Georgia Power Secures 1,137 MW Solar PPAs Across Seven Counties

Georgia Power has secured Public Service Commission approval for 1,137 MW of new solar power purchase agreements, split across seven projects in seven Georgia counties, with commercial operation expected as early as 2029.

The Georgia PSC signed off on the portfolio on 10 September 2026 under the utility’s CARES 2025 request-for-proposals programme, the second annual tranche of a procurement track authorised back in the 2022 Integrated Resource Plan (IRP).

The scale matters because it clears a threshold. The 2025 IRP set an initial renewable procurement target of 1,100 MW, and this single tranche fills and slightly exceeds it. It also follows 1,068 MW approved under CARES 2023 in September 2025, establishing a cumulative procurement trajectory rather than a one-off deal.

For developers and energy investors tracking offtake opportunities in the US Southeast, this is less a clean-energy headline than a procurement signal. It tells you where utility-scale solar capital is flowing right now, how fast, and under what contractual structure. Here is what the approval establishes, where the gaps remain, and how it stacks up against comparable programmes across the region.

Seven projects, seven counties: the shape of Georgia Power’s 1,137 MW solar build-out

The portfolio is spread across rural Georgia rather than concentrated in a single mega-site. The PSC approved seven separate solar PPAs, with the two largest tranches landing in Irwin County and Sumter County at 200 MW each. The smallest, in Appling County, comes in at 78 MW.

Here is the full county-by-county breakdown.

One structural point is worth pinning down. These are power purchase agreements, not utility-owned assets. Georgia Power will buy the electricity output under long-term contract rather than own and rate-base the panels themselves.

That distributed spread across seven counties tells you something the raw capacity number does not. This is a deliberately fragmented portfolio, which means multiple interconnection queues, separate landowner agreements, and likely several development teams working in parallel, even though none has been named.

Several key details remain undisclosed:

• The names of the solar developers awarded the seven PPAs have not been publicly released.
• The total contract value of the 1,137 MW portfolio has not been announced.
• The contract tenor for the agreements has not been disclosed.

The regulatory paper trail runs through PSC Dockets 56181 and 57154, covering Georgia Power’s CARES 2023 and CARES 2025 utility-scale renewable PPAs. For anyone tracking the Southeast solar pipeline, the county specifics and the 2029 operation target are the concrete parameters that anchor everything else in this story.

How this approval fits Georgia Power’s IRP and the path to 4,000 MW by 2035

This is not a standalone transaction. It sits inside a multi-year, regulator-approved procurement architecture, and understanding that scaffolding is what separates a durable pipeline from a discretionary one.

The chain of authority runs cleanly. The 2022 IRP authorised the CARES RFP programmes; those RFPs solicited the bids; the PSC then certified the resulting PPAs. Each approval is a mandated tranche, not a fresh negotiation.

Georgia Power filed its 2025 IRP on 31 January 2025, and the PSC approved it on 15 July 2025. That plan set an initial renewable procurement target of 1,100 MW via competitive auctions, which the 1,137 MW solar approval effectively fills.

Georgia Power’s 2025 IRP filings, including the approved plan and associated PSC docket documents, set out the full renewable procurement targets, load growth projections, and capacity needs underpinning the CARES programme authorisation.

The broader ambition is larger. The 2025 IRP targets up to 4,000 MW of new renewables by 2035, expanding Georgia Power’s renewable portfolio to roughly 11,000 MW, within a total new-capacity programme spanning 6,000-8,500 MW across all resource types.

Here are the milestones worth keeping to hand:

• 2025 IRP filed: 31 January 2025; approved 15 July 2025
• Initial renewable procurement target: 1,100 MW via competitive auctions
• Total renewable target by 2035: up to 4,000 MW
• Projected renewable portfolio by 2035: approximately 11,000 MW
• 2023 IRP Update authorisation: 2,100 MW utility-scale plus 200 MW distributed generation

The read for investors is straightforward. When a single CARES tranche fills the IRP’s initial renewable milestone, procurement is moving in lockstep with regulatory planning. That lowers the execution risk that so often derails utility clean-energy targets, and it strengthens the long-term offtake signal for developers weighing where to bid next.

Data-centre demand and the load growth backdrop

The engine behind all of this is load growth. Georgia Power’s IRP projects substantial new resource needs from the late 2020s onward, driven significantly by data-centre demand as the region’s power appetite climbs.

Data-centre power demand in the US Southeast is growing faster than almost any other load category, with major hyperscale facilities requiring firm, round-the-clock supply that intermittent solar PPAs alone cannot satisfy, which is part of why Georgia Power’s IRP retains dispatchable fossil capacity alongside its renewable build-out.

But the picture is not a clean fossil-to-solar swap. Utility Dive coverage of the 2025 IRP notes that the plan keeps certain coal plants online to manage near-term reliability against that same data-centre load.

That tension matters for how you read the solar approval. These PPAs are additive to dispatchable fossil capacity in the current plan, not a full substitute for it. The renewable share of Georgia Power’s actual dispatch mix will lag the headline procurement numbers for years.

