GCES Analyzed the 2025 IRP and the Georgia Power Grid
GCES used the Regional Energy Deployment System (ReEDS) model to prepare independent analysis for the 2025 IRP.
Click here to download Peter Hubbard’s expert testimony for the 2025 IRP (docket #56002, document #222485).
Upshot: The Georgia Power Company 2025 IRP is flawed and should be revised. This independent IRP-grade analysis provided below provides the receipts. It shows that fossil gas-fired power is uneconomic in an economic power model.
If Georgia Power Company had used accurate costs for new fossil gas power plants, their analysis would rarely if ever select for fossil gas. Instead, they omitted an enormous 2,900 megawatts of gas-fired combined cycle units at Plant Bowen from this 2025 IRP, and Georgia Power Company is already spending money imprudently to build these gas units before any regulatory review.
The analysis below is the result of independent, open analysis from GCES, where the inputs and outputs can be reviewed and verified. What you can see is that fossil gas-fired power is rarely selected on an economic basis or even a reliability basis, regardless of load growth forecast. This means the proposed fossil-fuel based 2025 IRP from Georgia Power Company is not in the interests of Georgia.
Below is independent analysis of new capacity and retirements on the Georgia power grid given today’s costs, as prepared by Peter Hubbard at the Georgia Center for Energy Solutions.
(1) The Base Load scenario for the power grid in Georgia shows that the system is currently overbuilt and no new capacity is required until 2032 when all coal is retired. This coal capacity is replaced in 2032 with 5 GW of 8-hour batteries and 2 GW of hydrogen combustion turbines (H2-CT) with electrolyzers to produce the hydrogen fuel. Solar PV is built throughout the forecast, wind resources are added near 2040, and more H2-CTs are added in the 2040s as well. To be clear, no new fossil gas-fired power was selected by the model because it was uneconomic and not needed for reliability. H2-CTs were selected because their capital costs were not doubled in the model as was done for fossil gas units, to reflect current market reality.
(2) The High Load scenario for the power grid in Georgia is the same as the Base Load scenario through 2032. The overbuilt system needs no new capacity until 2032 when all coal is retired. This coal capacity is replaced in 2032 with 5 GW of 8-hour batteries and 2 GW of hydrogen combustion turbines (H2-CT) with electrolyzers to produce the hydrogen fuel. With High Load, more wind power is required, which largely displaces the H2-CTs that were required in the Base Load scenario. It is only in 2042 when the system cost needs a modest amount of dispatchable power that a Gas-CC becomes economic in the model. In the High Load scenario, most new builds are batteries, solar, and wind that provide highly reliable, low-cost power for Georgia.
(3) The Base Load and Advanced Solar PV and Battery scenario for the power grid in Georgia is the same as the Base Load scenario through 2032. The overbuilt system needs no new capacity until 2032 when all coal is retired, even with a stronger cost decline curve for solar PV and batteries. When this coal capacity is replaced in 2032, there is now 4 GW of solar in 2032 together with 5 GW of 8-hour batteries and 2 GW of hydrogen combustion turbines (H2-CT). The lower cost of solar PV and batteries displaces most wind power and all but a few H2-CTs in the final years. Takeaway: solar and battery costs will continue to decline, likely more strongly than conventional wisdom holds. The batteries and solar provide highly reliable, low-cost power for Georgia.
(4) The High Load and Advanced Solar PV and Battery scenario for the power grid in Georgia remains overbuilt with no new capacity until 2032 when all coal is retired. This coal capacity is replaced in 2032 with 5 GW of solar, 5 GW of 8-hour batteries and 4 GW of hydrogen combustion turbines (H2-CT). The lower cost of solar PV and batteries together with wind power displaces most incremental H2-CT except in the final year. Even under a High Load scenario, solar power and batteries together with wind power provide highly reliable, low-cost power for Georgia. Of course, the large amount of wind power in 2040 could be spread over a number of years.
Reliability: These four portfolios are dispatched over the course of 31 days in which the system sees high-stress, and builds to ensure resource adequacy during those stressful timeslice periods. This can be seen in the High Load and Advanced Solar PV and Batteries scenario just below.
Georgia Power Company’s 2025 Integrated Resource Plan is flawed — it underestimates fossil gas costs, puts roadblocks in front of renewable energy, and will further raise power bills on the backs of residential electricity customers in Georgia.
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Georgia Power Company Exaggerates Load Growth in the 2025 IRP
This 2025 Integrated Resource Plan claims that 9,400 megawatts of load growth is expected in Georgia in 10 years. Georgia Power Company says it must build fossil gas power plants to meet this load growth. That is a provably false claim in this 2025 IRP.
