REGULATORY MATTERS

12 Months Ended

Dec. 31, 2025

Regulated Operations [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

Regulatory Assets and Liabilities

Details of regulatory assets and (liabilities) reflected in the balance sheets at December 31, 2025 and 2024 are provided in the following tables:

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At December 31, 2025
AROs(*)	$	5,482	$	1,644	$	3,604	$	234	$	—
Retiree benefit plans(*)	2,442		630		836		128		31
Remaining net book value of retired assets	1,052		408		631		13		—
Deferred income tax charges	962		261		675		25		—
Storm damage	941		—		912		29		—
Deferred depreciation	784		428		356		—		—
Under recovered regulatory clause revenues	284		232		—		24		28
Software and cloud computing costs	248		92		146		7		3
Environmental remediation(*)	242		—		13		—		229
Vacation pay(*)	242		90		124		12		16
Loss on reacquired debt	203		30		169		4		—
Nuclear outage	106		59		47		—		—
Regulatory clauses	83		52		—		—		31
Qualifying repairs of natural gas distribution systems	65		—		—		—		65
Fuel-hedging (realized and unrealized) losses	50		18		18		14		—
Long-term debt fair value adjustment	44		—		—		—		44
Plant Daniel Units 3 and 4	21		—		—		21		—
Other regulatory assets	225		65		30		40		90
Deferred income tax credits	(4,725)		(1,585)		(2,238)		(211)		(681)
Other cost of removal obligations	(1,022)		15		999		(115)		(1,921)
Reliability reserves	(243)		(184)		—		(59)		—
Over recovered regulatory clause revenues	(213)		—		(31)		—		(182)
Storm/property damage reserves	(118)		(60)		—		(58)		—
Plant Daniel Units 1 and 2 acquisition	(34)		—		—		(34)		—
Other regulatory liabilities	(234)		(17)		(16)		(3)		(61)
Total regulatory assets (liabilities), net	$	6,887	$	2,178	$	6,275	$	71	$	(2,308)

	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Company Gas
	(in millions)
At December 31, 2024
AROs(*)	$	5,810	$	1,906	$	3,658	$	248	$	—
Retiree benefit plans(*)	2,605		680		892		134		44
Remaining net book value of retired assets	1,198		454		729		15		—
Deferred income tax charges	927		264		634		27		—
Storm damage	859		—		827		32		—
Deferred depreciation	535		286		249		—		—
Environmental remediation(*)	249		—		16		—		233
Vacation pay(*)	224		85		112		12		15
Loss on reacquired debt	219		32		183		4		—
Software and cloud computing costs	200		76		116		4		4
Under recovered regulatory clause revenues	167		119		—		17		31
Regulatory clauses	162		82		—		—		80
Nuclear outage	92		39		53		—		—
Fuel-hedging (realized and unrealized losses)	69		23		29		17		—
Qualifying repairs of natural gas distribution systems	53		—		—		—		53
Long-term debt fair value adjustment	52		—		—		—		52
Plant Daniel Units 3 and 4	23		—		—		23		—
Other regulatory assets	184		42		40		30		72
Deferred income tax credits	(4,536)		(1,398)		(2,149)		(219)		(755)
Other cost of removal obligations	(1,176)		24		816		(170)		(1,846)
Over recovered regulatory clause revenues	(285)		(29)		(52)		—		(204)
Reliability reserves	(188)		(131)		—		(57)		—
Storm/property damage reserves	(122)		(70)		—		(52)		—
Nuclear fuel disposal cost recovery	(100)		(100)		—		—		—
Other regulatory liabilities	(180)		(28)		(14)		(6)		(31)
Total regulatory assets (liabilities), net	$	7,041	$	2,356	$	6,139	$	59	$	(2,252)

(*)Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability.

Unless otherwise noted, the following recovery and amortization periods for these regulatory assets and (liabilities) have been approved by the respective state PSC or regulatory agency:

AROs and other cost of removal obligations – Generally recorded over the related property lives, which may range up to 64 years for Alabama Power, 58 years for Georgia Power, 75 years for Mississippi Power, and 85 years for Southern Company Gas. AROs and other cost of removal obligations are settled and trued up following completion of the related activities. Alabama Power is recovering CCR ARO expenditures over a 38-year period ending in 2054 through Rate CNP Compliance. Georgia Power is recovering CCR ARO expenditures over four-year periods through its ECCR tariff. Mississippi Power is recovering CCR ARO expenditures over a 10-year period ending in 2034 through its ECO Plan. See "Georgia Power – Rate Plans" herein and Note 6 for additional information.

Retiree benefit plans – Recovered and amortized over the average remaining service period, which may range up to 14 years for Alabama Power, Georgia Power, and Mississippi Power and 15 years for Southern Company Gas. Southern Company's balances also include amounts at SCS and Southern Nuclear that are allocated to the applicable regulated utilities. See Note 11 for additional information.

Remaining net book value of retired assets –

Alabama Power: Primarily represents the net book value of Plant Gorgas Unit 10 ($387 million at December 31, 2025) being amortized over a remaining period of 12 years (through 2037) and Plant Barry Unit 4 ($32 million at December 31, 2025) being amortized over a remaining period of nine years (through 2034). See "Alabama Power – Environmental Accounting Order" herein for additional information.

Georgia Power: Net book values of Plant Wansley Units 1 and 2 and Plant Hammond Unit 4 (totaling $348 million and $271 million, respectively, at December 31, 2025) are being amortized over a remaining period of 13 years (through 2038) pursuant to the extension of the 2022 ARP. Balance also includes unusable materials and supplies inventories, for which the Georgia PSC will determine a recovery period in a future base rate case. See "Georgia Power – Rate Plans" herein additional information.

Mississippi Power: Represents net book value of certain environmental compliance assets at Plant Watson and Plant Greene County. The retail portion is being amortized over a remaining period of eight years (through 2033), and the wholesale portion is being amortized over a remaining period of nine years (through 2034). See "Mississippi Power – Environmental Compliance Overview Plan" herein for additional information.

Deferred income tax charges and credits – Charges are recovered and credits are primarily amortized over the related property lives, which may range up to 64 years for Alabama Power, 58 years for Georgia Power, 75 years for Mississippi Power, and 85 years for Southern Company Gas. See Note 10 for additional information. These accounts include certain deferred income tax assets and liabilities not subject to normalization, as described further below:

Alabama Power: Related amounts at December 31, 2025 include certain tax credits which will be returned to customers in a manner determined by the Alabama PSC, as discussed under "Alabama Power – Nuclear Production Tax Credits Order" herein. Related amounts at December 31, 2024 include excess federal deferred income tax liabilities that were returned for the benefit of customers in 2025, as discussed under "Alabama Power – Excess Accumulated Deferred Income Tax Accounting Order" herein.

Georgia Power: For deferred income tax charges, related amounts include deferred income tax assets related to construction costs for Plant Vogtle Units 3 and 4 ($120 million at December 31, 2025) being recovered over a remaining period of nine years (through 2034). For deferred income tax credits, related amounts at December 31, 2025 include $255 million of deferred income tax benefits for certain tax credits and $39 million of excess state deferred income tax liabilities, which are both expected to be amortized over a period of up to three years (through 2028), and related amounts at December 31, 2024 include $102 million of excess state deferred income tax liabilities that were returned to customers in 2025. See "Georgia Power – Rate Plans" and " – Nuclear Construction – Regulatory Matters" herein for additional information.

Mississippi Power: Related amounts at December 31, 2025 include retail excess federal deferred income tax liabilities of $21 million resulting from the Tax Reform Legislation, the flowback of which will be determined by the Mississippi PSC in a future rate proceeding. See "Mississippi Power – Excess Accumulated Deferred Income Tax Accounting Order" herein for additional information.

Southern Company Gas: Related amounts include deferred income tax liabilities ($26 million at December 31, 2025) being amortized over periods generally not exceeding five years, primarily related to excess state deferred income tax liabilities. See "Southern Company Gas – Rate Proceedings" herein for additional information.

Storm damage – See "Georgia Power – Storm Damage Recovery" herein for additional information. Mississippi Power's balance represents deferred storm costs associated with Hurricanes Ida and Zeta being recovered through PEP over a remaining period of nine years (through 2034).

Deferred depreciation –

Alabama Power: Represents deferred depreciation for Plant Barry Unit 5 ($170 million at December 31, 2025) and Plant Barry common coal assets ($73 million at December 31, 2025) to be amortized until 2036 beginning when Alabama Power utilizes updated deprecation rates which is anticipated to be January 1, 2028 and Plant Gaston Unit 5 coal assets ($185 million at December 31, 2025) to be amortized until 2039 beginning when the assets are retired.

