Case study: EVs & charging ecosystems — a city or utility pilot and the results so far

When the Columbus, Ohio metropolitan area installed its 1,000th public Level 2 and DC fast charger in September 2025, utilization data revealed a striking pattern: chargers placed using the city's equity-weighted site selection algorithm achieved 23% higher average utilization than those placed through traditional demand modeling alone. That finding, drawn from three years of operational data across the Smart Columbus EV charging network, upended conventional assumptions about where public charging infrastructure delivers the greatest return and offers procurement leaders a data-driven framework for replicating results in their own jurisdictions.

Why It Matters

The United States had approximately 4.5 million registered battery electric vehicles (BEVs) by the end of 2025, a figure the Department of Energy projects will reach 26-30 million by 2030 under current policy trajectories. Yet public charging infrastructure has consistently lagged adoption, with the National Renewable Energy Laboratory (NREL) estimating a shortfall of 500,000-800,000 public chargers relative to projected 2030 demand. The Infrastructure Investment and Jobs Act (IIJA) allocated $7.5 billion to EV charging through the National Electric Vehicle Infrastructure (NEVI) Formula Program ($5 billion) and the Competitive Grants for Charging and Fueling Infrastructure program ($2.5 billion), creating the largest single federal investment in transportation electrification infrastructure.

For municipal fleet managers and utility procurement professionals, the charging ecosystem challenge extends well beyond installing hardware. Grid capacity constraints, permitting timelines, site host negotiations, network interoperability, and ongoing maintenance and operations costs collectively determine whether a charging deployment succeeds or becomes a stranded asset. A 2025 survey by the American Public Power Association found that 42% of municipal utilities identified distribution transformer capacity as the primary bottleneck for new DC fast charging installations, with upgrade costs ranging from $50,000 to $350,000 per site depending on existing infrastructure.

The financial stakes are substantial. Average total installed costs for a four-port DC fast charging station (150 kW per port) reached $250,000-450,000 in 2025, with electrical infrastructure (transformer upgrades, switchgear, trenching, and utility interconnection) consuming 40-60% of total project costs. Achieving positive unit economics requires utilization rates exceeding 15-20% (defined as hours of active dispensing divided by total available hours), a threshold that fewer than 35% of US public DC fast chargers consistently met in 2024 according to data from the Alternative Fuels Data Center. Understanding what drives utilization above breakeven thresholds is the central operational question for any public-sector charging investment.

Key Concepts

Equity-Weighted Site Selection applies demographic, transit access, and environmental justice criteria alongside traditional demand signals (vehicle registration density, traffic counts, and proximity to arterials) when scoring potential charger locations. The methodology, developed by the Joint Office of Energy and Transportation in 2023, assigns additional weighting to census tracts classified as disadvantaged communities under the Justice40 initiative. NEVI program rules require that at least 40% of benefits flow to disadvantaged communities, making equity-weighted selection both a policy requirement and, as the Columbus data demonstrates, an operational advantage in markets where multi-unit dwelling residents lack home charging access and therefore depend disproportionately on public infrastructure.

Managed Charging and Vehicle-Grid Integration (VGI) encompasses demand response, time-of-use rate optimization, and bidirectional power flow (vehicle-to-grid, or V2G) that transforms EVs from simple loads into flexible grid assets. Managed charging software can shift charging sessions to periods of lower grid stress or higher renewable generation, reducing demand charges by 30-50% for site hosts while deferring utility distribution upgrades. Pacific Gas and Electric's (PG&E) EV Charge Network pilot in California demonstrated that managed charging reduced station-level demand charges by an average of 38% across 234 Level 2 sites.

Open Charge Point Protocol (OCPP) is the dominant open communication standard between charging stations and network management platforms, currently at version 2.0.1. OCPP compliance enables charger hardware to operate on any compatible network backend, preventing vendor lock-in and enabling competitive procurement. The Federal Highway Administration's NEVI minimum standards require OCPP 1.6J or higher for all federally funded chargers, with OCPP 2.0.1 recommended for new installations to support ISO 15118 Plug and Charge functionality.

Demand Charge Management addresses the utility rate structure challenge that represents the largest variable operating cost for DC fast charging stations. Demand charges, billed on the peak 15-minute power draw during a billing cycle, can reach $15-25 per kW per month in many utility territories. A four-port 150 kW DCFC station with coincident peak demand of 600 kW could face monthly demand charges of $9,000-15,000 even if actual energy throughput remains low. Battery energy storage systems (BESS), typically 100-250 kWh paired with DC fast chargers, can reduce peak demand by 40-60%, improving site economics significantly.

