PSE&G New Jersey commercial EV charging investment playbook

Why PSE&G's commercial EV charging programs matter structurally

PSE&G's commercial EV charging program is a substantially different investment proposition from residential charging programs covered in companion Drive Economics analyses. Where residential make-ready delivers up to $6,500 per home to a single property owner making a modest electrical investment, commercial make-ready can deliver tens of thousands to hundreds of thousands of dollars per site to institutional investors making substantial capital expenditure decisions on behalf of businesses, property developers, fleet operators, and municipal operations. The decision calculus accordingly shifts from household budget optimization to corporate capital allocation evaluated against standard investment thresholds.

Three structural characteristics distinguish commercial EV charging investment from the residential context. First, demand charges — a feature of commercial electricity rates largely absent from residential — create operating cost structures where facility peak kilowatt demand can drive bill composition as substantially as total kilowatt-hour consumption. For high-power DC fast charging specifically, demand charges can dominate operating expense in ways that fundamentally change project economics. Second, revenue models vary dramatically across use cases, from no direct revenue (workplace amenity) through operational cost offset (fleet) to direct user-pays revenue (public DCFC), producing fundamentally different IRR calculation structures and sensitivity analysis frameworks. Third, capital expenditure scales from tens of thousands of dollars (workplace L2) through hundreds of thousands (public DCFC) to millions (large fleet depots), requiring investment analysis at the scale typical of corporate capital planning rather than household budgeting.

This playbook treats PSE&G as the worked example throughout; the framework generalizes to any utility territory. The sections below cover PSE&G's three commercial program tiers, the commercial electricity rate schedule landscape in New Jersey, demand charge economics, equipment and installation costs, use-case-specific IRR scenario modeling for workplace, fleet, and public DCFC applications, a site selection and investment decision framework, and comparative positioning against peer utility commercial programs.

Commercial electricity rates in PSE&G New Jersey territory

Commercial EV charging economics in PSE&G territory depend on three interrelated rate structures that together determine the all-in cost of delivered electricity for commercial customers: the base rate schedule (General Lighting and Power, Large Power and Lighting Secondary, or Commercial and Industrial Energy Pricing), the demand charge structure applied within each rate schedule, and the time-of-use or time-of-day modifiers that adjust pricing by period. For prospective commercial EV charging investors, understanding where a proposed site falls within this rate structure landscape is the single most important input to pro forma development.

PSE&G's core commercial rate schedules partition customers by load profile characteristics:

• General Lighting and Power (GLP) — for smaller commercial and industrial services. Features standard flat energy pricing or specific day/night usage blocks under the Night Use Special Provision. Includes per-kilowatt generation and transmission obligations that scale with facility peak load share.
• Large Power and Lighting - Secondary (LPL-Secondary) — for larger secondary-voltage commercial users typically under 500 kilowatts peak load share. Features explicit on-peak and off-peak time-of-use energy pricing, higher demand charges than GLP, and significant generation and transmission obligations.
• Commercial and Industrial Energy Pricing (CIEP) — mandatory or optional hourly energy pricing typically applied to accounts of 500 kilowatts or greater peak demand (or elected under lower schedules by sophisticated customers). Includes a small CIEP Standby Fee ($0.000150 per kilowatt-hour, or $0.000160 including Sales and Use Tax) to cover Basic Generation Service administration. Hourly pricing structure requires more sophisticated load management but can produce substantial savings for customers with the operational capability to shift consumption.

Default supply vs third-party supplier

New Jersey operates as a deregulated electricity market. Commercial customers may remain on PSE&G's default Basic Generation Service — set via statewide New Jersey Board of Public Utilities auctions — or contract with a licensed New Jersey Energy Choice third-party supplier for fixed-price or indexed-pricing supply arrangements. For commercial EV charging investments the key observation is that competitive supplier contracts can change energy and capacity rates but do not reduce PSE&G delivery tariffs including demand charges, which remain billed through PSE&G regardless of supply arrangement. Prospective DCFC investors cannot shop their way out of demand charges by selecting a competitive supplier.

The demand charge economics: often the dominant commercial EV charging operating expense

Demand charges are the single most important commercial electricity rate feature that distinguishes commercial EV charging economics from residential. For public DC fast charging specifically, demand charges can exceed energy charges by a substantial margin and can determine whether a project is viable or non-viable at a given utilization rate.

