SOUTHERN CO (SO) FY 2024 MD&A

COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS

OVERVIEW

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

Alabama Power

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.

Georgia Power

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.

Integrated Resource Plans

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

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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.

Mississippi Power

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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Southern Power

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.

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

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.

Southern Company Gas

Nicor Gas

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.

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

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Atlanta Gas Light

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.

Virginia Natural Gas

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.

RESULTS OF OPERATIONS

Southern Company

Consolidated net income attributable to Southern Company was $4.4 billion in 2024, an increase of $425 million, or 10.7%, from 2023. The increase was primarily due to an increase in retail electric revenues associated with rates and pricing and weather impacts, an increase in natural gas revenues associated with rate increases, an increase in other revenues, and an increase in other electric revenues, partially offset by increases in non-fuel operations and maintenance expenses, income tax expense, interest expense, depreciation and amortization, taxes other than income taxes, and cost of other sales.

Basic EPS was $4.02 in 2024 and $3.64 in 2023. Diluted EPS, which factors in additional shares primarily related to stock-based compensation, was $3.99 in 2024 and $3.62 in 2023. EPS for 2024 and 2023 was negatively impacted by $0.01 and $0.06 per

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share, respectively, as a result of increases in the average shares outstanding. See Note 8 to the financial statements under "Outstanding Classes of Capital Stock – Southern Company" for additional information.

Dividends paid per share of common stock were $2.86 in 2024 and $2.78 in 2023. In January 2025, Southern Company declared a quarterly dividend of 72 cents per share. For 2024, the dividend payout ratio was 71% compared to 76% for 2023.

Discussion of Southern Company's results of operations is divided into three parts – the Southern Company system's primary business of electricity sales, its gas business, and its other business activities.

Electricity Business

Southern Company's electric utilities generate and sell electricity to retail and wholesale customers. A condensed statement of income for the electricity business follows:

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Electric Operating Revenues

Electric operating revenues for 2024 were $21.6 billion, reflecting a $1.6 billion, or 8.0%, increase from 2023. Details of electric operating revenues were as follows:

Retail electric revenues increased $1.4 billion, or 8.9%, in 2024 as compared to 2023. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to the inclusion of Plant Vogtle Units 3 and 4 in retail rates net of the elimination of the NCCR tariff at Georgia Power, customer bill credits in 2023 at Alabama Power related to the flowback of certain excess accumulated deferred income taxes, base tariff increases at Georgia Power in accordance with the 2022 ARP, higher contributions from commercial and industrial customers with variable demand-driven pricing at Georgia Power, and an increase in Rate CNP New Plant revenues at Alabama Power.

Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" for additional information. Also see "Energy Sales" herein for a discussion of changes in the volume of energy sold, including estimated changes related to sales and weather.

Wholesale electric revenues from power sales were as follows:

In 2024, wholesale electric revenues decreased $36 million, or 1.5%, as compared to 2023 due to a decrease of $58 million in energy revenues, partially offset by an increase of $22 million in capacity and other revenues. Energy revenues decreased $45 million at the traditional electric operating companies and $13 million at Southern Power primarily due to fuel and purchased power price decreases compared to 2023. Partially offsetting the Southern Power decrease was an increase in the volume of KWHs sold primarily under natural gas and solar PPAs. The increase in capacity revenues was primarily due to a net increase in revenues from capacity contracts at Georgia Power and an increase in capacity revenues associated with natural gas PPAs at Southern Power. The changes in capacity and energy revenues also reflect decreases resulting from power sales agreements that ended in 2023 at Alabama Power and Mississippi Power.

Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the

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Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated MRA sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

Other electric revenues increased $104 million, or 13.1%, in 2024 as compared to 2023. The increase was primarily due to increases of $77 million in open access transmission tariff sales at the traditional electric operating companies, $29 million in regulated sales primarily associated with power delivery construction and maintenance at Georgia Power, and $23 million in regulated outdoor lighting sales at Georgia Power, partially offset by a net increase of $17 million in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs at Georgia Power and a decrease of $14 million related to liquidated damages receipts associated with generation facility production guarantees and an arbitration award in 2023 at Southern Power.

Other revenues increased $90 million, or 22.7%, in 2024 as compared to 2023. The increase was primarily due to increases of $71 million in unregulated sales at Georgia Power associated with power delivery construction and maintenance, energy conservation projects, and renewables and $13 million in unregulated outdoor lighting sales at the traditional electric operating companies.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2024 and the percent change from 2023 were as follows:

(*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from normal temperature conditions. Normal temperature conditions are defined as those experienced in the applicable service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Weather-adjusted retail energy sales increased by 1.1 billion KWHs in 2024 as compared to 2023. Weather-adjusted residential KWH sales decreased 0.5% primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 2.2% primarily due to increased customer usage, primarily driven by existing data centers, and customer growth. Industrial KWH sales increased 0.7% primarily due to increases in the pipeline and transportation sectors, partially offset by a decrease in the primary metals sector.

See "Electric Operating Revenues" above for a discussion of significant changes in wholesale revenues related to changes in price and KWH sales.

Fuel and Purchased Power Expenses

The mix of fuel sources for the generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, the electric utilities purchase a portion of their electricity needs from the wholesale market.

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Details of the Southern Company system's generation and purchased power were as follows:

(a)Excludes KWHs generated from test period energy at Plant Vogtle Units 3 and 4 prior to each unit's respective in-service date. The related fuel costs were charged to CWIP in accordance with FERC guidance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

(b)Excludes $55 million of credits recorded to nuclear fuel expense in 2024 resulting from litigation related to nuclear fuel disposal costs. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

(c)Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

In 2024, total fuel and purchased power expenses were $5.0 billion, a decrease of $269 million, or 5.1%, as compared to 2023. The decrease was primarily the result of a $244 million decrease related to the average cost of fuel generated and purchased, partially offset by a $30 million net increase related to the volume of KWHs generated and purchased. Also contributing to the decrease was a $55 million credit to nuclear fuel expense at Georgia Power resulting from litigation related to nuclear fuel disposal costs. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See Note 2 to the financial statements for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

Fuel

In 2024, fuel expense was $4.1 billion, a decrease of $269 million, or 6.2%, as compared to 2023. The decrease was primarily due to a 9.0% decrease in the average cost of coal per KWH generated, a 5.4% decrease in the average cost of natural gas per KWH generated, and a 3.5% decrease in the volume of KWHs generated by natural gas, partially offset by a 15.6% increase in the volume of KWHs generated by nuclear, a 13.2% increase in the average cost per KWH generated by nuclear, an 8.0% decrease in the volume of KWHs generated by hydro, and a 7.6% increase in the volume of KWHs generated by coal. Also contributing to the decrease was a $55 million credit to nuclear fuel expense at Georgia Power resulting from litigation related to nuclear fuel disposal costs. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

Purchased Power

In 2024, purchased power expense was $883 million, which was flat compared to 2023.

Energy purchases will vary depending on demand for energy within the Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, and the availability of the Southern Company system's generation.

Cost of Other Sales

Cost of other sales increased $66 million, or 38.6%, in 2024 as compared to 2023. The increase was primarily due to increases of $40 million in expenses associated with unregulated power delivery construction and maintenance contracts at Georgia Power and $18 million in expenses associated with energy conservation projects at Georgia Power.

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Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $432 million, or 9.2%, in 2024 as compared to 2023. The increase was primarily due to increases of $170 million in generation expenses primarily associated with Plant Vogtle Units 3 and 4 being placed in service at Georgia Power, maintenance and scheduled outage expenses, and Rate CNP Compliance-related expenses at Alabama Power, $166 million in transmission and distribution expenses primarily related to line maintenance and billing adjustments with integrated transmission system owners at Georgia Power, $41 million in customer service and sales expenses including bad debt, $36 million related to an impairment loss associated with Alabama Power discontinuing the development of a multi-use commercial facility, $21 million associated with an additional Rate NDR accrual at Alabama Power, $20 million associated with reliability reserve accruals and reliability-related expenses at Alabama Power and Mississippi Power, $16 million associated with a gain on the sale of spare parts in 2023 at Southern Power, $11 million associated with an arbitration award received in 2023 at Southern Power related to losses previously incurred, and $10 million in amortization of deferred cloud implementation costs, partially offset by a $91 million increase in gains from sales of integrated transmission system assets at Georgia Power and a $31 million decrease in technology infrastructure and application production expenses. See Note 1 to the financial statements under "Storm Damage and Reliability Reserves" and "Impairment of Long-Lived Assets" and Note 2 to the financial statements under "Georgia Power – Transmission Asset Sales" and " – Nuclear Construction" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $169 million, or 4.4%, in 2024 as compared to 2023. The increase was primarily due to an increase of $244 million associated with additional plant in service, partially offset by a decrease of $59 million in amortization of regulatory assets related to CCR AROs at Georgia Power as approved in the 2024 compliance filing under the terms of the 2022 ARP and an increase of $24 million in amortization of federal ITCs at Georgia Power. See Note 2 to the financial statements under "Georgia Power – Rate Plans" for additional information. Also see Note 10 to the financial statements for additional information on amortization of federal ITCs.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $129 million, or 11.1%, in 2024 as compared to 2023. The increase was primarily due to increases of $92 million in property taxes primarily resulting from an increase in the assessed value of property at the traditional electric operating companies as well as a decrease in the capitalized portion of property taxes at Georgia Power primarily due to Plant Vogtle Units 3 and 4 being placed in service in July 2023 and April 2024, respectively, $23 million in municipal franchise fees resulting from higher retail revenues at Georgia Power, and $13 million in utility license taxes at Alabama Power resulting from an increase in the tax base. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Estimated Loss on Plant Vogtle Units 3 and 4

Georgia Power recorded credits to income related to the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $21 million and $68 million in 2024 and 2023, respectively. The credits to income reflected revisions to the total project capital cost forecast for the construction and completion of Plant Vogtle Units 3 and 4 and the related cost recovery. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction decreased $38 million, or 15.4%, in 2024 as compared to 2023. The decrease was primarily associated with Plant Vogtle Units 3 and 4 being placed in service in July 2023 and April 2024, respectively, at Georgia Power and Plant Barry Unit 8 being placed in service in November 2023 at Alabama Power, partially offset by an increase in capital expenditures subject to AFUDC at Georgia Power. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" and "Alabama Power – Rate CNP New Plant" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $98 million, or 7.7%, in 2024 as compared to 2023. The increase primarily reflects approximately $43 million related to higher interest rates and $37 million related to higher average outstanding borrowings, as well as a net decrease of $35 million in AFUDC debt and capitalized interest primarily related to Plant Vogtle Units 3 and 4 at Georgia Power and Plant Barry Unit 8 at Alabama Power. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein, Note 2 to the financial statements under "Alabama Power – Rate CNP New Plant" and "Georgia Power – Nuclear Construction," and Note 8 to the financial statements for additional information.

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Income Taxes

Income taxes increased $420 million, or 72.0%, in 2024 as compared to 2023. The increase was primarily due to higher pre-tax earnings, a $197 million decrease in the flowback of certain excess deferred income taxes at Alabama Power, and a $112 million increase in charges to a valuation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by an increase of $79 million in the generation of advanced nuclear PTCs at Georgia Power and $26 million from the recognition of certain state tax positions from amended returns at Georgia Power. See Note 10 to the financial statements for additional information.

Net Loss Attributable to Noncontrolling Interests

Substantially all noncontrolling interests relate to renewable projects at Southern Power. Net loss attributable to noncontrolling interests increased $14 million, or 11.0%, in 2024 as compared to 2023. The increased loss was primarily due to $23 million in higher HLBV loss allocations to Southern Power's tax equity partners, partially offset by $12 million in higher income allocations to Southern Power's equity partners.

Gas Business

Southern Company Gas distributes natural gas through utilities in four states and is involved in several other complementary businesses including gas pipeline investments and gas marketing services.

A condensed statement of income for the gas business follows:

Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. During the Heating Season, more customers are connected to Southern Company Gas' distribution systems and natural gas usage is higher in periods of colder weather. As a result, operating results can vary significantly from quarter to quarter. For 2024, the percentage of operating revenues and net income generated during the Heating Season was 62% and 80%, respectively. For 2023, the percentage of operating revenues and net income generated during the Heating Season was 67% and 73%, respectively.

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Operating Revenues

Operating revenues in 2024 were $4.5 billion, reflecting a $246 million, or 5.2%, decrease compared to 2023. Details of operating revenues were as follows:

Revenues increased from rate changes in 2024 primarily due to base rate increases at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

Revenues associated with gas costs and other cost recovery decreased in 2024 primarily due to lower natural gas cost recovery associated with lower natural gas prices and lower demand associated with warmer weather. The natural gas distribution utilities have weather or revenue normalization mechanisms that mitigate revenue fluctuations from customer consumption changes. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. See "Cost of Natural Gas" herein for additional information.

Revenues from gas marketing services decreased in 2024 primarily due to lower commodity prices.

Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services. Therefore, weather typically does not have a significant net income impact.

Cost of Natural Gas

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, the natural gas distribution utilities' rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas – Natural Gas Cost Recovery" for additional information. Cost of natural gas at the natural gas distribution utilities represented 80.3% of the total cost of natural gas for 2024.

Gas marketing services customers are charged for actual and estimated natural gas consumed. Cost of natural gas includes the cost of fuel and associated transportation costs, lost and unaccounted for gas, and gains and losses associated with certain derivatives.

Cost of natural gas was $1.2 billion, a decrease of $448 million, or 27.3%, in 2024 as compared to 2023, which reflects lower gas cost recovery in 2024 as a result of a 17.1% decrease in natural gas prices compared to 2023.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses decreased $40 million, or 3.1%, in 2024 as compared to 2023. The decrease was primarily due to prior year regulatory disallowances totaling $88 million at Nicor Gas and decreases of $12 million related to energy services contracts and $9 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at the natural gas distribution utilities, partially offset by increases of $56 million in compensation and benefit expenses and $20 million in survey, locate, and inspection expenses for distribution gas mains. See Note 2 to the financial statements under "Southern Company Gas" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $68 million, or 11.7%, in 2024 as compared to 2023. The increase was primarily due to continued investments at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information.

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Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $31 million, or 10.0%, in 2024 as compared to 2023. The increase reflects approximately $17 million related to higher average outstanding borrowings and $14 million related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein and Note 8 to the financial statements for additional information.

Income Taxes

Income taxes increased $47 million, or 22.3%, in 2024 as compared to 2023. The increase was primarily due to higher pre-tax earnings. See Note 10 to the financial statements for additional information.

Other Business Activities

Southern Company's other business activities primarily include the parent company (which does not allocate operating expenses to business units); PowerSecure, which provides distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers; Southern Holdings, which invests in various projects; and Southern Linc, which provides digital wireless communications for use by the Southern Company system and also markets these services to the public and provides fiber optics services within the Southeast.

A condensed statement of operations for Southern Company's other business activities follows:

Operating Revenues

Operating revenues for these other business activities increased $111 million, or 20.0%, in 2024 as compared to 2023 primarily due to an increase of $120 million at PowerSecure primarily related to distributed infrastructure projects, partially offset by a decrease of $18 million at Southern Linc primarily related to equipment sales associated with commercial customers.

Cost of Other Sales

Cost of other sales for these other business activities increased $56 million, or 15.8%, in 2024 as compared to 2023 primarily due to an increase of $82 million at PowerSecure primarily related to distributed infrastructure projects, partially offset by a decrease of $15 million at Southern Linc primarily related to equipment sales associated with commercial customers.

Other Operations and Maintenance

Other operations and maintenance expenses for these other business activities increased $38 million, or 21.7%, in 2024 as compared to 2023 primarily due to an increase at the parent company primarily related to higher director compensation expenses.

