The Regulator's Dilemma: Balancing Grid Modernization and Rising Electricity Rates

At the CleanPower 2025 conference hosted by the American Clean Power Association, several utility regulators said they face a paradox that needs urgent resolution: advancing grid modernization while keeping rising electricity bills under control.

According to the latest "Grid Modernization Policy Update" report from the Clean Energy Technology Center, there were 726 grid modernization-related policy actions in the U.S. in the first quarter of this year, many of which require large-scale new investment. However, the June Consumer Price Index from the Bureau of Labor Statistics shows that residential electricity prices nationwide rose 4.5% year-over-year, nearly double the 2.4% inflation rate over the same period.

"Utility regulation has always been a complex balancing act, and the lesson we've learned is that we must ensure investment value and utility accountability," said Mark LeBel, Research and Strategy Lead at the Regulatory Assistance Project (RAP). He added that regulators must "select the most cost-effective investments from realistic alternatives."

Data from the Edison Electric Institute from September 2024 shows that of the $186.4 billion spent by U.S. investor-owned utilities in 2024, nearly 80% went to infrastructure. And future spending will continue to increase: the latest update from GridStrategies shows that the five-year load growth forecast released in April is 120 gigawatts, more than five times the 23 gigawatts forecast in 2023.

"Regulators can view modernization investments like corporate investors," said Abigail Anthony, Commissioner at the Rhode Island Public Utility Commission. Utilities should present investment information like "business owners seeking loans" to alleviate regulators' concerns about "gambling with customers' money," she added.

Many commissioners agreed that balancing the seemingly opposing goals of modernization spending and avoiding electricity price increases is at the core of utility regulation. Some regulators noted that emerging tools for business case regulation include new metrics, effective planning, and well-paced spending, which can identify necessary investments that both add value and hold utilities accountable.

Can the opposing sides be balanced?

State utility commissioners and analysts say responsible regulators need new approaches to address this difficult choice: between reasonable modernization investments and the resulting upward pressure on electricity prices.

Bryce Yonker, Executive Director of Grid Forward, a modernization advocacy organization, noted that aging systems face increasing pressure and require substantial investment, which is largely borne by utility customers. However, if "affordability becomes the primary goal, then achieving modernization will be very difficult."

Tricia Pridemore, Commissioner at the Georgia Public Service Commission, said the commission recently launched a solution to balance the costs of new large-load customers, an approach many state regulators are adopting. "The new rules require Georgia Power to sign 15-year contracts with new large-load customers, with rates covering 100% of the utility's costs," she added.

Pridemore explained that Georgia Power is responsible for procuring the generation capacity needed for new large loads, and the commission approves contracts through a "collaborative planning process." Costs not covered by contracts would go into the utility's rate cases, but those costs are likely not allowed to be recovered "because contract negotiations are the utility's responsibility, not the customer's problem."

Amid questions about Georgia Power and its regulators regarding the company's leading profitability nationwide, Pridemore emphasized that the new rules are expected to reduce monthly rates by about $2.64 per residential customer. "Like every state commission," Georgia regulators are "trying to find a reasonable level of spending that ensures reliability while avoiding unnecessary costs," she added.

The Theory of Balance

One emerging tool for balancing spending and electricity price increases is new metrics.

"Ultimately, potential investments need to be prioritized," said Paul De Martini, Managing Partner at Newport Consulting Group. He co-authored a report released in January by Lawrence Berkeley National Laboratory on optimizing distribution system modernization investments.

The report describes "multi-objective prioritization" metrics developed by DTE Electric in Michigan and Portland General Electric in Oregon. It states that planning "must address multiple objectives" and "these objectives need to be prioritized," although "most distribution network investments can address more than one objective."

Dan Scripps, Chair of the Michigan Public Service Commission, said the commission uses DTE's global prioritization model but also recognizes practical limitations in its usefulness. "If the model inputs are good, we have confidence that the outputs are reliable."

The LBNL report states that regulators' priority should be "modernization projects that create the greatest value." It adds that the most valuable modernization investments are the result of "integrated distribution system planning," which typically includes comprehensive analysis and often uses two metrics.

LBNL notes that for individual expenditures whose full value is only realized when "interdependent components are all deployed," a "best-fit, lowest-cost" analysis can be used. The report adds that benefit-cost analysis is the best choice if benefits "are separable, allocable, quantifiable, and do not change materially with usage."

