ALABAMA POWER CO

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

II-35 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,

II-36 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

II-38 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 CO 2 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.

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.

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

II-44 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

II-45 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.