SOUTHERN CO (SO)

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

The following Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants.

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AND RESULTS OF OPERATIONS

OVERVIEW

Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies (Alabama Power, Georgia Power, and Mississippi Power), 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 distribution of natural gas and sale of other complementary products and services by Southern Company Gas. Alabama Power, Georgia Power, and Mississippi Power each operate with one reportable business segment, since substantially all of their business is providing electric service to customers. Southern Power also operates its business with one reportable business segment, the sale of electricity in the competitive wholesale market. Southern Company Gas' reportable segments are gas distribution operations, gas pipeline investments, and gas marketing services. See Note (L) to the Condensed Financial Statements herein for additional information on segment reporting. For additional information on the Registrants' primary business activities, see BUSINESS – "The Southern Company System" in Item 1 of the Form 10-K.

The Registrants continue to focus on several key performance indicators. For the traditional electric operating companies and Southern Company Gas, these indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. Southern Company Gas also continues to focus on several operating metrics, including customer count and volumes of natural gas sold. For Southern Power, key performance indicators include, but are 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. In addition, Southern Company and the Subsidiary Registrants focus on earnings per share and net income, respectively, as a key performance indicator.

Recent Developments

Alabama Power

In December 2025, the Alabama PSC issued a consent order to keep retail rates stable through 2027. On April 2, 2026, the State of Alabama enacted legislation providing that retail base rates established and in place on October 1, 2026 may not be increased before January 1, 2029 for utilities that are regulated by the Alabama PSC and that provide retail electric service. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

Southern Power

During the three months ended March 31, 2026, Southern Power committed to development projects to upgrade certain turbines at its existing Franklin and Wansley natural gas facilities, which are projected to add up to 400 MWs of incremental capacity. Commercial operations for the incremental capacity at the natural gas facilities are projected to occur between the second quarter 2029 and the first quarter 2031. The ultimate outcome of these matters cannot be determined at this time. In addition, in the first quarter 2026 and subsequent to March 31, 2026, Southern Power placed in service 51 MWs of the 200-MW repowering project at the Kay wind facility. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

At March 31, 2026, Southern Power's average 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 was 97% through 2030 and 88% through 2035, with an average remaining contract duration of approximately 12 years.

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AND RESULTS OF OPERATIONS (Continued)

RESULTS OF OPERATIONS

Southern Company

Net Income

Consolidated net income attributable to Southern Company in the first quarter 2026 was $1.36 billion ($1.21 per share) compared to $1.33 billion ($1.21 per share) for the corresponding period in 2025. The increase was primarily due to increases in retail electric revenues associated with sales growth, higher natural gas revenues associated with base rate increases, higher non-fuel-related wholesale electric revenues, and an increase in AFUDC equity, partially offset by an increase in depreciation and amortization, decreases in retail electrics revenues associated with weather impacts, and an increase in interest expense.

Retail Electric Revenues

In the first quarter 2026, retail electric revenues were $4.64 billion compared to $4.60 billion for the corresponding period in 2025. Details of the changes in retail electric revenues were as follows:

Changes in rates and pricing resulted in a decrease in revenues in the first quarter 2026 when compared to the corresponding period in 2025 primarily due to lower contributions from commercial and industrial customers with variable demand-driven pricing at Georgia Power, partially offset by increases in PEP rates at Mississippi Power. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information.

Changes in sales resulted in an increase in revenues in the first quarter 2026 when compared to the corresponding period in 2025. Weather-adjusted residential KWH sales increased 0.9% in the first quarter 2026 primarily due to customer growth. Weather-adjusted commercial KWH sales increased 4.6% in the first quarter 2026 primarily due to increased customer usage, largely driven by data centers at Georgia Power. Industrial KWH sales increased 1.5% in the first quarter 2026 primarily due to increases in the primary metals, pipeline, and stone, clay, and glass sectors, partially offset by decreases in the paper and chemicals sectors.

Fuel and other cost recovery revenues increased $48 million in the first quarter 2026 compared to the corresponding period in 2025 primarily due to higher recoverable fuel costs. 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 in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

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AND RESULTS OF OPERATIONS (Continued)

Wholesale Electric Revenues

In the first quarter 2026, wholesale electric revenues were $965 million compared to $744 million for the corresponding period in 2025. The increase was primarily due to an increase in energy revenues associated with a $145 million increase related to the average cost per KWH sold primarily resulting from higher fuel and purchased power prices and a $76 million increase related to the volume of KWHs sold resulting from higher demand.

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 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 municipal and rural association 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

In the first quarter 2026, other electric revenues were $265 million compared to $242 million for the corresponding period in 2025. The increase was primarily due to increases of $15 million in open access transmission tariff sales at the traditional electric operating com

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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 distribution 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 battery energy storage 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 and purchases 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 choice 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

Jurisdictional Separation Study Order

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

Reliability Reserve Accounting Order

In 2025, Alabama Power utilized $30 million of the reliability reserve for reliability-related transmission, distribution, and generation expenses and accrued $83 million to the reliability reserve in accordance with procedures established in the reliability reserve accounting order. In addition, Alabama Power notified the Alabama PSC through its annual RSE filing of its intent to utilize $60 million of its reliability reserve balance in 2026. See Note 2 to the financial statements under "Alabama Power – Reliability Reserve Accounting Order" for additional information.

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Rate CNP New Plant

On August 13, 2025, the Alabama PSC approved Alabama Power's petition for a CCN authorizing Alabama Power to complete the acquisition of the Lindsay Hill Generating Station (879.7 MWs), which had been approved by the FERC on June 6, 2025. The transaction closed on September 30, 2025. See Notes 2 and 15 to the financial statements under "Alabama Power – Rate CNP New Plant" and "Alabama Power," respectively, for additional information.

Nuclear Production Tax Credits Order

On October 7, 2025, the Alabama PSC issued an order authorizing Alabama Power to establish a regulatory liability for nuclear PTCs received through its nuclear generating facilities pursuant to Internal Revenue Code §45U for tax years 2024 through 2032. The §45U PTCs will be deferred as a regulatory liability until the Alabama PSC provides direction on how to apply them for the benefit of customers. For the 2024 tax year, Alabama Power received $180 million in §45U PTCs on Southern Company's consolidated federal income tax return. The ultimate outcome of this matter cannot be determined at this time.

December 5th Consent Order

On December 5, 2025, the Alabama PSC issued a consent order (December 5th Consent Order) approving a plan to keep retail rates stable through 2027. Alabama Power has agreed to:

•a moratorium on any upward rate adjustments associated with Rate RSE for 2027;

•maintain the current Rate CNP Compliance factors through December 2027;

•delay the effective date of Rate CNP New Plant adjustment to recover costs associated with the Lindsay Hill Generating Station acquisition until January 2028 billings;

•maintain the current Rate CNP PPA factor through March 2028; and

•maintain the current Rate ECR interim factor through December 2027.

To implement the plan, the Alabama PSC authorized Alabama Power to apply any customer refund resulting from Alabama Power's 2025 Rate RSE actual result calculation to the NDR. The Alabama PSC also approved the use of Alabama Power's 2024 nuclear PTCs, when monetized, to offset retail cost of service in 2027. In addition, any future regulatory liabilities associated with monetized nuclear PTCs from 2025, 2026, and 2027 will be used to offset future retail cost of service, including any under recovered balances under Rate CNP and Rate ECR.

Furthermore, the Alabama PSC, as part of its routine oversight of Alabama Power's regulated activities, will monitor factors such as weather, natural disasters, changes in fuel markets, and other significant unforeseen events that may impact this plan. If such events occur, Alabama Power will work with the Alabama PSC to determine a reasonable and responsive course of action under the circumstances.

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

Rate RSE

On December 1, 2025, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2026. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2026.

For the year ended December 31, 2025, Alabama Power's weighted common equity return exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $57 million for Rate RSE refunds, which was subsequently applied to the NDR pursuant to the December 5th Consent Order.

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

Georgia Power

2022 ARP

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

In a separate regulatory proceeding, on February 17, 2026, Georgia Power filed a request with the Georgia PSC to recover the reasonable and prudent storm costs incurred through December 31, 2025, which is expected to increase annual recovery by approximately $300 million effective June 1, 2026. The proposed annual recovery included in the filing is expected to fully

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recover the regulatory asset balance related to storm damage at December 31, 2025 over four years, and the remaining balance at December 31, 2028 will be included in the next rate case. Georgia Power expects the Georgia PSC to make a final decision on this matter on May 28, 2026. The ultimate outcome of this matter cannot be determined at this time.

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

See Note 2 to the financial statements under "Georgia Power – Rate Plans" and " – Storm Damage Recovery" for additional information.

Integrated Resource Plans

2025 IRP

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

•Extended operation of Plant Scherer Unit 3 (614 MWs based on 75% ownership) through at least December 31, 2035 and Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) through December 31, 2034.

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

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

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

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

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

See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – 2025 IRP" for additional information.

Certification Requests

On September 4, 2025, the Georgia PSC approved Georgia Power's request to certify a Georgia Power-owned battery energy storage facility with a capacity of 200 MWs and a projected COD in 2027.

On December 19, 2025, the Georgia PSC approved Georgia Power's request, as modified by a stipulation between Georgia Power and the staff of the Georgia PSC (Certification Stipulation), to certify the following resources totaling 9,885 MWs:

•18 resources selected from the RFP pursuant to the 2022 IRP final order, totaling 7,999 MWs (6,804 MWs of Georgia Power projects) with projected CODs or delivery commencement dates between 2028 and 2030.

•Extension of 50 MWs of an existing 750-MW affiliate PPA with Mississippi Power for an additional year through December 31, 2029.

•A 20-year non-affiliate PPA for 930 MWs commencing in 2030 and five 25-year non-affiliate PPAs totaling 646 MWs commencing in 2027.

•Construction of a 260-MW Georgia Power-owned battery energy storage facility with a projected COD in 2027 to be paired with an existing non-affiliate solar PPA.

Pursuant to the Certification Stipulation, Georgia Power has agreed to file its next base rate case in a manner that will ensure the incremental revenue from large load customers has downward pressure, on a levelized basis, of at least $556 million per year for the years 2029, 2030, and 2031.

The approved certification requests in September and December 2025 associated with these Georgia Power-owned projects and related transmission investments total approximately $16.7 billion, excluding AFUDC.

See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – Certification Requests" and FINANCIAL CONDITION AND LIQUIDITY – "Cash Requirements" herein for additional information.

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Fuel Cost Recovery

On February 17, 2026, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 12.6% effective June 1, 2026, which is expected to reduce annual billings by approximately $388 million. Georgia Power expects the Georgia PSC to make a final decision on this matter on May 28, 2026. The ultimate outcome of this matter cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power – Fuel Cost Recovery" for additional information.

Mississippi Power

On April 3, 2025, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy in December 2024, as part of the MRA tariff.

On June 17, 2025, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2025, resulting in an annual increase in revenues of approximately 4.0%, or $41 million. In accordance with the PEP rate schedule, an increase of 2.0% of total retail revenues, or approximately $22 million, became effective with the first billing cycle of April 2025, and the remaining approximately $19 million became effective with the first billing cycle of July 2025. Also in the PEP filing, the Mississippi PSC approved Mississippi Power's use of a portion of its retail reliability reserve balance during 2025. As a result, Mississippi Power utilized the retail reliability reserve in the amount of $10.9 million during 2025 for reliability-related generation, transmission, and distribution expenses.

On June 19, 2025, the Florida PSC issued a final order approving the transfer of FP&L's 50% ownership interest in Plant Daniel Units 1 and 2 to Mississippi Power. On July 30, 2025, Mississippi Power completed the acquisition of FP&L's 50% interest in Plant Daniel Units 1 and 2 and, as part of the acquisition, received approximately $36 million from FP&L, which was recorded as a regulatory liability and is being amortized to offset incremental costs as authorized by the Mississippi PSC.