First consider the load growth that Georgia Power Company claimed in the 2007 IRP, the 2010 IRP, the 2013 IRP, and the 2016 IRP—each of these IRPs forecasted much higher load through 2030 what actually happened. The Budget 2007 Total Peak forecast shown below was a key assumption used by Georgia Power Company to imprudently justify Vogtle 3&4, but was clearly wrong.
Then consider how Georgia Power Company used the 95th percentile probability for new large load customer successfully interconnecting at the requested level, a near perfect rate of customer success. And yet Microsoft, a major customer, filed a brief in the 2023 IRP Update stating that, “GPC’s 2023 IRP Update load forecasting methodology potentially over-estimates new load that will select GPC as a provider. Microsoft recommends using actual, committed loads among the large load customer class and those having made significant progress backed by resource commitments in developing load growth assumptions, particularly in the near term.” (source: Document #218199 Docket #55378)
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Residential Customers Paid 8.7 ¢/kWh for Electricity in 2007—Now They Pay 21 ¢/kWh in 2025. Meanwhile Data Centers Only Pay 5¢/kWh
Residential rates have risen dramatically since the 2007 IRP when GPC exaggerated load growth to justify Vogtle 3&4. Since that time, large load customer rates have barely risen. Residential customers are absorbing rate increases to subsidize new data centers and cryptocurrency operations. Since 2007 the Utility Consumers Counsel has been defunded to remove oversight, and hardworking Georgians have suffered massive energy bill increases as a result.
The massive inflation we’ve seen in the past several years has been due imprudent IRPs put forward by Georgia Power Company with the express intent to maximize corporate profits at the expense of all ratepayers but especially Residential Customers.
How is the 2025 IRP fundamentally flawed?
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Georgia Power Company in this 2025 IRP ignores that coal is uneconomic to dispatch and proposes to extend their life to 2038. Synapse in their November 2021 report “Georgia Power’s Uneconomic Coal Practices Cost Customers Millions” found the Company’s uneconomic coal unit commitment practices resulted in $232 million in excess costs for Customers from 2017 to 2020. Now GPC wants to
This 2025 IRP is heavily biased toward fossil fuels and fails to justify why coal units should be kept online until 2038. The proposed portfolio in the 2025 IRP fails to adequately demonstrate the economic benefits to Georgia and to Customers as required by O.C.G.A. § 46-3A-2.
By contrast, the Georgia Center for Energy Solutions modeled all coal in Georgia retiring by 2032 and found no adverse impacts on reliability and in fact a lower of cost by retiring uneconomic coal plants.
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Georgia Power Company is inflating the size of the load growth by assuming a statistically improbable level of load growth, at the 95th percentile instead of the 50th percentile. This inflates the magnitude of the capacity need and makes it appear as if the need is much larger than it is likely to be. Many of these prospective customers and their load growth are not even located in Georgia Power Company’s service territory or they are controversial cryptocurrency mining operations. The Company was unable to forecast 2 years into the future, from its 2022 IRP to this one, with a load forecast that was off by 1650%, so how can we trust their plan to take us 20 years into the future?
A key pillar of load growth outlook was the $5 Billion Rivian electric vehicle manufacturing plant just east of Atlanta. Rivian announced in March 2024 that it would pause its plans to move forward with the factory.
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Georgia Power Company waited until after the statutory deadline to file the 2025 IRP, then submitted an air permit request to the Georgia Environmental Protection Division to be able to emit the pollutants from 2,900 megawatts of new-build gas-fired combined cycle units at Plant Bowen that will take 40 years to pay off and operate continuously for long periods of time (with emissions and fuel costs). There is a legacy of massive pollution at Plant Bowen from legacy coal combustion residuals. A massive fossil gas expansion threatens to duplicate that error.
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The 2025 IRP assumes carbon capture and sequestration (CCS) will be commercially viable and that thousands of megawatts of CCS could be installed and operating on Georgia Power Company’s system by the 2030s. This is fantasy built on disinformation from the National Carbon Capture Center, an affiliate of Georgia Power Company, meant to make it seem like CCS is a viable technology. But from the Company’s own testimony in the 2023 IRP, “Although these technologies are not demonstrated nor technically feasible for implementation on simple cycle combustion turbines, the Company nonetheless included an assessment of possible cost.” and “Carbon capture costs are unreasonable for Plant Yates Units 8-10.” They are unreasonable for the Plant Bowen CCGT units as they were for the Yates CTs, leaving both power plants exposed to emissions compliance costs and at high risk of becoming stranded assets, which Georgia Power Company will ask to be put into the rate base as a regulatory asset, yet another hidden cost of gas.
