SO 10-Q Quarter ended Sept. 30, 2023

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The condensed quarterly financial statements of each Registrant included herein have been prepared by such Registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets at December 31, 2022 have been derived from the audited financial statements of each Registrant. In the opinion of each Registrant's management, the information regarding such Registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2023 and 2022. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each Registrant believes that the disclosures regarding such Registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy and other factors, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the overall results of operations, financial position, or cash flows of any Registrant.

Recently Adopted Accounting Standards

In March 2020 and December 2022, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting and ASU 2022-06, Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848 , respectively, providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR through December 31, 2024. See Note 1 to the financial statements under "Recently Adopted Accounting Standards" in Item 8 of the Form 10-K for additional information on the temporary guidance.

Certain provisions in PPAs at Southern Power include references to LIBOR. Contract amendments have been executed to change to a SOFR-based interest rate. Southern Power adopted and applied the practical expedients guidance to these PPAs. Additionally, the Registrants referenced LIBOR for certain debt and hedging arrangements. As of July 1, 2023, all of the debt and hedging arrangements of the Registrants have transitioned to a SOFR-based interest rate based on the terms of the agreements. There were no material impacts from the transition to SOFR and no impacts to any existing accounting conclusions. See Note (J) under "Interest Rate Derivatives" for additional information.

Goodwill and Other Intangible Assets

Goodwill at September 30, 2023 and December 31, 2022 was as follows:

			Goodwill
			(in millions)
Southern Company			$	5,161
Southern Company Gas:
Gas distribution operations			$	4,034
Gas marketing services			981
Southern Company Gas total			$	5,015

Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if goodwill impairment indicators arise.

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Other intangible assets were as follows:

			At September 30, 2023												At December 31, 2022
			Gross Carrying Amount			Accumulated Amortization			Other Intangible Assets, Net						Gross Carrying Amount			Accumulated Amortization			Other Intangible Assets, Net
			(in millions)												(in millions)
Southern Company
Subject to amortization:
Customer relationships			$	211		$	( 169 )		$	42					$	212		$	( 162 )		$	50
Trade names			63			( 50 )			13						64			( 44 )			20
PPA fair value adjustments			390			( 143 )			247						390			( 129 )			261
Other			5			( 5 )			—						5			( 5 )			—
Total subject to amortization			$	669		$	( 367 )		$	302					$	671		$	( 340 )		$	331
Not subject to amortization:
FCC licenses			75			—			75						75			—			75
Total other intangible assets			$	744		$	( 367 )		$	377					$	746		$	( 340 )		$	406
Southern Power (*)
PPA fair value adjustments			$	390		$	( 143 )		$	247					$	390		$	( 129 )		$	261
Southern Company Gas (*)
Gas marketing services
Customer relationships			$	156		$	( 143 )		$	13					$	156		$	( 139 )		$	17
Trade names			26			( 20 )			6						26			( 17 )			9
Total other intangible assets			$	182		$	( 163 )		$	19					$	182		$	( 156 )		$	26

(*) All subject to amortization.

Amortization associated with other intangible assets was as follows:

			Three Months Ended			Nine Months Ended			Three Months Ended			Nine Months Ended
			September 30, 2023						September 30, 2022
			(in millions)
Southern Company (a)			$	10		$	27		$	11		$	30
Southern Power (b)			5			14			5			15
Southern Company Gas			3			7			4			9

(a) Includes $ 5 million, $ 14 million, $ 5 million, and $ 15 million for the three and nine months ended September 30, 2023 and 2022, respectively, recorded as a reduction to operating revenues.

(b) Recorded as a reduction to operating revenues.

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Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amount shown in the condensed statements of cash flows for the applicable Registrants:

			Southern Company			Alabama Power			Georgia Power			Southern Power			Southern Company Gas
			(in millions)
At September 30, 2023
Cash and cash equivalents			$	1,676		$	621		$	173		$	236		$	397
Restricted cash (a) :
Other current assets			176			108			48			18			2
Other deferred charges and assets			38			—			35			3			—
Total cash, cash equivalents, and restricted cash (b)			$	1,890		$	729		$	256		$	257		$	399
At December 31, 2022
Cash and cash equivalents			$	1,917		$	687		$	364		$	131		$	81
Restricted cash (a) :
Other current assets			62			—			60			—			2
Other deferred charges and assets			58			—			56			3			—
Total cash, cash equivalents, and restricted cash (b)			$	2,037		$	687		$	480		$	133		$	83

(a) For Alabama Power, balance at September 30, 2023 reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2023. For Georgia Power, reflects proceeds from the issuance of solid waste disposal facility revenue bonds in 2022. For Southern Power, reflects $ 18 million at September 30, 2023 resulting from an arbitration interim award held to fund future replacement costs and $ 3 million at both September 30, 2023 and December 31, 2022 held to fund estimated construction completion costs at the Deuel Harvest wind facility. See Note (C) under "General Litigation Matters – Southern Power" for additional information. For Southern Company Gas, reflects collateral for workers' compensation, life insurance, and long-term disability insurance.

(b) Total may not add due to rounding.

Natural Gas for Sale

With the exception of Nicor Gas, Southern Company Gas records natural gas inventories on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated.

Southern Company Gas recorded no material adjustments to natural gas inventories for either period presented. Nicor Gas' inventory decrement at September 30, 2023 is expected to be restored prior to year-end.

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Storm Damage Reserves

See Note 1 to the financial statements in Item 8 of the Form 10-K under "Storm Damage and Reliability Reserves" for additional information.

Storm damage reserve activity for the traditional electric operating companies during the nine months ended September 30, 2023 was as follows:

			Southern Company (*)			Alabama Power			Georgia Power (*)			Mississippi Power
			(in millions)
Balance at December 31, 2022			$	216		$	97		$	83		$	36
Accrual			42			9			24			9
Weather-related damages			( 242 )			( 35 )			( 204 )			( 3 )
Balance at September 30, 2023			$	16		$	71		$	( 97 )		$	42

(*) See Note (B) under "Georgia Power – Storm Damage Recovery" for additional information.

Asset Retirement Obligations

See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

Following initial criticality on March 6, 2023, Georgia Power recorded AROs of approximately $ 90 million related to Plant Vogtle Unit 3. See Note (B) under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

In September 2023, Georgia Power recorded a net decrease of approximately $ 175 million to its AROs related to the CCR Rule and the related state rule resulting from changes in estimates, including lower future inflation rates and the timing of closure activities.

In June 2023, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in a decrease in Alabama Power's ARO liability of approximately $ 15 million. See "Nuclear Decommissioning" herein for additional information.

Nuclear Decommissioning

See Note 6 to the financial statements in Item 8 of the Form 10-K under "Nuclear Decommissioning" for additional information. Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on removal of the plant from service and prompt dismantlement. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

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The estimated costs of decommissioning Plant Farley based on Alabama Power's June 2023 site study are as follows:

			Plant Farley
Decommissioning periods:
Beginning year			2037
Completion year			2087
			(in millions)
Site study costs:
Radiated structures			$	1,402
Spent fuel management			513
Non-radiated structures			133
Total site study costs			$	2,048

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an estimated inflation rate of 4.5 % and an estimated trust earnings rate of 7.0 %.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power's site-specific estimates of decommissioning costs for Plant Farley are updated every five years . The next site study for Alabama Power is expected to be completed in 2028. Projections of funds are reviewed with the Alabama PSC to ensure that, over time, the deposits and earnings of the funds in the external trust will provide adequate funding to cover the site-specific costs. If necessary, Alabama Power would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.

Income Taxes

In the third quarter 2023, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Unit 3 beginning on the in-service date of July 31, 2023. PTCs are recognized as an income tax benefit based on KWH production. In addition, pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note (B) under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from certain other Vogtle Owners. The gain recognized on the purchase of the joint owner PTCs is recognized as an income tax benefit. See Note 1 to the financial statements under "Income Taxes" in Item 8 of the Form 10-K for additional information regarding accounting policies related to income taxes. See Note (B) under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4. Also see Note (G) under "Current and Deferred Income Taxes" for additional information.

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See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information relating to regulatory matters.

The recovery balances for certain retail regulatory clauses of the traditional electric operating companies and Southern Company Gas at September 30, 2023 and December 31, 2022 were as follows:

Regulatory Clause			Balance Sheet Line Item			September 30, 2023			December 31, 2022
						(in millions)
Alabama Power
Rate CNP Compliance			Other regulatory liabilities, deferred			$	3		$	—
			Other regulatory assets, current			—			47
Rate CNP PPA			Other regulatory assets, current			17			18
			Other regulatory assets, deferred			90			102
Retail Energy Cost Recovery			Other regulatory assets, current			208			102
			Other regulatory assets, deferred			80			520
Georgia Power
Fuel Cost Recovery (*)			Receivables – under recovered fuel clause revenues			$	730		$	—
			Deferred under recovered fuel clause revenues			1,279			2,056
Mississippi Power
Fuel Cost Recovery			Receivables – customer accounts, net			$	25		$	1
Ad Valorem Tax			Other regulatory assets, current			3			12
			Other regulatory assets, deferred			11			19
Southern Company Gas
Natural Gas Cost Recovery			Natural gas cost under recovery			$	—		$	108
			Natural gas cost over recovery			165			—

(*) See "Georgia Power – Fuel Cost Recovery" herein for additional information.

Alabama Power

Certificates of Convenience and Necessity

In 2020, the Alabama PSC approved a certificate of convenience and necessity authorizing Alabama Power's construction of Plant Barry Unit 8 and the recovery of estimated in-service costs of $ 652 million. At September 30, 2023, project expenditures associated with Plant Barry Unit 8 totaled approximately $ 583 million, of which $ 578 million and $ 5 million was included in CWIP and property, plant, and equipment in service, respectively. On November 1, 2023, the unit was placed in service. The ultimate outcome of this matter cannot be determined at this time.

Excess Accumulated Deferred Income Tax Accounting Order

On October 3, 2023, the Alabama PSC issued an order modifying its December 2022 order and authorizing Alabama Power to (i) flow back in 2023 approximately $ 24 million of certain federal excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017 and (ii) make available any remaining balance of excess accumulated deferred income taxes at the end of 2023 for the benefit of customers in 2024 and/or 2025. The ultimate outcome of this matter cannot be determined at this time.

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Rate CNP New Plant

On March 24, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with the acquisition of the Central Alabama Generating Station. The filing reflected an annual increase in retail revenues of $ 78 million effective with June 2023 billings. Through May 2023, Alabama Power recovered substantially all costs associated with the Central Alabama Generating Station through Rate RSE, offset by revenues from a power sales agreement. On May 24, 2023, the Central Alabama Generating Station was placed into retail service. See Note 15 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Renewable Generation Certificate

Through the issuance of a Renewable Generation Certificate (RGC), Alabama Power is authorized by the Alabama PSC to procure renewable capacity and energy and to market the related energy and environmental attributes to customers and other third parties. On April 4, 2023, the Alabama PSC approved two new solar PPAs totaling 160 MWs. Upon approval of these PPAs, Alabama Power had procured solar capacity totaling approximately 490 MWs under the RGC's original 500 -MW limit.