Earnings (Loss) from Equity Method Investments

Earnings (loss) from equity method investments for these other business activities decreased $21 million in 2024 as compared to 2023. The decrease was primarily due to investment losses at Southern Holdings. See Note 7 to the financial statements under "Southern Company" for additional information on Southern Holdings' equity method investments.

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Interest Expense

Interest expense for these other business activities increased $167 million, or 19.4%, in 2024 as compared to 2023. The increase primarily results from parent company financing activities and includes approximately $88 million related to higher average outstanding borrowings and $59 million related to higher interest rates. See Note 8 to the financial statements for additional information.

Income Taxes (Benefit)

The income tax benefit for these other business activities decreased $6 million, or 2.0%, in 2024 as compared to 2023. The decrease was primarily due to a $35 million tax benefit in 2023 at the parent company related to a reversal of an uncertain tax position associated with the 2019 sale of Gulf Power as well as higher pre-tax earnings at PowerSecure, largely offset by higher pre-tax losses at the parent company.

Alabama Power

Alabama Power's 2024 net income was $1.4 billion, representing a $33 million, or 2.4%, increase from 2023. The increase was primarily due to an increase in retail electric revenues associated with weather impacts, as well as an increase in Rate CNP New Plant revenues and an increase in other revenues. These increases to income were partially offset by increases in non-fuel operations and maintenance expenses, depreciation, and taxes other than income taxes. See Note 2 to the financial statements under "Alabama Power" for additional information.

A condensed income statement for Alabama Power follows:

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Operating Revenues

Operating revenues for 2024 were $7.6 billion, reflecting a $504 million, or 7.1%, increase from 2023. Details of operating revenues were as follows:

Retail revenues increased $480 million, or 7.8%, in 2024 as compared to 2023. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to customer bill credits in 2023 related to the flowback of certain excess accumulated deferred income taxes as well as an increase in Rate CNP New Plant revenues. See Note 2 to the financial statements under "Alabama Power – Rate CNP New Plant" for additional information.

See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including estimated changes related to sales and weather.

Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power" for additional information.

Wholesale revenues from sales to non-affiliated utilities were as follows:

In 2024, wholesale revenues from sales to non-affiliates decreased $87 million, or 20.5%, as compared to 2023. The decrease primarily reflects a 30.8% decrease in the volume of KWHs sold as a result of power sales agreements that ended in May 2023.

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Alabama Power's variable cost to produce the energy.

In 2024, wholesale revenues from sales to affiliates increased $79 million, or 131.7%, as compared to 2023. The revenue increase was primarily due to an increase of 165.5% in the volume of KWH sales due to affiliated company energy needs.

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales and purchases are made in accordance with the IIC, as approved by the FERC.

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These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.

In 2024, other operating revenues increased $32 million, or 7.9%, as compared to 2023 primarily due to a $30 million increase in transmission revenue primarily associated with open access transmission tariff sales.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2024 and the percent change from 2023 were as follows:

(*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from the normal temperature conditions. Normal temperature conditions are defined as those experienced in Alabama Power's service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Revenues attributable to changes in sales decreased in 2024 when compared to 2023. In 2024, weather-adjusted residential KWH sales decreased 0.7% primarily due to a decrease in customer usage. Weather-adjusted commercial KWH sales increased 0.8% primarily due to customer growth. Industrial KWH sales increased 0.7% primarily due to an increase in the pipeline and forest products sectors.

See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies related to changes in price and KWH sales.

Fuel and Purchased Power Expenses

The mix of fuel sources for generation of electricity is determined primarily by the unit cost of fuel consumed, demand, and the availability of generating units. Additionally, Alabama Power purchases a portion of its electricity needs from the wholesale market.

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Details of Alabama Power's generation and purchased power were as follows:

(*)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.

Fuel and purchased power expenses were $1.7 billion in 2024, a decrease of $71 million, or 3.9%, compared to 2023. The decrease was primarily due to a $54 million net decrease related to the average cost of fuel and purchased power and a $17 million net decrease related to the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 2 to the financial statements under "Alabama Power – Rate ECR" for additional information.

Fuel

Fuel expense was $1.4 billion in 2024, an increase of $59 million, or 4.5%, compared to 2023. The increase was primarily due to a 23.1% increase in the volume of KWHs generated by natural gas, an 8.4% increase in the volume of KWHs generated by coal, and a 9.6% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall, partially offset by an 8.7% decrease in the average cost per KWH generated by natural gas, which excludes tolling agreements, and a 7.8% decrease in the average cost per KWH generated by coal.

Purchased Power – Non-Affiliates

Purchased power expense from non-affiliates was $199 million in 2024, a decrease of $54 million, or 21.3%, compared to 2023. The decrease was primarily due to a 31.3% decrease in the volume of KWHs purchased as a result of a PPA that ended in May 2023 and the availability of Plant Barry Unit 8 and Central Alabama Generating Station generation, partially offset by a 12.5% increase in the average cost per KWH purchased.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

Purchased power expense from affiliates was $175 million in 2024, a decrease of $76 million, or 30.3%, compared to 2023. The decrease was primarily due to a 42.4% decrease in the volume of KWHs purchased due to the availability of Plant Barry Unit 8 and Central Alabama Generating Station generation and a reduction in capacity-related expenses due to lower capacity needs in 2024, partially offset by a 21.0% increase in the average cost per KWH purchased.

Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

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Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $126 million, or 7.1%, in 2024 as compared to 2023. The increase was primarily due to increases of $36 million related to an impairment loss associated with Alabama Power discontinuing the development of a multi-use commercial facility, $21 million associated with an additional Rate NDR accrual, $16 million in certain employee compensation and benefits, $15 million in Rate CNP Compliance-related expenses, $10 million associated with reliability reserve accruals and reliability-related expenses, $10 million in customer accounts primarily associated with bad debt expense, $9 million in transmission and distribution expenses primarily due to vegetation management, and $8 million related to the injuries and damages reserve. These increases were partially offset by a decrease of $28 million in technology infrastructure and application production costs.

See Note 1 to the financial statements under "Impairment of Long-Lived Assets" and Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance," " – Rate NDR," and " – Reliability Reserve Accounting Order" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $58 million, or 4.1%, in 2024 as compared to 2023 primarily due to additional plant in service related to transmission and distribution facilities as well as Plant Barry Unit 8 being placed in service in November 2023. See Note 2 to the financial statements under "Alabama Power – Rate CNP New Plant" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $29 million, or 6.6%, in 2024 as compared to 2023 primarily due to increases of $13 million in property taxes primarily resulting from an increase in the assessed value of property and $13 million in utility license taxes resulting from an increase in the tax base.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction decreased $25 million, or 30.5%, in 2024 as compared to 2023 primarily due to Plant Barry Unit 8 being placed in service in November 2023. See Note 2 to the financial statements under "Alabama Power – Rate CNP New Plant" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $23 million, or 5.4%, in 2024 as compared to 2023. The increase was primarily associated with increases of approximately $8 million related to higher interest rates and $8 million related to higher average outstanding borrowings, as well as a decrease of $8 million in AFUDC debt primarily due to Plant Barry Unit 8 being placed in service in November 2023. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital," Note 2 to the financial statements under "Alabama Power – Rate CNP New Plant," and Note 8 to the financial statements for additional information.

Income Taxes

Income taxes increased $279 million in 2024 as compared to 2023 primarily due to a decrease of $197 million in the flowback of certain excess deferred income taxes, as well as higher pre-tax earnings. See Note 2 to the financial statements under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" and Note 10 to the financial statements for additional information.

Georgia Power

Georgia Power's 2024 net income was $2.5 billion, representing a $0.5 billion, or 22.3%, increase from the previous year. The increase was primarily due to higher retail revenues associated with the inclusion of Plant Vogtle Units 3 and 4 in retail rates, base tariff increases in accordance with the 2022 ARP, and weather impacts, partially offset by a $112 million increase in charges to a valuation allowance on certain state tax credit carryforwards.

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A condensed income statement for Georgia Power follows:

Operating Revenues

Operating revenues for 2024 were $11.3 billion, reflecting a $1.2 billion, or 12.0%, increase from 2023. Details of operating revenues were as follows:

Retail revenues increased $1.0 billion, or 10.5%, in 2024 as compared to 2023. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to the inclusion of Plant Vogtle Units 3 and 4 in retail rates net of the elimination of the NCCR tariff, base tariff increases in accordance with the 2022 ARP, and higher contributions from commercial and industrial customers with variable demand-driven pricing. See Note 2 to the financial statements under "Georgia Power" for additional information.

See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including estimated changes related to sales and weather.

Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.

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Wholesale revenues from power sales were as follows:

In 2024, wholesale revenues increased $77 million, or 41.0%, as compared to 2023 largely due to increases of $85 million related to the volume of KWH sales associated with higher market demand and $76 million related to net additional capacity from wholesale capacity contracts, partially offset by a decrease of $89 million related to the average cost per KWH sold due to lower Southern Company system fuel and purchased power prices.

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.

In 2024, other operating revenues increased $171 million, or 24.2%, as compared to 2023 primarily due to increases of $76 million in unregulated sales primarily associated with power delivery construction and maintenance, energy conservation projects, and renewables, $40 million in open access transmission tariff sales, $29 million in regulated sales primarily associated with power delivery construction and maintenance, $23 million in regulated outdoor lighting sales, $8 million in pole attachment revenues, and $8 million in solar program fees, partially offset by a net increase of $17 million in realized losses associated with price stability products for retail customers on variable demand-driven pricing tariffs.

Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2024 and the percent change from 2023 were as follows:

(*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from normal temperature conditions. Normal temperature conditions are defined as those experienced in Georgia Power's service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Revenues attributable to changes in sales increased in 2024 when compared to 2023. Weather-adjusted residential sales decreased 0.2% primarily due to decreased customer usage, partially offset by customer growth. Weather-adjusted commercial KWH sales increased 2.6% primarily due to increased customer usage, primarily driven by existing data centers, and

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customer growth. Weather-adjusted industrial KWH sales increased 0.2% primarily due to an increase in the transportation sector, largely offset by a decrease in the electronics sector.

See "Operating Revenues" above for a discussion of significant changes in wholesale sales to non-affiliates and affiliated companies.

Fuel and Purchased Power Expenses

Fuel costs constitute one of the largest expenses for Georgia Power. The mix of fuel sources for the generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, Georgia Power purchases a portion of its electricity needs from the wholesale market.

Details of Georgia Power's generation and purchased power were as follows:

(a)Excludes KWHs generated from test period energy at Plant Vogtle Units 3 and 4 prior to each unit's respective in-service date. The related fuel costs were charged to CWIP in accordance with FERC guidance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

(b)Excludes $55 million of credits recorded to nuclear fuel expense in 2024 resulting from litigation related to nuclear fuel disposal costs. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

(c)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.

Fuel and purchased power expenses were $3.0 billion in 2024, a decrease of $44 million, or 1.4%, compared to 2023. The decrease was due to a net decrease of $96 million related to the average cost of fuel and purchased power and $55 million of credits recorded to nuclear fuel expense resulting from litigation related to nuclear fuel disposal costs, partially offset by an increase of $107 million related to the volume of KWHs generated and purchased. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.

Fuel

Fuel expense was $1.7 billion in 2024, a decrease of $123 million, or 6.9%, compared to 2023. The decrease was primarily due to $55 million of credits recorded to nuclear fuel expense resulting from litigation related to nuclear fuel disposal costs and decreases of 11.6% in the average cost per KWH generated by coal, 6.2% in the average cost per KWH generated by natural gas, and 3.5% in the volume of KWHs generated by natural gas, partially offset by increases of 26.8% in the volume of KWHs generated by nuclear, 17.1% in the average cost per KWH generated by nuclear, and 6.9% in the volume of KWHs generated by coal.

Purchased Power – Non-Affiliates

Purchased power expense from non-affiliates was $615 million in 2024, an increase of $98 million, or 19.0%, compared to 2023. The increase was primarily due to an increase of 28.8% in the volume of KWHs purchased as Georgia Power and other Southern Company system units generally dispatched at a higher cost than available market resources, partially offset by a decrease of 10.3% in the average cost per KWH purchased primarily due to lower natural gas prices.

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Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

Purchased power expense from affiliates was $745 million in 2024, a decrease of $19 million, or 2.5%, compared to 2023. The decrease was primarily due to a decrease of 6.3% in the volume of KWHs purchased as Southern Company system units generally dispatched at a higher cost than available market resources, partially offset by capacity purchased through a new PPA with Mississippi Power and an increase of 3.8% in the average cost per KWH purchased.

Energy purchases from affiliates will vary depending on the demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, all as approved by the FERC.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $289 million, or 13.9%, in 2024 as compared to 2023. The increase was primarily due to increases of $167 million in transmission and distribution costs primarily associated with line maintenance and billing adjustments with integrated transmission system owners, $126 million in generation expenses largely resulting from Plant Vogtle Units 3 and 4 being placed in service in July 2023 and April 2024, respectively, $40 million in expenses associated with unregulated power delivery construction and maintenance contracts, and $27 million in customer service and sales costs primarily associated with bad debt expense. Partially offsetting the increase was an increase of $91 million in gains from sales of integrated transmission system assets. See Note 2 to the financial statements under "Georgia Power – Transmission Asset Sales" and " – Nuclear Construction" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $93 million, or 5.5%, in 2024 as compared to 2023 primarily due to an increase of $173 million associated with additional plant in service, partially offset by a decrease of $59 million in amortization of regulatory assets related to CCR AROs as approved in the 2024 compliance filing under the terms of the 2022 ARP and an increase of $24 million in amortization of federal ITCs. See Note 2 to the financial statements under "Georgia Power – Rate Plans" for additional information. Also see Note 10 to the financial statements for additional information on amortization of federal ITCs.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $106 million, or 19.6%, in 2024 as compared to 2023 primarily due to an increase of $53 million in property taxes primarily resulting from an increase in the assessed value of property, a decrease of $30 million in property taxes capitalized primarily due to Plant Vogtle Units 3 and 4 being placed in service in July 2023 and April 2024, respectively, and an increase of $23 million in municipal franchise fees resulting from higher retail revenues. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.

Estimated Loss on Plant Vogtle Units 3 and 4

Georgia Power recorded credits to income related to the estimated probable loss on Plant Vogtle Units 3 and 4 totaling $21 million and $68 million in 2024 and 2023, respectively. The credits to income reflected revisions to the total project capital cost forecast for the construction and completion of Plant Vogtle Units 3 and 4 and the related cost recovery. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction decreased $13 million, or 7.9%, in 2024 as compared to 2023 primarily due to Plant Vogtle Units 3 and 4 being placed in service in July 2023 and April 2024, respectively, partially offset by an increase in capital expenditures subject to AFUDC. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $99 million, or 15.8%, in 2024 as compared to 2023. The increase was primarily associated with increases of approximately $36 million related to higher average outstanding borrowings and $30 million related to higher interest rates, as well as a decrease of $31 million in AFUDC debt primarily related to Plant Vogtle Units 3 and 4. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein, Note 2 to

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the financial statements under "Georgia Power – Nuclear Construction," and Note 8 to the financial statements for additional information.

Income Taxes

Income taxes increased $155 million, or 34.6%, in 2024 as compared to 2023 primarily due to higher pre-tax earnings and a $112 million increase in charges to a valuation allowance on certain state tax credit carryforwards, partially offset by an increase of $79 million in the generation of advanced nuclear PTCs and $26 million from the recognition of certain state tax positions from amended returns. See Note 10 to the financial statements for additional information.

Mississippi Power

Mississippi Power's net income was $199 million in 2024 compared to $188 million in 2023. The increase was primarily due to increases in affiliate wholesale capacity revenues, partially offset by increases in income taxes and non-fuel operations and maintenance expenses.

