Electric Vehicle Infrastructure

Are time-of-use (TOU) rates good or bad for the electric grid? While TOU rates aim to reduce system-wide peaks, they can increase grid stress and costs under many current designs—especially with the rapid growth of #electricvehicles and #electrification. Here’s why: Residential TOU peak periods typically end around 7-9 pm (survey of 30 large utilities). Many EV owners start charging immediately after off-peak rates begin, but these periods are based on system-wide loads, not local distribution peaks. Now, picture a neighborhood with 10 homes on a shared transformer, where 5+ homes have EVs. With each EV drawing around 7 kW, the load can more than double each household's load. The result? Transformer failures are the first sign of strain. As electrification grows, the stress will extend to feeders, substations, and beyond. So, should we abandon TOU rates? Regulators favor them because they shift load off-peak, are low cost, and are backed by historical results. But the more compliance, the more severe the local #grid stress. Another challenge: shifting peak periods. As #renewables like #solar and #wind expand and grid-scale #batteries become common, peak times are moving. California’s "duck curve" shows demand now shifting to different parts of the day. We now need to encourage EV charging mid-day in solar-rich areas! Constantly re-educating consumers on changing peak/off-peak times is impractical. What’s the fix? OPTION 1: Move off-peak to midnight. Some utilities now start off-peak for EVs at midnight when household demand is low, reducing but not solving the surge problem. OPTION 2: Stagger TOU start times. Spreading start times across households could ease local strain but is complex and unpopular with regulators. OPTION 3: Adopt dynamic solutions. The best option for now is managed EV charging (until we get #V2G). Customers set a "ready by" time (e.g., morning), and utilities optimize charging based on battery status, grid conditions, and costs. This keeps costs low for both consumers and the grid and the consumer gets a full charge without any intervention. 3A: Whole house vs. EV specific rates? Different appliances have different characteristics, time-based value, and needs. I think it makes sense to treat EV pricing separately that the other appliances in the house, just like we do for solar rooftop. While dynamic solutions like managed charging are the future, a mix of pricing options is essential. No single approach will work for every customer or address the grid’s evolving needs. Your thoughts? P.S. I've included a link to a longer PLMA (@PLMAflm) discussion about electricity pricing that includes ideas from myself and Ahmad Faruqui. #energy #utilities #gridmanagement #TOU #EVcharging #tesla #rivian #electricvehicles

Peak demand is the most expensive problem in electricity. A 15-minute DC fast charge can create a demand spike exceeding 1 MW per vehicle, requiring oversized transformers and stranded distribution assets. These short-duration, high-amplitude peaks lower asset utilization and force utilities into costly overbuilds. The spike isn't the only part of the issue. We also have to consider the human behavior behind fast charging. When people fast charge, it’s usually because they’re in the middle of a trip or scrambling to recover from forgetting to plug in. In those moments, they’re inflexible. They need energy right now. That urgency means utilities can’t shift the load. At home, the opposite is true. Whether your car fills at 9 p.m. or 11 p.m. doesn’t matter... as long as it’s ready by morning. That flexibility is gold for utilities. It allows charging to be spread out, shifted to off-peak hours, and harmonized with other loads. That’s why a distributed, low-power Level 2 model produces a long-dwell, low-amplitude load curve. The aggregate effect is a flatter, more predictable demand profile: - Loads are shifted into overnight off-peak periods - Transformer capacity is preserved by spreading kWh delivery over time - Distribution utilization improves, increasing ROI on existing assets When deployed in multifamily properties (dense clusters of vehicles colocated near commercial load centers), this model supports local grid balancing without requiring new generation. The outcome is a rare alignment: Utilities reduce capital costs, property owners provide charging at scale, and EV drivers gain convenience. This isn’t about “slow vs. fast charging.” It’s about aligning charging profiles with utility economic models. #EnergyManagement #UtilityEconomics #EVInfrastructure