Three mechanics of demand charges warrant careful attention:

• Peak demand measurement: Commercial accounts in PSE&G territory are billed based on the single highest 30-minute (or interval-metered) peak kilowatt demand recorded during the billing cycle. A site with 600 kilowatts of installed charging capacity that briefly operates at full output for even one 30-minute period in a month is billed at 600 kilowatts of peak demand for that entire month, regardless of average usage patterns across the rest of the month.
• Capacity obligations: Accounts under GLP and LPL schedules carry monthly demand-based generation capacity and transmission capacity obligations, often reported as separate line items on the bill. For LPL customers these obligations are frequently assigned via PJM Peak Load Share, which can create ratchet effects where peak demand from previous months continues to drive capacity charges even after the actual peak event has passed. Combined demand-related charges in PSE&G territory typically run $12 to $20 per kilowatt per month across all demand-related line items.
• Ratchet effects: Summer-on-peak capacity obligations assigned via PJM Peak Load Share often carry forward into subsequent billing periods. A single hot summer afternoon peak event can establish capacity obligations that persist for 11 months beyond the actual peak event, creating difficult-to-model indirect costs for commercial EV charging operators.

The practical consequence is that demand charge management, not energy procurement, is often the dominant operating cost optimization lever for commercial EV charging operators. The chart below illustrates how a single short-duration peak event can establish the entire month's demand charge bill.

Commercial EV charging equipment and installation costs

Commercial EV charging turnkey costs scale substantially with charging power level. The chart below reflects representative turnkey ranges by power tier based on current market pricing from major turnkey providers (ABM, Qmerit, and comparable integrators). All ranges include hardware, electrical infrastructure, civil site preparation, and soft costs; actual project costs vary with site-specific conditions.

Within each power tier, turnkey costs break down across four main categories whose relative shares shift as power level increases. The chart below shows representative cost allocation for a standard public DCFC project (90-180 kW tier) — the sweet spot for most new commercial public charging investments.

Use case 1: Workplace charging — employee amenity economics

Workplace EV charging is the most common commercial EV charging investment, driven primarily by employee retention and amenity considerations rather than direct revenue generation. Facility managers and human resources teams typically champion workplace charging as part of broader employee benefit packages, while CFOs and finance teams evaluate the cost per EV-driving employee served against alternative benefit spending options.

The economics of workplace charging rarely produce positive IRR as a standalone business case because there is typically no direct revenue stream. Employers may charge employees nominal fees for charging access (typically $0.10 to $0.15 per kilowatt-hour, approximately covering electricity cost at commercial rates), but these fees cover operating cost rather than generating profit. The appropriate decision framework is cost per EV-driving employee served, which can then be benchmarked against alternative employee amenity spending.

Three considerations shape workplace charging investment sizing:

• Port-to-employee ratio: Industry best practice is one Level 2 charging port per five to ten EV-driving employees, allowing for shift rotation during the workday. For a 200-employee office with 20% EV ownership (40 EV-driving employees), the typical port count is 4-8 Level 2 ports.
• Power sharing vs dedicated ports: Some workplace charging implementations use power-sharing smart chargers that distribute available current across multiple vehicles plugged in simultaneously, reducing peak power draw and demand charge exposure. For high-density workplace charging, power-sharing architectures can substantially reduce long-term operating costs.
• Networking and access control: Networked chargers with employee access controls (RFID cards, mobile app, employee ID integration) typically add 15-25% to hardware costs but enable usage reporting, employee-specific billing, and access management. Unnetworked basic chargers reduce hardware cost but lose these features.

The scenarios below compare three representative workplace charging deployment scales, each showing total project cost, PSE&G incentive coverage, net CapEx, and cost per EV-driving employee served over a 10-year amortization horizon.

The workplace charging scenarios illustrate a central characteristic of this use case: economy of scale fails for workplace charging because PSE&G's site caps (max 4 ports per site) and federal 30C limits do not scale with port count beyond modest sizes. A small office with 2 ports sees nearly full project cost coverage through incentives (cost per EV employee of approximately $0 to modest annual amortized cost); a large campus with 40 ports exhausts incentive availability quickly and bears substantial net CapEx that drives annualized cost per EV employee into the hundreds of dollars.

