GPJA 10-Q Quarter ended June 30, 2025

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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, 2024 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 June 30, 2025 and 2024. Certain information and 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.

The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. 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.

Goodwill and Other Intangible Assets

Goodwill at both June 30, 2025 and December 31, 2024 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 exist.

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Other intangible assets were as follows:

			At June 30, 2025												At December 31, 2024
			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			$	212		$	( 184 )		$	28					$	212		$	( 182 )		$	30
Trade names			64			( 63 )			1						64			( 59 )			5
PPA fair value adjustments			390			( 178 )			212						390			( 168 )			222
Other			3			( 3 )			—						3			( 3 )			—
Total subject to amortization			$	669		$	( 428 )		$	241					$	669		$	( 412 )		$	257
Not subject to amortization:
FCC licenses			75			—			75						75			—			75
Total other intangible assets			$	744		$	( 428 )		$	316					$	744		$	( 412 )		$	332
Southern Power (*)
PPA fair value adjustments			$	390		$	( 178 )		$	212					$	390		$	( 168 )		$	222
Southern Company Gas (*)
Gas marketing services
Customer relationships			$	156		$	( 151 )		$	5					$	156		$	( 150 )		$	6
Trade names			26			( 25 )			1						26			( 23 )			3
Total other intangible assets			$	182		$	( 176 )		$	6					$	182		$	( 173 )		$	9

(*) All subject to amortization.

Amortization associated with other intangible assets was as follows:

			Three Months Ended June 30,						Six Months Ended June 30,
			2025			2024			2025			2024
			(in millions)
Southern Company (a)			$	8		$	9		$	16		$	18
Southern Power (b)			5			5			10			10
Southern Company Gas
Gas marketing services			1			1			3			3

(a) Includes $ 5 million for the three months ended June 30, 2025 and 2024 and $ 10 million for the six months ended June 30, 2025 and 2024 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						Georgia Power			Southern Power			Southern Company Gas
			(in millions)
At June 30, 2025
Cash and cash equivalents			$	1,264					$	94		$	143		$	225
Restricted cash (*) :
Other current assets			1						—			—			—
Total cash, cash equivalents, and restricted cash			$	1,265					$	94		$	143		$	225
At December 31, 2024
Cash and cash equivalents			$	1,070					$	97		$	159		$	43
Restricted cash (*) :
Other current assets			31						21			9			1
Total cash, cash equivalents, and restricted cash			$	1,101					$	118		$	168		$	44

(*) For Georgia Power, reflects remaining proceeds held at December 31, 2024 from the issuance of solid waste disposal facility revenue bonds in 2022. For Southern Power, reflects remaining proceeds held at December 31, 2024 from an arbitration award held to fund future replacement costs. For Southern Company, also reflects collateral of $ 1 million for life insurance and long-term disability insurance, which was included at Southern Holdings and Southern Company Gas at June 30, 2025 and December 31, 2024, respectively.

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 non-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 June 30, 2025 is expected to be restored prior to year-end.

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Storm Damage Reserves

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

Storm damage reserve activity for the traditional electric operating companies during the six months ended June 30, 2025 was as follows:

			Southern Company			Alabama Power			Georgia Power			Mississippi Power
			(in millions)
Balance at December 31, 2024			$	( 705 )		$	70		$	( 827 )		$	52
Accrual (*)			36			13			16			7
Weather-related damages			( 198 )			( 85 )			( 106 )			( 7 )
Balance at June 30, 2025			$	( 867 )		$	( 2 )		$	( 917 )		$	52

(*) For Alabama Power, includes $ 7 million of undistributed customer bill credits related to the nuclear fuel disposal costs litigation award, as directed by the Alabama PSC in its December 2024 order. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

See Note 5 to the financial statements under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.

On April 1, 2025, the Mississippi PSC approved a stipulation between Mississippi Power and the Mississippi Public Utilities Staff for an $ 8 million increase in total annual depreciation effective January 1, 2025.

Asset Retirement Obligations

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

In June 2025, Alabama Power recorded a net decrease of approximately $ 257 million to its AROs related to the CCR Rule and the related state rule resulting from changes in estimates, including lower future inflation rates, higher discount rates, and timing of closure activities.

Also in June 2025, Mississippi Power, as a joint owner of Alabama Power's Plant Greene County Units 1 and 2, recorded a net decrease of approximately $ 13 million to its AROs related to the CCR Rule and the related Alabama state rule resulting from changes in estimates, including lower future inflation rates, higher discount rates, and timing of closure activities.

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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 fuel and natural gas cost recovery balances for the traditional electric operating companies and Southern Company Gas, respectively, at June 30, 2025 and December 31, 2024 were as follows:

Regulatory Clause			Balance Sheet Line Item			At June 30, 2025			At December 31, 2024
						(in millions)
Alabama Power
Rate ECR			Other regulatory assets, deferred			$	62		$	—
			Other regulatory liabilities, current			—			29
Georgia Power
Fuel Cost Recovery			Receivables – under recovered retail fuel clause revenues			$	655		$	713
			Deferred under recovered retail fuel clause revenues			325			453
Mississippi Power
Fuel Cost Recovery (*)			Receivables – customer accounts, net			$	28		$	—
			Deferred under recovered retail fuel clause revenues			—			32
			Over recovered retail fuel clause revenues			—			32
Southern Company Gas
Natural Gas Cost Recovery			Natural gas cost over recovery			$	107		$	193

(*) Mississippi Power also has wholesale MRA and Market Based (MB) fuel cost recovery factors. At June 30, 2025 and December 31, 2024, wholesale MRA fuel costs were over recovered $ 5 million and $ 19 million, respectively, and were included in other current liabilities on Mississippi Power's balance sheets. The wholesale MB fuel cost recovery was immaterial for both periods presented.

Alabama Power

Petition for Certificate of Convenience and Necessity

On June 6, 2025, the FERC approved Alabama Power's acquisition of Tenaska Alabama Partners, L.P., which owns and operates the Lindsay Hill Generating Station, an approximately 855 -MW combined cycle generation facility in Autauga County, Alabama. The total purchase price is approximately $ 622 million, subject to working capital adjustments. The completion of the acquisition is subject to the satisfaction or waiver of customary closing conditions, including, among others, approval by the Alabama PSC. Alabama Power expects to complete the acquisition by the end of the third quarter 2025. The ultimate outcome of this matter cannot be determined at this time.

Jurisdictional Separation Study Order

On June 5, 2025, the Alabama PSC approved an order authorizing Alabama Power to implement changes related to the Jurisdictional Separation Study (JSS) under Rate RSE, which allocates costs between retail and other electric services. For 2026, a revised JSS allocation factor will account for system capacity previously allocated to wholesale electric services that will be used for retail electric service starting January 1, 2026. In addition, Alabama Power is authorized to establish a regulatory asset to defer certain costs associated with this capacity for 2026, and those costs are estimated to be approximately $ 100 million. Beginning in 2027, Alabama Power will amortize the regulatory asset on a levelized basis over a period not exceeding 10 years.

Rate NDR

Beginning with July 2025 billings, the NDR reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $ 50 million. Alabama Power

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expects to collect $ 18 million in the second half of 2025 and approximately $ 36 million annually beginning in 2026 under Rate NDR unless the NDR balance exceeds $ 75 million. At June 30, 2025, Alabama Power's regulatory asset balance related to NDR was $ 2 million. Rate NDR is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 48-month period. The Alabama PSC gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance.

Reliability Reserve Accounting Order

On June 19, 2025, Alabama Power notified the Alabama PSC of its intent to use a portion of its $ 131 million reliability reserve balance during 2025. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

2022 ARP

On July 1, 2025, the Georgia PSC approved a settlement agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to extend the 2022 ARP for an additional three-year term through December 31, 2028 (ARP Extension). Under the ARP Extension, base rates will not be adjusted in 2026, 2027, or 2028 (ARP Extension Period) except for reasonable and prudent storm damage costs incurred through December 31, 2025, which will be determined in a separate regulatory proceeding.

Under the ARP Extension, Georgia Power's retail ROE set point will continue at 10.50 % and its equity ratio will continue at 56 %. Additionally, the retail ROE range approved by the Georgia PSC in the 2022 ARP, of 9.50 % to 11.90 %, will continue. The ARP Extension includes, among other things, the following modifications to the 2022 ARP:

• Storm damage costs will be included in a separate regulatory proceeding to be filed no sooner than February 1, 2026 and no later than July 1, 2026 to recover the actual reasonable and prudent storm costs incurred through December 31, 2025. Subject to Georgia PSC approval, new rates would be effective approximately 90 days after the filing is made. The Georgia PSC will determine the period over which any such storm damage costs will be recovered.

• Amortization of regulatory assets and liabilities in the 2022 ARP, which were subsequently included in current rates through annual compliance filings, will continue through the ARP Extension Period. This includes those regulatory asset and liability balances that were projected to be fully amortized through 2025 or during the ARP Extension Period.

• The amounts previously deferred during the 2022 ARP for ITCs and PTCs will be amortized through the ARP Extension Period. The acceleration of amortization during the ARP Extension Period is subject to the Internal Revenue Code normalization rules and other guidance (if any) released by the IRS. Certain amounts of ITCs generated during the ARP Extension Period will be amortized over five years, and additional ITC amounts will be deferred to a regulatory liability during the ARP Extension Period. Sixty percent (60%) of PTC benefits generated (excluding PTCs generated under Internal Revenue Code §45J) during the ARP Extension Period will be credited to income tax expense as generated. The remaining forty percent (40%) will be deferred to a regulatory liability.

• The period for depreciation and amortization related to certain generating plants and net book values of retired generating plants will be 13 years effective January 1, 2026.

Using the retail ROE range approved by the Georgia PSC in the 2022 ARP, earnings above 11.90 % retail ROE will continue to be subject to sharing whereby 40 % of earnings above the band would be applied to regulatory assets, 40 % would be directly refunded to customers, and the remaining 20 % would be retained by Georgia Power. There will be no recovery of any earnings shortfall below 9.50 % retail ROE on an actual basis. However, if at any time during the term of the ARP Extension Period, Georgia Power projects that its retail earnings will be less than the lower end of the approved retail ROE range for any calendar year of the ARP Extension Period, it may petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff to adjust Georgia Power's retail rates to

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achieve a retail ROE equal to the lower end of the approved retail ROE range. Any ICR tariff would expire at the earlier of January 1, 2029 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement the ICR tariff, Georgia Power may file a full base rate case.

Except as provided above, Georgia Power will not file a base rate increase while the ARP Extension is in effect. Georgia Power is required to file a general base rate case by July 1, 2028.

Integrated Resource Plans

On June 20, 2025, Georgia Power requested certification from the Georgia PSC for a Georgia Power-owned battery energy storage facility with a capacity of 200 MWs and a projected COD in 2027. Georgia Power expects the Georgia PSC to render a final decision in September 2025.

