SOUTHERN CO

Business Activities

Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies, Southern Power, and Southern Company Gas and owns other direct and indirect subsidiaries. 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. Southern Company's reportable 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. See Note 16 to the financial statements for additional information.

•The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service to retail customers in three Southeastern states in addition to wholesale customers in the Southeast.

•Southern Power develops, constructs, acquires, owns, operates, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power commits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.

•Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas. Southern Company Gas owns natural gas distribution utilities in four states – Illinois, Georgia, Virginia, and Tennessee – and is also involved in several other complementary businesses. Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services, which includes SouthStar, a Marketer and provider of energy-related products and services to natural gas markets – and one non-reportable segment, all other. See Notes 7, 15, and 16 to the financial statements for additional information.

Southern Company's other business activities include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, dispositions, and other strategic ventures or investments accordingly.

See FUTURE EARNINGS POTENTIAL herein for a discussion of many factors that could impact the Registrants' future results of operations, financial condition, and liquidity.

Recent Developments

On May 7, 2024, the Alabama PSC approved a decrease to Rate ECR from 3.270 cents per KWH to 3.015 cents per KWH, or approximately $135 million annually, effective with July 2024 billings. On December 3, 2024, the Alabama PSC approved an additional reduction to Rate ECR from 3.015 cents per KWH to 2.600 cents per KWH, or $218 million annually, effective with January 2025 billings.

On September 18, 2024, Alabama Power notified the Alabama PSC of its intent to use a portion of its reliability reserve balance in 2024. As a result, Alabama Power had usage of the reliability reserve in the amount of $12 million during the fourth quarter 2024 for reliability-related transmission, distribution, and generation expenses and nuclear production-related expenses.

On October 24, 2024, Alabama Power entered into an agreement to acquire all of the equity interests in Tenaska Alabama Partners, L.P. for a total purchase price of approximately $622 million, subject to working capital adjustments. Tenaska Alabama Partners, L.P. owns and operates the Lindsay Hill Generating Station, an approximately 855-MW combined cycle generation facility in Autauga County, Alabama. On October 30, 2024, Alabama Power filed a petition for a CCN with the Alabama PSC for authorization to procure additional generating capacity through the acquisition of the Lindsay Hill Generating Station. 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.

On November 27, 2024, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2025, resulting in an increase of 4.87%, or $325 million annually, that became effective for the billing month of January 2025.

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For the year ended December 31, 2024, Alabama Power's weighted common equity return exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $12 million for Rate RSE refunds, which will be refunded to customers through bill credits in May 2025.

See Note 2 to the financial statements under "Alabama Power" for additional information.

Plant Vogtle Units 3 and 4 Construction and Start-Up Status

Georgia Power placed Plant Vogtle Units 3 and 4 in service on July 31, 2023 and April 29, 2024, respectively. During the second quarter 2024, following Unit 4's in-service date, Southern Nuclear evaluated the remaining expected site demobilization costs and other contractor obligations and reduced the remaining estimate to complete forecast by approximately $21 million, including the impact of joint owner cost-sharing. Accordingly, Georgia Power recorded a pre-tax credit to income of approximately $21 million ($16 million after tax), including the joint owner agreement impacts, in the second quarter 2024 to recognize forecasted capital costs previously charged to income. Georgia Power's share of the remaining project capital cost forecast, including completion of site demobilization and remaining contractor obligations, is $69 million. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Cost and Schedule" for additional information.

Plant Vogtle Units 3 and 4 Regulatory Matters

In December 2023, the Georgia PSC approved Georgia Power's application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs as modified by the related stipulation (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors.

Georgia Power included in retail rate base $5.462 billion of construction and capital costs as well as $647 million of associated retail rate base items effective with the April 29, 2024 in-service date for Unit 4, pursuant to the approved Prudency Stipulation. Annual retail base revenues increased approximately $730 million and the average retail base rates were adjusted by approximately 5% (net of the elimination of the NCCR tariff described below) effective May 1, 2024.

