filings.toolsItem 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of The Southern Company and Subsidiary Companies
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of The Southern Company and Subsidiary Companies (Southern Company) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2025, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited Southern Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Southern Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, Southern Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.
Basis for Opinions
Southern Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on Southern Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective,
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or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters) to the financial statements
Critical Audit Matter Description
Southern Company's traditional electric operating companies and natural gas distribution utilities (the "regulated utility subsidiaries") are subject to rate regulation by their respective state Public Service Commissions or other applicable state regulatory agencies and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the "Commissions"). Management has determined that the regulated utility subsidiaries meet the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
The Commissions set the rates the regulated utility subsidiaries are permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of the applicable regulated utility subsidiary's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Southern Company's regulated utility subsidiaries expect to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
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We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates. We also tested the effectiveness of management's controls over the initial recognition of certain regulatory assets or liabilities.
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We read and evaluated relevant regulatory orders issued and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
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We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
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We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
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We evaluated Southern Company's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 18, 2026
We have served as Southern Company's auditor since 2002.
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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Southern Company and Subsidiary Companies
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Retail electric revenues | $ | 19,331 | $ | 17,790 | $ | 16,343 | |||||||||||
| Wholesale electric revenues | 2,941 | 2,431 | 2,467 | ||||||||||||||
| Other electric revenues | 953 | 896 | 792 | ||||||||||||||
| Natural gas revenues | 5,044 | 4,456 | 4,702 | ||||||||||||||
| Other revenues | 1,284 | 1,151 | 949 | ||||||||||||||
| Total operating revenues | 29,553 | 26,724 | 25,253 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 4,897 | 4,096 | 4,365 | ||||||||||||||
| Purchased power | 980 | 883 | 883 | ||||||||||||||
| Cost of natural gas | 1,599 | 1,196 | 1,644 | ||||||||||||||
| Cost of other sales | 687 | 668 | 560 | ||||||||||||||
| Other operations and maintenance | 7,066 | 6,518 | 6,025 | ||||||||||||||
| Depreciation and amortization | 5,501 | 4,755 | 4,525 | ||||||||||||||
| Taxes other than income taxes | 1,538 | 1,540 | 1,425 | ||||||||||||||
| Total operating expenses | 22,268 | 19,656 | 19,427 | ||||||||||||||
| Operating Income | 7,285 | 7,068 | 5,826 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Allowance for equity funds used during construction | 340 | 235 | 268 | ||||||||||||||
| Earnings from equity method investments | 112 | 139 | 144 | ||||||||||||||
| Interest expense, net of amounts capitalized | (3,238) | (2,743) | (2,446) | ||||||||||||||
| Other income (expense), net | 500 | 530 | 553 | ||||||||||||||
| Total other income and (expense) | (2,286) | (1,839) | (1,481) | ||||||||||||||
| Earnings Before Income Taxes | 4,999 | 5,229 | 4,345 | ||||||||||||||
| Income taxes | 828 | 969 | 496 | ||||||||||||||
| Consolidated Net Income | 4,171 | 4,260 | 3,849 | ||||||||||||||
| Net loss attributable to noncontrolling interests | (170) | (141) | (127) | ||||||||||||||
| Consolidated Net Income Attributable to Southern Company | $ | 4,341 | $ | 4,401 | $ | 3,976 | |||||||||||
| Common Stock Data: | |||||||||||||||||
| Earnings per share — | |||||||||||||||||
| Basic | $ | 3.94 | $ | 4.02 | $ | 3.64 | |||||||||||
| Diluted | 3.92 | 3.99 | 3.62 | ||||||||||||||
| Average number of shares of common stock outstanding — (in millions) | |||||||||||||||||
| Basic | 1,103 | 1,096 | 1,092 | ||||||||||||||
| Diluted | 1,109 | 1,102 | 1,098 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Southern Company and Subsidiary Companies
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Consolidated Net Income | $ | 4,171 | $ | 4,260 | $ | 3,849 | |||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Changes in fair value, net of tax of $8, $(2), and $(17), respectively | 26 | (5) | (41) | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $(10), $28, and $27, respectively | (33) | 80 | 69 | ||||||||||||||
| Pension and other postretirement benefit plans: | |||||||||||||||||
| Benefit plan net gain (loss), net of tax of $4, $10, and $(14), respectively | 10 | 23 | (39) | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $—, $—, and $—, respectively | — | 1 | 1 | ||||||||||||||
| Total other comprehensive income (loss) | 3 | 99 | (10) | ||||||||||||||
| Comprehensive loss attributable to noncontrolling interests | (170) | (141) | (127) | ||||||||||||||
| Consolidated Comprehensive Income Attributable to Southern Company | $ | 4,344 | $ | 4,500 | $ | 3,966 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2025, 2024, and 2023
Southern Company and Subsidiary Companies
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Consolidated net income | $ | 4,171 | $ | 4,260 | $ | 3,849 | |||||||||||
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 6,030 | 5,266 | 4,986 | ||||||||||||||
| Deferred income taxes | 618 | 626 | 416 | ||||||||||||||
| Allowance for equity funds used during construction | (340) | (235) | (268) | ||||||||||||||
| Pension, postretirement, and other employee benefits | (579) | (556) | (527) | ||||||||||||||
| Settlement of asset retirement obligations | (634) | (566) | (617) | ||||||||||||||
| Storm damage and reliability reserve accruals | 236 | 163 | 124 | ||||||||||||||
| Stock based compensation expense | 136 | 132 | 137 | ||||||||||||||
| Loss on extinguishment of debt | 252 | — | — | ||||||||||||||
| Retail fuel cost under recovery – long-term | (176) | (32) | (206) | ||||||||||||||
| Storm damage cost recovery – long-term | (275) | (631) | — | ||||||||||||||
| Other, net | (36) | (60) | (206) | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | (124) | (372) | 482 | ||||||||||||||
| -Retail fuel cost under recovery | 645 | 984 | 686 | ||||||||||||||
| -Fossil fuel for generation | 68 | 140 | (368) | ||||||||||||||
| -Materials and supplies | (24) | (189) | (345) | ||||||||||||||
| -Natural gas cost under recovery | — | — | 108 | ||||||||||||||
| -Other current assets | 47 | (47) | (106) | ||||||||||||||
| -Accounts payable | (290) | 492 | (863) | ||||||||||||||
| -Accrued interest | 125 | 30 | 42 | ||||||||||||||
| -Accrued taxes | (36) | 206 | 23 | ||||||||||||||
| -Customer refunds | (75) | 83 | (157) | ||||||||||||||
| -Natural gas cost over recovery | (36) | (21) | 214 | ||||||||||||||
| -Other current liabilities | 99 | 115 | 149 | ||||||||||||||
| Net cash provided from operating activities | 9,802 | 9,788 | 7,553 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Property additions | (12,737) | (8,955) | (9,095) | ||||||||||||||
| Business acquisition | (635) | — | — | ||||||||||||||
| Nuclear decommissioning trust fund purchases | (1,702) | (1,551) | (1,142) | ||||||||||||||
| Nuclear decommissioning trust fund sales | 1,685 | 1,535 | 1,121 | ||||||||||||||
| Proceeds from dispositions | 1 | 369 | 164 | ||||||||||||||
| Cost of removal, net of salvage | (655) | (632) | (592) | ||||||||||||||
| Change in construction payables, net | 301 | 106 | 18 | ||||||||||||||
| Payments pursuant to LTSAs | (159) | (108) | (99) | ||||||||||||||
| Other investing activities | (58) | (164) | (43) | ||||||||||||||
| Net cash used for investing activities | (13,959) | (9,400) | (9,668) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Increase (decrease) in notes payable, net | (414) | (648) | 973 | ||||||||||||||
| Proceeds — | |||||||||||||||||
| Long-term debt | 12,470 | 6,159 | 8,972 | ||||||||||||||
| Short-term borrowings | 200 | 700 | 350 | ||||||||||||||
| Common stock | 1,623 | 143 | 36 | ||||||||||||||
| Redemptions and repurchases — | |||||||||||||||||
| Long-term debt | (5,464) | (2,222) | (4,294) | ||||||||||||||
| Short-term borrowings | — | (1,020) | (1,630) | ||||||||||||||
| Distributions to noncontrolling interests | (200) | (185) | (234) | ||||||||||||||
| Purchase of membership interests from noncontrolling interests | (286) | — | — | ||||||||||||||
| Payment of common stock dividends | (3,015) | (2,954) | (3,035) | ||||||||||||||
| Other financing activities | (218) | (181) | (139) | ||||||||||||||
| Net cash provided from (used for) financing activities | 4,696 | (208) | 999 | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 539 | 180 | (1,116) | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 1,101 | 921 | 2,037 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 1,640 | $ | 1,101 | $ | 921 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid during the period for — | |||||||||||||||||
| Interest (net of $140, $103, and $132 capitalized, respectively) | $ | 2,692 | $ | 2,538 | $ | 2,184 | |||||||||||
| Income taxes, net (excludes credit transfers) | 284 | 176 | 132 | ||||||||||||||
| Noncash transactions — | |||||||||||||||||
| Accrued property additions at year-end | 1,473 | 1,199 | 1,027 | ||||||||||||||
| LTSA credits utilized from the sale of spare parts | 6 | 13 | 23 | ||||||||||||||
| Issuance of common stock under dividend reinvestment plan | 222 | 179 | — | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2025 and 2024
