Shortly after Memorial Day, the Georgia Public Service Commission (PSC) convened to hear testimony from parties asking for improvements in Georgia Power’s Integrated Resource Plan (IRP): the utility’s ten-year infrastructure plan for deciding what gets built, where electricity will flow, and who will pay for it. Multiple parties recommended improving system reliability and reducing costs through more comprehensive analysis of regional needs for transmission lines.
However, Commissioners and the utility were reluctant to move away from a traditional approach that relies heavily on Georgia Power building in-state power plants to meet the state’s growing energy needs. Like much of the Southeast, Georgia is experiencing new weather patterns, population growth, and the addition of major new individual electric loads on the system. These trends require a wide range of actions, including new and expanded transmission lines, in order to maintain reliable electric service. Georgia Power’s ten-year plan includes billions of dollars of new in-state transmission lines to connect both new power plants and major new industries to the grid.
The need for more energy will drive new transmission investments for Georgia Power, regardless of whether the utility chooses to build new power plants or increase connectivity to neighboring utilities. The status quo of Georgia Power’s closed transmission planning risks inefficient decisions showing up in your electric bill.
Improved Stakeholder Engagement, Role of Multi-Value Strategic Transmission
During the hearing, outside experts promoted the Carolinas Transmission Planning Collaborative as a successful model for stakeholder engagement that Georgia Power and its parent company, Southern, should follow when planning transmission locally through the Integrated Transmission System (ITS). Stakeholder meetings of the Carolinas Transmission Planning Collaborative, called the Transmission Advisory Group or TAG, are open to any individual or organization that signs up in advance.
In contrast, Georgia’s ITS process all occurs between Georgia utilities behind closed doors. And while stakeholders can attend a separate southeast regional meeting (Southeast Regional Transmission Planning, often called “SERTP”) hosted by Southern with other utilities to discuss regional transmission planning across multiple companies, it merely conducts a limited number of studies and does not have direct input into Georgia Power’s local plans.
Additionally, Georgia Power’s process prioritizes using local transmission lines within a utility’s service area to maintain system reliability. While “keeping the lights on” is the paramount goal of utility operations, this approach ignores a wide array of other effects that the size and location of transmission lines have on the grid. These effects include which power plants are used the most often, the opportunity to use cheaper generation for the system, improved power flows during hours of high-electric demand, and the availability of assistance from neighboring utility systems if a local power plant fails.
All of these additional factors are evaluated in a more robust transmission process called “Multi-Value Strategic Transmission” (MVST). In 2023, Duke added an MVST process to the Carolinas Transmission Planning Collaborative, in response to direction from the North Carolina Utilities Commission. Duke acknowledged the value of MVST in their filing to the Federal Energy Regulatory Commission. “To be positioned to reliably address the many dynamic demands facing the transmission grid, including not just the generation transition, but greater electrification, increased electric vehicle adoption, and new economic development, including from prospective customers with significant energy demands to power data centers or manufacturing hubs, Duke Energy needs to evolve its planning process from siloed planning for reliability, economics, and public policy.” Duke’s first round of the MVST process is expected to conclude by the end of 2025.
Grid Strategies recently examined the value of building three regional lines across the Southeast using MVST. They found that if SERTP built three new regional transmission lines instead of local projects, the average residential customer would save $4.47 per year. That’s about half of what customers are paying for Georgia Power’s Vogtle Unit 4, which added about $8.95 to the average customer’s bill. For system planning, if the Georgia Public Service Commission ordered Southern Company and Georgia Power to consider regional transmission lines as least regret projects with multiple benefits, these savings to ratepayers would only increase.
Interregional Transfer Capability enhances Georgia’s grid when it is constrained
Despite indications that a more public process and more comprehensive analysis could save customers billions of dollars, some members of the Georgia Public Service Commission were concerned that reliance on neighboring systems would undermine reliability. Georgia’s state law for integrated resource planning, however, lists power purchases from neighboring states as one of six possible sources of supply of power. During Winter Storm Elliott, Georgia Power was able to keep the lights on only because of emergency purchases from Florida Power and Light to Southern. Without Florida’s support, Georgia Power would have seen outages.
Congress also has tackled the issue of transmission lines needed for interregional coordination during severe weather. A Congressionally-mandated November 2024 Interregional Transfer Capability Study found that current transfer capability between Southeastern utilities is insufficient during extreme weather. Additional reporting by Grid Strategies concluded that rising load growth will put additional strain on a local utilities’ generation, further increasing the need for transfer capability not only between southeastern utilities, but also with utilities in other regions, allowing a utility to receive power from a region not experiencing high demand at the same time.
During the IRP hearing, Georgia Power cited recent blackouts in Louisiana as an example of why transmission planning should remain a local, utility-by-utility process rather than be regionally coordinated. Louisiana is part of a regional transmission organization named MISO that stretches from the Gulf to Canada. But, in the words of New Orleans City Councilman JP Morrell, the lead regulator of the power company Entergy in the city of New Orleans, “If we had better transmission, we could have flowed power from other parts of the state and other parts of this nation to keep power on.” In this case, MISO had proposed improved transmission ties into southern Louisiana but state regulators didn’t approve the cost. When a nuclear power plant went down, transmission was inadequate to transfer power from elsewhere in the region.
Improved Engagement enhances Transparency and “Right-Sizing” the Investment
As we outlined in our previous article, Georgia Power has the opportunity to improve its transmission planning by following our recommendations, which include:
- Clearly marking which transmission projects support which electricity needs
- Waiting to approve new transmission projects until the associated load growth has reached key interconnection and construction milestones
- Planning for batteries and solar based on their real-world support of the grid
These recommendations would be further enhanced by Georgia Power adopting open engagement with stakeholders and looking at a broad array of benefits when upgrading the grid. Beginning these processes now for both local and regional transmission planning will save Georgia ratepayers money, support growing demand for electricity, and keep the lights on.