EV Charging Pilot KPIs: Benchmark Ranges

Metric	Below Average	Average	Above Average	Top Quartile
DCFC Utilization Rate	<8%	8-15%	15-25%	>25%
Level 2 Utilization Rate	<10%	10-20%	20-35%	>35%
Uptime (% Available Hours)	<90%	90-95%	95-98%	>98%
Revenue per Port per Month (DCFC)	<$800	$800-1,800	$1,800-3,200	>$3,200
Cost per kWh Dispensed (all-in)	>$0.55	$0.35-0.55	$0.22-0.35	<$0.22
Demand Charge as % of Opex	>50%	30-50%	15-30%	<15%
Customer Satisfaction (CSAT)	<3.5/5	3.5-4.0/5	4.0-4.5/5	>4.5/5
Time to Permit and Energize (months)	>18	12-18	6-12	<6

What's Working

Columbus Smart Columbus Charging Network

Columbus leveraged a $40 million US Department of Transportation Smart City Challenge grant (awarded in 2016) and subsequent NEVI allocations to build one of the most instrumented municipal charging networks in the country. The program deployed 1,062 chargers (872 Level 2 and 190 DCFC) across 248 sites by September 2025, with granular utilization, reliability, and user satisfaction data collected continuously.

The equity-weighted site selection algorithm proved to be the program's most transferable innovation. Sites in disadvantaged communities achieved 23% higher utilization than conventionally sited locations, driven primarily by the higher proportion of residents without access to home charging. In ZIP codes where more than 60% of housing units are rentals or multi-unit dwellings, average DCFC utilization reached 22%, compared to 14% in suburban areas with high single-family home density. The insight reversed the initial assumption that charger placement should follow EV registration density; instead, the data showed that infrastructure-dependent users generate more sessions per charger than home-charging-enabled drivers who use public networks primarily for occasional top-ups.

Columbus also demonstrated effective demand charge management. By deploying 150 kWh battery buffers at 28 high-utilization DCFC sites through a partnership with Electreon and its battery partner, the city reduced average monthly demand charges by 44%, improving site-level economics from negative to breakeven or positive within the first year of operation.

Los Angeles Department of Water and Power (LADWP) Make-Ready Program

LADWP's approach focused on reducing the single largest barrier to private-sector charger deployment: electrical infrastructure costs. The utility invested $87 million between 2022 and 2025 in make-ready infrastructure (transformers, conduit, panels, and meters) at over 2,700 sites, with private charging network operators (ChargePoint, EVgo, Tesla, and Blink) responsible for charger hardware and operations. This division of responsibility reduced private-sector capital requirements by 45-55%, accelerating deployment timelines from an average of 16 months to 7 months.

The make-ready model proved particularly effective for multi-unit dwelling (MUD) installations, where landlord reluctance to bear electrical upgrade costs had previously blocked deployment. By 2025, LADWP's program had enabled Level 2 charging access at over 850 apartment and condominium complexes serving approximately 42,000 housing units. Utilization data from MUD sites averaged 28% for Level 2 chargers, exceeding the citywide average of 19%, confirming that removing infrastructure cost barriers at rental properties unlocks significant latent demand.

Georgia Power Fleet Electrification Partnership

Georgia Power partnered with the City of Atlanta and Fulton County to electrify 350 municipal fleet vehicles (including transit buses, refuse trucks, and light-duty sedans) between 2023 and 2025, with the utility providing depot charging infrastructure under a managed charging rate structure. The custom fleet rate eliminated demand charges in exchange for the city granting the utility control over charging schedules during overnight depot windows. Georgia Power used the aggregated fleet charging load (average peak of 4.2 MW) as a dispatchable resource, shifting charging to periods of high wind generation on the Southern Company system.

The program reduced municipal fleet fuel costs by 62% on a per-mile basis (from $0.18 per mile for diesel to $0.068 per mile for electricity under the managed rate). Fleet vehicle uptime improved from 89% to 96% due to reduced maintenance requirements. The model demonstrates how utility-municipal partnerships can simultaneously solve the fleet operator's total cost of ownership challenge and the utility's need for flexible loads to integrate variable renewable generation.