Why Georgia Power buys solar rather than builds it: the PPA model and its trade-offs

The decision to contract rather than build carries real financial logic, and reading the approval as a market mechanism, not just a capacity figure, changes what it tells you.

The core rationale is capital-structure driven. PPAs let Georgia Power and parent Southern Company add clean capacity without fully financing construction on their own balance sheet. Instead, the utility locks in long-term contracted prices from independent developers and passes those costs through under PSC oversight, rather than seeking rate-base treatment for self-built plants.

The contracted price levels hidden behind these PPAs are central to the story: solar investment returns in utility-scale offtake deals vary significantly depending on RFP design, interconnection costs, and the creditworthiness of the off-taking utility, all factors that shape developer margins in programmes like CARES.

There is a regulatory dimension too. By approving mixed portfolios that blend PPAs with utility-owned thermal, battery storage, and renewable assets, the PSC can measure third-party bids against utility self-build options and certify whichever combination is least-cost and best-fit. The PPA structure also extends beyond grid supply: Georgia Power’s commercial and industrial programme procures 2,100 MW of renewables via PPAs for C&I customer subscription.

Not everyone thinks the volumes go far enough. The Southern Renewable Energy Association (SREA) argues Georgia Power’s RFP sizing sits below the region’s economic potential and reliability needs.

The SREA recommends expanding the utility-scale renewables RFP to at least 2 GW by 2032, roughly double the planned volumes, alongside adding 2 GW of storage by 2032.

That recommendation reframes today’s approval. When even supporters of the transition call for the RFP volumes to double, the 1,137 MW reads as a meaningful but insufficient step. The debate in Georgia is about pace, not direction, and that distinction is what developers weighing the offtake market need to hold in view.

What comparable Southeast utility programmes reveal about Georgia’s solar market signal

To judge whether Georgia Power’s approval is a leading or lagging signal, it helps to set it against the regional peer group. The answer calibrates the opportunity rather than inflating it.

Dominion Energy Virginia issued a 2025 RFP for up to 1,000 MW of utility-scale solar and onshore wind PPAs. Its earlier renewable pilot programme carried an aggregate cap of just 40 MW, a useful reminder that regulatory cap size, not appetite alone, determines how deep a market actually gets.

Duke Energy Carolinas took a hybrid route. Its solar RFP targeted at least 700 MW, with roughly 385 MW on a utility-ownership track and around 315 MW via PPAs, letting regulators blend ownership and contracted procurement to spread risk.

Alabama Power proposed two 25-year energy purchase agreements for its Stockton I and II solar projects under a Certificate of Convenience and Necessity, showing PPA adoption even in a more cautious regulatory environment. Georgia’s own history runs deeper still: the REDI programme authorised up to 1,200 MW of renewables, and the PSC approved a 30-year PPA for 57.5 MW with GA Solar 3, LLC back in 2018.

Three cross-regional lessons emerge:

• PPAs are now the mainstream tool for utility-scale solar integration across the Southeast.
• Programme scale and RFP design, not technology, determine actual market depth for developers.
• Hybrid ownership-plus-PPA portfolios are becoming the emerging regulatory norm.

Add the cumulative arithmetic and the signal sharpens. Georgia Power’s two CARES cycles now total over 2.2 GW of PSC-approved solar PPAs. Set alongside Dominion’s 1 GW RFP and Duke’s hybrid 700 MW programme, that tells you the Southeast is running a genuinely competitive multi-utility solar PPA market, with Georgia Power established as its most active single buyer.

Utility-scale solar capital flows in 2026 are increasingly concentrated in regulated utility offtake markets rather than merchant or corporate PPA channels, a structural shift that makes PSC-approved programmes like CARES a more reliable signal of where development activity is heading than spot market pricing.

What the approval changes, and what remains unresolved

Strip away the framing and the approval establishes three firm facts: PSC-backed offtake for 1,137 MW of in-state solar, a 2029 commercial operation target, and a cumulative CARES pipeline now exceeding 2.2 GW across two tranches. That is a durable, regulator-anchored procurement track, not a discretionary announcement.

But the decision leaves real questions open:

• Which developers won the PPAs, and at what contracted price levels.
• Whether future CARES tranches will match or exceed this volume.
• How continued coal retention affects the renewable share of Georgia Power’s actual dispatch mix.

The arithmetic points to where the story sits. With over 2.2 GW approved against the IRP’s 4,000 MW by 2035 target, roughly 1.8 GW remains to be procured through future RFP cycles. This procurement story is near its halfway point, which makes the 2026 utility-scale renewables RFP the next material decision for anyone tracking Georgia Power’s trajectory. The SREA‘s call for at least 2 GW is the benchmark advocates will hold it against.

Solar supply chain risks are a material execution variable for the seven CARES 2025 projects, given that US utility-scale solar remains heavily dependent on imported panels and components subject to shifting trade policy and export controls.

PSC caution note: Regulators require thoroughly vetted load forecasts before authorising the upper end of Georgia Power’s 8,500 MW total new-capacity range, a reminder that procurement pace remains conditional on demand playing out as projected.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions.

Past performance does not guarantee future results. Financial projections and procurement targets are subject to regulatory decisions, market conditions, and various risk factors.