Last week, I got a call from a condo board in Toronto. They'd installed 20 EV chargers in 2023 using a cloud-based load management system. The contractor sold them on "smart technology" that would save them from upgrading their electrical service. Today, that entire system needs replacement. It doesn't meet Ontario's new safety requirements under ESA Bulletin 8-8-0. The bill? $180,000. The contractor who installed it? Nowhere to be found. Quick context for those unfamiliar: Power Control Systems (PCS) and EV Energy Management Systems (EVEMS) electronically control power to prevent overloading your electrical infrastructure. They're what allow buildings to install multiple EV chargers without massive service upgrades. Think of them as smart traffic controllers for electricity. Here's the reality hitting buildings across Canada: Every uncertified Power Control System installed today will need complete replacement. Not updates. Not patches. Full replacement. The ESA bulletin is clear: cloud-based control for critical safety limits is prohibited. When you're using Section 8 load calculation relaxations in the Canadian Electrical Code, your PCS must be certified to CSA 22.2 No. 343:25 or ULC-ORD-3141. No exceptions. Why these certifications matter: They prove the system keeps working when internet fails, power flickers, or components break. Your electrical safety can't depend on a server in California staying online. Cloud monitoring? Fine. Cloud control of safety limits? Illegal in Ontario. And soon everywhere else. To every AHJ across Canada: Start enforcing these standards now. Every uncertified system you approve today becomes tomorrow's $180,000 replacement project. Ask one question: Is the PCS certified to CSA 22.2 No. 343:25 or ULC-ORD-3141? If not, reject it. That Toronto condo trusted their contractor. The contractor trusted the manufacturer. Now 20 families are sharing the cost of doing it right the second time. Ontario has shown leadership with this bulletin. The standards exist. The requirements are clear. How many more buildings will install systems that need immediate replacement before other provinces follow? #ElectricalSafety #PowerControlSystems #EVCharging #ElectricalCode #BuildingSafety

I can see the day when electric utility peak demand is driven by transportation rather than temperature. Today's hot summer afternoons and cold winter mornings when electricity demand peaks will be replaced by travel holidays like Thanksgiving, Memorial Day, Fourth of July, Christmas, and Labor Day, when Americans take the roads en masse in their #EVs. I took a Labor Day trip to Wrightsville Beach for a frolicking boys' weekend. The trip was 700 miles roundtrip from my home in the mountains of western North Carolina. I headed out on Thursday ahead of holiday traffic and, as usual in the #EV-lagging Southeast, had the two Superchargers I stopped at to myself. But on the way back on Monday with the rest of the holiday frolickers, most of the chargers were occupied and were gobbling electricity. With the percentage of EVs on the road in the single digits, holiday travel has yet to impact peak demand at scale. However, during the next decade, EV penetration will trigger peak demand problems state by state. The peak EV demand problem is more of an electricity management issue than a power generation issue, so it won't be solved by building more stationary power plants. After all, EVs are on wheels and do not stay within a single power plant's reach. On my trip to the beach, my EV pulled power from four different power plants. Nor can utilities use the same strategies for on-road EV charging as home charging, such as using price signals to incentivize charging when abundant power is available. When driving long distances, EV drivers don't choose when to charge; the battery does. Hence, utilities must start planning for and getting deft at managing ever-increasing EV charging loads on the roads. Planning for and building the needed grid infrastructure to effectively manage complex mobile electricity loads will take about as long as it will take for EVs to become an electric utility management problem. So now that we all enjoyed a Labor Day weekend, we better get back to work! #electricvehicles #evcharging #climateaction #cleanenergygeneration

This study highlights a crucial insight: while EVs reduce CO₂ emissions and support sustainability goals, their success relies on integration with power grids, transport systems, and intelligent information networks. The research shows that charging demand during peak hours (1–4 pm) creates major stress on the grid, especially when charging stations are concentrated in limited areas. Without proper management, EV growth can lead to grid instability and higher energy demand. The study recommends incentivizing night-time charging and smart charging policies to balance demand. Why this matters for Oman? As Oman accelerates its EV journey (targeting 20,000 EVs by 2027), similar challenges will arise. Our power grid, urban planning, and charging infrastructure must evolve together. Ministry of Energy and Minerals, Ministry of Transport, Information Technology and Communications, Nama Group What should be considered? - Expanding distributed charging infrastructure across cities to avoid overloading specific zones. EV national Map is required. - Introducing differential tariffs to encourage off-peak charging. - Leveraging renewable energy integration (solar-powered stations) to align EV adoption with Oman’s Net Zero 2050 commitments. - Building an intelligent transport-energy system that connects EV data with grid operations for smarter decision-making. #ElectricVehicles #EVAdoption #EVCharging #FutureMobility #SustainableTransport #Decarbonization #NetZero2050 #EnergyTransition #Oman2040 #OmanNetZero #GCCEnergy #GreenOman #SustainableOman

Is the grid ready for EVs? With the rise in popularity of EVs, we're seeing a significant shift in electricity demand. As more people choose EVs, the need for electricity to power them is rapidly increasing. This surge in demand poses a unique challenge to our electric grids, which are the lifeline of this new automotive revolution. This challenge goes beyond simply producing enough electricity. The real test is in ensuring our electric grids can handle the increased load, particularly during peak times when the demand for electricity is at its highest. This is especially true in urban areas, where EV adoption rates are higher. But it’s not just about quantity; it’s about quality and management of the supply. We need to ensure our grids are not just robust but also smart. Smart grids, equipped with modern technology, can monitor and manage energy flow more efficiently. They can dynamically adjust to changing patterns in electricity usage, like the high demand during evening hours when people return home and plug in their EVs. Furthermore, integrating renewable energy sources into the grid is crucial. As EVs are meant to reduce our carbon footprint, it's essential that the electricity they use comes from clean sources. This integration also helps in balancing the grid load, as renewable sources like solar and wind can provide power during peak demand times. We also need to consider advancements in battery storage technology. Large-scale battery storage systems can store excess energy during low demand periods and release it during high demand, alleviating the pressure on the grid. How do you think we can best manage the increasing strain on electric grids due to the growing number of EVs, and what innovations do you believe are key to adapting our grids for this new era?”

