Duke’s 2025 Integrated Resource Plan is ongoing and will have a public hearing at the North Carolina Utilities Commission beginning June 9th.
Recent changes have not lived up to Commission’s goals
In the initial 2022 Carbon Plan order, the North Carolina Utilities Commission (NCUC) advised Duke to improve its transmission planning. Duke subsequently proposed to the Federal Energy Regulatory Commission (FERC) implementation of Multi-Value Strategic Transmission Planning (MVST), “To be positioned to reliably address the many dynamic demands facing the transmission grid… Duke Energy needs to evolve its planning process from siloed planning for reliability, economics, and public policy.”
However, as Duke moves through the 2025-2026 cycle of its Integrated Resource Plan at the Commission, recent testimony from Michael Goggin of Grid Strategies (sponsored by SACE, Vote Solar, and Sierra Club, represented by the Southern Environmental Law Center), highlights that the initial MVST process has not fulfilled this objective, and remains focused on short-term reliability needs instead of more cost-effective long-term solutions. This is caused by Duke evaluating transmission through new generation and load requests in the near-term. This approach at MVST closely mirrors traditional, reactive planning of transmission and does not anticipate future transmission needs. It misses an opportunity to take advantage of transmission as if it were a new highway that can facilitate future economic growth, where higher voltage lines will have extra capacity to take on new load and generation into the future, instead of needing piecemeal investments every few years.
Additionally, Duke only plans for transmission over a 10-year horizon. Transmission assets can last 40-50 years. If Duke used a 20-year window, they would identify that higher voltage solutions, including greenfield transmission, would be more cost-effective. In the long run, the current 10-year approach is more expensive for ratepayers than a 20-year plan.
As Goggin points out, “Even if Duke built zero storage and renewable generation over the next ten years, new load and the new generation required still need proactive transmission planning to right-size this investment. Reforming the MVST planning process to fix these problems is urgent due to the lead time required to plan, permit, and build transmission, particularly high-voltage and greenfield solutions.”
Duke has repeatedly pointed to the MVST process at the Carolinas Transmission Planning Collaborative as the venue for evaluating higher voltage and greenfield transmission lines, yet their approach continues to use selection criteria that always choose upgrades to existing lower-voltage lines. Without improvements to MVST, Duke’s system will expand too slowly, in a piecemeal manner that ultimately costs more to ratepayers, and is unable to meet energy needs in the Carolinas.
Despite Duke’s assurances that its system planning is evolving, proactive transmission planning has not been achieved and is still needed to meet growing electricity demand, not only from data centers, but also from the electrification of heat and transportation. Proactive transmission planning also increases opportunities to add new generation, including renewable energy.
Proactive Transmission requires more granular data to identify system needs
Duke currently carries out production cost modeling of its generation at the zonal level (Duke Energy Carolinas and Duke Energy Progress), yet this analysis lacks the precision necessary to identify economic congestion as a need for transmission investment. Instead, in order to capture the full value of transmission, Duke should use nodal production cost modeling as part of MVST to quantify economic congestion on their system. Nodal modeling examines the cost to provide electricity to customers across a replication of the electricity system, factoring in transmission constraints that require using higher-cost generation. This tool provides real-world data to identify a broader set of transmission solutions, increasing options for least-cost generation to support the Carolinas’ energy needs. When there is a risk of a thermal overload in a particular element of the transmission system, Duke’s options for which power plant to dispatch are limited. In other words, there are times when Duke’s existing transmission system requires Duke to use expensive power plants instead of a cheaper option, thus raising bills. This economic inefficiency on the grid is called “economic congestion.” Without using a granular model (nodal is more granular than zonal), Duke cannot identify and thus address the potential for this economic congestion, and it will continue into the future.
Interim Solutions not considered by Duke can support system needs while new transmission is built
If Duke begins using nodal production cost modeling in MVST to identify transmission needs, the resulting data will also show additional value for alternatives to upgrading transmission lines, such as adding battery storage or grid-enhancing technologies like Dynamic Line Rating (DLR) that allow us to use our existing grid infrastructure more efficiently. Battery storage can be deployed in load pockets such as urban areas to offset the need for grid upgrades and support local reliability. Duke’s reliability planning assesses whether a power plant or transmission line going offline creates overloads on nearby lines, and what upgrades are needed to address this contingency. According to Goggin, “Batteries can almost instantly respond to the change in power flows or voltage that result from these contingencies, preventing overloads or voltage instability and ensuring grid reliability is maintained.”