On July 30, 2025, Georgia Power requested certification from the Georgia PSC, for which a final decision is expected to be rendered in December 2025, for the following resources:

• As included in the 2022 IRP final order, Georgia Power initiated a request for proposals (RFP) of up to 8,500 MWs of capacity from a variety of resources with projected CODs or delivery commencement dates between 2028 and 2030. The RFP resulted in 18 resources, totaling 7,999 MWs, being selected which consist of four PPAs (including two affiliate PPAs with Southern Power that are subject to approval by the FERC) with capacity totaling 1,195 MWs commencing between 2028 and 2030, three project sites consisting of five Georgia Power-owned combined cycle units with capacity totaling 3,692 MWs and projected CODs commencing between 2029 and 2030, nine Georgia Power-owned battery energy storage facilities with capacity totaling 2,762 MWs and projected CODs commencing between 2028 and 2030, and two Georgia Power-owned battery energy storage facilities with solar with capacity totaling 350 MWs and projected CODs commencing in 2028.

• In July 2025, Georgia Power extended 50 MWs of an existing 750 -MW affiliate PPA with Mississippi Power for an additional year through December 31, 2029.

• Additionally, in July 2025, Georgia Power executed a 20-year non-affiliate PPA for 930 MWs commencing in 2030 and five 25-year non-affiliate PPAs totaling 646 MWs commencing in 2027.

• Georgia Power entered into agreements to initiate acquisition of property and construction of a 260 -MW Georgia Power-owned battery energy storage facility with a projected COD in 2027 to be paired with an existing non-affiliate solar PPA.

The certification requests on June 20, 2025 and July 30, 2025 associated with these Georgia Power-owned projects and related transmission investments total approximately $ 16.7 billion, excluding AFUDC.

As required by the 2025 IRP decision, Georgia Power will update its load forecast to support the certification requests from the RFP of up to 8,500 MWs. The Georgia PSC will determine the necessary generation resources to certify. See "2025 IRP" herein for information regarding the 2025 IRP.

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

2025 IRP

On July 15, 2025, the Georgia PSC approved Georgia Power's 2025 IRP, as modified by a stipulation among Georgia Power, the staff of the Georgia PSC, and certain intervenors. In the 2025 IRP decision, the Georgia PSC approved the following requests:

• Extended operation of Plant Scherer Unit 3 ( 614 MWs based on 75 % ownership) through at least December 31, 2035 and Plant Gaston Units 1 through 4 ( 500 MWs based on 50 % ownership through SEGCO) through at least December 31, 2034. See Note 7 to the financial statements under "SEGCO" in Item 8 of the Form 10-K for additional information.

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• Installation of environmental controls and natural gas co-firing at Plant Bowen Units 1 through 4 ( 3,160 MWs), Plant Scherer Units 1 and 2 ( 137 MWs based on 8.4 % ownership), and Plant Scherer Unit 3 for compliance with both ELG supplemental rules and GHG rules.

• Upgrades to Plant McIntosh Units 10 and 11 ( 1,319 MWs) for a projected 194 MWs of incremental capacity by 2028 and Plant McIntosh Units 1 through 8 ( 640 MWs) for a projected 74 MWs of incremental capacity by 2033.

• Upgrades to Plant Vogtle Units 1 and 2 ( 1,060 MWs based on 45.7 % ownership) for a projected 54 MWs of incremental capacity, some of which could be available as early as 2028.

• Investments related to the continued reliable hydro operations of four facilities, as well as the authority to spend up to $ 25 million to undertake engineering studies related to two additional hydro facilities.

• RFP for at least 1,100 MWs of utility scale and distributed generation renewable resources.

• Issuance of a capacity RFP to procure resources to meet capacity needs in 2032 and 2033.

• Strategic power delivery infrastructure plan necessary to help ensure adequate reliability and serve the projected future load growth expected in Georgia.

• Certification of approximately 187 MWs of wholesale capacity associated with Plant Scherer Unit 3 to be placed in retail rate base, some of which will be available beginning in 2026.

In addition, the 2025 IRP assumes Plant Bowen Units 1 and 2 will operate through at least the end of 2035.

Fuel Cost Recovery

On May 14, 2025, Georgia Power submitted an Interim Fuel Rider (IFR) notification and plan informing the Georgia PSC that Georgia Power's under recovered fuel balance exceeded the IFR threshold of $ 200 million, established in a Georgia PSC stipulation approved in May 2023. Georgia Power proposed no fuel cost recovery rate change and is required to monitor and report to the Georgia PSC monthly as long as the under recovered fuel balance is above $ 200 million. On July 15, 2025, Georgia Power filed its most recent IFR plan and notification which also proposed no fuel cost recovery rate change. Georgia Power is scheduled to file its next fuel case no later than February 28, 2026. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Nuclear Construction

Georgia Power placed Plant Vogtle Units 3 and 4 in service on July 31, 2023 and April 29, 2024, respectively. As of June 30, 2025, site demobilization efforts were largely complete. Georgia Power is finalizing remaining contractor obligations. Georgia Power's net capital costs incurred through June 30, 2025 in connection with Plant Vogtle Units 3 and 4, and its approximate proportionate share of remaining capital costs to be incurred after June 30, 2025, is as follows:

			(in millions)
Total project capital cost forecast (a)(b)			$	10,732
Net investment at June 30, 2025 (b)			( 10,690 )
Remaining estimate to complete			$	42

(a) Includes approximately $ 1.2 billion of costs that are not shared with the other Vogtle Owners. Excludes financing costs capitalized through AFUDC of approximately $ 440 million accrued through Unit 4's in-service date.

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

Other Construction

At June 30, 2025, Georgia Power had recorded approximately $ 1.3 billion of combined capital costs, excluding AFUDC, for the projects reflected in the table below. The total certified amounts related to these projects are

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approximately $ 2.8 billion, excluding AFUDC. The ultimate outcome of these matters cannot be determined at this time.

Project

Resource

Approximate Nameplate Capacity ( MW )

Projected COD

Regulatory Approval

Projects Under Construction at June 30, 2025

McGrau Ford

Battery energy storage

265

Fourth quarter 2026

2022 IRP

Plant Yates Units 8 through 10

Combustion turbine

1,326

Fourth quarter 2026 through third quarter 2027

2023 IRP Update

Various facilities

Battery energy storage

500

Second quarter 2026 through fourth quarter 2026

2023 IRP Update

Mississippi Power

Performance Evaluation Plan

On June 17, 2025, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2025, resulting in an annual increase in revenues of approximately 4.0 %, or $ 41 million, primarily due to increases in investment and depreciation. In accordance with the PEP rate schedule, an increase of 2.0 % of total retail revenues, or approximately $ 22 million, became effective with the first billing cycle of April 2025, and the remaining approximately $ 19 million became effective with the first billing cycle of July 2025.

Integrated Resource Plans

On July 8, 2025, Mississippi Power extended 50 MWs of an existing 750 -MW affiliate PPA with Georgia Power for an additional year through December 31, 2029, subject to approval by the Georgia PSC. The ultimate outcome of this matter cannot be determined at this time. See "Georgia Power – Integrated Resource Plans" herein for additional information.

Environmental Compliance Overview Plan

On April 1, 2025, the Mississippi PSC approved Mississippi Power's annual ECO Plan filing for 2025, resulting in a $ 6 million annual increase in revenues effective with the first billing cycle of May 2025.

Ad Valorem Tax Adjustment

On June 30, 2025, Mississippi Power submitted its annual ad valorem tax adjustment filing for 2025 to the Mississippi PSC, which requested a $ 7 million annual increase in revenues. The ultimate outcome of this matter cannot be determined at this time.

System Restoration Rider

On June 17, 2025, the Mississippi PSC approved Mississippi Power's annual SRR filing for 2025, with no change in retail rates. Mississippi Power's minimum annual SRR accrual increased from $ 12.6 million to $ 13.5 million and the target property damage reserve balance increased from $ 75 million to $ 125 million. Mississippi Power will continue to record a minimum annual accrual until a target property damage reserve balance of $ 125 million is met.

Reliability Reserve Accounting Order

On March 17, 2025, Mississippi Power notified the Mississippi PSC of its intent to use a portion of its $ 57 million reliability reserve balance during 2025, through the annual PEP filing. On June 17, 2025, the Mississippi PSC approved the annual PEP filing which allowed the use of $ 10.9 million of the reliability reserve balance, which Mississippi Power used for reliability-related generation, transmission, and distribution expenses in the second quarter 2025. See "Performance Evaluation Plan" herein for information regarding approval of the annual PEP filing.

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Plant Daniel

On June 19, 2025, the Florida PSC issued a final order approving the transfer of FP&L's 50 % ownership interest in Plant Daniel Units 1 and 2 to Mississippi Power. On July 30, 2025, Mississippi Power completed the acquisition of FP&L's 50 % interest in Plant Daniel Units 1 and 2 and, as part of the acquisition, received approximately $ 36 million from FP&L.

Municipal and Rural Associations Tariff

On April 3, 2025, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy in December 2024. The settlement agreement provides for (i) a $ 1 million increase in annual wholesale base revenues and a refund to customers of approximately $ 4 million, (ii) a rate escalation of 2.5 % on an annual basis in periods subsequent to December 31, 2024 and continuing through the end of the shared service agreement on December 31, 2035, and (iii) a waiver of rights by Mississippi Power and Cooperative Energy to file for any changes in non-fuel rates through the end of the term of the shared service agreement.

Southern Company Gas

Infrastructure Replacement Programs and Capital Projects

On March 26, 2025, the Illinois Supreme Court denied Nicor Gas' petition for leave to appeal $ 14 million of the 2019 Qualifying Infrastructure Plant disallowance. This matter is concluded and had no impact on the current period financial statements.

See Note 3 to the financial statements in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies.

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 intend to dispute the allegations raised in and vigorously defend against the pending legal challenges discussed below; however, the ultimate outcome of each of these matters cannot be determined at this time.

Southern Company

On July 11, 2025, a purported class action complaint was filed in the U.S. District Court for the District of Maryland against two nuclear consulting companies and all U.S. commercial nuclear power operators, or affiliated entities, including Southern Company. The purported class of plaintiffs includes all persons employed in nuclear power generation by the defendants, including nuclear operators, nuclear engineers, and nuclear technicians, from May 1, 2003 to the present. The complaint alleges that, since at least May 2003, the nuclear power industry conspired to fix and suppress employee compensation for nuclear power generation employees in violation of federal antitrust law. Although not named as defendants, other entities are accused of having participated in the plaintiffs' alleged conspiracy, including Southern Nuclear. The plaintiffs seek to recover, among other relief, unspecified monetary damages, including treble damages and attorneys' fees, and injunctive relief. An adverse outcome could have a material impact on Southern Company's financial statements.