On June 14, 2023, the Alabama PSC issued an order approving modifications to Alabama Power's RGC. The modifications authorized Alabama Power to procure an additional 2,400 MWs of renewable capacity and energy by June 14, 2029 and to market the related energy and environmental attributes to customers and other third parties. The modifications also increased the size of allowable renewable projects from 80 MWs to 200 MWs and increased the annual approval limit from 160 MWs to 400 MWs.

Reliability Reserve Accounting Order

On July 11, 2023, the Alabama PSC issued an order authorizing Alabama Power to expand the existing authority of its reliability reserve to include certain production-related expenses that are intended to maintain reliability in between scheduled generating unit maintenance outages.

On August 18, 2023, Alabama Power notified the Alabama PSC of its intent to use a portion of its $ 166 million reliability reserve balance during 2023. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

Rate Plans

In accordance with the terms of the 2022 ARP, on October 2, 2023, Georgia Power filed the following tariff adjustments to become effective January 1, 2024 pending approval by the Georgia PSC:

• increase traditional base tariffs by approximately $ 275 million;

• decrease the Environmental Compliance Cost Recovery tariff by approximately $ 99 million;

• increase the Demand-Side Management tariffs by approximately $ 10 million; and

• increase the Municipal Franchise Fee tariffs by approximately $ 5 million.

The ultimate outcome of this matter cannot be determined at this time.

Plant Vogtle Unit 3 and Common Facilities Rate Proceeding

In compliance with a Georgia PSC order approved in November 2021, Georgia Power increased annual retail base rates by $ 318 million effective August 1, 2023 based on the in-service date of July 31, 2023 for Plant Vogtle Unit 3. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" and "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

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Plant Vogtle Units 3 and 4 Prudency Proceeding

On August 30, 2023, as provided for in the December 2017 Georgia PSC approval of the seventeenth VCM report, Georgia Power filed with the Georgia PSC an application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (Application). The Application provides the necessary support to justify the reasonableness, prudence, and recovery of $ 8.826 billion in total construction and capital costs, $ 1.07 billion in associated retail rate base items, and the operating costs related to the full operation and output of Plant Vogtle Units 3 and 4. Through the VCM process, the Georgia PSC has verified and approved all expenditures up to the revised approved construction and capital cost of $ 7.3 billion and has reviewed, but not verified and approved, all expenditures through December 31, 2022 above that amount.

Also on August 30, 2023, the staff of the Georgia PSC filed a stipulated agreement (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors. The Prudency Stipulation is intended to resolve all issues for determination by the Georgia PSC regarding the reasonableness, prudence, and cost recovery for the remaining costs not already in retail base rates, after considering many of the issues raised by the staff of the Georgia PSC and intervenors in prior VCM proceedings, including the extended construction time, required rework, scheduling of activities, and challenges with testing and productivity. If the Prudency Stipulation is approved, Georgia Power will recover $ 7.562 billion in total construction and capital costs and associated retail rate base items of $ 1.02 billion, which includes AFUDC financing costs above $ 4.418 billion (the Georgia PSC-certified amount) up to $ 7.562 billion.

The Prudency Stipulation also provides for the recovery of projected operations and maintenance expenses, depreciation expense, nuclear decommissioning accruals, and property taxes, net of projected production tax credits. After considering construction and capital costs already in retail base rates of $ 2.1 billion and $ 362 million of associated retail rate base items (approved by the Georgia PSC in November 2021), and upon achieving commercial operation of Unit 4, Georgia Power will include in retail rate base the remaining $ 5.462 billion of construction and capital costs as well as $ 656 million of associated retail rate base items.

Under the terms of the Prudency Stipulation, when the rate adjustment occurs, Georgia Power's NCCR tariff will cease to be collected and financing costs will be included in Georgia Power's general revenue requirements. Additionally, if commercial operation for Unit 4 is not achieved by March 31, 2024, Georgia Power's ROE used to determine the NCCR tariff and calculate AFUDC will be reduced to zero, which would result in an estimated negative impact to earnings of approximately $ 12 million per month until commercial operation for Unit 4 is achieved. The Prudency Stipulation also provides that as of each Unit's respective first refueling outage, if the respective Unit's performance has materially deviated from expected performance, the Georgia PSC may order Georgia Power to credit customers for operations and maintenance expenses or disallow costs associated with the repair or replacement of any system, structure, or component found to have caused the material deviation in performance if proven to be the result of imprudent engineering, construction, procurement, testing, or start-up.

If the Prudency Stipulation is approved by the Georgia PSC, annual retail base revenues will increase approximately $ 729 million and the average retail base rates will be adjusted by approximately 5 % (net of the elimination of the NCCR tariff described above) effective the first day of the month after Unit 4 achieves commercial operation.

Georgia Power expects the Georgia PSC to render a final decision on these matters on December 19, 2023. The ultimate outcome of these matters cannot be determined at this time. See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" and "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Fuel Cost Recovery

On May 16, 2023, the Georgia PSC approved a stipulation agreement between Georgia Power and the staff of the Georgia PSC to increase annual fuel billings by 54 %, or approximately $ 1.1 billion, effective June 1, 2023. The increase includes a three-year recovery period for $ 2.2 billion of Georgia Power's under recovered fuel balance at May 31, 2023. Under the approved stipulation agreement, Georgia Power is allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case, subject to a maximum 40 % cumulative change, if its

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under or over recovered fuel balance accumulated since May 31, 2023 exceeds $ 200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2026. Changes in fuel rates have no significant effect on Southern Company's or Georgia Power's net income but do impact the related operating cash flows.

Integrated Resource Plans

In August 2022, Restore Chattooga Gorge Coalition (RCG) filed a petition in the Superior Court of Fulton County, Georgia against Georgia Power and the Georgia PSC. The petition challenges Georgia Power's plan to expend $ 115 million to modernize Plant Tugalo (a hydro facility), as approved in the 2019 IRP, and seeks judicial review of the Georgia PSC's order in the 2022 IRP proceeding with respect to the denial of RCG's challenge to the modernization plan. On October 23, 2023, the court granted Georgia Power's and the Georgia PSC's motions to dismiss the RCG petition. RCG has until November 22, 2023 to file a notice of appeal.

On October 27, 2023, Georgia Power filed an updated IRP (2023 IRP Update) with the Georgia PSC, which sets forth a plan to support the recent increase in the state of Georgia's projected energy needs since the 2022 IRP. In the 2023 IRP Update, Georgia Power requested the following:

• Authority to develop, own, and operate up to 1,400 MWs from three simple cycle combustion turbines at Plant Yates.

• Approval to pursue potential acquisition of an additional ownership interest in an existing generation asset within the Southern Company system's retail electric service territory.

• Certification of an affiliate PPA with Mississippi Power for 750 MWs starting January 2024 through December 2028.

• Certification of a non-affiliate PPA for 230 MWs starting the month after conclusion of the 2023 IRP Update proceeding continuing through December 2028.

• Authority to develop, own, and operate up to 1,000 MWs of battery energy storage facilities collocated with existing and new Georgia Power-owned solar facilities.

• Approval of transmission projects necessary to support the generation resources requested in the 2023 IRP Update.

The schedule for the Georgia PSC to consider the 2023 IRP Update has not been determined. Georgia Power has requested that the Georgia PSC evaluate the 2023 IRP Update by the end of April 2024.

The ultimate outcome of these matters cannot be determined at this time.

Storm Damage Recovery

Georgia Power is recovering $ 31 million annually under the 2022 ARP for incremental operating and maintenance costs of damage from major storms to its transmission and distribution facilities. During August 2023, Hurricane Idalia caused significant damage to Georgia Power's transmission and distribution facilities. The incremental restoration costs related to this hurricane deferred in the regulatory asset for storm damage totaled approximately $ 110 million. At September 30, 2023, Georgia Power's regulatory asset balance related to storm damage was $ 97 million. The rate of storm damage cost recovery is expected to be adjusted in future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's net income but do impact the related operating cash flows.

Nuclear Construction

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4, in which Georgia Power holds a 45.7 % ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement.

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In connection with the EPC Contractor's bankruptcy filing in March 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, under which Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, and mandatory prepayment events.

Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through July 2023 and March 2024, respectively, is as follows:

			(in millions)
Base project capital cost forecast (a)(b)			$	10,736
Construction contingency estimate			17
Total project capital cost forecast (a)(b)			10,753
Net investment at September 30, 2023 (b)			( 10,495 )
Remaining estimate to complete			$	258

(a) Includes approximately $ 610 million of costs that are not shared with the other Vogtle Owners, including $ 33 million of construction monitoring costs approved for recovery by the Georgia PSC in its nineteenth VCM order, and approximately $ 567 million of incremental costs under the cost-sharing provisions of the joint ownership agreements described below. Excludes financing costs expected to be capitalized through AFUDC of approximately $ 420 million, of which $ 385 million had been accrued through September 30, 2023.

(b) Net of $ 1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $ 188 million in related customer refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $ 3.5 billion, of which $ 3.4 billion had been incurred through September 30, 2023.

Georgia Power placed Unit 3 in service on July 31, 2023. See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts for Unit 4 on a regular basis to incorporate current information available, particularly in the areas of start-up testing and related test results, engineering support, system turnovers, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly testing and system turnover activities, which are reflected in the site work plan for Unit 4.

Since March 2020, the number of active COVID-19 cases at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion, with the site experiencing peaks in the

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number of active cases in January 2021, August 2021, and January 2022. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plans. As of September 30, 2023, Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is estimated to be approximately $ 200 million and is included in the total project capital cost forecast.

During the first nine months of 2023, established construction contingency totaling $ 43 million was assigned to the base capital cost forecast for costs primarily associated with the Unit 3 schedule extension and completion of start-up and pre-operational testing, including continued need of support resources for Unit 3 testing, as well as additional craft and support resources and subcontract work for Unit 4.

Hot functional testing for Unit 4 was completed on May 1, 2023. On July 20, 2023, Southern Nuclear announced that all Unit 4 ITAACs had been submitted to the NRC, and, on July 28, 2023, the NRC published its 103(g) finding that the accepted criteria in the combined license for Unit 4 had been met, which allowed nuclear fuel to be loaded and start-up testing to begin. Fuel load for Unit 4 was completed on August 19, 2023. On October 6, 2023, Georgia Power announced that during the start-up and pre-operational testing for Plant Vogtle Unit 4, Southern Nuclear identified a motor fault in one of four reactor coolant pumps (RCPs) and has started the process to replace this RCP with an on-site spare RCP from inventory. Considering this remediation and the remaining pre-operational testing, Unit 4 is projected to be placed in service during the first quarter 2024.

