As Duke Energy Corp. transitions its fleet away from coal-fired generation to help meet its emissions reduction goals, a new analysis shows the North Carolina investor-owned utility also risks stranding nearly $5 billion in planned natural gas investments.

"Without regulatory intervention, ratepayers will continue to pay off these plants for decades, even while they remain neither used nor useful," Tyler Fitch, regulatory manager for the Southeast at Vote Solar, wrote in the Energy Transition Institute's January report, "Carbon Stranding: Climate Risk and Stranded Assets in Duke's Integrated Resource Plan."

Under the 15-year integrated resource plans, or IRPs, filed in September 2020 by Duke Energy Carolinas LLC and Duke Energy Progress LLC, the utilities would retire all power plants in the Carolinas that "rely exclusively on coal" within the next 10 years and add between 1,050 MW and 7,400 MW of storage to their portfolios.

The six scenarios outlined in the IRPs are designed to allow Duke Energy to achieve its goal of a 50% reduction of carbon emissions by 2030 from 2005 levels and net-zero emissions by 2050. Certain scenarios are also designed to align with the North Carolina Clean Energy Plan, which calls for up to a 70% reduction in greenhouse gas emissions by 2030 from 2005 levels.

"To meet [Duke Energy's] corporate climate commitment, carbon-emitting plants within the Duke Energy fleet in the Carolinas will either need to decrease their usage rate or be pulled out of operation altogether," Fitch wrote. "This includes removing coal entirely from the portfolio in the early 2030s and stranding even recently built combined-cycle plants through the 2030s and 2040s."

The Energy Transition Institute analysis is especially critical of a base-case scenario that calls for 9,600 MW of new gas-fired generation by 2035. Under this scenario, which does not contemplate new carbon policy, Duke Energy also would add 8,650 MW of new solar capacity, 1,050 MW of battery storage and 2,050 MW of energy efficiency and demand response to the combined portfolios of DEC and DEP, while 3,050 MW of coal capacity "capable of co-firing on natural gas" would remain online.

The analysis calls Duke Energy's gas plans under this scenario "one of the largest proposed expansions of fossil generation capacity of any utility in the United States."

"The scenario of building no new natural gas sounds simple, but it's the most expensive option for our customers and actually requires coal units to operate longer," Duke Energy spokesperson Erin Culbert wrote in a Jan. 26 email. "It also relies heavily on emerging technologies and could present challenges in reliability for the families, businesses and industries who rely on us."

Culbert said that Duke Energy did model potentially shorter life spans for its gas units, 20 to 25 years instead of 35 to 40 years, "and it still showed those made sense."

The Energy Transition Institute, however, contends if Duke Energy pursues an investment plan in line with the IRPs, "a substantial portion of its power plant fleet will need to be taken offline to meet existing carbon commitments."

"Carbon stranding costs to ratepayers are on the order of tens or hundreds of millions of dollars per year," Fitch wrote. "In total, this analysis finds that carbon stranding costs from existing and proposed investments in these integrated resource plans will be $4.8 billion, or $900 in present-value costs for every residential Duke Energy customer in the Carolinas."

"Although the burden of stranded asset costs should be borne by utility shareholders in the abstract, stranded asset costs are more often assigned to ratepayers in practice," the report adds.

These stranded costs would exceed by "more than $1 billion" the total stranded costs to both Duke Energy and Dominion Energy Inc. combined from their decision to cancel the Atlantic Coast Pipeline project, according to the Energy Transition Institute.

The analysis also points to a 30 million metric tons "overshoot" of projected greenhouse gas emissions.

"If the Duke companies continue to operate their fleet as they have historically, the emissions trajectory of Duke Energy's operating companies in the Carolinas will be increasingly inconsistent with Duke Energy's corporate climate commitments," Finch wrote. "Duke Energy's emissions in the Carolinas will decline about 40 percent by 2050, from 50 million tons of carbon emitted in 2020 to just over 30 million metric tons in 2050."

Culbert, meanwhile, pointed out that "there are a variety of ways we could handle having gas in the mix as we get closer to 2050, and much of it depends on what technology develops by then."

"For example, those units could be hydrogen-capable, could get advanced sequestration technology or could simply not run as much as other dispatchable energy sources come online," Culbert said.

"While our IRPs involved significant stakeholder participation and stand up to intense scrutiny through a transparent regulatory review, there's virtually no way to validate the assumptions and conclusions in this report," Culbert added. "We are working with stakeholders and policymakers on a cost-effective path forward for the Carolinas' energy transition that's equitable for all. While we welcome all perspectives, not all parties have the same responsibility we do for providing energy that's cleaner, reliable and affordable."