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In the 2016 IRP, Georgia Power Company said, “Adding only natural gas-fired resources would result in an over-reliance on a fuel with a history of volatility and which is subject to potential future cost increases driven by regulation, changing market conditions and other factors.” Meanwhile they locked in nearly 4,700 megawatts of gas-fired capacity in the 2022 and 2023 IRPs. At the same time, Georgia Power Company has scaled back their fuel price hedging program in its Fuel Cost Recovery FCR-26 docket because Georgia Power Company passes 100% of the cost of fuel onto ratepayers. They can be cavalier about gas prices in their modeling because they bear no risk.
In 2023, Georgia Power Company came before the Georgia Public Service Commission to recover an extra $2 billion in fuel costs for fossil gas on top of their normal annual gas bill of $2 billion. Meanwhile, solar and wind are continuing their record-long streak of $0 fuel costs. By contrast, there are billions of dollars in hidden costs to gas-fired power plants that Georgia Power Company cleverly manipulates to be excluded in its IRP analysis. Georgia Power Company is asking for $2 billion in Hurricane Helene recovery costs, which is due to their fossil fuel emissions.
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The 2025 IRP fails to account for the cost today to use fossil gas as a fuel, by assuming $0 for CO2-equivalent emissions and the MG0 case as the base case. This does not reflect science or fact. Georgia Power Company’s plan to meet load growth is based on an MG0 world in which greenhouse gas emissions cost $0, which does not reflect the reality today.
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The Company’s own IRP scenario modeling shows that there is significant upside cost risk to fossil gas generation. The increasing reliance on gas, where this 2025 IRP would drive over 50% gas capacity and 50% gas generation for the Georgia power grid, this creates upward rate pressure from high gas prices and any level of carbon price, not to mention health risk. Georgia Power Company ignores this risk which is not acceptable when existing commercial technologies like solar+storage can provide all the energy, capacity, and ancillary services required, at lower cost and lower risk than gas.
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Georgia Power Company assigns a 0% capacity value to solar in the winter, which is completely inaccurate. It also assigns a 100% capacity accreditation to gas and coal thermal plants, which is also completely inaccurate. These choices biases the model toward fossil thermal generation and harm customers of Georgia Power Company. The Company limits how much solar, batteries, and wind can be built in its IRP model, which does not follow reality or logic. Instead, the Company restricts solar because it is less lucrative compared to building new fossil gas plants.
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Georgia Power Company shares resources with Alabama Power Company and Mississippi Power Company. Georgia Power tries to maximize new capital cost approvals like building new power plants because that is how they make more profit, even if it raises power bills. The system reserve margin in Georgia, a measure of backup power, is too high because the generation capacity of Georgia Power Company and Affiliates is overbuilt, beyond what is recommended in the company’s economic Target Reserve Margin. Furthermore, there are significant historical energy exports to neighboring Balancing Authorities, which is a strong signal of excess capacity, uneconomic unit commitment, or both. Overbuilt capacity is a significant cost that is not in the interests of Georgia and Customers of the Company. The result is a highly overbuilt Georgia electric grid. This observation is confirmed in the independent IRP analysis that was prepared by the Georgia Center for Energy Solutions. GCES found that no new capacity is needed until coal plants are forced to retire in 2032 due to federal regulations, at which point new solar and battery resources are needed to replace the retiring coal capacity.
What are the practical and low-cost solutions to help meet electric load growth in Georgia?
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A program like Hawaii Electric Company (HECO) and their highly successful Battery Bonus program should be the model in Georgia. Battery Bonus is simple: the utility pays an upfront cash incentive to help pay for the install (before counting the 30% tax credits) and provide bill credits for customers to add energy storage to a new or existing rooftop solar system. All customers receive an $850/kW payment for the battery plus an ongoing fee for usage, in exchange for a 10-year commitment of capacity that is discharged from the battery for 2 hours during the evening peak. The popular Battery Bonus incentive in Hawaii quickly reached the cap of 3% of total system firm capacity, demonstrating a rapid and proven solution to the acute near-term capacity shortage.
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Grid-Enhancing Technologies are technologies that are commercially available today, are low cost, and increase power grid transmission capacity by 30% or more to directly enable the existing grid to accommodate more renewable energy projects. Examples include Ambient Adjusted Rating devices that measure in real-time the power line’s temperature, current, and angle.
The Danish Transmission System Operator and other NorIic TSOs have seen great success using GETs. It allows transmission system operators to implement hourly ratings that change based on the projected ambient temperature every hour instead of just summer and winter ratings and comply with FERC Order 881 as Georgia Power Company is required to do by 2025. There is a direct impact from the IRP on the cost of the Transmission Planning Study (Docket #25981). In its response to STF-GS-1-7 “Has the Company evaluated whether the transmission upgrades identified in the Transmission Screening Analysis could be reduced, deferred, or eliminated with the deployment of grid-enhancing technologies including dynamic line ratings, topology optimization, power flow control devices, and similar solutions?” The answer was no, the Company had not.