With Unit 3's four RCPs operating as designed, Southern Nuclear believes that the motor fault on this single Unit 4 RCP is an isolated event. However, any findings related to the root cause of the motor fault on the single Unit 4 RCP could require engineering changes or remediation related to the other seven Unit 3 and Unit 4 RCPs. The projected schedule for Unit 4 significantly depends on the pace and success of replacing the RCP, which involves removing and re-installing commodities around the RCP. As Unit 4 completes the RCP replacement, including any associated repairs to other RCPs, and transitions further into testing, ongoing and potential future challenges include the management of contractors and vendors, subcontractor performance, the availability of materials and parts, and/or related cost escalation; the pace of remaining work package closures; the availability of craft, supervisory, and technical support resources; and the timeframe and duration of final component and pre-operational testing. New challenges also may continue to arise as Unit 4 moves further into testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). These challenges may result in further schedule delays and/or cost increases.

There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. With the receipt of the NRC's 103(g) findings for Units 3 and 4 in August 2022 and July 2023, respectively, the site is subject to the NRC's operating reactor oversight process and must meet applicable technical and operational requirements contained in its operating license. Various design and other licensing-based compliance matters may result in additional license amendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the Unit 4 project schedule that could result in increased costs.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond March 2024 for Unit 4, including the joint owner cost sharing impacts described below, is estimated to result in additional base capital costs for Georgia Power of up to $ 25 million per month, as well as the related AFUDC and any additional related construction, support resources, or testing costs. Pursuant to Georgia Power's Application and the Prudency Stipulation (as discussed under "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein), any further changes to the capital cost forecast are not expected to be recoverable through regulated rates and will be required to be charged to income. Such charges could be material.

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Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90 % of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

Amendments to the Vogtle Joint Ownership Agreements

In connection with a September 2018 vote by the Vogtle Owners to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $ 300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).

Pursuant to the Global Amendments: (i) each Vogtle Owner paid its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4, of which Georgia Power's share is $ 8.4 billion (VCM 19 Forecast Amount), plus $ 800 million; (ii) Georgia Power was responsible for 55.7 % of actual qualifying construction costs between $ 800 million and $ 1.6 billion over the VCM 19 Forecast Amount (resulting in $ 80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3 % of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power was responsible for 65.7 % of qualifying construction costs between $ 1.6 billion and $ 2.1 billion over the VCM 19 Forecast Amount (resulting in a further $ 100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3 % of such costs pro rata in accordance with their respective ownership interests. The Global Amendments provide that if the EAC was revised and exceeded the VCM 19 Forecast Amount by more than $ 2.1 billion, each of the other Vogtle Owners had a one-time option at the time the project budget cost forecast was so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100 % of such Vogtle Owner's remaining share of total construction costs in excess of the VCM 19 Forecast Amount plus $ 2.1 billion.

In addition, pursuant to the Global Amendments, the holders of at least 90 % of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events (Project Adverse Events) occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6 % of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more from the seventeenth VCM report estimated in-

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service dates of November 2021 and November 2022 for Units 3 and 4, respectively. The schedule extension announced in February 2022 triggered the requirement for a vote to continue construction and all the Vogtle Owners voted to continue construction. The filing of the Application with the Georgia PSC, which included Georgia Power's public announcement of its intention not to submit for rate recovery an amount that is greater than the first 6 % of costs during any six-month VCM reporting period, triggered the requirement for a vote to continue construction and all the Vogtle Owners voted to continue construction. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on Georgia Power's prudency application filing.

Georgia Power and the other Vogtle Owners did not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments or the extent to which COVID-19-related costs impact those provisions. The other Vogtle Owners notified Georgia Power that they believed the project capital cost forecast approved by the Vogtle Owners in February 2022 triggered the tender provisions. In June 2022 and July 2022, OPC and Dalton, respectively, notified Georgia Power of their purported exercises of their tender options. Georgia Power did not accept these purported tender exercises.

In June 2022, OPC and MEAG Power each filed a separate lawsuit against Georgia Power in the Superior Court of Fulton County, Georgia seeking a declaratory judgment that the starting dollar amount is $ 17.1 billion and that the cost-sharing and tender provisions had been triggered. The lawsuits also assert other claims, including breach of contract allegations, and seek, among other remedies, damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with MEAG Power's and OPC's interpretations of the Global Amendments. In July 2022, Georgia Power filed its answers in the lawsuits filed by MEAG Power and OPC and included counterclaims seeking a declaratory judgment that the starting dollar amount is $ 18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power's related financial obligations. In September 2022, Dalton filed complaints in each of these lawsuits.

Also in September 2022, Georgia Power and MEAG Power reached an agreement to resolve their dispute regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will reimburse a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $ 92 million based on the current project capital cost forecast; and (iii) Georgia Power will reimburse 20 % of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs. In addition, MEAG Power agreed to vote to continue construction upon occurrence of a Project Adverse Event unless the commercial operation date of either of Plant Vogtle Unit 3 or Unit 4 is not projected to occur by December 31, 2025. In October 2022, MEAG Power and Georgia Power filed a notice of settlement and voluntary dismissal of their pending litigation, including Georgia Power's counterclaim, and Dalton dismissed its related complaint.

On October 5, 2023 and October 17, 2023, Georgia Power reached agreements with OPC and Dalton, respectively, to resolve its respective dispute with each of OPC and Dalton regarding the proper interpretation of the cost-sharing and tender provisions of the joint ownership agreements relating to the Global Amendments. Under the terms of the agreements with OPC and Dalton, among other items, (i) each of OPC and Dalton retracted its exercise of the tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4, (ii) Georgia Power made payments immediately after execution of the agreements of $ 308 million and $ 17 million to OPC and Dalton, respectively, representing payment for a portion of each of OPC's and Dalton's costs of construction for Plant Vogtle Units 3 and 4 previously incurred, (iii) Georgia Power will pay a portion of each of OPC's and Dalton's further costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will be in an aggregate amount of approximately $ 105 million and $ 6 million for OPC and Dalton, respectively, based on the current project capital cost forecast, and (iv) Georgia Power will pay 66 % of each of OPC's and Dalton's costs of construction with respect to any amounts above the current project capital cost forecast, with no further adjustment for force majeure costs. On October 23, 2023, OPC, Dalton, and

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Georgia Power filed a stipulation of dismissal with prejudice of their litigation described above, including Georgia Power's counterclaims.

Georgia Power recorded pre-tax charges to income through the fourth quarter 2022 of $ 407 million ($ 304 million after tax) associated with the cost-sharing provisions of the Global Amendments, including the settlement with MEAG Power. Based on the current project capital cost forecast and the settlements with OPC and Dalton described above, Georgia Power recorded a pre-tax charge to income of approximately $ 160 million ($ 120 million after tax) in the third quarter 2023. These charges are included in the total project capital cost forecast and will not be recovered from retail customers.

The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $ 4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $ 4.418 billion. At September 30, 2023, Georgia Power had recovered approximately $ 3.0 billion of financing costs. Financing costs related to capital costs above $ 4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power is not recording AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $ 7.3 billion) and not requested for rate recovery. In December 2022, the Georgia PSC approved Georgia Power's filing to increase the NCCR tariff by $ 36 million annually, effective January 1, 2023. On November 1, 2023, Georgia Power filed a request to continue the current NCCR tariff for 2024, pending Georgia PSC approval. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on the NCCR tariff following commercial operation of Unit 4.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $ 3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the $ 0.3 billion paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $ 5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $ 5.68 billion were prudent, and (c) a revised capital cost forecast of $ 7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that a prudence proceeding on cost recovery will occur following Unit 4 fuel load, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95 % (the ROE rate setting point authorized by the Georgia PSC at that time) to 10.00 % effective January 1, 2016, (b) from 10.00 % to 8.30 %,

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effective January 1, 2020, and (c) from 8.30 % to 5.30 %, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00 % to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that effective the first month after Unit 3 reaches commercial operation, retail base rates would be adjusted to include the costs related to Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement Agreement. On July 31, 2023, Georgia Power notified the Georgia PSC that Unit 3 had reached commercial operation, and, effective August 1, 2023, Georgia Power adjusted retail base rates for Unit 3 and the common facilities shared between Units 3 and 4 (see "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information). On August 19, 2023, fuel load for Unit 4 was completed, and, on August 30, 2023, Georgia Power filed an application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (see "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information).

The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $ 300 million in 2022 and are estimated to have negative earnings impacts of approximately $ 290 million in 2023 and $ 60 million in 2024. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on impacts to the NCCR tariff if commercial operation for Unit 4 is not achieved by March 31, 2024.

In the August 2021 order approving the twenty-fourth VCM report, the Georgia PSC approved a stipulation addressing the following matters: (i) beginning with its twenty-fifth VCM report, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will request for approval costs up to the $ 7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order and (ii) Georgia Power will not seek rate recovery of the $ 0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income by Georgia Power in the second quarter 2018. In addition, the August 2021 stipulation confirmed that Georgia Power may request verification and approval of costs above $ 7.3 billion for inclusion in rate base at a later time, but no earlier than the prudence review contemplated by the seventeenth VCM order described previously. See "Plant Vogtle Units 3 and 4 Prudency Proceeding" herein for additional information on Georgia Power's request for verification and approval of costs above $ 7.3 billion for inclusion in rate base.

The Georgia PSC approved 25 VCM reports covering periods through June 30, 2021. These reports reflect total construction capital costs incurred of $ 7.9 billion (net of $ 1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $ 188 million in related customer refunds), of which the Georgia PSC has verified and approved $ 7.3 billion as described above. The Georgia PSC also has reviewed three additional VCM reports, which reflected $ 1.6 billion of additional construction capital costs incurred through December 31, 2022. Georgia Power filed its twenty-ninth VCM report with the Georgia PSC on August 30, 2023, which reflects the revised capital cost forecast as of June 30, 2023 of $ 10.6 billion and $ 390 million of construction capital costs incurred from January 1, 2023 through June 30, 2023.

The ultimate outcome of these matters cannot be determined at this time.

Mississippi Power

Performance Evaluation Plan

On June 13, 2023, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2023 indicating no change in retail rates.

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Ad Valorem Tax Adjustment

On May 2, 2023, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2 023, resulting in a $ 7 million annual decrease in revenues effective with the first billing cycle of June 2023.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable ad valorem taxes and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income but will affect operating cash flows.

Environmental Compliance Overview Plan

On April 4, 2023, the Mississip pi PSC approved Mississippi Power's annual ECO Plan filing for 2023, resulting in a $ 3 million annual increase in revenues effective with the first billing cycle of May 2023.

System Restoration Rider

On April 4, 2023 , th e Mississippi PSC approved Mississippi Power ' s annual SRR filing, which indicated no change in retail rates. Missi ssippi Power's minimum annual SRR accrual was increased from $ 8 million to $ 12 million.