On November 17, 2025, Mississippi Power submitted its annual preliminary retail PEP filing for 2026 to the Mississippi PSC, which requested a 1.8%, or $20 million, annual increase in revenues. In accordance with the PEP rate schedule, the rate increase became effective with the first billing cycle of January 2026, subject to refund. The Mississippi PSC is expected to render a final decision in the second quarter 2026. The ultimate outcome of this matter cannot be determined at this time.

On February 13, 2026, Mississippi Power submitted its annual ECO Plan filing to the Mississippi PSC, which requested a $2 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.

Southern Power

During 2025, Southern Power continued construction of the 200-MW first phase, the 180-MW second phase, and the 132-MW third phase of the Millers Branch solar facility. In addition, Southern Power continued the development project to repower 200 MWs of the 299-MW Kay wind facility and began development projects to repower the full capacity of the 147-MW Grant Plains, the 152-MW Grant, the 257-MW Wake, and the 276-MW Bethel wind facilities. The output of the development projects is contracted under new and amended PPAs, with commercial operations projected to occur between the third quarter 2026 and the third quarter 2027. The ultimate outcome of these matters cannot be determined at this time. Subsequent to December 31, 2025, Southern Power completed construction of the 200-MW first phase of the Millers Branch solar facility. See Note 15 to the financial statements under "Southern Power" for additional information.

On December 31, 2025, Southern Power purchased 100% of the noncontrolling Class A membership interests in the SP Wind tax equity partnership for approximately $282 million. See Note 7 to the financial statements under "Southern Power – Variable Interest Entities – SP Wind" for additional information.

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, 2025 was 97% through 2030 and 89% through 2035, with an average remaining contract duration of approximately 12 years.

Southern Company Gas

Nicor Gas

In connection with Nicor Gas' 2023 general base rate case proceeding, the Illinois Commission disallowed $127 million of capital investments that have been completed or were planned to be completed through December 31, 2024. This amount is comprised of $31 million for capital investments placed in service in 2022 and 2023 under a nine-year regulatory infrastructure program

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(Investing in Illinois) and $96 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. The disallowances are reflected on the statements of income in estimated loss on regulatory disallowance. In January 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 2023 base rate case decision. In February 2024, Nicor Gas filed a notice of appeal with the Illinois Appellate Court related to the Illinois Commission's rate case ruling. On December 1, 2025, the Illinois Appellate Court upheld the Illinois Commission's decision regarding certain capital investment disallowances in Nicor Gas' 2023 general base rate case proceeding. On December 22, 2025, Nicor Gas filed a petition for rehearing with the Illinois Appellate Court specifically addressing $43 million of the base rate case disallowances.

Any further cost disallowances by the Illinois Commission in the 2020 through 2023 annual review proceedings of the Investing in Illinois program 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 November 19, 2025, the Illinois Commission approved a $168 million annual base rate increase for Nicor Gas, which became effective December 2, 2025. The base rate increase was based on an ROE of 9.60% and an equity ratio of 50.00%.

Additionally, the Illinois Commission excluded $120 million of capital investments included in the base rate case filing that have been incurred or are expected to be incurred through December 31, 2026. Nicor Gas analyzed the Illinois Commission's order and recorded a pre-tax charge to income in the fourth quarter 2025 of $63 million ($47 million after tax) associated with excluded capital investments that have been incurred. The disallowances are reflected on the statements of income in estimated loss on regulatory disallowance.

On January 6, 2026, 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 19, 2025 base rate case decision. On January 14, 2026, Nicor Gas filed a petition for review with the Illinois Appellate Court related to the Illinois Commission's rate case ruling. It remains Nicor Gas' position that it has met its evidentiary burden to demonstrate that the amount and the timing of such capital investments are prudent and reasonable and that such capital investments should be included in base rates.

On January 9, 2026, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $221 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, 2027, 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. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" for additional information.

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

Virginia Natural Gas

On December 17, 2025, the Virginia Commission approved a stipulation related to Virginia Natural Gas' August 2024 general base rate case filing. The approved stipulation provides for a $40 million increase in annual base rate revenues, including the recovery of investments under the SAVE program, an ROE of 9.85%, and an equity ratio of 49.35%. Interim rates became effective January 1, 2025, subject to refund, based on Virginia Natural Gas' original requested increase of approximately $63 million. Refunds to customers related to the difference between the approved rates implemented December 31, 2025 and the interim rates will be administered during the first quarter 2026.

Key Performance Indicators

In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to approximately 9.0 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

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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 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 $4.3 billion in 2025, a decrease of $60 million, or 1.4%, from 2024. The decrease was primarily due to increases in depreciation and amortization, other operations and maintenance expenses, and interest expense, largely offset by increases in retail electric revenues associated with rates and pricing and sales growth, other revenues, natural gas revenues associated with base rate increases, and allowance for equity funds used during construction.

Basic EPS was $3.94 in 2025 and $4.02 in 2024. Diluted EPS, which factors in additional shares primarily related to stock-based compensation, was $3.92 in 2025 and $3.99 in 2024. EPS for 2025 and 2024 was negatively impacted by $0.03 and $0.01 per 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 $2.94 in 2025 and $2.86 in 2024. In January 2026, Southern Company declared a quarterly dividend of 74 cents per share. For 2025, the dividend payout ratio was 75% compared to 71% for 2024.

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.

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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:

Retail Electric Revenues

Retail electric revenues increased $1.5 billion, or 8.7%, in 2025 as compared to 2024. Details of the changes in retail electric revenues were as follows:

Changes in rates and pricing resulted in an increase in retail electric revenues in 2025 as compared to 2024 primarily due to increases at Georgia Power related to base tariff increases and increased ECCR tariff revenues in accordance with the 2022 ARP and the inclusion of Plant Vogtle Unit 4 in retail rates net of elimination of the NCCR tariff, as well as an increase in Rate RSE at Alabama Power. See Note 2 to the financial statements under "Alabama Power" and "Georgia Power" for additional information.

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Changes in sales resulted in an increase in retail electric revenues in 2025 as compared to 2024. Changes in retail electric revenues are influenced heavily by the change in the volume of energy sold from year to year, which generally results from changes in electricity usage by customers, weather, and the number of customers. Total retail KWH sales for 2025 and the percent changes from 2024 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.

Weather-adjusted retail energy sales increased by 2.5 billion KWHs in 2025 as compared to 2024. Weather-adjusted residential KWH sales increased 0.8% primarily due to customer growth. Weather-adjusted commercial KWH sales increased 2.8% primarily due to additional sales from new and existing data centers at Georgia Power. Industrial KWH sales increased 1.4% primarily due to increases in the electronics and primary metals sectors, partially offset by decreases in the pipeline and textiles sectors.

Changes in fuel and other cost recovery revenues resulted in an increase in retail electric revenues in 2025 as compared to 2024 primarily due to higher recoverable fuel costs, as discussed further under "Fuel and Purchased Power Expenses" herein. 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 for additional information.

Wholesale Electric Revenues

Wholesale electric revenues increased $510 million, or 21.0%, in 2025 as compared to 2024. Details of wholesale electric revenues were as follows:

The change in wholesale electric revenues was largely driven by increases in energy revenues of $326 million at the traditional electric operating companies and $179 million at Southern Power. The increase in energy revenues was due to a $420 million increase related to the average cost per KWH sold primarily resulting from higher fuel and purchased power prices, as well as an $85 million increase related to the volume of KWHs sold resulting from higher demand. Wholesale energy sales totaled 52.5 billion KWHs in 2025, a 4.7% increase as compared to 2024.

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 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

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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 and 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

Other electric revenues increased $57 million, or 6.4%, in 2025 as compared to 2024. The increase was primarily due to increases of $27 million in revenues from renewable energy programs at Georgia Power primarily associated with solar application fees, $24 million in regulated outdoor lighting sales at Georgia Power, $17 million in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs at Georgia Power, $10 million in customer fees at Georgia Power, and $7 million related to undistributed customer bill credits at Alabama Power, partially offset by decreases of $19 million in pole attachment revenues at Alabama Power and Georgia Power and $16 million associated with transmission revenues at Southern Power.

Other Revenues

Other revenues increased $66 million, or 13.6%, in 2025 as compared to 2024. The increase was primarily due to increases of $80 million in unregulated sales primarily associated with power delivery construction and maintenance, renewables, and resiliency projects at Georgia Power, partially offset by decreases of $10 million in unregulated sales associated with energy conservation projects at Georgia Power and $8 million in unregulated sales of products and services at Alabama Power.

Fuel and Purchased Power Expenses

In 2025, total fuel and purchased power expenses were $5.9 billion, an increase of $898 million, or 18.0%, as compared to 2024. The increase was primarily the result of a $592 million net increase related to the average cost of fuel and purchased power and a $251 million increase related to the volume of KWHs generated and purchased. Also contributing to the increase was $55 million related to credits recorded at Georgia Power 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.

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.

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. 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.

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

(a)Excludes KWHs generated from test period energy at Plant Vogtle Unit 4 prior to being placed in service in April 2024. The related fuel costs were charged to CWIP in accordance with FERC guidance.

(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.

Cost of Other Sales

Cost of other sales increased $37 million, or 15.6%, in 2025 as compared to 2024. The increase was primarily due to an increase in expenses associated with unregulated power delivery construction and maintenance contracts at Georgia Power.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $364 million, or 7.2%, in 2025 as compared to 2024. The increase was primarily due to a $132 million increase in generation expenses primarily due to non-outage maintenance expenses largely resulting from Plant Vogtle Unit 4 being placed in service in April 2024 at Georgia Power, as well as planned outages at Alabama Power and Mississippi Power, a $114 million gain in 2024 from the sale of integrated transmission system assets at Georgia Power, and increases of $65 million associated with reliability reserve accruals and reliability-related expenses at Alabama Power, $62 million associated with NDR accruals at Alabama Power, $60 million in certain employee compensation and benefit expenses, $57 million in certain technology infrastructure and application production costs, and $28 million related to injuries and damages primarily at Georgia Power, partially offset by a decrease of $98 million in transmission and distribution costs primarily associated with line maintenance and billings adjustments with integrated transmission system owners at Georgia Power, an increase of $39 million in credits to income related to the estimated probable loss on Plant Vogtle Units 3 and 4 at Georgia Power, and a $36 million impairment loss in 2024 associated with Alabama Power discontinuing the development of a multi-use commercial facility. See Note 1 to the financial statements under "Impairment of Long-Lived Assets" and Note 2 to the financial statements under "Alabama Power – Reliability Reserve Accounting Order" and – "Rate NDR" and "Georgia Power – Transmission Asset Sales" and " – Nuclear Construction" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $691 million, or 17.1%, in 2025 as compared to 2024. The increase was primarily due to increases of $298 million in accelerated depreciation at Southern Power related to wind repowering projects, $226 million associated with additional plant in service, and $123 million in amortization of regulatory assets related to CCR AROs at Georgia Power as approved in the 2025 compliance filing under the terms of the 2022 ARP. See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein and Notes 2 and 15 to the financial statements under "Georgia Power" and "Southern Power – Wind Repowering Projects," respectively, for additional information.

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Taxes Other Than Income Taxes

Taxes other than income taxes decreased $25 million, or 1.9%, in 2025 as compared to 2024. The decrease was primarily due to decreases of $78 million in property taxes primarily resulting from the actualization of prior-year tax assessments at Georgia Power, partially offset by increases of $21 million in municipal franchise fees resulting from higher retail revenues at Georgia Power, $18 million in utility license taxes at Alabama Power resulting from an increase in the tax base, and $9 million in payroll taxes.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction increased $109 million, or 52.2%, in 2025 as compared to 2024. The increase was primarily associated with increases in capital expenditures subject to AFUDC at Georgia Power and Alabama Power, partially offset by the impact of Plant Vogtle Unit 4 being placed in service in April 2024 at Georgia Power. See Notes 1 and 2 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized" and "Georgia Power," respectively, for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $73 million, or 5.3%, in 2025 as compared to 2024. The increase primarily reflects approximately $95 million related to higher average outstanding borrowings and a decrease of $12 million in net deferred financing costs related to Plant Vogtle Unit 3 at Georgia Power, partially offset by an increase of $41 million in capitalized interest and AFUDC debt associated with increased capital expenditures. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and – "Financing Activities" herein, Note 1 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized," and Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net decreased $4 million, or 0.8%, in 2025 as compared to 2024 primarily due to a $40 million increase in charitable donations at the traditional electric operating companies, primarily at Georgia Power, largely offset by increases of $13 million in interest income, $13 million in customer charges related to contributions in aid of construction at the traditional electric operating companies, and $10 million related to the receipt of liquidated damages at Alabama Power associated with the termination of two solar projects.