Further, as included in the approved Prudency Stipulation, since commercial operation for Unit 4 was not achieved by March 31, 2024, Georgia Power's ROE used to determine the NCCR tariff and calculate AFUDC was reduced to zero effective April 1, 2024. Effective May 1, 2024, following commercial operation for Unit 4, Georgia Power's NCCR tariff was eliminated.

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Regulatory Matters" for additional information.

Rate Plans

On December 17, 2024, in accordance with the terms of the 2022 ARP, the Georgia PSC approved tariff adjustments effective January 1, 2025 that resulted in a net increase in rates of $306 million. Georgia Power is required to file its next general base rate case by July 1, 2025. See Note 2 to the financial statements under "Georgia Power – Rate Plans – 2022 ARP" for additional information.

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 expected CODs or delivery commencement dates between 2028 and 2030. The RFP included Georgia Power-owned proposals. In conjunction with those proposals, Georgia Power entered into agreements for engineering, procurement, and construction through January 2025. Winning participants are expected to be notified in June 2025, and the Georgia PSC is anticipated to render a decision related to the certification of the winning submissions in the fourth quarter 2025. Depending on the outcomes of the RFP and certification processes, Georgia Power could spend up to $14 billion, excluding AFUDC, on approved Georgia Power-owned proposals and related transmission investments through 2029. The ultimate outcome of this matter cannot be determined at this time.

On April 16, 2024, the Georgia PSC approved Georgia Power's updated IRP as modified by a stipulation among Georgia Power, the staff of the Georgia PSC, and certain intervenors (2023 IRP Update). The 2023 IRP Update includes the authority to develop, own, and operate up to 1,400 MWs from three simple cycle combustion turbines at Plant Yates with the recoverable costs not to exceed the certified amount, which was approved by the Georgia PSC on August 20, 2024. With this approval, the Georgia PSC recognized the potential for circumstances beyond Georgia Power's control that could cause the project costs to exceed the certified amount, in which case Georgia Power would provide documentation to the Georgia PSC to explain and justify potential recovery of additional reasonable and prudent costs. Georgia Power is required to file semi-annual construction monitoring

II-4 reports with the Georgia PSC through commercial operation, the first of which was filed on February 14, 2025. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – 2023 IRP Update" for additional information.

On January 31, 2025, Georgia Power filed its triennial IRP (2025 IRP). The filing includes a request to extend the 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.

The 2025 IRP requests approval to pursue 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.

Additionally, the 2025 IRP requests 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. Also, the 2025 IRP requests upgrades to Plant Hatch Units 1 and 2 (900 MWs based on 50.1% ownership) and Plant Vogtle Units 1 and 2 (1,060 MWs based on 45.7% ownership) for a projected 112 MWs of incremental capacity, some of which would be available as early as 2028.

The 2025 IRP requests approval of investments related to the continued reliable hydro operations of nine facilities, as well as the authority to develop, own, and operate a projected incremental 16 MWs from Plant Goat Rock Units 3 through 6.

The 2025 IRP also includes requests for RFPs for at least 1,100 MWs of utility scale and distributed generation renewable resources. Georgia Power is seeking to add up to 4,000 MWs of incremental renewable resources by 2035.

A decision from the Georgia PSC on the 2025 IRP is expected in July 2025. The ultimate outcome of these matters cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – 2025 IRP" for additional information.

On April 26, 2024, Mississippi Power filed its 2024 IRP with the Mississippi PSC. The Mississippi PSC did not note any deficiencies within the prescribed 120-day review period; therefore, the filing is concluded. The 2024 IRP included a schedule to retire Plant Watson Unit 4 (268 MWs) and Plant Greene County Units 1 and 2 (206 MWs based on 40% ownership) and to retire early Plant Daniel Units 1 and 2 (502 MWs based on 50% ownership), all by the end of 2028, which is consistent with the completion of Mississippi Power's affiliate PPA with Georgia Power. On January 9, 2025, Mississippi Power notified the Mississippi PSC of its intent to extend the retirement date of Plant Daniel Unit 2 and potentially extend the retirement dates of other fossil steam units beyond their current 2028 retirement dates in order to serve recently signed economic development loads of approximately 600 MWs.