Municipal and Rural Associations Tariff

On October 27, 2023, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy on July 31, 2023 related to Mississippi Power's July 2022 request for a $ 23 million increase in annual wholesale base revenues under the MRA tariff. The settlement agreement provides for a $ 16 million increase in annual wholesale base revenues, effective September 14, 2022, and a refund to customers of approximately $ 6 million primarily related to the difference between the approved rates and interim rates.

Integrated Resource Plans

In October 2023, Mississippi Power signed an affiliate PPA with Georgia Power for 750 MWs of capacity and energy starting January 2024 through December 2028. In order to fulfill this agreement and serve the interests of customers, Mississippi Power will need to delay the anticipated retirement of certain electric generating units, as identified in its 2021 IRP. Mississippi Power is expected to file its next IRP in April 2024 in accordance with the rules and orders of the Mississippi PSC.

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

Capital expenditures incurred under specific infrastructure replacement programs and capital projects during the first nine months of 2023 were as follows:

Utility			Program			Nine Months Ended September 30, 2023
						(in millions)
Nicor Gas			Investing in Illinois			$	320
Virginia Natural Gas			SAVE			56
Atlanta Gas Light			System Reinforcement Rider			84
Chattanooga Gas			Pipeline Replacement Program			7
Total						$	467

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Nicor Gas

On June 15, 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP Rider, also referred to as Investing in Illinois, program. The Illinois Commission disallowed $ 32 million of the $ 415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $ 38 million ($ 28 million after tax) associated with the disallowance of capital investments. The disallowance is reflected on the statement of income as an $ 8 million reduction to revenues and a $ 30 million increase in operating expenses. On August 3, 2023, the Illinois Commission denied a rehearing request filed by Nicor Gas. On August 24, 2023, Nicor Gas filed a notice of appeal with the Illinois Appellate Court. Nicor Gas defends these investments in infrastructure as prudently incurred. The Illinois Commission has not yet conducted its review for calendar years 2020 through 2022 or the nine months ended September 30, 2023. Any further disallowance by the Illinois Commission could be material. The ultimate outcome of these matters cannot be determined at this time.

Rate Proceedings

Atlanta Gas Light

On July 14, 2023, Atlanta Gas Light filed its annual GRAM update with the Georgia PSC. The filing requests an annual base rate increase of $ 53 million based on the projected 12-month period beginning January 1, 2024. Resolution of the GRAM filing is expected by December 31, 2023, with new rates effective January 1, 2024. The ultimate outcome of this matter cannot be determined at this time.

Virginia Natural Gas

On August 28, 2023, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' August 2022 general base rate case filing. The approved agreement provides for a $ 48 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.70 %, and an equity ratio of 49.06 %. Interim rates became effective January 1, 2023, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $ 69 million. Refunds to customers related to the difference between the approved rates effective September 1, 2023 and the interim rates will be completed later in the fourth quarter 2023.

General Litigation Matters

The Registrants are involved in various matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements.

The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.

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Southern Company and Mississippi Power

In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $ 270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2. In 2016, additional DOE grants in the amount of $ 137 million were awarded to the Kemper County energy facility. In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $ 387 million of total grants received. In 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request, which enabled Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. In connection with the DOE closeout discussions, in 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of a civil investigation related to the DOE grants. On August 4, 2023, the U.S. District Court for the Northern District of Georgia unsealed a civil action in which defendants Southern Company, SCS, and Mississippi Power are alleged to have violated certain provisions of the False Claims Act by fraudulently inducing the DOE to disburse funds pursuant to the grants. The federal government declined to intervene in the action. On October 30, 2023, the plaintiff, a former SCS employee, filed an amended complaint, again alleging certain violations of the False Claims Act. The plaintiff seeks to recover all damages incurred personally and on behalf of the government caused by the defendants' alleged violations, as well as treble damages and attorneys' fees, among other relief. The ultimate outcome of this matter cannot be determined at this time; however, an adverse outcome could have a material impact on Southern Company's and Mississippi Power's financial statements.

Alabama Power

In September 2022, Mobile Baykeeper filed a citizen suit in the U.S. District Court for the Southern District of Alabama alleging that Alabama Power's plan to close the Plant Barry ash pond utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper seeks a declaratory judgment that the RCRA and regulations governing CCR are being violated, preliminary and injunctive relief to prevent implementation of Alabama Power's closure plan and the development of a closure plan that satisfies regulations governing CCR requirements. On December 19, 2022, Alabama Power filed a motion to dismiss the case. On September 30, 2023, the magistrate judge issued a report and recommendation to deny Alabama Power's motion to dismiss, to which Alabama Power has filed objections.

On January 31, 2023, the EPA issued a Notice of Potential Violations associated with Alabama Power's plan to close the Plant Barry ash pond. Ala bama Power has affirmed to the EPA its position that it is in compliance with CCR requirements.

The ultimate outcome of these matters cannot be determined at this time but could have a material impact on Alabama Power's ARO estimates and cash flows. See Note 6 to the financial statements in Item 8 of the Form 10-K for a discussion of Alabama Power's ARO liabilities.

Georgia Power

Municipal Franchise Fees

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In 2019, the Georgia PSC issued an order that found Georgia Power has appropriately implemented the municipal franchise fee schedule. In March 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment and the plaintiffs filed a notice of appeal. In April 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. In December 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to Georgia Power and dismissed Georgia Power's cross appeal on the

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issue of class certification as moot. Also in December 2021, the plaintiffs filed a petition for writ of certiorari to the Georgia Supreme Court, which was denied on January 27, 2023. On February 6, 2023, the plaintiffs filed a motion for reconsideration with the Georgia Supreme Court, which was denied on February 16, 2023. This matter is now concluded.

Plant Scherer

In July 2020, a group of individual plaintiffs filed a complaint, which was amended in December 2022, in the Superior Court of Fulton County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer has impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. In December 2022, the Superior Court of Fulton County, Georgia granted Georgia Power's motion to transfer the case to the Superior Court of Monroe County, Georgia. On May 9, 2023, the Superior Court of Monroe County, Georgia denied Georgia Power's motion to dismiss the case for lack of subject matter jurisdiction. On July 27, 2023, the Superior Court of Monroe County, Georgia denied the remaining motions to dismiss certain claims and plaintiffs that Georgia Power filed at the outset of the case.

In October 2021, February 2022, and January 2023, a total of eight additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs sought an unspecified amount of monetary damages including punitive damages. After Georgia Power removed these cases to the U.S. District Court for the Middle District of Georgia, the plaintiffs voluntarily dismissed their complaints without prejudice in November 2022 and January 2023. On May 12, 2023, the plaintiffs in the cases originally filed in October 2021, February 2022, and January 2023 refiled their eight complaints in the Superior Court of Monroe County, Georgia. Also on May 12, 2023, a new complaint was filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries. The plaintiff seeks an unspecified amount of monetary damages, including punitive damages. On May 18, 2023, Georgia Power removed all of these cases to the U.S. District Court for the Middle District of Georgia. The plaintiffs are requesting the court remand the cases back to the Superior Court of Monroe County, Georgia.

The amount of possible loss, if any, from these matters cannot be estimated at this time.

Mississippi Power

In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper and make claims for gross negligence, reckless conduct, and intentional wrongdoing. They also allege that Mississippi Power underpaid customers by up to $ 23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the district court denied each of the plaintiffs' pending

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Southern Power

In July 2021, Southern Power and certain of its subsidiaries filed an arbitration demand with the American Arbitration Association against First Solar for defective design of actuators on trackers and inverters installed by First Solar under the engineering, procurement, and construction agreements associated with five solar projects owned by Southern Power and partners and managed by Southern Power. In February 2023, arbitration hearings concluded. In July 2023, an interim award of approximately $ 36 million was entered in favor of Southern Power and was subsequently received in September 2023. The interim award included $ 18 million representing recovery of losses associated with replacement costs, penalty payments, and lost revenues previously incurred. This recovery is reflected in Southern Power's third quarter and year-to-date 2023 statements of income as an $ 11 million reduction to other operations and maintenance expense and a $ 7 million increase in other revenues, with $ 6 million allocated through noncontrolling interests to Southern Power's partners. The remaining $ 18 million in award proceeds received in excess of the losses incurred is recognized on the balance sheet at September 30, 2023 as restricted cash and a liability to fund future replacement costs. The parties are awaiting issuance of a final award. The ultimate outcome of this matter cannot be determined at this time.

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental remediation costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $ 14 million and $ 15 million at September 30, 2023 and December 31, 2022, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Southern Company Gas' environmental remediation liability was $ 234 million and $ 256 million at September 30, 2023 and December 31, 2022, respectively, based on the estimated cost of environmental investigation and remediation associated with known former manufactured gas plant operating sites.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.

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Other Matters

Traditional Electric Operating Companies

In April 2019, Bellsouth Telecommunications d/b/a AT&T Alabama (AT&T) filed a complaint against Alabama Power with the FCC alleging that the pole rental rate AT&T is required to pay pursuant to the parties' joint use agreement is unjust and unreasonable under federal law. The complaint sought a new rate and approximately $ 87 million in refunds of alleged overpayments for the preceding six years . In August 2019, the FCC stayed the case in favor of arbitration, which AT&T has not pursued. The ultimate outcome of this matter cannot be determined at this time, but an adverse outcome could have a material impact on the financial statements of Southern Company and Alabama Power. Georgia Power and Mississippi Power have joint use agreements with other AT&T affiliates.

Mississippi Power

In August 2022, the Mississippi Department of Revenue (Mississippi DOR) completed an audit of sales and use taxes paid by Mississippi Power from 2016 to 2019 and entered a final assessment, indicating a total amount due of $ 28 million, including associated penalties and interest. In October 2022, Mississippi Power filed an administrative appeal with the Mississippi DOR contesting the assessment. On October 2, 2023, Mississippi Power and the Mississippi DOR reached a settlement agreement on an assessment of approximately $ 11 million including associated penalties and interest, $ 7 million of which was previously paid by Mississippi Power. On October 5, 2023, Mississippi Power made a final $ 4 million payment and considers this matter closed.

Pursuant to an accounting order approved by the Mississippi PSC in December 2022, Mississippi Power deferred $ 3 million of the agreed upon assessment related to taxes and associated interest to a regulatory asset for disposition in a future rate proceeding.

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Revenue from Contracts with Customers

The Registrants generate revenues from a variety of sources, some of which are not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Revenues" in Item 8 of the Form 10-K for additional information on the revenue policies of the Registrants. See "Lease Income" herein and Note (J) for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.