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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. In August 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. In October 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 federal government caused by the defendants' alleged violations, as well as treble damages and attorneys' fees, among other relief. In February 2024, the defendants moved to dismiss the amended complaint. In August 2024, the court granted the defendants' motion in part and denied it in part, dismissing the plaintiff's False Claims Act count along with its accompanying treble damages and attorneys' fees but allowing the employment retaliation claim to proceed. In October 2024, the plaintiff requested interlocutory appeal of the court's decision, which was denied on February 25, 2025, and the defendants asserted counterclaims for conversion and misappropriation of trade secrets. In November 2024, the defendants filed a motion for judgment on the pleadings on the plaintiff's employment retaliation claim. In December 2024, the plaintiff filed a motion to dismiss the defendants' counterclaims. On July 15, 2025, the court denied the plaintiff's motion to dismiss the defendants' counterclaims and the defendants' motion for judgment on the pleadings. 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 surface impoundment utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper sought a declaratory judgment that the RCRA and regulations governing CCR were 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. In December 2022, Alabama Power filed a motion to dismiss the case. In January 2024, the lawsuit was dismissed without prejudice by the U.S. District Court judge. In February 2024, the plaintiff filed a motion to reconsider, which was denied by the U.S. District Court judge in July 2024. In August 2024, the plaintiff filed a notice of appeal in the U.S. Court of Appeals for the Eleventh Circuit challenging the denial of the motion to reconsider the order of dismissal.

In 2023, the EPA issued a Notice of Potential Violations (NOPV) associated with Alabama Power's plan to close the Plant Barry surface impoundment. In September 2024, Alabama Power reached a settlement with the EPA resolving two of the three allegations in the NOPV related to the groundwater monitoring system and the emergency action plan at the Plant Barry surface impoundment. The settlement did not resolve the EPA's allegation relating to Alabama Power's plan to close the Plant Barry surface impoundment. Alabama Power has affirmed to the EPA its position that it is in compliance with CCR requirements.

On July 29, 2025, Coosa Riverkeeper filed a citizen suit in the U.S. District Court for the Northern District of Alabama alleging that Alabama Power's closure of the Plant Gadsden surface impoundment violates the RCRA and regulations governing CCR. Among other relief requested, Coosa Riverkeeper seeks declaratory judgment that Alabama Power is in violation of RCRA and regulations governing CCR, and preliminary and injunctive relief to

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require Alabama Power to close the CCR unit and operate a groundwater monitoring system in a different manner to satisfy RCRA and the regulations governing CCR requirements.

These matters could have a material impact on Alabama Power's and Southern Company's financial statements, including 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.

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 $ 13 million at both June 30, 2025 and December 31, 2024. 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 $ 216 million and $ 222 million at June 30, 2025 and December 31, 2024, respectively, based on the estimated cost of environmental investigation and remediation at 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.

Other Matters

Mississippi Power

On March 31, 2025, the Mississippi Department of Revenue (Mississippi DOR) completed an audit of sales and use taxes paid by Mississippi Power from October 2019 to July 2024 and entered a final assessment, indicating a total amount due of $ 29 million, including associated penalties and interest. Mississippi Power does not agree with the audit findings and filed an administrative appeal with the Mississippi DOR on May 29, 2025. Mississippi Power's sales and use taxes are generally authorized for rate recovery. The ultimate outcome of this matter cannot be determined at this time.

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. Included in the wholesale electric revenues of the traditional electric operating companies and Southern Power are revenues associated with affiliate transactions. These revenues are generated through long-term PPAs or short-term energy sales made in accordance with the IIC, as approved by the FERC. Amounts related to these affiliate revenues are eliminated in consolidation for Southern Company. See Note 1 to the financial statements under "Affiliate Transactions" and "Revenues" in Item 8 of the Form 10-K for additional information. See "Lease Income" herein and Note (J) for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.

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The following table disaggregates revenue from contracts with customers for the three and six months ended June 30, 2025 and 2024:

			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
Three Months Ended June 30, 2025
Operating revenues
Retail electric revenues
Residential			$	2,021		$	725		$	1,217		$	79		$	—		$	—
Commercial			1,716			504			1,127			85			—			—
Industrial			1,015			432			496			87			—			—
Other			29			2			25			2			—			—
Total retail electric revenues			4,781			1,663			2,865			253			—			—
Natural gas distribution revenues
Residential			394			—			—			—			—			394
Commercial			94			—			—			—			—			94
Transportation			331			—			—			—			—			331
Industrial			7			—			—			—			—			7
Other			60			—			—			—			—			60
Total natural gas distribution revenues			886			—			—			—			—			886
Wholesale electric revenues
PPA energy revenues			310			58			50			2			210			—
PPA capacity revenues			154			29			35			17			85			—
Non-PPA revenues			60			36			10			100			59			—
Total wholesale electric revenues			524			123			95			119			354			—
Other natural gas revenues
Gas marketing services			81			—			—			—			—			81
Other			5			—			—			—			—			5
Total other natural gas revenues			86			—			—			—			—			86
Other revenues			457			67			206			9			8			—
Total revenue from contracts with customers			6,734			1,853			3,166			381			362			972
Other revenue sources (*)			239			115			( 56 )			19			184			7
Total operating revenues			$	6,973		$	1,968		$	3,110		$	400		$	546		$	979

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			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
Six Months Ended June 30, 2025
Operating revenues
Retail electric revenues
Residential			$	4,087		$	1,531		$	2,403		$	153		$	—		$	—
Commercial			3,327			986			2,181			160			—			—
Industrial			1,930			822			940			168			—			—
Other			61			4			52			5			—			—
Total retail electric revenues			9,405			3,343			5,576			486			—			—
Natural gas distribution revenues
Residential			1,239			—			—			—			—			1,239
Commercial			292			—			—			—			—			292
Transportation			737			—			—			—			—			737
Industrial			26			—			—			—			—			26
Other			170			—			—			—			—			170
Total natural gas distribution revenues			2,464			—			—			—			—			2,464
Wholesale electric revenues
PPA energy revenues			723			112			134			5			491			—
PPA capacity revenues			299			57			74			34			169			—
Non-PPA revenues			136			106			19			233			121			—
Total wholesale electric revenues			1,158			275			227			272			781			—
Other natural gas revenues
Gas marketing services			337			—			—			—			—			337
Other			10			—			—			—			—			10
Total other natural gas revenues			347			—			—			—			—			347
Other revenues			954			150			436			30			14			—
Total revenue from contracts with customers			14,328			3,768			6,239			788			795			2,811
Other revenue sources (*)			420			212			( 91 )			33			318			7
Total operating revenues			$	14,748		$	3,980		$	6,148		$	821		$	1,113		$	2,818

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			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
Three Months Ended June 30, 2024
Operating revenues
Retail electric revenues
Residential			$	2,049		$	736		$	1,236		$	77		$	—		$	—
Commercial			1,613			508			1,023			82			—			—
Industrial			962			445			434			83			—			—
Other			30			3			25			2			—			—
Total retail electric revenues			4,654			1,692			2,718			244			—			—
Natural gas distribution revenues
Residential			287			—			—			—			—			287
Commercial			69			—			—			—			—			69
Transportation			304			—			—			—			—			304
Industrial			5			—			—			—			—			5
Other			63			—			—			—			—			63
Total natural gas distribution revenues			728			—			—			—			—			728
Wholesale electric revenues
PPA energy revenues			265			55			22			1			192			—
PPA capacity revenues			153			23			32			15			99			—
Non-PPA revenues			54			27			2			95			50			—
Total wholesale electric revenues			472			105			56			111			341			—
Other natural gas revenues
Gas marketing services			68			—			—			—			—			68
Other			6			—			—			—			—			6
Total other natural gas revenues			74			—			—			—			—			74
Other revenues			419			62			185			10			11			—
Total revenue from contracts with customers			6,347			1,859			2,959			365			352			802
Other revenue sources (*)			116			14			( 84 )			( 1 )			172			29
Total operating revenues			$	6,463		$	1,873		$	2,875		$	364		$	524		$	831

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			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
Six Months Ended June 30, 2024
Operating revenues
Retail electric revenues
Residential			$	3,900		$	1,501		$	2,252		$	147		$	—		$	—
Commercial			3,084			976			1,955			153			—			—
Industrial			1,834			855			817			162			—			—
Other			60			6			50			4			—			—
Total retail electric revenues			8,878			3,338			5,074			466			—			—
Natural gas distribution revenues
Residential			1,032			—			—			—			—			1,032
Commercial			245			—			—			—			—			245
Transportation			666			—			—			—			—			666
Industrial			21			—			—			—			—			21
Other			176			—			—			—			—			176
Total natural gas distribution revenues			2,140			—			—			—			—			2,140
Wholesale electric revenues
PPA energy revenues			537			112			40			2			394			—
PPA capacity revenues			304			46			64			31			196			—
Non-PPA revenues			112			68			2			187			110			—
Total wholesale electric revenues			953			226			106			220			700			—
Other natural gas revenues
Gas marketing services			300			—			—			—			—			300
Other			11			—			—			—			—			11
Total other natural gas revenues			311			—			—			—			—			311
Other revenues			746			114			337			22			21			—
Total revenue from contracts with customers			13,028			3,678			5,517			708			721			2,451
Other revenue sources (*)			81			( 14 )			( 244 )			( 2 )			276			87
Total operating revenues			$	13,109		$	3,664		$	5,273		$	706		$	997		$	2,538

(*) 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 June 30, 2025 and December 31, 2024:

			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
Accounts Receivable
At June 30, 2025			$	3,106		$	778		$	1,485		$	133		$	132		$	451
At December 31, 2024			3,048			783			1,244			113			106			660
Contract Assets
At June 30, 2025			$	304		$	—		$	134		$	—		$	—		$	74
At December 31, 2024			323			3			184			—			—			72
Contract Liabilities
At June 30, 2025			$	170		$	14		$	73		$	2		$	1		$	—
At December 31, 2024			140			11			34			—			2			3

Contract assets for Georgia Power primarily relate to unregulated service agreements, where payment is contingent on project completion, and 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. Contract liabilities for Georgia Power primarily relate to cash collections recognized in advance of revenue for unregulated service agreements. 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 received cash advances totaling approximately $ 68 million from a third-party financial institution to fund work performed. 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 June 30, 2025 and December 31, 2024, Southern Company's unregulated distributed generation business had contract assets of $ 95 million and $ 67 million, respectively, and contract liabilities of $ 81 million and $ 95 million, respectively, for outstanding performance obligations, all of which are expected to be satisfied within one year.

Revenues recognized in the three and six months ended June 30, 2025, which were included in contract liabilities at December 31, 2024, were $ 44 million and $ 72 million, respectively, for Southern Company, $ 11 million and $ 16 million, respectively, for Georgia Power, and immaterial for the other 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

Southern Company's subsidiaries may enter into long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. For the traditional electric operating companies 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. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related

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to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at June 30, 2025 are expected to be recognized as follows:

			2025 (remaining)			2026			2027			2028			2029			Thereafter
			(in millions)
Southern Company			$	548		$	535		$	405		$	343		$	309		$	2,636
Alabama Power			49			6			4			1			—			—
Georgia Power			37			43			18			15			2			27
Mississippi Power (*)			31			66			69			73			—			—
Southern Power (*)			183			331			340			316			312			2,609

(*) Includes performance obligations related to affiliate PPAs with Georgia Power. See Note 1 to the financial statements under "Affiliate Transactions" in Item 8 of the Form 10-K for additional information.

