doing the EVSE design first, pulling permits, and then submitting the utility application often results in redesign loops when the study comes back with constraints the EVSE design didn't account for.
For Oregon commercial fleet operators, the relevant contacts:
- Portland General Electric: PGE's Business Solutions team handles commercial new service and service upgrade requests. Large commercial accounts (above PGE's threshold for key account designation) may have a dedicated account manager who can expedite coordination. PGE has an EV Fleet Charging program with staff specifically focused on commercial fleet applications.
- Pacific Power: Pacific Power's commercial service team handles service upgrade applications in their Oregon and Washington territories. For large commercial installations, Pacific Power's dedicated business energy services staff can provide load coordination assistance.
- Clark Public Utilities: Clark PUD handles commercial service additions through their engineering department. As a PUD, Clark has somewhat more flexible coordination processes than large IOUs, but still requires advance coordination for significant load additions.
Rate Schedule Selection During Coordination
The utility coordination process is also the right time to confirm which rate schedule will apply to the new load — or to investigate whether changing the rate schedule on the account makes sense in light of the new load profile. Some utilities offer EV-specific commercial rate schedules (like PGE's Schedule 74) that may be advantageous for fleet charging, but eligibility and metering requirements should be confirmed during the coordination process, not after the installation is energized.
If the fleet depot is currently on one commercial rate schedule and the EVSE addition would push demand above the schedule's maximum threshold, the utility may require migration to a different schedule during the service upgrade. Understanding this in advance allows the TCO model to reflect the correct rate structure. See our article on fleet electrification TCO for why this rate schedule question matters for cost modeling.
Transformer Sizing and Demand Management
A question that comes up in utility coordination: should the service upgrade be sized for the maximum theoretical charging load (all chargers running simultaneously at full rate) or for the managed load profile (staggered charging under demand management software)?
Utilities typically size service upgrades for the connected load — the maximum potential demand from the installed equipment. This is conservative from a grid planning perspective and protects against the scenario where charging management software fails or is bypassed. From a fleet operator's cost perspective, a service upgrade sized for full connected load may result in paying for more transformer capacity than is ever actually used.
Some utilities will work with commercial customers to size service upgrades for a managed load profile if the customer can demonstrate credible demand management controls. This requires committing to a demand cap in writing and potentially installing demand limiting equipment (a separate demand controller or a formally programmed EVSE management system) that the utility can inspect. The economics of negotiating a smaller service upgrade vs. deploying demand management software are worth examining for large installations where the difference in infrastructure cost is material.
We're not saying every fleet operator should negotiate load-based service sizing — the utility's willingness to do this varies, and the paperwork involved may not be worth it for smaller installations. What we're saying is that it's a question worth asking for large depots where the difference between full-connected-load and managed-load infrastructure sizing is significant.
Make-Ready and Conduit Infrastructure
Several utilities in Oregon and Washington have offered or piloted "make-ready" programs that fund or partially fund the electrical infrastructure (transformer upgrades, conduit, panel work) needed to support commercial EV charging, leaving EVSE hardware procurement to the customer. These programs emerged from state clean transportation policy initiatives and from utility planning incentives to build load in ways that improve load factor.
PGE's Commercial EV Charging program has offered make-ready infrastructure support for qualifying commercial customers including fleet operators. Program terms, funding levels, and eligibility criteria change through PUC proceedings. Fleet operators planning large installations should ask their utility contact specifically about make-ready program availability at the time of project planning — not as an afterthought after the project budget is finalized.
Building Permit Coordination
Commercial EVSE installations require building permits and electrical inspections in addition to utility coordination. In most Oregon jurisdictions, a commercial EV charger installation requires an electrical permit from the local building authority. For large installations, a licensed electrical contractor must design and pull the permits; the utility won't energize a new service until required permits are issued and inspections are passed.
The permit timeline and the utility service upgrade timeline run in parallel and need to be coordinated. An installation that receives utility service approval but can't get an inspection appointment for 6 weeks, or that completes permitting but is waiting for utility construction, may find one track stalling the other near the end of the project. Building coordination buffers into the project schedule for both tracks is more reliable than assuming everything will resolve simultaneously.
For fleet operators navigating this process, having an electrical contractor experienced in commercial EV installations — one who knows both the utility interconnection process and the local AHJ (Authority Having Jurisdiction) permit requirements — is genuinely worth the premium over a lower-bid general electrical contractor who hasn't done a depot-scale EVSE installation before. The learning curve on process details that an experienced contractor already knows is a real project risk.