The following table disaggregates revenue from contracts with customers for the three and nine months ended September 30, 2023 and 2022:

			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
Three Months Ended September 30, 2023
Operating revenues
Retail electric revenues
Residential			$	2,543		$	969		$	1,473		$	101		$	—		$	—
Commercial			1,845			599			1,151			95			—			—
Industrial			1,116			498			528			90			—			—
Other			30			3			25			2			—			—
Total retail electric revenues			5,534			2,069			3,177			288			—			—
Natural gas distribution revenues
Residential			217			—			—			—			—			217
Commercial			56			—			—			—			—			56
Transportation			275			—			—			—			—			275
Industrial			4			—			—			—			—			4
Other			60			—			—			—			—			60
Total natural gas distribution revenues			612			—			—			—			—			612
Wholesale electric revenues
PPA energy revenues			317			66			31			2			226			—
PPA capacity revenues			151			26			13			3			110			—
Non-PPA revenues			101			15			21			137			126			—
Total wholesale electric revenues			569			107			65			142			462			—
Other natural gas revenues
Gas marketing services			54			—			—			—			—			54
Other natural gas revenues			8			—			—			—			—			8
Total natural gas revenues			62			—			—			—			—			62
Other revenues			330			54			146			10			18			—
Total revenue from contracts with customers			7,107			2,230			3,388			440			480			674
Other revenue sources (*)			( 127 )			( 147 )			( 151 )			( 4 )			173			15
Total operating revenues			$	6,980		$	2,083		$	3,237		$	436		$	653		$	689

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			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
Nine Months Ended September 30, 2022
Operating revenues
Retail electric revenues
Residential			$	5,282		$	2,049		$	2,995		$	238		$	—		$	—
Commercial			4,202			1,285			2,688			229			—			—
Industrial			2,914			1,143			1,529			242			—			—
Other			79			10			62			7			—			—
Total retail electric revenues			12,477			4,487			7,274			716			—			—
Natural gas distribution revenues
Residential			1,821			—			—			—			—			1,821
Commercial			493			—			—			—			—			493
Transportation			872			—			—			—			—			872
Industrial			60			—			—			—			—			60
Other			244			—			—			—			—			244
Total natural gas distribution revenues			3,490			—			—			—			—			3,490
Wholesale electric revenues
PPA energy revenues			1,739			354			112			11			1,285			—
PPA capacity revenues			443			135			35			4			273			—
Non-PPA revenues			182			166			19			511			572			—
Total wholesale electric revenues			2,364			655			166			526			2,130			—
Other natural gas revenues
Gas marketing services			417			—			—			—			—			417
Other natural gas revenues			41			—			—			—			—			41
Total natural gas revenues			458			—			—			—			—			458
Other revenues			810			173			327			34			27			—
Total revenue from contracts with customers			19,599			5,315			7,767			1,276			2,157			3,948
Other revenue sources (*)			2,633			708			1,451			3			461			50
Total operating revenues			$	22,232		$	6,023		$	9,218		$	1,279		$	2,618		$	3,998

(*) Other revenue sources relate to revenues from customers accounted for as derivatives and leases, alternative revenue programs at Southern Company Gas, and cost recovery mechanisms and revenues (including those related to fuel costs) that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.

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Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at September 30, 2023 and December 31, 2022:

			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
Accounts Receivable
At September 30, 2023			$	2,680		$	858		$	1,175		$	106		$	138		$	331
At December 31, 2022			3,123			696			922			92			237			1,107
Contract Assets
At September 30, 2023			$	267		$	6		$	146		$	—		$	—		$	41
At December 31, 2022			156			2			89			—			—			—
Contract Liabilities
At September 30, 2023			$	62		$	—		$	8		$	2		$	8		$	—
At December 31, 2022			45			4			9			—			1			—

Contract assets for Georgia Power primarily relate to retail customer fixed bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, and unregulated service agreements, where payment is contingent on project completion. Contract liabilities for Georgia Power primarily relate to cash collections recognized in advance of revenue for unregulated service agreements. At September 30, 2023, Southern Company Gas' contract assets relate to work performed on an energy efficiency enhancement and upgrade contract with the U.S. General Services Administration. Southern Company Gas receives cash advances from a third-party financial institution to fund work performed, of which approximately $ 51 million had been received at September 30, 2023. These advances have been accounted for as long-term debt on the balance sheets. See Note 1 to the financial statements under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information regarding the construction contract. At September 30, 2023 and December 31, 2022, Southern Company's unregulated distributed generation business had contract assets of $ 75 million and $ 65 million, respectively, and contract liabilities of $ 47 million and $ 32 million, respectively, for outstanding performance obligations.

Revenues recognized in the three and nine months ended September 30, 2023, which were included in contract liabilities at December 31, 2022, were immaterial for the applicable Registrants. Contract liabilities are primarily classified as current on the balance sheets as the corresponding revenues are generally expected to be recognized within one year.

Remaining Performance Obligations

The Subsidiary Registrants may enter into long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. For Alabama Power, Georgia Power, and Southern Power, these contracts primarily relate to PPAs whereby electricity and generation capacity are provided to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. For Southern Company Gas, these contracts primarily relate to the U.S. General Services Administration contract described above. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain

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fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at September 30, 2023 are expected to be recognized as follows:

			2023 (remaining)			2024			2025			2026			2027			Thereafter
			(in millions)
Southern Company			$	166		$	599		$	359		$	318		$	319		$	2,245
Alabama Power			10			24			8			—			—			—
Georgia Power			23			66			34			14			14			23
Southern Power			84			356			302			303			310			2,233
Southern Company Gas			4			29			—			—			—			—

Lease Income

Lease income for the three and nine months ended September 30, 2023 and 2022 is as follows:

			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
For the Three Months Ended September 30, 2023
Lease income - interest income on sales-type leases			$	6		$	—		$	—		$	4		$	2		$	—
Lease income - operating leases			36			3			7			—			21			9
Variable lease income			134			—			—			—			144			—
Total lease income			$	176		$	3		$	7		$	4		$	167		$	9
For the Nine Months Ended September 30, 2023
Lease income - interest income on sales-type leases			$	18		$	—		$	—		$	11		$	7		$	—
Lease income - operating leases			129			32			22			2			64			27
Variable lease income			327			1			—			—			351			—
Total lease income			$	474		$	33		$	22		$	13		$	422		$	27
For the Three Months Ended September 30, 2022
Lease income - interest income on sales-type leases			$	7		$	—		$	—		$	4		$	3		$	—
Lease income - operating leases			50			19			8			1			21			9
Variable lease income			139			—			—			—			145			—
Total lease income			$	196		$	19		$	8		$	5		$	169		$	9
For the Nine Months Ended September 30, 2022
Lease income - interest income on sales-type leases			$	19		$	—		$	—		$	11		$	8		$	—
Lease income - operating leases			149			58			24			1			64			27
Variable lease income			355			1			—			—			372			—
Total lease income			$	523		$	59		$	24		$	12		$	444		$	27

Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Lease income for Alabama Power and Southern Power is included in wholesale revenues.

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Southern Company

At September 30, 2023 and December 31, 2022, Southern Holdings had equity method investments totaling $ 126 million and $ 112 million, respectively, primarily related to investments in venture capital funds focused on energy and utility investments. Earnings from these investments were immaterial for all periods presented.

Southern Power

Variable Interest Entities

Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.

SP Solar and SP Wind

At September 30, 2023 and December 31, 2022, SP Solar had total assets of $ 5.8 billion and $ 5.9 billion, respectively, total liabilities of $ 0.4 billion, and noncontrolling interests of $ 1.1 billion. Cash distributions from SP Solar are allocated 67 % to Southern Power and 33 % to the limited partner in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.

At September 30, 2023 and December 31, 2022, SP Wind had total assets of $ 2.2 billion, total liabilities of $ 184 million and $ 169 million, respectively, and noncontrolling interests of $ 38 million and $ 39 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60 % to Southern Power and 40 % to the three financial investors in accordance with the limited liability agreement.

Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

Other Variable Interest Entities

Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights.

At September 30, 2023 and December 31, 2022, the other VIEs had total assets of $ 1.7 billion and $ 1.8 billion, respectively, total liabilities of $ 0.2 billion, and noncontrolling interests of $ 0.8 billion. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.

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Equity Method Investments

At December 31, 2022, Southern Power had equity method investments in wind and battery energy storage projects totaling $ 49 million. During the first quarter 2023, Southern Power sold its remaining equity method investments in the projects and received proceeds of $ 50 million. Earnings (loss) from these investments, including the gains associated with the sales, were immaterial for all periods presented.

Southern Company Gas

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments at September 30, 2023 and December 31, 2022 and related earnings from those investments for the three and nine months ended September 30, 2023 and 2022 were as follows:

Investment Balance			September 30, 2023			December 31, 2022
			(in millions)
SNG			$	1,210		$	1,243
Other			33			33
Total			$	1,243		$	1,276

			Three Months Ended September 30,									Nine Months Ended September 30,
Earnings from Equity Method Investments			2023			2022						2023			2022
			(in millions)
SNG			$	32		$	34					$	104		$	104
Other			—			—						—			1
Total			$	32		$	34					$	104		$	105

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Bank Credit Arrangements

See Note 8 to the financial statements under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information.

At September 30, 2023, committed credit arrangements with banks were as follows:

						Expires
Company						2024			2025			2026			2028						Total						Unused																								Expires within One Year
						(in millions)
Southern Company parent (a)						$	150		$	—		$	—		$	1,850					$	2,000					$	1,998																							$	150
Alabama Power						—			—			650			700						1,350						1,350																								—
Georgia Power						—			—			—			1,750						1,750						1,726																								—
Mississippi Power						—			125			150			—						275						275																								—
Southern Power (a)(b)						—			—			—			600						600						589																								—
Southern Company Gas (c)						100			—			—			1,500						1,600						1,598																								100
SEGCO						30			—			—			—						30						30																								30
Southern Company						$	280		$	125		$	800		$	6,400					$	7,605					$	7,566																							$	280

(a) Arrangement expiring in 2028 represents a $ 2.45 billion combined arrangement for Southern Company and Southern Power as borrowers. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted.

(b) Does not include Southern Power Company's $ 75 million and $ 100 million continuing letter of credit facilities for standby letters of credit, expiring in 2025 and 2026, respectively, of which $ 9 million and $ 16 million, respectively, was unused at September 30, 2023. In March 2023, Southern Power amended the $ 100 million letter of credit facility, which, among other things, extended the expiration date from 2025 to 2026 and increased the amount from $ 75 million. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $ 800 million of the credit arrangement expiring in 2028. Southern Company Gas' committed credit arrangement expiring in 2028 also includes $ 700 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to the multi-year credit arrangement expiring in 2028, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. Nicor Gas is also the borrower under a $ 100 million credit arrangement expiring in 2024.