Three practical workplace charging investment heuristics emerge from the scenario analysis:

• Install exactly enough ports for current demand, not aspirational demand. PSE&G's $7,500 per port and $30,000 site cap favor sites installing 4 ports or fewer. Sites that could use 8-10 ports should consider installing 4 ports now (with full incentive coverage) and expanding later as EV ownership among employees grows. Multi-phase deployment captures incentive value more effectively than single-phase over-sizing.
• Charge employees modest usage fees to cover operating cost. A $0.10 per kilowatt-hour usage fee charged to employees approximately covers electricity cost at commercial rates. This eliminates ongoing operating cost burden and simplifies the business case to pure CapEx recovery over the amortization period.
• Benchmark cost per EV employee against alternative employee amenity spending. If the resulting cost per EV employee is less than annual gym membership subsidies, lunch stipends, or other common amenity spending, the investment is attractive on relative-benefit terms even without positive IRR as a standalone business case.

Use case 2: Fleet depot charging — operational cost reduction ROI

Fleet depot charging produces substantially stronger IRR than workplace or public DCFC in most realistic scenarios because the recurring annual cash flow comes from genuine operational cost reduction (replacing gasoline or diesel fuel cost) rather than nebulous amenity value or uncertain user-pays revenue. For fleets of 5 to 50 vehicles with predictable daily route patterns and overnight return-to-depot operations, the investment case is typically strong even before PSE&G incentive stacking.

The fleet depot business case rests on three cash flow drivers that compound favorably:

• Fuel cost replacement: Each electric vehicle in the fleet replaces the gasoline or diesel fuel cost of its predecessor. At current New Jersey AAA gasoline prices of $4.20 per gallon (regular, mid-grade $4.82, premium $5.12) and vehicle fuel efficiency of 20-25 miles per gallon, each mile driven on gasoline costs approximately $0.17-$0.21. For diesel fleet applications, current NJ diesel pricing at $6.39 per gallon with typical fleet diesel efficiency of 7-12 miles per gallon drives per-mile fuel cost to $0.53-$0.91 — substantially higher cost basis than gasoline. The equivalent EV charging cost at off-peak commercial rates (approximately $0.10 per kilowatt-hour) and typical EV efficiency (0.30-0.35 kilowatt-hours per mile for light/medium duty, higher for electric trucks) is approximately $0.03-$0.15 per mile depending on vehicle class — typically a 70-85% operational cost reduction per mile driven.
• Favorable charging timing: Fleet vehicles typically return to the depot during late afternoon or evening and remain there overnight. Depot L2 charging during overnight off-peak hours captures the lowest commercial electricity rates while avoiding demand charge exposure (overnight charging flattens peak demand across the day rather than concentrating it).
• High per-port utilization: Each depot charging port serves a dedicated vehicle every night, producing utilization rates (hours of actual charging / hours available) of 25-40% — substantially higher than typical public DCFC utilization and generating correspondingly higher annual energy throughput.

The chart below shows fleet depot payback period across a range of fleet size and daily route distance combinations, using current New Jersey AAA gasoline price data ($4.20 per gallon regular). For essentially every realistic fleet depot scenario modeled, payback occurs within 12 months and often within six months. Diesel fleets — particularly common in medium and heavy-duty trucking applications — see substantially faster payback than the gasoline baseline shown here, as current NJ diesel pricing at approximately $6.39 per gallon drives even larger per-mile operational savings against electric alternatives.

The fleet depot payback grid illustrates several important dynamics. First, essentially every realistic fleet depot scenario pays back within 12 months, and many within three to six months — a striking result driven by the combination of high per-mile fuel cost savings and strong incentive coverage of upfront CapEx. Second, higher daily route distances increase annual fuel savings proportionally while CapEx remains fixed, producing substantially faster payback at high-mileage scenarios. Third, larger fleets exhaust PSE&G incentive stacking faster (the $30,000 site cap caps incentive value regardless of fleet size), but the incremental annual savings from additional vehicles far outpaces the incremental CapEx, maintaining fast payback at scale.

