Published October 9, 2026
By NZero
Electricity is becoming a larger and less predictable line item for commercial and industrial organizations. In its October 2026 Short-Term Energy Outlook, the U.S. Energy Information Administration (EIA) forecast that wholesale electricity prices will average $52 per megawatthour in 2026, 11% higher than in 2025. The national average hides sharp regional differences: wholesale prices in the PJM region, which serves much of the Mid-Atlantic and Midwest, are expected to rise 41%, while prices at the Northwest Mid-Columbia hub are expected to fall 23%. At the same time, record-breaking summer temperatures pushed U.S. electricity consumption up 4% in the third quarter of 2026 compared with the same period a year earlier. For facility managers and energy teams, these figures point to a broader lesson that will outlast any single forecast. Controlling electricity costs is no longer only about how much power a building uses. It is increasingly about when and how that power is used.
EIA attributes much of the 2026 increase to weather. Winter Storm Fern and an unusually hot summer, particularly in July, pushed prices up across most of the country. Weather drives costs in two ways: it raises demand for heating and cooling, and it strains supply when the grid is already stretched. In the third quarter of 2026, commercial-sector electricity consumption rose 5% year over year, and residential consumption rose 6%, largely because of cooling needs.
Demand growth is a second, more structural factor. EIA expects commercial-sector electricity demand, which includes data centers, to keep rising through 2027, growing 2.8% year over year. Industrial demand is forecast to grow 2.7%. After roughly two decades of flat electricity use, this steady growth means more competition for grid capacity during the hours when it is scarcest.
Third, wholesale power is only part of what customers pay. Retail bills also cover transmission and distribution upgrades and, in some regions, capacity market costs. These components can rise even when wholesale prices are stable.
Finally, exposure depends heavily on location. EIA’s own outlook shows how quickly regional conditions can shift:
These swings show why organizations with facilities in several regions cannot rely on a single national price assumption when budgeting.
Most commercial electricity bills have two main parts. Energy charges are based on the total volume of electricity consumed, measured in kilowatthours (kWh). Demand charges are based on the highest rate of consumption during the billing period, measured in kilowatts (kW). According to the National Renewable Energy Laboratory (NREL), demand charges are typically calculated from the highest average usage within a short interval, usually 15 minutes, and they often make up 30% to 70% of a commercial electric bill.
This structure means a single short spike can shape a full month of costs. Consider a simple hypothetical example. Two buildings each use 100,000 kWh in a month. One holds its peak at 250 kW, while the other briefly reaches 400 kW when several large systems start at once. Under a $20/kW demand charge, the second building pays $3,000 more that month, despite using exactly the same amount of energy.
Demand charge rates also vary widely by location. NREL’s national survey of more than 10,000 utility tariffs found that nearly 5 million commercial customers, over a quarter of the U.S. total, can subscribe to tariffs with demand charges above $15/kW. Within New York alone, a customer on Long Island may pay more than $50/kW, while the state’s average maximum demand charge is below $10/kW.
Weather extremes make the problem harder. Heat waves and cold snaps push building loads up at the same moments when grid conditions are tightest, so peaks, high prices, and high demand charges tend to arrive together. As EIA’s 2026 data shows, those events are now a major driver of annual electricity costs.
The good news is that peak demand is often more controllable than total consumption. Many peaks are caused by operating habits and equipment schedules rather than by essential activity. The following approaches are widely used by commercial and industrial facilities:
Data and forecasting tie these strategies together. AI-based tools can combine historical consumption, weather forecasts, and operating schedules to predict when a facility is likely to set a new peak, giving operators time to act before the spike occurs. For organizations with many sites, the same analysis can show where peak management will deliver the largest savings first.
EIA’s October 2026 outlook expects wholesale prices to ease slightly in 2027, but the broader pattern is clear. Extreme weather, rising commercial and industrial demand, and growing grid investment are making electricity costs more volatile and more dependent on when power is used. Regional conditions can also change quickly, as the swings between PJM, the Northwest, and California show.
For facility owners and energy managers, this means that cost control cannot rely on price forecasts alone. Organizations that understand their load profiles, know what drives their peaks, and actively manage demand will be better protected whether prices rise or fall in a given year. Demand charges reward exactly this kind of operational discipline.
The most resilient approach combines accurate utility data, smarter equipment scheduling, and forecasting tools that anticipate peaks before they happen. Treated as an ongoing practice rather than a one-time reaction to a price spike, peak demand management can deliver lasting savings and greater budget certainty.