Southern Company and Subsidiary Companies
| Assets | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 1,639 | $ | 1,070 | |||||||
| Receivables — | |||||||||||
| Customer accounts | 2,251 | 2,228 | |||||||||
| Unbilled revenues | 931 | 825 | |||||||||
| Under recovered fuel clause revenues | 316 | 713 | |||||||||
| Other accounts and notes | 655 | 597 | |||||||||
| Accumulated provision for uncollectible accounts | (84) | (74) | |||||||||
| Materials and supplies | 2,202 | 2,178 | |||||||||
| Fossil fuel for generation | 735 | 803 | |||||||||
| Natural gas for sale | 396 | 388 | |||||||||
| Prepaid expenses | 327 | 294 | |||||||||
| Assets from risk management activities, net of collateral | 63 | 39 | |||||||||
| Regulatory assets – asset retirement obligations | 353 | 353 | |||||||||
| Other regulatory assets | 709 | 804 | |||||||||
| Other current assets | 424 | 476 | |||||||||
| Total current assets | 10,917 | 10,694 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 146,114 | 137,143 | |||||||||
| Less: Accumulated depreciation | 43,483 | 40,126 | |||||||||
| Plant in service, net of depreciation | 102,631 | 97,017 | |||||||||
| Other utility plant, net | 307 | 410 | |||||||||
| Nuclear fuel, at amortized cost | 897 | 873 | |||||||||
| Construction work in progress | 10,534 | 6,389 | |||||||||
| Total property, plant, and equipment | 114,369 | 104,689 | |||||||||
| Other Property and Investments: | |||||||||||
| Goodwill | 5,161 | 5,161 | |||||||||
| Nuclear decommissioning trusts, at fair value | 2,947 | 2,621 | |||||||||
| Equity investments in unconsolidated subsidiaries | 1,318 | 1,416 | |||||||||
| Other intangible assets, net of amortization of $444 and $412, respectively | 300 | 332 | |||||||||
| Miscellaneous property and investments | 714 | 668 | |||||||||
| Total other property and investments | 10,440 | 10,198 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Operating lease right-of-use assets, net of amortization | 1,358 | 1,386 | |||||||||
| Deferred charges related to income taxes | 948 | 889 | |||||||||
| Prepaid pension costs | 3,257 | 2,674 | |||||||||
| Unamortized loss on reacquired debt | 187 | 203 | |||||||||
| Deferred under recovered retail fuel clause revenues | 252 | 485 | |||||||||
| Regulatory assets – asset retirement obligations, deferred | 5,129 | 5,458 | |||||||||
| Other regulatory assets, deferred | 7,427 | 7,037 | |||||||||
| Other deferred charges and assets | 1,436 | 1,467 | |||||||||
| Total deferred charges and other assets | 19,994 | 19,599 | |||||||||
| Total Assets | $ | 155,720 | $ | 145,180 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2025 and 2024
Southern Company and Subsidiary Companies
| Liabilities and Stockholders' Equity | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 6,220 | $ | 4,718 | |||||||
| Notes payable | 722 | 1,338 | |||||||||
| Accounts payable | 3,710 | 3,701 | |||||||||
| Customer deposits | 475 | 486 | |||||||||
| Accrued taxes — | |||||||||||
| Accrued income taxes | 22 | 57 | |||||||||
| Other accrued taxes | 982 | 997 | |||||||||
| Accrued interest | 807 | 682 | |||||||||
| Accrued compensation | 1,418 | 1,261 | |||||||||
| Asset retirement obligations | 662 | 731 | |||||||||
| Liabilities from risk management activities, net of collateral | 118 | 160 | |||||||||
| Operating lease obligations | 197 | 200 | |||||||||
| Natural gas cost over recovery | 158 | 193 | |||||||||
| Other regulatory liabilities | 240 | 369 | |||||||||
| Other current liabilities | 1,157 | 1,100 | |||||||||
| Total current liabilities | 16,888 | 15,993 | |||||||||
| Long-Term Debt | 65,649 | 58,768 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 12,133 | 11,730 | |||||||||
| Deferred credits related to income taxes | 4,712 | 4,434 | |||||||||
| Accumulated deferred ITCs | 2,002 | 2,056 | |||||||||
| Employee benefit obligations | 980 | 1,011 | |||||||||
| Operating lease obligations, deferred | 1,287 | 1,253 | |||||||||
| Asset retirement obligations, deferred | 8,939 | 9,203 | |||||||||
| Other cost of removal obligations | 2,036 | 2,016 | |||||||||
| Other regulatory liabilities, deferred | 722 | 692 | |||||||||
| Other deferred credits and liabilities | 1,505 | 1,350 | |||||||||
| Total deferred credits and other liabilities | 34,316 | 33,745 | |||||||||
| Total Liabilities | 116,853 | 108,506 | |||||||||
| Common Stockholders' Equity: | |||||||||||
| Common stock, par value $5 per share (Authorized - 1.5 billion shares) | 5,554 | 5,446 | |||||||||
| (Issued - 1.1 billion shares; Treasury - 1.0 million shares) | |||||||||||
| Paid-in capital | 15,740 | 14,149 | |||||||||
| Treasury, at cost | (59) | (59) | |||||||||
| Retained earnings | 14,856 | 13,750 | |||||||||
| Accumulated other comprehensive loss | (75) | (78) | |||||||||
| Total common stockholders' equity | 36,016 | 33,208 | |||||||||
| Noncontrolling interests | 2,851 | 3,466 | |||||||||
| Total Stockholders' Equity (See accompanying statements) | 38,867 | 36,674 | |||||||||
| Total Liabilities and Stockholders' Equity | $ | 155,720 | $ | 145,180 | |||||||
| Commitments and Contingent Matters (See notes) |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2025, 2024, and 2023
Southern Company and Subsidiary Companies
| Southern Company Common Stockholders' Equity | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Number of Common Shares | Common Stock | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Issued | Treasury | Par Value | Paid-In Capital | Treasury | Retained Earnings | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | 1,090 | (1) | $ | 5,417 | $ | 13,673 | $ | (53) | $ | 11,538 | $ | (167) | $ | 4,124 | $ | 34,532 | |||||||||||||||||||||||||||||||||||||||||||
| Consolidated net income (loss) | — | — | — | — | — | 3,976 | — | (127) | 3,849 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | — | — | (10) | — | (10) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock issued | 2 | — | 6 | 30 | — | — | — | — | 36 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | 73 | — | — | — | — | 73 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends of $2.7800 per share | — | — | — | — | — | (3,035) | — | — | (3,035) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Capital contributions from noncontrolling interests | — | — | — | — | — | — | — | 21 | 21 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (236) | (236) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | (1) | (6) | 3 | — | (1) | (5) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2023 | 1,092 | (1) | 5,423 | 13,775 | (59) | 12,482 | (177) | 3,781 | 35,225 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Consolidated net income (loss) | — | — | — | — | — | 4,401 | — | (141) | 4,260 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | — | 99 | — | 99 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock issued | 6 | — | 23 | 299 | — | — | — | — | 322 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | 56 | — | — | — | — | 56 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends of $2.8600 per share | — | — | — | — | — | (3,133) | — | — | (3,133) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Capital contributions from noncontrolling interests | — | — | — | — | — | — | — | 11 | 11 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (185) | (185) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | 19 | — | — | — | — | 19 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2024 | 1,098 | (1) | 5,446 | 14,149 | (59) | 13,750 | (78) | 3,466 | 36,674 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Consolidated net income (loss) | — | — | — | — | — | 4,341 | — | (170) | 4,171 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | — | 3 | — | 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of equity units(*) | — | — | — | (173) | — | — | — | — | (173) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock issued | 22 | — | 107 | 1,738 | — | — | — | — | 1,845 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | 48 | — | — | — | — | 48 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends of $2.9400 per share | — | — | — | — | — | (3,237) | — | — | (3,237) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Capital contributions from noncontrolling interests | — | — | — | — | — | — | — | 23 | 23 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (202) | (202) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Purchase of membership interests from noncontrolling interests | — | — | — | (16) | — | — | — | (267) | (283) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | 1 | (6) | — | 2 | — | 1 | (2) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2025 | 1,120 | (1) | $ | 5,554 | $ | 15,740 | $ | (59) | $ | 14,856 | $ | (75) | $ | 2,851 | $ | 38,867 |
(*) See Note 8 under "Equity Units" for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Alabama Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Alabama Power Company (Alabama Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2025 and 2024, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2025, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Alabama Power as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Alabama Power's management. Our responsibility is to express an opinion on Alabama Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Alabama Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Alabama Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Alabama Power's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters – Alabama Power) to the financial statements
Critical Audit Matter Description
Alabama Power is subject to retail rate regulation by the Alabama Public Service Commission and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the "Commissions"). Management has determined that it meets the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
The Commissions set the rates Alabama Power is permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of Alabama Power's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Alabama Power expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
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We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
-
We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates. We also tested the effectiveness of management's controls over the initial recognition of certain regulatory assets or liabilities.
-
We read and evaluated relevant regulatory orders issued and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
-
We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
-
We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
-
We evaluated Alabama Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 18, 2026
We have served as Alabama Power's auditor since 2002.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Alabama Power Company
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Retail revenues | $ | 7,136 | $ | 6,639 | $ | 6,159 | |||||||||||
| Wholesale revenues, non-affiliates | 449 | 337 | 424 | ||||||||||||||
| Wholesale revenues, affiliates | 188 | 139 | 60 | ||||||||||||||
| Other revenues | 462 | 439 | 407 | ||||||||||||||
| Total operating revenues | 8,235 | 7,554 | 7,050 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 1,524 | 1,358 | 1,299 | ||||||||||||||
| Purchased power, non-affiliates | 235 | 199 | 253 | ||||||||||||||
| Purchased power, affiliates | 273 | 175 | 251 | ||||||||||||||
| Other operations and maintenance | 2,026 | 1,895 | 1,769 | ||||||||||||||
| Depreciation and amortization | 1,510 | 1,459 | 1,401 | ||||||||||||||
| Taxes other than income taxes | 498 | 471 | 442 | ||||||||||||||
| Total operating expenses | 6,066 | 5,557 | 5,415 | ||||||||||||||
| Operating Income | 2,169 | 1,997 | 1,635 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Allowance for equity funds used during construction | 69 | 57 | 82 | ||||||||||||||
| Interest expense, net of amounts capitalized | (465) | (448) | (425) | ||||||||||||||
| Other income (expense), net | 168 | 157 | 159 | ||||||||||||||
| Total other income and (expense) | (228) | (234) | (184) | ||||||||||||||
| Earnings Before Income Taxes | 1,941 | 1,763 | 1,451 | ||||||||||||||
| Income taxes | 425 | 360 | 81 | ||||||||||||||
| Net Income | $ | 1,516 | $ | 1,403 | $ | 1,370 | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Alabama Power Company
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Net Income | $ | 1,516 | $ | 1,403 | $ | 1,370 | |||||||||||
| Other comprehensive income: | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $1, respectively | 2 | 2 | 2 | ||||||||||||||
| Total other comprehensive income | 2 | 2 | 2 | ||||||||||||||
| Comprehensive Income | $ | 1,518 | $ | 1,405 | $ | 1,372 |
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2025, 2024, and 2023
Alabama Power Company
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Net income | $ | 1,516 | $ | 1,403 | $ | 1,370 | |||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 1,654 | 1,608 | 1,554 | ||||||||||||||
| Deferred income taxes | 220 | (55) | (242) | ||||||||||||||
| Allowance for equity funds used during construction | (69) | (57) | (82) | ||||||||||||||
| Pension, postretirement, and other employee benefits | (211) | (213) | (204) | ||||||||||||||
| Settlement of asset retirement obligations | (269) | (254) | (270) | ||||||||||||||
| Natural disaster reserve and reliability reserve accruals | 179 | 96 | 70 | ||||||||||||||
| Retail fuel cost under recovery – long-term | (146) | — | — | ||||||||||||||
| Other, net | (55) | 103 | 4 | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | (34) | (32) | (24) | ||||||||||||||
| -Fossil fuel stock | 36 | 55 | (165) | ||||||||||||||
| -Materials and supplies | (29) | (57) | (105) | ||||||||||||||
| -Retail fuel cost under recovery | — | 246 | 376 | ||||||||||||||
| -Other current assets | 18 | (32) | (20) | ||||||||||||||
| -Accounts payable | (99) | (127) | (162) | ||||||||||||||
| -Customer refunds | (108) | 87 | (39) | ||||||||||||||
| -Other current liabilities | (31) | 124 | 18 | ||||||||||||||
| Net cash provided from operating activities | 2,572 | 2,895 | 2,079 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Property additions | (1,935) | (1,881) | (2,022) | ||||||||||||||
| Business acquisition | (635) | — | — | ||||||||||||||
| Nuclear decommissioning trust fund purchases | (564) | (593) | (301) | ||||||||||||||
| Nuclear decommissioning trust fund sales | 564 | 592 | 300 | ||||||||||||||
| Cost of removal net of salvage | (175) | (166) | (178) | ||||||||||||||
| Change in construction payables, net of joint owner portion | (48) | 10 | (44) | ||||||||||||||
| Other investing activities | (21) | 51 | 49 | ||||||||||||||
| Net cash used for investing activities | (2,814) | (1,987) | (2,196) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Increase (decrease) in notes payable, net | — | (40) | 40 | ||||||||||||||
| Proceeds — | |||||||||||||||||
| Senior notes | 1,100 | — | 500 | ||||||||||||||
| Revenue bonds | — | — | 326 | ||||||||||||||
| Short-term borrowings | — | 50 | — | ||||||||||||||
| Other long-term debt | 5 | 8 | 29 | ||||||||||||||
| Redemptions and repurchases — | |||||||||||||||||
| Senior notes | (250) | — | (300) | ||||||||||||||
| Revenue bonds | — | (21) | — | ||||||||||||||
| Short-term borrowings | — | (50) | — | ||||||||||||||
| Other long-term debt | (1) | (22) | — | ||||||||||||||
| Capital contributions from parent company | 601 | 527 | 407 | ||||||||||||||
| Payment of common stock dividends | (1,219) | (1,182) | (1,141) | ||||||||||||||
| Other financing activities | (13) | (2) | (22) | ||||||||||||||
| Net cash provided from (used for) financing activities | 223 | (732) | (161) | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (19) | 176 | (278) | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 585 | 409 | 687 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 566 | $ | 585 | $ | 409 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid during the period for — | |||||||||||||||||
| Interest (net of $20, $18, and $27 capitalized, respectively) | $ | 431 | $ | 428 | $ | 397 | |||||||||||
| Income taxes, net | 243 | 387 | 315 | ||||||||||||||
| Noncash transactions — Accrued property additions at year-end | 100 | 148 | 138 | ||||||||||||||
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2025 and 2024
Alabama Power Company
| Assets | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 566 | $ | 585 | |||||||
| Receivables — | |||||||||||
| Customer accounts | 470 | 512 | |||||||||
| Unbilled revenues | 189 | 187 | |||||||||
| Affiliated | 126 | 91 | |||||||||
| Other accounts and notes | 113 | 126 | |||||||||
| Accumulated provision for uncollectible accounts | (23) | (22) | |||||||||
| Fossil fuel stock | 303 | 339 | |||||||||
| Materials and supplies | 732 | 699 | |||||||||
| Prepaid expenses | 86 | 63 | |||||||||
| Other regulatory assets | 344 | 332 | |||||||||
| Other current assets | 80 | 79 | |||||||||
| Total current assets | 2,986 | 2,991 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 38,915 | 36,501 | |||||||||
| Less: Accumulated provision for depreciation | 12,816 | 11,741 | |||||||||
| Plant in service, net of depreciation | 26,099 | 24,760 | |||||||||
| Other utility plant, net | 307 | 410 | |||||||||
| Nuclear fuel, at amortized cost | 290 | 262 | |||||||||
| Construction work in progress | 1,441 | 1,377 | |||||||||
| Total property, plant, and equipment | 28,137 | 26,809 | |||||||||
| Other Property and Investments: | |||||||||||
| Nuclear decommissioning trusts, at fair value | 1,542 | 1,386 | |||||||||
| Equity investments in unconsolidated subsidiaries | 48 | 48 | |||||||||
| Miscellaneous property and investments | 123 | 129 | |||||||||
| Total other property and investments | 1,713 | 1,563 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Operating lease right-of-use assets, net of amortization | 86 | 84 | |||||||||
| Deferred charges related to income taxes | 261 | 264 | |||||||||
| Prepaid pension and other postretirement benefit costs | 1,016 | 841 | |||||||||
| Regulatory assets – asset retirement obligations | 1,518 | 1,780 | |||||||||
| Other regulatory assets, deferred | 1,982 | 1,815 | |||||||||
| Other deferred charges and assets | 425 | 391 | |||||||||
| Total deferred charges and other assets | 5,288 | 5,175 | |||||||||
| Total Assets | $ | 38,124 | $ | 36,538 |
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2025 and 2024
Alabama Power Company
| Liabilities and Stockholder's Equity | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 625 | $ | 655 | |||||||
| Accounts payable — | |||||||||||
| Affiliated | 294 | 299 | |||||||||
| Other | 576 | 625 | |||||||||
| Customer deposits | 113 | 113 | |||||||||
| Accrued taxes | 105 | 78 | |||||||||
| Accrued interest | 134 | 120 | |||||||||
| Accrued compensation | 275 | 240 | |||||||||
| Asset retirement obligations | 256 | 364 | |||||||||
| Other regulatory liabilities | 89 | 165 | |||||||||
| Other current liabilities | 135 | 219 | |||||||||
| Total current liabilities | 2,602 | 2,878 | |||||||||
| Long-Term Debt | 11,388 | 10,499 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 4,209 | 4,178 | |||||||||
| Deferred credits related to income taxes | 1,585 | 1,398 | |||||||||
| Accumulated deferred ITCs | 115 | 113 | |||||||||
| Employee benefit obligations | 152 | 148 | |||||||||
| Operating lease obligations | 78 | 76 | |||||||||
| Asset retirement obligations, deferred | 3,423 | 3,694 | |||||||||
| Other regulatory liabilities, deferred | 252 | 271 | |||||||||
| Other deferred credits and liabilities | 326 | 195 | |||||||||
| Total deferred credits and other liabilities | 10,140 | 10,073 | |||||||||
| Total Liabilities | 24,130 | 23,450 | |||||||||
| Common Stockholder's Equity: | |||||||||||
| Common stock, par value $40 per share (Authorized - 40 million shares; Outstanding - 31 million shares) | 1,222 | 1,222 | |||||||||
| Paid-in capital | 8,263 | 7,657 | |||||||||
| Retained earnings | 4,512 | 4,214 | |||||||||
| Accumulated other comprehensive loss | (3) | (5) | |||||||||
| Total common stockholder's equity (See accompanying statements) | 13,994 | 13,088 | |||||||||
| Total Liabilities and Stockholder's Equity | $ | 38,124 | $ | 36,538 | |||||||
| Commitments and Contingent Matters (See notes) |
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2025, 2024, and 2023
Alabama Power Company
| Number of Common Shares Issued | Common Stock | Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | 31 | $ | 1,222 | $ | 6,710 | $ | 3,764 | $ | (9) | $ | 11,687 | ||||||||||||||||||||||||
| Net income | — | — | — | 1,370 | — | 1,370 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 415 | — | — | 415 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 2 | 2 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (1,141) | — | (1,141) | |||||||||||||||||||||||||||||
| Balance at December 31, 2023 | 31 | 1,222 | 7,125 | 3,993 | (7) | 12,333 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 1,403 | — | 1,403 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 532 | — | — | 532 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 2 | 2 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (1,182) | — | (1,182) | |||||||||||||||||||||||||||||
| Balance at December 31, 2024 | 31 | 1,222 | 7,657 | 4,214 | (5) | 13,088 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 1,516 | — | 1,516 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 606 | — | — | 606 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 2 | 2 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (1,219) | — | (1,219) | |||||||||||||||||||||||||||||
| Other | — | — | — | 1 | — | 1 | |||||||||||||||||||||||||||||
| Balance at December 31, 2025 | 31 | $ | 1,222 | $ | 8,263 | $ | 4,512 | $ | (3) | $ | 13,994 |
The accompanying notes are an integral part of these financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Georgia Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Georgia Power Company (Georgia Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2025 and 2024, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2025, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Georgia Power as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Georgia Power's management. Our responsibility is to express an opinion on Georgia Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Georgia Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Georgia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Georgia Power's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters – Georgia Power) to the financial statements
Critical Audit Matter Description
Georgia Power is subject to retail rate regulation by the Georgia Public Service Commission and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the "Commissions"). Management has determined that it meets the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
The Commissions set the rates Georgia Power is permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of Georgia Power's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Georgia Power expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
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We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
-
We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates. We also tested the effectiveness of management's controls over the initial recognition of certain regulatory assets or liabilities.
-
We read and evaluated relevant regulatory orders issued and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
-
We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
-
We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
-
We evaluated Georgia Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 18, 2026
We have served as Georgia Power's auditor since 2002.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Georgia Power Company
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Retail revenues | $ | 11,110 | $ | 10,187 | $ | 9,222 | |||||||||||
| Wholesale revenues | 525 | 265 | 188 | ||||||||||||||
| Other revenues | 996 | 879 | 708 | ||||||||||||||
| Total operating revenues | 12,631 | 11,331 | 10,118 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 2,040 | 1,658 | 1,781 | ||||||||||||||
| Purchased power, non-affiliates | 659 | 615 | 517 | ||||||||||||||
| Purchased power, affiliates | 858 | 745 | 764 | ||||||||||||||
| Other operations and maintenance | 2,585 | 2,351 | 2,015 | ||||||||||||||
| Depreciation and amortization | 2,074 | 1,774 | 1,681 | ||||||||||||||
| Taxes other than income taxes | 576 | 647 | 541 | ||||||||||||||
| Total operating expenses | 8,792 | 7,790 | 7,299 | ||||||||||||||
| Operating Income | 3,839 | 3,541 | 2,819 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Allowance for equity funds used during construction | 248 | 152 | 165 | ||||||||||||||
| Interest expense, net of amounts capitalized | (793) | (725) | (626) | ||||||||||||||
| Other income (expense), net | 159 | 178 | 170 | ||||||||||||||
| Total other income and (expense) | (386) | (395) | (291) | ||||||||||||||
| Earnings Before Income Taxes | 3,453 | 3,146 | 2,528 | ||||||||||||||
| Income taxes | 602 | 603 | 448 | ||||||||||||||
| Net Income | $ | 2,851 | $ | 2,543 | $ | 2,080 | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Georgia Power Company
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Net Income | $ | 2,851 | $ | 2,543 | $ | 2,080 | |||||||||||
| Other comprehensive income: | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Changes in fair value, net of tax of $1, $6, and $(1), respectively | 3 | 18 | (2) | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $—, $1, and $2, respectively | 1 | 4 | 5 | ||||||||||||||
| Total other comprehensive income | 4 | 22 | 3 | ||||||||||||||
| Comprehensive Income | $ | 2,855 | $ | 2,565 | $ | 2,083 |
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2025, 2024, and 2023
Georgia Power Company
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Net income | $ | 2,851 | $ | 2,543 | $ | 2,080 | |||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 2,376 | 2,080 | 1,914 | ||||||||||||||
| Deferred income taxes | 493 | 380 | 206 | ||||||||||||||
| Allowance for equity funds used during construction | (248) | (152) | (165) | ||||||||||||||
| Pension, postretirement, and other employee benefits | (289) | (288) | (272) | ||||||||||||||
| Settlement of asset retirement obligations | (321) | (270) | (304) | ||||||||||||||
| Retail fuel cost under recovery – long-term | — | — | (157) | ||||||||||||||
| Storm damage cost recovery – long-term | (275) | (631) | — | ||||||||||||||
| Other, net | (95) | (145) | (141) | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | 33 | (268) | (57) | ||||||||||||||
| -Retail fuel cost under recovery | 645 | 738 | 308 | ||||||||||||||
| -Fossil fuel stock | 22 | 96 | (189) | ||||||||||||||
| -Materials and supplies | (32) | (81) | (154) | ||||||||||||||
| -Other current assets | (58) | (51) | (63) | ||||||||||||||
| -Accounts payable | (347) | 633 | (206) | ||||||||||||||
| -Accrued taxes | (125) | 212 | 74 | ||||||||||||||
| -Customer refunds | 33 | (4) | (117) | ||||||||||||||
| -Other current liabilities | 145 | 1 | (5) | ||||||||||||||
| Net cash provided from operating activities | 4,808 | 4,793 | 2,752 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Property additions | (7,792) | (4,816) | (4,786) | ||||||||||||||
| Nuclear decommissioning trust fund purchases | (1,137) | (958) | (841) | ||||||||||||||
| Nuclear decommissioning trust fund sales | 1,122 | 942 | 821 | ||||||||||||||
| Cost of removal, net of salvage | (324) | (336) | (279) | ||||||||||||||
| Change in construction payables, net of joint owner portion | 358 | 68 | 50 | ||||||||||||||
| Payments pursuant to LTSAs | (62) | (74) | (49) | ||||||||||||||
| Proceeds from dispositions | — | 357 | 59 | ||||||||||||||
| Other investing activities | (98) | (79) | (54) | ||||||||||||||
| Net cash used for investing activities | (7,933) | (4,896) | (5,079) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Increase (decrease) in notes payable, net | 160 | (811) | 811 | ||||||||||||||
| Proceeds — | |||||||||||||||||
| Senior notes | 3,100 | 2,117 | 2,450 | ||||||||||||||
| Short-term borrowings | 200 | 350 | 350 | ||||||||||||||
| Revenue bonds | — | — | 229 | ||||||||||||||
| Redemptions and repurchases — | |||||||||||||||||
| Senior notes | (700) | (400) | (800) | ||||||||||||||
| Short-term borrowings | — | (670) | (1,430) | ||||||||||||||
| FFB loan | (86) | (86) | (86) | ||||||||||||||
| Revenue bonds | (45) | — | — | ||||||||||||||
| Capital contributions from parent company | 2,700 | 1,780 | 2,291 | ||||||||||||||
| Payment of common stock dividends | (2,209) | (2,051) | (1,855) | ||||||||||||||
| Other financing activities | (54) | (83) | (38) | ||||||||||||||
| Net cash provided from financing activities | 3,066 | 146 | 1,922 | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (59) | 43 | (405) | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 118 | 75 | 480 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 59 | $ | 118 | $ | 75 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid (received) during the period for — | |||||||||||||||||
| Interest (net of $78, $57, and $86 capitalized, respectively) | $ | 717 | $ | 680 | $ | 592 | |||||||||||
| Income taxes, net (excludes credit transfers) | 129 | (14) | 220 | ||||||||||||||
| Noncash transactions — Accrued property additions at year-end | 1,072 | 739 | 680 | ||||||||||||||
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2025 and 2024
Georgia Power Company
| Assets | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 59 | $ | 97 | |||||||
| Receivables — | |||||||||||
| Customer accounts, net | 993 | 985 | |||||||||
| Unbilled revenues | 346 | 341 | |||||||||
| Under recovered retail fuel clause revenues | 310 | 713 | |||||||||
| Joint owner accounts | 195 | 101 | |||||||||
| Affiliated | 96 | 65 | |||||||||
| Other accounts and notes | 61 | 92 | |||||||||
| Fossil fuel stock | 362 | 385 | |||||||||
| Materials and supplies | 994 | 968 | |||||||||
| Regulatory assets – asset retirement obligations | 222 | 222 | |||||||||
| Other regulatory assets | 335 | 373 | |||||||||
| Other current assets | 285 | 262 | |||||||||
| Total current assets | 4,258 | 4,604 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 59,458 | 55,036 | |||||||||
| Less: Accumulated provision for depreciation | 15,957 | 14,806 | |||||||||
| Plant in service, net of depreciation | 43,501 | 40,230 | |||||||||
| Nuclear fuel, at amortized cost | 606 | 611 | |||||||||
| Construction work in progress | 6,764 | 3,197 | |||||||||
| Total property, plant, and equipment | 50,871 | 44,038 | |||||||||
| Other Property and Investments: | |||||||||||
| Nuclear decommissioning trusts, at fair value | 1,405 | 1,236 | |||||||||
| Equity investments in unconsolidated subsidiaries | 40 | 43 | |||||||||
| Miscellaneous property and investments | 231 | 192 | |||||||||
| Total other property and investments | 1,676 | 1,471 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Operating lease right-of-use assets, net of amortization | 1,120 | 1,331 | |||||||||
| Deferred charges related to income taxes | 660 | 596 | |||||||||
| Prepaid pension costs | 1,099 | 897 | |||||||||
| Deferred under recovered retail fuel clause revenues | 212 | 453 | |||||||||
| Regulatory assets – asset retirement obligations, deferred | 3,382 | 3,436 | |||||||||
| Other regulatory assets, deferred | 4,032 | 3,814 | |||||||||
| Other deferred charges and assets | 767 | 615 | |||||||||
| Total deferred charges and other assets | 11,272 | 11,142 | |||||||||
| Total Assets | $ | 68,077 | $ | 61,255 |
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2025 and 2024
Georgia Power Company
| Liabilities and Stockholder's Equity | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 1,370 | $ | 966 | |||||||
| Notes payable | 160 | 200 | |||||||||
| Accounts payable — | |||||||||||
| Affiliated | 992 | 984 | |||||||||
| Other | 1,728 | 1,837 | |||||||||
| Customer deposits | 267 | 256 | |||||||||
| Accrued taxes | 678 | 803 | |||||||||
| Accrued interest | 234 | 190 | |||||||||
| Accrued compensation | 327 | 276 | |||||||||
| Operating lease obligations | 170 | 169 | |||||||||
| Asset retirement obligations | 360 | 309 | |||||||||
| Other regulatory liabilities | 52 | 150 | |||||||||
| Other current liabilities | 332 | 296 | |||||||||
| Total current liabilities | 6,670 | 6,436 | |||||||||
| Long-Term Debt | 20,122 | 17,384 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 4,811 | 4,385 | |||||||||
| Deferred credits related to income taxes | 2,225 | 2,047 | |||||||||
| Accumulated deferred ITCs | 354 | 343 | |||||||||
| Employee benefit obligations | 189 | 205 | |||||||||
| Operating lease obligations, deferred | 960 | 1,159 | |||||||||
| Asset retirement obligations, deferred | 5,167 | 5,106 | |||||||||
| Other deferred credits and liabilities | 545 | 509 | |||||||||
| Total deferred credits and other liabilities | 14,251 | 13,754 | |||||||||
| Total Liabilities | 41,043 | 37,574 | |||||||||
| Common Stockholder's Equity: | |||||||||||
| Common stock, without par value (Authorized - 20 million shares; Outstanding - 9 million shares) | 398 | 398 | |||||||||
| Paid-in capital | 22,416 | 19,708 | |||||||||
| Retained earnings | 4,204 | 3,562 | |||||||||
| Accumulated other comprehensive income | 16 | 13 | |||||||||
| Total common stockholder's equity (See accompanying statements) | 27,034 | 23,681 | |||||||||
| Total Liabilities and Stockholder's Equity | $ | 68,077 | $ | 61,255 | |||||||
| Commitments and Contingent Matters (See notes) |
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2025, 2024, and 2023
Georgia Power Company
| Number of Common Shares Issued | Common Stock | Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | 9 | $ | 398 | $ | 15,626 | $ | 2,846 | $ | (12) | $ | 18,858 | ||||||||||||||||||||||||
| Net income | — | — | — | 2,080 | — | 2,080 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 2,297 | — | — | 2,297 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 3 | 3 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (1,855) | — | (1,855) | |||||||||||||||||||||||||||||
| Balance at December 31, 2023 | 9 | 398 | 17,923 | 3,071 | (9) | 21,383 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 2,543 | — | 2,543 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 1,785 | — | — | 1,785 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 22 | 22 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (2,051) | — | (2,051) | |||||||||||||||||||||||||||||
| Other | — | — | — | (1) | — | (1) | |||||||||||||||||||||||||||||
| Balance at December 31, 2024 | 9 | 398 | 19,708 | 3,562 | 13 | 23,681 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 2,851 | — | 2,851 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 2,708 | — | — | 2,708 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 4 | 4 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (2,209) | — | (2,209) | |||||||||||||||||||||||||||||
| Other | — | — | — | — | (1) | (1) | |||||||||||||||||||||||||||||
| Balance at December 31, 2025 | 9 | $ | 398 | $ | 22,416 | $ | 4,204 | $ | 16 | $ | 27,034 |
The accompanying notes are an integral part of these financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Mississippi Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Mississippi Power Company (Mississippi Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2025 and 2024, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2025, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Mississippi Power as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Mississippi Power's management. Our responsibility is to express an opinion on Mississippi Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Mississippi Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Mississippi Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Mississippi Power's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters – Mississippi Power) to the financial statements
Critical Audit Matter Description
Mississippi Power is subject to retail rate regulation by the Mississippi Public Service Commission and wholesale regulation by the Federal Energy Regulatory Commission (collectively, the "Commissions"). Management has determined that it meets the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
The Commissions set the rates Mississippi Power is permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of Mississippi Power's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Mississippi Power expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
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We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
-
We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates. We also tested the effectiveness of management's controls over the initial recognition of certain regulatory assets or liabilities.
-
We read and evaluated relevant regulatory orders issued and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
-
We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
-
We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
-
We evaluated Mississippi Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 18, 2026
We have served as Mississippi Power's auditor since 2002.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Mississippi Power Company
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Retail revenues | $ | 1,085 | $ | 965 | $ | 963 | |||||||||||
| Wholesale revenues, non-affiliates | 275 | 228 | 272 | ||||||||||||||
| Wholesale revenues, affiliates | 280 | 218 | 200 | ||||||||||||||
| Other revenues | 55 | 52 | 39 | ||||||||||||||
| Total operating revenues | 1,695 | 1,463 | 1,474 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel and purchased power | 624 | 477 | 538 | ||||||||||||||
| Other operations and maintenance | 387 | 370 | 362 | ||||||||||||||
| Depreciation and amortization | 211 | 193 | 190 | ||||||||||||||
| Taxes other than income taxes | 139 | 127 | 124 | ||||||||||||||
| Total operating expenses | 1,361 | 1,167 | 1,214 | ||||||||||||||
| Operating Income | 334 | 296 | 260 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Interest expense, net of amounts capitalized | (79) | (77) | (71) | ||||||||||||||
| Other income (expense), net | 25 | 27 | 35 | ||||||||||||||
| Total other income and (expense) | (54) | (50) | (36) | ||||||||||||||
| Earnings Before Income Taxes | 280 | 246 | 224 | ||||||||||||||
| Income taxes | 65 | 47 | 36 | ||||||||||||||
| Net Income | $ | 215 | $ | 199 | $ | 188 | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Mississippi Power Company
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Net Income | $ | 215 | $ | 199 | $ | 188 | |||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Changes in fair value, net of tax of $—, $2, and $—, respectively | (1) | 5 | — | ||||||||||||||
| Total other comprehensive income (loss) | (1) | 5 | — | ||||||||||||||
| Comprehensive Income | $ | 214 | $ | 204 | $ | 188 |
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2025, 2024, and 2023
Mississippi Power Company
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Net income | $ | 215 | $ | 199 | $ | 188 | |||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 230 | 209 | 232 | ||||||||||||||
| Deferred income taxes | 9 | 16 | (13) | ||||||||||||||
| Pension, postretirement, and other employee benefits | (20) | (21) | (20) | ||||||||||||||
| Settlement of asset retirement obligations | (19) | (17) | (18) | ||||||||||||||
| Property damage reserve and reliability reserve accruals | 26 | 35 | 23 | ||||||||||||||
| Retail fuel cost under recovery – long-term | (30) | (32) | (50) | ||||||||||||||
| Plant acquisition regulatory liability | 36 | — | — | ||||||||||||||
| Other, net | (12) | 5 | (5) | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | (3) | (14) | 85 | ||||||||||||||
| -Fossil fuel stock | 10 | (9) | (3) | ||||||||||||||
| -Materials and supplies | (2) | (13) | (9) | ||||||||||||||
| -Prepaid income taxes | 11 | (11) | — | ||||||||||||||
| -Other current assets | (1) | (1) | 10 | ||||||||||||||
| -Accounts payable | (13) | (10) | (81) | ||||||||||||||
| -Retail fuel cost over recovery | (10) | 55 | 27 | ||||||||||||||
| -Wholesale fuel cost over recovery | (20) | 15 | 5 | ||||||||||||||
| -Other current liabilities | 7 | — | (2) | ||||||||||||||
| Net cash provided from operating activities | 414 | 406 | 369 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Property additions | (328) | (311) | (319) | ||||||||||||||
| Contributions in aid of construction | 58 | — | — | ||||||||||||||
| Cost of removal net of salvage | (55) | (41) | (32) | ||||||||||||||
| Change in construction payables, net | (4) | — | 9 | ||||||||||||||
| Payments pursuant to LTSAs | (20) | (19) | (26) | ||||||||||||||
| Other investing activities | (7) | (2) | (2) | ||||||||||||||
| Net cash used for investing activities | (356) | (373) | (370) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Increase (decrease) in notes payable, net | (14) | 14 | — | ||||||||||||||
| Proceeds — Senior notes | 100 | 250 | 100 | ||||||||||||||
| Redemptions — | |||||||||||||||||
| Senior notes | — | (200) | — | ||||||||||||||
| Revenue bonds | (11) | — | — | ||||||||||||||
| Capital contributions from parent company | 77 | 68 | 68 | ||||||||||||||
| Payment of common stock dividends | (194) | (188) | (185) | ||||||||||||||
| Other financing activities | (3) | (2) | (3) | ||||||||||||||
| Net cash used for financing activities | (45) | (58) | (20) | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 13 | (25) | (21) | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 13 | 38 | 59 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 26 | $ | 13 | $ | 38 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid during the period for — | |||||||||||||||||
| Interest | $ | 76 | $ | 74 | $ | 66 | |||||||||||
| Income taxes, net | 42 | 51 | 52 | ||||||||||||||
| Noncash transactions — Accrued property additions at year-end | 38 | 36 | 34 | ||||||||||||||
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2025 and 2024
Mississippi Power Company
| Assets | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 26 | $ | 13 | |||||||
| Receivables — | |||||||||||
| Customer accounts, net | 50 | 45 | |||||||||
| Unbilled revenues | 44 | 39 | |||||||||
| Affiliated | 26 | 33 | |||||||||
| Other accounts and notes | 22 | 24 | |||||||||
| Fossil fuel stock | 46 | 56 | |||||||||
| Materials and supplies | 101 | 103 | |||||||||
| Other regulatory assets | 49 | 43 | |||||||||
| Other current assets | 10 | 28 | |||||||||
| Total current assets | 374 | 384 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 5,972 | 5,697 | |||||||||
| Less: Accumulated provision for depreciation | 1,922 | 1,833 | |||||||||
| Plant in service, net of depreciation | 4,050 | 3,864 | |||||||||
| Construction work in progress | 238 | 253 | |||||||||
| Total property, plant, and equipment | 4,288 | 4,117 | |||||||||
| Other Property and Investments | 143 | 152 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Deferred charges related to income taxes | 25 | 27 | |||||||||
| Prepaid pension costs | 151 | 124 | |||||||||
| Deferred under recovered retail fuel clause revenues | 40 | 32 | |||||||||
| Regulatory assets – asset retirement obligations | 229 | 243 | |||||||||
| Other regulatory assets, deferred | 255 | 259 | |||||||||
| Accumulated deferred income taxes | 66 | 82 | |||||||||
| Other deferred charges and assets | 66 | 74 | |||||||||
| Total deferred charges and other assets | 832 | 841 | |||||||||
| Total Assets | $ | 5,637 | $ | 5,494 |
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2025 and 2024
Mississippi Power Company
| Liabilities and Stockholder's Equity | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 66 | $ | 12 | |||||||
| Notes payable | — | 14 | |||||||||
| Accounts payable — | |||||||||||
| Affiliated | 70 | 68 | |||||||||
| Other | 77 | 83 | |||||||||
| Accrued taxes | 125 | 115 | |||||||||
| Accrued compensation | 49 | 46 | |||||||||
| Asset retirement obligations | 21 | 32 | |||||||||
| Over recovered retail fuel clause revenues | — | 32 | |||||||||
| Other regulatory liabilities | 20 | 5 | |||||||||
| Other current liabilities | 92 | 95 | |||||||||
| Total current liabilities | 520 | 502 | |||||||||
| Long-Term Debt | 1,720 | 1,681 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 491 | 492 | |||||||||
| Deferred credits related to income taxes | 211 | 219 | |||||||||
| Employee benefit obligations | 67 | 65 | |||||||||
| Asset retirement obligations, deferred | 103 | 116 | |||||||||
| Other cost of removal obligations | 115 | 170 | |||||||||
| Other regulatory liabilities, deferred | 141 | 121 | |||||||||
| Other deferred credits and liabilities | 80 | 39 | |||||||||
| Total deferred credits and other liabilities | 1,208 | 1,222 | |||||||||
| Total Liabilities | 3,448 | 3,405 | |||||||||
| Common Stockholder's Equity: | |||||||||||
| Common stock, without par value (Authorized - 50 million shares; Outstanding - 1 million shares) | 38 | 38 | |||||||||
| Paid-in capital | 4,871 | 4,791 | |||||||||
| Accumulated deficit | (2,724) | (2,745) | |||||||||
| Accumulated other comprehensive income | 4 | 5 | |||||||||
| Total common stockholder's equity (See accompanying statements) | 2,189 | 2,089 | |||||||||
| Total Liabilities and Stockholder's Equity | $ | 5,637 | $ | 5,494 | |||||||
| Commitments and Contingent Matters (See notes) |
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2025, 2024, and 2023
Mississippi Power Company
| Number of Common Shares Issued | Common Stock | Paid-In Capital | Retained Earnings (Accumulated Deficit) | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | 1 | $ | 38 | $ | 4,652 | $ | (2,759) | $ | — | $ | 1,931 | ||||||||||||||||||||||||
| Net income | — | — | — | 188 | — | 188 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 69 | — | — | 69 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (185) | — | (185) | |||||||||||||||||||||||||||||
| Balance at December 31, 2023 | 1 | 38 | 4,721 | (2,756) | — | 2,003 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 199 | — | 199 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 70 | — | — | 70 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 5 | 5 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (188) | — | (188) | |||||||||||||||||||||||||||||
| Balance at December 31, 2024 | 1 | 38 | 4,791 | (2,745) | 5 | 2,089 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 215 | — | 215 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 80 | — | — | 80 | |||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | (1) | (1) | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (194) | — | (194) | |||||||||||||||||||||||||||||
| Balance at December 31, 2025 | 1 | $ | 38 | $ | 4,871 | $ | (2,724) | $ | 4 | $ | 2,189 |
The accompanying notes are an integral part of these financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Southern Power Company and Subsidiary Companies
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Southern Power Company and subsidiary companies (Southern Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2025, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Power as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Southern Power's management. Our responsibility is to express an opinion on Southern Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Southern Power's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Income/Loss Allocation to Noncontrolling Interests – Refer to Note 1 (Summary of Significant Accounting Policies – Variable Interest Entities) and Note 7 (Consolidated Entities and Equity Method Investments – Southern Power – Variable Interest Entities) to the financial statements
Critical Audit Matter Description
Southern Power has entered into a number of tax equity partnership arrangements, wherein they agree to sell 100% of a class of membership interests (e.g. Class A) in an entity to a noncontrolling investor in exchange for cash contributions, while retaining control of the entity through a separate class of membership interests (e.g. Class B). The agreements for these partnerships give different rights and priorities to their owners in terms of cash distributions, tax attribute allocations, and partnership income or loss allocations. These provisions make the conventional equity method of accounting where an investor applies its "percentage ownership interest" to the investee's net income under generally accepted accounting principles to determine the investor's share of earnings or losses difficult to apply. Therefore, Southern Power uses the Hypothetical Liquidation at Book Value (HLBV) accounting method to account for these partnership arrangements. The HLBV accounting method calculates each partner's share of income or loss based on the change in net equity the partner can legally claim at the end of the reporting period compared to the beginning of the reporting period. The application of the HLBV accounting method by Southern Power required significant consideration of the allocations between Southern Power and the noncontrolling investors over the life of the agreement and the liquidation provisions of the agreement to determine the appropriate allocation of income or loss between the parties.
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The determination of the appropriate amount of allocated partnership income or loss to noncontrolling interests using the HLBV accounting method required increased audit effort and specialized skill and knowledge, including evaluation of the terms of the agreement and consideration of the appropriateness of the HLBV model based on the provisions of the agreement.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures included the following, among others:
-
We read certain agreements to understand the liquidation provisions and the provisions governing the allocation of benefits.
-
We evaluated certain HLBV models utilized by management to determine whether the models accurately reflect the allocation of income or loss and tax attributes in accordance with the liquidation provisions and allocation terms defined in the agreements, as well as whether the inputs in the models are accurate and complete.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 18, 2026
We have served as Southern Power's auditor since 2002.
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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Southern Power Company and Subsidiary Companies
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Wholesale revenues, non-affiliates | $ | 1,743 | $ | 1,606 | $ | 1,597 | |||||||||||
| Wholesale revenues, affiliates | 437 | 371 | 537 | ||||||||||||||
| Other revenues | 18 | 37 | 55 | ||||||||||||||
| Total operating revenues | 2,198 | 2,014 | 2,189 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 676 | 579 | 706 | ||||||||||||||
| Purchased power | 122 | 78 | 116 | ||||||||||||||
| Other operations and maintenance | 528 | 516 | 473 | ||||||||||||||
| Depreciation and amortization | 843 | 522 | 504 | ||||||||||||||
| Taxes other than income taxes | 48 | 41 | 51 | ||||||||||||||
| Gain on dispositions, net | — | — | (20) | ||||||||||||||
| Total operating expenses | 2,217 | 1,736 | 1,830 | ||||||||||||||
| Operating Income (Loss) | (19) | 278 | 359 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Interest expense, net of amounts capitalized | (104) | (117) | (129) | ||||||||||||||
| Other income (expense), net | 17 | 13 | 12 | ||||||||||||||
| Total other income and (expense) | (87) | (104) | (117) | ||||||||||||||
| Earnings (Loss) Before Income Taxes | (106) | 174 | 242 | ||||||||||||||
| Income taxes (benefit) | (61) | (13) | 12 | ||||||||||||||
| Net Income (Loss) | (45) | 187 | 230 | ||||||||||||||
| Net loss attributable to noncontrolling interests | (170) | (141) | (127) | ||||||||||||||
| Net Income Attributable to Southern Power | $ | 125 | $ | 328 | $ | 357 |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Southern Power Company and Subsidiary Companies
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Net Income (Loss) | $ | (45) | $ | 187 | $ | 230 | |||||||||||
| Other comprehensive income: | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Changes in fair value, net of tax of $14, $(10), and $(1), respectively | 43 | (31) | (3) | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $(14), $12, and $4, respectively | (45) | 39 | 11 | ||||||||||||||
| Pension and other postretirement benefit plans: | |||||||||||||||||
| Benefit plan net gain (loss), net of tax of $1, $2, and $(2), respectively | 4 | 7 | (7) | ||||||||||||||
| Total other comprehensive income | 2 | 15 | 1 | ||||||||||||||
| Comprehensive loss attributable to noncontrolling interests | (170) | (141) | (127) | ||||||||||||||
| Comprehensive Income Attributable to Southern Power | $ | 127 | $ | 343 | $ | 358 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2025, 2024, and 2023
Southern Power Company and Subsidiary Companies
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Net income (loss) | $ | (45) | $ | 187 | $ | 230 | |||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 866 | 537 | 524 | ||||||||||||||
| Deferred income taxes | (34) | (7) | 16 | ||||||||||||||
| Utilization of federal tax credit carryforward | (95) | 75 | 332 | ||||||||||||||
| Amortization of ITCs | (58) | (58) | (58) | ||||||||||||||
| Gain on dispositions, net | — | — | (20) | ||||||||||||||
| Other, net | 13 | 36 | 28 | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | 40 | (39) | 121 | ||||||||||||||
| -Other current assets | (19) | (22) | (22) | ||||||||||||||
| -Accounts payable | 7 | (3) | (60) | ||||||||||||||
| -Accrued taxes | (8) | 16 | (12) | ||||||||||||||
| -Other current liabilities | 3 | (14) | 17 | ||||||||||||||
| Net cash provided from operating activities | 670 | 708 | 1,096 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Acquisitions, net of cash acquired | — | — | (181) | ||||||||||||||
| Property additions | (878) | (344) | (118) | ||||||||||||||
| Change in construction payables | (1) | 35 | 21 | ||||||||||||||
| Proceeds from dispositions | — | — | 59 | ||||||||||||||
| Payments pursuant to LTSAs | (56) | (45) | (50) | ||||||||||||||
| Other investing activities | 1 | 24 | 4 | ||||||||||||||
| Net cash used for investing activities | (934) | (330) | (265) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Increase (decrease) in notes payable, net | 140 | (129) | (83) | ||||||||||||||
| Proceeds — Senior notes | 1,100 | — | — | ||||||||||||||
| Redemptions — Senior notes | (900) | — | (290) | ||||||||||||||
| Capital contributions from parent company | 619 | 216 | 18 | ||||||||||||||
| Capital contributions from noncontrolling interests | 23 | 11 | 21 | ||||||||||||||
| Distributions to noncontrolling interests | (200) | (185) | (234) | ||||||||||||||
| Purchase of membership interests from noncontrolling interests | (286) | — | — | ||||||||||||||
| Payment of common stock dividends | (279) | (262) | (252) | ||||||||||||||
| Other financing activities | (16) | (5) | — | ||||||||||||||
| Net cash provided from (used for) financing activities | 201 | (354) | (820) | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (63) | 24 | 11 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 168 | 144 | 133 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 105 | $ | 168 | $ | 144 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid (received) during the period for — | |||||||||||||||||
| Interest (net of $25, $7, and $3 capitalized, respectively) | $ | 88 | $ | 107 | $ | 122 | |||||||||||
| Income taxes, net (excludes credit transfers) | 148 | (32) | (254) | ||||||||||||||
| Noncash transactions — | |||||||||||||||||
| Accrued property additions at year-end | 59 | 84 | 59 | ||||||||||||||
| LTSA credits utilized from the sale of spare parts | 6 | 13 | 23 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2025 and 2024
Southern Power Company and Subsidiary Companies
| Assets | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 105 | $ | 159 | |||||||
| Receivables — | |||||||||||
| Customer accounts, net | 151 | 122 | |||||||||
| Affiliated | 35 | 39 | |||||||||
| Other | 16 | 90 | |||||||||
| Materials and supplies | 132 | 107 | |||||||||
| Other current assets | 89 | 82 | |||||||||
| Total current assets | 528 | 599 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 15,034 | 14,961 | |||||||||
| Less: Accumulated provision for depreciation | 5,214 | 4,540 | |||||||||
| Plant in service, net of depreciation | 9,820 | 10,421 | |||||||||
| Construction work in progress | 1,080 | 317 | |||||||||
| Total property, plant, and equipment | 10,900 | 10,738 | |||||||||
| Other Property and Investments: | |||||||||||
| Intangible assets, net of amortization of $188 and $168, respectively | 203 | 223 | |||||||||
| Net investment in sales-type leases | 137 | 143 | |||||||||
| Total other property and investments | 340 | 366 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Operating lease right-of-use assets, net of amortization | 479 | 484 | |||||||||
| Prepaid LTSAs | 170 | 234 | |||||||||
| Other deferred charges and assets | 240 | 232 | |||||||||
| Total deferred charges and other assets | 889 | 950 | |||||||||
| Total Assets | $ | 12,657 | $ | 12,653 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2025 and 2024
Southern Power Company and Subsidiary Companies
| Liabilities and Stockholders' Equity | 2025 | 2024 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 587 | $ | 500 | |||||||
| Notes payable | 138 | — | |||||||||
| Accounts payable — | |||||||||||
| Affiliated | 88 | 80 | |||||||||
| Other | 93 | 100 | |||||||||
| Accrued taxes | 9 | 18 | |||||||||
| Accrued interest | 38 | 26 | |||||||||
| Operating lease obligations | 31 | 29 | |||||||||
| Other current liabilities | 92 | 96 | |||||||||
| Total current liabilities | 1,076 | 849 | |||||||||
| Long-Term Debt | 2,353 | 2,180 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 579 | 712 | |||||||||
| Accumulated deferred ITCs | 1,383 | 1,440 | |||||||||
| Operating lease obligations, deferred | 510 | 511 | |||||||||
| Other deferred credits and liabilities | 235 | 279 | |||||||||
| Total deferred credits and other liabilities | 2,707 | 2,942 | |||||||||
| Total Liabilities | 6,136 | 5,971 | |||||||||
| Common Stockholder's Equity: | |||||||||||
| Common stock, par value $0.01 per share (Authorized - 1 million shares; Outstanding - 1,000 shares) | — | — | |||||||||
| Paid-in capital | 1,912 | 1,306 | |||||||||
| Retained earnings | 1,758 | 1,912 | |||||||||
| Accumulated other comprehensive income (loss) | — | (2) | |||||||||
| Total common stockholder's equity | 3,670 | 3,216 | |||||||||
| Noncontrolling Interests | 2,851 | 3,466 | |||||||||
| Total Stockholders' Equity (See accompanying statements) | 6,521 | 6,682 | |||||||||
| Total Liabilities and Stockholders' Equity | $ | 12,657 | $ | 12,653 | |||||||
| Commitments and Contingent Matters (See notes) |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2025, 2024, and 2023
Southern Power Company and Subsidiary Companies
| Number of Common Shares Issued | Common Stock | Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Common Stockholder's Equity | Noncontrolling Interests | Total | ||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | — | $ | — | $ | 1,069 | $ | 1,741 | $ | (18) | $ | 2,792 | $ | 4,124 | $ | 6,916 | ||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | 357 | — | 357 | (127) | 230 | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 19 | — | — | 19 | — | 19 | |||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 1 | 1 | — | 1 | |||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (252) | — | (252) | — | (252) | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from noncontrolling interests | — | — | — | — | — | — | 21 | 21 | |||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (236) | (236) | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | — | — | (1) | (1) | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2023 | — | — | 1,088 | 1,846 | (17) | 2,917 | 3,781 | 6,698 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | 328 | — | 328 | (141) | 187 | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 218 | — | — | 218 | — | 218 | |||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 15 | 15 | — | 15 | |||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (262) | — | (262) | — | (262) | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from noncontrolling interests | — | — | — | — | — | — | 11 | 11 | |||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (185) | (185) | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2024 | — | — | 1,306 | 1,912 | (2) | 3,216 | 3,466 | 6,682 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | 125 | — | 125 | (170) | (45) | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 622 | — | — | 622 | — | 622 | |||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 2 | 2 | — | 2 | |||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (279) | — | (279) | — | (279) | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from noncontrolling interests | — | — | — | — | — | — | 23 | 23 | |||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (202) | (202) | |||||||||||||||||||||||||||||||||||||||
| Purchase of membership interests from noncontrolling interests(*) | — | — | (16) | — | — | (16) | (267) | (283) | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | — | — | 1 | 1 | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2025 | — | $ | — | $ | 1,912 | $ | 1,758 | $ | — | $ | 3,670 | $ | 2,851 | $ | 6,521 |
(*) See Note 15 under "Southern Power – Purchase of Renewable Facility Interests" for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Southern Company Gas and subsidiary companies (Southern Company Gas) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2025, the related notes, and the financial statement schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Company Gas as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
We did not audit the financial statements of Southern Natural Gas Company, L.L.C. (SNG), Southern Company Gas' investment which is accounted for by the use of the equity method. The accompanying consolidated financial statements of Southern Company Gas include its equity investment in SNG of $1,148 million and $1,245 million as of December 31, 2025 and December 31, 2024, respectively, and its earnings from its equity method investment in SNG of $127 million, $146 million, and $139 million for the years ended December 31, 2025, 2024, and 2023, respectively. Those statements were audited by BDO USA, P.C., whose reports (which express unqualified opinions on SNG's financial statements and contain an emphasis of matter paragraph calling attention to SNG's significant transactions with related parties) have been furnished to us, and our opinion, insofar as it relates to the amounts included for SNG, is based solely on the reports of the other auditors.
Basis for Opinion
These financial statements are the responsibility of Southern Company Gas' management. Our responsibility is to express an opinion on Southern Company Gas' financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Company Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Company Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Southern Company Gas' internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Rate Regulation on the Financial Statements – Refer to Note 1 (Summary of Significant Accounting Policies – Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters – Southern Company Gas) to the financial statements
Critical Audit Matter Description
Southern Company Gas' natural gas distribution utilities (the "regulated utility subsidiaries") are subject to rate regulation by their respective state Public Service Commission or other applicable state regulatory agencies (collectively, the "Commissions"). Management has determined that the regulated utility subsidiaries meet the requirements under accounting principles generally accepted in the United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation
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of its financial statements. Accounting for the economics of rate regulation may impact multiple financial statement line items and disclosures.
The Commissions set the rates the regulated utility subsidiaries are permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of the applicable regulated utility subsidiary's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered through rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While Southern Company Gas' regulated utility subsidiaries expect to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on those investments.
We identified the impact of rate regulation related to certain assets and liabilities as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and/or the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Auditing these judgments, which include assumptions about the outcome of future decisions by the Commissions, required specialized knowledge of accounting for rate regulations and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the impact of rate regulation on certain assets and liabilities included the following, among others:
-
We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of certain incurred costs and (2) refunds or future reductions in rates that should be reported as regulatory liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering certain costs in future rates or of a future reduction in rates, including previously incurred Qualifying Infrastructure Plant capital investments by Nicor Gas. We also tested the effectiveness of management's controls over the initial recognition of certain regulatory assets or liabilities.
-
We read and evaluated relevant regulatory orders issued and/or other relevant publicly available information to assess the likelihood of recovery of certain incurred costs in future rates or of a future reduction in rates based on precedents of the treatment of similar costs under similar circumstances.
-
We tested certain incurred costs recorded as regulatory assets or liabilities during the period for completeness and accuracy.
-
We obtained representation from management regarding the likelihood of recoverability of incurred costs and potential refund or future reduction in rates to assess management's assertions about the likelihood of recovery, refund, or a future reduction in rates.
-
We evaluated Southern Company Gas' disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments, including where there is a high degree of subjectivity involved in assessing the potential impact of future regulatory orders on incurred costs.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 18, 2026
We have served as Southern Company Gas' auditor since 2016.
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Report of Independent Registered Public Accounting Firm
Board of Directors and Members
Southern Natural Gas Company, L.L.C.
Houston, Texas
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Southern Natural Gas Company, L.L.C. (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income, members' equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
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Postretirement Benefits Plan – Fair Value of Investments Measured at Net Asset Value
As discussed in Note 5 to the consolidated financial statements, the fair value of postretirement benefits plan assets on December 31, 2025, was $79 million. Of this amount, $78 million represents the fair value of investments measured at net asset value (NAV).
We identified the assessment of the postretirement benefits plan fair value of investments measured at NAV as a critical audit matter. Estimating the fair value requires management to make certain determination of unobservable inputs. Auditing these elements involved subjective auditor judgment due to the nature and extent of audit effort required, including the extent of specialized skills or knowledge needed to assess sufficiency of audit evidence.
The primary procedures we performed to address this critical audit matter included:
-
Comparing the fair values as recorded by the Company to external confirmations received directly from the third-party investment managers.
-
Utilizing specialists who performed a benchmark analysis to determine the correlation of the funds and the stated benchmark; the results were used to estimate the high and low fair value range of the investments to compare to the Company's fair value.
Emphasis of Matter – Significant Transactions with Related Parties
As discussed in Note 6 to the consolidated financial statements, the Company has entered into significant transactions with related parties.
/s/ BDO USA, P.C.
We have served as the Company's auditor since 2018.
Houston, Texas
February 5, 2026
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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Southern Company Gas and Subsidiary Companies
| 2025 | 2024 | 2023 | ||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Operating Revenues: | ||||||||||||||||||||
| Natural gas revenues (includes revenue taxes of $136, $115, and $133, respectively) | $ | 5,044 | $ | 4,456 | $ | 4,702 | ||||||||||||||
| Total operating revenues | 5,044 | 4,456 | 4,702 | |||||||||||||||||
| Operating Expenses: | ||||||||||||||||||||
| Cost of natural gas | 1,599 | 1,196 | 1,644 | |||||||||||||||||
| Other operations and maintenance | 1,297 | 1,235 | 1,187 | |||||||||||||||||
| Depreciation and amortization | 708 | 650 | 582 | |||||||||||||||||
| Taxes other than income taxes | 272 | 248 | 262 | |||||||||||||||||
| Estimated loss on regulatory disallowance | 63 | — | 88 | |||||||||||||||||
| Total operating expenses | 3,939 | 3,329 | 3,763 | |||||||||||||||||
| Operating Income | 1,105 | 1,127 | 939 | |||||||||||||||||
| Other Income and (Expense): | ||||||||||||||||||||
| Earnings from equity method investments | 127 | 146 | 140 | |||||||||||||||||
| Interest expense, net of amounts capitalized | (377) | (341) | (310) | |||||||||||||||||
| Other income (expense), net | 59 | 66 | 57 | |||||||||||||||||
| Total other income and (expense) | (191) | (129) | (113) | |||||||||||||||||
| Earnings Before Income Taxes | 914 | 998 | 826 | |||||||||||||||||
| Income taxes | 182 | 258 | 211 | |||||||||||||||||
| Net Income | $ | 732 | $ | 740 | $ | 615 |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2025, 2024, and 2023
Southern Company Gas and Subsidiary Companies
| 2025 | 2024 | 2023 | ||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Net Income | $ | 732 | $ | 740 | $ | 615 | ||||||||||||||
| Other comprehensive income (loss): | ||||||||||||||||||||
| Qualifying hedges: | ||||||||||||||||||||
| Changes in fair value, net of tax of $(1), $(3), and $(18), respectively | (3) | (9) | (45) | |||||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $1, $12, and $19, respectively | 3 | 30 | 46 | |||||||||||||||||
| Pension and other postretirement benefit plans: | ||||||||||||||||||||
| Benefit plan net gain (loss), net of tax of $2, $5, and $(7), respectively | 4 | 11 | (15) | |||||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $(1), $(1), and $—, respectively | (1) | — | (1) | |||||||||||||||||
| Total other comprehensive income (loss) | 3 | 32 | (15) | |||||||||||||||||
| Comprehensive Income | $ | 735 | $ | 772 | $ | 600 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2025, 2024, and 2023
Southern Company Gas and Subsidiary Companies
| 2025 | 2024 | 2023 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Consolidated net income | $ | 732 | $ | 740 | $ | 615 | |||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 701 | 643 | 582 | ||||||||||||||
| Deferred income taxes | 122 | 132 | 126 | ||||||||||||||
| Estimated loss on regulatory disallowance | 63 | — | 96 | ||||||||||||||
| Other, net | 41 | 3 | (74) | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | (189) | 28 | 431 | ||||||||||||||