The practical fleet depot investment heuristics:

• If your fleet drives 60+ miles per day per vehicle on average and operates 20+ vehicles, the payback case is essentially guaranteed to be fast. At current NJ gasoline prices and off-peak commercial electricity rates, annual fuel cost savings per vehicle run $2,400 to $5,500 for gasoline fleets depending on daily mileage, and substantially more for diesel fleets, which rapidly amortizes the net CapEx of approximately $2,500 to $4,500 per port after incentive stacking.
• The strongest case is for fleets currently running gasoline vehicles with high daily mileage patterns (last-mile delivery, service, utility). Fleets currently running diesel vehicles see even stronger per-mile savings due to higher diesel fuel costs and lower EV electricity cost comparison.
• Overnight charging timing is operationally compatible with most fleet patterns. Fleet vehicles return to depot in late afternoon or evening and sit overnight. Depot L2 charging during 11 PM - 6 AM super off-peak hours captures lowest rates and avoids demand charge exposure. For fleets with vehicles out of depot at random times (24/7 operations), the economics shift but typically remain favorable.
• Fleet electrification planning should sequence vehicle purchases to maximize PSE&G incentive capture. The $30,000 L2 site cap applies per site; multi-depot fleets can capture incentive value at each depot separately. Phased deployment that triggers incentive application at each new deployment opportunity may be more valuable than consolidating purchases.

Use case 3: Public DC fast charging — utilization-sensitive IRR

Public DCFC is the most capital-intensive and highest-risk commercial EV charging investment. Capital expenditure runs $120,000 to $350,000 per site depending on power tier and port count. Revenue depends entirely on actual utilization — the share of installed capacity hours actually delivering charging sessions to paying customers. Operating expenses are dominated by demand charges, which can exceed energy charges by substantial margins at low utilization. The IRR calculation is therefore extremely sensitive to utilization rate assumptions, and realistic utilization data for proposed sites is often difficult to establish before deployment.

Three structural challenges shape public DCFC investment:

• Early utilization is almost always below long-run utilization. New public DCFC sites typically see 2-5% utilization in the first six months as EV drivers discover the location and establish usage patterns. Mature sites with established user bases typically see 10-20% utilization; the best-located highway corridor sites can approach 25-30%. Investment models that assume mature utilization from day one systematically understate payback period.
• Demand charges punish low utilization severely. Monthly demand charges apply based on peak kilowatt demand during each month, regardless of total energy delivered. A 300 kilowatt installation operating at 5% utilization (36 hours per month of actual delivery across both ports) still incurs demand charges based on 300 kilowatt peak demand — approximately $4,500 per month at $15 per kilowatt per month commercial demand rates. This means low-utilization sites can lose money on operating basis before even considering CapEx recovery.
• PSE&G demand charge rebate dramatically shifts low-utilization economics. PSE&G's DCFC demand charge rebate structure covers a declining share of demand charges over the first several years of operation. For low-utilization sites in startup phase, the demand charge rebate is often the difference between operating losses and operating viability.

The chart below shows public DCFC IRR as a function of utilization rate, with and without PSE&G demand charge rebate assistance. The 12% CFO threshold is highlighted.

The DCFC utilization sensitivity chart illustrates the central investment challenge of public DC fast charging. Without PSE&G demand charge rebate assistance, the site requires approximately 25%-plus utilization to clear the 12% CFO acceptance threshold — a utilization rate achieved only by well-located mature sites. With PSE&G demand charge rebate during the first five years of operation, the threshold crosses at approximately 15% utilization, a substantially more achievable target for new sites with reasonable traffic patterns.

Three strategic observations about public DCFC investment:

• Site selection drives everything. The difference between a sub-10% utilization site and a 25%-plus utilization site is primarily location: proximity to EV traffic patterns, visibility from the roadway, co-location with amenities that encourage dwell time, and competitive density of other DCFC sites in the area. Investment analysis should rest on realistic traffic and utilization modeling before committing capital.
• Oversize incrementally, not aspirationally. A 180 kW dual-port site with modest utilization is more economically viable than a 350 kW quad-port site with the same absolute throughput. Demand charges scale with installed peak capacity, not actual delivered energy; oversized sites carry demand charge burden without the corresponding revenue to support it. For most non-highway-corridor applications, 90-180 kW tier equipment is appropriate; the 240-350+ kW tier should be reserved for genuine highway corridor locations with high transient traffic.
• Secure PSE&G demand charge rebate before investment commitment. The rebate structure is subject to annual program authorization and may be modified for new sites in future program cycles. Prospective DCFC investors should engage PSE&G early in site planning to confirm current rebate parameters and secure participation before committing capital. Site viability modeled on current rebate structure may need re-evaluation if rebate terms change for new sites.