What are hot and cold loads, and why does it matter when sizing equipment and setting relays? This is kind of an interesting topic because it is something most engineers do not run across very often. Hot and cold load factor deals with load diversity. Most loads have minimum and maximum demands that do not line up perfectly with one another. Hot water heaters, electric heat, air conditioners, pumps, and motors are not running 100% of the time. They cycle on and off as needed. Because of that, the maximum total load is usually not just the sum of all of their individual peaks. That is diversity. When a system loses diversity, a lot of those loads start trying to operate at the same time. This often happens following an outage or when everyone wants to do something like charge their EV cars at the same time. Low diversity or simultaneous EV car charging can cause capacity issues. A lot of cars on Level 2 charging pull around 7 to 12 kW, and some go even higher. That is as much as, or more than, what many homes see during normal peak usage. The bigger issue is coincidence. If everyone plugs in after work at the same time, the system sees a large new demand all at once. That is why staggered or smart charging gets pushed so often as a way to reduce utility capacity upgrades. This also matters in relaying. A pickup based on hot load can trip unnecessarily during cold load pickup. For example, if a distribution feeder has been de-energized for a while, a lot of customer loads, pumps, compressors, air conditioners, electric heaters, and water heaters may all try to come back on immediately when power is restored. That can trip relay settings based on normal 'hot' load conditions. You would not want that. But you also would not want to set the normal pickup so high that it loses sensitivity during normal operation. That is why timers and relay logic are often used to determine whether the relay should be using a hot load pickup or a cold load pickup setting based on what just happened on the system. Hot load is load operating with diversity. Cold load pickup is what happens when that diversity temporarily disappears and a large amount of load tries to come on at once. #utilities #substation #electricalengineer #renewables #energystorage #electriccars #EV

Batteries are becoming one of the most powerful tools in the EV-charging playbook. When you combine the right battery, the right tariff and the right charging profile, the impact on utility bills can be huge. In the US, the real killer is not the cents per kWh. It is the dollars per kW. Many commercial tariffs hit $20-$40 per kW, especially in CA, NY, HI and parts of the Midwest. A couple of 150 to 350kW fast-charging sessions can set the entire monthly peak. That is why DC fast charging often sees 30-60% of its electricity bill tied up in demand charges. Even AC sites at hotels, depots or workplaces can trigger expensive peaks if 20+ cars plug in at the same time. This is where battery storage changes the math. Take Sycuan Casino Resort in California. PowerFlex deployed more than 100 Level 2 ports, several DC fast chargers and a 250kW / 560kWh BESS, all orchestrated through one platform. AC charging shifts into cheaper hours, the battery handles the spikes and the building avoids the demand-charge hammer. That is how you combine storage with mixed AC/DC in a real-world, high-load environment. For DC fast charging, battery-buffered systems are becoming the only way to scale without burning money. The concept is simple. Pull a steady 50-75kW from the grid. Let the battery absorb the 150-300kW peaks. Avoid a six-figure feeder upgrade. Across multiple utility models, properly sized BESS routinely delivers 40-50 percent peak reduction and 20-30 percent total electricity cost savings. Add solar and you squeeze more value, but peak control is the main event. Tesla has been quietly proving this at their own sites. Newer Supercharger locations in the Southwest that pair Megapacks with solar flatten the load they expose to the utility and avoid extreme demand events while still giving drivers the full experience. But battery storage is not a universal fix. For AC-heavy installations, hotels, offices, multifamily, campuses, software often beats hardware. Smart load management, staggered charging, dynamic site caps and time-based prioritization can deliver most of the benefit at a fraction of the cost. Only when the tariff, building peak and EV load truly justify it does a battery become the right investment. And batteries come with real costs. Even with IRA incentives, commercial systems still run hundreds of dollars per kWh installed. Add UL9540A testing, fire-life-safety requirements and interconnection reviews, and the economics collapse quickly if you misjudge the cycling or oversize the system. Batteries plus EV charging are incredibly powerful when deployed with precision, at high-demand sites, grid-constrained locations and mixed-use destinations where unmanaged peaks destroy margins. Used blindly, they simply shift CapEx from the transformer pad to a steel box in the car park. RENON POWER #EVCharging #BatteryStorage #BESS #EnergyCosts #DemandCharges #DCFC #EVInfrastructure #SmartCharging #FleetElectrification #Microgrids #EnergyManagement