PIA staff and intervenors asked if grid-enhancing technologies had been considered in the last IRP, and GPC demurred then as well as now. When asked if GPC is considering grid-enhancing technologies, the answer was no, they are considering reconductoring, redispatch, and rebuild but not dynamic line ratings and other grid-enhancing technologies.
GPC will not pursue this low cost, commercially available suite of technology solutions known as grid-enhancing technologies that can help to solve the near-term capacity and energy shortfall unless the Commission requires it in this proceeding.
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GPC reported that only 0.04% of its residential customers are participating in the Community Solar offering (Document #216375). This is a clear failure due to the program designed to fail and lacking regulatory oversight, whereas by contrast we have multiple examples of successful Community Solar programs flourishing across the United States. This is a failure of leadership from the regulatory authority.
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Georgia Power Company has a long history of anti-competitive behavior. In particular, GPC intentionally makes it difficult to develop cheap, clean, firm new generation resources in Georgia by obscuring and changing the calculation of system Avoided Cost, which is the cost GPC avoids by not producing for itself an equivalent amount of energy and capacity. PURPA requires electric utilities to purchase the electric energy and capacity made available by these generators at just and reasonable rates. However, independent power producers have had difficulty selling energy and capacity to GPC, whether as a PURPA qualifying facility or when trying to secure a Power Purchase Agreement.
In January 2024, a major developer of renewable capacity and energy resources filed a petition before the Commission in Docket #4822 that states, “At a time when Georgia Power acknowledges its urgent need for new generation capacity, [this developer] urges the Commission to remove unlawful barriers blocking the development of 420 MW of new, clean, affordable power generation that [this developer] stands ready to build and operate.” This developer has significant solar and storage capacity it could bring online to help meet the acute short-term capacity shortage, but for GPC standing in the way.
In the 2022 IRP, in the 2023 IRP Update, and again in the 2025 IRP, the Incremental Capacity Equivalent (ICE) Factor showed utility scale solar with a 10% winter and 35% summer capacity value (rooftop solar is 5% and 25%, respectively). Solar has non-zero capacity value at all times, yet solar received a 0% capacity credit in the GPC capacity RFP.
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Georgia Power Company acknowledges that the Thermostat DR program shows a positive Total Resource Cost based on kW demand savings, and this despite lower Avoided Costs that hurt Demand Side Management measures. The Company is artificially limiting this program to 25,000 customers or well under 1% of residential customers, when it could expand the program to 2.4 million residential customers. This is a missed opportunity and an example of a concrete action this Commission can authorize to address the acute near-term capacity shortage.
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Georgia Power Company states, “Yes, the Company could consider an agreement outside of a RFP process for the potential new or planned projects.” The Commission should require the Company to target thousands of megawatts of solar, battery, and solar+storage projects in the current RFP and future ones. The Company should also entertain proposals received outside of announced RFPs and RFIs for energy resources that a customer develops and brings to the table, including community solar. Such projects would be subject the same rigorous scrutiny for interconnection and other requirements without being burdened by Georgia Power Company’s onerous, time-intensive, and inefficient RFP and RFI solicitation process.
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The Intercompany Interchange Contract (IIC) provides for coordinated planning between the Operating Companies and for the sharing of surpluses and deficits of capacity. Georgia Power Company could rely on the reserve sharing provision of the IIC, utilizing its affiliates’ capacity surplus in Winter of 2026 to eliminate the GPC capacity deficit. In its 2023 IRP Update and beginning in Winter of 2027, GPC noted that its need with planning reserve sharing would be slightly less due to another affiliate having a small amount of capacity surplus for Winter of 2027 through Winter of 2040. This capacity is available to Georgia Power customers.
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The completely arbitrary 70/30 rule that says if Georgia Power Company doesn’t own 70% or more of the generating assets than the system will be unreliable is patently false. Any claim that PPAs are less reliable than GPC-owned assets is much less of a concern than meeting load growth with available assets. GPC argues without merit that PPAs should be limited to 30% of load because PPAs are more risky. However, many other utilities like Detroit Edison (DTE) in Michigan have PPA ownership at 50% and see no reliability concerns. Also, many PPAs are with GPC affiliates, raising concerns more about reliability with GPC affiliates and less about the contract structure of a PPA that can be rewritten to fully mitigate any perceived risk.
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Georgia Power Company can trigger an additional 10% investment tax credit by retiring coal plants and siting new solar and storage facilities in the resulting Energy Communities. By keeping these coal plants running when they are currently uneconomic and not retiring them, they are putting significant upward pressure on electricity rates. Specifically, retiring Plant Bowen would open up significant new economic development in solar and battery storage project development in those economic catchment areas.