ROI framework: model your specific site

The scenario analyses above illustrate general patterns across workplace, fleet, and public DCFC use cases. For evaluating specific proposed sites, the interactive calculators below allow prospective investors to vary the key input assumptions and see immediate output of the economic implications. All three calculators use the same methodology as the scenario charts: PSE&G incentive stacking per program tier, federal Section 30C stacking, straight-line amortization for workplace, simple payback for fleet, and 10-year cash flow for public DCFC with PSE&G declining demand charge rebate.

Workplace & multifamily L2 charging calculator

Adjust the sliders to model workplace or multifamily deployment. The key output is cost per EV employee served per year — benchmark this against alternative employee amenity spending to evaluate relative appeal.

Fleet depot payback calculator

Adjust the sliders to model fleet depot deployment. The key output is simple payback period in months — fleet depot investments generally have strong payback characteristics due to fuel cost savings dominating investment economics.

Public DCFC 10-year pro forma example

Public DCFC economics are too dependent on site-specific utilization patterns to lend themselves to simple slider modeling. Instead, the example 10-year cash flow table below illustrates the typical structure of a public DCFC pro forma, with PSE&G's declining demand charge rebate highlighted. The example assumes a standard 180 kW dual-port site at 12% utilization, representative of a well-located but not exceptional traffic site. For prospective investors, substitute site-specific utilization assumptions and verify current PSE&G rebate structure before committing capital.

Four observations about the example DCFC pro forma. First, payback is achieved in Year 3 (highlighted in green), as cumulative cash flow turns positive. Second, PSE&G demand charge rebate (highlighted rows) front-loads cash flow in the critical early years when CapEx recovery is most time-sensitive — without the rebate, payback would extend into Year 4 or later and 10-year IRR would be substantially lower. Third, demand charges ($54,000 per year, unchanging) exceed energy costs ($49,000 to $61,000) throughout the 10-year horizon, confirming that demand charge management is the dominant operating cost optimization lever. Fourth, 10-year cumulative return of approximately $582,000 against initial CapEx of $250,000 represents strong investment economics once site-specific utilization patterns support the modeled 12% utilization rate.

How PSE&G compares to peer utility commercial EV programs

PSE&G's commercial EV program is substantially generous compared to peer utility programs across US territories, driven primarily by generous per-port and per-site caps across all three program tiers. The chart below compares maximum per-site commercial EV program value across representative peer utilities, with PSE&G L2 and DCFC program maximums highlighted.

Three observations about PSE&G's peer positioning. First, PSE&G's commercial program value per site exceeds most peer utility programs across both L2 commercial ($40,000 site maximum) and public DCFC ($150,000 site maximum) tiers. The structural generosity reflects New Jersey's aggressive EV adoption policy environment and PSE&G's own commitment to supporting commercial EV charging buildout. Second, Con Edison's PowerReady program approaches or exceeds PSE&G at the highest end of PowerReady project types but applies to a more limited universe of specific site categories. Third, PECO's PA EVsmart commercial program (covered in companion deep-dive) provides substantially higher value in Environmental Justice areas (up to $80,000 per site) but lower baseline value for standard commercial sites ($20,000). Prospective PSE&G commercial applicants benefit from relatively uniform generosity across all site types.

Further economic considerations

Several additional factors shape commercial EV charging investment viability in PSE&G territory.

Federal Section 30C commercial tax credit stacks with PSE&G incentives. The federal Alternative Fuel Vehicle Refueling Property Credit covers up to 30% of commercial charging equipment and installation costs, capped at $100,000 per charging unit. For commercial applications, this credit can be substantial — a $200,000 DCFC project in an eligible census tract can see federal 30C of $60,000 stacking on top of PSE&G's $150,000 maximum, reducing net project CapEx to approximately $0 for optimally-sized projects. Section 30C applies to commercial charging equipment in low-income and non-urban census tracts; for PSE&G territory, geographic qualification varies substantially.

Networking service fees are a recurring operating expense that can be substantial. Public DCFC sites typically carry ongoing networking service fees of $1,500 to $5,000 per port per year for payment processing, user authentication, usage reporting, and remote management. Workplace L2 charging networking fees are generally lower ($300 to $800 per port per year) but still substantial for larger deployments. These recurring costs can shift project economics meaningfully and should be modeled explicitly in pro formas.