Lease Income

Lease income for the three and six months ended June 30, 2025 and 2024 was as follows:

			Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
			(in millions)
Three Months Ended June 30, 2025
Lease income - interest income on sales-type leases			$	6		$	—		$	—		$	4		$	2		$	—
Lease income - operating leases			33			2			7			1			37			9
Variable lease income			125			—			—			—			136			—
Total lease income			$	164		$	2		$	7		$	5		$	175		$	9
Six Months Ended June 30, 2025
Lease income - interest income on sales-type leases			$	11		$	—		$	—		$	7		$	4		$	—
Lease income - operating leases			66			3			14			1			73			18
Variable lease income			207			1			—			—			225			—
Total lease income			$	284		$	4		$	14		$	8		$	302		$	18
Three Months Ended June 30, 2024
Lease income - interest income on sales-type leases			$	7		$	—		$	—		$	5		$	2		$	—
Lease income - operating leases			35			2			9			1			22			9
Variable lease income			129			—			—			—			139			—
Total lease income			$	171		$	2		$	9		$	6		$	163		$	9
Six Months Ended June 30, 2024
Lease income - interest income on sales-type leases			$	14		$	—		$	—		$	9		$	5		$	—
Lease income - operating leases			71			5			16			2			43			18
Variable lease income			201			—			—			—			218			—
Total lease income			$	286		$	5		$	16		$	11		$	266		$	18

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 related to PPAs is included in wholesale revenues for Alabama Power, Georgia Power, and Southern Power.

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See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company

At June 30, 2025 and December 31, 2024, Southern Holdings had equity method investments totaling $ 115 million and $ 128 million, respectively, primarily related to investments in venture capital funds focused on energy and utility investments. The net losses from these investments totaled $ 14 million and $ 20 million for the three and six months ended June 30, 2025, respectively. Earnings/losses from these investments for the three and six months ended June 30, 2024 were immaterial .

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 June 30, 2025 and December 31, 2024, SP Solar had total assets of $ 5.3 billion and $ 5.4 billion, respectively, total liabilities of $ 360 million and $ 372 million, respectively, and noncontrolling interests of $ 1.0 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 June 30, 2025 and December 31, 2024, SP Wind had total assets of $ 2.0 billion, total liabilities of $ 247 million and $ 177 million, respectively, and noncontrolling interests of $ 34 million and $ 35 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.

Subsequent to June 30, 2025, Southern Power notified the Class A members of its intent to exercise the option to purchase all Class A membership interests in the SP Wind tax equity partnership on December 31, 2025 under the terms of the limited liability agreement.

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 June 30, 2025 and December 31, 2024, the other VIEs had total assets of $ 1.6 billion, total liabilities of $ 229 million and $ 224 million, respectively, and noncontrolling interests of $ 657 million and $ 691 million, respectively.

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Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.

Southern Company Gas

The carrying amounts of Southern Company Gas' equity method investments at June 30, 2025 and December 31, 2024 were as follows:

Investment Balance			At June 30, 2025			At December 31, 2024
			(in millions)
SNG			$	1,266		$	1,245
Other			34			34
Total			$	1,300		$	1,279

The earnings from Southern Company Gas' equity method investment in SNG were $ 23 million and $ 32 million for the three months ended June 30, 2025 and 2024, respectively, and $ 62 million and $ 76 million for the six months ended June 30, 2025 and 2024, respectively. The earnings from Southern Company Gas' other equity method investments were immaterial for all periods presented.

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 June 30, 2025, committed credit arrangements with banks were as follows:

						Expires
Company						2026			2027									2030						Total						Unused																								Expires within One Year
						(in millions)
Southern Company parent (a)						$	—		$	500								$	2,500					$	3,000					$	2,999																							$	—
Alabama Power (b)						665			—									700						1,365						1,364																								—
Georgia Power						—			—									2,050						2,050						2,026																								—
Mississippi Power (a)						—			125									150						275						275																								—
Southern Power (a)(c)						—			—									600						600						600																								—
Southern Company Gas (d)						—			—									1,600						1,600						1,598																								—
SEGCO						30			—									—						30						30																								30
Southern Company						$	695		$	625								$	7,600					$	8,920					$	8,892																							$	30

(a) Arrangement expiring in 2030 represents a $ 3.25 billion combined arrangement for Southern Company, Mississippi Power, and Southern Power allowing for flexible sublimits. Pursuant to the combined facility, the allocations among Southern Company, Southern Power, and Mississippi Power may be adjusted.

(b) Includes $ 15 million expiring in 2026 at Alabama Property Company, a wholly-owned subsidiary of Alabama Power, of which $ 14 million was unused at June 30, 2025. Alabama Power is not party to this arrangement.

(c) Does not include Southern Power Company's $ 75 million and $ 100 million continuing letter of credit facilities for standby letters of credit, expiring in 2027 and 2028, respectively, of which $ 17 million and $ 4 million, respectively, was unused at June 30, 2025. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(d) 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 2030. Southern Company Gas' committed credit arrangement expiring in 2030 also includes $ 800 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 2030, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

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As reflected in the table above, in March 2025, (i) Southern Company and Southern Power amended and restated their combined multi-year credit arrangement to include Mississippi Power, increase the total credit arrangement from $ 2.45 billion to $ 3.25 billion (currently allocated $ 2.50 billion for Southern Company, $ 600 million for Southern Power, and $ 150 million for Mississippi Power), and extend the maturity date from 2029 to 2030; (ii) Southern Company increased its $ 150 million credit arrangement to $ 500 million and extended the maturity date from 2025 to 2027; (iii) Georgia Power increased its $ 1.75 billion credit arrangement to $ 2.05 billion and extended the maturity date from 2029 to 2030; and (iv) Southern Company Gas Capital, along with Nicor Gas, increased its $ 1.5 billion credit arrangement to $ 1.6 billion (currently allocated $ 800 million for each of Southern Company Gas Capital and Nicor Gas). Also in March 2025, (i) Georgia Power terminated $ 300 million of credit arrangements expiring in 2025, (ii) Mississippi Power terminated $ 150 million of credit arrangements expiring in 2027, and (iii) Nicor Gas terminated a $ 100 million credit arrangement expiring in 2025. Alabama Power and Southern Company Gas Capital, along with Nicor Gas, entered into agreements in March 2025 to extend the maturity date of each of their respective multi-year credit agreements in May 2025 from 2029 to 2030. In May and June 2025, SEGCO amended its credit arrangements aggregating $ 30 million, which extended the maturity dates from 2025 to 2026.

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 June 30, 2025, 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 June 30, 2025, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $ 1.5 billion (comprised of approximately $ 796 million at Alabama Power, $ 667 million at Georgia Power, and $ 69 million at Mississippi Power). Subsequent to June 30, 2025, Mississippi Power repaid at maturity approximately $ 11 million of its $ 69 million variable rate demand revenue bonds. In addition, at June 30, 2025, Alabama Power and Georgia Power had approximately $ 280 million and $ 501 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. Alabama Power's $ 280 million of fixed rate revenue bonds are classified as securities due within one year on its balance sheets as they are not covered by long-term committed credit. All other 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 May 2025, Southern Company issued $ 1.65 billion aggregate principal amount of Series 2025A 3.25 % Convertible Senior Notes due June 15, 2028 (Series 2025A Convertible Senior Notes). Southern Company used a portion of the proceeds from the Series 2025A Convertible Senior Notes to repurchase approximately $ 781.6 million of the $ 1.725 billion aggregate principal amount outstanding of its Series 2023A 3.875 % Convertible Senior Notes due December 15, 2025 and approximately $ 328.1 million of the $ 1.5 billion aggregate principal amount outstanding of its Series 2024A 4.50 % Convertible Senior Notes due June 15, 2027, in each case, through privately negotiated transactions with a limited number of holders thereof. Southern Company evaluated these repurchases and determined that all of the repurchased notes were accounted for as extinguishment of debt. As a result of these transactions, Southern Company recognized a $ 129 million loss on extinguishment of debt in the second quarter 2025 within interest expense in the consolidated statements of income.

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Interest on the Series 2025A Convertible Senior Notes is payable semiannually, beginning December 15, 2025. The Series 2025A Convertible Senior Notes will mature on June 15, 2028, unless earlier converted or repurchased, but are not redeemable at the option of Southern Company. The Series 2025A 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 2025A Convertible Senior Notes at their option prior to the close of business on the business day preceding March 15, 2028, 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 2025A Convertible Senior Notes, as determined by Southern Company following a request by a holder of Series 2025A 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 2025A Convertible Senior Notes.

On or after March 15, 2028, a holder may convert all or any portion of its Series 2025A 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 2025A Convertible Senior Notes by paying cash up to the aggregate principal amount of the Series 2025A 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 2025A Convertible Senior Notes being converted. The Series 2025A Convertible Senior Notes are initially convertible at a rate of 8.8077 shares of common stock per $1,000 principal amount converted, which is approximately equal to $ 113.54 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 2025A 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, other than an excluded fundamental change (each as defined in the indenture governing the Series 2025A Convertible Senior Notes), holders of the Series 2025A Convertible Senior Notes may require Southern Company to purchase all or a portion of their Series 2025A 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 2025A Convertible Senior Notes to be purchased plus any accrued and unpaid interest.

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Equity Distribution Agreement

See Note 8 to the financial statements under "Equity Distribution Agreement" in Item 8 of the Form 10-K for additional information.

The table below reflects shares of Southern Company common stock sold under separate forward sale contracts with forward purchasers during the six months ended June 30, 2025.

Shares Sold			Initial Forward Price per Share			To be Settled On or Before
292,694 (a)			$ 83.3293			December 31, 2025
563,386			$ 87.9027			December 31, 2025
1,000,000			$ 88.7502			June 30, 2026
1,000,000			$ 88.7739			June 30, 2026
1,000,000			$ 91.2856			June 30, 2026
1,000,000			$ 89.1444			June 30, 2026
1,000,000			$ 88.8490			June 30, 2026
1,000,000			$ 88.8903			June 30, 2026
1,000,000			$ 90.9196			June 30, 2026
1,255,000			$ 91.0566			June 30, 2026
1,324,942			$ 88.7048			December 31, 2026
2,277,113			$ 88.3227			December 31, 2026
3,130,641			$ 88.2823			December 31, 2026
3,255,866			$ 89.4692			December 31, 2026
1,849,629 (b)			$ 90.6617 (b)			December 31, 2026

(a) The total number of shares sold under this forward sale contract is 436,614 , of which the first 143,920 shares were sold in December 2024.

(b) The total number of shares sold under this forward sale contract is 3,850,000 , of which the remaining 2,000,371 shares were sold subsequent to June 30, 2025. The initial forward price was determined after the completion of sales by the forward seller in July 2025.

As of June 30, 2025, Southern Company had entered into separate forward sale contracts with forward purchasers for a total of 25,093,562 shares of common stock, of which 23,093,191 shares had been sold by the forward sellers, and no shares had been settled under the forward sale contracts.

