Dive Brief:
- Improved grid utilization could save customers of vertically integrated U.S. utilities $110 billion to $170 billion over the next 10 years, according to a new analysis prepared by the Brattle Group for GridLab and the Utilize Coalition.
- A 10% boost to annual system utilization translates to an average 3.4% decline in customer rates in 2030, assuming an increase in electricity sales between 20% and 30% over the same period, the report said. In a “status quo” scenario with the same load growth and no utilization increase, customer rates rise 1.4% by 2030, Brattle said.
- Ian Magruder, executive director of the Utilize Coalition, said on a Wednesday webinar detailing the report that with the grid running at half-capacity “at any given hour,” getting more out of existing infrastructure is a cost-effective solution for affordability concerns. “Our view is that … grid utilization is one of the only near-term solutions that can reduce the cost of electricity at scale in short order,” he said.
Dive Insight:
Brattle’s report is not the first to tackle the subject of underutilized grid capacity.
A report from the American Council for an Energy-Efficient Economy found at-scale deployment of load shifting capabilities, such as managed electric vehicle charging, could reduce peak demand by 60-200 GW over the next decade. The high end of that estimate is “an amount up to double the most aggressive projections of total U.S. data center capacity by 2030,” ACEEE said.
Finding spare capacity is harder now than it was two years ago as data centers interconnect at locations with preexisting headroom, said Ryan Hledik, Brattle Group principal and lead author on the report.
On the other hand, freeing up capacity is easier thanks to “a lot of options that have really just emerged at scale in the past five years,” such as distributed batteries, HVAC load control systems, managed EV charging, smart electrical panels and grid-enhancing technologies, he said.
Step two is finding new customers to absorb that capacity, which Hledik said has also gotten easier with data centers, advanced manufacturing and electrified homes and vehicles “knocking on the door and asking to connect to the grid.”
Step three, Hledik said, is recovering costs from those customers, which represent $140 billion in incremental annual revenue. A “significant portion of that” would cover costs associated with existing generation, transmission and distribution infrastructure, according to the report.
Brattle’s report found a clear inverse relationship between load growth and customer rate increases from 2019 to 2024. Texas, Nebraska and New Mexico saw load growth of about 15% or more during the period as rates declined by about 0.5% to 2%, for example. North Dakota, the most extreme case, saw nearly 40% load growth and a roughly 2.5% drop in rates. In contrast, California and Hawaii saw declining loads alongside sharp rate increases.
“States that have seen load growth are also the states that tend to have seen rate decreases,” Hledik said.
To calculate the potential benefits of increased grid utilization, Brattle modeled a “mid-sized U.S. investor-owned utility” with 3 GW peak demand, 43% generation capacity utilization, a 14 cents/kWh average retail rate and marginal capacity costs 30% higher than its average costs. It assumed 1 GW of new load in the near term, split evenly between distributed loads such as EVs and transmission-connected large loads like data centers.
In the status quo scenario, the utility serves the new loads “entirely through investment in traditional infrastructure,” or 1 GW of incremental generation and transmission capacity plus 500 MW of incremental distribution capacity. The rates charged to the new load cover the utility’s embedded costs but not the full incremental costs associated with the new infrastructure, Brattle said.
In the increased utilization scenario, the utility connects half the new transmission-level load “without imposing material new capacity costs on the system” via self-supply or load flexibility during peak hours. At the same time, it develops a 500-MW portfolio of distributed energy resources at a net cost of $50/kW-year, which — due to capacity derating — offsets some but not all of the new distribution-level load, Brattle said.
The result is an average customer rate reduction of 3.4% and a 10% increase in system utilization. If the DERs turn out to be cheaper to deploy or more impactful on the system, rates could fall by even more, though more expensive or less impactful DERs might have the opposite effect, Brattle said.
Because the increased grid utilization Brattle modeled “can reduce but doesn’t eliminate the need to invest in new infrastructure … utilities are still growing their rate base,” Hledik said. “That will be important to get everyone’s incentives aligned with this opportunity.”
However, the report also highlighted the tension between utility’s profit incentives and customer interests.
Even with an assumed lower return on equity, Brattle’s modeled utility earns more revenue in the “status quo” scenario – that is, with the same load growth assumptions but no grid utilization focus – than it would by focusing on grid utilization.
Compared with a no-growth “baseline” scenario, the utility’s “status quo” revenue increases 37% to $435 million per year without improved grid utilization. Its revenue only rises 23% to $390 million per year in the increased utilization scenario. Its ROE is 9.8% in the baseline and status quo scenarios, and 10.1% in the increased utilization scenario. The report’s authors assumed a regulatory mechanism “through which cost savings are shared between customers and shareholders.”
But there may be other incentives for utilities to invest in grid utilization. Brattle also found that increasing grid utilization shortens load interconnection headways, a major pain point for AI data center customers in particular. Load interconnection timelines fall from five to 10 years in the status quo scenario to one to five years in the increased utilization scenario.
On the webinar, Hledik acknowledged that “current regulatory models typically don’t do a good job of aligning utilities’ incentives” with pro-utilization investments.
“Utilities are financially incentivized to make investments in capital infrastructure … we need regulatory models that reward utilities for pursuing this opportunity,” he said.
Pier LaFarge, CEO of distributed energy provider Sparkfund, said on the webinar that load-shifting technologies — especially batteries — nevertheless enjoy powerful economic tailwinds.
“The coincidence of batteries getting cheap and load growth coming back make this inevitable even in the current regulatory model,” LaFarge said.
In an email, Hledik said the idea of increased grid utilization may be more appealing to utilities today than a few years ago, when load growth was minimal, utilities weren’t as “capital-constrained” by the need for significant system investments to keep pace, and affordability concerns didn’t dominate the political conversation.
“In the utilization-focused case, earnings go up and rates go down” relative to present levels, he said. “In the status quo case, earnings go up and rates go up. With today’s headline-level concerns about energy affordability, the former looks like a much more tractable path than the latter.”