Dynamic line rating is a real-time assessment of available capacity on a transmission line. Transmission lines are typically rated extremely conservatively based on worst-case conditions, such as summer peak during the hottest day of the year. Dynamic line rating measures the current temperature and wind speed, and can increase the transmission line’s power flow limit, reducing the need for transmission upgrades to get power to where it is needed. Duke recently filed a dynamic line rating pilot program with the Commission. However, if dynamic line rating were evaluated across Duke’s system during transmission planning, it would likely lead to a group of transmission upgrades that would see higher use, with fewer investments in upgrades that only support the grid under the limited snapshot of system conditions currently employed.
Duke’s approach undervalues benefits of regional transmission
Utilities are all already interconnected, but typically experience power plant outages and peak demand at different hours of the day. By improving the ability to transfer power from neighboring utilities through higher voltage transmission, Duke can import lower-cost power when it is available and export power when they have a surplus. Duke claims that no additional transfer capability is needed with its neighbors, because there has not been an increase in transmission service requests. However, these requests are long-term reservations between utilities, rather than the hourly transactions of power sold between utilities each day. Duke’s approach also fails to quantify the value of transmission ties outside of the Southeast, where access to wind power from midwestern markets through interregional transmission would improve reliability during winter mornings. This is all yet another way that Duke is continuing to plan its transmission in a piecemeal and reactive way.
Duke is required by FERC to conduct regional transmission planning with Southern, TVA, and other utilities through the Southeast Regional Transmission Planning (SERTP) region. Like Duke, other SERTP utilities use a 10-year planning window and prioritize reliability needs as their inputs for regional planning. This discourages improved regional ties despite the reliability and economic value of these options.
Recognizing that current regional planning is not leading to a more efficient grid, FERC issued in 2024 Order 1920, which requires Duke and other SERTP utilities to assess the production cost savings created by transmission over the entire region. Using nodal production cost modeling through MVST would provide the best data from Duke to SERTP’s regional planning, improving opportunities to identify regional transmission solutions to the Southeast’s growing energy needs over each hour of the year.
Order 1920 creates a role for state commissions to be more involved in regional transmission planning. Relevant State Entities, such as the NCUC, will have a say in establishing how to allocate the costs of regional transmission among the benefiting utilities (and their customers) within SERTP.
This is a historic opportunity for state commissions to exercise greater influence over transmission planning in order to right-size transmission investment, rather than allowing the continued practice of regulated utilities using transmission planning as an excuse to plan system expansion as an island, prioritizing capital-intensive power plants that increase profits and shareholder payments on the backs of ratepayers.
Our recommendations for 2026 Carbon Plan IRP include that the Commission:
- Urge Duke to plan transmission based on economics, not just reliability
- Urge Duke to use production cost modeling for transmission at the nodal level to precisely identify system needs
- Urge Duke to use a 20-year planning horizon for the next cycle of MVST
- Urge Duke to transparently evaluate a broader range of solutions, including higher-voltage and greenfield transmission, interim solutions like Grid-Enhancing Technologies (GETs), and strategically-sited batteries
- Encourage Duke to (1) propose and advocate for the Southeastern Regional Transmission Planning (SERTP) process to conduct proactive multi-value transmission planning using reasonable assumptions that accurately reflect the value of transmission and (2) instruct Duke to use the benefits and methodology to calculate the benefits that SERTP adopts in compliance with Order No. 1920 in the MVST process.
- Push Duke to assess the net economic and reliability benefits for ratepayers from improved regional coordination in power system operations.
The CPIRP will affect what shows up in your bill for years to come. Transmission planning, done proactively and integrated or at least iterated with the CPIRP, will help mitigate future rate hikes caused by reactive and siloed planning processes. We encourage everyone to tune in to the hearing beginning June 9th.