What's Not Working

Permitting and Interconnection Delays

Despite federal funding availability, permitting and utility interconnection timelines remain the most persistent bottleneck for charging deployment. A 2025 analysis by the Joint Office of Energy and Transportation found that the median time from site selection to energized charger was 14.3 months for DCFC installations, with permitting consuming 4-7 months and utility interconnection adding another 3-6 months. In jurisdictions requiring environmental review under state-level equivalents of NEPA, timelines extended to 18-24 months. These delays directly conflict with NEVI program spending deadlines, creating pressure to deploy in easier-to-permit locations that may not optimize network coverage or equity outcomes.

Several states have begun implementing streamlined permitting processes. Colorado's SB 23-256 created a standardized permitting pathway for EV charging with a 30-day maximum review period, and California's AB 1236 requires jurisdictions to adopt streamlined permitting for Level 2 installations. However, DCFC permitting, which often triggers commercial electrical code reviews, ADA compliance evaluations, and stormwater management requirements, remains complex in most states.

Reliability and Maintenance Challenges

Charger reliability has emerged as a significant barrier to consumer confidence and utilization growth. A 2025 study by the National Center for Sustainable Transportation at UC Davis found that 21% of public DCFC sessions resulted in a failed or incomplete charge, with causes including software errors (38% of failures), payment processing issues (24%), connector damage (18%), and network communication failures (20%). The reliability problem is particularly acute for non-Tesla DCFC networks, where combined uptime across ChargePoint, EVgo, Electrify America, and Blink averaged 82-88% in 2024, compared to Tesla Supercharger uptime of 96-98%.

Maintenance logistics compound the problem. Third-party charging networks rely on field service organizations that may require 48-72 hours for non-emergency repairs, creating extended downtime periods that erode user trust. Columbus addressed this by negotiating 4-hour response time service level agreements (SLAs) with network operators and imposing financial penalties ($500 per day per port) for downtime exceeding 24 hours, achieving fleet-wide uptime of 94.7%.

Utility Rate Design Misalignment

Standard commercial electricity rate structures penalize the inherently peaky load profiles of DC fast charging. Analysis by Rocky Mountain Institute found that demand charges constituted 30-55% of total electricity costs for DCFC stations operating below 25% utilization, a threshold that the majority of US public fast chargers have not reached. This creates a vicious cycle: high electricity costs require high per-kWh pricing to consumers, which suppresses utilization, which keeps demand charge impacts elevated.

Some utilities have introduced EV-specific commercial rates. Southern California Edison's TOU-EV-8 rate and Con Edison's EV Fast Charge rate reduce or eliminate demand charges for qualifying charging stations, typically in exchange for time-of-use pricing that incentivizes off-peak charging. However, these rate designs remain unavailable in the majority of US utility territories. The Edison Electric Institute reported in 2025 that only 37 of the approximately 200 investor-owned utilities in the US offer dedicated commercial EV charging rates.

Key Players

ChargePoint operates the largest open charging network in North America with over 70,000 ports, offering both hardware sales and network-as-a-service models for fleet and public charging applications.

Tesla has opened over 60% of its US Supercharger network to non-Tesla vehicles following NEVI program participation, with the NACS connector becoming the de facto North American standard after adoption by Ford, GM, Rivian, and others.

EVgo focuses on metropolitan fast charging with over 1,000 DCFC locations, pioneering co-located battery storage for demand charge management at high-utilization urban sites.

ABB E-mobility supplies DC fast charging hardware globally, with the Terra 360 achieving 360 kW per port, supporting the latest 800V vehicle architectures from Hyundai, Kia, and Porsche.

Joint Office of Energy and Transportation coordinates federal NEVI and Competitive Grant programs, providing technical assistance to state departments of transportation on site selection, procurement, and standards compliance.

Pacific Gas and Electric (PG&E) has invested over $380 million in EV charging make-ready infrastructure across Northern and Central California, serving as a model for utility-led deployment strategies.

