Georgia Power Tells the PSC to Give Its Staff's Fuel-Cost Rules 'No Weight' as the Data Center Pricing Review Nears a Hearing

“The Commission should give PIA Staff’s guidelines no weight as an authority and justification for proposed modifications to the RTP fuel credit methodology” ^[2]. That is Georgia Power’s answer, filed at the Georgia Public Service Commission on Tuesday, October 27, to its own regulator’s advocacy staff in Docket 57171 ^[2]. The docket asks a narrow accounting question with a data center at the end of it: when customers on real-time pricing pay their bills, how much of that money goes to cover fuel, and how much goes to base rates ^[1,5]?

This is a state commission proceeding, and it has a fixed clock. The commission hears Georgia Power’s rebuttal on November 12 and is scheduled to vote December 15 ^[1].

What the commission ordered, and what the company filed

The review comes out of Georgia Power’s 2026 fuel case. The May 28 order adopting that settlement, in Docket 56765, required the commission to “further review the methodology by which the Company credits Real-Time Pricing (‘RTP’) revenue to the FCR revenues,” and said the proceeding “shall be concluded by December 31, 2026” ^[1]. FCR is the fuel cost recovery rate on every customer’s bill. On July 7 the commission adopted the schedule and made its Public Interest Advocacy Staff a party, with a duty to argue the public interest ^[1]. The vote to open the probe was unanimous; a motion from Commissioner Peter Hubbard to widen it failed on the Republican majority’s votes, according to the Georgia Recorder ^[7].

Real-time pricing lets large commercial and industrial customers buy energy at hourly prices tied to Georgia Power’s marginal cost ^[4,6]. Since 2010 the company has credited the fuel account from those sales at an hourly marginal replacement fuel cost, not the average fuel rate ^[4]. On average, staff found, that credit ran about $9 per megawatt-hour below the average fuel cost each year ^[4]. Real-time sales were 20% to 21% of Georgia Power’s energy requirements from 2023 through 2025, and staff says the share is growing; the projected figures are redacted ^[4].

The October 27 rebuttal, from Georgia Power pricing director Ross Beppler, vice president Lee Evans and Southern Company Services’ Brandon Looney, holds three lines ^[2]:

• New pipeline capacity. Firm gas transportation (FT), meaning pipeline capacity reserved in advance, contracted since the start of the 2023 IRP Update and “driven primarily by large load growth” would be recovered from large-load customers in the fuel clause, allocated on winter peak demand ^[2,3].
• Existing pipeline capacity. It stays out of the credit. FT is a fixed cost and “should not be allocated to RTP customers on an energy basis” ^[2].
• Must-take power contracts. The company backs Option 1, which removes both the cost and the output of non-dispatchable purchased power, such as qualifying facilities, solar, wind and biomass, from the credit calculation ^[2,3].

Proposals that reach into cost allocation and rate design, the company says, belong in its next base rate case ^[2].

Where the money moves

Staff’s September 23 testimony puts numbers on the gap. Under the current method, real-time sales credited $1.086 billion to fuel from 2023 through 2025; under staff’s proposals the figure would have been $1.415 billion, a difference of about $329 million ^[4]. Staff says that would have wiped out a $322 million fuel under-collection and left typical bills about $1.35 a month lower ^[4]. In 2025 alone, about 9.8 million MWh of must-take generation went into the credit calculation while $486 million of its cost stayed out, staff found ^[4].

Staff projects the must-take shortfall rising from about $126 million in 2026 to about $399 million in 2031 if the method stands ^[4]. For pipeline capacity, staff wants every FT and storage dollar, existing and new, spread across all customers by monthly energy use; that change alone would have moved $93 million to fuel over 2023-2025 ^[4].

The catch is that the money does not disappear from the other side of the ledger. Revenue credited to fuel is revenue no longer offsetting base rates. Georgia Power says real-time sales contributed $264 million toward fixed costs in 2025 through what it calls capital substitution ^[3]. The Georgia Association of Manufacturers warns that a bigger fuel credit “would put upward pressure on base rates,” and that base and fuel costs fall on customer classes in different proportions ^[6]. Staff’s response is that fuel costs are entirely ratepayers’ responsibility, so the method has to be right, and that its review of 2023-2025 surveillance filings shows the company could have absorbed the shift while earning its targeted return ^[4].

Timing matters too. Georgia Power has pledged that large-load revenue will put at least $102 a year of downward pressure on the typical residential bill in 2029, 2030 and 2031 ^[3]. This docket decides how much real-time revenue lands on the fuel side of that ledger instead.

Where the sides stand

Georgia Power’s case is that the rate does what it was built to do. Real-time pricing “is by design a marginal cost-based rate that is not intended to recover all embedded costs,” the panel testified, and adopting staff’s guidelines “would set a dangerous policy precedent” ^[2]. It points out that staff used a demand allocator for FT in the fuel case five months ago and now argues for an energy allocator ^[2]. A demand allocation on new FT, the company says, protects other customers even if large-load projects fail to materialize as projected, because the split is fixed on the planning assumptions ^[2].

Staff calls the company’s proposal “only a partial solution,” because it leaves existing FT untouched ^[4]. Staff says it used the demand allocator in the fuel case only to illustrate the size of the problem ^[4]. If the commission prefers a demand method, staff says, all FT should move out of the fuel clause and into base rates ^[4].

Georgia Interfaith Power & Light and three congregations make the data center connection explicit. Their witness, John D. Wilson, testified that the fuel case was “the first fuel proceeding since the data center boom began,” and that parties had raised concerns that the method, “which has been applied to data center customers, resulted in higher fuel costs for other customers” ^[5]. Wilson agrees with the company on Option 1 but would reject the winter-peak allocation, using the transmission allocator until the next rate case, and wants intervenors given a working copy of Georgia Power’s large-load cost model ^[5].

The manufacturers argue the FT fight is mostly about something else. Customers of 100 MW and up, their witness said, also pay access charges reflecting Georgia Power’s incremental costs, so FT allocation and the real-time credit overlap only because those customers can elect real-time service ^[6]. On must-take contracts, either of the company’s two options would address the concern, the group said ^[6].

None of this record identifies which real-time customers are data centers. That is a gap for a docket the commission’s own staff opened because real-time load “is growing significantly” ^[4].

One more fact for the day. Two of the five commission seats are on today’s ballot, including Hubbard’s District 3 seat, and Bisnow has reported that data center costs figure in the candidates’ positions ^[8].

What I’m watching

November 12: the rebuttal hearing. Staff and intervenors get their first chance to cross-examine the company’s panel on the switch in allocators and on the “new FT” line drawn at the 2023 IRP Update ^[1,2].

December 15: the vote. Briefs are due December 2 and the Energy Committee takes the case up December 10 ^[1]. The question I will read the order for is whether existing pipeline capacity stays with non-real-time customers.