LBNL concludes that the best practice in planning is to link investments to "achieving specific outcomes... that clearly support stated planning objectives." The best metrics should reflect both "the prioritization of objectives" and "the degree to which proposed solutions contribute to each objective."

Ann Rendahl, Commissioner at the Washington Utilities and Transportation Commission, agreed that the planning process is critical to effective decision-making. "Large rate increase requests have become more common," but through effective planning, regulators can address the "trade-offs" between cost savings and "the most efficient and reliable service," she said.

De Martini noted that other recent studies have also developed new metrics. Pacific Northwest National Laboratory has studied planning strategies for aging infrastructure replacement, and the Clean Air Task Force has examined the risks of over-reliance on levelized cost of energy data, he said.

"Defining affordability at the beginning of the planning process is also important," De Martini cautioned. "Utilities assume that a certain percentage increase in revenue requirements relative to inflation is affordable, but stakeholders, regulators, and legislators may have different views."

Many attendees acknowledged that despite the best metrics, regulators ultimately still face difficult subjective judgments.

Harder Balancing Decisions

Regulators and analysts say protecting customers from high electricity prices may mean making imperfect choices.

"There are always trade-offs; some potential investments cannot be implemented, but resources are limited," said LeBel of RAP. "The best but most expensive option, such as undergrounding lines, may not be the wisest for utilities and regulators, but it is the regulator's duty to learn all lessons and do better in the future."

Andrea Staid, Principal Technical Leader for Energy Systems and Climate Analysis at the Electric Power Research Institute (EPRI), acknowledged that worsening extreme weather events due to climate change make doing better more challenging, especially when necessary decisions are costly.

But "research shows the cost of inaction will be enormous," Staid said. Regulators need to remember that "utilities are already planning significant spending to meet customer needs, and investments that reduce climate risk and enhance climate resilience have benefits far exceeding upfront costs," she added.

Ted Thomas, former Chair of the Arkansas Public Service Commission and now founder of Energize Strategies, agreed that regulators need to limit spending "to hold utilities accountable." But he added, "They must never stifle innovative investments in technologies like Advanced Metering Infrastructure (AMI), which can lead to a higher-quality system."

Finally, Letha Tawney, Chair of the Oregon Public Utility Commission, said regulators need to carefully pace investments by understanding "what is necessary versus what is nice-to-have." Current planning allows regulators "to pace and prioritize based on the additional capability and reliability impacts proposed by utilities," she added.

"There is no perfect answer because stakeholders value different things," but the planning process allows stakeholders "to fully analyze proposed investments," Tawney said. Then regulators "can decide how quickly each investment can be implemented."

Regulators are bringing the challenges of new metrics, innovation potential, and spending pace into the actual modernization process.

Real-World Balance

Commissioners say that in the real world, hard business facts matter.

Michigan Chair Scripps said the third-party audit of DTE and Consumers Energy's distribution systems by Liberty Consulting was extremely valuable. The year-long audit produced multiple "specific recommendations for cost-effective improvements," and "we approved cost recovery mechanisms based on the audit results," he added.

Another example of the growing emphasis on business approaches is the order issued in June by the Massachusetts Department of Public Utilities authorizing utility modernization spending. The order states: "Grid modernization and resilience planning must ultimately become part of each company's standard business practices."

A landmark "business case proceeding" led to the Rhode Island Public Utility Commission authorizing Rhode Island Energy to deploy AMI in May. The commission approved recovery of the utility's capital expenditures—but with "conditions."

"Commission decisions often fall between 'what the utility wants' and 'what Rhode Island needs,'" said RI PUC Commissioner Anthony, a long-time advocate of the business case approach. "The AMI proposal was approved because, despite limited proof of need and value, there was a strong accountability mechanism."

"The first part of the accountability framework is setting a hard budget cap of $154 million in customer costs, which the company itself proposed," Anthony said. The company also committed to continuing to invest its own funds, even if it exceeds the cap, "until it delivers the advanced metering capabilities it promised," she added.

Additionally, the commission imposed penalty provisions if the company fails to achieve "the core elements of its value case," such as improved outage notifications and "faster transmission of customer data from the meter to the utility and back to the customer," Anthony said.

"Modernization can create a more reliable, more sustainable electricity system," but "there is also a risk that customers pay for a system that fails to deliver," Anthony said. "The stakes are too high for regulators to gamble on outcomes," but in the AMI deployment, a strong business case convinced the Rhode Island commission, she added.

"Electricity prices will inevitably rise due to spending needs for distribution system modernization," said De Martini of Newport Consulting. "The question is how much they will rise."