Income Taxes

Income taxes increased $36 million, or 3.6%, in 2025 as compared to 2024. The increase was primarily due to higher pre-tax earnings and a $29 million increase in charges to a valuation allowance on certain state tax credit carryforwards at Georgia Power, partially offset by increases of $28 million in the flowback of certain excess deferred income taxes at the traditional electric operating companies and $21 million in the generation of advanced nuclear PTCs 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 $29 million, or 20.6%, in 2025 as compared to 2024. The increased loss was primarily due to $20 million in higher HLBV loss allocations to Southern Power's tax equity partners and $11 million in lower 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.

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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 2025, the percentage of operating revenues and net income generated during the Heating Season was 66% and 82%, respectively. For 2024, the percentage of operating revenues and net income generated during the Heating Season was 62% and 80%, respectively.

Natural Gas Revenues

Natural gas revenues in 2025 were $5.0 billion, reflecting a $588 million, or 13.2%, increase compared to 2024. Details of natural gas revenues were as follows:

Changes in rates resulted in an increase in revenues in 2025 as compared to 2024 primarily due to base rate increases at Atlanta Gas Light and Virginia Natural Gas. 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 increased in 2025 primarily due to higher cost of natural gas driven by higher natural gas prices and gas volumes, as well as increases in other expenses passed through to 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 the natural gas distribution utilities. See "Cost of Natural Gas" and "Other Operations and Maintenance Expenses" herein for additional information.

Revenues from gas marketing services increased in 2025 primarily due to higher commodity prices.

Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limits positive or negative impacts to income from 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

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impacts in the event of warmer-than-normal weather 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 81.7% of the total cost of natural gas for 2025.

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 $1.6 billion, an increase of $403 million, or 33.7%, in 2025 as compared to 2024, which reflects higher gas cost recovery in 2025 as a result of a 51.0% increase in natural gas prices as compared to 2024.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $125 million, or 10.1%, in 2025 as compared to 2024. The increase was primarily due to $63 million in charges related to the disallowance of certain capital investments at Nicor Gas, as well as increases of $38 million in employee compensation and benefit expenses, $23 million in expenses passed through to customers at the natural gas distribution utilities, and $17 million in bad debt expense, partially offset by a decrease of $26 million related to certain deferred expenses. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $58 million, or 8.9%, in 2025 as compared to 2024. The increase was primarily due to additional plant in service related 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.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $24 million, or 9.7%, in 2025 as compared to 2024. The increase was primarily due to an increase in revenue taxes as a result of higher natural gas revenues at Nicor Gas. Revenue taxes imposed on Nicor Gas are recoverable from its customers.

Earnings from Equity Method Investments

Earnings from equity method investments decreased $19 million, or 13.0%, in 2025 as compared to 2024. The decrease was primarily due to legal settlements, increased spending on system integrity initiatives, and lower rates, all at SNG. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $36 million, or 10.6%, in 2025 as compared to 2024. The increase was primarily associated with higher average outstanding borrowings. 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 decreased $76 million, or 29.5%, in 2025 as compared to 2024. The decrease was primarily due to lower pre-tax earnings, including the impact of the regulatory disallowance at Nicor Gas, an increase of $36 million in the flowback of excess federal and state deferred income taxes, and a decrease of $8 million related to uncertain state tax positions in 2024. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" and 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, through its subsidiaries, invests in various projects and insures various risk exposures of Southern Company and its subsidiaries; and Southern Linc, which provides digital

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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 $67 million, or 10.1%, in 2025 as compared to 2024 primarily due to an increase in revenues at PowerSecure largely related to a higher volume of distributed infrastructure projects.

Other Operations and Maintenance

Other operations and maintenance expenses for these other business activities increased $41 million, or 19.2%, in 2025 as compared to 2024 primarily due to an increase of $43 million in expenses at PowerSecure primarily related to a higher volume of distributed infrastructure projects, partially offset by a decrease of $16 million in expenses at the parent company primarily related to lower director compensation expenses.

Interest Expense

Interest expense for these other business activities, which primarily results from parent company financing activities, increased $387 million, or 37.6%, in 2025 as compared to 2024 primarily due to increases of $252 million associated with the extinguishment of debt at the parent company, $117 million related to higher average outstanding borrowings, and $29 million related to higher interest rates. See Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net for these other business activities decreased $26 million, or 108.3%, in 2025 as compared to 2024 primarily due to an increase in charitable donations at the parent company.

Income Taxes (Benefit)

The income tax benefit for these other business activities increased $101 million, or 34.6%, in 2025 as compared to 2024 primarily due to higher pre-tax losses at the parent company.

Alabama Power

Alabama Power's net income was $1.5 billion in 2025, representing a $113 million, or 8.1%, increase from 2024. The increase was primarily due to higher retail electric revenues resulting from changes in rates and pricing, partially offset by increases in other operations and maintenance expenses and depreciation and amortization.

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A condensed income statement for Alabama Power follows:

Retail Revenues

Retail revenues increased $497 million, or 7.5%, in 2025 as compared to 2024. Details of the changes in retail revenues were as follows:

Changes in rates and pricing resulted in an increase in revenues primarily due to an increase in Rate RSE. See Note 2 to the financial statements under "Alabama Power – Rate RSE" for additional information.

Changes in sales resulted in an increase in retail revenues in 2025 as compared to 2024. Changes in retail revenues are influenced heavily by the change in the volume of energy sold from year to year, which generally results from changes in electricity usage by

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customers, weather, and the number of customers. Total retail KWH sales for 2025 and the percent change from 2024 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.

Weather-adjusted retail energy sales increased by 0.3 billion KWHs in 2025 as compared to 2024. Weather-adjusted residential and commercial KWH sales increased 0.5% and 0.2%, respectively, primarily due to customer growth. Industrial KWH sales increased 1.1% primarily due to increases in the primary metals sector.

Changes in fuel and other cost recovery revenues resulted in an increase in retail revenues in 2025 as compared to 2024 primarily due to higher recoverable fuel costs, as discussed further under "Fuel and Purchased Power Expenses" herein. 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

Wholesale revenues from sales to non-affiliates increased $112 million, or 33.2%, in 2025 as compared to 2024. Details of wholesale revenues from sales to non-affiliated utilities were as follows:

The increase in wholesale revenues from sales to non-affiliates was due to increases of $45 million related to the volume of KWH sales associated with higher demand, $40 million related to the average cost per KWH sold due to higher Southern Company system fuel and purchased power prices, and $27 million related to non-fuel revenues from wholesale capacity contracts. Wholesale energy sales to non-affiliates totaled 7.6 billion KWHs in 2025, an 18.4% increase as compared to 2024.

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 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 made at market-based rates that generally provide a margin above Alabama Power's variable cost to produce the energy.

Wholesale revenues from sales to affiliates increased $49 million, or 35.3%, in 2025 as compared to 2024. The increase was primarily due to an increase of $48 million related to the average price of energy due to an increase in natural gas prices. Wholesale energy sales to affiliates totaled 5.7 billion KWHs in 2025, a 0.4% increase as compared to 2024.

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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.

Other Revenues

In 2025, other operating revenues increased $23 million, or 5.2%, as compared to 2024 primarily due to an $11 million increase in open access transmission tariff sales, a $10 million increase in regulated energy services revenues, $7 million related to undistributed customer bill credits associated with nuclear fuel disposal costs litigation, which was offset by an additional NDR accrual within other operations and maintenance expenses, and a $4 million increase in cogeneration revenues primarily related to higher fuel prices. These increases were partially offset by a $10 million decrease in pole attachment revenues and an $8 million decrease in sales of unregulated products and services. See Note 3 to the financial statements under "Nuclear Fuel Disposal Costs" for additional information.

Fuel and Purchased Power Expenses

Fuel and purchased power expenses were $2.0 billion in 2025, an increase of $300 million, or 17.3%, as compared to 2024. The increase was primarily due to a $159 million increase related to the volume of KWHs generated and purchased and a $141 million increase related to the average cost of fuel and purchased power.

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.

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, Alabama Power purchases a portion of its electricity needs from the wholesale market. 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. 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.

Details of Alabama Power's generation and purchased power and the related costs 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.

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $131 million, or 6.9%, in 2025 as compared to 2024. The increase was primarily due to increases of $65 million associated with reliability reserve accruals and reliability-related expenses, $62 million associated with NDR accruals, $27 million in certain employee compensation and benefit expenses, and $21 million in generation expenses primarily associated with planned outages, partially offset by a $36 million impairment loss in 2024 associated with

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Alabama Power discontinuing the development of a multi-use commercial facility. See Note 1 to the financial statements under "Impairment of Long-Lived Assets" and Note 2 to the financial statements under "Alabama Power – Reliability Reserve Accounting Order" and – "Rate NDR" for additional information.

Depreciation and Amortization

Depreciation and amortization increased $51 million, or 3.5%, in 2025 as compared to 2024 primarily due to additional plant in service related to transmission and distribution facilities.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $27 million, or 5.7%, in 2025 as compared to 2024 primarily due to an increase 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 increased $12 million, or 21.1%, in 2025 as compared to 2024 primarily due to an increase in capital expenditures subject to AFUDC. See Note 1 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $17 million, or 3.8%, in 2025 as compared to 2024. The increase was primarily associated with higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" and – "Sources of Capital" herein and Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net increased $11 million, or 7.0%, in 2025 as compared to 2024 primarily due to the receipt of liquidated damages associated with the termination of two solar projects.

Income Taxes

Income taxes increased $65 million in 2025 as compared to 2024 primarily due to higher pre-tax earnings and a decrease of $39 million in the flowback of certain excess deferred income taxes. 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 net income was $2.9 billion in 2025, representing a $308 million, or 12.1%, increase from 2024. The increase was primarily due to higher retail revenues associated with rates and pricing and sales growth, as well as an increase in other revenues, partially offset by increases in depreciation and amortization and other operations and maintenance expenses.

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A condensed income statement for Georgia Power follows:

Retail Revenues

Retail revenues increased $923 million, or 9.1%, in 2025 as compared to 2024. Details of the changes in retail revenues were as follows:

Changes in rates and pricing resulted in an increase in revenues primarily due to base tariff increases and increased ECCR tariff revenues in accordance with the 2022 ARP, the inclusion of Plant Vogtle Unit 4 in retail rates net of elimination of the NCCR tariff, 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.

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Changes in sales resulted in an increase in retail revenues in 2025 as compared to 2024. Changes in retail revenues are influenced heavily by the change in the volume of energy sold from year to year, which generally results from changes in electricity usage by customers, weather, and the number of customers. Total retail KWH sales for 2025 and the percent change from 2024 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.

Weather-adjusted retail energy sales increased by 2.1 billion KWHs in 2025 as compared to 2024. Weather-adjusted residential sales increased 1.0% primarily due to customer growth. Weather-adjusted commercial KWH sales increased 4.1% primarily due to additional sales from new and existing data centers. Weather-adjusted industrial KWH sales increased 2.1% primarily due to an increase in the electronics and transportation sectors, partially offset by decreases in the textiles and pipeline sectors.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Changes in retail fuel cost recovery revenues resulted in an increase in retail revenues in 2025 as compared to 2024 primarily due to higher recoverable fuel costs, as discussed further under "Fuel and Purchased Power Expenses" herein. 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.

