Southern Co. subsidiary Georgia Power has proposed a pivot toward extending the life of several existing coal and natural gas-fired power plants into the late 2030s—well beyond previous retirement timelines—citing rising electricity demand, regulatory constraints, and grid reliability risks.
The utility’s , filed with the Georgia Public Service Commission (PSC) on Jan. 31, 2025, marks a strategic shift in the company’s approach to managing its supply and demand profile. Over the next 10 years—between the winter of 2024/2025 and 2028/2029—the company expects its load forecast to surge to 9.4 GW. It expects 8.2 GW in load growth over the next six years alone—”an increase of more than 2,200 MW in peak demand by the end of 2030 when compared to projections in the 2023 IRP Update,” the utility noted.
The IRP attributes this to “a growing pipeline of potential and committed large load customers,” including industrial projects like in Bryan County— which alone represents “the largest economic development project in Georgia’s history”—and the in Bartow County. As a whole, the IRP reveals that Georgia Power expects a 7% compound annual load growth rate through 2031, fueled by a 22.8 GW active pipeline of potential and committed commercial and industrial (C&I) projects as of the second quarter of 2024—6.8 GW higher than 2023 projections.
“The size of many of these projects far exceeds historical annual norms, with some individual projects surpassing 1,000 MW,” the IRP warns. “In addition to the size of the large loads presented by these new projects, many of the projects reflect a higher load factor with around-the-clock operations, which requires a substantial amount of generation and consistent energy delivery throughout the day and night as opposed to only during specific times.”
Coal Fleet: Compliance Upgrades to Enable 14-Year Extensions
Since 2007, Georgia Power has retired 5,547 MW of capacity, including 4,787 MW of coal, 509 MW of oil, 132 MW of gas/oil dual-fuel, 118 MW of oil-fired combustion turbines, and 0.4 MW of hydro. Today, the utility operates an 18.5-GW fleet, balancing company-owned assets and power purchase agreements (PPAs). Its generation mix includes 3.9 GW of coal across two plants, 8 GW of natural gas from combined cycle and combustion turbine units, 1.1 GW of hydroelectric power from 66 units across 15 plants, 2 GW of solar from owned and contracted projects, and 500 MW of battery energy storage.
The 2025 IRP underscores the need “to invest in its foundational resources” to maintain system reliability. Abandoning earlier plans to phase out its remaining coal plants, the utility has proposed to extend operations at the 3.2-GW Plant Bowen—one of the world’s largest coal plants—beyond 2034 and keep the 648-MW Plant Scherer online until 2038. The move marks a sharp shift from the company’s 2022 IRP, which slated Plant Bowen for retirement by 2027 and Plant Scherer Unit 3 by 2028.
Plant Bowen, located in Bartow County, will require compliance modifications to meet the Environmental Protection Agency’s (EPA’s) recently finalized regulating wastewater discharges by December 2029. The ELG controls will provide Georgia Power with compliance flexibility to meet the EPA’s (111 GHG Rules), “enabling the natural gas co-fire compliance pathway to be selected during the state plan development process,” the IRP says.
“Notably, the co-fire pathway in the 111 GHG Rules permits operation until December 31, 2038, while reducing reliance on natural gas pipeline infrastructure and deferring the need for replacement capacity until 2039.” The utility suggested that the pathway is more economical than the other 111 GHG Rules compliance options—such as full-scale carbon capture—and reduces the need to procure new capacity by 2032 or earlier. “Maintaining dispatchable generation in north Georgia is crucial for transmission system reliability,” it adds. “Considering the uncertainty surrounding future environmental regulations and market conditions, this approach provides an economical, flexible, and adaptive strategy to ensure continued compliance and resource planning optionality.”
Plant Scherer, located in Monroe County, will follow a similar compliance pathway, leveraging for wastewater treatment, which will likely be installed in 2028. Additionally, 187 MW of capacity from Scherer Unit 3 will be allocated to Georgia Power’s retail jurisdiction to reinforce system reliability.
Natural Gas: $1.2B in Capacity Upgrades
While the utility had also moved to retire Plant Gaston, a 566-MW oil and gas plant in Alabama, the 2025 IRP calls for extending the operation of the plant’s four units, along with its oil-fired Unit A, beyond December 2028, assuming continued operation through the end of 2034. The decision will “help preserve capacity and add flexibility to the resource plan, given the ability to retire the capacity if projected load does not materialize,” the IRP says.
It also proposes major upgrades at several gas plants:
Plant McIntosh, located in Rincon, Georgia, will undergo a 194 MW capacity increase with the installation of GE 7FA.05 high-efficiency turbines at Units 10-11. Additionally, McIntosh Units 1A-8A will receive staggered turbine replacements, adding 74.4 MW of peaking capacity between 2026 and 2032, bringing the total plant capacity to about 1,380 MW .
Plant McDonough, situated in Smyrna, Georgia, a key natural gas combined-cycle facility, will remain in operation through 2057, supporting baseload reliability with a total capacity of 2,792 MW, with individual unit capacities ranging from 840 MW to 934 MW.
