In the Era of Rising Interest Rates: Policies to Enhance Power System Flexibility Can Reduce Energy Costs

As new electricity demand from hyperscale data centers and other large loads grows, the burden of electricity bills on customers is increasing. Electric power industry stakeholders told Utility Dive that if utilities can leverage emerging flexible resources to manage demand peaks, they can effectively limit electricity price increases.

According to data from the U.S. Energy Information Administration (EIA) for September 2025, total U.S. electric power industry generation will grow by 2.3% in 2025 due to rising electricity demand from data centers and industrial customers. EIA data browser shows that from July 2024 to July 2025, the average U.S. residential electricity price increased by more than 5%.

Stakeholders say that expanding the power system to meet new large load demand while limiting electricity price impacts and paying for investments may seem contradictory, but it is not unachievable.

Severin Borenstein, a professor at the Haas School of Business at the University of California, Berkeley, noted that if large loads cause utilities to make expensive grid infrastructure upgrades to meet higher demand peaks, this will push up electricity prices. But he added that if policies incentivize "shaving" peak demand, large loads can avoid the costs that drive up electricity prices.

Analysts believe that state policymakers and stakeholders can design and implement these incentives and other policies to enhance the flexibility, affordability, and reliability of the power system.

"Rising electricity prices are drawing the attention of politicians because costs, especially energy costs, are becoming a new focus for consumers," said Ted Thomas, former chairman of the Arkansas Public Service Commission and founder of Energize Strategies. "This makes resisting electricity price increases an important issue that politicians are willing to invest political capital in."

Although the scale of load growth remains uncertain, investments to meet that demand already threaten affordability. However, data shows that appropriate regulation can limit its impact and potentially stabilize customer costs.

Electricity price increase trends

According to a September report from the Edison Electric Institute (EEI), investor-owned utilities, which serve 57% of U.S. electricity demand, will invest approximately $1.1 trillion in infrastructure from 2025 to 2029, up from $765 billion in the previous five years. The report shows that 91 GW of new capacity is currently under construction, with another 488 GW planned or proposed.

A September policy brief from the Union of Concerned Scientists (UCS) noted that data center electricity demand has created "a new class of costs" for system expansion and modernization, threatening "bills for all customers." The brief added that state-level regulatory practices "allow this worst-case outcome" to occur.

But stakeholders say new policies that encourage large loads such as data centers to use electricity flexibly and avoid demand peaks can improve outcomes.

Large load flexibility

Borenstein of the Haas Institute said large loads push up electricity prices because system operators and utilities must make capital expenditures (CapEx) to meet demand peaks. He added that these peaks occur only 50 hours or less per year, but the infrastructure costs to meet them are included in and drive up customer electricity prices.

Borenstein believes the most important way to prevent electricity price increases is to enable large loads and system operators to use demand flexibility to manage these rare peaks. He added that grid connection for data centers and large loads "can be conditioned on flexibly adjusting their demand during peak periods."

Borenstein said that using flexibility to reduce the demand peak of new large loads can spread the increased electricity sales of utilities across periods when infrastructure and supply are sufficient. Even if some distribution system investment is needed, "electricity prices will not rise significantly."

A report from the Nicholas Institute at Duke University shows that through "flexible demand strategies," the U.S. power system can meet more than 98 GW of new demand from data centers and other large loads. The report adds that "only a 0.5% annual curtailment" is needed during demand peak periods.

An August 31 analysis from the Electric Power Research Institute (EPRI) also argues that greater flexibility "can transform data centers from passive customers into grid assets" to improve reliability, reduce costs, and accelerate grid connection. A pilot project led by Emerald AI in Arizona in May 2025, using technology designed for NVIDIA chips, validated the potential of data center flexibility.

Mike Hogan, senior advisor at the Regulatory Assistance Project (RAP), said relying solely on generation to meet rare peak demand could drive investment in "rarely used capacity" to meet resource adequacy standards. He added that utilizing low-cost demand-side options "is more valuable than ever."

Former Commissioner Thomas said regulators can also implement large load tariffs that ensure new demand is paid for by those who cause it through contractual commitments. Thomas said policymakers want to support economic development while protecting consumers from electricity price increases. He added that some "will stake their next election on the decisions they face."

Flexibility of distributed generation

Analysts, utilities, and other stakeholders say the use of flexible distributed energy resources (DERs) aggregated in virtual power plants (VPPs) is growing significantly.

A 2024 study by Lawrence Berkeley National Laboratory found that shifting distribution system peaks may have the greatest impact on customer costs, as 44% of utility capital expenditures go to distribution systems. Wood Mackenzie's September research shows that aggregated DERs and VPPs capable of shifting distribution demand peaks are growing.