Wholesale Revenues

Wholesale revenues from power sales increased $260 million, or 98.1%, in 2025 as compared to 2024. Details of wholesale revenues were as follows:

The increase in wholesale revenues from power sales was due to a $239 million increase in energy revenues due to increases of $195 million in fuel-related revenues, of which $118 million related to the volume of KWH sales associated with higher demand and $77 million related to the average cost per KWH sold due to higher Southern Company system fuel and purchased power prices, and $44 million in non-fuel-related energy revenues from wholesale contracts, as well as a $21 million increase in capacity revenues from new and existing power sales agreements. Wholesale energy sales from power sales totaled 9.5 billion KWHs in 2025, a 106.4% increase as compared to 2024.

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.

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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.

Other Revenues

In 2025, other operating revenues increased $117 million, or 13.3%, as compared to 2024 primarily due to increases of $80 million in unregulated sales primarily associated with power delivery construction and maintenance, renewables, and resiliency projects, $27 million in revenues from renewable energy programs primarily associated with solar application fees, $22 million in outdoor lighting sales, $17 million in realized gains associated with price stability products for retail customers on variable demand-driven pricing tariffs, and $10 million in customer fees, partially offset by decreases of $15 million in open access transmission tariff sales, $10 million in unregulated sales associated with energy conservation projects, $9 million in regulated sales associated with power delivery construction and maintenance projects, and $8 million in pole attachment revenues.

Fuel and Purchased Power Expenses

Fuel and purchased power expenses were $3.6 billion in 2025, an increase of $539 million, or 17.9%, as compared to 2024. The increase was due to a $288 million increase related to the volume of KWHs generated and purchased, an increase of $196 million related to the average cost of fuel and purchased power, and an increase of $55 million related to credits recorded 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.

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.

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. 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. 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, all as approved by the FERC.

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

(a)Excludes KWHs generated from test period energy at Plant Vogtle Unit 4 prior to being placed in service in April 2024. The related fuel costs were charged to CWIP in accordance with FERC guidance.

(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.

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Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $234 million, or 10.0%, in 2025 as compared to 2024. The increase was primarily due to a $114 million gain from the sale of integrated transmission system assets in 2024 and increases of $75 million in generation expenses primarily due to non-outage maintenance expenses largely resulting from Plant Vogtle Unit 4 being placed in service in April 2024, $42 million in certain technology infrastructure and application production costs, $38 million in expenses associated with unregulated power delivery construction and maintenance, energy conservation, and renewables projects, $33 million in certain employee compensation and benefit expenses, and $24 million related to injuries and damages, partially offset by a decrease of $80 million in transmission and distribution costs primarily associated with line maintenance and billings adjustments with integrated transmission system owners and an increase of $39 million in credits to income related to the estimated probable loss on Plant Vogtle Units 3 and 4. 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 $300 million, or 16.9%, in 2025 as compared to 2024 primarily due to increases of $156 million associated with additional plant in service and $123 million in amortization of regulatory assets related to CCR AROs as approved in the 2025 compliance filing under the terms of the 2022 ARP. See Note 2 to the financial statements under "Georgia Power – Rate Plans" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes decreased $71 million, or 11.0%, in 2025 as compared to 2024 primarily due to a decrease of $98 million in property taxes primarily resulting from the actualization of prior-year tax assessments, partially offset by an increase of $21 million in municipal franchise fees resulting from higher retail revenues.

Allowance for Equity Funds Used During Construction

Allowance for equity funds used during construction increased $96 million, or 63.2%, in 2025 as compared to 2024 primarily due to an increase in capital expenditures subject to AFUDC, partially offset by the impact of Plant Vogtle Unit 4 being placed in service in April 2024. See Notes 1 and 2 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized" and "Georgia Power," respectively, for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $68 million, or 9.4%, in 2025 as compared to 2024. The increase was primarily associated with an increase of approximately $71 million related to higher average outstanding borrowings and a decrease of $12 million in net deferred financing costs related to Plant Vogtle Unit 3, partially offset by an increase of $22 million in AFUDC debt related to increased capital expenditures. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and – "Financing Activities" herein, Note 1 to the financial statements under "Allowance for Funds Used During Construction and Interest Capitalized," and Note 8 to the financial statements for additional information.

Other Income (Expense), Net

Other income (expense), net decreased $19 million, or 10.7%, in 2025 as compared to 2024 primarily due to a $45 million increase in charitable donations, partially offset by a $15 million increase in customer charges related to contributions in aid of construction.

Income Taxes

Income taxes decreased $1 million, or 0.2%, in 2025 as compared to 2024 primarily due to increases of $77 million in the flowback of excess state deferred income taxes and $21 million in the generation of advanced nuclear PTCs, largely offset by higher pre-tax earnings and a $29 million increase in charges to a valuation allowance on certain state tax credit carryforwards. See Note 10 to the financial statements for additional information.

Mississippi Power

Mississippi Power's net income was $215 million in 2025, representing a $16 million, or 8.0%, increase from 2024. The increase was primarily due to higher retail revenues primarily resulting from changes in rates and pricing, partially offset by increases in depreciation and amortization and other operations and maintenance expenses.

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A condensed income statement for Mississippi Power follows:

Retail Revenues

Retail revenues for 2025 increased $120 million, or 12.4%, as compared to 2024. Details of the changes in retail revenues were as follows:

Changes in rates and pricing resulted in an increase in revenues primarily due to new PEP rates that became effective for the first billing cycle of April 2025. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan" for additional information.

Changes in sales resulted in an increase in retail revenues in 2025 as compared to 2024. Changes in retail revenues are influenced heavily by the change in the volume of energy sold from year to year, which generally results from changes in electricity usage by

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customers, weather, and the number of customers. Total retail KWH sales for 2025 and the percent change from 2024 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.

Weather-adjusted retail energy sales increased by 86 million KWHs in 2025 as compared to 2024. Weather-adjusted residential KWH sales increased 2.1% primarily due to increased customer usage. Weather-adjusted commercial KWH sales decreased 0.5% primarily due to decreased customer usage. Industrial KWH sales increased 1.3% primarily due to increases in the petroleum and chemicals sectors.

Changes in fuel and other cost recovery revenues resulted in an increase in retail revenues in 2025 as compared to 2024 primarily due to higher recoverable fuel costs, as discussed further under "Fuel and Purchased Power Expenses" herein. 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. 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

Wholesale revenues from sales to non-affiliates increased $47 million, or 20.6%, in 2025 as compared to 2024. Details of wholesale revenues from power sales to non-affiliated utilities, including FERC-regulated MRA sales as well as market-based sales, were as follows:

The increase in wholesale revenues from sales to non-affiliates was due to a $25 million increase associated with MRA customers largely due to higher recoverable fuel costs, a $15 million increase associated with changes in power supply agreements, and a $7 million increase in opportunity sales. Wholesale energy sales to non-affiliates totaled 3,397 million KWHs in 2025, an 8.5% increase as compared to 2024.

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 which are subject to regulation by the FERC. The contracts with these wholesale customers represented 12.9% of Mississippi Power's total operating revenues in 2025. Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at

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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 $62 million, or 28.4%, in 2025 as compared to 2024. The increase was primarily due to increases of $44 million related to the price of energy driven by natural gas prices and $16 million related to the volume of KWH sales. Wholesale energy sales to affiliates totaled 5,636 million KWHs in 2025, a 10.4% increase as compared to 2024. 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.

Other Revenues

In 2025, other operating revenues increased $3 million, or 5.8%, as compared to 2024 primarily due to an increase of $8 million in customer charges related to contributions in aid of construction included in rates, partially offset by a decrease of $4 million in transmission revenue primarily associated with open access transmission tariff revenues.

Fuel and Purchased Power Expenses

Fuel and purchased power expenses were $624 million in 2025, an increase of $147 million, or 30.8%, as compared to 2024. The increase was primarily due to a $111 million increase related to the average cost of fuel and a $36 million increase 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 Mississippi Power's fuel cost recovery clauses. See Note 2 to the financial statements under "Mississippi Power – Fuel Cost Recovery" for additional information.

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, Mississippi Power purchases a portion of its electricity needs from the wholesale market. 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 electric 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.

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

Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $17 million, or 4.6%, in 2025 as compared to 2024. The increase was primarily due to increases of $20 million in generation expenses primarily associated with planned outages, $7 million in transmission and distribution expenses primarily associated with routine maintenance, and $3 million in customer service expenses, partially offset by a decrease of $10.9 million due to utilization of the retail reliability reserve to offset generation, transmission, and distribution expenses and a decrease of $8 million due to lower retail reliability reserve accruals. See Note 2 to the financial statements under "Mississippi Power – Reliability Reserve Accounting Order" for additional information.

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Depreciation and Amortization

Depreciation and amortization increased $18 million, or 9.3%, in 2025 as compared to 2024 primarily due to increases of $10 million resulting from higher depreciation rates and $9 million associated with additional plant in service. See Note 5 to the financial statements under "Depreciation and Amortization" for additional information.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $12 million, or 9.4%, in 2025 as compared to 2024. The increase was primarily due to an increase in property taxes primarily resulting from an increase in the assessed value of property.

Income Taxes

Income taxes increased $18 million, or 38.3%, in 2025 as compared to 2024 primarily due to a decrease of $10 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 2025 was $125 million, a $203 million decrease from 2024. The decrease was primarily due to accelerated depreciation related to wind repowering projects, partially offset by higher revenues driven by higher market prices of energy. See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein and Note 15 to the financial statements under "Southern Power – Wind Repowering Projects" for additional information.

A condensed statement of income for Southern Power follows:

Operating Revenues

Total operating revenues include PPA capacity revenues derived primarily from long-term contracts associated with natural gas facilities and PPA energy revenues derived from long-term contracts associated with 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

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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.

Operating Revenues Details

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

Operating revenues for 2025 were $2.2 billion, a $184 million, or 9.1%, increase from 2024. The change in operating revenues was primarily due to the following:

•PPA capacity revenues increased $16 million, or 3.2%, due to a net increase in MW capacity under contract from natural gas PPAs, partially offset by a decrease associated with a change in rates from natural gas PPAs.

•PPA energy revenues increased $180 million, or 14.7%, primarily due to an increase of $96 million largely driven by fuel and purchased power prices and an increase of $87 million related to the volume of KWHs sold under natural gas PPAs.

•Non-PPA revenues increased $7 million, or 2.8%, due to an increase of $72 million driven by the market price of energy, largely offset by a decrease of $67 million related to the volume of KWHs sold through short-term sales.

•Other revenues decreased $19 million, or 51.4%, primarily due to a $16 million decrease associated with transmission revenues.

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

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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.

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

Total fuel and purchased power expenses increased $141 million, or 21.5%, in 2025 as compared to 2024. Fuel expense increased $97 million, or 16.8%, due to an increase of $232 million associated with the average cost of fuel, largely offset by a decrease of $135 million related to the volume of KWHs generated. Purchased power expense increased $44 million, or 56.4%, due to an increase of $29 million associated with the average cost of purchased power and an increase of $15 million related to the volume of KWHs purchased.

Depreciation and Amortization

Depreciation and amortization increased $321 million, or 61.5%, in 2025 as compared to 2024 primarily due to a $298 million increase in accelerated depreciation related to wind repowering projects. See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein and Note 15 to the financial statements under "Southern Power – Wind Repowering Projects" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized decreased $13 million, or 11.1%, in 2025 as compared to 2024. The decrease was primarily due to an $18 million increase in capitalized interest associated with construction and wind repowering projects, partially offset by a $5 million increase in interest expense related to higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and – "Financing Activities" herein and Note 8 to the financial statements for additional information.

Income Taxes (Benefit)

Income tax benefit increased $48 million in 2025 as compared to 2024 primarily due to a decrease in pre-tax earnings attributable to Southern Power. See Notes 1, 10, and 15 to the financial statements under "Income Taxes," "Effective Tax Rate," and "Southern Power – Wind Repowering Projects," respectively, for additional information.

Net Loss Attributable to Noncontrolling Interests

Net loss attributable to noncontrolling interests increased $29 million, or 20.6%, in 2025 as compared to 2024. The increased loss was primarily due to $20 million in higher HLBV loss allocations to tax equity partners and $11 million in lower income allocations to equity partners.

