Energy cost is no longer a predictable line item in commercial real estate operating budgets. Through 2019, most REIT portfolio managers treated electricity as roughly $2.00–$2.50 per square foot annually for Class A office — a stable, plannable number. The 2021–2023 utility rate cycle, driven by fuel cost pass-throughs and distribution investment recovery surcharges, pushed that figure meaningfully higher across most major markets. Combined with load growth from EV charging infrastructure and data center-driven building densification, the energy cost picture for office, industrial, and mixed-use portfolios entering 2025 looks structurally different from the pre-2020 baseline that most NOI models were calibrated against.
This article presents benchmark ranges for commercial building energy costs in 2025, examines the demand charge component specifically (which is where the most actionable management opportunity lies), and offers a diagnostic framework for portfolio operators to identify where their properties stand relative to peer-class benchmarks.
Benchmark Ranges by Asset Class
The figures below represent blended electricity cost per square foot per year, including both energy (kWh) and demand (kW) components, across major U.S. commercial markets. These ranges reflect 2024 billing data and 2025 utility rate schedule filings across PJM, SERC, and WECC territories. They are not utility-published statistics — they reflect the operating cost range that property managers in well-managed mid-to-large commercial portfolios actually see on their invoices.
Class A Office — Urban High-Rise (250,000+ sq ft)
- Low end: $2.40–$2.80/sq ft/year (energy efficient, modern building systems, active demand management)
- Midrange: $3.20–$3.80/sq ft/year (typical 2000s-era construction, standard BMS, no demand optimization)
- High end: $4.20–$5.50/sq ft/year (older pre-2000 buildings, electric resistance heat, poor load factor, high demand charge exposure)
Class B Office — Suburban Mid-Rise (50,000–200,000 sq ft)
- Low end: $2.10–$2.60/sq ft/year
- Midrange: $3.00–$3.60/sq ft/year
- High end: $4.00–$5.00/sq ft/year
Industrial / Logistics (Light Manufacturing, Warehouse with Office)
- Low end: $0.80–$1.20/sq ft/year (low-intensity warehouse, minimal climate control)
- Midrange: $1.60–$2.20/sq ft/year (mixed use, some process load)
- High end: $2.80–$4.00/sq ft/year (refrigerated logistics, heavy process equipment, EV fleet charging)
Retail (Anchored Shopping Center, Strip Mall)
- Low end: $2.20–$2.80/sq ft/year (common area only, tenant-metered for individual suites)
- Midrange: $3.40–$4.20/sq ft/year (full-service with anchor tenants on landlord meter)
- High end: $5.00–$7.00/sq ft/year (grocery-anchored with refrigeration on master meter)
The retail high end deserves context: grocery and food service refrigeration is one of the highest demand charge exposure categories in commercial real estate because refrigeration compressors run continuously and create persistent, high load factors with poor diversity. Unlike office HVAC, which can be pre-conditioned and setpoint-shifted during peak demand windows, refrigeration has hard lower bounds on acceptable setpoint deviation.
The Demand Charge Component: Where the Gap Is
In urban Mid-Atlantic and Southeast markets (PJM-East, Dominion Virginia, Duke Energy Carolinas), demand charges typically represent 30–48% of total electricity cost for commercial accounts on general service large demand rate schedules. In high-constraint urban distribution zones — particularly in dense urban cores where transformer and substation capacity is limited — demand charges can reach 55–60% of the total bill for buildings with poor load factors.
The benchmark gap between a high-performing building and a low-performing building in the same asset class is almost entirely in the demand charge component, not the energy charge. Two Class A office buildings with identical energy consumption profiles (kWh) can differ by $0.80–$1.20/sq ft/year in total electricity cost if one has active demand management and one does not, because their 15-minute peak demand intervals — and therefore their monthly demand charges — are dramatically different.
This is the highest-leverage insight for portfolio operators: you can reduce energy cost by 10–15% through LED lighting retrofits and efficient HVAC equipment, which requires capital expenditure and a multi-year payback. You can reduce demand cost by 18–35% through load management and demand-aware controls, which requires instrumentation and software but generally has a faster payback because demand charges are the more expensive component per unit of reduction.