Georgia Power: Represents deferred depreciation for Plant Scherer Units 1 through 3 and Plant Bowen Units 1 and 2 (totaling $209 million and $121 million, respectively, at December 31, 2025) to be amortized over 13 years beginning January 1, 2026 (through 2038), both pursuant to the extension of the 2022 ARP, and Plant Vogtle Unit 3 and common facilities ($26 million at December 31, 2025) being amortized over a remaining period of nine years (through 2034). See "Georgia Power – Rate Plans" herein additional information.

Under and over recovered regulatory clause revenues –

Alabama Power: Balances are recorded monthly and expected to be recovered over periods of up to five years. See "Alabama Power – Rate CNP PPA," " – Rate CNP Compliance," and " – Rate ECR" herein for additional information.

Georgia Power: Related to Demand-Side Management (DSM) tariffs. Balances are recorded monthly. Pursuant to the extension of the 2022 ARP, the Georgia PSC will determine a recovery period in a future base rate case. See "Georgia Power – Rate Plans" herein for additional information.

Mississippi Power: At December 31, 2025, $11 million is expected to be recovered through various rate recovery mechanisms over a period to be determined in future rate filings. See "Mississippi Power – Ad Valorem Tax Adjustment" herein for additional information.

Southern Company Gas: Balances are recorded and recovered or amortized over periods generally not exceeding five years. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities have various other cost recovery mechanisms for the recovery of costs, including those related to infrastructure replacement programs.

Software and cloud computing costs – Represents certain deferred operations and maintenance costs associated with software and cloud computing projects. For Alabama Power, costs are amortized ratably over the life of the related software, which ranges up to 10 years (through 2035). For Georgia Power, costs incurred through 2022 are being amortized over five years (through 2027), and the recovery period for costs incurred after 2022 will be determined in its next base rate case. For Mississippi Power, the recovery period will be determined in Mississippi Power's annual PEP filing process following the completion of the projects and is expected to begin no earlier than 2027. For Southern Company Gas, costs are being amortized ratably over the life of the related software, which ranges up to 10 years (through 2035).

Environmental remediation – Effective January 1, 2023, Georgia Power is recovering $5 million annually for environmental remediation under the 2022 ARP. Southern Company Gas' costs are recovered through environmental cost recovery mechanisms when the remediation work is performed. See Note 3 under "Environmental Remediation" for additional information.

Vacation pay – Recorded as earned by employees and recovered as paid, generally within one year. Includes both vacation and banked holiday pay, if applicable.

Loss on reacquired debt – Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue. At December 31, 2025, the remaining amortization periods do not exceed 22 years for Alabama Power, 27 years for Georgia Power, 16 years for Mississippi Power, and two years for Southern Company Gas.

Nuclear outage – Costs are deferred to a regulatory asset when incurred and amortized over a subsequent period of 18 months for Alabama Power and up to 24 months for Georgia Power. See Note 5 for additional information.

Regulatory clauses –

Alabama Power: Effective January 1, 2023, balance is being amortized through Rate RSE over a five-year period ending in 2027.

Southern Company Gas: Represents amounts related to Nicor Gas' volume balancing adjustment rider expected to be recovered over a period of less than two years.

Qualifying repairs of natural gas distribution systems – Represents deferred costs of certain repairs at Atlanta Gas Light being amortized over 20 years.

Fuel-hedging (realized and unrealized) losses and gains – Assets and liabilities are recorded over the life of the underlying hedged purchase contracts. Upon final settlement, actual costs incurred are recovered through the applicable traditional electric operating company's fuel cost recovery mechanism. Purchase contracts generally do not exceed three and a half years for Alabama Power, three years for Georgia Power, and five years for Mississippi Power. Immaterial amounts for fuel-hedging gains at December 31, 2025 and 2024 are included in other regulatory liabilities. See Note 14 for additional information.

Long-term debt fair value adjustment – Recovered over the remaining lives of the original debt issuances at acquisition, which range up to 13 years at December 31, 2025.

Plant Daniel Units 3 and 4 – Represents the difference between Mississippi Power's revenue requirement for Plant Daniel Units 3 and 4 under purchase accounting and operating lease accounting. At December 31, 2025, consists of the $15 million retail portion being amortized through 2046 over the remaining life of the related property and the $7 million wholesale portion being amortized over 10 years (through 2034).

Other regulatory assets – Comprised of numerous immaterial components with remaining amortization periods at December 31, 2025 generally not exceeding 18 years for Alabama Power, nine years for Georgia Power, 10 years for Mississippi Power, and 15 years for Southern Company Gas.

Reliability reserves and storm/property damage reserves – Utilized as related expenses are incurred. See "Alabama Power – Rate NDR" and " – Reliability Reserve Accounting Order," "Georgia Power – Storm Damage Recovery," and "Mississippi Power – System Restoration Rider" and " – Reliability Reserve Accounting Order" herein for additional information.

Plant Daniel Units 1 and 2 acquisition – Represents the incremental cost to Mississippi Power to acquire FP&L's 50% ownership interest in Plant Daniel Units 1 and 2. Utilized as related expenses are incurred. See "Mississippi Power – Plant Daniel" herein for additional information.

Nuclear fuel disposal cost recovery – At December 31, 2024, represents award resulting from litigation related to nuclear fuel disposal costs, of which $93 million was returned to customers through bill credits during the months of January, February, and March 2025 and the remaining $7 million was applied to the NDR balance. See "Alabama Power – Rate NDR" herein and Note 3 under "Nuclear Fuel Disposal Costs" for additional information.

Other regulatory liabilities – Comprised of numerous immaterial components with remaining amortization periods at December 31, 2025 generally not exceeding one year for Alabama Power, three years for Georgia Power, one year for Mississippi Power, and 20 years for Southern Company Gas.

Alabama Power

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power.

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. The related impacts are described under "Rate RSE," "Rate CNP New Plant," "Rate CNP PPA," "Rate CNP Compliance," "Rate ECR," "Rate NDR," and "Nuclear Production Tax Credits Order" herein. 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.

Renewable Generation Certificate

Through the issuance of a Renewable Generation Certificate (RGC), Alabama Power is authorized by the Alabama PSC to procure renewable capacity and energy and to market the related energy and environmental attributes to customers and other third parties. Under the original RGC, Alabama was authorized to procure up to 500 MWs of renewable capacity and energy. In 2023, the Alabama PSC issued an order approving modifications to Alabama Power's RGC. The modifications authorized Alabama Power to procure an additional 2,400 MWs of renewable capacity and energy by June 14, 2029 and to market the related energy and environmental attributes to customers and other third parties. The modifications also increased the size of allowable renewable projects from 80 MWs to 200 MWs and increased the annual approval limit from 160 MWs to 400 MWs. Through December 31, 2025, Alabama Power has procured solar capacity totaling approximately 670 MWs under the RGC.

Rate RSE

The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted common equity return (WCER) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. When the projected WCER is under the allowed range, there is an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCER adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.

At December 31, 2025 and 2024, Alabama Power's equity ratio was approximately 53.7% and 53.9%, respectively.

Generally, during a year without a Rate RSE upward adjustment, if Alabama Power's actual WCER is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%. During a year with a Rate RSE upward adjustment, if Alabama Power's actual WCER exceeds 6.15%, customers receive 50% of the amount between 6.15% and 6.90% and all amounts in excess of an actual WCER of 6.90%. Alabama Power's ability to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range positions Alabama Power to address the

pressure on its credit quality, without increasing retail rates under Rate RSE in the near term. There is no provision for additional customer billings should the actual retail return fall below the WCER range.

Retail rates under Rate RSE did not change for 2024 and increased by 4.87%, or $325 million annually, effective with the billing month of January 2025.

For the years ended December 31, 2023, 2024, and 2025, Alabama Power's WCER exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $15 million, $12 million, and $57 million, respectively, for Rate RSE refunds. The $15 million and $12 million regulatory liability at December 31, 2023 and 2024, respectively, was refunded to customers through bill credits in April 2024 and May 2025, respectively. The December 5th Consent Order required Alabama Power to subsequently apply the $57 million regulatory liability to the NDR on December 31, 2025.

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. In addition, pursuant to the December 5th Consent Order, Alabama Power agreed to implement a moratorium on any upward rate adjustments under Rate RSE for 2027.

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 accounts 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 was 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.

Excess Accumulated Deferred Income Tax Accounting Order

In 2022, the Alabama PSC directed Alabama Power to accelerate the amortization of a regulatory liability associated with excess federal accumulated deferred income taxes. Under this order, in 2023, approximately $304 million was returned to customers through bill credits to offset the impact of a January 2023 rate increase under Rate CNP Depreciation.

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

Rate CNP New Plant

Rate CNP New Plant allows for recovery of Alabama Power's retail costs associated with newly developed or acquired certificated generating facilities placed into retail service.

