Duke Energy customers in North Carolina may soon find themselves paying to keep aging coal plants running for years beyond their planned retirement dates, all while footing early construction bills for nuclear reactors that won’t produce electricity until the next decade. That is the practical effect of a policy push now advancing through the state legislature, where a Joint Legislative Commission on Energy Policy met on February 3, 2026, and placed Duke’s nuclear expansion strategy at the center of the state’s coal transition.
The concept is straightforward: no coal plant shuts down until regulators have approved enough new nuclear capacity to replace every megawatt lost. But the execution is anything but simple, and the gap between the policy’s ambition and the reality of nuclear licensing timelines could leave ratepayers stuck with a double bill for years.
The legislative trail from HB 951 to now
North Carolina has been building toward this moment since 2021, when HB 951 first introduced a replace-before-retire framework for subcritical coal units. That law conditioned retirements on replacement resources being placed in service and tied those replacements to the certificate of public convenience and necessity (CPCN) process, the regulatory gate a utility must clear before building new generation under G.S. 62-110.1. The CPCN process requires public notice, evidentiary hearings, and detailed cost analysis, and for nuclear projects, it can take years.
Since then, lawmakers have steadily cleared regulatory obstacles for new reactors. Session Law 2023-138 expanded the state’s definition of clean energy to include nuclear and fusion, removing a classification barrier that could have complicated reactor permitting. More recently, SL 2025-78, called The Power Bill Reduction Act, adjusted cost-recovery rules for baseload construction work in progress (CWIP). In plain terms, that means Duke can begin billing customers for nuclear development costs before a plant generates a single kilowatt-hour of electricity.
The February 3 commission session fits squarely into this pattern. Over several meetings, the Joint Legislative Commission on Energy Policy has used its interim authority to probe Duke’s long-term resource plans and test whether nuclear can anchor the state’s carbon-reduction targets. The latest discussion of a megawatt-for-megawatt replacement rule for coal is not an isolated idea; it is the next step in a multi-year legislative shift toward nuclear-centric energy planning.
What Duke brought to the table
Duke Energy’s own nuclear strategy document, posted to the commission’s meeting materials, laid out the utility’s case. The handout detailed the size of Duke’s regulated nuclear fleet, ongoing license renewals for existing reactors, and planned capacity uprates totaling roughly 300 megawatts. It also highlighted customer savings Duke attributed to federal nuclear production tax credits in 2024, framing the existing fleet as a cost advantage rather than a financial burden.
Duke disclosed that it had submitted early-stage development work for future nuclear capacity, though the public document did not specify reactor types, whether small modular reactors or conventional large-scale plants, or proposed sites. That distinction matters. Small modular reactors remain largely unproven at commercial scale in the United States, while conventional nuclear projects have a well-documented history of cost overruns and schedule delays. The type of reactor Duke ultimately pursues will shape both the timeline and the price tag for ratepayers.
Why the timeline is the real problem
Tying coal retirements to completed nuclear approvals creates a procedural bottleneck with no clear end date. North Carolina’s administrative code requires nuclear CPCN applications to include detailed cost exhibits and fuel-load projections, all of which must be vetted through formal regulatory proceedings. Nationally, nuclear licensing and construction have consistently stretched beyond initial estimates. The two most recent large-scale U.S. nuclear builds, Vogtle Units 3 and 4 in Georgia, came online years late and billions over budget.
If lawmakers formalize the replace-before-retire mandate for nuclear specifically, coal plants that Duke had targeted for shutdown in the late 2020s could remain operational well into the 2030s. During that overlap, customers would absorb maintenance costs for aging coal units while simultaneously paying CWIP charges for reactors still in early development. No updated integrated resource plan filing has quantified what that dual burden would look like on a monthly bill, but the structural math is clear: two sets of costs, one set of customers.
What hasn’t happened yet
For all the momentum behind this policy direction, several critical pieces are missing from the public record as of June 2026. No bill text has been filed that specifies which coal units would be blocked from retirement, how many megawatts the mandate would cover, or what happens if nuclear approvals stall indefinitely. Duke operates multiple coal stations across the Carolinas, and the gap between a general policy direction discussed at a commission meeting and a binding statute with unit-level schedules remains wide.
The NC Public Staff, the state agency that represents ratepayer interests in utility proceedings, has not published a formal position on the specific nuclear replacement proposal discussed at the February session. The Public Staff’s oversight covers both coal retirements and nuclear license renewals, but no intervention filings on this scenario have appeared in the publicly accessible docket system. Without that input, it is difficult to know whether the state’s consumer advocate views the megawatt-for-megawatt requirement as a reliability safeguard or a cost trap for households.
Regional grid dynamics add another layer of uncertainty. Duke’s Carolinas system operates within a broader southeastern power network where imports, exports, and reserve margins depend on coordinated planning. A unilateral decision to keep coal online longer, or to channel billions into new nuclear while delaying other resource additions, could ripple through regional reliability assessments and long-term power purchase agreements. None of those downstream effects are addressed in the documents released so far.
What North Carolina ratepayers should watch for
The policy trajectory in Raleigh is unmistakable. Across three legislative sessions, lawmakers have reclassified nuclear as clean energy, enabled utilities to bill customers for construction costs before plants are built, and laid the groundwork for a rule that would keep coal burning until nuclear replacements are certified. Each step has been incremental. Together, they represent a fundamental reorientation of how North Carolina plans to generate electricity.
But the most consequential details remain unresolved. Which plants are affected, how long they might run, and how much customers will ultimately pay will only become clear when lawmakers translate the commission’s discussions into a specific bill with a number, a committee assignment, and a vote. Until that happens, the coal-to-nuclear linkage is best understood as an emerging strategy with strong legislative backing rather than a settled mandate. Ratepayers should watch the General Assembly’s calendar closely, because the bill that eventually surfaces will determine whether this approach delivers affordable, reliable power or locks North Carolina into years of overlapping costs with no guaranteed timeline for relief.
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*This article was researched with the help of AI, with human editors creating the final content.