NJ Charge Up fleet rebate adds further value for electrifying fleet vehicles. The vehicle rebate covered in the companion PSE&G residential analysis ($4,000 per qualifying BEV priced at $55,000 or less) also applies to commercial fleet vehicle purchases. For a fleet of 20 vehicles qualifying for NJ Charge Up, the state rebate value is $80,000 — separate from and additive to PSE&G make-ready for the depot charging infrastructure.

Multi-site operators can capture incentive stacking at each site. PSE&G's per-site caps apply individually to each physical site rather than aggregating across an operator's portfolio. A fleet operator with three depots can capture up to $120,000 in L2 commercial incentives ($40,000 per site × 3) rather than being limited to a single-site cap. Public DCFC operators can similarly stack incentive value across multiple corridor sites.

Site selection should consider PJM Peak Load Share dynamics. New Jersey commercial accounts under LPL and higher-tier schedules are assigned PJM Peak Load Share obligations based on consumption patterns during PJM-defined peak hours. For high-power commercial EV charging operators, demand management strategies that reduce exposure to PJM peak periods can produce substantial savings in capacity obligations over time. Sophisticated operators engage energy consultants with PJM demand management expertise.

Program parameters are subject to rate case and policy changes. PSE&G's commercial EV charging program parameters are established through New Jersey Board of Public Utilities proceedings and may be adjusted in future rate case cycles. Historical program continuity through 2024-2026 has been reasonably stable, but prospective investors should verify current program availability, caps, and participation terms at the point of project planning.

Method. PSE&G commercial EV charging program parameters (Level 2 commercial and multifamily at $7,500 per port with $30,000 site cap and $10,000 USMR; Public DCFC at $25,000 per port with $100,000 site cap and $50,000 USMR plus demand charge rebate; ENERGY STAR hardware requirements for L2; data-sharing compliance requirements; commercial rate schedule compliance; licensed contractor requirements) reflect current PSE&G program documentation as communicated by the household source. Commercial rate schedule structure (GLP, LPL-Secondary, CIEP), demand charge thresholds (10-50 kW activation range depending on sub-schedule), demand charge mechanics (highest 30-minute peak kW during billing cycle), time-of-use windows (GLP Night Use 8 PM - 8 AM M-F plus all weekends; LPL/HTS on-peak 8 AM - 10 PM M-F) reflect current PSE&G tariff structure. All-in commercial rate range of $0.13 to $0.19 per kilowatt-hour is approximate for calculation purposes; actual rates vary by schedule, time period, and current PSE&G filings. Demand charges are modeled at $15 per kilowatt per month in scenario analyses as a representative all-in rate across generation capacity, transmission capacity, and local demand components; actual demand charge composition and rate varies substantially by schedule and billing period. Turnkey cost ranges by power tier ($50K-$100K for 30-60 kW, $120K-$220K for 90-180 kW, $200K-$350K+ for 240-350+ kW) and cost allocation shares (hardware 35-45%, electrical infrastructure 30-40%, civil 15-20%, soft costs 10%) reflect representative US market pricing from major turnkey providers as of 2026; actual project costs vary with site conditions. Workplace charging scenarios assume $4,500 per port turnkey, employee usage fee of $0.10/kWh approximately covering electricity cost, and 10-year straight-line amortization. Fleet depot scenarios assume $4.20 per gallon regular gasoline (current NJ AAA pricing; diesel baseline would use $6.39), 22 miles per gallon fleet vehicle equivalent efficiency, 0.30 kilowatt-hours per mile EV efficiency, $0.10 per kilowatt-hour off-peak commercial electricity, and 250 working days per year. Public DCFC scenarios assume $0.45 per kilowatt-hour retail charging rate, $0.13 per kilowatt-hour energy cost, $15 per kilowatt per month demand charge rate, 300 kW peak demand for a 180 kW dual-port installation, networking service fees of $4,000 per year and maintenance of $5,000 per year. PSE&G demand charge rebate is modeled as 50% average over first 5 years of operation; actual rebate structure may differ. Peer utility commercial program comparison reflects published maximum per-site values as of Q3 2026; peer programs change frequently. 12% CFO IRR acceptance threshold reflects a common corporate finance benchmark; actual acceptance thresholds vary by organization and project type. All numbers are estimates for guidance; actual commercial EV charging investment outcomes depend on specific site characteristics, utilization rates, operating conditions, and current program and rate structures at the time of commitment.