Wood Mackenzie reported: "The VPP market grew more than 33% from 2024 to 2025," with aggregators achieving "433 utilities and projects, up 35% from last year."

In Illinois, ComEd has proposed a "bring-your-own-device load reduction program" to "leverage customer energy storage resources," said Scott Vogt, vice president of strategy, energy policy, and revenue programs at the company. The program's capital expenditures would be "minimal" and would begin with a competitive solicitation of DER aggregators.

Vogt said aggregators would receive signals to reduce consumption during peak hours, with the goal of enrolling at least 10 GW of the 47 GW of DERs in ComEd's territory. DER aggregators and owners would be compensated, but for the utility and its non-DER customers, "the value lies in lowering the demand curve."

Former Commissioner Thomas emphasized that shifting large amounts of load away from peak periods can reduce new distribution system infrastructure and system maintenance costs. Regulators across the country are increasingly being asked to recognize the value of demand flexibility at all levels of the system.

Regulation to expand demand flexibility

Elizabeth Cook, vice president of the Association of Edison Illuminating Companies (AEIC), said current regulatory processes and requirements leave utilities "in a bind" and unable to adopt forward-looking "out-of-the-box thinking." She added that to meet today's load growth, utilities need to enhance analytical capabilities and "actually reshape the way they view the system."

Cook continued: "Hyperscale data centers also need to adjust their attitude toward utilities, even if they can acquire the utilities they work with."

According to the DELTa database of the North Carolina Clean Energy Technology Center and the Smart Electric Power Alliance (SEPA), over the past three years, 30 states have designed 49 newly approved or proposed large load tariffs for 44 investor-owned and public power companies and cooperatives.

Ann Collier, senior manager of emerging technologies at SEPA, said "balancing among numerous goals such as energy affordability, economic development, reliability, and clean energy is a significant effort." Provisions in new tariffs may include curtailing load during extreme demand peaks, building on-site generation or storage, or making long-term contractual commitments to cover infrastructure costs.

Josh Keeling, chief commercial officer of UtilityAPI, said expanding demand flexibility can reduce costs and increase participation, but regulatory processes create too much friction for residential customers. UtilityAPI helps utilities aggregate and use DERs. Keeling said few utilities can easily access the customer-level data needed to integrate VPPs. But initiatives such as EPRI's Open Power AI are developing methods to share data while protecting data security.

Utilities such as Eversource, Pacific Gas & Electric (PG&E), and Con Edison, along with their regulators, have streamlined data access, Keeling said. Maryland, New Jersey, Illinois, and New Hampshire are following the successful data access experiences of New York, California, and Texas.

Scott Harden, senior vice president and chief technology officer of Schneider Electric, said that for demand flexibility to be most effective, program design must include meaningful compensation and be clearly understood by participating customers. He said program assets must be dispatchable.

Harden added that new load growth will give regulators reason to address utilities' traditional bias in spending on distribution system management software technology.

Brendan Reed, vice president of Sparkfund, said regulators can formalize the use of aggregated DERs through distributed capacity procurement (DCP) to reduce demand peaks and their associated costs. He added that DCP would be considered for cost recovery in utility planning processes alongside other peak capacity resources.

Will Baker, director of market innovation at Renew Home, said another metric is data from randomized controlled trials. He added that randomized controlled trial data can approximate the value of avoided transmission and distribution costs, ancillary services, and energy.

Hannah Bascom, chief growth officer of DER aggregator Uplight, said state policymakers can mandate that utilities reduce a certain percentage of overall peak load through load flexibility programs. Bascom added that even without mandates, utilities facing load growth are beginning to view flexibility as the most prudent investment to protect affordability and reliability.

Flexibility as prudence

Multiple stakeholders said that failing to fully consider flexibility in utility planning and rate cases violates the fundamental principles of prudence and reasonableness in electricity regulation.

Mark LeBel, research and strategy lead at the Regulatory Assistance Project (RAP), said that as demand grows, publicly available standardized data in utility planning and rate cases becomes more important. He added that it would be imprudent for regulators to approve utility rate case investment proposals without adequate supporting information.

Abigail Anthony, commissioner of the Rhode Island Public Utilities Commission, said that for a proposed rate case investment to be reasonable and prudent, utilities must present a business case explaining its need, value, and responsibility to customers. Anthony said utilities may argue that regulatory requirements hinder critical modernization, but they must demonstrate that modernization investments provide net value to ratepayers.

Anthony and others said proving the value of new investments is particularly important when significant uncertainty remains about the scale of load growth.

But regardless of future load growth, "in this world of computing power, utilities need hyperscale data centers to create AI analytics, and hyperscale data centers need utilities to provide electricity," said Cook of the Association of Edison Illuminating Companies. "Regulation that fosters collaboration could become a win-win, enhancing overall reliability and affordability."