SOUTHERN CO

Business Activities

Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies, Southern Power, and Southern Company Gas and owns other direct and indirect subsidiaries. The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. See Note 16 to the financial statements for additional information.

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

•Southern Power develops, constructs, acquires, owns, 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. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. See Notes 7, 15, and 16 to the financial statements for additional information.

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

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

Recent Developments

On March 24, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with the acquisition of the Central Alabama Generating Station. The filing reflected an annual increase in retail revenues of $78 million, or 1.1%, effective with June 2023 billings. Through May 2023, Alabama Power recovered substantially all costs associated with the Central Alabama Generating Station through Rate RSE, offset by revenues from a power sales agreement. On May 24, 2023, the Central Alabama Generating Station was placed into retail service. On November 1, 2023, Alabama Power placed Plant Barry Unit 8 in service. On December 1, 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with Plant Barry Unit 8. The filing reflected an annual increase in retail revenues of $91 million, or 1.4%, effective with January 2024 billings.

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

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

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On August 18, 2023, Alabama Power notified the Alabama PSC of its intent to use a portion of its reliability reserve balance in 2023. During the fourth quarter 2023, Alabama Power used $75 million of the reliability reserve for reliability-related transmission, distribution, and generation expenses and nuclear production-related expenses. At December 31, 2023, Alabama Power accrued $52 million to its reliability reserve.

On October 3, 2023, the Alabama PSC issued an order modifying its December 2022 order related to excess federal accumulated deferred income taxes and authorizing Alabama Power to (i) flow back in 2023 approximately $24 million of certain federal excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017 and (ii) make available any remaining balance of excess accumulated deferred income taxes at the end of 2023 for the benefit of customers in 2024 and/or 2025. At December 31, 2023, the remaining balance was $81 million, of which approximately $67 million and $14 million will flow back in 2024 and 2025, respectively, for the benefit of customers.

On November 9, 2023, the Alabama PSC approved a decrease to Rate ECR of approximately $126 million annually, effective with December 2023 billings.

On December 1, 2023, Alabama Power submitted calculations to the Alabama PSC for Rate CNP Compliance for 2024, which resulted in an annual revenue decrease of approximately $23 million, or 0.3%, effective with January 2024 billings.

For the year ended December 31, 2023, Alabama Power's weighted common equity return exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $15 million for Rate RSE refunds, which will be refunded to customers through bill credits in April 2024.

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

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

Georgia Power placed Plant Vogtle Unit 3 in service on July 31, 2023 and continues construction on Plant Vogtle Unit 4 (each with electric generating capacity of approximately 1,100 MWs), in which it holds a 45.7% ownership interest. Georgia Power's share of the total project capital cost forecast to complete Plant Vogtle Units 3 and 4, including contingency, through the second quarter 2024 is $10.8 billion.

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

On February 1, 2024, Georgia Power announced that during start-up and pre-operational testing for Unit 4, Southern Nuclear identified, and has remediated, vibrations associated with certain piping within the cooling system. Considering the remaining pre-operational testing, Unit 4 is projected to be placed in service during the second quarter 2024. On February 14, 2024, Unit 4 achieved self-sustaining nuclear fission, commonly referred to as initial criticality. The projected schedule for Unit 4 significantly depends on the progression of start-up and pre-operational testing, which may be impacted by equipment or other operational failures. In addition, any findings related to the root cause of the motor fault on the single Unit 4 RCP could require engineering changes or remediation related to the other seven Unit 3 and Unit 4 RCPs. Any further delays could result in a later in-service date and cost increases.

As of December 31, 2023, based on completion of construction work and the assessment of start-up and pre-operational testing remaining, Southern Nuclear has an estimated $36 million for construction contingency remaining in the estimate to complete. This contingency is projected to be allocated in the future to address any further Unit 4 schedule extensions or remediation of other issues discovered during start-up testing.