Action Checklist

• Conduct a distribution grid capacity assessment for planned charging sites, including transformer loading analysis and upgrade cost estimation
• Implement equity-weighted site selection methodology incorporating Justice40 criteria, rental housing density, and transit access metrics
• Negotiate demand charge mitigation strategies with the local utility, including EV-specific commercial rates, managed charging agreements, or battery storage deployment
• Specify OCPP 2.0.1 compliance and ISO 15118 Plug and Charge capability in all procurement solicitations to prevent vendor lock-in
• Establish minimum uptime SLAs of 95% with financial penalties for sustained downtime in network operator contracts
• Coordinate with permitting authorities early to identify potential review requirements and establish expedited pathways where available
• Deploy managed charging software for fleet depot installations to minimize demand charges and participate in utility demand response programs
• Collect and publish utilization, reliability, and cost data transparently to inform future deployment decisions and build public accountability

FAQ

Q: What utilization rate is needed for a public DC fast charger to achieve positive unit economics? A: Breakeven utilization depends heavily on local electricity rates, demand charge structures, and pricing to consumers. Under typical US conditions (blended electricity cost of $0.25-0.35 per kWh including demand charges, consumer pricing of $0.40-0.55 per kWh), DCFC stations require 15-20% utilization to cover operating expenses excluding capital recovery. Including capital amortization on a 10-year basis, breakeven utilization rises to 20-30%. Stations with battery storage for demand charge management or utility EV-specific rates can achieve breakeven at 12-15% utilization.

Q: How should procurement teams evaluate NEVI compliance requirements for federally funded chargers? A: NEVI minimum standards require: CCS connectors (with NACS adapters or dedicated ports permitted), 150 kW minimum per port with at least four ports per station, 97% uptime reporting, OCPP 1.6J or higher, contactless payment acceptance, and real-time availability data sharing. Procurement solicitations should specify these as minimum thresholds and add requirements for OCPP 2.0.1, ISO 15118 support, and ADA-compliant design. Evaluate bidders on demonstrated reliability track records, not just hardware specifications; request uptime data from comparable existing deployments.

Q: What is the business case for utility make-ready investment versus site-host-funded infrastructure? A: Utility make-ready programs accelerate deployment by 40-55% (measured by months from site selection to energized station) and reduce private capital requirements proportionally. Utilities recover make-ready investments through incremental electricity sales and rate base additions that earn regulated returns. For site hosts, utility make-ready eliminates the largest capital expenditure line item and shifts infrastructure risk to the utility. The trade-off is reduced site host control over electrical infrastructure design and potential rate adjustments over time. In LADWP's program, make-ready sites achieved first-year utilization 35% higher than comparable non-make-ready sites, suggesting the speed advantage translates directly to earlier revenue generation.

Q: How do managed charging programs affect fleet vehicle operations? A: Well-designed managed charging systems maintain full operational readiness by establishing minimum state-of-charge thresholds (typically 80-90% by shift start) while optimizing charging schedules within those constraints. Georgia Power's municipal fleet program demonstrated zero operational impacts from managed charging across 350 vehicles over 18 months, while reducing electricity costs by 38% versus unmanaged charging. The key design requirement is accurate departure time forecasting; fleets with predictable schedules (transit, refuse, school buses) are ideal candidates, while emergency or on-call vehicles should be excluded from managed charging programs.

Q: What emerging technologies will most impact charging infrastructure economics in the next 3-5 years? A: Three technologies will reshape economics: (1) Megawatt Charging System (MCS) standardization for heavy-duty vehicles, enabling 1+ MW charging that opens the commercial fleet segment but requires significant grid upgrades; (2) bidirectional charging (V2G/V2B), which enables revenue generation from parked EVs providing grid services, with pilot programs showing $800-2,000 annual revenue per vehicle; and (3) battery-integrated charging stations that decouple charger power output from grid connection capacity, potentially reducing infrastructure costs by 30-50% at constrained sites.

Sources

• National Renewable Energy Laboratory. (2025). National Charging Network Assessment: Gap Analysis and Deployment Scenarios. Golden, CO: NREL.
• Joint Office of Energy and Transportation. (2025). NEVI Program Implementation: Year Two Progress Report. Washington, DC: JOET.
• Smart Columbus. (2025). EV Charging Network Performance Report: 2022-2025 Operational Data Summary. Columbus, OH: City of Columbus.
• Rocky Mountain Institute. (2025). Reducing EV Charging Costs: Rate Design and Demand Charge Solutions. Basalt, CO: RMI.
• National Center for Sustainable Transportation. (2025). Public EV Charger Reliability: National Assessment of Failure Modes and Uptime. Davis, CA: UC Davis.
• Los Angeles Department of Water and Power. (2025). EV Make-Ready Program: Deployment Outcomes and Utilization Analysis. Los Angeles, CA: LADWP.
• Edison Electric Institute. (2025). Electric Company EV Programs and Investments: 2025 National Survey. Washington, DC: EEI.