As reflected in the table above, in May 2023, Southern Company and Southern Power combined and extended their multi-year credit arrangements previously maturing in 2026, resulting in a single aggregate $ 2.45 billion facility (currently allocated $ 1.85 billion for Southern Company and $ 600 million for Southern Power) maturing in 2028. Pursuant to the combined facility, the allocations between Southern Company and Southern Power may be adjusted. Alabama Power, Georgia Power, and Southern Company Gas Capital, along with Nicor Gas, amended and restated certain of their multi-year credit arrangements, which, among other things, extended the maturity dates from 2026 to 2028. Mississippi Power amended and restated certain of its multi-year credit arrangements aggregating $ 150 million, which, among other things, extended the maturity dates from 2024 to 2026. Nicor Gas also entered into a $ 100 million credit arrangement maturing in 2024 to replace its $ 250 million credit arrangement that expired in 2023. In June 2023, Southern Company also entered into a new $ 150 million credit arrangement maturing in 2024. In August 2023, Alabama Power amended and restated one of its multi-year credit arrangements, which, among other things, extended the maturity date from 2024 to 2026 and increased the borrowing capacity from $ 550 million to $ 650 million.

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Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

These bank credit arrangements, as well as the term loan arrangements of the Registrants, Nicor Gas, and SEGCO, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. The cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At September 30, 2023, the Registrants, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

A portion of the unused credit with banks is allocated to provide liquidity support to certain revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. At September 30, 2023, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $ 1.7 billion (comprised of approximately $ 818 million at Alabama Power, $ 819 million at Georgia Power, and $ 69 million at Mississippi Power). In addition, at September 30, 2023, Alabama Power and Georgia Power had approximately $ 120 million and $ 325 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. The variable rate demand revenue bonds and fixed rate revenue bonds required to be remarketed within the next 12 months are classified as long-term debt on the balance sheets as a result of available long-term committed credit.

Convertible Senior Notes

In February 2023, Southern Company issued $ 1.5 billion aggregate principal amount of Series 2023A 3.875 % Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes). In March 2023, Southern Company issued an additional $ 225 million aggregate principal amount of the Series 2023A Convertible Senior Notes upon the exercise by the initial purchasers of their over-allotment option.

Interest on the Series 2023A Convertible Senior Notes is payable semiannually, which began on June 15, 2023. The Series 2023A Convertible Senior Notes will mature on December 15, 2025, unless earlier converted or repurchased, but are not redeemable at the option of Southern Company. The Series 2023A Convertible Senior Notes are direct, unsecured, and unsubordinated obligations of Southern Company, ranking equally with all of Southern Company's other unsecured and unsubordinated indebtedness from time to time outstanding, and are effectively subordinated to all secured indebtedness of Southern Company.

Holders may convert their Series 2023A Convertible Senior Notes at their option prior to the close of business on the business day preceding September 15, 2025, but only under the following circumstances:

• during any calendar quarter (and only during such calendar quarter), if the last reported sale price of Southern Company's common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130 % of the conversion price on each applicable trading day as determined by Southern Company;

• during the five business day period after any 10 consecutive trading day period (Measurement Period) in which the trading price per $1,000 principal amount of Series 2023A Convertible Senior Notes for each trading day of the Measurement Period was less than 98 % of the product of the last reported sale price of the common stock and the conversion rate on each such trading day; or

• upon the occurrence of certain corporate events specified in the indenture governing the Series 2023A Convertible Senior Notes.

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On or after September 15, 2025, a holder may convert all or any portion of its Series 2023A Convertible Senior Notes at any time prior to the close of business on the second scheduled trading day immediately preceding the maturity date regardless of the foregoing conditions.

Southern Company will settle conversions of the Series 2023A Convertible Senior Notes by paying cash up to the aggregate principal amount of the Series 2023A Convertible Senior Notes to be converted and paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at Southern Company's election, in respect of the remainder, if any, of Southern Company's conversion obligation in excess of the aggregate principal amount of the Series 2023A Convertible Senior Notes being converted. The Series 2023A Convertible Senior Notes are initially convertible at a rate of 11.8818 shares of common stock per $1,000 principal amount converted, which is approximately equal to $ 84.16 per share of common stock. The conversion rate will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), Southern Company will, in certain circumstances, increase the conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

Upon the occurrence of a fundamental change (as defined in the indenture governing the Series 2023A Convertible Senior Notes), holders of the Series 2023A Convertible Senior Notes may require Southern Company to purchase all or a portion of their Series 2023A Convertible Senior Notes, in principal amounts equal to $1,000 or an integral multiple thereof, for cash at a price equal to 100 % of the principal amount of the Series 2023A Convertible Senior Notes to be purchased plus any accrued and unpaid interest.

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share (EPS) is attributable to awards outstanding under stock-based compensation plans and the Series 2023A Convertible Senior Notes. EPS dilution resulting from stock-based compensation plans is determined using the treasury stock method and EPS dilution resulting from the Series 2023A Convertible Senior Notes is determined using the net share settlement method. See Note 12 to the financial statements in Item 8 of the Form 10-K and "Convertible Senior Notes" herein for additional information. Shares used to compute diluted EPS were as follows:

			Three Months Ended September 30,						Nine Months Ended September 30,
			2023			2022			2023			2022
			(in millions)
As reported shares			1,092			1,082			1,092			1,070
Effect of stock-based compensation			7			6			6			6
Diluted shares			1,099			1,088			1,098			1,076

For all periods presented, an immaterial number of stock-based compensation awards was excluded from the diluted EPS calculation because the awards were anti-dilutive.

For all periods presented, there was no dilution resulting from the Series 2023A Convertible Senior Notes.

Southern Company Leveraged Lease

See Note 9 to the financial statements in Item 8 of the Form 10-K for information on a leveraged lease agreement related to energy generation. In June 2022, the Southern Holdings subsidiary operating the generating plant for the lessee provided notice to the lessee to terminate the related operating and maintenance agreement effective June 30, 2023. Subsequently, the lessee failed to make the semi-annual lease payment due in December 2022. As a result, the Southern Holdings subsidiary was unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. The parties to the lease entered into forbearance agreements which suspended the related contractual rights of the parties while they continued restructuring negotiations, during which

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See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit and Net Operating Loss Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $ 1.0 billion and $ 1.1 billion at September 30, 2023 and December 31, 2022, respectively.

Southern Company's federal PTC and ITC carryforwards begin expiring in 2031, but are expected to be fully utilized by 2028. The utilization of each Registrant's estimated tax credit and state net operating loss carryforwards and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable projects, changes in taxable income projections, transfer of eligible credits, and potential income tax rate changes. In the third quarter 2023, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Unit 3 beginning on the in-service date of July 31, 2023. In addition, pursuant to the Global Amendments to the Vogtle Joint Ownership Agreements (as defined in Note (B) under "Georgia Power – Nuclear Construction – Joint Owner Contracts"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 from certain other Vogtle Owners. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Effective Tax Rate

Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power.

Details of significant changes in the effective tax rate for the applicable Registrants are provided herein.

Southern Company

Southern Company's effective tax rate was 13.9 % for the nine months ended September 30, 2023 compared to 20.0 % for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes at Alabama Power in 2023, lower pre-tax earnings in 2023, and an adjustment related to state tax credit carryforwards and the related valuation allowance at Georgia Power in 2022 and 2023, partially offset by the flowback of certain excess deferred income taxes ending in 2022 at Georgia Power.

Alabama Power

Alabama Power's effective tax rate was 8.3 % for the nine months ended September 30, 2023 compared to 23.7 % for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" in Item 8 of the Form 10-K for additional information.

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Georgia Power

Georgia Power's effective tax rate was 18.2 % for the nine months ended September 30, 2023 compared to 18.5 % for the corresponding period in 2022. The effective tax rate decrease was primarily due to an adjustment related to state tax credit carryforwards in 2022, a decrease in a valuation allowance on certain state tax credit carryforwards in 2023, and lower pre-tax earnings in 2023, largely offset by the flowback of certain excess deferred income taxes ending in 2022.

Mississippi Power

Mississippi Power's effective tax rate was 16.9 % for the nine months ended September 30, 2023 compared to 20.1 % for the corresponding period in 2022. The effective tax rate decrease was primarily due to an increase in the flowback of certain excess deferred income taxes in 2023.

Southern Power

Southern Power's effective tax rate was 14.8 % for the nine months ended September 30, 2023 compared to 18.8 % for the corresponding period in 2022. The effective tax rate decrease was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by the State of Tennessee in May 2023.

Unrecognized Tax Benefits

Southern Company's and Georgia Power's unrecognized tax positions balances at September 30, 2023 were $ 167 million and $ 86 million, respectively, compared to $ 80 million for Southern Company at December 31, 2022. The increases from prior periods are primarily related to the amendment of certain 2019 through 2021 state tax filing positions related to tax credit utilization. If effective settlement of the positions is favorable, these positions would decrease Southern Company's and Georgia Power's effective tax rates. The ultimate outcome of this unrecognized tax benefit, of which a portion is expected to be resolved within the next 12 months, is dependent on acceptance by the state or expiration of related statute of limitations.

Subsequent to September 30, 2023, a statute of limitations expired related to a 2019 state tax filing position to exclude certain gains from 2019 dispositions from taxation in a certain unitary state. This $ 44 million tax position and related interest will be recognized in the fourth quarter 2023 and will decrease Southern Company's annual effective tax rate.

The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2023. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.

On each Registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and nine months ended September 30, 2023 and 2022 are presented in the following tables.

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At September 30, 2023, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

			Fair Value Measurements Using:
At September 30, 2023			Quoted Prices in Active Markets for Identical Assets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs (Level 3)						Net Asset Value as a Practical Expedient (NAV)						Total
			(in millions)
Southern Company
Assets:
Energy-related derivatives (a)			$	7					$	73					$	—					$	—					$	80
Investments in trusts: (b)
Domestic equity			692						196						—						—						888
Foreign equity			131						154						—						—						285
U.S. Treasury and government agency securities			—						337						—						—						337
Municipal bonds			—						42						—						—						42
Pooled funds – fixed income			—						6						—						—						6
Corporate bonds			—						368						—						—						368
Mortgage and asset backed securities			—						85						—						—						85
Private equity			—						—						—						169						169
Cash and cash equivalents			3						—						—						—						3
Other			33						3						—						8						44
Cash equivalents and restricted cash			919						11						—						—						930
Other investments			9						34						8						—						51
Total			$	1,794					$	1,309					$	8					$	177					$	3,288
Liabilities:
Energy-related derivatives (a)			$	34					$	217					$	—					$	—					$	251
Interest rate derivatives			—						351						—						—						351
Foreign currency derivatives			—						192						—						—						192
Contingent consideration			5						—						19						—						24
Other			—						13						—						—						13
Total			$	39					$	773					$	19					$	—					$	831

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			Fair Value Measurements Using:
At September 30, 2023			Quoted Prices in Active Markets for Identical Assets (Level 1)						Significant Other Observable Inputs (Level 2)						Significant Unobservable Inputs (Level 3)						Net Asset Value as a Practical Expedient (NAV)						Total
			(in millions)
Mississippi Power
Assets:
Energy-related derivatives			$	—					$	24					$	—					$	—					$	24
Cash equivalents			3						—						—						—						3
Total			$	3					$	24					$	—					$	—					$	27
Liabilities:
Energy-related derivatives			$	—					$	44					$	—					$	—					$	44
Southern Power
Assets:
Energy-related derivatives			$	—					$	5					$	—					$	—					$	5
Cash equivalents			23						—						—						—						23
Total			$	23					$	5					$	—					$	—					$	28
Liabilities:
Energy-related derivatives			$	—					$	6					$	—					$	—					$	6
Foreign currency derivatives			—						42						—						—						42
Contingent consideration			5						—						19						—						24
Other			—						13						—						—						13
Total			$	5					$	61					$	19					$	—					$	85
Southern Company Gas
Assets:
Energy-related derivatives (a)			$	7					$	4					$	—					$	—					$	11
Non-qualified deferred compensation trusts:
Domestic equity			—						7						—						—						7
Foreign equity			—						1						—						—						1
Pooled funds – fixed income			—						6						—						—						6
Cash equivalents			3						—						—						—						3
Cash equivalents			294						—						—						—						294
Total			$	304					$	18					$	—					$	—					$	322
Liabilities:
Energy-related derivatives (a)			$	34					$	9					$	—					$	—					$	43
Interest rate derivatives			—						99						—						—						99
Total			$	34					$	108					$	—					$	—					$	142

(a) Excludes cash collateral of $ 49 million.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

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Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and nine months ended September 30, 2023 and 2022. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

			Three Months Ended						Nine Months Ended
Fair value increases (decreases)			September 30, 2023			September 30, 2022			September 30, 2023			September 30, 2022
			(in millions)
Southern Company			$	( 4 )		$	( 106 )		$	211		$	( 486 )
Alabama Power			( 36 )			( 53 )			54			( 245 )
Georgia Power			32			( 53 )			157			( 241 )

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (J) for additional information on how these derivatives are used.

For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

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Southern Power has contingent payment obligations related to two of its acquisitions whereby it is primarily obligated to make generation-based payments to the seller, commencing at the commercial operation of each facility and continuing through 2026 and 2035, respectively. The obligations are primarily categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility's generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

Southern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.

"Other investments" primarily includes investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.

At September 30, 2023, the fair value measurements of private market investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $ 177 million and unfunded commitments related to the private market investments totaled $ 72 million. Private market investments include high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a private credit fund. Private market funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.

At September 30, 2023, other financial instruments for which the carrying amount did not equal fair value were as follows:

			Southern Company (*)			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas (*)
			(in billions)
Long-term debt, including securities due within one year:
Carrying amount			$	58.8		$	11.2		$	15.8		$	1.6		$	2.7		$	8.1
Fair value			50.8			9.4			13.4			1.3			2.4			6.5

(*) The carrying amount of Southern Company Gas' long-term debt includes fair value adjustments from the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the remaining lives of the respective bonds, the latest being through 2043.

The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.

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to correspond with the classification of the hedged interest or principal, respectively. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

The Subsidiary Registrants enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

Energy-related derivative contracts are accounted for under one of three methods:

• Regulatory Hedges – Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through an approved cost recovery mechanism.

• Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in accumulated OCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.

• Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

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At September 30, 2023, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

			Net Purchased mmBtu						Longest Hedge Date						Longest Non-Hedge Date
			(in millions)
Southern Company (*)			422						2030						2028
Alabama Power			109						2026						—
Georgia Power			104						2026						—
Mississippi Power			80						2027						—
Southern Power			8						2030						2024
Southern Company Gas (*)			121						2027						2028

(*) Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of 135.5 million mmBtu long natural gas positions and 14.2 million mmBtu short natural gas positions at September 30, 2023, which is also included in Southern Company's total volume.

In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 14 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 2 million mmBtu for Mississippi Power, and 3 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2024 are $ 30 million for Southern Company, $ 25 million for Southern Company Gas, and immaterial for Southern Power.

Interest Rate Derivatives

Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

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At September 30, 2023, the following interest rate derivatives were outstanding:

			Notional Amount						Weighted Average Interest Rate Paid			Interest Rate Received			Hedge Maturity Date			Fair Value Gain (Loss) at September 30, 2023
			(in millions)															(in millions)
Fair Value Hedges of Existing Debt
Southern Company parent			$	400					1-month SOFR + 0.80 %			1.75 %			March 2028			$	( 56 )
Southern Company parent			1,000						1-month SOFR + 2.48 %			3.70 %			April 2030			( 196 )
Southern Company Gas			500						1-month SOFR + 0.49 %			1.75 %			January 2031			( 99 )
Southern Company			$	1,900														$	( 351 )

For cash flow hedges of interest rate derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending September 30, 2024 are $ 19 million for Southern Company and immaterial for the traditional electric operating companies and Southern Company Gas. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2052 for Southern Company, Alabama Power, and Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.

At September 30, 2023, the following foreign currency derivatives were outstanding:

			Pay Notional			Pay Rate			Receive Notional			Receive Rate			Hedge Maturity Date			Fair Value Gain (Loss) at September 30, 2023
			(in millions)						(in millions)									(in millions)
Cash Flow Hedges of Existing Debt
Southern Power			$	564		3.78 %			€	500		1.85 %			June 2026			$	( 42 )
Fair Value Hedges of Existing Debt
Southern Company parent			1,476			3.39 %			1,250			1.88 %			September 2027			( 150 )
Southern Company			$	2,040					€	1,750								$	( 192 )

For cash flow hedges of foreign currency derivatives, the estimated pre-tax losses expected to be reclassified from accumulated OCI to earnings for the 12-month period ending September 30, 2024 are $ 10 million for Southern Power.

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Derivative Financial Statement Presentation and Amounts

The Registrants enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

			At September 30, 2023						At December 31, 2022
Derivative Category and Balance Sheet Location			Assets			Liabilities			Assets			Liabilities
			(in millions)						(in millions)
Southern Company
Energy-related derivatives designated as hedging instruments for regulatory purposes
Assets from risk management activities/Liabilities from risk management activities			$	34		$	134		$	123		$	121
Other deferred charges and assets/Other deferred credits and liabilities			36			77			52			44
Total derivatives designated as hedging instruments for regulatory purposes			70			211			175			165
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities			—			28			3			27
Other deferred charges and assets/Other deferred credits and liabilities			4			2			6			4
Interest rate derivatives:
Assets from risk management activities/Liabilities from risk management activities			—			80			12			62
Other deferred charges and assets/Other deferred credits and liabilities			—			271			—			240
Foreign currency derivatives:
Assets from risk management activities/Liabilities from risk management activities			—			35			—			34
Other deferred charges and assets/Other deferred credits and liabilities			—			157			—			182
Total derivatives designated as hedging instruments in cash flow and fair value hedges			4			573			21			549
Energy-related derivatives not designated as hedging instruments
Assets from risk management activities/Liabilities from risk management activities			5			8			13			13
Other deferred charges and assets/Other deferred credits and liabilities			1			2			2			1
Total derivatives not designated as hedging instruments			6			10			15			14
Gross amounts recognized			80			794			211			728
Gross amounts offset (a)			( 37 )			( 86 )			( 70 )			( 111 )
Net amounts recognized in the Balance Sheets (b)			$	43		$	708		$	141		$	617

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(a) Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $ 49 million and $ 41 million at September 30, 2023 and December 31, 2022, respectively.

(b) Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for both periods presented.

(c) Energy-related derivatives not designated as hedging instruments were immaterial for Alabama Power and Mississippi Power at December 31, 2022. There were no such instruments for Alabama Power and Mississippi Power at September 30, 2023.

At September 30, 2023 and December 31, 2022, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet
Derivative Category and Balance Sheet Location			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
			(in millions)
At September 30, 2023:
Energy-related derivatives:
Other regulatory assets, current			$	( 113 )		$	( 39 )		$	( 54 )		$	( 16 )		$	( 4 )
Other regulatory assets, deferred			( 48 )			( 19 )			( 18 )			( 11 )			—
Other regulatory liabilities, current			23			8			1			4			10
Other regulatory liabilities, deferred			6			1			2			3			—
Total energy-related derivative gains (losses)			$	( 132 )		$	( 49 )		$	( 69 )		$	( 20 )		$	6
At December 31, 2022:
Energy-related derivatives:
Other regulatory assets, current			$	( 71 )		$	( 8 )		$	( 26 )		$	( 13 )		$	( 24 )
Other regulatory assets, deferred			( 23 )			( 7 )			( 14 )			( 2 )			—
Other regulatory liabilities, current			72			29			19			22			2
Other regulatory liabilities, deferred			31			9			2			20			—
Total energy-related derivative gains (losses)			$	9		$	23		$	( 19 )		$	27		$	( 22 )

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For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on accumulated OCI for the applicable Registrants were as follows:

Gain (Loss) Recognized in OCI on Derivatives			For the Three Months Ended September 30,						For the Nine Months Ended September 30,
			2023			2022			2023			2022
			(in millions)						(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives			$	( 4 )		$	11		$	( 55 )		$	51
Interest rate derivatives			( 3 )			6			( 12 )			36
Foreign currency derivatives			( 15 )			( 35 )			( 6 )			( 137 )
Fair value hedges (*) :
Foreign currency derivatives			27			20			28			18
Total			$	5		$	2		$	( 45 )		$	( 32 )
Georgia Power
Cash flow hedges:
Interest rate derivatives			$	—		$	—		$	( 3 )		$	31
Southern Power
Cash flow hedges:
Energy-related derivatives			$	—		$	( 11 )		$	( 14 )		$	( 4 )
Foreign currency derivatives			( 15 )			( 35 )			( 6 )			( 137 )
Total			$	( 15 )		$	( 46 )		$	( 20 )		$	( 141 )
Southern Company Gas
Cash flow hedges:
Energy-related derivatives			$	( 4 )		$	22		$	( 41 )		$	55
Interest rate derivatives			( 4 )			5			—			—
Total			$	( 8 )		$	27		$	( 41 )		$	55

(*) Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.

For the three and nine months ended September 30, 2022, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for Alabama Power and there were no such effects in 2023.

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For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships			For the Three Months Ended September 30,						For the Nine Months Ended September 30,
			2023			2022			2023			2022
			(in millions)						(in millions)
Southern Company
Total cost of natural gas			$	102		$	294		$	1,199		$	1,840
Gain (loss) on energy-related cash flow hedges (a)			( 4 )			9			( 32 )			28
Total other operations and maintenance			1,424			1,527			4,352			4,568
Gain (loss) on energy-related cash flow hedges (a)			( 1 )			—			( 2 )			—
Total depreciation and amortization			1,143			922			3,365			2,728
Gain (loss) on energy-related cash flow hedges (a)			( 5 )			( 1 )			( 18 )			5
Total interest expense, net of amounts capitalized			( 620 )			( 511 )			( 1,812 )			( 1,461 )
Gain (loss) on interest rate cash flow hedges (a)			( 22 )			( 7 )			( 31 )			( 19 )
Gain (loss) on foreign currency cash flow hedges (a)			( 3 )			( 3 )			( 8 )			( 16 )
Gain (loss) on interest rate fair value hedges (b)			( 47 )			( 102 )			( 50 )			( 300 )
Total other income (expense), net			141			132			428			414
Gain (loss) on foreign currency cash flow hedges (a)(c)			( 14 )			( 32 )			( 4 )			( 129 )
Gain (loss) on foreign currency fair value hedges			( 7 )			( 59 )			19			( 180 )
Amount excluded from effectiveness testing recognized in earnings			( 27 )			( 21 )			( 28 )			( 17 )
Southern Power
Total depreciation and amortization			$	130		$	133		$	380		$	384
Gain (loss) on energy-related cash flow hedges (a)			( 5 )			( 1 )			( 18 )			5
Total interest expense, net of amounts capitalized			( 32 )			( 32 )			( 98 )			( 105 )
Gain (loss) on foreign currency cash flow hedges (a)			( 3 )			( 3 )			( 8 )			( 16 )
Total other income (expense), net			4			3			8			5
Gain (loss) on foreign currency cash flow hedges (a)(c)			( 14 )			( 32 )			( 4 )			( 129 )
Southern Company Gas
Total cost of natural gas			$	102		$	294		$	1,199		$	1,840
Gain (loss) on energy-related cash flow hedges (a)			( 4 )			9			( 32 )			28
Total other operations and maintenance			264			252			879			824
Gain (loss) on energy-related cash flow hedges (a)			( 1 )			—			( 2 )			—
Total interest expense, net of amounts capitalized			( 77 )			( 65 )			( 226 )			( 187 )
Gain (loss) on interest rate cash flow hedges (a)			( 18 )			( 2 )			( 18 )			( 3 )
Gain (loss) on interest rate fair value hedges (b)			( 11 )			( 30 )			( 14 )			( 87 )

(a) Reclassified from accumulated OCI into earnings.

(b) For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.

(c) The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

The pre-tax effects of cash flow and fair value hedge accounting on income for interest rate derivatives were immaterial for the traditional electric operating companies for all periods presented.

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At September 30, 2023 and December 31, 2022, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

			Carrying Amount of the Hedged Item									Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items			At September 30, 2023			At December 31, 2022						At September 30, 2023			At December 31, 2022
			(in millions)									(in millions)
Southern Company
Long-term debt			$	( 2,873 )		$	( 2,927 )					$	328		$	282
Southern Company Gas
Long-term debt			$	( 402 )		$	( 415 )					$	95		$	81

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas were as follows:

						Gain (Loss)
						Three Months Ended September 30,									Nine Months Ended September 30,
Derivatives in Non-Designated Hedging Relationships			Statements of Income Location			2023			2022						2023			2022
						(in millions)									(in millions)
Energy-related derivatives:			Natural gas revenues (*)			$	—		$	3					$	—		$	( 10 )
			Cost of natural gas			7			( 2 )						36			( 7 )
Total derivatives in non-designated hedging relationships						$	7		$	1					$	36		$	( 17 )

(*) Excludes $ 14 million of gains for the nine months ended September 30, 2023, and immaterial amounts for all other periods presented, recorded in natural gas revenues associated with weather derivatives.

For the three and nine months ended September 30, 2023 and 2022, the pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for the other Registrants.

Contingent Features

The Registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. At September 30, 2023, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For Southern Company, the fair value of foreign currency derivative liabilities and interest rate derivative liabilities with contingent features, and the maximum potential collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3, was $ 78 million at September 30, 2023. For Southern Power, the fair value of foreign currency derivative liabilities with contingent features, and the maximum potential collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3, was $ 20 million at September 30, 2023. For the traditional electric operating companies and Southern Power, energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial at September 30, 2023. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could

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require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements. At September 30, 2023, cash collateral posted in these accounts was $ 18 million for Southern Power and immaterial for Alabama Power. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At September 30, 2023, cash collateral held on deposit in broker margin accounts was $ 49 million.

The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.

Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

Southern Company Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.

The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.

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Southern Power

Asset Acquisitions

Southern Power's asset acquisitions during the nine months ended September 30, 2023 are detailed in the following table:

Project Facility

Resource

Seller

Approximate Nameplate Capacity ( MW )

Location

Southern Power Ownership Percentage

Expected COD

PPA Contract Period

Millers Branch (*)

Solar

EDF Renewables, Inc.

200

Haskell County, TX

100 %

Fourth quarter 2025

20 years

South Cheyenne

Solar

Hanwha Q Cells USA Corp.

150

Laramie County, WY

100 %

First quarter 2024

20 years

(*) The project includes an option to expand capacity up to an additional 300 MWs.

The aggregate purchase price for the two projects was $ 193 million, which is primarily recorded within construction work in progress on the balance sheet.

Southern Company Gas

On September 22, 2023, Southern Company Gas completed the sale of its California natural gas storage facility, resulting in an immaterial loss.

Southern Company

The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The traditional electric operating companies are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy and battery energy storage projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities and is involved in several other complementary businesses including gas pipeline investments and gas marketing services.

Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $ 156 million and $ 406 million for the three and nine months ended September 30, 2023, respectively, and $ 336 million and $ 673 million for the three and nine months ended September 30, 2022, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were immaterial for all periods presented. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications. All other inter-segment revenues are not material.

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Financial data for business segments and products and services for the three and nine months ended September 30, 2023 and 2022 was as follows:

			Electric Utilities
			Traditional Electric Operating Companies			Southern Power			Eliminations			Total			Southern Company Gas			All Other			Eliminations			Consolidated
			(in millions)
Three Months Ended September 30, 2023
Operating revenues			$	5,674		$	653		$	( 160 )		$	6,167		$	689		$	154		$	( 30 )		$	6,980
Segment net income (loss) (a)(b)(c)			1,419			100			—			1,519			82			( 179 )			—			1,422
Nine Months Ended September 30, 2023
Operating revenues			$	14,145		$	1,686		$	( 417 )		$	15,414		$	3,417		$	499		$	( 122 )		$	19,208
Segment net income (loss) (a)(b)(c)(d)			2,852			288			—			3,140			475			( 490 )			( 4 )			3,121
At September 30, 2023
Goodwill			$	—		$	2		$	—		$	2		$	5,015		$	144		$	—		$	5,161
Total assets			99,464			13,090			( 568 )			111,986			24,823			2,370			( 858 )			138,321
Three Months Ended September 30, 2022
Operating revenues			$	6,938		$	1,180		$	( 691 )		$	7,427		$	857		$	135		$	( 41 )		$	8,378
Segment net income (loss) (a)(b)			1,445			95			—			1,540			83			( 152 )			1			1,472
Nine Months Ended September 30, 2022
Operating revenues			$	16,716		$	2,618		$	( 1,391 )		$	17,943		$	3,998		$	418		$	( 127 )		$	22,232
Segment net income (loss) (a)(b)			3,256			265			—			3,521			516			( 415 )			( 11 )			3,611
At December 31, 2022
Goodwill			$	—		$	2		$	—		$	2		$	5,015		$	144		$	—		$	5,161
Total assets			95,861			13,081			( 659 )			108,283			24,621			2,665			( 678 )			134,891

(a) Attributable to Southern Company.

(b) For the traditional electric operating companies, includes pre-tax charges (credits) to income at Georgia Power for the estimated probable loss associated with the construction of Plant Vogtle Units 3 and 4 of $ 160 million ($ 120 million after tax) for the three and nine months ended September 30, 2023 and $( 70 ) million ($( 52 ) million after tax) and $( 18 ) million ($( 13 ) million after tax) for the three and nine months ended September 30, 2022, respectively. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

(c) For Southern Power, includes an $ 18 million pre-tax loss recovery ($ 9 million after tax and partnership allocations) for the three and nine months ended September 30, 2023 related to an arbitration interim award and a $ 16 million pre-tax gain ($ 12 million after tax) on the sale of spare parts for the nine months ended September 30, 2023. See Note (C) under "General Litigation Matters – Southern Power" for additional information.

(d) For Southern Company Gas, includes a pre-tax charge of approximately $ 38 million ($ 28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for additional information.

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Products and Services

			Electric Utilities' Revenues
			Retail			Wholesale			Other			Total
			(in millions)
Three Months Ended September 30, 2023			$	5,139		$	727		$	301		$	6,167
Three Months Ended September 30, 2022			5,961			1,197			269			7,427
Nine Months Ended September 30, 2023			$	12,597		$	1,930		$	887		$	15,414
Nine Months Ended September 30, 2022			14,363			2,798			782			17,943

			Southern Company Gas' Revenues
			Gas Distribution Operations			Gas Marketing Services			Other			Total
			(in millions)
Three Months Ended September 30, 2023			$	617		$	56		$	16		$	689
Three Months Ended September 30, 2022			748			85			24			857
Nine Months Ended September 30, 2023			$	2,989		$	376		$	52		$	3,417
Nine Months Ended September 30, 2022			3,513			420			65			3,998

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Southern Company Gas

Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services. The non-reportable segments are combined and presented as all other.

Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states.

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50 % interest in SNG and a 50 % joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. See Note 7 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar.

The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. The all other column included a natural gas storage facility in Texas through its sale in November 2022 and a natural gas storage facility in California through its sale in September 2023. See Note 15 to the financial statements in Item 8 of the Form 10-K and Note (K) under "Southern Company Gas" for additional information.

Business segment financial data for the three months ended September 30, 2023 and 2022 was as follows:

			Gas Distribution Operations			Gas Pipeline Investments			Gas Marketing Services			Total			All Other			Eliminations			Consolidated
			(in millions)
Three Months Ended September 30, 2023
Operating revenues			$	619		$	8		$	56		$	683		$	8		$	( 2 )		$	689
Segment net income (loss)			70			24			2			96			( 14 )			—			82
Nine Months Ended September 30, 2023
Operating revenues			$	3,002		$	24		$	376		$	3,402		$	30		$	( 15 )		$	3,417
Segment net income (*)			352			73			59			484			( 9 )			—			475
Total assets at September 30, 2023			22,625			1,542			1,519			25,686			9,795			( 10,658 )			24,823
Three Months Ended September 30, 2022
Operating revenues			$	751		$	8		$	85		$	844		$	16		$	( 3 )		$	857
Segment net income (loss)			59			24			( 2 )			81			2			—			83
Nine Months Ended September 30, 2022
Operating revenues			$	3,533		$	24		$	420		$	3,977		$	43		$	( 22 )		$	3,998
Segment net income			365			76			65			506			10			—			516
Total assets at December 31, 2022			22,040			1,577			1,616			25,233			8,943			( 9,555 )			24,621

(*) For gas distribution operations, includes a pre-tax charge of approximately $ 38 million ($ 28 million after tax) associated with the disallowance of certain capital expenditures at Nicor Gas. See Note (B) under "Southern Company Gas" for additional information.

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