Southern Company Gas

Southern Company Gas uses Heating Degree Days to measure weather and the operational effects on its business. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. However, Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit positive or negative impacts to income from 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 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

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quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. Thus, Southern Company Gas' 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 2025 was $732 million, a decrease of $8 million, or 1.1%, compared to 2024. The decrease was primarily due to a $16 million decrease in net income at gas pipeline investments and a $15 million decrease in net income at gas marketing services, partially offset by a $19 million increase in net income at gas distribution operations.

A condensed income statement for Southern Company Gas follows:

Natural Gas Revenues

Natural gas revenues in 2025 were $5.0 billion, reflecting a $588 million, or 13.2%, increase compared to 2024. Details of natural gas revenues were as follows:

Changes in rates resulted in an increase in revenues in 2025 as compared to 2024 primarily due to base rate increases at Atlanta Gas Light and Virginia Natural Gas. 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 increased in 2025 as compared to 2024 primarily due to higher cost of natural gas driven by higher natural gas prices and volumes, as well as increases in other expenses passed through to 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 "Cost of Natural Gas" and "Other Operations and Maintenance Expenses" herein for additional information.

Revenues from gas marketing services increased in 2025 as compared to 2024 primarily due to higher 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, 2025 and 2024:

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 81.7% of the total cost of natural gas for 2025.

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 $1.6 billion, an increase of $403 million, or 33.7%, in 2025 as compared to 2024, which reflects higher gas cost recovery in 2025 as a result of a 51.0% increase in natural gas prices as compared to 2024.

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.

The following table details the volumes of natural gas sold during 2025 and 2024:

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Other Operations and Maintenance Expenses

Other operations and maintenance expenses increased $62 million, or 5.0%, in 2025 as compared to 2024. The increase was primarily due to increases of $38 million in employee compensation and benefit expenses, $23 million in expenses passed through to customers at gas distribution operations, and $17 million in bad debt expense, partially offset by a decrease of $26 million related to certain deferred expenses.

Depreciation and Amortization

Depreciation and amortization increased $58 million, or 8.9%, in 2025 as compared to 2024. The increase was primarily due to additional plant in service related 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.

Taxes Other Than Income Taxes

Taxes other than income taxes increased $24 million, or 9.7%, in 2025 as compared to 2024. The increase was primarily due to an increase in revenue taxes as a result of higher natural gas revenues at Nicor Gas. Revenue taxes imposed on Nicor Gas are recoverable from its customers.

Estimated Loss on Regulatory Disallowance

In 2025, Southern Company Gas recorded $63 million in charges related to the disallowance of certain capital investments at Nicor Gas. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" for additional information.

Earnings from Equity Method Investments

Earnings from equity method investments decreased $19 million, or 13.0%, in 2025 as compared to 2024. The decrease was primarily due to legal settlements, increased spending on system integrity initiatives, and lower rates, all at SNG. See Note 7 to the financial statements under "Southern Company Gas" for additional information.

Interest Expense, Net of Amounts Capitalized

Interest expense, net of amounts capitalized increased $36 million, or 10.6%, in 2025 as compared to 2024. The increase was primarily associated with higher average outstanding borrowings. 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 decreased $76 million, or 29.5%, in 2025 as compared to 2024. The decrease was primarily due to lower pre-tax earnings, including the impact of the regulatory disallowance at Nicor Gas, an increase of $36 million in the flowback of excess federal and state deferred income taxes, and a decrease of $8 million related to uncertain state tax positions in 2024. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Nicor Gas" and Note 10 to the financial statements for additional information.

Segment Information

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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 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, 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 2025, net income increased $19 million, or 3.5%, as compared to 2024 as described further below:

•Operating revenues increased $529 million primarily due to higher gas cost recovery and base rate increases. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas.

•Operating expenses increased $539 million primarily due to a $346 million increase in cost of natural gas as a result of higher gas prices and higher volumes sold compared to 2024, a $63 million charge related to the disallowance of certain capital investments at Nicor Gas, a $57 million increase in depreciation primarily due to additional plant in service related to continued investments at the natural gas distribution utilities, a $43 million increase related to expenses passed through to customers, a $25 million increase related to employee compensation and benefit expenses, and a $17 million increase in bad debt expense, partially offset by a decrease of $26 million related to certain deferred expenses.

•Interest expense, net of amounts capitalized increased $31 million primarily due to higher average outstanding borrowings.

•Income taxes decreased $63 million primarily due to lower pre-tax earnings, including the impact of the regulatory disallowance at Nicor Gas, and an increase in the flowback of excess federal and state deferred income taxes.

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – 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. In 2025, net income decreased $16 million, or 15.8%, as compared to 2024 primarily due to legal settlements, increased spending on system integrity initiatives, and lower rates at SNG.

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 2025, net income decreased $15 million, or 14.7%, as compared to 2024. The decrease was due to an $82 million increase in operating expenses primarily related to an increase in cost of natural gas and an increase in charitable contributions, partially offset by a $66 million increase in operating revenues primarily due to higher commodity prices.

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.

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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. The ability of the traditional electric operating companies and the natural gas distribution companies to effectively operate pursuant to these regulatory mechanisms and/or processes and appropriately balance required costs and capital expenditures with customer prices will continue to be a challenge 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 occur in the future.

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 load 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. Historically, the traditional electric operating companies have entered into large load contracts that support economic development and benefit existing customers; since 2023, the traditional electric operating companies have contracted with new data centers and other large load customers covering approximately nine GWs of electric load, with each contract individually representing a maximum annual electric load greater than 100 MWs, that have been signed by the parties and/or reviewed by the state regulatory commissions. These new contracts fully ramp up over several years after commencement of service. Some of these contracts are already in effect. Service under the contracts is expected to begin through 2028. The contracts contain various terms and conditions, such as minimum duration, minimum bill provisions, contribution by the customer to local construction costs, termination payment requirements, and financial security, designed to generate adequate incremental revenues associated with incremental costs to serve these customers. These projected growth opportunities may be affected by a variety of factors, such as energy efficiency, changes in technology, reliability and operational factors, customer demand, and government policies, which could increase or decrease the pace of growth associated with these opportunities. In addition, these opportunities present risks such as capital access and cost recovery risks. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" for additional information regarding Georgia Power's related regulatory proceedings.

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 generating 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 under current and future tax legislation and U.S. Treasury guidance; transmission constraints; cost of generation from units within the Southern Company power pool; and operational limitations. See "Income Tax Matters" herein for information regarding the IRA's expansion of the availability of federal ITCs and PTCs and the OBBB's restrictions on 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

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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, including from large customers, 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 from data centers and other large load customers and associated load and operating requirements; 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 and could be influenced by changes in technology, public policy, utility efficiency programs, and customer behavior. Significant changes in fiscal, monetary, or trade policies could affect actual economic activity and historical economic relationships in ways not anticipated in economic outlooks or Southern Company system plans. Additionally, changes in inflation, interest rates, and credit market conditions could affect the cost of doing business. All of these factors may impact future earnings. See RESULTS OF OPERATIONS herein for information on energy sales in the Southern Company system's service territory during 2025.

Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi which are subject to regulation by the FERC. The contracts with these wholesale customers represented 12.9% of Mississippi Power's total operating revenues in 2025. 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.

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, joint ventures, 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/or 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,

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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 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 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 2030 based on the current environmental compliance strategy for the Southern Company system and the traditional electric operating companies are as follows:

(a)Excludes amounts related to Alabama Power's decision to convert Plant Barry Unit 5 from coal to natural gas totaling $38 million in 2026, $15 million in 2027, and $54 million in 2028. See "Environmental Laws and Regulations – Water Quality" herein and Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" for additional information.

(b)Includes amounts contingent upon approval by the Mississippi PSC related to Mississippi Power's decision to convert Plant Daniel Unit 2 from coal to natural gas totaling $28 million in 2028 and $41 million in 2029. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plans" for additional information.

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

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.

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Court of Appeals for the Fifth Circuit stayed the EPA's disapproval of the Mississippi SIP, and, on March 25, 2025, the court vacated and remanded the EPA's disapproval of the Mississippi SIP. On May 9, 2025, other parties to the case requested en banc review before the full U.S. Court of Appeals for the Fifth Circuit. The stay remains in effect, which protects the State of Mississippi from the requirements of the federal good neighbor plan. 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, which protects the State of Alabama from the requirements of a federal good neighbor plan pending resolution of the case. The case is currently being held in abeyance. On January 30, 2026, the EPA published the proposed Phase 1 rule reconsideration of the good neighbor plan which includes a reconsideration of the EPA's previous disapprovals of ozone interstate transport SIPs from multiple states, including Alabama and Mississippi.

In June 2023, the EPA published the 2015 Ozone NAAQS good neighbor federal implementation plan (FIP), which requires reductions in nitrogen oxides emissions from sources in 23 states, including Alabama and Mississippi 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. In June 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 March 12, 2025, the EPA announced its intent to reconsider the FIP.

The ultimate impact of the FIP and associated legal matters cannot be determined at this time; however, implementation of the stayed FIP and underlying SIPs would likely result in increased compliance costs for the traditional electric operating companies.

Water Quality

In May 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 2020 ELG rule's permanent cessation of coal combustion (PCCC) subcategory and the existing rule's voluntary incentive program (VIP) compliance option. It also adds a new PCCC 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. Numerous groups and states filed petitions for review challenging the rule in multiple federal circuit courts, and, in June 2024, the challenges were consolidated in the U.S. Court of Appeals for the Eighth Circuit. On February 28, 2025, the U.S. Court of Appeals for the Eighth Circuit placed the 2024 ELG Rule litigation in abeyance pending additional rulemaking. On December 31, 2025, the EPA published a final rule to extend certain 2024 ELG Rule compliance deadlines (ELG Deadline Extensions Rule), and, subsequently, multiple petitions for review were filed challenging the ELG Deadline Extensions Rule, which have been consolidated in the U.S. Court of Appeals for the Second Circuit. The EPA also indicated in this rulemaking that it will further evaluate whether to reconsider the 2024 ELG Rule technology requirements. The ultimate impacts of the 2024 ELG Rule, the ELG Deadline Extensions Rule, and associated legal matters cannot be determined at this time; however, they may result in significant compliance costs.

In 2021, Alabama Power submitted Notices of Planned Participation (NOPPs) 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 Gaston Unit 5 (880 MWs). However, subsequent to December 31, 2025, as a result of projected future generation needs, a decision was made to convert Plant Barry Unit 5 from coal to natural gas and to continue operating Plant Barry Unit 5 beyond December 31, 2028. As agent for SEGCO, Alabama Power indicated plans to retire Plant Gaston Units 1 through 4 (1,000 MWs) by December 31, 2028. However, upon further analysis, Alabama Power, in conjunction with Georgia Power, now expects to operate Plant Gaston Units 1 through 4 through December 31, 2034. As of December 31, 2025, Alabama Power is in compliance with the 2020 ELG rule generally applicable limits for bottom ash transport water for Plant Gaston Units 1 through 4. On December 30, 2025, pursuant to the 2024 ELG Rule, Alabama Power submitted additional NOPPs to the ADEM for Plant Barry Units 4 and 5, Plant Gaston Unit 5, and Plant Gorgas, opting in to the PCCC compliance subcategory for combustion residual leachate discharges by December 31, 2034. See Notes 2 and 7 to the financial statements under "Georgia Power – Integrated Resource Plans – 2025 IRP" and "SEGCO," respectively, for additional information.

The remaining assets for which Alabama Power has indicated retirement, due to repowering of the unit to natural gas, have net book values totaling approximately $464 million (excluding capitalized asset retirement costs which are recovered through Rate CNP Compliance) at December 31, 2025. 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 Environmental Accounting Order, the regulatory asset would be amortized and recovered over an affected unit's remaining useful

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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.