Getting fleet charging right isn’t about plugs — it’s about strategy. Up to 30–40% of EV fleet downtime can be linked to poor charging access or planning The most successful EV fleet programmes don’t ask: ❌ “Where can we charge?” They ask: ✅ “What charging model actually fits how this fleet operates?” Because the wrong infrastructure decisions don’t fail loudly — they quietly erode utilisation, cost savings and service reliability. Depot charging: control & consistency 70–80% of fleet charging typically happens at depots for return-to-base operations (local authorities, waste, highways, pool cars, service fleets), depots remain the backbone. Predictable access, managed maintenance, overnight charging — and clear governance. The challenge? Grid capacity. Smart fleets plan early with DNOs, phase deployments, mix charger speeds and avoid “all-at-once” electrification that outpaces available power. As Grid upgrades can take 12–36 months, making phased rollouts critical. Home charging: convenience with complexity Perfect for distributed teams — housing officers, community services, sales and field engineers. But it brings governance challenges: reimbursement, safety, ownership and monitoring. Best practice = clear policies, standardised installs via approved providers like Evolt Charging and simple, auditable reimbursement models (especially critical in the public sector). Public charging: flexibility, not default Public networks have improved — but for fleets, they work best as a strategic supplement, not Plan A. As, charging typically costs 2–3x more per kWh than depot or home charging Ideal for: • Long routes & top-ups • Contingency planning • Variable duty cycles Risk comes from variability (availability, downtime, pricing). Leading fleets counter this with driver training, route planning, preferred networks and clear escalation plans. Load management: where money is won or lost Smart charging, scheduling and energy monitoring are the real performance levers. The best operators treat charging like a controlled operational process — not an ad-hoc activity. Well-managed EV fleets achieve 20–30% lower cost per mile compared to ICE equivalents 🚛 Different fleets, different answers • Local authorities prioritise reliability & governance • Utilities balance resilience across dispersed teams • Commercial fleets focus on uptime, cost per mile & scalability Charging infrastructure isn’t an add-on to fleet strategy. It is fleet strategy. The fleets that win are those designing charging around duty cycles, power constraints and real-world operations from day one. 👉 Looking for EV & Hybrid fleet charging solutions? Drop me a message to see how Evolt Charging helps organisations design charging that actually works — operationally, financially and at scale. #EVstrategy #Fleet #EVCharging #NetZero #FleetCharging #LocalAuthorities #Utilities #CommercialFleets #FleetManagement #SmartCharging #TransportDecarbonisation

Organising tenders for public EV charging infrastructure is a key tool for public authorities - national, regional and local - to shape the EV charging network needed to enable their citizens to switch to electric private or shared cars and vans. As part of the European Commission's Sustainable Transport Forum sub-group on best practices by public authorities to support the deployment of charging infrastructure, we've produced this new updated guide. Getting EV charging right - both in terms of planned locations and the ability of users to charge flexibly - is a key objective for public authorities, especially as grids increasingly appear to be a bottleneck in the wider energy transition. Concession agreements can be used as a tool to channel and direct (future) charging demand to areas with sufficient capacity or where grid upgrades are feasible or planned. Passing on dynamic energy prices and the benefits of DSO-led local flexibility programmes to end users will not only reduce their bills, but also deliver wider societal benefits - a key reason to get it right. (For more on this topic, also see Regulatory Assistance Project (RAP)'s short public authorities smart charging guide by Dr. Julia Hildermeier and me: https://lnkd.in/gEtUd_XX) Using concessions as a tool, public authorities can ensure that public EV charging takes place in locations: ⚡ where grid capacity is available 👐 expanding access and improve accessibility ☀️ can be co-hosted with renewable energy generation 🚃 align with multimodal transit, parking vision As EVs mature, public charging network deployment may progress through stages: one after another: 📍 Strategic 🕸️ Coverage-based 📈 Usage-based Ensuring that chargers facilitate the ability of users to integrate their electric vehicles into the energy system (AFIR, Article 15.3) is another aspect that public authorities can address in a tender. Similarly, these tender requirements should include requirements for energy efficiency, modularity and upgradeability to extend the technical life of the charging infrastructure. Public authorities can also speed up the roll-out of public charging and reduce costs for all parties involved by coordinating with their local DSO at all stages. By forecasting and properly modelling (flexible) EV charging demand, the necessary (anticipatory) investments can be made as needed. Pre-approval and pre-application for grid connections before / during a tendering process can significantly speed up the actual deployment by selected charging point operators. One-step approaches, where the grounding and other civil works for the grid connection by the DSO, the installation of the charging point by the operator and the right parking / signage by the public authority are all combined in one go, are a proven way to save time and the scarce resource of skilled labour needed in the energy transition.