In 2020, the Alabama PSC approved a CCN authorizing Alabama Power to complete the acquisition of the Central Alabama Generating Station, which occurred in August 2020. Through May 2023, Alabama Power recovered substantially all costs associated with the Central Alabama Generating Station through Rate RSE, offset by revenues from a power sales agreement. Beginning in July 2022, fuel costs associated with Central Alabama Generating Station are being recovered through Rate ECR. In March 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover costs associated with the acquisition of the Central Alabama Generating Station. The filing reflected an annual increase in retail revenues of $78 million, or 1.1%, effective with June 2023 billings. On May 24, 2023, the Central Alabama Generating Station was placed into retail service.

The Alabama PSC's 2020 CCN also authorized Alabama Power to construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8) and the recovery of estimated in-service costs. On November 1, 2023, the unit was placed in service. In December 2023, Alabama Power filed Rate CNP New Plant with the Alabama PSC to recover the related costs. The filing reflected an annual increase in retail revenues of $91 million, or 1.4%, effective with January 2024 billings.

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. As part of the acquisition, Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to a non-affiliated third party through April 2027. Upon expiration of that agreement, Alabama Power will recover costs associated with the Lindsay Hill Generating Station acquisition

through Rate CNP New Plant, Rate CNP Compliance, Rate ECR, and Rate RSE. The December 5th Consent Order authorized Alabama Power to delay the effective date of the Rate CNP New Plant cost recovery until January 2028 billings. See Note 15 under "Alabama Power" for additional information.

Rate CNP PPA

Rate CNP PPA allows for the recovery of Alabama Power's retail costs associated with certificated PPAs. Revenues for Rate CNP PPA, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factors will have no significant effect on Southern Company's or Alabama Power's revenues or net income but will affect annual cash flow. No adjustments to Rate CNP PPA occurred during the period from 2023 through 2025, and, pursuant to the December 5th Consent Order, there will be no adjustments through March 2028 billings. At December 31, 2025 and 2024, Alabama Power had an under recovered Rate CNP PPA balance of $67 million and $84 million, respectively, of which $17 million and $17 million, respectively, is included in other regulatory assets, current and $50 million and $67 million, respectively, is included in other regulatory assets, deferred on Southern Company's and Alabama Power's balance sheets.

Rate CNP Compliance

Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to factors that are calculated and submitted to the Alabama PSC by December 1 with rates effective for the following calendar year. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factors will have no significant effect on Southern Company's or Alabama Power's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income.

In December 2023, November 2024, and November 2025, Alabama Power submitted calculations to the Alabama PSC associated with its cost of complying with governmental mandates for the following calendar year, as provided under Rate CNP Compliance. The 2023 filing reflected a $23 million, or 0.3%, annual decrease effective with January 2024 billings. The 2024 and 2025 filings reflected a projected under recovered retail revenue requirement of $50 million and $44 million, respectively. In December 2024, the Alabama PSC issued a consent order directing Alabama Power to maintain the 2024 Rate CNP Compliance factors in effect through 2025, and, pursuant to the December 5th Consent Order, Alabama Power will continue to maintain those same factors through the billing month of December 2027. Both consent orders specified that any prior year under collected amounts would be deemed recovered before any current year amounts are recovered and any remaining under recovered amounts would be reflected in the subsequent year's filing.

At December 31, 2025 and 2024, Alabama Power had an under recovered Rate CNP Compliance balance of $18 million and $35 million, respectively, which are included in other regulatory assets, deferred on Southern Company's and Alabama Power's balance sheets.

Rate CNP Depreciation

Rate CNP Depreciation allows Alabama Power to recover changes in depreciation resulting from updates to certain depreciation rates, excluding any depreciation recovered through Rate CNP New Plant, Rate CNP Compliance, or costs associated with the capitalization of asset retirement costs. No adjustments to Rate CNP Depreciation have occurred since its implementation effective with January 2023 billings, and no adjustments will occur in 2026.

Rate ECR

Rate ECR recovers Alabama Power's retail energy costs based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed gives rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on Southern Company's or Alabama Power's net income but will impact the related operating cash flows. The Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.

In November 2023, the Alabama PSC approved a decrease to Rate ECR of approximately $126 million annually, effective with December 2023 billings. In May 2024, the Alabama PSC approved a decrease to Rate ECR of approximately $135 million annually, effective with July 2024 billings. In December 2024, the Alabama PSC approved an additional reduction to Rate ECR of $218 million annually, effective with January 2025 billings. Pursuant to the December 5th Consent Order, the currently effective energy cost recovery factor of 2.600 cents per KWH will remain in effect for the billing months of January 2026 through December 2027. Beginning with January 2028 billings, the rate will adjust to 5.910 cents per KWH absent a further order from the Alabama PSC.

At December 31, 2025, Alabama Power's under recovered fuel costs totaled $146 million and is included in other regulatory assets, deferred on Southern Company's and Alabama Power's balance sheets. At December 31, 2024, Alabama Power's over recovered fuel costs totaled $29 million and is included in other regulatory liabilities, current on Southern Company's and Alabama Power's balance sheets. These classifications are based on estimates, which include such factors as weather, generation availability, energy demand, and the price of energy. A change in any of these factors could have a significant impact on the timing of any recovery or return of fuel costs.

Plant Greene County

Alabama Power jointly owns Plant Greene County Units 1 and 2 with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" for additional information. Mississippi Power's 2024 IRP includes a schedule to retire Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 by the end of 2028. Alabama Power currently expects to retire Plant Greene County Units 1 and 2 (300 MWs based on 60% ownership) by the end of 2028. Alabama Power and Mississippi Power have continued to evaluate operating conditions and business needs relevant to the anticipated retirement of Plant Greene County Units 1 and 2. The ultimate outcome of this matter cannot be determined at this time. See "Mississippi Power – Integrated Resource Plans" herein for additional information.

Rate NDR

Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million.

The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 48-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. The maximum charge to recover a deficit is $5.00 per month per non-residential customer account and $2.50 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant, which can be used to offset storm charges. Alabama Power made additional accruals of $7 million and $21 million in 2025 and 2024, respectively, and applied the 2025 Rate RSE refund of $57 million to the NDR in accordance with the December 5th Consent Order.

Under Rate NDR, Alabama Power collected approximately $23 million, $12 million, and $12 million in 2025, 2024, and 2023, respectively. Pursuant to orders of the Alabama PSC, Alabama Power applied $7 million of undistributed customer bill credits related to the nuclear fuel disposal costs litigation award to Rate NDR in 2025. Additionally, undistributed customer bill credits of $6 million and $1 million associated with Rate RSE refunds were applied in 2024 and 2023, respectively. Beginning with July 2025 billings, the reserve maintenance charge was suspended and the reserve establishment charge was activated as a result of the NDR balance falling below $50 million. Alabama Power expects to collect approximately $36 million annually under Rate NDR unless the NDR balance exceeds $75 million. At December 31, 2025 and 2024, the NDR balance was $60 million and $70 million, respectively, and is included in other regulatory liabilities, deferred on Southern Company's and Alabama Power's balance sheets. See Note 3 under "Nuclear Fuel Disposal Costs" for additional information regarding the nuclear fuel disposal costs litigation.

As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.

Reliability Reserve Accounting Order

Based on orders from the Alabama PSC, Alabama Power is authorized to maintain a reliability reserve separate from the NDR and to include certain reliability-related transmission and distribution expenses and generation-related expenses intended to

maintain reliability between scheduled generating unit maintenance outages. Alabama Power may make accruals to the reliability reserve if the NDR balance exceeds $35 million.

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 2023 and 2024, Alabama Power utilized a net $23 million and $12 million, respectively, from the reliability reserve for reliability-related transmission, distribution, and generation expenses.

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.

At December 31, 2025, Alabama Power's reliability reserve balance was $184 million, of which $60 million is included in other regulatory liabilities, current and $124 million is included in other regulatory liabilities, deferred on Southern Company's and Alabama Power's balance sheets. At December 31, 2024, Alabama Power's reliability reserve balance was $131 million and is included in other regulatory liabilities, deferred on Southern Company's and Alabama Power's balance sheets.

Environmental Accounting Order

Based on an order from the Alabama PSC, Alabama Power is authorized to establish a regulatory asset to record the unrecovered investment costs, including the unrecovered plant asset balance and the unrecovered costs associated with site removal and closure associated with future unit retirements, caused by environmental regulations. The regulatory asset is amortized and recovered over the affected unit's remaining useful life, as established prior to the decision regarding early retirement, through Rate CNP Compliance.

Alabama Power previously indicated plans to retire Plant Barry Unit 5 (700 MWs) by December 31, 2028. 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 a result, the unit's net book value of approximately $307 million no longer meets the criteria to be considered probable of abandonment. Accordingly, in the first quarter 2026, approximately $307 million will be reclassified from other utility plant, net to plant in service on Alabama Power's and Southern Company's balance sheets.