In 2021, Georgia Power submitted NOPPs to the Georgia Environmental Protection Division (EPD) indicating plans to retire 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. As of December 31, 2025, Georgia Power is in compliance with the ELG rules for Plant Bowen Units 3 and 4 through the generally applicable requirements; therefore, no NOPP submission was required for these units. Through its 2025 IRP, Georgia Power received approval from the Georgia PSC to extend the operation of Plant Scherer Unit 3 through at least December 31, 2035, as well as Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) through December 31, 2034. In addition, the 2025 IRP assumes operation of Plant Bowen Units 1 and 2 through at least December 31, 2035 and does not impact the ELG compliance strategy for Plant Bowen as the flue gas desulfurization wastewater system is a common environmental control for all four generating units. On December 31, 2025, Georgia Power submitted a transfer NOPP indicating plans to pursue compliance with the 2020 ELG rule for Plant Scherer Unit 3 through the VIP by December 31, 2028. 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. See Notes 2 and 7 to the financial statements under "Georgia Power – Integrated Resource Plans – 2025 IRP" 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.

In June 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 the EPA's denial of ADEM's CCR permit program cannot be determined at this time; however, it may result in significant compliance costs.

Beginning in January 2022, the EPA issued numerous determinations that stated its 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 determinations may impact closure and groundwater monitoring plans.

In May 2024, the EPA published the final legacy CCR surface impoundments rule (2024 Legacy Rule) which regulates two new categories of federally regulated CCR, legacy surface impoundments and CCR management units (CCRMUs). The 2024 Legacy 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 2024 Legacy Rule for legacy surface impoundments and within 54 months after the effective date of the 2024 Legacy Rule for CCRMUs. Numerous industry groups, electric generators, and states filed petitions for review challenging the 2024 Legacy Rule in the U.S. Court of Appeals for the D.C. Circuit. On February 13, 2025, the U.S. Court of Appeals for the D.C. Circuit placed the 2024 Legacy Rule in abeyance pending additional rulemaking. On March 12, 2025, the EPA announced its intent to undertake several regulatory actions related to the CCR Rule. On February 10, 2026, the EPA published a final rule extending certain deadlines for compliance for owners and operators of CCRMUs. The ultimate impact of any final rule and associated legal matters cannot be determined at this time; however, it may result in significant compliance costs.

Based on compliance requirements for closure and monitoring of landfills and surface impoundments pursuant to state and federal CCR 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. 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

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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

In May 2024, the EPA published the final GHG rules (2024 GHG Rules) to establish GHG emissions standards for existing fossil fuel-fired steam electric generating units and new fossil fuel-fired combustion turbines and combined cycle generation facilities. The 2024 GHG Rules do not include standards for existing fossil fuel-fired combustion turbines or combined cycle generation facilities. Under the 2024 GHG Rules, existing source compliance for steam generating units would begin as early as January 1, 2030, depending on the subcategory for the affected unit, and 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 carbon capture and sequestration (CCS) beginning on January 1, 2032.

Numerous industry groups, electric generators, and states have filed petitions for review challenging the 2024 GHG Rules in the U.S. Court of Appeals for the D.C. Circuit. On April 25, 2025, the U.S. Court of Appeals for the D.C. Circuit placed the litigation over the 2024 GHG Rules in abeyance. On June 17, 2025, the EPA published a proposed rule that includes a primary proposal and an alternative proposal. Under the primary proposal, the EPA would repeal all GHG emissions standards for fossil fuel-fired power plants promulgated under Section 111 of the Clean Air Act based on a finding that GHG emissions from those plants do not meet the prerequisite for regulation under Section 111 that they contribute significantly to dangerous air pollution. Under the alternative proposal, the EPA would repeal all of the GHG emissions guidelines for existing fossil fuel-fired steam generating units as well as the carbon capture and storage requirement for new base load stationary combustion turbines, leaving the remaining emissions standards from the 2024 GHG Rules in place. The ultimate impact of any final rule and associated legal matters cannot be determined at this time; however, if the EPA selects the alternative proposal, it may result in increased compliance costs.

It is unclear what impact the EPA's February 12, 2026 repeal of its 2009 endangerment finding for GHG emissions from motor vehicles might have on the remaining Section 111 emissions standards if the EPA selects the alternative proposal. The EPA acknowledged in the repeal of the 2009 endangerment finding that other Clean Air Act rulemakings, including the Section 111 emissions standards for fossil fuel-fired power plants, have cited the 2009 endangerment finding, and the EPA said it would address any overlapping issues in separate rulemakings.

Internationally, 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. The United States withdrew from the Paris Agreement effective January 27, 2026.

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 20% coal, 51% natural gas, and 19% nuclear in 2025. 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 12,700 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 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.

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The following table provides the Registrants' 2024 and preliminary 2025 Scope 1 GHG emissions based on equity share of facilities:

(*)Includes GHG emissions attributable to acquired assets beginning with the date of the applicable acquisition. See Note 15 to the financial statements for additional information.

Since 2018, Southern Company system management established GHG emissions reductions goals including an intermediate goal of 50% from 2007 levels by 2030 and a long-term goal of net zero by 2050. Based on the preliminary 2025 emissions, the Southern Company system has achieved an estimated GHG emission reduction of 47% since 2007, compared to a 49% reduction in 2024. This increase in emissions is primarily attributed to increased electric generation and changes in fuel mix driven by economic dispatch, 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. Due primarily to the projected electric load growth, current projections indicate it will be extremely challenging to meet the 2030 goal. The Southern Company system continues to work toward its GHG goals while seeking to ensure reliable and affordable energy for its customers. 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, including projected load growth from large load customers, energy policy and regulations, natural gas prices, customer demand for carbon-free energy, and the development and deployment of low- to no-GHG energy technologies. Southern Company system management expects to continue to economically transition the 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; implementing initiatives to reduce natural gas distribution emissions; continuing research and development with a focus on technologies that lower GHG emissions; 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.

Alabama Power

On November 14, 2025, Alabama Power issued an RFP seeking on-demand dispatchable capacity resources of 100 MWs or greater to meet future energy needs. Any purchases will depend upon the cost competitiveness of the respective offers, as well as other options available to Alabama Power, and would ultimately require approval by the Alabama PSC. The ultimate outcome of this matter cannot be determined at this time.

Construction Programs

The Southern Company system strategy continues to include developing and constructing new electric generating and battery energy storage 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, through which the traditional electric operating companies recover their approved investment and a return on investment. Through the 2022 IRP and the 2023 IRP Update, the Georgia PSC has certified resources totaling approximately 13 GWs, approximately nine GWs of which are new generation and battery energy storage facilities that are being, or are expected to be, constructed by Georgia Power. These Georgia Power projects are projected to be placed in service through 2030. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Other Construction" for additional information.

Alabama Power executed an agreement to build a battery energy storage facility at the former Plant Gorgas site in Walker County, Alabama. The new Gorgas battery facility is designed to have the capacity to store up to 150 MWs of electricity generated by other Alabama Power resources. Construction began in the third quarter 2025, with projected completion by 2027.

Southern Power's construction program includes the Millers Branch solar project and the Kay, Grant Plains, Grant, Wake, and Bethel wind repowering projects. The repowering projects result in accelerated depreciation related to the equipment being replaced that will continue until the projects' CODs, which are projected to occur between the third quarter 2026 and the third quarter 2027. At December 31, 2025, the remaining pre-tax accelerated depreciation is projected to total approximately $490 million in 2026 and $100 million in 2027. The ultimate impact of these matters cannot be determined at this time. 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 approved investment and a return on investment associated with these infrastructure programs through their regulated rates, as approved by their applicable state regulatory agency. 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.

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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 2025, Southern Power continued to be successful in remarketing up to 1,339 MWs of annual generation capacity to load-serving entities, as well as to commercial and industrial customers, through several PPAs extending over the next 20 years. Market demand is being driven by customers securing generation capacity to manage risk, support reliability and operational commitments, replace expiring PPAs and retiring generation, and plan for future growth.

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 and to provide a return on investment. 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 claim certain deductions and to utilize certain tax credits and net operating losses. 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.

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Federal Tax Legislation

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.

The OBBB was signed into law on July 4, 2025. It extends many of the Tax Reform Legislation's provisions that were set to expire and makes some of them permanent. The OBBB includes major changes to tax incentives for renewable energy projects. The legislation restricts the ITCs and PTCs for solar and wind power projects, which were originally set to run through 2032 under the IRA. Such projects must now either begin construction by July 2026 or be fully operational by the end of 2027 in order to claim the applicable tax credits. Nuclear, hydropower, and geothermal energy projects maintain tax credits under the new law. Battery energy storage projects retain their full tax credit through 2033, with a gradual phase-out by 2036. The OBBB added new restrictions to tax credits for renewable facilities that are controlled or influenced by a prohibited foreign entity or that receive material assistance from a prohibited foreign entity. Pursuant to an executive order, the U.S. Treasury issued a notice on August 15, 2025, making changes to the start-of-construction guidance for wind and solar projects that begin construction after September 1, 2025. The Southern Company system is implementing the guidance in its plans for future renewable projects. Additionally, the IRS is expected to issue significant guidance on the tax provisions in the OBBB. The Southern Company system is still assessing and will continue to monitor the impacts of the OBBB. The ultimate outcome of this legislation cannot be determined at this time.

For solar projects placed in service in 2022 through 2027 or that begin construction by July 2026, the IRA and the OBBB provide for a 30% ITC and an option to claim a PTC instead of an ITC. Starting in 2023 and through 2033, with a gradual phase-out by 2036, the IRA and the OBBB provide for a 30% ITC for stand-alone battery energy storage projects. For wind projects placed in service in 2022 through 2027 or that have begun construction by July 2026, the IRA and the OBBB provide for a 100% PTC, adjusted for inflation annually. The 2025 PTC rate is 3 cents per KWH on solar and wind projects where PTCs have 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. Alabama Power, Georgia Power, and Southern Power have 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.

Tax Credits

Southern Company receives ITCs and PTCs in connection with investments in solar, wind, fuel cell, 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, 2025, Southern Company and Southern Power had approximately $850 million and $481 million, respectively, of unutilized federal ITCs and PTCs, which are currently projected to be fully utilized by 2031 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. On December 31, 2025, Southern Power purchased 100% of the noncontrolling Class A membership interests in the SP Wind tax equity partnership and became the sole owner of SP Wind, and the partnership was dissolved. Beginning in 2026, Southern Power will recognize the full tax benefit, net of applicable transfer discounts, on credits generated by the eight underlying wind facilities as they are generated. See Note 15 under "Southern Power – Purchase of Renewable Facility Interests" for additional information.

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.

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

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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.

Alabama Power and Georgia Power have nuclear generating facilities that qualify for Internal Revenue Code §45U PTCs under the IRA. The §45U PTC is available for tax years 2024 to 2032 and is subject to a phase-out. Southern Company, Alabama Power, and Georgia Power each evaluates annually whether it qualifies for the credit. For the 2024 tax year, Southern Company, Alabama Power, and Georgia Power claimed a credit of $373 million, $180 million, and $193 million, respectively, on the consolidated federal tax return, which included the prevailing wage multiplier. This credit, net of the transfer discount, was recorded as a regulatory liability. In November 2025, Southern Company received a full acceptance letter from the IRS for the consolidated 2024 federal income tax return. The estimated total credit amounts for the 2025 tax year are $122 million, $50 million, and $72 million for Southern Company, Alabama Power, and Georgia Power, respectively. Due to uncertainty regarding the acceptance of this credit by the IRS, the amounts for the 2025 tax year have been fully reserved. The ultimate outcome of this matter cannot be determined at this time.

See Note 2 to the financial statements under "Alabama Power – Nuclear Production Tax Credits Order" and "Georgia Power – Rate Plans" and Note 10 to the financial statements under "Unrecognized Tax Benefits" for additional information.

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

Corporate Alternative Minimum Tax

On June 2, 2025 and September 30, 2025, the U.S. Treasury and the IRS issued guidance on the application of the CAMT. Southern Company has filed its consolidated 2024 federal income tax return and determined it was not subject to CAMT. Southern Company is still assessing the issued guidance and is not expecting to be subject to CAMT for the 2025 tax year.

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

Natural Gas Safe Harbor Method

In 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. In April 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 submitted a tax accounting method change for qualifying expenditures with the filing of its consolidated 2024 federal income tax return. The new tax method of accounting resulted in a material net positive cash flow for Southern Company Gas. This method change did 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.