In September 2022, Georgia Power and MEAG Power reached an agreement to resolve a dispute regarding the cost-sharing and tender provisions of the Global Amendments (as defined in Note 2 to the financial statements under "Georgia Power – Nuclear Construction – Joint Owner Contracts"). Under the terms of the agreement, among other items, (i) MEAG Power will not exercise its tender option and will retain its full ownership interest in Plant Vogtle Units 3 and 4; (ii) Georgia Power will reimburse a portion of MEAG Power's costs of construction for Plant Vogtle Units 3 and 4 as such costs are incurred and with no further adjustment for force majeure costs, which payments will total approximately $92 million based on the current project capital cost forecast; and (iii) Georgia Power will reimburse 20% of MEAG Power's costs of construction with respect to any amounts over the current project capital cost forecast, with no further adjustment for force majeure costs.

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

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

The ultimate impact of these matters on the construction schedule for Plant Vogtle Unit 4 and project capital cost forecast for Plant Vogtle Units 3 and 4 cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" for additional information.

Plant Vogtle Units 3 and 4 Rate and Prudency Proceedings

In compliance with a Georgia PSC order approved in 2021, Georgia Power increased annual retail base rates by $318 million effective August 1, 2023 based on the in-service date of July 31, 2023 for Unit 3.

On December 19, 2023, the Georgia PSC voted to approve the application to adjust rates to include reasonable and prudent Plant Vogtle Units 3 and 4 costs (Application) as modified by the related stipulated agreement (Prudency Stipulation) among Georgia Power, the staff of the Georgia PSC, and certain intervenors.

Under the terms of the approved Prudency Stipulation, Georgia Power will recover $7.562 billion in total construction and capital costs and associated retail rate base items of $1.02 billion, which includes AFUDC financing costs above $4.418 billion (the Georgia PSC-certified amount) up to $7.562 billion. Georgia Power will also recover projected operations and maintenance expenses, depreciation expense, nuclear decommissioning accruals, and property taxes, net of projected PTCs. After considering construction and capital costs already in retail base rates of $2.1 billion and $362 million of associated retail rate base items (approved by the Georgia PSC in 2021) and upon achieving commercial operation of Unit 4, Georgia Power will include in retail rate base the remaining $5.462 billion of construction and capital costs as well as $656 million of associated retail rate base items.

Under the Prudency Stipulation, if commercial operation for Unit 4 is not achieved by March 31, 2024, Georgia Power's ROE used to determine the NCCR tariff and calculate AFUDC will be reduced to zero, which will result in an estimated negative impact to earnings of approximately $30 million per month until the month following the date commercial operation for Unit 4 is achieved. The ultimate outcome of this matter cannot be determined at this time.

Annual retail base revenues will increase approximately $729 million and the average retail base rates will be adjusted by approximately 5% (net of the elimination of the NCCR tariff described above) effective the first day of the month after Unit 4 achieves commercial operation.

The approval of the Application and the Prudency Stipulation resolves all issues for determination by the Georgia PSC regarding the reasonableness, prudence, and cost recovery for the remaining Plant Vogtle Units 3 and 4 construction and capital costs not already in retail base rates.

As a result of the Georgia PSC's approval of the Prudency Stipulation, Georgia Power recorded a pre-tax credit to income of approximately $228 million ($170 million after tax) in the fourth quarter 2023 to recognize CWIP costs previously charged to income, which are now recoverable through retail rates. Associated AFUDC on these costs was also recognized.

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

Rate Plans

On November 16, 2023, in accordance with the terms of the 2022 ARP, the Georgia PSC approved tariff adjustments effective January 1, 2024 that resulted in a net increase in rates of $191 million.

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Georgia Power expects to submit a compliance filing in the fourth quarter 2024 to request tariff adjustments approved pursuant to the 2022 ARP effective January 1, 2025. The ultimate outcome of this matter cannot be determined at this time.

See Note 2 to the financial statements under "Georgia Power – Rate Plans – 2022 ARP" for additional information.