On November 8, 2024, Mississippi Power entered into an agreement with FP&L to acquire FP&L's 50% ownership interest in Plant Daniel Units 1 and 2. This acquisition will include a payment by FP&L to Mississippi Power of between $35 million and $38 million, which represents an estimate of the incremental cost to Mississippi Power to assume ownership of FP&L's interest, based on the timing of the completion of the transaction. On January 7, 2025, the Mississippi PSC approved Mississippi Power's request for (i) the inclusion of the acquired assets and the associated costs at Plant Daniel in Mississippi Power's retail rate base, upon completion of the transaction, (ii) the establishment of a new regulatory liability account in which all of the proceeds to be paid by FP&L will be recorded, and (iii) Mississippi Power's ability to amortize that regulatory liability by charging certain expenditures against it. The completion of the transaction is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, approval by the Florida PSC.

On February 14, 2025, Mississippi Power submitted its annual ECO Plan filing to the Mississippi PSC, which requested a $6 million annual increase in revenues.

On May 28, 2024, the FERC issued an order accepting Mississippi Power's request for an $8 million increase in annual wholesale base revenues under the MRA tariff, effective May 29, 2024, subject to refund. On December 23, 2024, Mississippi Power and Cooperative Energy filed a settlement agreement with the FERC. 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 Services Agreement (SSA) 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 SSA. The settlement agreement is subject to approval by the FERC.

The ultimate outcome of these matters cannot be determined at this time. See Note 2 to the financial statements under "Mississippi Power" for additional information.

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During 2024, Southern Power completed construction of and placed in service the 150-MW South Cheyenne solar facility. In addition, Southern Power continued construction of the 200-MW first phase and began construction of the 180-MW second phase and the 132-MW third phase of the Millers Branch solar facility with commercial operation projected to occur in the fourth quarter 2025, the second quarter 2026, and the fourth quarter 2026, respectively. Upon completion, the Millers Branch solar project will have a total generating capacity of 512 MWs, substantially all of which is contracted under multiple PPAs ranging from 15 years to 20 years.

In November 2024, Southern Power committed to a development project to repower 200 MWs of the 299-MW Kay Wind facility. The output of the project is contracted under an amended 20-year PPA with commercial operation projected to occur in the third quarter 2026.

Southern Power calculates an investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective facilities' net book value (or expected in-service value for facilities under construction) as the investment amount. With the inclusion of investments associated with facilities under construction, as well as other capacity and energy contracts, Southern Power's average investment coverage ratio at December 31, 2024 was 96% through 2029 and 87% through 2034, with an average remaining contract duration of approximately 12 years.

See Note 15 to the financial statements under "Southern Power" for additional information.

In June 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP rider, also referred to as Investing in Illinois program. The Illinois Commission disallowed $32 million of the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments placed in service in 2019. The disallowance is reflected on the statement of income as an $8 million reduction to revenues and $30 million in estimated loss on regulatory disallowance. On August 3, 2023, the Illinois Commission denied a rehearing request filed by Nicor Gas. On August 24, 2023, Nicor Gas filed a notice of appeal with the Illinois Appellate Court. On November 25, 2024, the Illinois Appellate Court agreed with the Illinois Commission's review of the QIP capital investments by Nicor Gas for calendar year 2019 under the QIP rider apart from one immaterial item. On December 24, 2024, Nicor Gas filed a petition for leave to appeal $14 million of the 2019 QIP disallowance with the Illinois Supreme Court. Nicor Gas defends these investments in infrastructure as prudently incurred.