A condensed income statement for Mississippi Power follows:

Operating Revenues

Operating revenues for 2024 were $1.5 billion, reflecting an $11 million, or 0.7%, decrease from 2023. Details of operating revenues were as follows:

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Retail revenues for 2024 increased $2 million, or 0.2%, compared to 2023. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing was primarily due to certain regulatory assets that fully amortized in December 2023 and higher ECO Plan rates that became effective in June 2024. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" for additional information.

See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including estimated changes related to sales and weather.

Electric rates for Mississippi Power include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel and emissions portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. See Note 2 to the financial statements under "Mississippi Power – Fuel Cost Recovery" for additional information.

Wholesale revenues from power sales to non-affiliated utilities, including FERC-regulated MRA sales as well as market-based sales, were as follows:

Wholesale revenues from sales to non-affiliates decreased $44 million, or 16.2%, in 2024 as compared to 2023. The decrease was largely due to decreases of $35 million associated with power supply agreements mainly due to agreements that ended in 2023 and $10 million associated with MRA customers primarily due to lower recoverable fuel costs and customer usage, partially offset by an increase in demand as a result of weather impacts.

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. In addition, Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under requirements cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 13.9% of Mississippi Power's total operating revenues in 2024. Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Mississippi Power's variable cost to produce the energy. See Note 2 under "Mississippi Power – Municipal and Rural Associations Tariff" for additional information.

Wholesale revenues from sales to affiliates increased $18 million, or 9.0%, in 2024 compared to 2023. The increase was primarily due to an increase of $60 million in capacity revenues primarily associated with a new PPA with Georgia Power and $4 million related to the price of energy driven by natural gas prices. This increase was partially offset by decreases of $31 million in capacity revenues mainly associated with Mississippi Power's lower availability of generation reserves to the Southern Company power pool and $15 million primarily related to the volume of KWH sales. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plans" for additional information.

Wholesale revenues from sales to affiliates will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC or other contractual agreements, as approved by the FERC. The energy portion of these transactions does not have a significant impact on earnings since this energy is generally sold at marginal cost.

In 2024, other operating revenues increased $13 million, or 33.3%, as compared to 2023 primarily due to an increase in open access transmission tariff revenues.

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Energy Sales

Changes in revenues are influenced heavily by the change in the volume of energy sold from year to year. KWH sales for 2024 and the percent change from 2023 were as follows:

(*)Weather-adjusted KWH sales are estimated using statistical models of the historical relationship between temperatures and energy sales, and then removing the estimated effect of deviations from normal temperature conditions. Normal temperature conditions are defined as those experienced in Mississippi Power's service territory over a specified historical period. This metric is useful because it allows trends in historical operations to be evaluated apart from the influence of weather conditions. Management also considers this metric in developing long-term capital and financial plans.

Changes in retail energy sales are generally the result of changes in electricity usage by customers, weather, and the number of customers. Revenues attributable to changes in sales increased in 2024 when compared to 2023. Weather-adjusted residential KWH sales decreased 2.4% primarily due to decreased customer usage. Weather-adjusted commercial KWH sales increased 2.8% primarily due to increased customer usage. Industrial KWH sales increased 0.3% primarily due to an increase in the chemicals sector.

See "Operating Revenues" above for a discussion of significant changes in wholesale revenues to affiliated companies.

Fuel and Purchased Power Expenses

The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally, Mississippi Power purchases a portion of its electricity needs from the wholesale market.

Details of Mississippi Power's generation and purchased power were as follows:

Fuel and purchased power expenses were $477 million in 2024, a decrease of $61 million, or 11.3%, as compared to 2023. The decrease was primarily due to a $45 million net decrease related to the average cost of fuel and purchased power and a $16 million net decrease related to the volume of KWHs generated and purchased.

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Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clauses. See Note 2 to the financial statements under "Mississippi Power – Fuel Cost Recovery" and Note 1 to the financial statements under "Fuel Costs" for additional information.

Fuel expense decreased $75 million, or 14.5%, in 2024 as compared to 2023 primarily due to a 10.8% decrease in the average cost of natural gas per KWH generated and a 7.1% decrease in the volume of KWHs generated by natural gas.

Purchased power expense increased $14 million, or 63.6%, in 2024 as compared to 2023 primarily due to a 56.7% increase in the volume of KWHs purchased and a 3.0% increase in the average cost per KWH purchased.

Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $8 million, or 2.2%, in 2024 as compared to 2023. The increase was primarily due to increases of $10 million in reliability reserve accruals, $6 million in generation expenses primarily associated with non-outage costs, and $4 million in certain compensation and benefits expenses. These increases were partially offset by decreases of $12 million associated with previously deferred Plant Ratcliffe expenses that fully amortized in December 2023 and $4 million associated with the Kemper County energy facility largely due to a decrease in dismantlement costs in 2024 when compared to 2023. See Notes 2 and 3 to the financial statements under "Mississippi Power – Reliability Reserve Accounting Order" and "Other Matters – Mississippi Power," respectively, for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $6 million, or 8.5%, in 2024 as compared to 2023. The increase was primarily due to increases of approximately $4 million related to higher average outstanding borrowings and $2 million related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein and Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net decreased $8 million, or 22.9%, in 2024 as compared to 2023 primarily due to an increase of $13 million in charitable donations, partially offset by an increase of $3 million in customer charges related to contributions in aid of construction.

Income Taxes

Income taxes increased $11 million, or 30.6%, in 2024 as compared to 2023 primarily due to a decrease of $6 million in the flowback of certain excess deferred income taxes and higher pre-tax earnings. See Note 10 to the financial statements for additional information.

Southern Power

Net income attributable to Southern Power for 2024 was $328 million, a $29 million decrease from 2023. The decrease was primarily related to increases in scheduled outage and maintenance expenses, a prior year receipt of an arbitration award for losses previously incurred, and a prior year gain on the sale of spare parts, partially offset by an increase in PPA capacity revenues related to new natural gas PPAs and higher HLBV income associated with tax equity partnerships.

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A condensed statement of income follows:

Operating Revenues

Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the Southern Company power pool.

Natural Gas Capacity and Energy Revenue

Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.

Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are generally accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.

Solar and Wind Energy Revenue

Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors.

See FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.

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Operating Revenues Details

Details of Southern Power's operating revenues were as follows:

Operating revenues for 2024 were $2.0 billion, a $175 million, or 8.0%, decrease from 2023. The change in operating revenues was primarily due to the following:

•PPA capacity revenues increased $26 million, or 5.5%, due to a net increase in MW capacity under contract from natural gas PPAs and an increase associated with a change in rates from natural gas PPAs.

•PPA energy revenues increased $1 million, or 0.1%, primarily due to an increase of $33 million related to the volume of KWHs sold primarily under natural gas and solar PPAs, largely offset by a decrease of $32 million driven by fuel and purchased power prices.

•Non-PPA revenues decreased $184 million, or 42.2%, primarily due to a decrease of $176 million related to the volume of KWHs sold through short-term sales.

•Other revenues decreased $18 million, or 32.7%, primarily due to a prior year receipt of an arbitration award for losses previously incurred and decreases in receipts of liquidated damages associated with generation facility production guarantees.

Fuel and Purchased Power Expenses

Details of Southern Power's generation and purchased power were as follows:

Southern Power's PPAs for natural gas generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the Southern Company power pool for capacity owned directly by Southern Power.

Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the Southern Company power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.

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Details of Southern Power's fuel and purchased power expenses were as follows:

Total fuel and purchased power expenses decreased $165 million, or 20.1%, in 2024 as compared to 2023. Fuel expense decreased $127 million, or 18.0%, due to a $96 million decrease related to the volume of KWHs generated and a $31 million decrease associated with the average cost of fuel. Purchased power expense decreased $38 million, or 32.8%, primarily due to a $32 million decrease associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $43 million, or 9.1%, in 2024 as compared to 2023. The increase was primarily due to an increase of $32 million in scheduled outage and generation maintenance expenses and $11 million associated with an arbitration award received in 2023 related to losses previously incurred.

Depreciation and Amortization

Depreciation and amortization increased $18 million, or 3.6%, in 2024 as compared to 2023 primarily due to a $9 million increase associated with the retirement of assets and $9 million in accelerated depreciation related to the repowering of the Kay Wind facility. See Note 15 to the financial statements under "Southern Power – Development Projects" for additional information.

Gain on Dispositions, Net

Gain on dispositions, net decreased $20 million in 2024 as compared to 2023 primarily due to a $16 million gain on the sale of spare parts in 2023.

Income Taxes (Benefit)

In 2024, income tax benefit was $13 million compared to income tax expense of $12 million for 2023, a change of $25 million. The change was primarily due to lower pre-tax earnings and higher wind and solar PTCs. See Notes 1 and 10 to the financial statements under "Income Taxes" and "Effective Tax Rate," respectively, for additional information.

Net Loss Attributable to Noncontrolling Interests

Net loss attributable to noncontrolling interests increased $14 million, or 11.0%, in 2024 as compared to 2023. The increased loss was primarily due to $23 million in higher HLBV loss allocations to tax equity partners, partially offset by $12 million in higher income allocations to equity partners.

Southern Company Gas

Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory. Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services. Therefore, weather typically does not have a significant net income impact.

During the Heating Season, more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Southern Company Gas' base operating expenses, excluding cost of natural gas and bad debt expense, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. Thus, Southern Company Gas'

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operating results can vary significantly from quarter to quarter as a result of seasonality. The impact of Heating Season on Southern Company Gas' annual results is illustrated in the table below.

Net Income

Net income attributable to Southern Company Gas in 2024 was $740 million, an increase of $125 million, or 20.3%, compared to 2023. The increase was primarily due to a $109 million increase in net income at gas distribution operations and an $11 million increase in net income at gas marketing services.

A condensed income statement for Southern Company Gas follows:

Operating Revenues

Operating revenues in 2024 were $4.5 billion, reflecting a $246 million, or 5.2%, decrease compared to 2023. Details of operating revenues were as follows:

Revenues increased from rate changes in 2024 primarily due to base rate increases at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" for additional information.

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Revenues associated with gas costs and other cost recovery decreased in 2024 primarily due to lower natural gas cost recovery associated with lower natural gas prices and lower demand associated with warmer weather. The natural gas distribution utilities have weather or revenue normalization mechanisms that mitigate revenue fluctuations from customer consumption changes. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information.

Revenues from gas marketing services decreased in 2024 primarily due to lower commodity prices.

Customer Count

The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas distribution operations' and gas marketing services' customers are primarily located in Georgia and Illinois.

The following table provides the number of customers served by Southern Company Gas at December 31, 2024 and 2023:

Southern Company Gas anticipates customer growth and uses a variety of targeted marketing programs to attract new customers and to retain existing customers.

Cost of Natural Gas

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See Note 2 to the financial statements under "Southern Company Gas – Natural Gas Cost Recovery" for additional information. Cost of natural gas at gas distribution operations represented 80.3% of the total cost of natural gas for 2024.

Gas marketing services customers are charged for actual and estimated natural gas consumed. Cost of natural gas includes the cost of fuel and associated transportation costs, lost and unaccounted for gas, and gains and losses associated with certain derivatives.

Cost of natural gas was $1.2 billion, a decrease of $448 million, or 27.3%, in 2024 as compared to 2023, which reflects lower gas cost recovery in 2024 as a result of a 17.1% decrease in natural gas prices compared to 2023.

Volumes of Natural Gas Sold

Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas.

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The following table details the volumes of natural gas sold during 2024 and 2023:

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $48 million, or 4.0%, in 2024 as compared to 2023. The increase was primarily due to increases of $56 million in compensation and benefit expenses and $20 million in survey, locate, and inspection expenses for distribution gas mains. These increases were partially offset by decreases of $12 million related to energy services contracts and $9 million in expenses passed through to customers primarily related to bad debt and energy efficiency programs at gas distribution operations.

Depreciation and Amortization

Depreciation and amortization increased $68 million, or 11.7%, in 2024 as compared to 2023. The increase was primarily due to continued investments at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information.

Estimated Loss on Regulatory Disallowance

In 2023, Southern Company Gas recorded $88 million in charges related to disallowances of certain capital investments at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $31 million, or 10.0%, in 2024 as compared to 2023. The increase reflects approximately $17 million related to higher average outstanding borrowings and $14 million related to higher interest rates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein and Note 8 to the financial statements for additional information.

Income Taxes

Income taxes increased $47 million, or 22.3%, in 2024 as compared to 2023. The increase was primarily due to higher pre-tax earnings. See Note 10 to the financial statements for additional information.

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Segment Information

Gas Distribution Operations

The gas distribution operations segment is the largest component of Southern Company Gas' business and is subject to regulation and oversight by regulatory agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.

With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories. See Note 2 to the financial statements under "Southern Company Gas" for additional information.

In 2024, net income increased $109 million, or 24.7%, compared to 2023. Operating revenues decreased $206 million primarily due to lower gas cost recovery, partially offset by rate increases. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas. Operating expenses decreased $390 million primarily due to a $412 million decrease in cost of natural gas as a result of lower gas prices and lower volumes sold compared to 2023 and the $88 million prior year regulatory disallowance at Nicor Gas, partially offset by higher depreciation resulting from additional assets placed in service, higher compensation and benefits expenses, and higher revenue taxes. The decrease in operating expenses also includes costs passed through directly to customers, primarily related to bad debt expense, energy efficiency programs, and revenue taxes. The decrease in net income also includes an increase of $46 million in income taxes primarily as a result of higher pre-tax earnings and an increase of $36 million in interest expense, net of amounts capitalized primarily due to higher interest rates and higher average outstanding debt. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for additional information.

Gas Pipeline Investments

The gas pipeline investments segment consists primarily of joint ventures in natural gas pipeline investments including SNG and Dalton Pipeline. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

Gas Marketing Services

The gas marketing services segment provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.

In 2024, net income increased $11 million, or 12.1%, compared to 2023. The increase was due to a $43 million decrease in operating expenses primarily related to a decrease in cost of natural gas, partially offset by a $32 million decrease in operating revenues primarily due to lower retail margins.

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All Other

All other includes a renewable natural gas business, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements. All other included a natural gas storage facility in California through its sale in September 2023. See Note 15 to the financial statements under "Southern Company Gas" for additional information.

FUTURE EARNINGS POTENTIAL

General

Prices for electric service provided by the traditional electric operating companies and natural gas distribution service provided by the natural gas distribution utilities to retail customers are set by state PSCs or other applicable state regulatory agencies under cost-based regulatory principles. Retail rates and earnings are reviewed through various regulatory mechanisms and/or processes and may be adjusted periodically within certain limitations. Effectively operating pursuant to these regulatory mechanisms and/or processes and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the traditional electric operating companies and the natural gas distribution utilities for the foreseeable future. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by the FERC. Southern Power continues to focus on long-term PPAs. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Utility Regulation" herein and Note 2 to the financial statements for additional information about regulatory matters.

Each Registrant's results of operations are not necessarily indicative of its future earnings potential. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein. The Registrants are unable to predict changes in law, regulations, regulatory guidance, legal interpretations, policy positions, and implementation actions that may result from the change in presidential administrations.

For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, including those related to projected long-term demand growth, stringent environmental standards, including CCR rules, safety, system reliability and resiliency, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants, extending the retirement dates of certain fossil fuel plants, and expanding and improving the transmission and distribution systems; continued customer growth; and the trends of an uncertain inflationary environment and reduced electricity usage per customer, especially in residential and commercial markets.

Earnings in the electricity business will also depend upon maintaining and growing sales and pricing of large customers such that incremental costs are met with adequate incremental revenues, considering, among other things, recent trends driving projected growth in electricity consumption including the increasing digitization of the economy and growth in data centers, an increase in industrial activity in the Southern Company system's electric service territory, and continued electrification of transportation. These projected growth opportunities could be offset by energy efficiency trends in each market.

Global and U.S. economic conditions continue to be affected by higher-than-expected inflation that arose from the COVID-19 pandemic and associated policy responses of governments and central banks. In response to elevated inflation levels, the U.S. Federal Reserve raised interest rates faster than any rate increase cycle in the last 40 years, which have helped to slow the rate of inflation and curtail economic activity. In 2024, the U.S. Federal Reserve began cutting policy rates as inflation began to approach the 2% target level. Uncertainty remains as to whether the rate reductions will continue in 2025 as potential fiscal policy changes could influence inflation levels, progress to the 2% target, and subsequent policy rate decisions. This uncertainty in economic growth, interest rates, tariffs, and inflation could impact customer demand for energy and the cost of doing business. The shifting economic policy variables and weakening of historic relationships among economic activity, prices, and employment have increased the uncertainty of future levels of economic activity, which will directly impact future energy demand and operating costs. Weakening economic activity increases the risk of slowing or declining energy sales. See RESULTS OF OPERATIONS herein for information on energy sales in the Southern Company system's service territory during 2024.

The level of future earnings for Southern Power's competitive wholesale electric business depends on numerous factors including the parameters of the wholesale market and the efficient operation of its wholesale generating assets; Southern Power's ability to execute its growth strategy through the development, construction, or acquisition of renewable facilities and other energy projects while containing costs; regulatory matters; customer creditworthiness; total electric generating capacity available in Southern Power's market areas; Southern Power's ability to successfully remarket capacity as current contracts expire; renewable portfolio standards; continued availability of federal and state ITCs and PTCs, which could be impacted by future tax legislation; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations. See

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"Income Tax Matters" herein for information regarding the IRA's expansion of the availability of federal ITCs and PTCs. Also see Notes 10 and 15 to the financial statements for additional information.

The level of future earnings for Southern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, including those related to projected long-term demand growth, safety, system reliability and resiliency, natural gas, and capital expenditures, including expanding and improving the natural gas distribution systems; the completion and subsequent operation of ongoing infrastructure and other construction projects; customer creditworthiness; and certain policies to limit the use of natural gas, such as the potential in Illinois and across certain other parts of the United States for state or municipal bans on the use of natural gas or policies designed to promote electrification. The volatility of natural gas prices has an impact on Southern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies, geopolitical events, and diminished gas production, subject a portion of Southern Company Gas' operations to earnings variability and may result in higher natural gas prices. Additional economic factors may contribute to this environment. The demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis. Alternatively, a significant drop in oil and natural gas prices could lead to a consolidation of natural gas producers or reduced levels of natural gas production.

Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather; competition; developing new and maintaining existing energy contracts and associated load requirements with wholesale customers; demand growth in data centers; customer energy conservation practices; the use of alternative energy sources by customers; government incentives to reduce overall energy usage; fuel, labor, and material prices in an environment of heightened inflation and material and labor supply chain disruptions; and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.

Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under requirements cost-based electric tariffs which are subject to regulation by the FERC. The contracts with these wholesale customers represented 13.9% of Mississippi Power's total operating revenues in 2024. See Note 2 to the financial statements under "Mississippi Power – Municipal and Rural Associations Tariff" for information on a rate settlement related to Mississippi Power's contract with Cooperative Energy through the end of 2035, subject to approval by the FERC.

As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of, or the sale of interests in, certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, Southern Power and Southern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements and "Construction Programs" herein for additional information.

Environmental Matters

The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, avian and other wildlife and habitat protection, and other natural resources. The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess both current and upcoming requirements and compliance costs associated with these environmental laws and regulations. New or revised environmental laws and regulations could further affect many areas of operations for the Subsidiary Registrants. The costs required to comply with environmental laws and regulations and to achieve stated goals, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, may impact future electric generating unit retirement and replacement decisions (which are generally subject to approval from the traditional electric operating companies' respective state PSCs), results of operations, cash flows, and/or financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit extensions or retirements and replacements, or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission and distribution (electric and natural gas) systems. A major portion of these costs is expected to be recovered through retail and wholesale rates, including existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed herein cannot be determined at this time and will depend on various factors, such as state adoption and

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implementation of requirements, the availability and cost of any deployed technology, fuel prices, the outcome of pending and/or future legal challenges and regulatory matters, and the ability to continue recovering the related costs, through rates for the traditional electric operating companies and the natural gas distribution utilities and/or through long-term wholesale agreements for the traditional electric operating companies and Southern Power.

Alabama Power and Mississippi Power recover environmental compliance costs through separate mechanisms, Rate CNP Compliance and the ECO Plan, respectively. Georgia Power's base rates include an ECCR tariff that allows for the recovery of environmental compliance costs. The natural gas distribution utilities of Southern Company Gas generally recover environmental remediation expenditures through rate mechanisms approved by their applicable state regulatory agencies. See Notes 2 and 3 to the financial statements for additional information.

Southern Power's PPAs generally contain provisions that permit charging the counterparty for some of the new costs incurred as a result of changes in environmental laws and regulations. Since Southern Power's units are generally newer natural gas and renewable generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal or older natural gas generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the potential presence of wetlands or threatened and endangered species, the availability of water withdrawal rights, uncertainties regarding impacts such as increased light or noise, and concerns about potential adverse health impacts can, however, increase the cost of siting and/or operating any type of existing or future facility. The impact of such laws, regulations, and other considerations on Southern Power and subsequent recovery through PPA provisions cannot be determined at this time.

Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which may have the potential to affect their demand for electricity and natural gas.

Although the timing, requirements, and estimated costs could change materially as environmental laws and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are initiated or completed, estimated capital expenditures through 2029 based on the current environmental compliance strategy for the Southern Company system and the traditional electric operating companies are as follows:

These estimates do not include compliance costs associated with regulation of GHG emissions. See "Environmental Laws and Regulations – Greenhouse Gases" herein for additional information. The Southern Company system also anticipates substantial expenditures associated with surface impoundment closure and groundwater monitoring under the CCR Rule and related state rules, which are reflected in the applicable Registrants' ARO liabilities. See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein and Note 6 to the financial statements for additional information.

Environmental Laws and Regulations

Air Quality

Since 1990, the Southern Company system reduced SO2 and NOX air emissions by 99% and 92%, respectively, through 2023. Since 2005, the Southern Company system reduced mercury air emissions by 97% through 2023.

In February 2023, the EPA published a final rule disapproving 19 state implementation plans (SIPs), including SIPs submitted by the States of Alabama and Mississippi, under the interstate transport (good neighbor) provisions of the Clean Air Act for the 2015 Ozone National Ambient Air Quality Standards (NAAQS). In March 2023, the State of Mississippi and Mississippi Power challenged the EPA's disapproval of the Mississippi SIP in the U.S. Court of Appeals for the Fifth Circuit. In June 2023, the U.S. Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of the Mississippi SIP, pending appeal. In April 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative challenged the EPA's disapproval of the Alabama SIP in the U.S. Court of Appeals for the Eleventh Circuit. In August 2023, the U.S. Court of Appeals for the Eleventh Circuit stayed the EPA's disapproval of the Alabama SIP, pending appeal. On October 21, 2024, the U.S. Supreme Court issued an order granting review of a decision by the U.S. Court of Appeals for the Tenth Circuit transferring challenges to the EPA's disapproval of

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Oklahoma's and Utah's interstate transport SIPs to the U.S. Court of Appeals for the D.C. Circuit. On October 24, 2024, the U.S. Court of Appeals for the Eleventh Circuit placed the Alabama SIP disapproval case in abeyance pending the U.S. Supreme Court's decision on the venue issue.

In June 2023, the EPA published the 2015 Ozone NAAQS Good Neighbor federal implementation plan (FIP), which requires reductions in NOX emissions from sources in 23 states, including Alabama and Mississippi, to assure those states satisfy their Clean Air Act good neighbor obligations for the 2015 Ozone NAAQS. Georgia and North Carolina have approved interstate transport SIPs addressing the 2015 Ozone NAAQS and are not subject to this rule. In June 2023, the State of Mississippi and Mississippi Power challenged the FIP for Mississippi in the U.S. Court of Appeals for the Fifth Circuit. In August 2023, the State of Alabama, Alabama Power, and PowerSouth Energy Cooperative challenged the FIP for Alabama in the U.S. Court of Appeals for the Eleventh Circuit. Both cases are being held in abeyance pending resolution of the Mississippi SIP disapproval and Alabama SIP disapproval cases, respectively. On June 27, 2024, the U.S. Supreme Court stayed the FIP pending the disposition of petitions for review of the FIP in the U.S. Court of Appeals for the D.C. Circuit and any petition for writ of certiorari to the U.S. Supreme Court. On September 12, 2024, the U.S. Court of Appeals for the D.C. Circuit granted the EPA's motion for partial voluntary remand of the FIP to address the administrative record deficiencies preliminarily identified by the U.S. Supreme Court. On December 10, 2024, the EPA published its supplemental response to comments on the FIP which addresses the administrative record deficiencies. On February 6, 2025, the EPA filed a motion in the U.S. Court of Appeals for the D.C. Circuit requesting a 60-day abeyance of the FIP challenges so that the new Trump Administration can determine how to proceed with the litigation.

In July and September 2023, the EPA published an Interim Final Rule and an updated Interim Final Rule that stays the implementation of the FIPs for states with judicially stayed SIP disapprovals, including Mississippi and Alabama, respectively. The Interim Final Rule revises the existing regulations to maintain currently applicable trading programs for those states.

The ultimate impact of the rule and associated legal matters cannot be determined at this time; however, implementation of the stayed FIPs may result in increased compliance costs.

Water Quality

In 2020, the EPA published the final steam electric ELG reconsideration rule (2020 ELG Rule), a reconsideration of the 2015 ELG rule's limits on bottom ash transport water and flue gas desulfurization wastewater that extended the latest applicability date for both discharges to December 31, 2025. The 2020 ELG Rule also updated the voluntary incentive program (VIP) and provided new subcategories for low utilization electric generating units and electric generating units that will permanently cease coal combustion by 2028. On May 9, 2024, the EPA published the final rule revising the Steam Effluent Guidelines (2024 ELG Rule), which establishes more stringent limits for flue gas desulfurization wastewater, bottom ash transport water, and combustion residual leachate to be met no later than December 31, 2029. The 2024 ELG Rule maintains the existing rule's permanent cessation of coal subcategory and the existing rule's VIP and adds a new cessation subcategory which allows units to cease coal combustion by December 31, 2034 as opposed to meeting the new more stringent requirements. The 2024 ELG Rule also establishes limitations for legacy wastewater which became effective on July 8, 2024. Numerous groups and states filed petitions for review challenging the rule in multiple federal circuit courts, and, on June 14, 2024, the challenges were consolidated in the U.S. Court of Appeals for the Eighth Circuit. On July 26, 2024, industry and state petitioners filed a motion to stay the rule pending judicial review, which was denied on October 10, 2024. The ultimate impact of the 2024 ELG Rule and associated legal matters cannot be determined at this time; however, it may result in significant compliance costs.

As required by the 2020 ELG Rule, in 2021, Alabama Power and Georgia Power each submitted initial notices of planned participation (NOPP) for applicable units seeking to qualify for these cessation of coal combustion or VIP subcategories that require compliance by December 31, 2028.

Alabama Power submitted its NOPP to the Alabama Department of Environmental Management (ADEM) indicating plans to retire Plant Barry Unit 5 (700 MWs) and to cease using coal and begin operating solely on natural gas at Plant Barry Unit 4 (350 MWs) and Plant Gaston Unit 5 (880 MWs). Alabama Power, as agent for SEGCO, indicated plans to retire Plant Gaston Units 1 through 4 (1,000 MWs). However, Alabama Power, in conjunction with Georgia Power, is evaluating extending the operation of Plant Gaston Units 1 through 4 beyond the indicated retirement date. The NOPP submittals are subject to the review of the ADEM. Plant Barry Unit 4 ceased using coal and began to operate solely on natural gas in December 2022. See Notes 2 and 7 to the financial statements under "Georgia Power – Integrated Resource Plans" and "SEGCO," respectively, for additional information.

The remaining assets for which Alabama Power has indicated retirement, due to early closure or repowering of the unit to natural gas, have net book values totaling approximately $944 million (excluding capitalized asset retirement costs which are recovered through Rate CNP Compliance) at December 31, 2024. Based on an Alabama PSC order, Alabama Power is authorized to establish a regulatory asset to record the unrecovered investment costs, including the plant asset balance and the site removal and closure costs, associated with unit retirements caused by environmental regulations (Environmental Accounting Order). Under the

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Environmental Accounting Order, the regulatory asset would be amortized and recovered over an affected unit's remaining useful life, as established prior to the decision regarding early retirement, through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and " – Environmental Accounting Order" for additional information.

Georgia Power submitted its NOPP to the Georgia Environmental Protection Division (EPD) indicating plans to retire Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), which occurred in August 2022, Plant Bowen Units 1 and 2 (1,400 MWs), and Plant Scherer Unit 3 (614 MWs based on 75% ownership) on or before the compliance date of December 31, 2028. Georgia Power also submitted a NOPP indicating plans to pursue compliance with the 2020 ELG Rule for Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership) through the VIP by no later than December 31, 2028. Georgia Power intends to comply with the ELG rules for Plant Bowen Units 3 and 4 through the generally applicable requirements by December 31, 2025; therefore, no NOPP submission was required for these units. The NOPP submittals and generally applicable requirements are subject to the review of the Georgia EPD and decisions related to retirement or continued operation of units are subject to Georgia PSC approval.

On January 31, 2025, Georgia Power filed its 2025 IRP, which includes a request to extend the operation of Plant Scherer Unit 3 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. As in the 2023 IRP Update as well as the 2025 IRP, Plant Bowen Units 1 and 2 were also assumed to operate through at least the end of 2035. See Notes 2 and 7 to the financial statements under "Georgia Power – Integrated Resource Plans" and "SEGCO," respectively, for additional information.

Coal Combustion Residuals

In 2015, the EPA finalized non-hazardous solid waste regulations for the management and disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments at active electric generating power plants. The CCR Rule requires landfills and surface impoundments to be evaluated against a set of performance criteria and potentially closed if certain criteria are not met. Closure of existing landfills and surface impoundments requires installation of equipment and infrastructure to manage CCR in accordance with the CCR Rule. In addition to the federal CCR Rule, the States of Alabama and Georgia finalized state regulations regarding the management and disposal of CCR within their respective states. In 2019, the State of Georgia received partial approval from the EPA for its state CCR permitting program, which has broader applicability than the federal rule. The State of Mississippi has not developed a state CCR permit program.

On June 7, 2024, the EPA published a final determination to deny the ADEM's CCR permit program. Alabama Power's permits to close its CCR facilities remain valid under state law. In the absence of an EPA-approved state permit program, CCR facilities in Alabama will remain subject to both the federal and state CCR rules. The ultimate impact of this action cannot be determined at this time; however, it may result in significant compliance costs.

The Holistic Approach to Closure: Part A rule, finalized in 2020, revised the deadline to stop sending CCR and non-CCR wastes to unlined surface impoundments to April 11, 2021 and established a process for the EPA to approve extensions to the deadline. The traditional electric operating companies stopped sending CCR and non-CCR wastes to their unlined surface impoundments prior to April 11, 2021 and, therefore, did not submit requests for extensions. Beginning in January 2022, the EPA issued numerous Part A determinations that state its current positions on a variety of CCR Rule compliance requirements, such as criteria for groundwater corrective action and CCR unit closure. The traditional electric operating companies are working with state regulatory agencies to determine whether the EPA's current positions may impact closure and groundwater monitoring plans.

In April 2022, the Utilities Solid Waste Activities Group and a group of generating facility operators filed petitions for review in the U.S. Court of Appeals for the D.C. Circuit challenging whether the EPA's January 2022 actions establish new legislative rules that should have gone through notice-and-comment rulemaking. On June 28, 2024, the U.S. Court of Appeals for the D.C. Circuit issued a decision dismissing the challenges to the EPA's January 2022 actions and interpretations related to the closure performance standards in the 2015 CCR rule. The ultimate impact of this decision and the EPA's current positions cannot be determined at this time; however, it may result in significant compliance costs.

On May 8, 2024, the EPA published the final legacy CCR surface impoundments rule which regulates two new categories of federally regulated CCR, legacy surface impoundments and CCR management units (CCRMUs). The rule requires legacy surface impoundments and CCRMUs to meet certain existing regulatory requirements, including a requirement to initiate closure within 42 months after the effective date of the final rule for legacy surface impoundments and within 54 months after the effective date of the final rule for CCRMUs. The final rule also includes an option to defer closure of previously closed units where certain criteria have been met. The final rule also includes enhanced reporting requirements. The EPA is also finalizing an alternative provision for closure by removal that will allow certifying completion of closure of a unit while conducting groundwater monitoring and corrective action during post-closure care. Numerous industry groups, electric generators, and states filed petitions for review challenging the rule in the U.S. Court of Appeals for the D.C. Circuit. On August 19, 2024, an industry petitioner filed

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a motion seeking to stay the legacy CCR rule pending judicial review, which was denied by the U.S. Court of Appeals for the D.C. Circuit on November 1, 2024. On November 5, 2024, the industry petitioner filed an emergency stay application with the U.S. Supreme Court, which was denied on December 11, 2024. On February 13, 2025, the U.S. Court of Appeals for the D.C. Circuit placed the legacy CCR rule challenges in abeyance for 120 days so that the new Trump Administration can determine how to proceed with the litigation. The ultimate impact of the final rule and associated legal matters cannot be determined at this time; however, it may result in significant compliance costs.

Based on requirements for closure and monitoring of landfills and surface impoundments pursuant to the CCR Rule and applicable state rules, the traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to compliance monitoring, closure methodologies and strategies, schedules, and/or costs becomes available. Some of these updates have been, and future updates may be, material. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein, Notes 2 and 3 to the financial statements under "Georgia Power – Rate Plans" and "General Litigation Matters – Alabama Power," respectively, and Note 6 to the financial statements for additional information.

Greenhouse Gases

On May 9, 2024, the EPA published the final GHG rules for existing fossil fuel-fired steam electric generating units and new fossil fuel-fired combustion turbines and combined cycle generation facilities, which requires GHG limits for subcategories of both new and existing units. The new rules do not include standards for existing fossil fuel-fired combustion turbines and combined cycle generation facilities, which have been deferred to a future rulemaking. Requirements for existing coal-fired units are based on technologies such as carbon capture and sequestration (CCS) and natural gas co-firing. States have 24 months after the rule's publication to submit state plans for existing units. The rule allows states to consider remaining useful life and other factors to specify alternative, unit-specific emissions limits and compliance timelines for existing units, as needed to address reliability and other concerns. Existing source compliance will begin as early as January 1, 2030, depending on the subcategory. The final rule incorporates some limited reliability mechanisms including a provision for short-term grid emergencies and a "reliability assurance mechanism" that allows for a one-time, up to one year, extension of existing coal unit retirement dates specified in an approved state plan. The standards for new combustion turbines and combined cycles include subcategories for low, intermediate, and base load operations. Compliance with new source standards begins when the unit comes online, with requirements for CCS beginning on January 1, 2032. The EPA also simultaneously repealed the Affordable Clean Energy rule. Numerous industry groups, electric generators, and states have filed petitions for review challenging the rule in the U.S. Court of Appeals for the D.C. Circuit. A total of eight stay motions were filed seeking a stay of the rule pending judicial review, which were denied by the U.S. Court of Appeals for the D.C. Circuit on July 19, 2024. On February 5, 2025, the EPA filed a motion in the U.S. Court of Appeals for the D.C. Circuit requesting a 60-day abeyance of the challenges so that the new Trump Administration can determine how to proceed with the litigation. On October 16, 2024, the U.S. Supreme Court denied emergency stay applications filed by numerous industry groups, electric generators, and states. The ultimate impact of the final rules and associated legal matters cannot be determined at this time; however, it may result in significant compliance costs.

In 2021, the United States officially rejoined the Paris Agreement. The Paris Agreement establishes a non-binding universal framework for addressing GHG emissions based on nationally determined emissions reduction contributions and sets in place a process for tracking progress towards the goals every five years. On January 20, 2025, President Trump issued an executive order directing the United States to withdraw from the Paris Agreement and revoke commitments made by the United States under the United Nations Framework Convention on Climate Change.

Additional GHG policies, including legislation, may emerge in the future requiring the United States to accelerate its transition to a lower GHG emitting economy; however, associated impacts are currently unknown. The Southern Company system has transitioned from an electric generating mix of 70% coal, 15% natural gas, and 14% nuclear in 2007 to a mix of 18% coal, 52% natural gas, and 20% nuclear in 2024. This transition has been supported in part by the Southern Company system retiring over 6,700 MWs of coal-fired generating capacity since 2010 and converting 3,700 MWs of generating capacity from coal to natural gas since 2015, as well as the addition of over 1,100 MWs of nuclear generating capacity (based on Georgia Power's ownership interest in Plant Vogtle Units 3 and 4) since 2023. In addition, the Southern Company system's capacity mix consists of over 12,500 MWs of renewable and storage facilities through ownership (including 100% of the nameplate capacity of Southern Power's facilities owned with partners) and long-term PPAs. See "Environmental Laws and Regulations – Water Quality" herein for information on plans to retire or convert to natural gas additional coal-fired generating capacity. In addition, Southern Company Gas has replaced over 6,000 miles of pipe material that was more prone to fugitive emissions (unprotected steel and

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cast-iron pipe), resulting in mitigation of more than 3.3 million metric tons of CO2 equivalents from its natural gas distribution system since 1998.

The following table provides the Registrants' 2023 and preliminary 2024 Scope 1 GHG emissions based on equity share of facilities:

(*)Includes GHG emissions attributable to disposed assets through the date of the applicable disposition. See Note 15 to the financial statements for additional information.

Southern Company system management has established an intermediate goal of a 50% reduction in GHG emissions from 2007 levels by 2030 and a long-term goal of net zero GHG emissions by 2050. Based on the preliminary 2024 emissions, the Southern Company system has achieved an estimated GHG emission reduction of 49% since 2007. Although electric generation increased, GHG emissions remained flat in 2024 when compared to 2023 due to an increase in lower carbon generation, including from Plant Vogtle Units 3 and 4, as discussed further under RESULTS OF OPERATIONS – "Southern Company – Electricity Business" herein. While none of Southern Company's subsidiaries are currently subject to renewable portfolio standards or similar requirements, management of the traditional electric operating companies is working with applicable regulators through their IRP processes to continue the generating fleet transition in a manner responsible to customers, communities, employees, and other stakeholders. The natural gas distribution utilities also engage in long-term planning processes in accordance with their state regulatory processes and are investing in programs and efforts to reduce GHG emissions associated with the delivery and use of natural gas, such as advanced leak detection and repair and renewable natural gas. Achievement of these goals is dependent on various factors, many of which the Southern Company system does not control, including load growth across the Southern Company system's service territory, energy policy and regulations, natural gas prices, and the pace and extent of development and deployment of low- to no-GHG energy technologies and negative carbon concepts. Southern Company system management plans to continue to economically transition the Southern Company system's generating fleet through a diverse portfolio of resources including low-carbon and carbon-free resources; making the necessary related investments in transmission and distribution systems; continuing to implement effective energy efficiency and demand response programs; customer demand for carbon-free energy; implementing initiatives to reduce natural gas distribution emissions; continuing research and development with a focus on technologies that lower GHG emissions, including methods of removing carbon from the atmosphere; and constructively engaging with policymakers, regulators, investors, customers, and other stakeholders to support outcomes leading to a net zero future. There is no guarantee that the Southern Company system will achieve these goals.

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 Southern Company Gas conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in their financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia (which represent substantially all of Southern Company Gas' accrued remediation costs) have all 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. The traditional electric operating companies and Southern Company Gas may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Remediation" for additional information.

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Regulatory Matters

See OVERVIEW – "Recent Developments" herein and Note 2 to the financial statements for a discussion of regulatory matters related to Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas, including items that could impact the applicable Registrants' future earnings, cash flows, and/or financial condition.

Construction Programs

The Southern Company system strategy continues to include developing and constructing new electric generating facilities, expanding and improving the electric transmission and electric and natural gas distribution systems, and undertaking projects to comply with environmental laws and regulations.

The traditional electric operating companies are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. Major generation construction projects are subject to state PSC approval in order to be included in retail rates. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for information regarding Georgia Power's construction of three simple cycle combustion turbines at Plant Yates and additional capacity through its 2022 IRP and 2023 IRP Update sought through RFPs.

Southern Power's construction program includes the Millers Branch solar project and the Kay Wind repowering project. The Kay Wind repowering project results in accelerated depreciation related to the equipment being replaced that will continue until commercial operation of the project, which is projected to occur in the third quarter 2026. Pre-tax accelerated depreciation, net of noncontrolling interest impacts, is projected to total approximately $100 million in 2025 and $40 million in 2026. See Note 15 to the financial statements under "Southern Power" for information relating to Southern Power's construction of renewable energy facilities.

Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and resiliency, reduce emissions, and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" for additional information on Southern Company Gas' construction program.

SNG is developing an approximately $3 billion proposed pipeline project, designed to meet customer demand by increasing SNG's existing pipeline capacity by approximately 1.3 billion cubic feet per day. Subject to the satisfaction or waiver of various conditions, including the receipt of all required approvals by regulators, including the FERC, the operator of the joint venture anticipates the project will be completed in 2029. Southern Company Gas' share of the total project costs would be 50%. The ultimate outcome of this matter cannot be determined at this time. See Note 7 to the financial statements under "Southern Company Gas" for additional information on SNG.

See FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements – Capital Expenditures" herein for additional information regarding the Registrants' capital requirements for their construction programs, including estimated totals for each of the next five years.

Southern Power's Power Sales Agreements

General

Southern Power has PPAs with certain of the traditional electric operating companies, other investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. The PPAs are expected to provide Southern Power with a stable source of revenue during their respective terms.

Many of Southern Power's PPAs have provisions that require Southern Power or the counterparty to post collateral or an acceptable substitute guarantee if (i) S&P, Fitch, or Moody's downgrades the credit ratings of the respective company to an unacceptable credit rating, (ii) the counterparty is not rated, or (iii) the counterparty fails to maintain a minimum coverage ratio. See FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information.

Southern Power works to maintain and expand its share of the wholesale market. During 2024, Southern Power continued to be successful in remarketing up to 1,014 MWs of annual natural gas and solar generation capacity to load-serving entities through several PPAs extending over the next 16 years. Market demand is being driven by load-serving entities replacing expired purchase contracts and/or retired generation, as well as planning for future growth.

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Natural Gas

Southern Power's electricity sales from natural gas facilities are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated generating unit where all or a portion of the generation from that unit is reserved for that customer. Southern Power typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides that Southern Power serve the customer's capacity and energy requirements from a combination of the customer's own generating units and from Southern Power resources not dedicated to serve unit or block sales. Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable.

As a general matter, substantially all of the PPAs provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel or purchased power relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs, Southern Power may be responsible for excess fuel costs. With respect to fuel transportation risk, most of Southern Power's PPAs provide that the counterparties are responsible for the availability of fuel transportation to the particular generating facility.

Capacity charges that form part of the PPA payments are designed to recover fixed and variable operation and maintenance costs based on dollars-per-kilowatt year. In general, to reduce Southern Power's exposure to certain operation and maintenance costs, Southern Power has LTSAs. See Note 1 to the financial statements under "Long-Term Service Agreements" for additional information.

Solar and Wind

Southern Power's electricity sales from solar and wind generating facilities are also primarily through long-term PPAs; however, these PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or provide Southern Power a certain fixed price for the electricity sold to the grid. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Generally, under the renewable generation PPAs, the purchasing party retains the right to keep or resell the associated renewable energy credits.

Income Tax Matters

Consolidated Income Taxes

The impact of certain tax events at Southern Company and/or its other subsidiaries can, and does, affect each Registrant's ability to utilize certain tax credits. See "Tax Credits" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates – Accounting for Income Taxes" herein and Note 10 to the financial statements for additional information.

Tax Credits

Southern Company receives ITCs and PTCs in connection with investments in solar, wind, fuel cell, advanced nuclear, hydroelectric, and battery energy storage facilities primarily at Southern Power, Georgia Power, and Alabama Power.

Southern Power's ITCs relate to its investment in new solar facilities and battery energy storage facilities (co-located with existing solar facilities) that are acquired or constructed and its PTCs relate to the first 10 years of energy production from its wind and solar facilities, which have had, and may continue to have, a material impact on Southern Power's cash flows and net income. At December 31, 2024, Southern Company and Southern Power had approximately $765 million and $384 million, respectively, of unutilized federal ITCs and PTCs, which are currently projected to be fully utilized by 2028 but could be further delayed. Since 2018, Southern Power has utilized tax equity partnerships for certain wind, solar, and battery energy storage projects, where the tax equity partner takes significantly all of the respective federal tax benefits. These tax equity partnerships are consolidated in Southern Company's and Southern Power's financial statements using the HLBV methodology to allocate partnership gains and losses.

In the third quarter 2023 and the second quarter 2024, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Units 3 and 4, respectively, beginning on each unit's respective in-service date. PTCs are recognized as an income tax benefit based on KWH production. In addition, pursuant to the Vogtle Joint Ownership Agreements (as defined in Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Cost and Schedule"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Units 3 and 4 from the other Vogtle Owners. The gain recognized on the purchase of the joint owner PTCs is recognized as an income tax benefit. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

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See Note 1 to the financial statements under "General" for additional information on the HLBV methodology and Note 1 to the financial statements under "Income Taxes" and Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" and "Effective Tax Rate" for additional information regarding utilization and amortization of credits and the tax benefit related to associated basis differences.

Inflation Reduction Act

In 2022, the IRA was signed into law. The IRA extends, expands, and increases ITCs and PTCs for clean energy projects, allows PTCs for solar projects, adds ITCs for stand-alone energy storage projects with an option to elect out of the tax normalization requirement, and allows for the transferability of the tax credits. The IRA extends and increases the tax credits for CCS projects and adds tax credits for clean hydrogen and nuclear projects. Additional ITC and PTC amounts are available if the projects meet domestic content requirements or are located in low-income or energy communities. The IRA also enacted a 15% CAMT on book income, with material adjustments for pension costs and tax depreciation. The 15% CAMT on book income can be reduced by tax credits.

For solar projects placed in service in 2022 through 2032, the IRA provides for a 30% ITC and an option to claim a PTC instead of an ITC. Starting in 2023 and through 2032, the IRA provides for a 30% ITC for stand-alone energy storage projects. For wind projects placed in service in 2022 through 2032, the IRA provides for a 100% PTC, adjusted for inflation annually. For projects placed in service before 2022, the 2024 PTC rate is 2.9 cents per KWH. For projects placed in service in 2022 and later, the 2024 PTC rate is 3 cents per KWH. The same PTC rate applies for solar projects for which the PTC option has been elected. To realize the full value of ITCs and PTCs, the IRA requires satisfaction of prevailing wage and apprenticeship requirements.