On May 16, 2023, the Georgia PSC approved a stipulation agreement between Georgia Power and the staff of the Georgia PSC to increase annual fuel billings by 54%, or approximately $1.1 billion, effective June 1, 2023. The increase reflects a three-year recovery period for $2.2 billion of Georgia Power's under recovered fuel balance at May 31, 2023. Changes in fuel rates have no significant effect on Southern Company's or Georgia Power's net income but do impact the related operating cash flows. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.

Integrated Resource Plans

On October 27, 2023, Georgia Power filed an updated IRP (2023 IRP Update) with the Georgia PSC, which sets forth a plan to support the recent increase in the state of Georgia's projected energy needs since the 2022 IRP. Georgia Power expects the Georgia PSC to render a final decision on the 2023 IRP Update on April 16, 2024. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for additional information.

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

In October 2023, Mississippi Power signed an affiliate PPA with Georgia Power for 750 MWs of capacity, which began January 1, 2024 and will continue through December 2028. In order to fulfill this PPA and serve the interests of customers, Mississippi Power now expects electric generating units identified in its 2021 IRP to remain in service beyond the previously indicated dates. Mississippi Power is expected to file its next IRP in April 2024 in accordance with the rules and orders of the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.

On February 6, 2024, the Mississippi PSC approved Mississippi Power's request to increase retail fuel revenues by $18 million annually effective with the first billing cycle of March 2024.

On February 12, 2024, Mississippi Power submitted its annual ECO Plan filing to the Mississippi PSC, which requested a $9 million annual increase in revenues. The ultimate outcome of this matter cannot be determined at this time.

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

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On September 20, 2023, Southern Power acquired 100% of the membership interests in the 200-MW Millers Branch solar project located in Haskell County, Texas from EDF Renewables Development, Inc. and is continuing construction. The facility's output is contracted under a 20-year PPA and commercial operation is expected to occur in the fourth quarter 2025. The project includes an option to expand capacity up to an additional 300 MWs. Subsequent to December 31, 2023, Southern Power committed to expand the construction of the facility through a second phase adding up to 205 MWs, with commercial operation expected to occur in the second quarter 2026.

On September 22, 2023, Southern Power acquired 100% of the membership interests in the 150-MW South Cheyenne solar project located in Laramie County, Wyoming from Hanwha Q Cells USA Corp. and is continuing construction. The facility's output is contracted under a 20-year PPA and commercial operation is expected to occur in the second quarter 2024.

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, 2023 was 97% through 2028 and 89% through 2033, with an average remaining contract duration of approximately 12 years.

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

On June 15, 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP rider, also referred to as Investing in Illinois program. The Illinois Commission disallowed $32 million of the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in the second quarter 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments 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. Nicor Gas defends these investments in infrastructure as prudently incurred.

On November 16, 2023, the Illinois Commission approved a $223 million annual base rate increase for Nicor Gas, which became effective December 1, 2023. The base rate increase was based on a return on equity of 9.51% and an equity ratio of 50.00%.

In connection with Nicor Gas' general base rate case proceeding, the Illinois Commission disallowed $126.8 million of capital investments that have been completed or 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 16, 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 could be material to the financial statements of Southern Company Gas. The ultimate outcome of these matters cannot be determined at this time. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Nicor Gas" for additional information.

On December 19, 2023, the Georgia PSC approved Atlanta Gas Light's annual GRAM filing, which resulted in an annual base rate increase of $53 million effective January 1, 2024.

On February 1, 2024, Atlanta Gas Light filed its triennial Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which included a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2025 through 2034), as well as the required capital investments and related costs to implement the programs. The i-CDP reflected

II-7 capital investments totaling approximately $0.7 billion to $1.0 billion annually. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter in the third quarter 2024. The ultimate outcome of this matter cannot be determined at this time.

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

On February 9,2024, Virginia Natural Gasfiled with the Virginia Commission a request to extend the existing SAVE program through 2029. The request 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. Virginia Natural Gas expects the Virginia Commission to issue a final order on this matter in the second quarter 2024. 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. 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. See RESULTS OF OPERATIONS – "Southern Company Gas" 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.

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