In connection with Nicor Gas' 2023 general base rate case proceeding, the Illinois Commission disallowed $126.8 million of capital investments that have been completed or were planned to be completed through December 31, 2024. This includes $31 million for capital investments placed in service in 2022 and 2023 under the Investing in Illinois program and $95.9 million for other transmission and distribution capital investments. Nicor Gas recorded a pre-tax charge to income in the fourth quarter 2023 of $58 million ($44 million after tax) associated with the disallowances, with the remaining $69 million related to prospective projects that will be postponed and/or reevaluated. The disallowance is reflected on the statement of income in estimated loss on regulatory disallowance. On January 3, 2024, the Illinois Commission denied a request by Nicor Gas for rehearing on the base rate case disallowances associated with capital investment, as well as on other issues determined in the Illinois Commission's November 2023 base rate case decision. On February 6, 2024, Nicor Gas filed a notice of appeal with the Illinois Appellate Court related to the Illinois Commission's rate case ruling.

Any further cost disallowances by the Illinois Commission in the pending cases and the 2020 through 2023 annual review proceedings could be material to the financial statements of Southern Company Gas. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for additional information.

On January 3, 2025, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $309 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending December 31, 2026, an ROE of 10.35%, and an equity ratio of 54.6%. The Illinois Commission is expected to rule on the requested increase within the 11-month statutory time limit, after which rate adjustments will be effective.

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On July 2, 2024, the Georgia PSC approved a stipulation related to Atlanta Gas Light's 2024 Integrated Capacity and Delivery Plan, which allows capital investments totaling approximately $0.6 billion annually for the years 2025 through 2027 with related revenue requirement recovery through either the annual GRAM filing or the System Reinforcement Rider surcharge adjustment. Additionally, the Georgia PSC approved a surcharge recovery mechanism for capital projects related to municipal, county, and Georgia Department of Transportation infrastructure work. Rate changes associated with the new surcharge will be based on requests filed annually on September 1. If approved, new rates will become effective January 1 of the following year.

On December 12, 2024, the Georgia PSC approved Atlanta Gas Light's annual GRAM filing, which included annual base rate increases of $72 million, $73 million, and $74 million effective January 1, 2025, 2026, and 2027, respectively.

On June 7,2024, the Virginia Commission approved the extension of the existing SAVE program through 2029. The extension of the program includes investments of$70 million in each year from 2025 through 2029, with a potential variance of up to $5 million allowed for the program, for a maximum total investment over the five-year extension (2025 through 2029) of $355 million.

On August 1, 2024, Virginia Natural Gas filed a base rate case with the Virginia Commission seeking an increase in annual base revenues of $63 million, including $17 million related to the recovery of investments under the SAVE program, primarily to recover investments and increased costs associated with infrastructure and technology. The requested increase is based on a projected 12-month period beginning January 1, 2025, an ROE of 10.45%, and an equity ratio of 54.92%. Rate adjustments were effective January 1, 2025, subject to refund. The Virginia Commission is expected to issue an order on the requested increase in the fourth quarter 2025. The ultimate outcome of this matter cannot be determined at this time.

Key Performance Indicators

In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to approximately 8.9 million electric and gas utility customers collectively, the traditional electric operating companies and Southern Company Gas continue to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share (EPS) and net income, respectively, as a key performance indicator. See RESULTS OF OPERATIONS herein for information on the Registrants' financial performance.

The financial success of the traditional electric operating companies and Southern Company Gas is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. The traditional electric operating companies use customer satisfaction surveys to evaluate their results and generally target the top quartile of these surveys in measuring performance. Reliability indicators are also used to evaluate results. See Note 2 to the financial statements under "Alabama Power – Rate RSE" and "Mississippi Power – Performance Evaluation Plan" for additional information on Alabama Power's Rate RSE and Mississippi Power's PEP rate plan, respectively, both of which contain mechanisms that directly tie customer service indicators to the allowed equity return.

Southern Company Gas also continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. See RESULTS OF OPERATIONS – "Southern Company Gas" herein for additional information on Southern Company Gas' operating metrics.

Southern Power continues to focus on several key performance indicators, including, but not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers.