Commercial electricity rates across the United States have increased approximately 40 percent since 2020, reaching a national average of nearly 18 cents per kilowatt-hour. This is not a temporary spike. The structural forces driving these increases, including aging grid infrastructure, the energy transition to renewables, rising fuel costs, and extreme weather events, are embedded in the utility cost base and will continue to push rates higher for the foreseeable future.
For commercial real estate operators, this means that electricity has shifted from a relatively stable and predictable operating expense to one that requires active management, strategic planning, and regular forecasting updates. A portfolio that budgeted $10 million for electricity in 2020 is now spending approximately $14 million for the same consumption, and that number will likely climb to $17 million or more by 2028 if current trends continue.
This article examines the key drivers behind commercial electricity rate increases nationally, identifies the regions experiencing the steepest escalation, and provides a framework for budgeting and managing electricity costs in an environment of sustained rate growth.
What Is Driving Rate Increases Nationally
The increase in commercial electricity rates is not driven by a single factor but by the convergence of multiple cost pressures hitting the utility industry simultaneously. Understanding these drivers is essential for forecasting where rates are headed and which cost components are controllable versus fixed.
Grid Infrastructure Investment
The U.S. electric grid was largely built between the 1950s and 1970s, and much of it is reaching the end of its design life. Utilities across the country are investing hundreds of billions of dollars in transmission and distribution upgrades, substation replacements, smart grid technology, and grid hardening against extreme weather. The Edison Electric Institute estimates that U.S. utilities will invest over $160 billion annually in grid infrastructure through 2030, up from approximately $100 billion in 2020. These capital investments are recovered through rates over their useful life, creating a sustained upward pressure on per-kWh charges.
Renewable Energy Transition Costs
The transition from fossil fuel generation to renewable sources creates temporary cost overlaps. Utilities are simultaneously paying to maintain existing gas and coal plants (which are needed for reliability during the transition), investing in new wind and solar generation, building battery storage to firm up intermittent renewables, and constructing new transmission lines to connect remote renewable generation to load centers. The long-term promise is that zero-fuel-cost renewables will reduce the marginal cost of generation, but in the near term, ratepayers are bearing the capital cost of building the new system while still paying to operate the old one.
Natural Gas Price Volatility
Natural gas remains the marginal fuel for electricity generation in most U.S. markets, meaning that the price of gas directly influences the wholesale price of electricity. While natural gas prices have moderated from their 2022 peak, they remain elevated relative to the 2019 baseline and are subject to seasonal spikes during cold weather events and summer heat waves. The increasing export of U.S. natural gas as LNG has also tightened domestic supply, creating a structural floor under gas prices that did not exist a decade ago.
Extreme Weather and Resilience Costs
The frequency and severity of extreme weather events, including hurricanes, winter storms, heat waves, and wildfires, have increased utility costs in every region of the country. These costs include emergency restoration after storms, proactive grid hardening to prevent future damage, wildfire mitigation in western states, and flood protection for coastal infrastructure. Insurance costs for utility assets have also risen dramatically, particularly in wildfire-prone areas of California and hurricane-exposed regions of the Gulf Coast and Southeast.
Regional Rate Landscape: Where Rates Are Highest
While rate increases are a national phenomenon, the magnitude varies dramatically by region. Understanding your regional context is critical for benchmarking your buildings against peers and prioritizing cost management investments.
Northeast. New England and the Mid-Atlantic states have the highest average commercial electricity rates in the country, ranging from 18 to 28 cents per kWh depending on the state and utility. These rates reflect constrained natural gas pipeline capacity (which drives up the cost of gas-fired generation during peak periods), aggressive renewable energy mandates, and aging transmission infrastructure. Massachusetts, Connecticut, and New Hampshire consistently rank among the five most expensive states for commercial electricity.
California. The state's three investor-owned utilities charge commercial rates of 25 to 45 cents per kWh on a blended TOU basis, making California the single most expensive market for commercial electricity outside of Hawaii. The drivers are well documented: wildfire cost recovery, ambitious renewable energy mandates, transmission expansion, and the costs of retiring the state's remaining nuclear and gas generation.
Southeast. Historically one of the more affordable regions for electricity, the Southeast is experiencing above-average rate growth as utilities invest in grid modernization and replace aging coal plants with natural gas and renewables. Duke Energy, Southern Company, and Florida Power & Light have all filed for significant rate increases in recent years, pushing commercial rates from the 10 to 12 cent range toward 13 to 16 cents per kWh.
Midwest and PJM territory. The PJM Interconnection, which operates the grid across 13 states and the District of Columbia, saw its capacity auction clear at a 800 percent increase in 2024. This capacity cost increase is flowing into commercial bills across Ohio, Pennsylvania, New Jersey, Maryland, Virginia, and surrounding states, adding 2 to 4 cents per kWh to effective rates. Combined with distribution rate increases from local utilities, PJM-territory commercial customers are experiencing 12 to 18 percent year-over-year rate growth.
Texas and ERCOT. The Texas deregulated market offers some of the lowest headline commercial rates in the country at 8 to 12 cents per kWh, but with significantly higher volatility. The ERCOT grid remains vulnerable to price spikes during extreme weather, and commercial customers without fixed-rate procurement contracts can see their costs double or triple during summer heat events. Texas rates are trending upward as the state invests in grid weatherization and new generation capacity following the 2021 winter storm.
Impact on Commercial Real Estate Operations
Rising electricity costs affect commercial real estate operations in several interconnected ways. The most obvious impact is on net operating income: every dollar of increased utility cost that is not passed through to tenants reduces NOI dollar for dollar. For buildings on gross leases, the landlord absorbs the full rate increase. For buildings on net leases, tenants bear the direct cost, but persistently rising utility expenses can make the building less competitive in the leasing market.
The effect on property valuations is amplified by cap rate math. At a 6 percent cap rate, every $50,000 in annual utility cost savings translates to approximately $833,000 in asset value. Conversely, every $50,000 in rate-driven cost increases that cannot be offset through efficiency or procurement reduces asset value by the same amount. For a portfolio of 50 buildings, the cumulative valuation impact of unmanaged rate increases can reach tens of millions of dollars.
Insurance and financing markets are also beginning to incorporate energy cost risk into their underwriting. Properties with documented energy management programs and stable utility cost trajectories are increasingly viewed as lower-risk assets by lenders and insurers. Properties with no energy management and full exposure to rate escalation face higher financing costs and tighter coverage terms.
A Budgeting Framework for Rate Escalation
Traditional utility budgeting methods that apply a flat 2 to 3 percent annual escalation factor are no longer adequate. Commercial electricity rates are growing at 6 to 12 percent annually in most markets, and the gap between budgeted and actual utility costs is widening for firms that have not updated their forecasting approach.
A more accurate framework starts with your current effective rate per kWh (total electricity cost divided by total consumption) and applies a market-specific escalation factor based on pending rate cases and regulatory proceedings in your utility's territory. Layer in building-specific adjustments for planned capital improvements, occupancy changes, and rate schedule migrations, then add a contingency buffer of 3 to 5 percent for unanticipated mid-year surcharges.
- Baseline: Calculate your trailing 12-month effective rate per kWh for each building
- Rate escalation: Apply a regional factor (6-8% for Southeast/Midwest, 8-10% for Northeast, 8-12% for California)
- Building adjustments: Factor in efficiency projects, solar installations, or occupancy changes that will affect consumption
- Contingency: Add 3-5% for mid-year surcharges and unanticipated rate changes
- Quarterly true-up: Compare actual costs to budget quarterly and adjust the full-year forecast
Cost Mitigation Strategies
While you cannot control utility rates, you can control your response to them. The most effective portfolio operators are pursuing a layered mitigation strategy that combines procurement optimization, operational efficiency, and capital investments.
Procurement optimization. In deregulated markets, competitive supply contracts can lock in rates below the utility default for 12 to 36 months. The savings potential is typically 5 to 15 percent on the supply portion of the bill, depending on market conditions and contract timing. Aggregating procurement across multiple buildings improves negotiating leverage and can yield volume discounts.
Operational efficiency. Energy efficiency measures such as LED lighting upgrades, HVAC optimization, building automation improvements, and envelope upgrades reduce total kWh consumption. Every kWh saved avoids the rate increase entirely. A 10 percent reduction in consumption offsets approximately 10 percent in rate growth, effectively buying you one year of rate stability.
Load shifting and demand management. In markets with time-of-use rates, shifting consumption from peak to off-peak hours reduces effective rates by 10 to 20 percent. Demand charge management, including peak shaving with batteries, HVAC staggering, and demand response program enrollment, provides additional savings that grow as rates increase.
On-site generation. Solar, solar-plus-battery, and combined heat and power systems provide a hedge against rate increases by producing a portion of the building's electricity at a fixed cost. As grid rates increase, the value of on-site generation grows proportionally. The current federal Investment Tax Credit at 30 percent makes these investments more financially attractive than at any point in the past decade.
The 2027-2030 Outlook
The structural forces driving rate increases show no signs of abating. Grid infrastructure investment is accelerating, the renewable energy transition is entering its most capital-intensive phase, extreme weather costs continue to rise, and the growing electrification of transportation and buildings is adding load to a grid that is already strained in many regions.
Industry analysts project national average commercial electricity rates to reach 20 to 22 cents per kWh by 2028 and 23 to 26 cents by 2030. High-cost regions like California and the Northeast could see commercial rates approaching 45 to 55 cents per kWh by the end of the decade. For commercial real estate operators, the message is clear: electricity cost management is no longer a back-office function but a strategic priority that directly affects asset value, tenant satisfaction, and competitive positioning.
A commercial portfolio spending $10 million annually on electricity in 2020 is likely spending $14 million today and will spend $18 to $20 million by 2028 at current rate trajectories. The operators who manage this escalation proactively will maintain NOI margins. Those who do not will see their returns erode year after year.