Plant Yates, located in Newnan, Georgia, originally slated for potential retirement, will continue operating until 2038. Units 6 and 7 provide a combined capacity of approximately 648 MW, while additional units contribute to the plant’s overall capacity.
Nuclear Uprates for Bolstered Baseload Capacity
In addition, the IRP outlines a significant capacity expansion for Georgia Power’s existing nuclear fleet, which comprises two boiling water reactors(BWR) at Plant Hatch in Baxley, Georgia (Units 1 and 2, totaling about 1,848 MW), and four pressurized water reactors at Plant Vogtle near Waynesboro, Georgia (Units 1-4, totaling approximately 4,536 MW).
It plans extended power uprates (EPU) at Plant Vogtle Units 1-2 and Plant Hatch Units 1-2 to increase their reactor thermal output—potentially adding up to 112 MW of additional nuclear generation by 2032 while avoiding the need for new transmission infrastructure investments.
The planned capacity gains follow a phased schedule, with incremental increases beginning in 2028. The upgrades at Plant Hatc’s BWRs will also include a Maximum Extended Load Line Limit (MELLA+) enhancement, which boosts thermal efficiency without increasing core flow. Additionally, Georgia Power is evaluating a transition to a 24-month refueling cycle at Vogtle Units 1-2 , a move designed to extend unit runtimes and reduce refueling outages across its nuclear fleet.
Georgia Power noted the investments will align with the Inflation Reduction Act’s (IRA) Section 45Y production tax credits (PTCs), which could provide 10 years of financial benefits for the additional capacity. In addition, “The state of Georgia offers an [investment tax credits] for investments in new or existing facilities. The upgrades to Plant Hatch are expected to qualify for 5%, and the upgrades to Plant Vogtle are expected to qualify for 3%,” the IRP notes.
The upgrades could also qualify for Department of Energy (DOE) Title 17 loan guarantees. Notably, Georgia Power also said it is exploring whether the incremental nuclear capacity can be offered as part of a carbon-free energy subscription program—a move that could decrease the net upgrades’ net costnet cost to non-participating customers and provide “access to incremental clean energy attributes to help meet customer specific needs.”
Renewables and Storage: Cautious Expansion
The 2025 IRP maintains its commitment to an 11,000 MW renewable energy portfolio by 2035 but acknowledges key system integration challenges. It suggests that the utility will request proposals (RFPs) in 2025 to procure an additional 1,100 MW of renewables, including 1,000 MW of utility-scale solar and 100 MW of distributed generation. A separate 500 MW storage RFP is scheduled for the fourth quarter of 2025, with an anticipated certification by the third quarter of 2027. Additionally, Georgia Power will develop 80 MW of demonstration projects to evaluate the performance of four-hour battery storage systems at the Army’s Fort Stewart site.
The IRP also notably includes a $127 million hydroelectric modernization investment across nine facilities to extend critical assets’ operational life. Key projects include turbine and generator upgrades at Bartletts Ferry and Goat Rock and improvements at Plant Tallulah, Plant Yonah, and Plant Wallace. “Approval to modernize the remaining hydro fleet will allow the Company to fully gain the benefits of enhanced fleet dispatch and operational efficiency of each river chain. The hydro modernization effort seeks to strategically plan projects while optimizing resources, design, planning, and execution of work more efficiently than a longer-term piecemeal approach,” the IRP notes.
Finally, the IRP underscores strategic transmission planning to address South-to-North transmission constraints, a growing concern as power demand surges in metro Atlanta and other expanding regions. It outlines major transmission projects, such as the Heard County-Tenaska 500kV line (2025), Dresden-Talbot 500kV line (2029), and Hatch-Wadley 500kV line (2031), to bolster transfer capacity and system resilience. Meanwhile, under the 2024 Georgia Integrated Transmission System (ITS) Ten-Year Plan, the utility will continue to evaluate infrastructure needs in coordination with Georgia Transmission Corporation (GTC), Municipal Electric Authority of Georgia (MEAG Power), and Dalton Utilities to ensure a cohesive, statewide approach to grid reliability and expansion.
For now, the IRP suggests the utility is eyeing $160 million in DOE Grid Resilience and Innovation Partnerships (GRIP) funding and DOE Title 17 loans to offset costs while expanding transmission infrastructure beyond the traditional ten-year planning horizon. The measure aligns with push for long-term regional planning, it says.
Grid Reliability: New Reserve Margins
Still, echoing concerns expressed by utilities and power companies across the industry, Georgia Power’s 2025 IRP emphasizes an onslaught of reliability risks, including renewable intermittency, cold-weather gas supply constraints, prolonged peak demand periods, and increased dependence on market purchases.
The utility warns that “the significant presence of winter reliability risks” is compounded by factors such as “cold-weather-related unit outages, the penetration of solar resources, increased reliance on natural gas, and market purchase availability.” As more solar and battery storage resources are integrated into the grid, operating reserves are growing increasingly important to manage unexpected fluctuations in generation and load, it notes. The 2025 IRP notably raises the summer reserve margin from 16.25% to 20%, though its winter reserve margin remains at 26%.
—Sonal Patel is a POWER senior editor (, ).