Georgia State Tax Legislation

On April 15, 2025, the State of Georgia enacted tax legislation that reduced the corporate income tax rate from 5.39% to 5.19% effective for the 2025 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 in 2025.

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

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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 2025 for the applicable Registrants were as follows: 90% for Southern Company, 98% for Alabama Power, 95% for Georgia Power, 99% for Mississippi Power, and 88% 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, 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

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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 2025 by certain Registrants.

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.

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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.

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

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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, 2025.

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 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 any 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,

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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 and any goodwill is recognized as a residual over the fair values of the identifiable net assets acquired. Assets 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. See Note 7 to the financial statements under "Southern Power – Variable Interest Entities" for additional information.

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.

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FINANCIAL CONDITION AND LIQUIDITY

Overview

The financial condition of each Registrant remained stable at December 31, 2025. 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 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. For the three-year period from 2026 through 2028, 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 other sources, 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 2026. 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 2025, the market price of Southern Company's common stock was $87.20 per share (based on the closing price as reported on the NYSE) and the book value was $32.18 per share, representing a market-to-book value ratio of 271%, compared to $82.32, $30.28, and 272%, respectively, at the end of 2024.

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Cash Requirements

Capital Expenditures

Total estimated capital expenditures, including LTSA and nuclear fuel commitments, for the Registrants through 2030 based on their current construction programs are as follows:

(a)Excludes amounts related to Alabama Power's decision to convert Plant Barry Unit 5 from coal to natural gas totaling $38 million in 2026, $15 million in 2027, and $54 million in 2028. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" herein and Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" for additional information.

(b)Includes expenditures of approximately $3.1 billion, $5.5 billion, $5.1 billion, $3.2 billion, and $0.8 billion for 2026 through 2030, respectively, for construction projects and related transmission investments approved in conjunction with the 2022 IRP, the 2023 IRP Update, and the 2025 IRP. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Other Construction" for additional information.

(c)Includes amounts contingent upon approval by the Mississippi PSC related to Mississippi Power's decision to convert Plant Daniel Unit 2 from coal to natural gas totaling $28 million in 2028 and $41 million in 2029. See Note 2 to the financial statements under "Mississippi Power – Integrated Resource Plans" for additional information.

(d)Includes $40 million in 2026 related to the Millers Branch solar project and $0.7 billion and $0.4 billion in 2026 and 2027, respectively, related to wind repowering projects. Excludes approximately $0.8 billion per year for 2026 through 2029 and $0.7 billion for 2030 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 wind repowering projects.

(e)Includes gas pipeline investment of approximately $0.3 billion, $0.8 billion, $0.5 billion, and $0.1 billion for 2026 through 2029, respectively. See FUTURE EARNINGS POTENTIAL – "Construction Programs" herein for information regarding this project.

Total estimated capital expenditures, primarily at the traditional electric operating companies, increased significantly since 2023, from $45.2 billion previously estimated for 2024 through 2028 to $78.1 billion currently estimated for 2026 through 2030. The traditional electric operating companies project a significant increase in demand for electricity sales, largely driven by data centers and other large load customers. Serving the projected increased load demand from these new customers while continuing to serve existing customers safely, reliably, and affordably requires investing in generation, transmission, and distribution systems and pricing sales to these new customers such that the related incremental costs are met with adequate incremental revenues from these new customers. Through the 2022 IRP and the 2023 IRP Update, the Georgia PSC has certified resources totaling approximately 13 GWs, approximately nine GWs of which are new generation and battery energy storage facilities that are being, or are expected to be, constructed by Georgia Power. The certified costs of these Georgia Power projects total $19.5 billion, and these projects are projected to be placed in service through 2030. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Other Construction" for additional information.

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, 2025, 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 state and federal CCR 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 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 2030 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

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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; changes in technology; 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, 2025, 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, 2025 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, 2025. As discussed under "Capital Expenditures" herein, estimated expenditures for nuclear fuel are included in the applicable Registrants' construction programs for the years 2026 through 2030. Nuclear fuel commitments at December 31, 2025 that extend beyond 2030 are 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."

In connection with Georgia Power's 2022 IRP, the Georgia PSC certified two affiliate PPAs with Southern Power, which are expected to be accounted for as leases and are contingent upon approval by the FERC. The expected capacity payments associated

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with the PPAs total $61 million in 2030 and $2.6 billion thereafter. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans – Certification Requests" for additional information.

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 2026 through 2030. Total estimated payments for LTSA commitments at December 31, 2025 that extend beyond 2030 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, 2025 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, 2025 and valued at $151 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, 2025 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.

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 other sources, 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 2026, 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

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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, 2025, the amount of subsidiary retained earnings restricted to dividend totaled $1.8 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, 2025. The following table shows the amount by which current liabilities exceeded current assets at December 31, 2025 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.

Bank Credit Arrangements

At December 31, 2025, unused committed credit arrangements with banks were as follows:

(a)Includes $15 million at Alabama Property Company, a wholly-owned subsidiary of Alabama Power. Alabama Power is not party to this arrangement.

(b)Georgia Power had $26 million of letters of credit outstanding under an uncommitted letter of credit facility at December 31, 2025.

(c)At December 31, 2025, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $21 million was unused. In addition, Southern Power Company has $23 million of letters of credit outstanding under an uncommitted letter of credit facility at December 31, 2025. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.

(d)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, 2025, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $1.5 billion (comprised of approximately $796 million at Alabama Power, $667 million at Georgia

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Power, and $58 million at Mississippi Power). In addition, at December 31, 2025, Alabama Power and Georgia Power had approximately $280 million and $384 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. Alabama Power's $280 million of fixed rate revenue bonds are classified as securities due within one year on its balance 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:

(*)Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2025, 2024, and 2023.

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Analysis of Cash Flows

Net cash flows provided from (used for) operating, investing, and financing activities in 2025 and 2024 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 $14 million in 2025 as compared to 2024 primarily due to higher net income after non-cash adjustments and the timing of storm restoration cost recovery at Georgia Power and customer receivable collections, largely offset by the timing of vendor payments, decreased retail fuel cost recovery, and the timing of tax payments. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information.

The net cash used for investing activities in 2025 and 2024 was primarily related to the Subsidiary Registrants' construction programs.

The net cash provided from financing activities in 2025 was primarily related to net issuances of long-term debt and issuances of common stock through the settlement of forward sale contracts, partially offset by common stock dividend payments, a reduction in commercial paper borrowings, and Southern Power's purchase of membership interests in SP Wind. 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. See Notes 8 and 15 to the financial statements under "Equity Distribution Agreement" and "Southern Power – Purchase of Renewable Facility Interests," respectively, for additional information.

Alabama Power

Net cash provided from operating activities decreased $323 million in 2025 as compared to 2024 primarily due to a decrease in fuel cost recovery and customer refunds associated with the nuclear fuel disposal cost award, partially offset by the monetization of §45U PTCs. See Notes 2 and 3 to the financial statements under "Alabama Power – Nuclear Production Tax Credits Order" and "Nuclear Fuel Disposal Costs," respectively, for additional information.

The net cash used for investing activities in 2025 and 2024 was primarily related to gross property additions and, for 2025, the acquisition of the Lindsay Hill Generating Station. See Note 15 to the financial statements under "Alabama Power" for additional information.

The net cash provided from financing activities in 2025 was primarily related to net issuances of senior notes and capital contributions from Southern Company, partially offset by common stock dividend payments. 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.

Georgia Power

Net cash provided from operating activities increased $15 million in 2025 as compared to 2024 primarily due to the timing of storm restoration cost recovery and customer receivable collections and an increase in retail revenues associated with base tariff increases, largely offset by the timing of vendor payments and higher income tax payments. See Note 2 to the financial statements under "Georgia Power – Storm Damage Recovery" for additional information relating to storm restoration costs.

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The net cash used for investing activities in 2025 and 2024 was primarily related to gross property additions including costs associated with projects approved through the 2023 IRP Update and the certification requests in September and December 2025. See Note 2 to the financial statements under "Georgia Power – Integrated Resource Plans" and " – Other Construction" for information regarding Georgia Power's current construction projects.

The net cash provided from financing activities in 2025 was primarily related to capital contributions from Southern Company and net issuances of senior notes, partially offset by common stock dividend payments. 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.

Mississippi Power

Net cash provided from operating activities increased $8 million in 2025 as compared to 2024 primarily due to funds received as part of the Plant Daniel acquisition, lower income tax payments, and the timing of fossil fuel stock purchases, largely offset by decreased fuel cost recovery. See Note 2 to the financial statements under "Mississippi Power – Plant Daniel" for additional information.

The net cash used for investing activities in 2025 and 2024 was primarily related to gross property additions.

The net cash used for financing activities in 2025 was primarily related to common stock dividend payments and a reduction in commercial paper borrowings, partially offset by issuances of senior notes and capital contributions from Southern Company. 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.

Southern Power

Net cash provided from operating activities decreased $38 million in 2025 as compared to 2024 primarily due to a change in the utilization of federal tax credit carryforwards, partially offset by the timing of customer receivable collections.

The net cash used for investing activities in 2025 and 2024 was primarily related to ongoing construction activities. See Note 15 to the financial statements under "Southern Power" for additional information.

The net cash provided from financing activities in 2025 was primarily related to capital contributions from Southern Company, net issuances of senior notes, and an increase in commercial paper borrowings, partially offset by the purchase of membership interests from noncontrolling interests, common stock dividend payments, and net distributions to noncontrolling interests. 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.

Southern Company Gas

Net cash provided from operating activities increased $65 million in 2025 as compared to 2024 primarily due to changes in recovery on certain regulatory clauses, due to weather impacts and timing, and timing of payments for natural gas as a result of higher volume and prices, as well as timing of other vendor payments, partially offset by timing of customer receivable collections as a result of weather impacts, higher natural gas prices, and increased base rates in 2025, as well as timing of income tax payments.

The net cash used for investing activities in 2025 and 2024 was primarily related to construction of transmission and distribution assets recovered through base rates.

The net cash provided from financing activities in 2025 was primarily related to net issuances of senior notes and first mortgage bonds, partially offset by common stock dividend payments. 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.

Significant Balance Sheet Changes

Southern Company

Significant balance sheet changes in 2025 for Southern Company included:

•an increase of $9.7 billion in total property, plant, and equipment primarily related to the Subsidiary Registrants' construction programs;

•an increase of $8.4 billion in long-term debt (including securities due within one year) related to issuances of senior notes and junior subordinated notes, partially offset by repayment of senior notes;

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•an increase of $2.8 billion in total common stockholders' equity primarily related to net income and issuances of common stock largely through the settlement of forward sale contracts, partially offset by common stock dividend payments;

•a decrease of $630 million in under recovered fuel clause revenues primarily due to increased fuel cost recovery at Georgia Power;

•a decrease of $616 million in notes payable due to a reduction in commercial paper borrowings and repayment of short-term bank debt;

•a decrease of $615 million in noncontrolling interests primarily related to Southern Power's purchase of membership interests in SP Wind, net distributions to noncontrolling interests, and net loss attributable to noncontrolling interests;

•an increase of $583 million in prepaid pension costs primarily related to actual returns on plan assets, partially offset by actuarial losses resulting from decreases in the assumed discount rates;

•an increase of $569 million in cash and cash equivalents, as reflected in the statements of cash flows and discussed further under "Analysis of Cash Flow – Southern Company" herein; and

•an increase of $403 million in accumulated deferred income taxes primarily related to an increase in property-related timing differences and federal tax credit carryforwards.

See "Financing Activities" herein and Notes 2, 5, 7, 8, 10, 11, and 15 to the financial statements for additional information.

Alabama Power

Significant balance sheet changes in 2025 for Alabama Power included:

•an increase of $1.3 billion in total property, plant, and equipment primarily related to the construction of transmission and distribution facilities and the acquisition of the Lindsay Hill Generating Station;

•an increase of $906 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 $859 million in long-term debt (including securities due within one year) primarily due to net issuances of senior notes; and

•decreases of $379 million and $262 million in AROs and regulatory assets associated with AROs, respectively, primarily related to settlements and cost estimate updates.