In April 2024, the IRS issued final regulations related to the transfer of tax credits. In 2024, Alabama Power, Georgia Power, and Southern Power entered into purchase and sale agreements with non-affiliated parties to sell ITCs and PTCs at a discount to the generated credit value in 2024, 2025, and 2026. The discount will be recorded as a reduction in tax credits recognized in the financial statements. The Southern Company system continues to explore the ability to efficiently monetize tax credits through third-party transferability agreements. See Note 10 to the financial statements for additional information.

Alabama Power and Georgia Power have nuclear generating facilities that may qualify to generate and claim PTCs under the IRA beginning in 2024.

On September 12, 2024, the U.S. Treasury Department and the IRS issued a notice of proposed regulations that would address the application of the CAMT. Southern Company is evaluating the proposed regulations and is subject to the CAMT for the 2024 tax year, primarily driven by tax deductions for Georgia Power's storm restoration costs and the natural gas safe harbor tax accounting method change, based on interpretations of the early CAMT guidance. The CAMT will primarily be satisfied by tax credits for the 2024 tax year. The CAMT impacts operating cash flows of certain Registrants but will not impact the Registrants' net income. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information on Georgia Power's storm restoration costs. Also see "Natural Gas Safe Harbor Method" herein and Note 10 to the financial statements for additional information.

Implementation of the IRA provisions related to existing nuclear generating facilities and CAMT is subject to the issuance of additional guidance by the U.S. Treasury Department and the IRS. The Registrants are still evaluating the impacts, and the ultimate outcome of this matter cannot be determined at this time.

Georgia State Tax Legislation

On April 18, 2024, the State of Georgia enacted tax legislation that reduced the corporate income tax rate from 5.75% to 5.39% effective for the 2024 tax year. This legislation reduced the amount of Southern Company's and certain subsidiaries' income tax expense in the State of Georgia and existing state net accumulated deferred tax liabilities, increased regulatory liabilities at Georgia Power and Southern Company Gas, and reduces Georgia Power's ability to utilize certain state tax credits in the State of Georgia. The legislation did not have a material impact on the net income of the applicable Registrants.

Natural Gas Safe Harbor Method

In April 2023, the IRS issued Revenue Procedure 2023-15, which provides a safe harbor tax method of accounting that taxpayers may use to determine whether certain expenditures to maintain, repair, replace, or improve natural gas transmission and distribution property must be capitalized or allowed as repair deductions. The revenue procedure allows multiple alternatives for implementation which will result in a tax accounting method change for Southern Company Gas' eligible expenditures. On April 30, 2024, the IRS issued Revenue Procedure 2024-23, which gives additional implementation guidance on the natural gas safe harbor tax method of accounting for qualifying repair deductions. Southern Company and Southern Company Gas intend to submit a tax accounting method change for qualifying expenditures with the filing of the 2024 federal income tax return. The new tax method of accounting is expected to result in a material net positive cash flow for Southern Company Gas; however, the

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timing of this positive cash flow will be delayed by application of the CAMT. This method change will not have an impact on the net income of Southern Company and Southern Company Gas. See Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" for additional information.

General Litigation and Other Matters

The Registrants are involved in various matters being litigated and/or regulatory and other matters that could affect future earnings, cash flows, and/or financial condition. The ultimate outcome of such pending or potential litigation against each Registrant and any subsidiaries or regulatory and other matters cannot be determined at this time; however, for current proceedings and/or matters not specifically reported herein or in Notes 2 and 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings and/or matters would have a material effect on such Registrant's financial statements. See Notes 2 and 3 to the financial statements for a discussion of various contingencies, including matters being litigated, regulatory matters, and other matters which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

The Registrants prepare their financial statements in accordance with GAAP, which requires the use of estimates, judgments, and assumptions. Significant accounting policies are described in the notes to the financial statements. Detailed further herein are certain estimates made in the application of these policies that may have a material impact on the results of operations, financial condition, and related disclosures of the applicable Registrants (as indicated in the section descriptions herein). Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. Senior management has reviewed and discussed these critical accounting policies and estimates with the Audit Committee of Southern Company's Board of Directors.

Utility Regulation (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The traditional electric operating companies and the natural gas distribution utilities are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by the FERC. These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards for rate regulated entities also impacts their financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the results of operations and financial condition of the applicable Registrants than they would on a non-regulated company. Additionally, a regulatory agency may disallow recovery of all or a portion of certain assets. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for information regarding the disallowance of certain capital investments at Nicor Gas.

Revenues related to regulated utility operations as a percentage of total operating revenues in 2024 for the applicable Registrants were as follows: 89% for Southern Company, 98% for Alabama Power, 95% for Georgia Power, 99% for Mississippi Power, and 87% for Southern Company Gas.

As reflected in Note 2 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the financial statements of the applicable Registrants.

Accounting for Income Taxes (Southern Company, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas)

The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data,

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reasonable projections of taxable income, the ability and intent to implement tax planning strategies if necessary, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in which the Southern Company system operates.

Southern Company files a consolidated federal income tax return and the Registrants file various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and each subsidiary is allocated an amount of tax similar to that which would be paid if it filed a separate income tax return except for certain credit utilization and state apportionment results. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability. Certain deductions and credits can be limited or utilized at the consolidated or combined level resulting in tax credit and/or state net operating loss carryforwards that would not otherwise result on a stand-alone basis. Utilization of these carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis of Southern Company's and its subsidiaries' current financial position and results of operations, including currently available information about future years, to estimate when future taxable income will be realized. See Note 10 to the financial statements under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" and " – Net Operating Loss Carryforwards" for additional information.

Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States have various filing methodologies and utilize specific formulas to calculate the apportionment of taxable income. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. Any apportionments and/or filing methodologies ultimately finalized in a manner inconsistent with expectations could have a material effect on the financial statements of the applicable Registrants.

Asset Retirement Obligations (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

Estimating AROs requires significant judgment. AROs are computed as the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities.

The ARO liabilities for the traditional electric operating companies primarily relate to facilities that are subject to the CCR Rule and the related state rules, principally surface impoundments. In addition, Alabama Power and Georgia Power have retirement obligations related to the decommissioning of nuclear facilities (Alabama Power's Plant Farley and Georgia Power's ownership interests in Plants Hatch and Vogtle). Other significant AROs include various landfill sites and asbestos removal for Alabama Power, Georgia Power, and Mississippi Power and gypsum cells and mine reclamation for Mississippi Power.

The traditional electric operating companies and Southern Company Gas also have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain transformers, leasehold improvements, equipment on customer property, and property associated with the Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.

The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule and the related state rules. The traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to these assumptions becomes available. Some of these updates have been, and future updates may be, material. The cost estimates for Alabama Power are based on closure-in-place for all surface impoundments. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some surface impoundments and closure by removal for others. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. See Note 6 to the financial statements and FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein for additional information, including updates to AROs related to surface impoundments recorded during 2024 by certain Registrants.

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Pension and Other Postretirement Benefits (Southern Company, Alabama Power, Georgia Power, Mississippi Power, and Southern Company Gas)

The applicable Registrants' calculations of pension and other postretirement benefits expense are dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term rate of return (LRR) on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the applicable Registrants believe the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect their pension and other postretirement benefit costs and obligations.

Key elements in determining the applicable Registrants' pension and other postretirement benefit expense are the LRR and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. For purposes of determining the applicable Registrants' liabilities related to the pension and other postretirement benefit plans, Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. The discount rate assumption impacts both the service cost and non-service costs components of net periodic benefit costs as well as the projected benefit obligations.

The LRR on pension and other postretirement benefit plan assets is based on Southern Company's investment strategy, as described in Note 11 to the financial statements, historical experience, and expectations that consider external actuarial advice, and represents the average rate of earnings expected over the long term on the assets invested to provide for anticipated future benefit payments. Southern Company determines the amount of the expected return on plan assets component of non-service costs by applying the LRR of various asset classes to Southern Company's target asset allocation. The LRR only impacts the non-service costs component of net periodic benefit costs for the following year and is set annually at the beginning of the year.

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The following table illustrates the sensitivity to changes in the applicable Registrants' long-term assumptions with respect to the discount rate, salary increases, and the long-term rate of return on plan assets:

See Note 11 to the financial statements for additional information regarding pension and other postretirement benefits.

Impairment (Southern Company, Alabama Power, Southern Power, and Southern Company Gas)

Goodwill (Southern Company and Southern Company Gas)

The acquisition method of accounting for business combinations requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. The applicable Registrants have recognized goodwill as of the date of their acquisitions, as a residual over the fair values of the identifiable net assets acquired. Goodwill is recorded at the reporting unit level, which is the operating segment or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by management. Components are aggregated if they have similar economic characteristics. Goodwill is tested for impairment at the reporting unit level on an annual basis in the fourth quarter of the year and on an interim basis if events and circumstances occur that indicate goodwill may be impaired.

Goodwill is evaluated for impairment either under the qualitative assessment option or the quantitative option to determine the fair value of the reporting unit. If goodwill is determined to be impaired, an impairment loss measured at the amount by which the reporting unit's carrying amount exceeds its fair value, not to exceed the carrying amount of goodwill, is recorded.

Goodwill for Southern Company and Southern Company Gas was $5.2 billion and $5.0 billion, respectively, at December 31, 2024. During 2022, Southern Company recorded a $119 million impairment loss as a result of its annual goodwill impairment test for PowerSecure.

The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact the applicable Registrant's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain

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estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates.

See Note 1 to the financial statements under "Goodwill and Other Intangible Assets" for additional information regarding the applicable Registrants' goodwill.

Long-Lived Assets (Southern Company, Alabama Power, Southern Power, and Southern Company Gas)

The applicable Registrants assess their other long-lived assets for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. If an impairment indicator exists, the asset is tested for recoverability by comparing the asset carrying amount to the sum of the undiscounted expected future cash flows directly attributable to the asset's use and eventual disposition. If the estimate of undiscounted future cash flows is less than the carrying amount of the asset, the fair value of the asset is determined and a loss is recorded equal to the difference between the carrying amount and the fair value of the asset. In addition, when assets are identified as held for sale, an impairment loss is recognized to the extent the carrying amount of the assets or asset group exceeds their fair value less cost to sell. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, some of which have been quite volatile in recent years. See Notes 1 and 15 to the financial statements for additional information, including recent asset impairments.

As the determination of the expected future cash flows generated from an asset, an asset's fair value, and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates.

Revenue Recognition (Southern Power)

Southern Power's power sale transactions, which include PPAs, are classified in one of four general categories: leases, normal sale derivatives or contracts with customers, derivatives designated as cash flow hedges, and derivatives not designated as hedges. Southern Power's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract. The two categories with the most judgment required for Southern Power are described further below.

Lease Transactions

Southern Power considers the terms of a sales contract to determine whether it should be accounted for as a lease. A contract is or contains a lease if the contract conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. If the contract meets the criteria for a lease, Southern Power performs further analysis to determine whether the lease is classified as operating, financing, or sales-type. Generally, Southern Power's power sales contracts that are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and is included in Southern Power's operating revenues. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. For those contracts that are determined to be sales-type leases, capacity revenues are recognized by accounting for interest income on the net investment in the lease and are included in Southern Power's operating revenues. See Note 9 to the financial statements for additional information.

Normal Sale Derivative Transactions and Contracts with Customers

If the power sales contract is not classified as a lease, Southern Power further considers whether the contract meets the definition of a derivative. If the contract does meet the definition of a derivative, Southern Power will assess whether it can be designated as a normal sale contract. The determination of whether a contract can be designated as a normal sale contract requires judgment, including whether the sale of electricity involves physical delivery in quantities within Southern Power's available generating capacity and that the purchaser will take quantities expected to be used or sold in the normal course of business.

Contracts that do not meet the definition of a derivative or are designated as normal sales are accounted for as revenue from contracts with customers. For contracts that have a capacity charge, the revenue is generally recognized in the period that it becomes billable. Revenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered. See Note 4 to the financial statements for additional information.

Acquisition Accounting (Southern Power)

Southern Power may acquire generation assets as part of its overall growth strategy. At the time of an acquisition, Southern Power will assess if these assets and activities meet the definition of a business. Acquisitions that meet the definition of a business are accounted for under the acquisition method, whereby the identifiable assets acquired, liabilities assumed, and any noncontrolling interests (including any intangible assets, primarily related to acquired PPAs) are recognized and measured at fair value. Assets

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acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired.

Determining the fair value of assets acquired and liabilities assumed requires management judgment and Southern Power may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. For potential or successful acquisitions that meet the definition of a business, any due diligence or transaction costs incurred are expensed as incurred. If the acquisition is an asset acquisition, direct and incremental transaction costs can be capitalized as a component of the cost of the assets acquired.

See Note 13 to the financial statements for additional fair value information and Note 15 to the financial statements for additional information on recent acquisitions.

Variable Interest Entities (Southern Power)

Southern Power has partnerships with varying ownership structures. Upon entering into these arrangements, membership interests and other variable interests are evaluated to determine if the legal entity is a VIE. If the legal entity is a VIE, Southern Power will assess if it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE, making it the primary beneficiary. Making this determination may require significant management judgment.

If Southern Power is the primary beneficiary and is considered to have a controlling ownership, the assets, liabilities, and results of operations of the entity are consolidated. If Southern Power is not the primary beneficiary, the legal entity is generally accounted for under the equity method of accounting. Southern Power reconsiders its conclusions as to whether the legal entity is a VIE and whether it is the primary beneficiary for events that impact the rights of variable interests, such as ownership changes in membership interests.

Southern Power has controlling ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in an HLBV at the end of the period compared to the beginning of the period.

Contingent Obligations (All Registrants)

The Registrants are subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject them to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Notes 2 and 3 to the financial statements for more information regarding certain of these contingencies. The Registrants periodically evaluate their exposure to such risks and record reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the results of operations, cash flows, or financial condition of the Registrants.

Recently Issued Accounting Standards

See Note 1 to the financial statements under "Recently Adopted Accounting Standards" for additional information.

FINANCIAL CONDITION AND LIQUIDITY

Overview

The financial condition of each Registrant remained stable at December 31, 2024. The Registrants' cash requirements primarily consist of funding ongoing operations, including unconsolidated subsidiaries, as well as common stock dividends, capital expenditures, and debt maturities. Southern Power's cash requirements also include distributions to noncontrolling interests. Capital expenditures and other investing activities for the traditional electric operating companies include investments to build new generation facilities to meet projected long-term demand requirements and to replace units being retired as part of the generation fleet transition, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units and closures of surface impoundments, to expand and improve transmission and distribution facilities, and for restoration following major storms. Southern Power's capital expenditures and other investing activities may include acquisitions or new construction associated with its overall growth strategy and to maintain its existing generation fleet's performance. Southern Company Gas' capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing natural gas transmission and distribution

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systems as well as to update and expand these systems, and to comply with environmental regulations. See "Cash Requirements" herein for additional information.

Operating cash flows provide a substantial portion of the Registrants' cash needs. During 2024, Southern Power utilized federal tax credit carryforwards, which provided $75 million in operating cash flows. For the three-year period from 2025 through 2027, each Registrant's projected stock dividends, capital expenditures, and debt maturities, as well as distributions to noncontrolling interests for Southern Power, are expected to exceed its operating cash flows. Southern Company plans to finance future cash needs in excess of its operating cash flows through one or more of the following: accessing borrowings from financial institutions, issuing debt, equity, and/or hybrid securities in the capital markets, and/or through its stock plans and its continuous equity offering program. Each Subsidiary Registrant plans to finance its future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. The Registrants plan to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs and continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital" and "Financing Activities" herein for additional information.