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. Pursuant to the December 5th Consent Order, Alabama Power will utilize the 2024 nuclear PTCs, when monetized, to offset retail cost of service in 2027. In addition, the nuclear PTCs generated in 2025, 2026, and 2027, when monetized, will be used to offset future retail cost of service, including any under recovered balances under Rate CNP and Rate ECR. The §45U PTC is subject to a phase-out. As such, Alabama Power will evaluate annually whether it qualifies for the credit. The ultimate outcome of this matter cannot be determined at this time. See Note 10 under "Unrecognized Tax Benefits" for additional information.

Georgia Power

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power recovers its costs from the regulated retail business through traditional base tariffs, DSM tariffs, the ECCR tariff, and Municipal Franchise Fee (MFF) tariffs. These tariffs were set under the 2022 ARP for the years 2023 through 2025 and subsequently extended through 2028 as described herein. In addition, fuel costs are collected through a separate fuel cost recovery tariff.

See "Nuclear Construction – Regulatory Matters" herein for information regarding the approved recovery through retail base rates of certain costs related to Plant Vogtle Unit 3 and the common facilities shared between Plant Vogtle Units 3 and 4 (Common Facilities) that became effective August 1, 2023 based on the in-service date of July 31, 2023 for Unit 3, as well as base rate adjustments for the remaining costs related to Plant Vogtle Units 3 and 4 that became effective May 1, 2024 based on the in-service date of April 29, 2024 for Unit 4. Financing costs on certified construction costs of Plant Vogtle Units 3 and 4 were collected through Georgia Power's NCCR tariff until the inclusion of certified construction costs in rate base. When the base rate adjustments occurred following commercial operation of Unit 4, the NCCR tariff ceased to be collected and financing costs are now included in Georgia Power's general retail revenue requirements. See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.

Rate Plans

In November 2023 and December 2024, the Georgia PSC approved the following tariff adjustments under the 2022 ARP effective January 1, 2024 and 2025, respectively:

Tariff	2024		2025
	(millions)
Traditional base(a)	$	275	$	194
ECCR	(99)		126
DSM	10		(22)
MFF	5		9
Total(b)	$	191	$	306

(a)For 2025, net of $122 million related to the Georgia state tax rate reduction.

(b)Totals may not add due to rounding.

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 (ARP Extension Period) except for reasonable and prudent storm damage costs incurred through December 31, 2025, which will be determined in a separate regulatory proceeding. The ARP Extension includes, among other things, the following modifications to the 2022 ARP:

•Storm damage costs will be included in a separate regulatory proceeding to be filed no later than July 1, 2026 to recover the actual reasonable and prudent storm costs incurred through December 31, 2025. Subject to Georgia PSC approval, new rates would be effective approximately 90 days after the filing is made. The Georgia PSC will determine the period over which any such storm damage costs will be recovered.

•Amortization of regulatory assets and liabilities in the 2022 ARP, which were subsequently included in current rates through annual compliance filings, will continue through the ARP Extension Period. This includes those regulatory asset and liability balances that were projected to be fully amortized through 2025 or during the ARP Extension Period.

•The amounts previously deferred during the 2022 ARP for ITCs and PTCs will be amortized through the ARP Extension Period. The acceleration of amortization during the ARP Extension Period is subject to the Internal Revenue Code normalization rules and other guidance (if any) released by the IRS. Certain amounts of ITCs generated during the ARP Extension Period will be amortized over five years, and additional ITC amounts will be deferred to a regulatory liability during the ARP Extension Period. Sixty percent (60%) of PTC benefits generated (excluding PTCs generated under Internal Revenue Code §45J) during the ARP Extension Period will be credited to income tax expense as generated. The remaining forty percent (40%) will be deferred to a regulatory liability.

•The period for depreciation and amortization related to certain generating plants and net book values of retired generating plants will be 13 years effective January 1, 2026.

In the 2022 ARP, the Georgia PSC approved recovery through the ECCR tariff of estimated CCR ARO compliance costs for 2024 and 2025 over four-year periods beginning January 1 of each respective year, with recovery of construction contingency beginning in the year following actual expenditures, resulting in a reduction of $60 million in the related amortization for 2024 and an increase of $123 million in the related amortization for 2025. Under the ARP Extension, the amortization will not change for 2026 through 2028. Compliance costs incurred were $300 million, $265 million, and $315 million in 2023, 2024, and 2025, respectively.

Further, under the 2022 ARP and the ARP Extension, Georgia Power's retail ROE is set at 10.50% and its equity ratio is set at 56%. Earnings are evaluated against a retail ROE range of 9.50% to 11.90%. Any earnings above 11.90% retail ROE will be subject to sharing whereby 40% of earnings above the band would be applied to regulatory assets, 40% would be directly refunded to customers, and the remaining 20% would be retained by Georgia Power. There will be no recovery of any earnings shortfall below 9.50% retail ROE on an actual basis. However, if at any time during the term of the 2022 ARP and the ARP Extension Period, Georgia Power projects that its retail earnings will be less than the lower end of the approved retail ROE range for any calendar year, it may petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff to adjust Georgia Power's retail rates to achieve a retail ROE equal to the lower end of the approved retail ROE range. The Georgia PSC would have 90 days to rule on Georgia Power's request. Any ICR tariff would expire at the earlier of January 1, 2029 or the end of the calendar year in which the ICR tariff becomes effective. In lieu of requesting implementation of an ICR tariff, or if the Georgia PSC chooses not to implement an ICR tariff, Georgia Power may file a full base rate case. In 2023, 2024, and 2025, Georgia Power's retail ROE was within the allowed retail ROE range.

Except as provided above, Georgia Power will not file a base rate increase while the ARP Extension is in effect. Georgia Power is required to file a general base rate case by July 1, 2028, in response to which the Georgia PSC would be expected to determine whether the 2022 ARP should be continued, modified, or discontinued.

Integrated Resource Plans

2025 IRP

On July 15, 2025, the Georgia PSC approved Georgia Power's triennial IRP (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 the following requests:

•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. See Note 7 under "SEGCO" for additional information.

•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.

•Issuance of a capacity RFP to procure resources to meet capacity needs in 2032 and 2033.

•Strategic power delivery infrastructure plan necessary to help ensure adequate reliability and serve the projected future load growth projected in Georgia.

•Certification of approximately 187 MWs of wholesale capacity associated with Plant Scherer Unit 3 to be placed in retail rate base, some of which will be available beginning in 2026.

In addition, the 2025 IRP assumes Plant Bowen Units 1 and 2 will operate through at least the end of 2035.

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, which consist of four PPAs (including two affiliate PPAs with Southern Power that are subject to approval by the FERC) with capacity totaling 1,195 MWs commencing between 2028 and 2030, three project sites consisting of five Georgia Power-owned combined cycle units with capacity totaling 3,692 MWs and projected CODs commencing between 2029 and 2030, nine Georgia Power-owned battery energy storage facilities with capacity totaling 2,762 MWs and projected CODs commencing between 2028 and 2030, and two Georgia Power-owned battery energy storage facilities with solar with capacity totaling 350 MWs and projected CODs commencing in 2028.

•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.

As required by the 2025 IRP decision, Georgia Power filed with the Georgia PSC on September 17, 2025 an updated load forecast to support the certification requests from the RFP of up to 8,500 MWs.

As included in the 2022 IRP final order, on February 11, 2026, Georgia Power initiated an RFP for up to 500 MWs of capacity for battery energy storage facilities with projected CODs or delivery commencement dates by 2031.

See "2025 IRP" and "Other Construction" herein for additional information.

Transmission Asset Sales

In March 2024, the FERC approved the sale of transmission line assets under the integrated transmission system agreement, with a net book value of $236 million. In April 2024, the sale, with a purchase price of $351 million, was completed resulting in a pre-tax gain of approximately $114 million ($84 million after tax) recorded in 2024.

Fuel Cost Recovery

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. During 2022, Georgia Power's under recovered fuel balance increased significantly due to higher fuel and purchased power costs. In 2023, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to increase annual fuel billings by 54%, or approximately $1.1 billion, effective June 1, 2023. The increase includes a three-year recovery period for $2.2 billion of Georgia Power's under recovered fuel balance at May 31, 2023. Under the approved stipulation, Georgia Power is allowed to adjust its fuel cost recovery rates under an interim fuel rider (IFR) prior to the next fuel case, subject to a maximum 40% cumulative change, if its under or over recovered fuel balance accumulated since May 31, 2023 exceeds $200 million (IFR Threshold). On May 14, 2025, Georgia Power submitted an IFR notification and plan informing the Georgia PSC that Georgia Power's under recovered fuel balance exceeded the IFR Threshold. Georgia Power proposed no fuel cost recovery rate change and was required to monitor and report to the Georgia PSC monthly as long as the under recovered fuel balance was above the IFR Threshold. Georgia Power filed an IFR notification and plan monthly through September 2025, each of which also proposed no fuel cost recovery rate change. Between September 30, 2025 and November 30, 2025, Georgia Power's under recovered fuel balance did not exceed the IFR Threshold. On each of January 15, 2026 and February 13, 2026, Georgia Power filed an IFR notification and plan informing the Georgia PSC that Georgia Power's under recovered fuel balance exceeded the IFR Threshold as of December 31, 2025 and January 31, 2026, respectively, and proposed no fuel cost recovery rate change. 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.

Georgia Power's under recovered fuel balance totaled $522 million at December 31, 2025, of which $310 million is included in under recovered fuel clause revenues and under recovered retail fuel clause revenues on Southern Company's and Georgia Power's balance sheets, respectively, and $212 million is included in deferred under recovered retail fuel clause revenues on Southern Company's and Georgia Power's balance sheets. The under recovered fuel balance totaled $1.2 billion at December 31, 2024, of which $713 million is included in under recovered fuel clause revenues and under recovered retail fuel clause revenues on Southern Company's and Georgia Power's balance sheets, respectively, and $453 million is included in deferred under recovered retail fuel clause revenues on Southern Company's and Georgia Power's balance sheets.

Georgia Power's fuel cost recovery mechanism includes costs associated with a natural gas hedging program, as revised and approved by the Georgia PSC, allowing the use of an array of derivative instruments within a 36-month time horizon.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income but will affect operating cash flows.

Storm Damage Recovery

Georgia Power defers and recovers certain costs related to damages to its transmission and distribution facilities resulting from major storms as mandated by the Georgia PSC. Beginning January 1, 2023, Georgia Power is recovering $31 million annually under the 2022 ARP. During September 2024, Hurricane Helene caused significant damage to Georgia Power's transmission and distribution facilities. The incremental restoration costs related to this hurricane totaled approximately $880 million, of which approximately $780 million was deferred in the regulatory asset for storm damage, approximately $75 million was capitalized to property, plant, and equipment, and approximately $25 million was deferred and subsequently billed in 2025 to open access transmission tariff customers. At December 31, 2025 and 2024, Georgia Power's regulatory asset balance related to storm damage was $912 million and $827 million, respectively, of which $31 million for each year is included in other regulatory assets, current

and $880 million and $795 million, respectively, is included in other regulatory assets, deferred on Southern Company's and Georgia Power's balance sheets.

Pursuant to the ARP Extension, 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 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. See "Rate Plans" herein for additional information.

The rate of storm damage cost recovery is expected to be further adjusted in future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's net income but do impact the related operating cash flows.

Nuclear Construction

See Note 8 under "Long-term Debt – DOE Loan Guarantee Borrowings" for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, and mandatory prepayment events.

Cost and Schedule

Georgia Power placed Plant Vogtle Units 3 and 4 (553 MWs each based on 45.7% ownership) in service on July 31, 2023 and April 29, 2024, respectively. During the third quarter 2025, following the completion of site demobilization efforts, Southern Nuclear evaluated the remaining contractor obligations and reduced the remaining estimate to complete forecast by approximately $33 million. During the fourth quarter 2025, Southern Nuclear finalized the remaining contractor obligations and reduced the remaining estimate to complete forecast, including the impact of joint owner cost-sharing described below, by approximately $27 million. Accordingly, Georgia Power recorded pre-tax credits to income of approximately $33 million ($25 million after tax) and $27 million ($20 million after tax) in the third quarter 2025 and the fourth quarter 2025, respectively, to recognize capital costs previously charged to income. Georgia Power's final net investment in connection with Plant Vogtle Units 3 and 4 is $10.670 billion, which excludes capitalized AFUDC of approximately $440 million accrued through Unit 4's in-service date.

Georgia Power previously reached agreements with MEAG Power, OPC, and Dalton to resolve its respective dispute with each regarding the cost-sharing and tender provisions of the joint ownership agreements, as amended (Vogtle Joint Ownership Agreements). Under the terms of these agreements, among other items, Georgia Power reimbursed a portion of MEAG Power's, OPC's, and Dalton's costs of construction for Plant Vogtle Units 3 and 4 as such costs were incurred and with no further adjustment for force majeure costs, which payments (including amounts paid to date) totaled approximately $86 million, $82 million, and $4.4 million for MEAG Power, OPC, and Dalton, respectively, based on the final project capital cost. Georgia Power also reimbursed 20% of MEAG Power's costs of construction and 66% of each of OPC's and Dalton's costs of construction with respect to amounts over the final project capital cost, with no further adjustment for force majeure costs. Georgia Power recorded pre-tax charges to income through 2024 of $559 million ($418 million after tax) and a pre-tax credit to income in the fourth quarter 2025 of $22 million ($17 million after tax) associated with the cost-sharing provisions of the Vogtle Joint Ownership Agreements, including the settlements with the other Vogtle Owners described above. These charges are included in the total project capital cost and will not be recovered from retail customers.

Regulatory Matters

In 2021, the Georgia PSC approved an order under which Georgia Power would include in rate base an allocation of $2.1 billion to Plant Vogtle Unit 3 and the Common Facilities from the $3.6 billion of Plant Vogtle Units 3 and 4 costs previously deemed prudent by the Georgia PSC and would recover the related depreciation through retail base rates effective the month after Unit 3 is placed in service. In compliance with the Georgia PSC order, Georgia Power increased annual retail base rates by $318 million effective August 1, 2023 based on the in-service date of July 31, 2023 for Unit 3. The related increase in annual retail base rates included recovery of all projected operations and maintenance expenses for Unit 3 and the Common Facilities and other related costs of operation, partially offset by the related PTCs.

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

Under the terms of the approved Prudency Stipulation, Georgia Power is recovering $7.562 billion in total construction and capital costs and associated retail rate base items of $1.02 billion, which includes AFUDC financing costs above $4.418 billion (the Georgia PSC-certified amount) up to $7.562 billion. Georgia Power is also recovering projected operations and maintenance

expenses, depreciation, nuclear decommissioning accruals, and property taxes, net of projected PTCs. After considering construction and capital costs already in retail base rates of $2.1 billion and $362 million of associated retail rate base items for Unit 3 and Common Facilities (approved by the Georgia PSC in 2021), Georgia Power included in retail rate base the remaining $5.462 billion of construction and capital costs as well as $647 million of associated retail rate base items effective with the April 29, 2024 in-service date for Unit 4. Annual retail base revenues increased approximately $730 million and the average retail base rates were adjusted by approximately 5% (net of the elimination of the NCCR tariff described below) effective May 1, 2024.

Reductions to the ROE used to calculate the NCCR tariff (pursuant to prior Georgia PSC orders) negatively impacted earnings by approximately $80 million through the second quarter 2024 and $310 million in 2023. Further, as included in the approved Prudency Stipulation, since commercial operation for Unit 4 was not achieved by March 31, 2024, Georgia Power's ROE used to determine the NCCR tariff and calculate AFUDC was reduced to zero effective April 1, 2024, which resulted in a negative impact to earnings of approximately $10 million (for one month) in the second quarter 2024 based on the April 29, 2024 in-service date. Effective May 1, 2024, following commercial operation of Unit 4, Georgia Power's NCCR tariff was eliminated and financing costs are included in Georgia Power's general retail revenue requirements.

As of each Unit's respective first refueling outage, if the respective Unit's performance has materially deviated from expected performance, the Georgia PSC may order Georgia Power to credit customers for operations and maintenance expenses or disallow costs associated with the repair or replacement of any system, structure, or component found to have caused the material deviation in performance if proven to be the result of imprudent engineering, construction, procurement, testing, or start-up. Unit 3 demonstrated high performance and reliability during the first 14 months of operation leading up to its first refueling outage, which took place in the fall of 2024. Unit 4 also demonstrated high performance and reliability during the first 16 months of operation leading up to its first refueling outage, which took place in the fall of 2025. No customer credits for operations and maintenance expenses or performance-related disallowances were recorded.

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

As a result of the Georgia PSC's approval of the Prudency Stipulation, Georgia Power recorded a pre-tax credit to income of approximately $228 million ($170 million after tax) in the fourth quarter 2023 to recognize CWIP costs previously charged to income, which are now recoverable through retail rates. Associated AFUDC on these costs, which totaled approximately $14 million, was also recognized.

Other Construction

At December 31, 2025, Georgia Power had recorded approximately $3.1 billion of combined capital costs, excluding AFUDC, for the projects reflected in the table below approved through the 2023 IRP Update and the approved certification requests in September and December 2025. The total certified amounts related to these projects are approximately $19.5 billion, excluding

AFUDC. Georgia Power is required to file periodic construction monitoring reports with the Georgia PSC through commercial operation. The ultimate outcome of these matters cannot be determined at this time.

Resource/Project	Approximate Nameplate Capacity (MW)	Projected COD
Projects Under Construction at December 31, 2025
Battery Energy Storage
McGrau Ford Phase 1	265	Fourth quarter 2026
Twiggs County	200	Fourth quarter 2027
Wadley	260	Fourth quarter 2027
Plant Bowen Phase 1	250	Fourth quarter 2028
Plant Bowen Phase 2	250	Fourth quarter 2029
South Hall	250	Fourth quarter 2028
Plant Wansley	500	Fourth quarter 2028
Plant Yates Phase 1	320	Fourth quarter 2028
Plant Yates Phase 2	250	Fourth quarter 2028
Thomson	500	Fourth quarter 2029
Hammond Phase 2	193	Fourth quarter 2030
Plant McIntosh	250	Fourth quarter 2030
Various facilities	500	Second quarter 2026 through fourth quarter 2026
Solar with Battery Energy Storage
Laurens County	200	Fourth quarter 2028
Plant Mitchell	150	Fourth quarter 2028
Combined Cycle
Plant Bowen Unit 7	741	Fourth quarter 2029
Plant Bowen Unit 8	741	Second quarter 2030
Plant McIntosh Unit 12	757	Fourth quarter 2030
Plant Wansley Unit 10	727	Fourth quarter 2029
Plant Wansley Unit 11	727	Second quarter 2030
Combustion Turbine
Plant Yates Unit 8(*)	442	Fourth quarter 2026
Plant Yates Unit 9(*)	442	Second quarter 2027
Plant Yates Unit 10(*)	442	Third quarter 2027

(*)Pursuant to the 2023 IRP Update, cost recovery over the certified amount is limited.

Mississippi Power

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Recoverable costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates.

Performance Evaluation Plan

Mississippi Power's retail base rates generally are set under the PEP, a rate plan approved by the Mississippi PSC. In recognition that Mississippi Power's long-term financial success is dependent upon how well it satisfies its customers' needs, PEP includes performance indicators that directly tie customer service indicators to Mississippi Power's allowed ROE. PEP measures Mississippi Power's performance on a 10-point scale as a weighted average of results in three areas: average customer price, as compared to prices of other regional utilities (weighted at 40%); service reliability, measured in percentage of time customers had electric service (40%); and customer satisfaction, measured in a survey of residential customers (20%). Typically, two PEP filings are made for each calendar year: the PEP preliminary report filing in November of the preceding year and the PEP Evaluation Report, which includes the current year PEP projected filing and the previous year PEP lookback filing, filed in March of the subsequent year. The annual PEP preliminary report filing is an informational report indicating whether a revenue adjustment is needed for the preceding year. The annual PEP projected filings utilize a historic test year adjusted for "known and measurable" changes and discounted cash flow and regression formulas to determine base ROE. The PEP lookback filing reflects the actual revenue requirement.

In June 2023 and June 2024, the Mississippi PSC approved Mississippi Power's annual retail PEP filings for 2023 and 2024, respectively, with no change in retail rates. 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, primarily due to increases in investment and depreciation. 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.

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.

Integrated Resource Plans

In 2023, Mississippi Power signed an affiliate PPA with Georgia Power for 750 MWs of capacity, which began January 1, 2024 and will continue through December 31, 2028. On July 8, 2025, Mississippi Power extended 50 MWs of its affiliate PPA with Georgia Power for an additional year through December 31, 2029. See "Georgia Power – Integrated Resource Plans – Certification Requests" herein for additional information.

In April 2024, Mississippi Power filed its 2024 IRP with the Mississippi PSC. The Mississippi PSC did not note any deficiencies within the prescribed 120-day review period; therefore, the filing was concluded. The 2024 IRP included a schedule to retire Plant Watson Unit 4 (268 MWs) and Plant Greene County Units 1 and 2 (206 MWs based on 40% ownership) and to retire early Plant Daniel Units 1 and 2 (502 MWs based on 50% ownership), all by the end of 2028, which is consistent with the completion of the initial term of Mississippi Power's affiliate PPA with Georgia Power. On January 9, 2025, Mississippi Power notified the Mississippi PSC of its intent to extend the retirement date of Plant Daniel Unit 2 and potentially extend the retirement dates of other fossil steam units beyond their current 2028 retirement dates in order to serve recently signed economic development loads of approximately 600 MWs. Mississippi Power has since acquired FP&L's 50% ownership interest in Plant Daniel Units 1 and 2 as described under "Plant Daniel" herein. In 2026, in compliance with its IRP requirements, Mississippi Power is expected to file a mid-point update to its 2024 IRP with the Mississippi PSC.

On February 12, 2026, Mississippi Power filed a request with the Mississippi PSC to convert Plant Daniel Unit 2 from a coal-fired unit to a natural gas-fired unit. Conversion of the unit is projected to be completed in 2029.

The remaining net book value of Plant Daniel Units 1 and 2 was approximately $465 million at December 31, 2025, and Mississippi Power is continuing to depreciate these units using the current approved rates. Mississippi Power expects to reclassify the net book value remaining at retirement to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with a 2020 order. The Plant Watson and Plant Greene County units are expected to be fully depreciated upon retirement.

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

Plant Daniel

In November 2024, Mississippi Power entered into an agreement with FP&L to acquire FP&L's 50% ownership interest in Plant Daniel Units 1 and 2. On January 7, 2025, the Mississippi PSC approved Mississippi Power's request for (i) the inclusion of the acquired assets and the associated costs at Plant Daniel in Mississippi Power's retail rate base, upon completion of the transaction, (ii) the establishment of a new regulatory liability account in which all of the proceeds to be paid by FP&L will be recorded, and (iii) Mississippi Power's ability to amortize that regulatory liability by charging certain expenditures against it. 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% ownership 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 being amortized to offset incremental costs as authorized by the Mississippi PSC. As part of the agreement, FP&L retained responsibility for environmental remediation and decommissioning liabilities related to its prior ownership interest.

Environmental Compliance Overview Plan

The Mississippi PSC has authorized Mississippi Power to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations.

In April 2023, May 2024, and April 2025, the Mississippi PSC approved Mississippi Power's annual ECO Plan filings, resulting in increases in revenues of approximately $3 million annually effective with the first billing cycle of May 2023, $9 million

annually effective with the first billing cycle of June 2024, and $6 million annually effective with the first billing cycle of May 2025, respectively.

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.

Fuel Cost Recovery

Mississippi Power annually establishes, and is required to file for an adjustment to, the retail fuel cost recovery factor that is approved by the Mississippi PSC. In February 2024, the Mississippi PSC approved Mississippi Power's request to increase retail fuel revenues by $18 million annually effective with the first billing cycle of March 2024. The approved filing included the deferral of approximately $61 million of under recovered fuel costs as of October 2023. On January 7, 2025, the Mississippi PSC approved Mississippi Power's request for no change in retail fuel revenues effective with the first billing cycle of February 2025. The approved filing included the deferral of approximately $25 million of under recovered fuel costs as of October 2024. On January 13, 2026, the Mississippi PSC approved Mississippi Power's request to increase retail fuel revenues by $40 million annually effective with the first billing cycle of February 2026. The approved filing included the deferral of approximately $31 million of under recovered fuel costs as of October 2025, which is expected to be included in Mississippi Power's next fuel filing. Mississippi Power will continue to accrue its weighted-average cost of capital on any under or over fuel recovery balance.

At December 31, 2025, Mississippi Power had $40 million of deferred under recovered retail fuel clause revenues related to higher recoverable fuel costs and its fuel-hedging program on its balance sheet. At December 31, 2024, Mississippi Power had $32 million of deferred under recovered retail fuel clause revenues primarily associated with its fuel-hedging program and $32 million of over recovered retail fuel clause revenues primarily related to lower recoverable fuel costs on its balance sheet. See Note 1 under "Fuel Costs" for additional information.

Mississippi Power has wholesale MRA and Market Based (MB) fuel cost recovery factors. Effective with the first billing cycles for January 2024, 2025, and 2026, annual revenues under the wholesale MRA fuel rate decreased $4 million, decreased $19 million, and increased $23 million, respectively. At December 31, 2025 and 2024, wholesale MRA fuel costs were under recovered $6 million and over recovered $19 million, respectively, and were included in other current assets and other current liabilities, respectively, on Mississippi Power's balance sheets. The wholesale MB fuel rate did not change materially in any period presented. The wholesale MB fuel cost recovery was immaterial for both periods presented.

Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income but will affect operating cash flows.

Ad Valorem Tax Adjustment

Mississippi Power annually establishes an ad valorem tax adjustment factor that is approved by the Mississippi PSC. Any changes are not expected to have a significant effect on Mississippi Power's net income but will affect operating cash flows. Effective with the first billing cycle of June 2023, July 2024, and September 2025, the Mississippi PSC approved changes in annual revenues collected through the ad valorem tax adjustment factor resulting in a $7 million decrease, a $5 million decrease, and a $7 million increase, respectively.

System Restoration Rider

Mississippi Power carries insurance for the cost of certain types of damage to generation plants and general property. However, Mississippi Power is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, Mississippi Power accrues for the cost of such damage through an annual expense accrual which is credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. Every year, the Mississippi PSC, the MPUS, and Mississippi Power agree on SRR revenue level(s). In the event the expected annual charges exceed the annual accrual or the target balance has been met, Mississippi Power and the Mississippi PSC will determine the appropriate change to the annual accrual. Additionally, if PEP earnings are above a certain threshold, Mississippi Power has the ability to apply any required PEP refund as an additional accrual to the property damage reserve in lieu of customer refunds.

Mississippi Power's net retail SRR accrual, which includes carrying costs and previously included amortization of related excess deferred income tax benefits, was $13.5 million in 2025, $12.6 million in 2024, and $11.7 million in 2023. At December 31, 2025 and 2024, the retail property damage reserve balance was $57 million and $52 million, respectively, and is included in other regulatory liabilities, deferred on Mississippi Power's balance sheets.

In 2023, the Mississippi PSC approved Mississippi Power's annual SRR filing, with no change in retail rates. Mississippi Power's minimum annual SRR accrual was increased from $8.3 million to $11.7 million. In April 2024, the Mississippi PSC approved Mississippi Power's annual SRR filing to the Mississippi PSC, with no change in retail rates. Mississippi Power's minimum annual SRR accrual was increased from $11.7 million to $12.6 million. On June 17, 2025, the Mississippi PSC approved Mississippi Power's annual SRR filing for 2025, with no change in retail rates. Mississippi Power's minimum annual SRR accrual increased from $12.6 million to $13.5 million and the target property damage reserve balance increased from $75 million to $125 million. Mississippi Power will continue to record the minimum annual accrual until the target property damage reserve balance of $125 million is met.

Reliability Reserve Accounting Order

Based on an order from the Mississippi PSC, Mississippi Power is authorized to maintain a retail reliability reserve to offset future generation, transmission, and distribution reliability-related expenditures for use in a future year. Mississippi Power may make accruals to the retail reliability reserve each year after meeting with the MPUS and Mississippi PSC staff. Mississippi Power will provide annually, through its capital plan, energy delivery plan, or PEP filing, any amounts to be charged against the retail reliability reserve during the current year.

During 2025, 2024, and 2023, Mississippi Power accrued $13 million, $21 million, and $11 million, respectively, to the retail reliability reserve. On June 17, 2025, the Mississippi PSC approved Mississippi Power's use of a portion of its retail reliability reserve balance during 2025, through its annual PEP filing. 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. See "Performance Evaluation Plan" herein for information regarding approval of the annual PEP filing.

At December 31, 2025, Mississippi Power's retail reliability reserve balance was $59 million, of which $9 million is included in other regulatory liabilities, current and $50 million is included in other regulatory liabilities, deferred on Mississippi Power's balance sheets. At December 31, 2024, Mississippi Power's retail reliability reserve balance was $57 million and is included in other regulatory liabilities, deferred on Mississippi Power's balance sheets.

Excess Accumulated Deferred Income Tax Accounting Order

On January 13, 2026, the Mississippi PSC approved an accounting order authorizing Mississippi Power to accelerate the amortization of approximately $21 million of a regulatory liability associated with certain federal excess accumulated deferred income taxes resulting from the Tax Reform Legislation. The flowback will be determined in a future rate proceeding. The ultimate outcome of this matter cannot be determined at this time.

Municipal and Rural Associations Tariff

Mississippi Power provides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and the City of Collins, all located in southeastern Mississippi, under a long-term, FERC-regulated MRA tariff.

In 2017, Mississippi Power and Cooperative Energy executed, and the FERC accepted, a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy share in providing electricity to the Cooperative Energy delivery points under the tariff. In 2022, the FERC accepted an amended SSA between Mississippi Power and Cooperative Energy, effective July 1, 2022, under which Cooperative Energy will continue to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually through 2035. At December 31, 2025, Mississippi Power is serving approximately 394 MWs of Cooperative Energy's annual demand. Beginning in 2036, Cooperative Energy will provide 100% of its electricity requirements at the MRA delivery points under the tariff. Neither party has the option to cancel the amended SSA.

In May 2024, the FERC issued an order accepting Mississippi Power's request for an $8 million increase in annual wholesale base revenues under the MRA tariff, effective May 29, 2024, subject to refund. On April 3, 2025, the FERC approved a settlement agreement filed by Mississippi Power and Cooperative Energy in December 2024. The settlement agreement provided for (i) a $1 million increase in annual wholesale base revenues and a refund to customers of approximately $4 million, (ii) a rate escalation of 2.5% on an annual basis in periods subsequent to December 31, 2024 and continuing through the end of the SSA on December 31, 2035, and (iii) a waiver of rights by Mississippi Power and Cooperative Energy to file for any changes in non-fuel rates through the end of the term of the SSA.

Southern Company Gas

Utility Regulation and Rate Design

The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies. Rates charged to customers vary according to customer class (residential, commercial, or industrial) and rate jurisdiction. These

agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.

As a result of operating in a deregulated environment, Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically. The Marketers add these fixed charges when billing their respective customers. This mechanism, called a straight-fixed-variable rate design, minimizes the seasonality of Atlanta Gas Light's revenues since the monthly fixed charge is not volumetric or directly weather dependent.

With the exception of Atlanta Gas Light, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of price levels for natural gas and general economic conditions that may impact customers' ability to pay for natural gas consumed. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes. Southern Company Gas has various mechanisms, such as weather and revenue normalization mechanisms, that limit exposure to weather changes within typical ranges in these utilities' respective service territories.

In addition to natural gas cost recovery mechanisms, other cost recovery mechanisms and regulatory riders, which vary by utility, allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation, energy efficiency plans, and bad debts. In traditional rate designs, utilities recover a significant portion of the fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by customers. With the exception of Chattanooga Gas, the natural gas distribution utilities have decoupled regulatory mechanisms that Southern Company Gas believes encourage conservation by separating the recoverable amount of these fixed costs from the amounts of natural gas used by customers. See "Rate Proceedings" herein for additional information. Also see "Infrastructure Replacement Programs and Capital Projects" herein for additional information regarding infrastructure replacement programs at certain of the natural gas distribution utilities.

The following table provides regulatory information for Southern Company Gas' natural gas distribution utilities:

	Nicor Gas	Atlanta Gas Light	Virginia Natural Gas	Chattanooga Gas
Authorized ROE at December 31, 2025	9.60%	10.25%	9.85%	9.80%
Weather normalization mechanisms(a)			ü	ü
Decoupled, including straight-fixed-variable rates(b)	ü	ü	ü
Regulatory infrastructure program rate(c)		ü	ü	ü
Bad debt rider(d)	ü		ü	ü
Energy efficiency plan(e)	ü		ü
Annual base rate adjustment mechanism(f)		ü		ü
Year of last base rate case decision	2025	2019	2025	2018

(a)Designed to help stabilize operating results by allowing recovery of costs in the event of unseasonal weather, but are not direct offsets to the potential impacts on earnings of weather and customer consumption.

(b)Allows for recovery of fixed customer service costs separately from assumed natural gas volumes used by customers and provides a benchmark level of revenue for recovery.

(c)See "Infrastructure Replacement Programs and Capital Projects" herein for additional information. Chattanooga Gas' pipeline replacement program costs are recovered through its annual base rate review mechanism.

(d)The recovery (refund) of bad debt expense over (under) an established benchmark expense. The gas portion of bad debt expense is recovered through purchased gas adjustment mechanisms. Nicor Gas also has a rider to recover the non-gas portion of bad debt expense.

(e)Recovery of costs associated with plans to achieve specified energy savings goals.

(f)Regulatory mechanism allowing annual adjustments to base rates up or down based on authorized ROE and/or ROE range.

Infrastructure Replacement Programs and Capital Projects

In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Virginia Natural Gas has a separate rate rider that provides timely recovery of capital expenditures for specific infrastructure replacement programs, and Atlanta Gas Light has a separate rate rider that provides for the timely recovery of capital expenditures for a specific reinforcement capital program. Total capital expenditures incurred during 2025 for all gas distribution operations were $1.9 billion.

The following table and discussions provide updates on the infrastructure replacement programs and capital projects at the natural gas distribution utilities at December 31, 2025. These programs are risk-based and designed to update and replace cast iron, bare

steel, and mid-vintage plastic materials or expand Southern Company Gas' distribution systems to improve reliability and meet operational flexibility and growth.

Utility	Program	Recovery	Capital Expenditures in 2025		Capital Expenditures Since Project Inception		Pipe Installed Since Project Inception	Scope of Program	Program Duration	Last Year of Program
			(in millions)				(miles)	(miles)	(years)
Virginia Natural Gas	SAVE	Rider	$	72	$	633	620	938	18	2029
Atlanta Gas Light	System Reinforcement Rider	Rider	131		410		43	N/A	6	2027
Chattanooga Gas	Pipeline Replacement Program	Rate Base	13		41		37	73	10	2031
			$	216	$	1,084	700	1,011

Virginia Natural Gas

The SAVE program, an accelerated infrastructure replacement program, allows Virginia Natural Gas to continue replacing aging pipeline infrastructure. The program included authorized annual investments of $70 million in each of 2023 and 2024, with a total potential variance of up to $5 million allowed for the program, for a maximum total investment over the previous six-year term (2019 through 2024) of $365 million.

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

The SAVE program is subject to annual review by the Virginia Commission. In accordance with the base rate case approved by the Virginia Commission in 2025, Virginia Natural Gas is recovering program costs incurred prior to January 1, 2025 through base rates. Program costs incurred subsequent to January 1, 2025 are currently being recovered through a separate rider and are subject to future base rate case proceedings. See "Rate Proceedings – Virginia Natural Gas" herein for additional information.

Atlanta Gas Light

In 2019, the Georgia PSC approved the continuation of GRAM as part of Atlanta Gas Light's 2019 rate case order. Various infrastructure programs previously authorized by the Georgia PSC, including the Integrated Vintage Plastic Replacement Program to replace aging plastic pipe and the Integrated System Reinforcement Program to upgrade Atlanta Gas Light's distribution system and LNG facilities in Georgia, continue under GRAM and the recovery of and return on the infrastructure program investments are included in annual base rate adjustments. The amounts recovered through rates related to allowed, but not incurred, costs were quantified as an unrecognized ratemaking amount that is not reflected on the balance sheets. These allowed costs are primarily the equity return on the capital investment under the infrastructure programs in place prior to GRAM and are expected to be fully recovered through GRAM and base rates by the end of 2027. The Georgia PSC reviewed Atlanta Gas Light's performance annually under GRAM. See "Unrecognized Ratemaking Amounts" herein for additional information.

Atlanta Gas Light and the staff of the Georgia PSC previously agreed to a variation of the Integrated Customer Growth Program to extend pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. A separate tariff provides recovery of up to $25 million annually for strategic economic development projects approved by the Georgia PSC.

The Georgia PSC also approved a new System Reinforcement Rider for authorized large pressure improvement and system reliability projects. Capital investments for the years 2022 through 2024 related to the System Reinforcement Rider totaled $279 million.

See "Rate Proceedings – Atlanta Gas Light" herein for additional information regarding the Georgia PSC's 2021 approval of Atlanta Gas Light's GRAM filing and Integrated Capacity and Delivery Plan (i-CDP).

Chattanooga Gas

In 2021, the Tennessee Public Utilities Commission approved Chattanooga Gas' pipeline replacement program to replace approximately 73 miles of distribution main over a seven-year period. The estimated total cost of the program is $118 million, which will be recovered through Chattanooga Gas' annual base rate review mechanism.

In June 2025, the Tennessee Public Utilities Commission approved an extension of Chattanooga Gas' pipeline replacement program from seven to 10 years.

Nicor Gas

Illinois legislation allowed Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system through 2023 and stipulated that rate increases to customers as a result of any infrastructure investments did not exceed a cumulative annual average of 4.0% or, in any given year, 5.5% of base rate revenues. In 2014, the Illinois Commission approved the nine-year regulatory infrastructure program, Investing in Illinois, which concluded in 2023 and is subject to annual review, as discussed further below. In accordance with orders from the Illinois Commission, Nicor Gas recovered program costs incurred through a separate rider and base rates. See "Rate Proceedings – Nicor Gas" herein for additional information.

In 2023, the Illinois Commission concluded its review of the Qualifying Infrastructure Plant (QIP) capital investments by Nicor Gas for calendar year 2019 under the QIP rider, also referred to as Investing in Illinois program. The Illinois Commission disallowed $32 million of the $415 million of capital investments commissioned in 2019, together with the related return on investment. Nicor Gas recorded a pre-tax charge to income in 2023 of $38 million ($28 million after tax) associated with the disallowance of capital investments placed in service in 2019. The disallowances are reflected on the statements of income as an $8 million reduction to revenues and $30 million in estimated loss on regulatory disallowance. Later in 2023, the Illinois Commission denied a rehearing request filed by Nicor Gas, and Nicor Gas filed a notice of appeal with the Illinois Appellate Court. In November 2024, the Illinois Appellate Court upheld the Illinois Commission's review of the QIP capital investments by Nicor Gas for calendar year 2019 under the QIP rider apart from one immaterial item. In December 2024, Nicor Gas filed a petition for leave to appeal $14 million of the 2019 QIP disallowances with the Illinois Supreme Court, which was denied on March 26, 2025. This matter is now concluded and had no impact on the financial statements for the period ended December 31, 2025.

The following table provides a summary of QIP capital investments during the nine-year program:

Year	Status of QIP Annual Review Proceeding	Capital Investments			Disallowed			Month of Disallowance
		(in millions)
2015 – 2018	Complete	$	1,246		$	—
2019	Complete	415			32			June 2023
2020	Filed March 2021	402		(a)
2021	Filed March 2022	392		(a)
2022	Filed March 2023	408		(a)	6		(b)	November 2023
2023	Filed March 2024	365		(a)	25		(b)	November 2023
		$	3,228		$	63

(a)Capital investments are subject to the required QIP annual review proceeding; years 2020 through 2023 are pending with the Illinois Commission.

(b)Disallowed in Nicor Gas' 2023 general base rate case proceeding. See "Rate Proceedings – Nicor Gas" herein for additional information regarding the Illinois Commission's disallowance of certain capital investments.

Any further cost disallowances by the Illinois Commission in the pending cases could be material to the financial statements of Southern Company Gas. The ultimate outcome of these matters cannot be determined at this time.

Natural Gas Cost Recovery

With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. The natural gas distribution utilities defer or accrue the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. Natural gas costs generally do not have a significant effect on Southern Company's or Southern Company Gas' net income but could have a significant effect on cash flows. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it does not utilize a traditional natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain natural gas inventory for the Marketers in Georgia and recovers the cost through recovery mechanisms approved by the Georgia PSC. At December 31, 2025 and 2024, the over recovered balance was $158 million and $193 million, respectively, which is included in natural gas cost over recovery on Southern Company's and Southern Company Gas' balance sheets.

Rate Proceedings

Nicor Gas

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

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 the Investing in Illinois program and $96 million for other transmission and distribution capital investments. Nicor Gas recorded a pre-tax charge to income in 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. See "Infrastructure Replacement Programs and Capital Projects – Nicor Gas" herein for additional information regarding the Illinois Commission's disallowance of certain capital investments. 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.

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.

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

Atlanta Gas Light

The Georgia PSC evaluates Atlanta Gas Light's earnings against an ROE range of 10.05% to 10.45%, with disposition of any earnings above 10.45% to be determined by the Georgia PSC. Additionally, the Georgia PSC allows inclusion in base rates of the recovery of and return on the infrastructure program investments, including, but not limited to, GRAM adjustments. GRAM filing rate adjustments are based on an authorized ROE of 10.25%.

In 2021, Atlanta Gas Light filed its i-CDP with the Georgia PSC, which included a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2022 through 2031), as well as the required capital investments and related costs to implement the programs. The i-CDP reflected capital investments totaling approximately $0.5 billion to $0.6 billion annually.

Also in 2021, the Georgia PSC approved a stipulation between Atlanta Gas Light and the staff of the Georgia PSC, under which, for the years 2022 through 2024, Atlanta Gas Light would incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, which resulted in a reduction of $7 million for 2023 and $9 million for 2024. The stipulation also provided for $1.7 billion of total capital investment for the years 2022 through 2024.

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

GRAM filing, which included annual base rate increases of $72 million, $73 million, and $74 million effective January 1, 2025, 2026, and 2027, respectively.

In July 2024, the Georgia PSC approved a stipulation related to Atlanta Gas Light's 2024 i-CDP, which included a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2025 through 2034), as well as the required capital investments and related cost to implement the programs. The i-CDP allows capital investments totaling approximately $0.6 billion annually for the years 2025 through 2027 with related revenue requirement recovery through either the annual GRAM filing or the System Reinforcement Rider surcharge adjustment. Additionally, the Georgia PSC approved a surcharge recovery mechanism for capital projects related to municipal, county, and Georgia Department of Transportation infrastructure work. Rate changes associated with the new surcharge will be based on requests filed annually on September 1. If approved, new rates will become effective January 1 of the following year.

Virginia Natural Gas

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

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.

Unrecognized Ratemaking Amounts

The following table illustrates Southern Company Gas' authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily comprised of an allowed equity rate of return on assets associated with certain regulatory infrastructure programs. These amounts will be recognized as revenues in Southern Company Gas' financial statements in the periods they are billable to customers, the majority of which will be recovered by 2027.

	December 31, 2025		December 31, 2024
	(in millions)
Atlanta Gas Light	$	4	$	11
Virginia Natural Gas	9		10
Chattanooga Gas	7		7
Total	$	20	$	28