See "Financing Activities – Alabama Power" herein and Notes 5, 6, 8, and 15 to the financial statements for additional information.

Georgia Power

Significant balance sheet changes in 2025 for Georgia Power included:

•an increase of $6.8 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities, including costs associated with projects approved through the 2023 IRP Update and the certification requests in September and December 2025;

•an increase of $3.4 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;

•an increase of $3.1 billion in long-term debt (including securities due within one year) primarily due to net issuances of senior notes;

•a decrease of $644 million 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; and

•an increase of $426 million in accumulated deferred income taxes primarily related to an increase in property-related timing differences.

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

Mississippi Power

Significant balance sheet changes in 2025 for Mississippi Power included:

•an increase of $171 million in total property, plant, and equipment primarily related to the construction of transmission and distribution facilities;

•an increase of $100 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;

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•an increase of $93 million in long-term debt (including securities due within one year) primarily due to issuances of senior notes;

•a decrease of $55 million in other cost of removal obligations primarily due to an increase in expenditures related to transmission and other production assets; and

•an increase of $41 million in other deferred credits and liabilities primarily due to contributions in aid of construction.

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 2025 for Southern Power included:

•an increase of $260 million in long-term debt (including securities due within one year) primarily due to net issuances of senior notes;

•an increase of $162 million in total property, plant, and equipment in service primarily due to an increase in CWIP primarily related to the continued construction of the Millers Branch solar facility and the wind repowering projects, partially offset by the continued depreciation of assets;

•a decrease of $161 million in total stockholders' equity primarily due to the purchase of membership interests from noncontrolling interests, dividends paid to Southern Company, net distributions to noncontrolling interests, and net loss, partially offset by capital contributions from Southern Company;

•an increase of $138 million in notes payable due to an increase in commercial paper borrowings; and

•a decrease of $133 million in accumulated deferred income taxes primarily related to a change in the utilization of ITCs.

See "Financing Activities – Southern Power" and Notes 5, 8, 10, and 15 to the financial statements for additional information.

Southern Company Gas

Significant balance sheet changes in 2025 for Southern Company Gas included:

•an increase of $1.2 billion in total property, plant, and equipment primarily related to the construction of transmission and distribution assets;

•an increase of $743 million in long-term debt (including securities due within one year) due to net issuances of senior notes and first mortgage bonds;

•an increase of $200 million in total accounts receivable primarily related to higher customer billings driven by colder weather, higher natural gas prices, and increased base rates;

•an increase of $175 million in accumulated deferred income taxes primarily due to reversal of CAMT and additional property-related timing differences;

•an increase of $131 million in common stockholder's equity primarily related to net income, partially offset by dividends paid to Southern Company; and

•an increase of $111 million in total accounts payable primarily related to higher natural gas volumes and prices and the timing of vendor payments.

See "Financing Activities – Southern Company Gas" and FUTURE EARNINGS POTENTIAL – "Income Tax Matters" 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, 2025:

(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 $10 million of its $100 million principal amount long-term bank loan due November 15, 2026, 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 2025, Southern Company issued approximately 22.5 million shares of common stock primarily through forward sale contract settlements and dividend reinvestment and employee equity compensation and savings plans. Proceeds from settlements of the forward sale contracts totaled approximately $1.5 billion. Also during 2025, Southern Company entered into additional forward sale contracts for the issuance of shares of common stock that may be settled through June 2027. See Note 8 to the financial statements under "Equity Distribution Agreement" for additional information.

In addition, in November 2025, Southern Company issued 40 million 2025 Series A Equity Units (2025 Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total stated amount of $2 billion. Net proceeds from the issuance were $1.965 billion. Each Corporate Unit is comprised of (i) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than December 15, 2028, a certain number of shares of Southern Company's common stock for $50 in cash, (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2025B Remarketable Senior Notes due 2030, and (iii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2025C Remarketable Senior Notes due 2033. See Note 8 to the financial statements under "Equity Units" for additional information.

In January 2025, Southern Company issued $565 million aggregate principal amount of Series 2025A 6.50% Junior Subordinated Notes due March 15, 2085.

In February 2025, Southern Company issued $1.8 billion aggregate principal amount of Series 2025B 6.375% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due March 15, 2055.

In May 2025, Southern Company issued $1.65 billion aggregate principal amount of Series 2025A 3.25% Convertible Senior Notes due June 15, 2028 in a private offering. Southern Company used a portion of the proceeds from this issuance to repurchase approximately $781.6 million of the $1.725 billion aggregate principal amount outstanding of its Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes) and approximately $328.1 million of the $1.5 billion aggregate principal amount outstanding of its Series 2024A 4.50% Convertible Senior Notes due June 15, 2027

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(Series 2024A Convertible Senior Notes). See Note 8 to the financial statements under "Convertible Senior Notes" herein for additional information.

In October 2025, Southern Company repaid at maturity $500 million aggregate principal amount of its Series 2022A 5.15% Senior Notes.

In November 2025, Southern Company used a portion of the net proceeds from the 2025 Equity Units to repurchase (i) an additional approximately $674.4 million of the remaining approximately $943.4 million aggregate principal amount outstanding of its Series 2023A Convertible Senior Notes and (ii) an additional approximately $342.0 million of the remaining approximately $1.172 billion aggregate principal amount outstanding of its Series 2024A Convertible Senior Notes. See Note 8 to the financial statements under "Equity Units" for additional information.

In December 2025, Southern Company settled at maturity the remaining approximately $269.1 million outstanding of its Series 2023A Convertible Senior Notes. See Note 8 to the financial statements under "Convertible Senior Notes" for additional information.

Subsequent to December 31, 2025, Southern Company redeemed all $1.25 billion aggregate principal amount of its Series 2020B 4.00% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due January 15, 2051.

Alabama Power

During 2025, a subsidiary of Alabama Power borrowed an additional approximately $5 million under a $20 million fixed rate bank loan entered into in December 2023 with a maturity date of December 31, 2030. The aggregate amount outstanding under this loan at December 31, 2025 was approximately $20 million.

In March 2025, Alabama Power issued $500 million aggregate principal amount of Series 2025A 5.10% Senior Notes due April 2, 2035.

In April 2025, Alabama Power repaid at maturity $250 million aggregate principal amount of its Series 2015B 2.80% Senior Notes.

In June 2025, Alabama Power issued $100 million aggregate principal amount of Series 2025B Floating Rate Senior Notes due August 15, 2075.

In July 2025, a subsidiary of Alabama Power repaid $1 million under a $15 million credit line entered into in December 2024 with a maturity date of December 11, 2026.

In September 2025, Alabama Power issued $500 million aggregate principal amount of Series 2025C 4.30% Senior Notes due March 15, 2031.

Georgia Power

In March 2025, Georgia Power issued $400 million aggregate principal amount of Series 2025A Floating Rate Senior Notes due September 15, 2026, $500 million aggregate principal amount of Series 2025B 4.85% Senior Notes due March 15, 2031, and $700 million aggregate principal amount of Series 2025C 5.20% Senior Notes due March 15, 2035.

In May 2025, Georgia Power repaid at maturity $700 million aggregate principal amount of its Series 2023C Floating Rate Senior Notes.

Also in May 2025, Georgia Power entered into a $200 million short-term floating rate bank loan bearing interest based on term SOFR.

In June 2025, Georgia Power extended both of its short-term floating rate bank loans totaling $400 million to long-term term loans, which mature in June 2026.

In July 2025, Georgia Power repaid at maturity its obligations with respect to $45 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 1995.

In September 2025, Georgia Power issued $250 million aggregate principal amount of additional Series 2025B 4.85% Senior Notes due March 15, 2031, $750 million aggregate principal amount of Series 2025D 4.00% Senior Notes due October 1, 2028, and $500 million aggregate principal amount of Series 2025E 5.50% Senior Notes due October 1, 2055.

Mississippi Power

In March 2025, Mississippi Power issued $50 million aggregate principal amount of Series 2025A 5.01% Senior Notes due March 15, 2030 and $50 million aggregate principal amount of Series 2025B 6.03% Senior Notes due March 15, 2055.

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In July 2025, Mississippi Power repaid at maturity its obligations with respect to approximately $11 million aggregate principal amount of Mississippi Business Finance Corporation Solid Waste Disposal Facilities Revenue Bonds, Series 1995 (Mississippi Power Company Project).

Southern Power

In September 2025, Southern Power issued $550 million aggregate principal amount of Series 2025A 4.25% Senior Notes due October 1, 2030 and $550 million aggregate principal amount of Series 2025B 4.90% Senior Notes due October 1, 2035.

In October 2025, Southern Power redeemed all $500 million aggregate principal amount of its Series 2015C 4.15% Senior Notes due December 1, 2025.

In December 2025, Southern Power redeemed all $400 million aggregate principal amount of its Series 2021A 0.90% Senior Notes due January 15, 2026.

Southern Company Gas

In August 2025, Nicor Gas repaid at maturity $50 million aggregate principal amount of its 1.42% Series First Mortgage Bonds.

In September 2025, Southern Company Gas Capital issued $425 million aggregate principal amount of Series 2025A 4.05% Senior Notes due September 15, 2028 and $425 million aggregate principal amount of Series 2025B 5.10% Senior Notes due September 15, 2035, both guaranteed by Southern Company Gas.

In October 2025, Nicor Gas issued in a private placement $25 million aggregate principal amount of 4.17% Series First Mortgage Bonds due October 1, 2028 and $75 million aggregate principal amount of 4.92% Series First Mortgage Bonds due October 1, 2035. In December 2025, pursuant to the same agreement, Nicor Gas issued in a private placement $50 million aggregate principal amount of 5.59% Series First Mortgage Bonds due December 15, 2055 and $50 million aggregate principal amount of 5.69% Series First Mortgage Bonds due December 15, 2065.

In November 2025, Southern Company Gas Capital repaid at maturity $250 million aggregate principal amount of its 3.875% Senior Notes.

Credit Rating Risk

At December 31, 2025, 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.

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 equipment purchases related to construction of facilities.

The maximum potential collateral requirements under these contracts at December 31, 2025 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, 2025.

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

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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 August 22, 2025, Fitch revised the ratings outlook of Georgia Power to stable from positive.

On September 23, 2025, Moody's revised the ratings outlook of Southern Company to negative from stable and the ratings outlook of Georgia Power to stable from positive.

Market Price Risk

The Registrants had no material change in market risk exposure for the year ended December 31, 2025 when compared to the year ended December 31, 2024. 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 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, 2025 for the applicable Registrants:

(*)Includes $2.0 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, 2025 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.

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Changes in fair value of energy-related derivative contracts for Southern Company and Southern Company Gas for the years ended December 31, 2025 and 2024 are provided in the table below. At December 31, 2025 and 2024, 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 $33 million, $17 million, and $62 million at December 31, 2025, 2024, and 2023, 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.

The net hedge volumes of energy-related derivative contracts for natural gas purchased at December 31, 2025 and 2024 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 72 million mmBtu and short natural gas positions of 9 million mmBtu at December 31, 2025 and the net of long natural gas positions of 90 million mmBtu and short natural gas positions of 7 million mmBtu at December 31, 2024.

For the Southern Company system, the weighted average swap contract cost per mmBtu was approximately $0.11 per mmBtu below market prices at December 31, 2025 and was approximately $0.15 per mmBtu below market prices at December 31, 2024. 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

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measurements. The maturities of the energy-related derivative contracts for Southern Company and Southern Company Gas at December 31, 2025 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 $33 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 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. The traditional electric operating companies and Southern Power have received collateral or acceptable substitute guarantees as financial security from counterparties to contracts for certain data centers and other large load customers as described in FUTURE EARNINGS POTENTIAL – "General" herein and PPAs as described in FUTURE EARNINGS POTENTIAL – "Southern Power's Power Sales Agreements" herein. 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 2025, the four largest Marketers based on customer count, which includes SouthStar, accounted for 19% of Southern Company Gas' operating revenues and 22% 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.

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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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