Each initial forward price is subject to adjustment under certain circumstances as specified in the forward sales contract. Southern Company may settle these forward transactions in shares, cash, or net shares.

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, forward sale contracts pursuant to the equity distribution agreement, and convertible senior notes. EPS dilution resulting from stock-based compensation plans and the forward sale contracts is determined using the treasury stock method, and EPS dilution resulting from the convertible senior notes is determined using the net share settlement method. See "Convertible Senior Notes" and "Equity Distribution Agreement" herein and Note 8 to the financial statements under "Convertible Senior Notes"

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and "Equity Distribution Agreement" and Note 12 to the financial statements in Item 8 of the Form 10-K for additional information. Shares used to compute diluted EPS were as follows:

			Three Months Ended June 30,						Six Months Ended June 30,
			2025			2024			2025			2024
			(in millions)
As reported shares			1,101			1,096			1,100			1,095
Effect of stock-based compensation			6			6			6			6
Effect of convertible senior notes			1			—			1			—
Diluted shares			1,108			1,102			1,107			1,101

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 the three and six months ended June 30, 2025, dilution resulting from forward sale contracts was immaterial.

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

Current and Deferred Income Taxes

In 2024, Alabama Power, Georgia Power, and Southern Power entered into agreements with non-affiliated parties to transfer ITCs and PTCs at a discount to the generated credit value in 2024, 2025, and 2026. During the first six months of 2025, Alabama Power, Georgia Power, and Southern Power received cash of $ 44 million, $ 28 million, and $ 13 million, respectively, from credits transferred. The discount is recorded as a reduction in tax credits recognized in the financial statements and does not have a material impact on results of operations. The Southern Company system continues to explore the ability to efficiently monetize its tax credits through third-party transfer agreements.

Pursuant to certain joint ownership agreements, Georgia Power paid $ 81 million in the second quarter 2025 to the other Vogtle Owners for advanced nuclear PTCs for Plant Vogtle Units 3 and 4. The gain was recognized in 2025 as an income tax benefit and was immaterial.

Tax Credit and Net Operating Loss Carryforwards

Southern Company's federal PTC and ITC carryforwards are expected to be fully utilized by 2030. The utilization of each Registrant's estimated federal and state tax attributes and related valuation allowances could be impacted by numerous factors, including the acquisition of additional renewable energy and battery energy storage projects, changes in taxable income projections, and potential income tax rate changes. See Notes (B) and (K) under "Georgia Power" and "Southern Power," respectively, herein for information regarding current renewable energy and battery energy storage projects.

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.

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 21.1 % for the six months ended June 30, 2025 compared to 18.5 % for the corresponding period in 2024. The effective tax rate increase was primarily due to charges to a valuation allowance on certain state tax credit carryforwards at Georgia Power, the recognition of certain state tax positions

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from amended returns in the second quarter 2024 at Georgia Power, and a decrease in the flowback of certain excess deferred income taxes at Alabama Power, partially offset by increases in the flowback of excess state deferred income taxes and in the generation of advanced nuclear PTCs at Georgia Power.

Alabama Power

Alabama Power's effective tax rate was 23.0 % for the six months ended June 30, 2025 compared to 21.0 % for the corresponding period in 2024. The effective tax rate increase was primarily due to a decrease in the flowback of certain excess deferred income taxes.

Georgia Power

Georgia Power's effective tax rate was 21.7 % for the six months ended June 30, 2025 compared to 18.4 % for the corresponding period in 2024. The effective tax rate increase was primarily due to charges to a valuation allowance on certain state tax credit carryforwards and the recognition of certain state tax positions from amended returns in the second quarter 2024, partially offset by increases in the flowback of excess state deferred income taxes and in the generation of advanced nuclear PTCs.

Mississippi Power

Mississippi Power's effective tax rate was 22.8 % for the six months ended June 30, 2025 compared to 18.4 % for the corresponding period in 2024. The effective tax rate increase was primarily due to a decrease in the flowback of certain excess deferred income taxes.

Southern Power

Southern Power's effective tax benefit rate was ( 7.0 )% for the six months ended June 30, 2025 compared to ( 0.8 )% for the corresponding period in 2024. The effective tax rate decrease was primarily due to a change in pre-tax earnings attributable to Southern Power, including the impact of accelerated depreciation related to wind repowering projects and changes in tax rates resulting from tax legislation enacted by the State of Georgia in the second quarters of 2024 and 2025. See Note (K) under "Southern Power – Wind Repowering Projects" herein for additional information.

Southern Company Gas

Southern Company Gas' effective tax rate was 23.7 % for the six months ended June 30, 2025 compared to 25.1 % for the corresponding period in 2024. The effective tax rate decrease was primarily due to an increase in the flowback of excess state deferred income taxes.

Unrecognized Tax Benefits

Southern Company's, Alabama Power's, and Georgia Power's unrecognized tax positions balances at June 30, 2025 were $ 382 million, $ 144 million, and $ 188 million, respectively. At December 31, 2024, Southern Company's and Georgia Power's unrecognized tax positions balances were $ 82 million and $ 34 million, respectively, and Alabama Power had no unrecognized tax positions. The increases from prior periods are related to Alabama Power's and Georgia Power's ability to meet prevailing wage requirements related to existing zero-emission nuclear power PTCs and will not impact Southern Company's, Alabama Power's, and Georgia Power's effective tax rates if recognized. The ultimate outcome of this unrecognized tax benefit, which is expected to be resolved within the next 12 months, is dependent on acceptance by the IRS and cannot be determined at this time.

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. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2025. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly

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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.

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 six months ended June 30, 2025 and 2024 are presented in the following tables.

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			Southern Company						Alabama Power						Georgia Power						Mississippi Power						Southern Power						Southern Company Gas
			(in millions)
Three Months Ended June 30, 2025
Pension Plans
Service cost			$	66					$	15					$	15					$	2					$	2					$	7
Interest cost			166						38						49						8						3						11
Expected return on plan assets			( 320 )						( 78 )						( 99 )						( 14 )						( 4 )						( 22 )
Amortization:
Prior service costs			—						—						1						—						—						( 1 )
Regulatory asset			—						—						—						—						—						4
Net (gain) loss			10						4						3						—						( 2 )						—
Net periodic pension income			$	( 78 )					$	( 21 )					$	( 31 )					$	( 4 )					$	( 1 )					$	( 1 )
Postretirement Benefits
Service cost			$	3					$	1					$	1					$	—					$	—					$	—
Interest cost			18						4						7						—						—						2
Expected return on plan assets			( 22 )						( 9 )						( 8 )						—						—						( 2 )
Amortization:
Regulatory asset			—						—						—						—						—						2
Net (gain) loss			( 4 )						—						( 2 )						1						—						( 2 )
Net periodic postretirement benefit cost (income)			$	( 5 )					$	( 4 )					$	( 2 )					$	1					$	—					$	—
Six Months Ended June 30, 2025
Pension Plans
Service cost			$	132					$	30					$	31					$	5					$	3					$	13
Interest cost			332						77						98						15						5						22
Expected return on plan assets			( 640 )						( 156 )						( 198 )						( 29 )						( 8 )						( 43 )
Amortization:
Prior service costs			—						—						1						—						—						( 1 )
Regulatory asset			—						—						—						—						—						8
Net (gain) loss			19						6						7						1						( 1 )						—
Net periodic pension income			$	( 157 )					$	( 43 )					$	( 61 )					$	( 8 )					$	( 1 )					$	( 1 )
Postretirement Benefits
Service cost			$	6					$	2					$	2					$	—					$	—					$	—
Interest cost			35						8						13						1						—						4
Expected return on plan assets			( 45 )						( 18 )						( 16 )						—						—						( 4 )
Amortization:
Prior service costs			1						—						—						—						—						—
Regulatory asset			—						—						—						—						—						3
Net gain			( 7 )						—						( 2 )						—						—						( 4 )
Net periodic postretirement benefit cost (income)			$	( 10 )					$	( 8 )					$	( 3 )					$	1					$	—					$	( 1 )

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			Southern Company						Alabama Power						Georgia Power						Mississippi Power						Southern Power						Southern Company Gas
			(in millions)
Three Months Ended June 30, 2024
Pension Plans
Service cost			$	73					$	17					$	17					$	3					$	1					$	7
Interest cost			158						37						48						7						2						11
Expected return on plan assets			( 315 )						( 76 )						( 98 )						( 15 )						( 4 )						( 21 )
Amortization:
Prior service costs			—						—						1						—						—						( 1 )
Regulatory asset			—						—						—						—						—						4
Net loss			13						4						4						2						1						—
Net periodic pension income			$	( 71 )					$	( 18 )					$	( 28 )					$	( 3 )					$	—					$	—
Postretirement Benefits
Service cost			$	3					$	1					$	1					$	—					$	—					$	—
Interest cost			17						4						5						—						—						2
Expected return on plan assets			( 22 )						( 8 )						( 8 )						—						—						( 2 )
Amortization:
Regulatory asset			—						—						—						—						—						2
Net gain			( 4 )						( 2 )						—						—						—						( 1 )
Net periodic postretirement benefit cost (income)			$	( 6 )					$	( 5 )					$	( 2 )					$	—					$	—					$	1
Six Months Ended June 30, 2024
Pension Plans
Service cost			$	146					$	34					$	35					$	6					$	3					$	14
Interest cost			317						74						96						14						4						21
Expected return on plan assets			( 631 )						( 153 )						( 197 )						( 29 )						( 8 )						( 43 )
Amortization:
Prior service costs			—						—						1						—						—						( 1 )
Regulatory asset			—						—						—						—						—						8
Net loss			27						8						9						2						1						—
Net periodic pension income			$	( 141 )					$	( 37 )					$	( 56 )					$	( 7 )					$	—					$	( 1 )
Postretirement Benefits
Service cost			$	7					$	2					$	2					$	—					$	—					$	—
Interest cost			33						8						11						1						—						4
Expected return on plan assets			( 44 )						( 17 )						( 16 )						—						—						( 4 )
Amortization:
Prior service costs			1						—						—						—						—						—
Regulatory asset			—						—						—						—						—						3
Net gain			( 8 )						( 2 )						( 1 )						( 1 )						—						( 3 )
Net periodic postretirement benefit income			$	( 11 )					$	( 9 )					$	( 4 )					$	—					$	—					$	—

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At June 30, 2025, 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 June 30, 2025			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)			$	11					$	122					$	—					$	—					$	133
Interest rate derivatives			—						9						—						—						9
Foreign currency derivatives			—						34						—						—						34
Investments in trusts: (b)
Domestic equity			876						268						—						—						1,144
Foreign equity			164						206						—						—						370
U.S. Treasury and government agency securities			—						355						—						—						355
Municipal bonds			—						48						—						—						48
Pooled funds – fixed income			—						5						—						—						5
Corporate bonds			—						495						—						—						495
Mortgage- and asset-backed securities			—						122						—						—						122
Private equity			—						—						—						191						191
Cash and cash equivalents			1						—						—						—						1
Other			33						3						—						9						45
Investments, available-for-sale:
U.S. Treasury and government agency securities			1						10						—						—						11
Corporate bonds			—						2						—						—						2
Mortgage- and asset-backed securities			—						9						—						—						9
Cash equivalents and restricted cash			631						18						—						—						649
Other investments			10						37						8						—						55
Total			$	1,727					$	1,743					$	8					$	200					$	3,678
Liabilities:
Energy-related derivatives (a)			$	6					$	66					$	—					$	—					$	72
Interest rate derivatives			—						206						—						—						206
Foreign currency derivatives			—						22						—						—						22
Contingent consideration			3						—						14						—						17
Other			—						13						11						—						24
Total			$	9					$	307					$	25					$	—					$	341

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			Fair Value Measurements Using
At June 30, 2025			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)
Alabama Power
Assets:
Energy-related derivatives			$	—					$	47					$	—					$	—					$	47
Nuclear decommissioning trusts: (b)
Domestic equity			470						258						—						—						728
Foreign equity			164						—						—						—						164
U.S. Treasury and government agency securities			—						17						—						—						17
Municipal bonds			—						1						—						—						1
Corporate bonds			—						299						—						—						299
Mortgage- and asset-backed securities			—						33						—						—						33
Private equity			—						—						—						191						191
Other			11						1						—						9						21
Cash equivalents			145						18						—						—						163
Other investments			—						37						—						—						37
Total			$	790					$	711					$	—					$	200					$	1,701
Liabilities:
Energy-related derivatives			$	—					$	23					$	—					$	—					$	23
Georgia Power
Assets:
Energy-related derivatives			$	—					$	35					$	—					$	—					$	35
Nuclear decommissioning trusts: (b)
Domestic equity			406						1						—						—						407
Foreign equity			—						205						—						—						205
U.S. Treasury and government agency securities			—						338						—						—						338
Municipal bonds			—						47						—						—						47
Corporate bonds			—						196						—						—						196
Mortgage- and asset-backed securities			—						89						—						—						89
Other			22						2						—						—						24
Total			$	428					$	913					$	—					$	—					$	1,341
Liabilities:
Energy-related derivatives			$	—					$	19					$	—					$	—					$	19
Interest rate derivatives			—						1						—						—						1
Total			$	—					$	20					$	—					$	—					$	20

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			Fair Value Measurements Using
At June 30, 2025			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			$	—					$	28					$	—					$	—					$	28
Cash equivalents			2						—						—						—						2
Total			$	2					$	28					$	—					$	—					$	30
Liabilities:
Energy-related derivatives			$	—					$	19					$	—					$	—					$	19
Southern Power
Assets:
Energy-related derivatives			$	—					$	4					$	—					$	—					$	4
Foreign currency derivatives			—						26						—						—						26
Total			$	—					$	30					$	—					$	—					$	30
Liabilities:
Contingent consideration			3						—						14						—						17
Other			—						13						11						—						24
Total			$	3					$	13					$	25					$	—					$	41
Southern Company Gas
Assets:
Energy-related derivatives (a)			$	11					$	8					$	—					$	—					$	19
Interest rate derivatives			—						4						—						—						4
Non-qualified deferred compensation trusts:
Domestic equity			—						9						—						—						9
Foreign equity			—						1						—						—						1
Pooled funds – fixed income			—						5						—						—						5
Cash and cash equivalents			1						—						—						—						1
Cash equivalents			212						—						—						—						212
Total			$	224					$	27					$	—					$	—					$	251
Liabilities:
Energy-related derivatives (a)			$	6					$	5					$	—					$	—					$	11
Interest rate derivatives			—						63						—						—						63
Total			$	6					$	68					$	—					$	—					$	74

(a) Excludes cash collateral of $ 6 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 under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

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

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the three and six months ended June 30, 2025 and 2024. 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 June 30,						Six Months Ended June 30,
Fair value increases (decreases)			2025			2024			2025			2024
			(in millions)
Southern Company			$	165		$	32		$	159		$	135
Alabama Power			99			19			86			87
Georgia Power			66			13			73			48

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.

Southern Company's investments, available for sale relate to a wholly-owned subsidiary that insures various risk exposures of Southern Company and its subsidiaries. Corporate and municipal bonds, government agency securities, and commercial paper are valued using pricing models maximizing the use of observable inputs for similar securities, including basing value on yields currently available on comparable securities of issues with similar credit ratings. Mortgage- and asset-backed securities are valued through an analysis of the underlying assets and a review of the documentation, including financials, the manager's valuation methodology in valuing their underlying assets, the types of assets and risks involved, and the investor's exit and termination parameters.

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

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and continuing through 2026 and 2036, 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 the obligations 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 June 30, 2025, 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 $ 200 million and unfunded commitments related to the private market investments totaled $ 101 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 June 30, 2025, 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			$	68.1		$	11.5		$	19.3		$	1.8		$	2.7		$	8.5
Fair value			63.6			10.3			17.7			1.6			2.7			7.5

(*) 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.

The Registrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities 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.

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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 natural gas 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 natural gas 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 June 30, 2025, 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 (*)			415						2030						2028
Alabama Power			130						2028						—
Georgia Power			110						2028						—
Mississippi Power			102						2029						—
Southern Power			8						2030						2025
Southern Company Gas (*)			65						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 78.6 million mmBtu long natural gas positions and 13.6 million mmBtu short natural gas positions at June 30, 2025, 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 2.4 million mmBtu for Southern Company, which includes 0.6 million mmBtu for Alabama Power, 0.9 million mmBtu for Georgia Power, 0.4 million mmBtu for Mississippi Power, and 0.5 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2026 is immaterial for Southern Company, Southern Power, and Southern Company Gas.

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 June 30, 2025, 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 June 30, 2025
			(in millions)												(in millions)
Cash Flow Hedges of Forecasted Debt
Southern Company Gas			$	250		4.03 %			N/A			September 2025			$	4
Georgia Power			275			4.29 %			N/A			August 2025			( 1 )
Fair Value Hedges of Existing Debt
Southern Company parent			400			1-month SOFR + 0.80 %			1.75 %			March 2028			( 30 )
Southern Company parent			1,000			1-month SOFR + 2.48 %			3.70 %			April 2030			( 106 )
Southern Company parent			565			1-month SOFR + 1.56 %			6.50 %			March 2045			( 1 )
Southern Company Gas			500			1-month SOFR + 0.49 %			1.75 %			January 2031			( 63 )
Southern Company			$	2,990											$	( 197 )

For cash flow hedges of interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the 12-month period ending June 30, 2026 are immaterial for Southern Company, 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 2054 for Southern Company, Georgia Power, and Mississippi Power, 2052 for Alabama 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.

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At June 30, 2025, the following foreign currency derivatives were outstanding:

			Pay Notional			Pay Rate			Receive Notional			Receive Rate			Hedge Maturity Date			Fair Value Gain (Loss) at June 30, 2025
			(in millions)						(in millions)									(in millions)
Cash Flow Hedges of Existing Debt
Southern Power			$	564		3.78 %			€	500		1.85 %			June 2026			$	26
Fair Value Hedges of Existing Debt
Southern Company parent			1,476			3.39 %			1,250			1.88 %			September 2027			( 14 )
Southern Company			$	2,040					€	1,750								$	12

For cash flow hedges of foreign currency derivatives, the estimated pre-tax gains expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2026 are $ 26 million for Southern Power.

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.

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The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected as either assets or liabilities in the balance sheets (included in "Other" or shown separately as "Risk Management Activities") as follows:

			At June 30, 2025						At December 31, 2024
Derivative Category and Balance Sheet Location			Assets			Liabilities			Assets			Liabilities
			(in millions)
Southern Company
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current			$	57		$	38		$	33		$	82
Non-current			63			26			42			40
Total derivatives designated as hedging instruments for regulatory purposes			120			64			75			122
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Current			5			2			4			3
Non-current			4			—			4			—
Interest rate derivatives:
Current			9			57			—			61
Non-current			—			149			—			208
Foreign currency derivatives:
Current			26			22			—			36
Non-current			8			—			—			182
Total derivatives designated as hedging instruments in cash flow and fair value hedges			52			230			8			490
Energy-related derivatives not designated as hedging instruments
Current			4			6			5			3
Non-current			—			—			1			—
Total derivatives not designated as hedging instruments			4			6			6			3
Gross amounts recognized			176			300			89			615
Gross amounts offset (a)			( 56 )			( 62 )			( 44 )			( 61 )
Net amounts recognized in the Balance Sheets (b)			$	120		$	238		$	45		$	554
Alabama Power
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current			$	23		$	13		$	11		$	30
Non-current			24			10			15			12
Total derivatives designated as hedging instruments for regulatory purposes			47			23			26			42
Gross amounts offset			( 20 )			( 20 )			( 19 )			( 19 )
Net amounts recognized in the Balance Sheets			$	27		$	3		$	7		$	23

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			At June 30, 2025						At December 31, 2024
Derivative Category and Balance Sheet Location			Assets			Liabilities			Assets			Liabilities
			(in millions)
Georgia Power
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current			$	15		$	11		$	6		$	32
Non-current			20			6			13			9
Total derivatives designated as hedging instruments for regulatory purposes			35			17			19			41
Interest rate derivatives designated as hedging instruments in cash flow and fair value hedges
Current			—			1			—			—
Energy-related derivatives not designated as hedging instruments
Current			—			2			—			1
Gross amounts recognized			35			20			19			42
Gross amounts offset			( 16 )			( 16 )			( 15 )			( 15 )
Net amounts recognized in the Balance Sheets			$	19		$	4		$	4		$	27
Mississippi Power
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current			$	9		$	9		$	5		$	15
Non-current			19			10			14			19
Total derivatives designated as hedging instruments for regulatory purposes			28			19			19			34
Gross amounts offset			( 16 )			( 16 )			( 17 )			( 17 )
Net amounts recognized in the Balance Sheets			$	12		$	3		$	2		$	17
Southern Power
Derivatives designated as hedging instruments in cash flow hedges
Energy-related derivatives:
Current			$	1		$	—		$	1		$	—
Non-current			3			—			3			—
Foreign currency derivatives:
Current			26			—			—			11
Non-current			—			—			—			40
Total derivatives designated as hedging instruments in cash flow hedges			30			—			4			51
Net amounts recognized in the Balance Sheets			$	30		$	—		$	4		$	51

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			At June 30, 2025						At December 31, 2024
Derivative Category and Balance Sheet Location			Assets			Liabilities			Assets			Liabilities
			(in millions)
Southern Company Gas
Energy-related derivatives designated as hedging instruments for regulatory purposes
Current			$	10		$	5		$	11		$	5
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Current			4			2			3			3
Non-current			1			—			1			—
Interest rate derivatives:
Current			4			15			—			17
Non-current			—			48			—			67
Total derivatives designated as hedging instruments in cash flow and fair value hedges			9			65			4			87
Energy-related derivatives not designated as hedging instruments
Current			4			4			5			2
Non-current			—			—			1			—
Total derivatives not designated as hedging instruments			4			4			6			2
Gross amounts recognized			23			74			21			94
Gross amounts offset (a)			( 4 )			( 10 )			7			( 10 )
Net amounts recognized in the Balance Sheets (b)			$	19		$	64		$	28		$	84

(a) Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $ 6 million and $ 17 million at June 30, 2025 and December 31, 2024, respectively.