Geographic Variation in Demand Charge Rates
Demand charge rates vary substantially by utility territory, and this is one of the most underappreciated variables in portfolio-level energy benchmarking. A REIT with properties spread across ERCOT (Texas), PJM-East (Mid-Atlantic), and Southern Company territory (Georgia/Alabama) is operating under demand charge structures that differ by a factor of 2–3×, which directly affects the ROI calculation on demand management investments.
| Utility Territory | Typical Peak Demand Charge | Time-of-Use Demand? |
|---|---|---|
| PPL Electric (PJM-East PA) | $16–$21/kW | Yes (summer on-peak premium) |
| Dominion Energy Virginia | $14–$19/kW | Yes |
| Duke Energy Carolinas | $12–$18/kW | Yes |
| Oncor (ERCOT Dallas-Fort Worth) | $8–$14/kW | Some rate classes |
| Con Edison (NYC) | $22–$35/kW | Yes (seasonal, time-of-use) |
| Georgia Power | $10–$16/kW | Limited |
Portfolio operators with properties in ConEd territory face the highest demand charge exposure in the continental U.S., and the financial case for demand management software is correspondingly stronger. A 500 kW peak reduction in a ConEd large-commercial account saves $11,000–$17,500 per month during peak months — an annualized value of $60,000–$90,000 from demand charge reduction alone for a single building.
EPC Contractors and the Demand Blind Spot
A persistent pattern in commercial real estate energy management is that energy efficiency capital projects — LED retrofits, HVAC equipment upgrades, window film, building envelope improvements — are well-understood and routinely procured through energy performance contracting (EPC) arrangements with guaranteed savings. Demand charge optimization, which requires software, instrumentation, and ongoing operational management rather than capital hardware replacement, fits poorly into EPC contract structures that guarantee a fixed kWh reduction.
We're not saying that EPC projects are the wrong approach to energy management — they have genuine value and are often the right first step for older buildings with significant equipment efficiency gaps. The issue is that EPC projects systematically undervalue demand charge opportunity because their savings measurement and verification (M&V) frameworks are built around kWh, not kW. An EPC that guarantees 15% energy savings on a building where 40% of the bill is demand charges may only address 9% of the total electricity cost, leaving the most actionable cost reduction opportunity untouched.
Key Diagnostic Metrics for Portfolio Benchmarking
When evaluating where a given building stands relative to peer benchmarks, four metrics provide the most actionable signal:
1. Load Factor
Calculated as: (total monthly kWh) / (peak monthly kW × hours in month). Industry range: 0.40–0.75 for commercial office. Load factors below 0.45 indicate significant spike exposure relative to average consumption. Load factors above 0.70 suggest relatively flat demand with less demand charge optimization headroom.
2. Demand Charge Fraction
Calculated as: demand charges / total electricity cost. Above 45% in a standard utility territory suggests either a spiked load profile or a rate schedule mismatch. This metric varies by utility territory, so benchmark only within territory peer groups.
3. Peak Demand Intensity
Calculated as: peak monthly demand (kW) / building area (1,000 sq ft). Typical range for Class A office: 3.5–7.5 kW per 1,000 sq ft. Buildings above 7.5 kW/1,000 sq ft have either high plug load density (data rooms, trading floors) or uncontrolled coincident peak events. Buildings below 3.5 kW/1,000 sq ft may be underlighting or operating with partial occupancy — the benchmark comparison should weight occupancy-adjusted figures.
4. Summer-to-Annual Peak Ratio
Calculated as: highest summer month demand / 12-month average monthly peak. High ratios (above 1.35) indicate that summer cooling drives disproportionate demand charge exposure — a profile that benefits most from summer peak shaving strategies including chilled water storage, HVAC pre-cooling, and demand-aware BESS dispatch during summer afternoons.
The Portfolio-Level Business Case
The strongest business case for demand management investment in a REIT context comes from portfolio-level analysis rather than single-building ROI. A 30-property office portfolio with average peak demand of 600 kW per building, operating under a blended $16/kW demand charge rate, carries approximately $3.5 million in annual demand charge expense. A 25% demand reduction across the portfolio — achievable with real-time monitoring, automated demand sequencing, and coordinated BESS dispatch — translates to $875,000 in annual savings. At 20% asset manager margins, that directly supports an $8.75 million increase in portfolio NAV at a 10% cap rate.
The data infrastructure required to achieve portfolio-level demand management — interval telemetry from each building's main meter, cloud aggregation, portfolio-level demand forecasting — has a fully loaded cost of $2,000–$6,000 per building per year depending on the platform and integration complexity. For a 30-property portfolio, that's $60,000–$180,000 annually, against $875,000 in potential demand charge savings. The ratio is 5–15x, which is the kind of operating leverage that justifies moving it from an IT budget line item to a capital allocation priority.
The portfolios that have moved first on this — largely the institutionally managed Class A office REITs with active sustainability mandates and board-level energy KPIs — have already captured meaningful operating cost advantages over peer portfolios that are still treating demand charges as a fixed utility expense. That gap will widen as utility rates continue on their upward trajectory.