See Note 11 to the financial statements under "Pension Plans" for information on the Registrants' investments in their qualified pension plans. No mandatory contributions to the qualified pension plans are anticipated during 2025. See Note 6 to the financial statements under "Nuclear Decommissioning" for information on Alabama Power's and Georgia Power's investments in their respective nuclear decommissioning trust funds.

At the end of 2024, the market price of Southern Company's common stock was $82.32 per share (based on the closing price as reported on the NYSE) and the book value was $30.28 per share, representing a market-to-book value ratio of 272%, compared to $70.12, $28.83, and 243%, respectively, at the end of 2023.

Cash Requirements

Capital Expenditures

Total estimated capital expenditures, including LTSA and nuclear fuel commitments, for the Registrants through 2029 based on their current construction programs are as follows:

(a)Includes amounts contingent upon approval by the Alabama PSC related to Alabama Power's October 2024 CCN filing totaling $640 million in 2025, $23 million in 2026, $15 million in 2027, $13 million in 2028, and $107 million in 2029. See Note 2 to the financial statements under "Alabama Power – Petition for Certificate of Convenience and Necessity" for additional information.

(b)Includes committed expenditures in 2025 related to generation construction projects Georgia Power has bid through an RFP as initiated in the 2022 IRP. Excludes all other expenditures not yet approved of up to $14 billion, excluding AFUDC, for Georgia Power-owned proposals in RFPs and related transmission investments through 2029. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for additional information.

(c)Includes $0.4 billion and $0.1 billion in 2025 and 2026, respectively, related to the Millers Branch solar project and $0.3 billion and $0.1 billion in 2025 and 2026, respectively, related to the Kay Wind repowering project. Excludes approximately $0.7 billion per year for 2025 and 2026 and $0.8 billion per year for 2027 through 2029 for Southern Power's planned acquisitions and placeholder growth, which may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 15 to the financial statements under "Southern Power" for additional information regarding the Millers Branch solar project and the Kay Wind repowering project.

(d)Includes gas pipeline investment of approximately $0.1 billion, $0.2 billion, $0.7 billion, $0.4 billion, and $0.2 billion for 2025 through 2029, respectively. See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein for information regarding this project.

These capital expenditures include estimates to comply with environmental laws and regulations, but do not include compliance costs associated with regulation of GHG emissions. See FUTURE EARNINGS POTENTIAL – "Environmental Matters" herein for additional information. At December 31, 2024, significant purchase commitments were outstanding in connection with the Registrants' construction programs.

The traditional electric operating companies also anticipate continued expenditures associated with closure and monitoring of surface impoundments and landfills in accordance with the CCR Rule and the related state rules, which are reflected in the applicable Registrants' ARO liabilities. The cost estimates for Alabama Power are based on closure-in-place for all surface

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impoundments. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some surface impoundments and closure by removal for others. These estimated costs are likely to change, and could change materially, as assumptions and details pertaining to closure are refined and compliance activities continue. Current estimates of these costs through 2029 are provided in the table below. Material expenditures in future years for ARO settlements will also be required for surface impoundments, nuclear decommissioning (for Alabama Power and Georgia Power), and other liabilities reflected in the applicable Registrants' AROs, as discussed further in Note 6 to the financial statements. Also see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" herein.

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation, regulation, and/or tariff policy; the cost, availability, and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures and AROs will be fully recovered. Additionally, expenditures associated with Southern Power's planned acquisitions may vary due to market opportunities and the execution of its growth strategy. See Note 15 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects.

See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein for additional information.

Other Significant Cash Requirements

Long-term debt maturities and the interest payable on long-term debt each represent a significant cash requirement for the Registrants. See Note 8 to the financial statements for information regarding the Registrants' long-term debt at December 31, 2024, the weighted average interest rate applicable to each long-term debt category, and a schedule of long-term debt maturities over the next five years. The Registrants plan to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Fuel and purchased power costs represent a significant component of funding ongoing operations for the traditional electric operating companies and Southern Power. Total estimated costs for fuel and purchased power commitments at December 31, 2024 for the applicable Registrants are provided in the table below. Fuel costs include purchases of coal (for the traditional electric operating companies) and natural gas (for the traditional electric operating companies and Southern Power), as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery; the amounts reflected below have been estimated based on the NYMEX future prices at December 31, 2024. As discussed under "Capital Expenditures" herein, estimated expenditures for nuclear fuel are included in the applicable Registrants' construction programs for the years 2025 through 2029. Nuclear fuel commitments at December 31, 2024 that extend beyond 2029 are

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included in the table below. Purchased power costs represent estimated minimum obligations for various PPAs for the purchase of capacity and energy, except for those accounted for as leases, which are discussed in Note 9 to the financial statements.

(*)Excludes capacity payments related to Plant Vogtle Units 1 and 2, which are discussed in Note 3 to the financial statements under "Commitments."

The traditional electric operating companies and Southern Power have entered into LTSAs for the purpose of securing maintenance support for certain of their generating facilities. See Note 1 to the financial statements under "Long-term Service Agreements" for additional information. As discussed under "Capital Expenditures" herein, estimated expenditures related to LTSAs are included in the applicable Registrants' construction programs for the years 2025 through 2029. Total estimated payments for LTSA commitments at December 31, 2024 that extend beyond 2029 are provided in the following table and include price escalation based on inflation indices:

In addition, Southern Power has certain other operations and maintenance agreements. Total estimated costs for these commitments at December 31, 2024 are provided in the table below.

Southern Company Gas has commitments for pipeline charges, storage capacity, and gas supply, including charges recoverable through natural gas cost recovery mechanisms or, alternatively, billed to marketers selling retail natural gas. Gas supply commitments include amounts for gas commodity purchases associated with Nicor Gas and SouthStar of 39 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2024 and valued at $136 million. Southern Company Gas' expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets at December 31, 2024 were as follows:

See Note 9 to the financial statements for information on the Registrants' operating lease obligations, including a maturity analysis of the lease liabilities over the next five years and thereafter.

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Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt, hybrid, and/or equity issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings.

The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. Operating cash flows provide a substantial portion of the Registrants' cash needs.

The amount, type, and timing of any financings in 2025, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for certain of the Subsidiary Registrants), and other factors. See "Cash Requirements" herein for additional information.

The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by the FERC. Additionally, with respect to the public offering of securities, Southern Company, the traditional electric operating companies, Southern Power (excluding its subsidiaries), Southern Company Gas Capital, and Southern Company Gas (excluding its other subsidiaries) file registration statements with the SEC under the Securities Act of 1933, as amended.

The Registrants generally obtain financing separately without credit support from any affiliate. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information. The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company in the Southern Company system, except in the case of Southern Company Gas, as described below.

The traditional electric operating companies and SEGCO may utilize a Southern Company subsidiary organized to issue and sell commercial paper at their request and for their benefit. Proceeds from such issuances for the benefit of an individual company are loaned directly to that company. The obligations of each traditional electric operating company and SEGCO under these arrangements are several and there is no cross-affiliate credit support. Alabama Power also maintains its own separate commercial paper program.

Southern Company Gas Capital obtains external financing for Southern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates. Southern Company Gas maintains commercial paper programs at Southern Company Gas Capital and Nicor Gas. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the other Southern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program.

By regulation, Nicor Gas is restricted, up to its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At December 31, 2024, the amount of subsidiary retained earnings restricted to dividend totaled $1.6 billion. This restriction did not impact Southern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

Certain Registrants' current liabilities frequently exceed their current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. The Registrants generally plan to refinance long-term debt as it matures. See Note 8 to the financial statements for additional information. Also see "Financing Activities" herein for information on financing activities that occurred subsequent to December 31, 2024. The following table shows the amount by which current liabilities exceeded current assets at December 31, 2024 for the applicable Registrants:

The Registrants believe the need for working capital can be adequately met by utilizing operating cash flows, as well as commercial paper, lines of credit, and short-term bank notes, as market conditions permit. In addition, under certain circumstances, the Subsidiary Registrants may utilize equity contributions and/or loans from Southern Company.

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Bank Credit Arrangements

At December 31, 2024, unused committed credit arrangements with banks were as follows:

(a)Includes $14 million at Alabama Property Company, a wholly-owned subsidiary of Alabama Power. Alabama Power is not party to this arrangement.

(b)At December 31, 2024, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $27 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(c)Includes $798 million and $800 million at Southern Company Gas Capital and Nicor Gas, respectively.

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

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 December 31, 2024, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $1.7 billion (comprised of approximately $796 million at Alabama Power, $819 million at Georgia Power, and $69 million at Mississippi Power). In addition, at December 31, 2024, Alabama Power and Georgia Power had approximately $207 million and $157 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. Alabama Power's $207 million of fixed rate revenue bonds are classified as securities due within one year on its balance sheet 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.

See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.

Short-term Borrowings

The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Power's subsidiaries are not issuers or obligors under its commercial paper program. Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of the Registrants' short-term borrowings were as follows:

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(*)    Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2024, 2023, and 2022.

Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities in 2024 and 2023 are presented in the following table:

Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Southern Company

Net cash provided from operating activities increased $2.2 billion in 2024 as compared to 2023 primarily due to the timing of vendor payments, increased retail fuel cost recovery primarily at Georgia Power, and the timing of fossil fuel stock purchases, partially offset by the timing of customer receivable collections, storm restoration costs at Georgia Power, and decreased natural gas cost recovery at the natural gas distribution utilities.

The net cash used for investing activities in 2024 and 2023 was primarily related to the Subsidiary Registrants' construction programs.

The net cash used for financing activities in 2024 was primarily related to common stock dividend payments, a reduction in commercial paper borrowings, and a net decrease in short-term borrowings, partially offset by net issuances of long-term debt. The net cash provided from financing activities in 2023 was primarily related to net issuances of long-term debt and an increase in commercial paper borrowings, partially offset by common stock dividend payments and net repayments of short-term bank loans.

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Alabama Power

Net cash provided from operating activities increased $816 million in 2024 as compared to 2023 primarily due to an increase in retail revenues associated with customer bill credits in 2023, the timing of fossil fuel stock purchases, and the timing of vendor payments, partially offset by a decrease in fuel cost recovery.

The net cash used for investing activities in 2024 and 2023 was primarily related to gross property additions, including approximately $79 million related to the construction of Plant Barry Unit 8 in 2023. See Note 2 to the financial statements under "Alabama Power" for additional information.

The net cash used for financing activities in 2024 was primarily related to common stock dividend payments, partially offset by capital contributions from Southern Company. The net cash used for financing activities in 2023 was primarily related to common stock dividend payments, largely offset by net issuances of long-term debt and capital contributions from Southern Company.

Georgia Power

Net cash provided from operating activities increased $2.0 billion in 2024 as compared to 2023 primarily due to the timing of vendor payments, increased fuel cost recovery, and fossil fuel stock purchases, partially offset by storm restoration costs and the timing of customer receivable collections.

The net cash used for investing activities in 2024 and 2023 was primarily related to gross property additions, including approximately $0.2 billion and $1.1 billion, respectively, related to the construction and completion of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information on construction of Plant Vogtle Units 3 and 4.

The net cash provided from financing activities in 2024 was primarily related to capital contributions from Southern Company and net issuances of senior notes, partially offset by common stock dividend payments, a reduction in commercial paper borrowings, and a net decrease in short-term borrowings. The net cash provided from financing activities in 2023 was primarily related to capital contributions from Southern Company, net issuances of senior notes, an increase in commercial paper borrowings, and reofferings of pollution control revenue bonds which were previously held by Georgia Power, partially offset by common stock dividend payments and a net decrease in short-term borrowings.

Mississippi Power

Net cash provided from operating activities increased $37 million in 2024 as compared to 2023 primarily due to the timing of vendor payments and increased retail fuel cost recovery, partially offset by the timing of customer receivable collections.

The net cash used for investing activities in 2024 and 2023 was primarily related to gross property additions.

The net cash used for financing activities in 2024 was primarily related to common stock dividend payments, partially offset by capital contributions from Southern Company and net issuances of senior notes. The net cash used for financing activities in 2023 was primarily related to common stock dividend payments, partially offset by the issuance of senior notes.

Southern Power

Net cash provided from operating activities decreased $388 million in 2024 as compared to 2023 primarily due to the utilization of federal tax credit carryforwards and the timing of customer receivable collections, partially offset by the timing of vendor payments.

The net cash used for investing activities in 2024 was primarily related to ongoing construction activities. The net cash used for investing activities in 2023 was primarily related to the acquisitions of the South Cheyenne and Millers Branch solar facilities and ongoing construction activities. See Note 15 to the financial statements under "Southern Power" for additional information.

The net cash used for financing activities in 2024 was primarily related to common stock dividend payments, net distributions to noncontrolling interests, and a reduction in commercial paper borrowings, partially offset by capital contributions from Southern Company. The net cash used for financing activities in 2023 was primarily related to the repayment of senior notes at maturity, common stock dividend payments, net distributions to noncontrolling interests, and net repayments of short-term debt.

Southern Company Gas

Net cash provided from operating activities decreased $210 million in 2024 as compared to 2023 primarily due to a reduction in natural gas cost recovery as well as a decrease in receivables, partially offset by a decrease in payables for natural gas, both as a result of significantly lower gas prices in 2024 and weather impacts.

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The net cash used for investing activities in 2024 and 2023 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at certain gas distribution operations.

The net cash provided from financing activities in 2024 was primarily related to the issuance of senior notes and first mortgage bonds, partially offset by common stock dividend payments. The net cash used for financing activities in 2023 was primarily related to repayment of short-term borrowings and common stock dividend payments, partially offset by net issuances of long-term debt and capital contributions from Southern Company.

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes in 2024 for Southern Company included:

•an increase of $4.8 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs;

•an increase of $3.8 billion in long-term debt (including securities due within one year) related to net issuances of senior notes, partially offset by the maturity of junior subordinated notes;

•an increase of $1.8 billion in total common stockholders' equity primarily related to net income, partially offset by common stock dividend payments;

•a decrease of $1.0 billion in notes payable due to a reduction in commercial paper borrowings and net repayments of short-term bank debt;

•an increase of $0.8 billion in accounts payable primarily related to the timing of vendor payments and storm restoration costs at Georgia Power;

•a decrease of $0.8 billion in deferred under recovered fuel clause revenues primarily due to increased fuel cost recovery at Georgia Power;

•an increase of $0.8 billion in other regulatory assets, deferred primarily related to storm restoration costs at Georgia Power;

•an increase of $0.7 billion in accumulated deferred income taxes primarily related to an increase in property-related and storm damage timing differences; and

•an increase of $0.6 billion in prepaid pension costs primarily related to actuarial gains resulting from increases in the assumed discount rates and actual returns on plan assets.

See "Financing Activities" herein and Notes 1, 2, 5, 8, and 10 to the financial statements for additional information.

Alabama Power

Significant balance sheet changes in 2024 for Alabama Power included:

•an increase of $755 million in total common stockholder's equity primarily due to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;

•an increase of $664 million in total property, plant, and equipment primarily related to the construction of transmission and distribution facilities;

•an increase of $261 million in cash and cash equivalents, as discussed further under "Analysis of Cash Flow – Alabama Power" herein; and

•a decrease of $246 million in under recovered retail fuel clause revenues primarily resulting from increased recovery of deferred fuel expense.

See Notes 2 and 5 to the financial statements for additional information.

