Power used to be a line item most executives could treat as steady, predictable, even unexciting. That’s changing. Across U.S. power markets, utilities are facing a collision of volatility in wholesale prices, more extreme weather, deferred maintenance, and a demand curve that is no longer flat. The result is a quiet but consequential shift in who absorbs the risks. “The most dangerous risks are the ones you’re not aware of, which are actually being transferred to you,” says Tad W. Piper, Founder and President of TWP Strategic. For many organizations, the utility is no longer buffering price swings, peak system stress, or even outage exposure in the way leaders have come to expect. Instead, risk is being embedded into the rate design itself.
For decades, demand growth was modest enough that many businesses could reliably estimate electricity costs. Most customers could take usage and multiply it by 12 to 14 cents per kilowatt-hour and call it a reasonable forecast. Now, that model is eroding, especially for commercial and industrial customers, as utilities are increasingly aligning what customers pay with real-time market conditions and grid stress.
This has an outsized effect in a system where prices can move sharply. At the same time, the generation mix is changing, with older coal plants being retired and new renewables coming online. Most important, demand is growing again. “It was basically flat demand from 2010 to 2020,” Piper says. “And now we’re talking about large increases in demand across most or all major energy markets.”
The Demand Spike Is Not Just a Headline About AI
Executives are hearing plenty about the load growth tied to data centers and AI. Piper sees a more layered story. Part of the reason demand appeared flat for a decade is that efficiency gains masked growth. “We’ve run out of light bulb replacements,” he says, referring to the long wave of upgrades from incandescent bulbs to LEDs and other efficiency programs. Then came electrification. Electric vehicles (EVs), electric heating in certain regions, and a broader push to shift end uses from fossil fuels to electricity all added to load. More recently, data centers and the migration from traditional servers to AI servers have accelerated the trend.
Piper is careful not to turn AI into a scapegoat. What it does, he argues, is amplify the pressure on a system that was built for a different demand profile. And that pressure is showing up as a transfer of financial and operational risk from regulated utilities to the organizations they serve.
How The Risk Transfer Shows Up In Your Bill
Demand surge, paired with weather-driven stress and tighter supply margins, is driving a rapid evolution in how utilities recover costs and manage uncertainty. Risk transfer is not just a simple rate increase; it is a redesign of incentives that pushes more variability onto customers that utilities once smoothed. “More and more commercial and industrial customers are being moved to real-time power price exposure,” Piper says. In this real-time pricing structure, the customer bears the consequences when prices jump from typical levels to extreme spikes.
A second mechanism is time-of-use tariffs. Utilities shift higher rates into specific hours to encourage customers to change when they consume electricity. A third is peak demand pricing, where a larger share of the bill is tied to the single moment of highest usage. That moment often coincides with the grid’s most expensive resources running and drives increased generation capacity needs.
The policy debate is widening as well. Piper notes a “raging debate in most markets” over large load customer tariffs, often defined at 25 to 50 megawatts. The details vary by jurisdiction, but the direction is consistent: regulators and utilities are asking which customers should bear more of the system’s volatility and infrastructure costs.
The Volatility Problem Boards Are Not Budgeting For
Rising electricity prices get attention because they can be plotted as a trend line. The more disruptive reality is volatility. Leaders might plan for a bill that rises from $100 to $110 per month, only to find that, under real-time exposure, the wrong event can produce a shock month. “We all talk about the rising cost of electricity,” he says, “but it oftentimes hides the volatility risk that is happening in the middle of all that.”
A clear example emerged in Texas in 2020, when many consumers moved to real-time pricing and benefited while market prices remained low. The risk became clear when Winter Storm Uri hit in 2021, sending prices to “$9,000 a megawatt-hour,” Piper says, roughly 300 times normal levels for several days. “Your bill isn’t going to go from $100 to 110,” Piper says. “It’s going to go from $100 to $3,000 for one month.”
The experience is analogous to insurance. When a utility shields customers from market spikes, someone is paying for that protection. “If wholesale energy is $30 and your bill is the equivalent of $120,” he says, “there’s essentially $90 in risk management.” When utilities decide they no longer want to absorb that exposure for certain customers, the bill stops behaving like a stable operating expense.
How To Regain Control During The 20 To 100 Hours That Matter
Piper’s core argument is that risk transfer does not automatically mean higher costs. Unmanaged risk does. “The question is, is what steps can you take to manage that risk?” he says. The leverage point, surprisingly, is narrow. “In general, the majority of your electricity bill is generated through, in some cases as little as 20 hours of activity a year,” he says, adding that it is typically less than 100 hours. Those are the hours when the grid is strained, when the most expensive generation runs, and when infrastructure investments are justified.
If an organization can reduce usage or shift it away from those peaks, it can blunt both cost and volatility exposure. Piper calls that “flexibility management,” and he breaks it into three pathways: adding a battery, adding on-site generation (such as backup generators), and implementing load controls to reduce exposure to peak moments.
The consumer analog is familiar. Early EV charging pushed a spike into the evening when people got home and plugged in. Utilities responded with time-of-use rates. The behavioral response was to charge later at night, and then to move toward managed charging that hits a target like “fully charged at 6am” while distributing the load. The business version is more complex but the principle is the same: understand what drives costs in the tariff, then build operational and technical flexibility around those triggers.
The Utility Transfer Of Risk Is A Strategy Test
Utilities are trying to solve what Piper calls “the worst hour of the worst day of the year.” That single system peak drives capacity costs, network upgrades, and reliability investments. If the system can spread load more evenly, infrastructure is used more efficiently, and everyone’s costs stabilize.
Power can no longer be managed solely through procurement. It requires a cross-functional lens that ties tariffs and market exposure to operations, technology, and risk governance. Piper’s warning returns to awareness. Risk that is visible can be priced, hedged, or engineered around. Risk that is hidden inside a tariff change can surface as an unpleasant surprise in the month it matters most.
Follow Tad W. Piper on LinkedIn or visit his website for more insights.
