The headline percentage matters. The rate design details matter more — especially for manufacturers, data centers, NOC operators, and any industrial user that cannot simply shift load off-peak.
Duke Energy filed applications with the North Carolina Utilities Commission on November 20, 2025 requesting a 15% revenue increase over two years for both Duke Energy Carolinas (Docket E-7, Sub 1329) and Duke Energy Progress (Docket E-2, Sub 1380). If approved, Duke Energy Carolinas residential customers using 1,000 kilowatt-hours per month would see bills rise $17.22 per month beginning January 1, 2027 — from $144.98 to $162.20. Duke Energy Progress residential customers would see $23.11 added to their monthly bills. The NCUC is expected to issue a final order in late 2026.
Those residential numbers have driven most of the public debate. Governor Stein and Attorney General Jeff Jackson both publicly opposed the rate increases in December 2025. Advocacy groups have characterized the proposal as excessive given Duke’s recent profitability. Those are legitimate concerns for a state where residential electricity prices rose 10.5% nationally between January and August 2025 — among the fastest increases in a decade.
But for large industrial customers, continuous operations users, and companies operating specialized facilities that depend on reliable, predictably priced electricity, the most consequential questions in this rate case are not the headline residential numbers. They are the rate design provisions — the structure of the increases, the cost allocation framework, the TOU expansion, and the proposed changes to how large-load customers are treated — that will govern electricity economics for years beyond the current proceeding.
The Rate Case Structure: What MYRP Actually Means
This rate case is structured as a Multi-Year Rate Plan — a two-year plan covering 2027 and 2028. Under the MYRP framework, the NCUC first establishes base rates through traditional ratemaking, then layered on top are automatic “step-up” adjustments tied to specific capital investments scheduled to come into service during the plan period. For 2027 and 2028, Duke has proposed $8.3 billion in investments whose costs will flow through those step-up mechanisms: $3.2 billion in distribution upgrades across 436 projects, $1.3 billion in transmission across 603 projects, $1.7 billion in energy storage across 13 projects, $502 million in nuclear across 48 projects, and $934 million in natural gas, coal, and hydro across 198 projects.
For industrial customers planning capital budgets, the MYRP structure creates a materially different planning environment than a traditional single-year rate case. Costs can increase within the approved plan period without a full commission proceeding — through the step-up mechanism — meaning electricity cost projections carry more uncertainty than the approved base rate implies. The Carolina Industrial Group for Fair Utility Rates (CIGFUR) challenged this structure within days of the filing, arguing that a two-year plan violates House Bill 951 — passed in 2021 as “Energy Solutions for North Carolina” — which established a specific three-year rate plan framework negotiated through a nine-month stakeholder process. Duke countered that the two-year plan is designed to align with the company’s pending merger of Duke Energy Carolinas and Duke Energy Progress — a business combination application that is separately before the NCUC. The commission has not yet resolved the CIGFUR objection.
Time-of-Use Rates and the Continuous Operations Problem
Duke’s filing includes expanded time-of-use rate options for commercial and industrial customers. The basic logic of TOU pricing is sound: customers who can shift electricity use away from system peaks reduce strain on the grid and should receive a pricing signal that rewards that flexibility. Duke’s consumer-facing guidance captures this simply — run the dishwasher overnight, do laundry on weekends.
That logic applies cleanly to discretionary loads. It does not apply to continuous operations. A steelmaking furnace cannot be paused during peak hours. A Network Operations Center supporting hospital communications, public safety dispatch systems, or military network infrastructure cannot reduce load during the 4-to-9 PM window because that is when demand peaks on the Duke system. A data center running AI inference workloads for a government customer cannot shift its computing load to off-peak hours based on grid conditions.
For these users, TOU rate designs that presume load flexibility can function as a cost penalty on continuous operations rather than a grid management tool. A TOU structure that creates material cost premiums during peak windows — without carve-outs, exemption mechanisms, or alternative rate schedules for customers with operationally non-negotiable continuous load profiles — effectively charges a premium for reliability. The rate case is an opportunity to evaluate whether Duke’s proposed TOU expansion is designed to genuinely manage system peaks or whether its cost implications fall disproportionately on customers who have no option but to run continuously.
Nucor, NOC Operators, and Why Rate Design Is an Operational Issue
Duke Energy’s proposed Accelerating Clean Electricity tariff — which would initially serve Amazon, Google, Microsoft, and Nucor, the Charlotte-based steelmaker — illustrates how directly rate design intersects with specific industrial customers’ operational and economic planning. Nucor is not a passive electricity consumer. It is one of the largest users of electricity in Duke’s service territory, and its operations — electric arc furnace steelmaking — are among the most energy-intensive and continuous industrial processes in existence. Rate changes that affect demand charge structures, peak adders, or the cost of maintaining baseload draw through peak periods directly affect Nucor’s production economics in ways that simpler customers never encounter.
The same logic applies to a different category of user that the rate case debate rarely addresses: operators of Network Operations Centers (NOCs) and mission-critical communications infrastructure. Companies providing managed support services for public safety communications networks — supporting the 911 systems, emergency dispatch infrastructure, and interoperable radio networks relied upon by law enforcement, fire, EMS, and hospitals — operate NOCs that run continuously, 24 hours a day, 365 days a year. These are not facilities that can participate in load flexibility programs or shift consumption to off-peak windows. Their power draw is governed by the mission, not the rate schedule. For these operators, demand charge structures, peak adders, and TOU pricing that presumes flexibility create cost exposure that cannot be mitigated through operational adjustments.
Duke has stated it is evolving its contracts with large-load customers to include termination penalties and minimum bills for customers whose plans subsequently change — a mechanism designed to ensure infrastructure built for specific large customers is paid for if those customers exit. That is a reasonable approach to cost protection. The question for existing continuous operations users is whether analogous protections run in the other direction: rate structures that recognize continuous, mission-critical load profiles as a distinct category deserving of rate treatment that does not penalize reliability dependence.
The Cost Allocation Question Underneath the Rate Case
The deepest issue in Duke’s rate case is one the headline percentage obscures entirely: who pays for the infrastructure being built to serve rapid load growth from data centers, advanced manufacturing, and electrification? The Energy Policy Task Force’s interim report identified large load tariff development as a top priority precisely because this question has not been resolved in North Carolina’s regulatory framework. A large load tariff would require new large-load customers to pay rates tied to the full infrastructure cost of serving them, protecting existing residential and commercial customers from subsidizing growth.
Duke’s rate case does not include a large load tariff — that remains the task force’s domain and a future proceeding. But the rate case does include provisions that begin to move in that direction: the Accelerating Clean Electricity tariff proposal, the termination penalty and minimum bill provisions, and the broader MYRP framework in which specific capital investments are linked to step-up adjustments that customers will ultimately pay for.
Senate Bill 266, enacted over Governor Stein’s veto in 2025, added another dimension. Under SB 266’s revised fuel charge framework, residential customers may bear a greater share of fuel and purchased power costs while large commercial customers pay proportionately less. The interaction between SB 266’s cost allocation shift and Duke’s proposed base rate structure is a question that warrants scrutiny from any large industrial customer evaluating total electricity cost exposure under the post-2026 rate environment.
The Duke Energy rate case proceeding is active, and a final NCUC order is expected before the end of 2026. For industrial users, continuous operations companies, data center operators, and public safety technology firms with significant North Carolina electricity consumption, the proceeding is worth tracking not only for its bottom-line impact on monthly bills but for the rate design decisions embedded within it. Those decisions will govern electricity economics in North Carolina for years — and some of their implications for continuous, mission-critical operations will not be visible from the headline percentage alone.