Georgia Power

Significant balance sheet changes in 2024 for Georgia Power included:

•an increase of $3.0 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including costs associated with Plant Yates Units 8 through 10 and Plant Vogtle Unit 4;

•an increase of $2.3 billion in common stockholder's equity primarily due to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company;

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•an increase of $1.7 billion in long-term debt (including securities due within one year) primarily due to net issuances of senior notes;

•a decrease of $1.1 billion in notes payable primarily due to net repayments of short-term bank debt;

•increases of $0.9 billion and $0.7 billion in other regulatory assets, deferred and other accounts payable, respectively, primarily related to storm restoration costs;

•a decrease of $0.7 billion in under recovered retail fuel clause revenues primarily resulting from increased recovery of deferred fuel expense as ordered in Georgia Power's 2023 fuel cost recovery case;

•increases of $0.5 billion and $0.4 billion in total operating lease obligations and operating lease right-of-use assets, net of amortization, respectively, related to new affiliate PPAs;

•an increase of $0.4 billion in accumulated deferred income taxes primarily related to an increase in property-related and storm damage timing differences; and

•a decrease of $0.3 billion in AROs primarily due to updates related to nuclear decommissioning AROs.

See "Financing Activities – Georgia Power" herein and Notes 2, 5, 6, 8, 9, and 10 to the financial statements for additional information.

Mississippi Power

Significant balance sheet changes in 2024 for Mississippi Power included:

•an increase of $183 million in total property, plant, and equipment primarily related to the construction of transmission and distribution facilities;

•an increase of $86 million in common stockholder's equity primarily related to net income and capital contributions from Southern Company, partially offset by dividends paid to Southern Company; and

•an increase of $49 million in long-term debt (including securities due within one year) primarily due to net issuances of senior notes.

See "Financing Activities – Mississippi Power" herein and Notes 5 and 8 to the financial statements for additional information.

Southern Power

Significant balance sheet changes in 2024 for Southern Power included:

•a decrease of $138 million in notes payable primarily due to a reduction in commercial paper borrowings;

•a decrease of $111 million in total property, plant, and equipment in service primarily due to the continued depreciation of assets, partially offset by an increase in CWIP primarily related to the construction of the Millers Branch solar facility;

•an increase of $98 million in accumulated deferred income taxes primarily related to the expected utilization of federal tax credit carryforwards in 2024;

•a decrease of $58 million in accumulated deferred ITCs due to the continued amortization of accumulated deferred ITCs; and

•a decrease of $16 million in total stockholders' equity primarily due to dividends paid to Southern Company and net distributions to noncontrolling interests, partially offset by capital contributions from Southern Company and net income.

See Notes 5, 8, 10, and 15 to the financial statements for additional information.

Southern Company Gas

Significant balance sheet changes in 2024 for Southern Company Gas included:

•an increase of $1.1 billion in total property, plant, and equipment primarily related to the construction of transportation and distribution assets;

•an increase of $0.4 billion in long-term debt (including securities due within one year) due to issuances of senior notes and first mortgage bonds;

•an increase of $0.2 billion in common stockholder's equity primarily related to net income, partially offset by dividends paid to Southern Company; and

•an increase of $0.1 billion in accumulated deferred income taxes primarily due to property-related timing differences.

See "Financing Activities – Southern Company Gas" herein and Notes 5, 8, and 10 to the financial statements for additional information.

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Financing Activities

The following table outlines long-term debt financing activities for the year ended December 31, 2024:

(a)Includes reductions in finance lease obligations resulting from cash payments under finance leases and, for Georgia Power, principal amortization payments totaling $86 million for FFB borrowings. See Note 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information.

(b)Includes repayment by SEGCO of $20 million of its $100 million principal amount long-term bank loan due November 15, 2025, which is guaranteed by Alabama Power. See Note 3 to the financial statements under "Guarantees" for additional information.

(c)Represents reductions in affiliate finance lease obligations at Georgia Power, which are eliminated in Southern Company's consolidated financial statements.

Except as otherwise described herein, the Registrants used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The Subsidiary Registrants also used the proceeds for their construction programs.

In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

Southern Company

During 2024, Southern Company issued approximately 5.8 million shares of common stock primarily through equity compensation plans. Also during 2024, Southern Company entered into forward sale contracts for the issuance of shares of common stock that are expected to be settled in 2025. See Note 8 to the financial statements under "Equity Distribution Agreement" for additional information.

In February 2024, Southern Company issued an additional $400 million aggregate principal amount of its Series 2023D 5.50% Senior Notes due March 15, 2029 (Series 2023D Senior Notes) and an additional $400 million aggregate principal amount of its Series 2023E 5.70% Senior Notes due March 15, 2034 (Series 2023E Senior Notes). Upon these issuances, the aggregate principal amount of outstanding Series 2023D Senior Notes and Series 2023E Senior Notes was $1.0 billion and $1.1 billion, respectively.

Also in February 2024, Southern Company borrowed $300 million pursuant to a short-term uncommitted bank credit arrangement, which was repaid in March 2024.

Also in February 2024, Southern Company repaid at maturity $600 million aggregate principal amount of its Series 2021A 0.60% Senior Notes.

In May 2024, Southern Company issued $1.5 billion aggregate principal amount of its Series 2024A 4.50% Convertible Senior Notes due June 15, 2027 in a private offering. See Note 8 to the financial statements under "Convertible Senior Notes" for additional information.

In August 2024, Southern Company repaid at maturity $862.5 million aggregate principal amount of its Series 2019A Remarketable Junior Subordinated Notes.

In September 2024, Southern Company issued $750 million aggregate principal amount of Series 2024B 4.85% Senior Notes due March 15, 2035.

Subsequent to December 31, 2024, Southern Company issued $565 million aggregate principal amount of Series 2025A 6.50% Junior Subordinated Notes due March 15, 2085.

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Alabama Power

In January 2024, Alabama Power repaid at maturity its obligations with respect to approximately $21 million aggregate principal amount of The Industrial Development Board of the Town of Wilsonville (Alabama) Pollution Control Revenue Bonds (Alabama Power Company Gaston Plant Project), Series D.

In May 2024, Alabama Power entered into a $50 million short-term floating rate bank loan, which it repaid at maturity in July 2024.

In October 2024, a subsidiary of Alabama Power repaid the remaining $22 million outstanding principal amount of a $39 million long-term floating rate bank loan entered into in December 2022 with a maturity date of December 12, 2029.

In December 2024, a subsidiary of Alabama Power borrowed $1 million under a $15 million credit line entered into in December 2024 with a maturity date of December 11, 2026.

Georgia Power

In January 2024, Georgia Power borrowed an additional $150 million pursuant to a short-term uncommitted bank credit arrangement. In February 2024, Georgia Power repaid the aggregate $250 million outstanding.

Also in February 2024, Georgia Power issued $500 million aggregate principal amount of Series 2024A 5.004% Senior Notes due February 23, 2027 and $900 million aggregate principal amount of Series 2024B 5.250% Senior Notes due March 15, 2034.

In June 2024, Georgia Power entered into a $200 million short-term floating rate bank loan bearing interest based on term SOFR.

In July 2024, Georgia Power repaid $210 million of a $420 million short-term floating rate bank loan due November 2024. In August 2024, Georgia Power repaid the remaining $210 million outstanding.

In September 2024, Georgia Power repaid at maturity $400 million aggregate principal amount of its Series 2019A 2.20% Senior Notes.

In November 2024, Georgia Power issued approximately $117 million aggregate principal amount of Series 2024C Floating Rate Senior Notes due November 15, 2074.

In December 2024, Georgia Power issued $600 million aggregate principal amount of Series 2024D 4.55% Senior Notes due March 15, 2030.

Mississippi Power

In March 2024, Mississippi Power issued in a private placement $100 million aggregate principal amount of Series 2024A 5.62% Senior Notes due March 15, 2034 and $50 million aggregate principal amount of Series 2024B 5.72% Senior Notes due March 15, 2036. In June 2024, pursuant to the same agreement, Mississippi Power issued in a private placement $100 million aggregate principal amount of Series 2024C 5.91% Senior Notes due June 15, 2054.

Also in June 2024, Mississippi Power repaid at maturity $200 million aggregate principal amount of its Series 2021A Floating Rate Senior Notes.

Southern Company Gas

During 2024, Southern Company Gas received additional cash advances totaling $8 million under a long-term financing agreement related to a construction contract, for a total aggregate outstanding balance of $68 million.

In September 2024, Nicor Gas issued in a private placement $25 million aggregate principal amount of 4.78% Series First Mortgage Bonds due September 15, 2031, $100 million aggregate principal amount of 5.00% Series First Mortgage Bonds due September 15, 2034, and $31 million aggregate principal amount of 5.58% Series First Mortgage Bonds due September 15, 2059. In December 2024, pursuant to the same agreement, Nicor Gas issued in a private placement $50 million aggregate principal amount of 4.63% Series First Mortgage Bonds due December 15, 2029 and $69 million aggregate principal amount of 5.66% Series First Mortgage Bonds due December 15, 2064.

In September 2024, Southern Company Gas Capital issued $450 million aggregate principal amount of Series 2024A 4.95% Senior Notes due September 15, 2034, guaranteed by Southern Company Gas.

Credit Rating Risk

At December 31, 2024, the Registrants did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

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There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain Registrants to BBB and/or Baa2 or below. These contracts are primarily for physical electricity and natural gas purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and, for Georgia Power, services at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at December 31, 2024 were as follows:

(*)Southern Power has PPAs that could require collateral, but not accelerated payment, in the event of a downgrade of Southern Power's credit. The PPAs require credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses resulting from a credit downgrade. Southern Power had $106 million of cash collateral posted related to PPA requirements at December 31, 2024.

The amounts in the previous table for the traditional electric operating companies and Southern Power include certain agreements that could require collateral if either Alabama Power or Georgia Power has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of the Registrants to access capital markets and would be likely to impact the cost at which they do so.

Mississippi Power and its largest retail customer, Chevron Products Company (Chevron), have agreements under which Mississippi Power provides retail service to the Chevron refinery in Pascagoula, Mississippi through at least 2038. The agreements grant Chevron a security interest in the co-generation assets owned by Mississippi Power located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.

On May 2, 2024, S&P upgraded the issuer credit rating for Southern Company to A- from BBB+. Due to S&P's rating methodology, the upgrade of Southern Company's issuer credit rating resulted in the upgrade of the senior unsecured long-term debt ratings of Mississippi Power, Southern Company Gas Capital, and Atlanta Gas Light to A- from BBB+, the senior unsecured long-term debt rating of Georgia Power to A from BBB+, the senior unsecured long-term debt rating of Alabama Power to A from A-, and the senior unsecured long-term debt ratings of Southern Company and Southern Power to BBB+ from BBB. Nicor Gas' long-term issuer rating remained at A-. S&P revised its credit rating outlook for Southern Company and its subsidiaries to stable from positive.

On August 20, 2024, Fitch upgraded the senior unsecured long-term debt ratings of Georgia Power and Mississippi Power to A from A-.

On September 26, 2024, Moody's upgraded the senior unsecured long-term debt rating of Southern Company to Baa1 from Baa2 and of Georgia Power to A3 from Baa1. Moody's also revised the ratings outlook for Southern Company to stable from positive.

Market Price Risk

The Registrants had no material change in market risk exposure for the year ended December 31, 2024 when compared to the year ended December 31, 2023. See Note 14 to the financial statements for an in-depth discussion of the Registrants' derivatives, as well as Note 1 to the financial statements under "Financial Instruments" for additional information.

Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. The traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. Mississippi Power also manages wholesale fuel-hedging programs under agreements with its wholesale customers. Because energy from Southern Power's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric

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operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market.

Certain of Southern Company Gas' non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Southern Company Gas' gas marketing services business also actively manages storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. These hedging instruments are used to substantially protect economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize exposure to declining earnings. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment.

The following table provides information related to variable interest rate exposure on long-term debt (including amounts due within one year) at December 31, 2024 for the applicable Registrants:

(*)Includes $1.4 billion of long-term variable interest rate exposure at the Southern Company parent entity.

The Registrants may enter into interest rate derivatives designated as hedges, which are intended to mitigate interest rate volatility related to forecasted debt financings and existing fixed and floating rate obligations. See Note 14 to the financial statements under "Interest Rate Derivatives" for additional information.

Southern Company and Southern Power had foreign currency denominated debt at December 31, 2024 and have each mitigated exposure to foreign currency exchange rate risk through the use of foreign currency swaps. See Note 14 to the financial statements under "Foreign Currency Derivatives" for additional information.

Changes in fair value of energy-related derivative contracts for Southern Company and Southern Company Gas for the years ended December 31, 2024 and 2023 are provided in the table below. At December 31, 2024 and 2023, substantially all of the traditional electric operating companies' and certain of the natural gas distribution utilities' energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company's fuel-hedging program.

(a)Excludes cash collateral held on deposit in broker margin accounts of $17 million, $62 million, and $41 million at December 31, 2024, 2023, and 2022, respectively, and immaterial premium and intrinsic value associated with weather derivatives for all periods presented.

(b)The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. Current period changes also include the changes in fair value of new contracts entered into during the period, if any.

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The net hedge volumes of energy-related derivative contracts for natural gas purchased at December 31, 2024 and 2023 for Southern Company and Southern Company Gas were as follows:

Southern Company Gas' derivative contracts are comprised of 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. The volumes presented above for Southern Company Gas represent the net of long natural gas positions of 90 million mmBtu and short natural gas positions of 7 million mmBtu at December 31, 2024 and the net of long natural gas positions of 112 million mmBtu and short natural gas positions of 10 million mmBtu at December 31, 2023.

For the Southern Company system, the weighted average swap contract cost per mmBtu was approximately $0.15 per mmBtu below market prices at December 31, 2024 and was approximately $0.76 per mmBtu below market prices at December 31, 2023. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Substantially all of the traditional electric operating companies' natural gas hedge gains and losses are recovered through their respective fuel cost recovery clauses.

The Registrants use OTC contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. In addition, Southern Company Gas uses exchange-traded market-observable contracts, which are categorized as Level 1. See Note 13 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts for Southern Company and Southern Company Gas at December 31, 2024 were as follows:

(a)Valued using NYMEX futures prices.

(b)Level 2 amounts for Southern Company Gas are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.

(c)Excludes cash collateral of $17 million as well as immaterial premium and associated intrinsic value associated with weather derivatives.

The Registrants are exposed to risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts, as applicable. The Registrants generally enter into agreements and material transactions with counterparties that have

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investment grade credit ratings by Moody's, S&P, or Fitch or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Registrants do not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements.

Credit Risk

Southern Company (except as discussed herein), the traditional electric operating companies, and Southern Power are not exposed to any concentrations of credit risk. Southern Company Gas' exposure to concentrations of credit risk is discussed herein.

Southern Company Gas

Gas Distribution Operations

Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of the 14 Marketers in Georgia. The credit risk exposure to the Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light. For 2024, the four largest Marketers based on customer count, which includes SouthStar, accounted for 20% of Southern Company Gas' operating revenues and 23% of operating revenues for Southern Company Gas' gas distribution operations segment.

Several factors are designed to mitigate Southern Company Gas' risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above, Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears. Atlanta Gas Light accepts credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers, and corporate guarantees from investment-grade entities. Southern Company Gas reviews the adequacy of credit support coverage, credit rating profiles of credit support providers, and payment status of each Marketer. Southern Company Gas believes that adequate policies and procedures are in place to properly quantify, manage, and report on Atlanta Gas Light's credit risk exposure to Marketers.

Atlanta Gas Light also faces potential credit risk in connection with assignments of interstate pipeline transportation and storage capacity to Marketers. Although Atlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would likely seek repayment from Atlanta Gas Light.

Gas Marketing Services

Southern Company Gas obtains credit scores for its firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceed Southern Company Gas' credit threshold. Southern Company Gas considers potential interruptible and large commercial customers based on reviews of publicly available financial statements and commercially available credit reports. Prior to entering into a physical transaction, Southern Company Gas also assigns physical wholesale 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.

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