(b) Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives at June 30, 2025 and December 31, 2024.

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At June 30, 2025 and December 31, 2024, 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 June 30, 2025:
Energy-related derivatives:
Other regulatory assets, current			$	( 8 )		$	( 3 )		$	( 1 )		$	( 3 )		$	( 1 )
Other regulatory liabilities, current			26			13			5			3			5
Other regulatory liabilities, deferred			37			14			14			9			—
Total energy-related derivative gains (losses)			$	55		$	24		$	18		$	9		$	4
At December 31, 2024:
Energy-related derivatives:
Other regulatory assets, current			$	( 61 )		$	( 23 )		$	( 26 )		$	( 11 )		$	( 1 )
Other regulatory assets, deferred			( 5 )			—			—			( 5 )			—
Other regulatory liabilities, current			8			4			—			—			4
Other regulatory liabilities, deferred			8			3			4			1			—
Total energy-related derivative gains (losses)			$	( 50 )		$	( 16 )		$	( 22 )		$	( 15 )		$	3

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For the three and six months ended June 30, 2025 and 2024, 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			Three Months Ended June 30,						Six Months Ended June 30,
			2025			2024			2025			2024
			(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives			$	( 13 )		$	3		$	6		$	( 5 )
Interest rate derivatives			9			1			5			24
Foreign currency derivatives			47			( 6 )			67			( 20 )
Fair value hedges (*) :
Foreign currency derivatives			3			( 4 )			( 13 )			( 4 )
Total			$	46		$	( 6 )		$	65		$	( 5 )
Georgia Power
Cash flow hedges:
Interest rate derivatives			$	5		$	—		$	3		$	16
Mississippi Power
Cash flow hedges:
Interest rate derivatives			$	—		$	—		$	—		$	7
Southern Power
Cash flow hedges:
Energy-related derivatives			$	( 1 )		$	1		$	2		$	—
Foreign currency derivatives			47			( 6 )			67			( 20 )
Total			$	46		$	( 5 )		$	69		$	( 20 )
Southern Company Gas
Cash flow hedges:
Energy-related derivatives			$	( 12 )		$	2		$	4		$	( 5 )
Interest rate derivatives			4			1			4			1
Total			$	( 8 )		$	3		$	8		$	( 4 )

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

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For the three and six months ended June 30, 2025 and 2024, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

						Gain (Loss)
Statements of Income Location			Derivative Category			Three Months Ended June 30,						Six Months Ended June 30,
						2025			2024			2025			2024
						(in millions)
Southern Company
Fuel			Energy-related cash flow hedges			$	—		$	( 1 )		$	1		$	( 2 )
Cost of natural gas			Energy-related cash flow hedges			1			( 7 )			—			( 30 )
Other operations and maintenance			Energy-related cash flow hedges			—			—			—			( 1 )
Interest expense, net of amounts capitalized			Interest rate cash flow hedges			( 3 )			( 4 )			( 6 )			( 8 )
			Foreign currency cash flow hedges			( 2 )			( 3 )			( 5 )			( 6 )
			Interest rate fair value hedges			29			—			69			( 31 )
Other income (expense), net			Foreign currency cash flow hedges			45			( 5 )			67			( 17 )
			Foreign currency fair value hedges			115			( 18 )			155			21
			Amount excluded from effectiveness testing recognized in earnings			( 3 )			5			13			5
Southern Power
Fuel			Energy-related cash flow hedges			$	—		$	( 1 )		$	1		$	( 2 )
Interest expense, net of amounts capitalized			Foreign currency cash flow hedges			( 2 )			( 3 )			( 5 )			( 6 )
Other income (expense), net			Foreign currency cash flow hedges			45			( 5 )			67			( 17 )
Southern Company Gas
Cost of natural gas			Energy-related cash flow hedges			$	1		$	( 7 )		$	—		$	( 30 )
Operations and maintenance			Energy-related cash flow hedges			—			—			—			( 1 )
Interest expense, net of amounts capitalized			Interest rate fair value hedges			3			( 6 )			21			( 10 )

At June 30, 2025 and December 31, 2024, 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 June 30, 2025			At December 31, 2024			At June 30, 2025			At December 31, 2024
			(in millions)
Southern Company
Long-term debt			$	( 3,798 )		$	( 2,936 )		$	164		$	242
Southern Company Gas
Long-term debt			$	( 442 )		$	( 422 )		$	56		$	75

Pre-tax gains (losses) on energy-related derivatives not designated as hedging instruments were $( 14 ) million and $ 16 million for the three months ended June 30, 2025 and 2024, respectively, and $( 6 ) million and $ 63 million for the six months ended June 30, 2025 and 2024, respectively, and reflected in cost of natural gas on the statements of income of Southern Company and Southern Company Gas.

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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 June 30, 2025, 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 $ 35 million at June 30, 2025. 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 $ 13 million at June 30, 2025. 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 June 30, 2025. 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 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 June 30, 2025, cash collateral posted in these accounts was immaterial for Alabama Power and Southern 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, which are netted with energy-related derivatives recognized in the balance sheets.

The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants generally enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's, S&P, or Fitch 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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See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.

Alabama Power

On June 6, 2025, the FERC approved Alabama Power's acquisition of Tenaska Alabama Partners, L.P., which owns and operates the Lindsay Hill Generating Station. The ultimate outcome of this matter cannot be determined at this time. See Note (B) under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information.

Mississippi Power

On June 19, 2025, the Florida PSC issued a final order approving the transfer of FP&L's 50 % ownership interest in Plant Daniel Units 1 and 2 to Mississippi Power. On July 30, 2025, Mississippi Power completed the acquisition of FP&L's 50 % interest in Plant Daniel Units 1 and 2 and, as part of the acquisition, received approximately $ 36 million from FP&L. See Note 2 to the financial statements under "Mississippi Power – Plant Daniel" in Item 8 of the Form 10-K for additional information.

Southern Power

Construction Projects

During the six months ended June 30, 2025, Southern Power continued construction of the three phases of the 512 -MW Millers Branch solar facility. At June 30, 2025, the total cost of construction incurred for the Millers Branch project was $ 537 million, which is primarily included in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Project Facility

Resource

Approximate Nameplate Capacity ( MW )

Location

Projected COD

PPA Contract Period

Projects Under Construction at June 30, 2025

Millers Branch

Phase I

Solar

200

Haskell County, TX

Fourth quarter 2025

20 years

Phase II

Solar

180

Haskell County, TX

Second quarter 2026

15 years

Phase III

Solar

132

Haskell County, TX

Fourth quarter 2026

15 years

Wind Repowering Projects

During the six months ended June 30, 2025, Southern Power continued the development project to repower the Kay Wind facility. In addition, Southern Power committed to development projects to repower the Grant Plains, Grant Wind, and Wake Wind facilities. At June 30, 2025, the total cost of construction incurred related to the projects was

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$ 89 million and is included in CWIP. The repowered output of the facilities is contracted under new and amended PPAs. The ultimate outcome of these matters cannot be determined at this time.

Project Facility

Resource

Approximate Nameplate Capacity ( MW )

Location

Projected COD

Projects Under Construction at June 30, 2025

Kay Wind (*)

Wind

200

Kay County, OK

Third quarter 2026

Grant Plains

Wind

147

Grant County, OK

Fourth quarter 2026

Grant Wind

Wind

152

Grant County, OK

Fourth quarter 2026

Wake Wind

Wind

257

Crosby & Floyd Counties, TX

Second quarter 2027

(*) The facility has a total capacity of 299 MWs, of which 200 MWs is projected to be repowered and is contracted under an amended PPA.

See Note 16 to the financial statements in Item 8 of the Form 10-K for additional information.

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, operates, 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. While the traditional electric operating companies represent three separate operating segments, they are vertically integrated utilities providing electric service to retail customers, as well as wholesale customers, in the Southeast and have been aggregated into one reportable segment. Revenues from sales by Southern Power to the traditional electric operating companies were $ 114 million and $ 229 million for the three and six months ended June 30, 2025, respectively, and $ 86 million and $ 179 million for the three and six months ended June 30, 2024, 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.

Southern Company's CODM utilizes segment net income, including variances to budget and forecasts, to assess performance and is not provided with segment expense information. To achieve the consolidated net income goal, Southern Company's CODM sets net income expectations for each operating segment, which is expected to monitor its expenses in order to achieve its assigned net income target. Therefore, Southern Company has no reportable significant segment expenses.

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Financial data for business segments for the three and six months ended June 30, 2025 and 2024 was as follows:

			Electric Utilities
			Traditional Electric Operating Companies			Southern Power			Eliminations			Total			Southern Company Gas			Total Reportable Segments			All Other			Eliminations			Consolidated
			(in millions)
Three Months Ended June 30, 2025
Operating revenues			$	5,380		$	546		$	( 122 )		$	5,804		$	979		$	6,783		$	225		$	( 35 )		$	6,973
Other segment items (a)			2,674			296			( 122 )			2,848			599			3,447			193			( 23 )			3,617
Depreciation and amortization (b)			957			177			—			1,134			172			1,306			17			—			1,323
Earnings from equity method investments			4			—			—			4			23			27			( 17 )			—			10
Interest expense (c)			336			24			—			360			92			452			422			—			874
Income taxes (benefit)			370			( 2 )			—			368			33			401			( 112 )			—			289
Segment net income (loss) (b)(c)(d)			$	1,047		$	51		$	—		$	1,098		$	106		$	1,204		$	( 312 )		$	( 12 )		$	880
Six Months Ended June 30, 2025
Operating revenues			$	10,692		$	1,113		$	( 245 )		$	11,560		$	2,818		$	14,378		$	454		$	( 84 )		$	14,748
Other segment items (a)			5,468			599			( 245 )			5,822			1,670			7,492			401			( 81 )			7,812
Depreciation and amortization (b)			1,905			329			—			2,234			341			2,575			33			—			2,608
Earnings from equity method investments			2			—			—			2			62			64			( 21 )			—			43
Interest expense (c)			652			50			—			702			183			885			703			—			1,588
Income taxes (benefit)			596			( 3 )			—			593			162			755			( 186 )			—			569
Segment net income (loss) (b)(c)(d)			$	2,073		$	138		$	—		$	2,211		$	524		$	2,735		$	( 518 )		$	( 3 )		$	2,214
At June 30, 2025
Goodwill			$	—		$	2		$	—		$	2		$	5,015		$	5,017		$	144		$	—		$	5,161
Total assets			108,676			12,817			( 1,013 )			120,480			26,376			146,856			2,417			( 420 )			148,853

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			Electric Utilities
			Traditional Electric Operating Companies			Southern Power			Eliminations			Total			Southern Company Gas			Total Reportable Segments			All Other			Eliminations			Consolidated
			(in millions)
Three Months Ended June 30, 2024
Operating revenues			$	5,025		$	524		$	( 93 )		$	5,456		$	831		$	6,287		$	222		$	( 46 )		$	6,463
Other segment items (a)(e)			2,322			268			( 93 )			2,497			478			2,975			193			( 43 )			3,125
Depreciation and amortization			880			127			—			1,007			158			1,165			17			—			1,182
Earnings from equity method investments			—			—			—			—			32			32			( 1 )			—			31
Interest expense			323			30			—			353			83			436			259			( 1 )			694
Income taxes (benefit)			308			13			—			321			36			357			( 67 )			—			290
Segment net income (loss) (d)(e)			$	1,192		$	86		$	—		$	1,278		$	108		$	1,386		$	( 181 )		$	( 2 )		$	1,203
Six Months Ended June 30, 2024
Operating revenues			$	9,463		$	997		$	( 189 )		$	10,271		$	2,538		$	12,809		$	383		$	( 83 )		$	13,109
Other segment items (a)(e)			4,603			512			( 189 )			4,926			1,443			6,369			347			( 60 )			6,656
Depreciation and amortization			1,733			245			—			1,978			313			2,291			36			—			2,327
Earnings from equity method investments			2			—			—			2			76			78			( 2 )			1			77
Interest expense			635			59			—			694			167			861			508			( 11 )			1,358
Income taxes (benefit)			482			( 1 )			—			481			174			655			( 142 )			—			513
Segment net income (loss) (d)(e)			$	2,012		$	182		$	—		$	2,194		$	517		$	2,711		$	( 368 )		$	( 11 )		$	2,332
At December 31, 2024
Goodwill			$	—		$	2		$	—		$	2		$	5,015		$	5,017		$	144		$	—		$	5,161
Total assets			105,577			12,653			( 1,025 )			117,205			26,177			143,382			2,371			( 573 )			145,180

(a) Primarily consists of fuel, purchased power, cost of natural gas, cost of other sales, other operations and maintenance, taxes other than income taxes, AFUDC equity, non-service cost-related retirement benefits income, and net income (loss) attributable to noncontrolling interests.

(b) For Southern Power, includes accelerated depreciation related to the repowering of the Kay Wind, Grant Plains, and Grant Wind facilities of $ 42 million ($ 31 million after tax, net of noncontrolling interest impacts) and $ 69 million ($ 51 million after tax, net of noncontrolling interest impacts) for the three and six months ended June 30, 2025, respectively. See Note (K) under "Southern Power – Wind Repowering Projects" herein and Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.

(c) For all other, includes a pre-tax loss of $ 129 million ($ 97 million after tax) associated with the extinguishment of debt at the parent company. See Note (F) under "Convertible Senior Notes" herein for additional information.

(d) Attributable to Southern Company.

(e) For the traditional electric operating companies, includes a pre-tax credit to income at Georgia Power of $ 21 million ($ 16 million after tax) related to the estimated probable loss associated with the completion of Plant Vogtle Units 3 and 4, as well as a pre-tax gain at Georgia Power of approximately $ 114 million ($ 84 million after tax) related to the sale of transmission line assets under the integrated transmission system agreement. See Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information.

Traditional Electric Operating Companies

Each of the traditional electric operating companies' single reportable business segment is the sale of electricity.

Alabama Power and Georgia Power have identified utility operations and maintenance expenses as significant segment expenses provided to their CODMs. Utility operations and maintenance expenses is calculated as other operations and maintenance, as reflected on the statements of income, less expenses from unregulated products and

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services, losses (gains) on asset dispositions, impairment charges, amortization of cloud software, and, for Georgia Power, charges (credits) for estimated loss on Plant Vogtle Units 3 and 4. Alabama Power's utility operations and maintenance expenses are disaggregated into expenses related to Rate RSE and Rate CNP Compliance, which are not applicable to Georgia Power. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Financial data for Alabama Power's and Georgia Power's significant segment expenses and other segment information for the three and six months ended June 30, 2025 and 2024 was as follows:

			Three Months Ended June 30,						Six Months Ended June 30,
			2025			2024			2025			2024
			(in millions)
Alabama Power
Operating revenues			$	1,968		$	1,873		$	3,980		$	3,664
Utility operations and maintenance
Rate RSE expenses			374			339			739			664
Rate CNP Compliance expenses			67			66			142			129
Total utility operations and maintenance			441			405			881			793
Other segment items (a)			544			519			1,152			1,033
Depreciation and amortization			371			364			741			725
Interest expense			116			114			225			224
Income taxes			115			102			226			187
Segment net income			$	381		$	369		$	755		$	702
Capital expenditures			$	599		$	470		$	1,159		$	921
Georgia Power
Operating revenues			$	3,110		$	2,875		$	6,148		$	5,273
Utility operations and maintenance			568			499			1,104			962
Other segment items (a)(b)			989			790			2,106			1,610
Depreciation and amortization			512			447			1,015			872
Interest expense			198			185			385			359
Income taxes			236			192			334			271
Segment net income (b)			$	607		$	762		$	1,204		$	1,199
Capital expenditures			$	1,676		$	1,320		$	3,313		$	2,353

(a) Primarily consists of fuel, purchased power, expenses from unregulated products and services, losses (gains) on asset dispositions, amortization of cloud software, taxes other than income taxes, AFUDC equity, non-service cost-related retirement benefits income, and, for Georgia Power, charges (credits) for estimated loss on Plant Vogtle Units 3 and 4. Also includes earnings from equity method investments, which were immaterial for all periods presented.

(b) For the three and six months ended June 30, 2024, includes a pre-tax credit to income of $ 21 million ($ 16 million after tax) related to the estimated probable loss associated with the completion of Plant Vogtle Units 3 and 4, as well as a pre-tax gain of approximately $ 114 million ($ 84 million after tax) related to the sale of transmission line assets under the integrated transmission system agreement. See Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information.

Mississippi Power's CODM utilizes segment expense information in the form of variances to budget to assess performance; therefore, Mississippi Power has no reportable significant segment expenses. Mississippi Power's segment information for revenues, depreciation and amortization, interest expense, and income taxes is reflected on its statements of income. Mississippi Power's earnings from equity method investments are included in other income (expense), net on its statements of income and were immaterial for all periods presented. Other segment items primarily consist of fuel and purchased power, other operations and maintenance, taxes other than income taxes, and non-service cost-related retirement benefits income and totaled $ 252 million and $ 528 million for the

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three and six months ended June 30, 2025, respectively, and $ 221 million and $ 438 million for the three and six months ended June 30, 2024, respectively.

Southern Power

Southern Power's single reportable business segment is the sale of electricity in the competitive wholesale market. Southern Power's CODM utilizes segment expense information in the form of variances to budget to assess performance; therefore, Southern Power has no reportable significant segment expenses. Southern Power's segment information for revenues, depreciation and amortization, interest expense, and income taxes (benefit) is reflected on its consolidated statements of income. Southern Power had no earnings from equity method investments for any period presented. Other segment items primarily consist of fuel, purchased power, other operations and maintenance, taxes other than income taxes, and net income (loss) attributable to noncontrolling interests and totaled $ 296 million and $ 599 million for the three and six months ended June 30, 2025, respectively, and $ 268 million and $ 512 million for the three and six months ended June 30, 2024, respectively.

For the three and six months ended June 30, 2025, depreciation and amortization includes accelerated depreciation of $ 42 million ($ 31 million after tax, net of noncontrolling interest impacts) and $ 69 million ($ 51 million after tax, net of noncontrolling interest impacts), respectively, related to the repowering of the Kay Wind, Grant Plains, and Grant Wind facilities. See Note (K) under "Southern Power – Wind Repowering Projects" herein and Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.

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.

The gas distribution operations segment 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.

The gas pipeline investments segment 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.

The gas marketing services segment 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.

Southern Company Gas' CODM utilizes segment expense information in the form of variances to budget to assess performance; therefore, Southern Company Gas has no reportable significant segment expenses.

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Financial data for business segments for the three and six months ended June 30, 2025 and 2024 was as follows:

			Gas Distribution Operations			Gas Pipeline Investments			Gas Marketing Services			Total Reportable Segments			All Other			Eliminations			Consolidated
			(in millions)
Three Months Ended June 30, 2025
Operating revenues			$	885		$	8		$	83		$	976		$	5		$	( 2 )		$	979
Other segment items (*)			526			1			68			595			6			( 2 )			599
Depreciation and amortization			167			1			3			171			1			—			172
Earnings from equity method investments			—			23			—			23			—			—			23
Interest expense			82			9			1			92			—			—			92
Income taxes			19			5			3			27			6			—			33
Segment net income			$	91		$	15		$	8		$	114		$	( 8 )		$	—		$	106
Six Months Ended June 30, 2025
Operating revenues			$	2,454		$	16		$	345		$	2,815		$	9		$	( 6 )		$	2,818
Other segment items (*)			1,431			3			234			1,668			8			( 6 )			1,670
Depreciation and amortization			330			3			7			340			1			—			341
Earnings from equity method investments			—			62			—			62			—			—			62
Interest expense			164			18			1			183			—			—			183
Income taxes (benefit)			123			13			29			165			( 3 )			—			162
Segment net income			$	406		$	41		$	74		$	521		$	3		$	—		$	524
Total assets at June 30, 2025			$	24,864		$	1,595		$	1,679		$	28,138		$	10,492		$	( 12,254 )		$	26,376
Three Months Ended June 30, 2024
Operating revenues			$	749		$	8		$	70		$	827		$	7		$	( 3 )		$	831
Other segment items (*)			420			2			52			474			7			( 3 )			478
Depreciation and amortization			152			1			4			157			1			—			158
Earnings from equity method investments			—			32			—			32			—			—			32
Interest expense			76			9			2			87			( 4 )			—			83
Income taxes			21			6			3			30			6			—			36
Segment net income (loss)			$	80		$	22		$	9		$	111		$	( 3 )		$	—		$	108
Six Months Ended June 30, 2024
Operating revenues			$	2,212		$	16		$	305		$	2,533		$	13		$	( 8 )		$	2,538
Other segment items (*)			1,246			4			193			1,443			8			( 8 )			1,443
Depreciation and amortization			303			2			7			312			1			—			313
Earnings from equity method investments			—			76			—			76			—			—			76
Interest expense			154			18			2			174			( 7 )			—			167
Income taxes (benefit)			127			16			29			172			2			—			174
Segment net income			$	382		$	52		$	74		$	508		$	9		$	—		$	517
Total assets at December 31, 2024			$	24,067		$	1,573		$	1,696		$	27,336		$	10,047		$	( 11,206 )		$	26,177

(*) Primarily consists of cost of natural gas, other operations and maintenance, taxes other than income taxes, AFUDC equity, and non-service cost-related retirement benefits income.

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Name

Title

Date of Adoption

Expiration Date

Aggregate Number of Shares Covered

Bryan D. Anderson

Executive Vice President

May 30, 2025

September 30, 2026

6,206

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