| -Natural gas for sale, net of temporary LIFO liquidation | (8) | 32 | 19 | ||||||||||||||
| -Prepaid income taxes | 12 | 63 | (11) | ||||||||||||||
| -Natural gas cost under recovery | — | — | 108 | ||||||||||||||
| -Other current assets | 41 | (52) | (17) | ||||||||||||||
| -Accounts payable | 75 | (6) | (276) | ||||||||||||||
| -Natural gas cost over recovery | (36) | (21) | 214 | ||||||||||||||
| -Other current liabilities | 63 | (10) | (51) | ||||||||||||||
| Net cash provided from operating activities | 1,617 | 1,552 | 1,762 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Property additions | (1,741) | (1,541) | (1,561) | ||||||||||||||
| Cost of removal, net of salvage | (99) | (88) | (104) | ||||||||||||||
| Change in construction payables, net | (2) | (19) | (38) | ||||||||||||||
| Investments in unconsolidated subsidiaries | (74) | (82) | (11) | ||||||||||||||
| Returned investment in unconsolidated subsidiaries | 148 | 15 | 14 | ||||||||||||||
| Proceeds from dispositions | — | 3 | 42 | ||||||||||||||
| Other investing activities | — | 1 | 2 | ||||||||||||||
| Net cash used for investing activities | (1,768) | (1,711) | (1,656) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Increase (decrease) in notes payable, net | (31) | 40 | (153) | ||||||||||||||
| Proceeds — | |||||||||||||||||
| Senior notes | 850 | 450 | 500 | ||||||||||||||
| First mortgage bonds | 200 | 275 | 275 | ||||||||||||||
| Other long-term debt | — | 8 | 37 | ||||||||||||||
| Redemptions and repurchases — | |||||||||||||||||
| Senior notes | (250) | — | — | ||||||||||||||
| First mortgage bonds | (50) | — | (50) | ||||||||||||||
| Short-term borrowings | — | — | (200) | ||||||||||||||
| Medium-term notes | — | — | (350) | ||||||||||||||
| Return of capital to parent company | (23) | — | — | ||||||||||||||
| Capital contributions from parent company | 39 | 16 | 373 | ||||||||||||||
| Payment of common stock dividends | (594) | (605) | (585) | ||||||||||||||
| Other financing activities | (19) | (16) | (1) | ||||||||||||||
| Net cash provided from (used for) financing activities | 122 | 168 | (154) | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (29) | 9 | (48) | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 44 | 35 | 83 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 15 | $ | 44 | $ | 35 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid during the period for — | |||||||||||||||||
| Interest (net of $16, $21, and $16 capitalized, respectively) | $ | 372 | $ | 329 | $ | 291 | |||||||||||
| Income taxes, net | 29 | 59 | 91 | ||||||||||||||
| Noncash transactions — | |||||||||||||||||
| Accrued property additions at year-end | 112 | 113 | 139 | ||||||||||||||
| Return of capital to parent company | 34 | — | — |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2025 and 2024
Southern Company Gas and Subsidiary Companies
| Assets | 2025 | 2024 | ||||||||||||
| (in millions) | ||||||||||||||
| Current Assets: | ||||||||||||||
| Cash and cash equivalents | $ | 15 | $ | 43 | ||||||||||
| Receivables — | ||||||||||||||
| Customer accounts | 490 | 399 | ||||||||||||
| Unbilled revenues | 341 | 244 | ||||||||||||
| Other accounts and notes | 57 | 45 | ||||||||||||
| Accumulated provision for uncollectible accounts | (50) | (33) | ||||||||||||
| Materials and supplies | 62 | 66 | ||||||||||||
| Natural gas for sale | 396 | 388 | ||||||||||||
| Prepaid expenses | 26 | 45 | ||||||||||||
| Other regulatory assets | 114 | 187 | ||||||||||||
| Other current assets | 66 | 55 | ||||||||||||
| Total current assets | 1,517 | 1,439 | ||||||||||||
| Property, Plant, and Equipment: | ||||||||||||||
| In service | 24,098 | 22,338 | ||||||||||||
| Less: Accumulated depreciation | 6,273 | 5,887 | ||||||||||||
| Plant in service, net of depreciation | 17,825 | 16,451 | ||||||||||||
| Construction work in progress | 863 | 1,057 | ||||||||||||
| Total property, plant, and equipment | 18,688 | 17,508 | ||||||||||||
| Other Property and Investments: | ||||||||||||||
| Goodwill | 5,015 | 5,015 | ||||||||||||
| Equity investments in unconsolidated subsidiaries | 1,182 | 1,279 | ||||||||||||
| Other intangible assets, net of amortization of $179 and $173, respectively | 3 | 9 | ||||||||||||
| Miscellaneous property and investments | 24 | 25 | ||||||||||||
| Total other property and investments | 6,224 | 6,328 | ||||||||||||
| Deferred Charges and Other Assets: | ||||||||||||||
| Operating lease right-of-use assets, net of amortization | 85 | 38 | ||||||||||||
| Prepaid pension and other postretirement benefit costs | 229 | 191 | ||||||||||||
| Other regulatory assets, deferred | 517 | 481 | ||||||||||||
| Other deferred charges and assets | 127 | 192 | ||||||||||||
| Total deferred charges and other assets | 958 | 902 | ||||||||||||
| Total Assets | $ | 27,387 | $ | 26,177 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2025 and 2024
Southern Company Gas and Subsidiary Companies
| Liabilities and Stockholder's Equity | 2025 | 2024 | ||||||||||||
| (in millions) | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Securities due within one year | $ | 531 | $ | 302 | ||||||||||
| Notes payable | 425 | 455 | ||||||||||||
| Accounts payable — | ||||||||||||||
| Affiliated | 70 | 75 | ||||||||||||
| Other | 553 | 437 | ||||||||||||
| Customer deposits | 75 | 98 | ||||||||||||
| Accrued taxes | 107 | 85 | ||||||||||||
| Accrued interest | 100 | 88 | ||||||||||||
| Accrued compensation | 137 | 129 | ||||||||||||
| Natural gas cost over recovery | 158 | 193 | ||||||||||||
| Other regulatory liabilities | 36 | 7 | ||||||||||||
| Other current liabilities | 110 | 149 | ||||||||||||
| Total current liabilities | 2,302 | 2,018 | ||||||||||||
| Long-term Debt | 8,743 | 8,229 | ||||||||||||
| Deferred Credits and Other Liabilities: | ||||||||||||||
| Accumulated deferred income taxes | 1,971 | 1,796 | ||||||||||||
| Deferred credits related to income taxes | 681 | 755 | ||||||||||||
| Employee benefit obligations | 78 | 78 | ||||||||||||
| Operating lease obligations | 123 | 30 | ||||||||||||
| Other cost of removal obligations | 1,921 | 1,846 | ||||||||||||
| Accrued environmental remediation | 207 | 198 | ||||||||||||
| Other deferred credits and liabilities | 234 | 231 | ||||||||||||
| Total deferred credits and other liabilities | 5,215 | 4,934 | ||||||||||||
| Total Liabilities | 16,260 | 15,181 | ||||||||||||
| Common Stockholder’s Equity: | ||||||||||||||
| Common stock, par value $0.01 per share (Authorized - 100 million shares; Outstanding - 100 shares) | — | — | ||||||||||||
| Paid-in capital | 10,854 | 10,863 | ||||||||||||
| Retained earnings | 222 | 85 | ||||||||||||
| Accumulated other comprehensive income | 51 | 48 | ||||||||||||
| Total common stockholder's equity (See accompanying statements) | 11,127 | 10,996 | ||||||||||||
| Total Liabilities and Stockholder's Equity | $ | 27,387 | $ | 26,177 | ||||||||||
| Commitments and Contingent Matters (See notes) |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
For the Years Ended December 31, 2025, 2024, and 2023
Southern Company Gas and Subsidiary Companies
| Number of Common Shares Issued | Common Stock | Paid-In Capital | Retained Earnings (Accumulated Deficit) | Accumulated Other Comprehensive Income (Loss) | Total | |||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | — | $ | — | $ | 10,445 | $ | (79) | $ | 31 | $ | 10,397 | |||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | 615 | — | 615 | ||||||||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 391 | — | — | 391 | ||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | (15) | (15) | ||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (585) | — | (585) | ||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2023 | — | — | 10,836 | (49) | 16 | 10,803 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | 740 | — | 740 | ||||||||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 27 | — | — | 27 | ||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 32 | 32 | ||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (605) | — | (605) | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | (1) | — | (1) | ||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2024 | — | — | 10,863 | 85 | 48 | 10,996 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | 732 | — | 732 | ||||||||||||||||||||||||||||||||||||||||||||
| Return of capital to parent company | — | — | (57) | — | — | (57) | ||||||||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 47 | — | — | 47 | ||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 3 | 3 | ||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (594) | — | (594) | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | 1 | (1) | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2025 | — | $ | — | $ | 10,854 | $ | 222 | $ | 51 | $ | 11,127 |
The accompanying notes are an integral part of these consolidated financial statements.
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Notes to the Financial Statements
for
The Southern Company and Subsidiary Companies
Alabama Power Company
Georgia Power Company
Mississippi Power Company
Southern Power Company and Subsidiary Companies
Southern Company Gas and Subsidiary Companies
Index to the Combined Notes to Financial Statements
Index to Applicable Notes to Financial Statements by Registrant
The following notes to the financial statements are a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants. The table below indicates the Registrants to which each note applies.
| Applicable Notes | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Registrant | 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 | 9 | 10 | 11 | 12 | 13 | 14 | 15 | 16 | ||||||||||||||||||||||||||||||||||
| Southern Company | l | l | l | l | l | l | l | l | l | l | l | l | l | l | l | l | ||||||||||||||||||||||||||||||||||
| Alabama Power | l | l | l | l | l | l | l | l | l | l | l | l | l | l | l | l | ||||||||||||||||||||||||||||||||||
| Georgia Power | l | l | l | l | l | l | l | l | l | l | l | l | l | l | l | |||||||||||||||||||||||||||||||||||
| Mississippi Power | l | l | l | l | l | l | l | l | l | l | l | l | l | l | l | |||||||||||||||||||||||||||||||||||
| Southern Power | l | l | l | l | l | l | l | l | l | l | l | l | l | l | l | |||||||||||||||||||||||||||||||||||
| Southern Company Gas | l | l | l | l | l | l | l | l | l | l | l | l | l | l | l |
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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Company is the parent company of three traditional electric operating companies, as well as Southern Power, Southern Company Gas, SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, and other direct and indirect subsidiaries. The traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, operates, and manages power generation assets, including battery energy storage projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities, including Nicor Gas (Illinois), Atlanta Gas Light (Georgia), Virginia Natural Gas, and Chattanooga Gas (Tennessee). Southern Company Gas is also involved in several other complementary businesses including gas pipeline investments and gas marketing services. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary, which, through its subsidiaries, invests in various projects and insures various risk exposures of Southern Company and its subsidiaries. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including Alabama Power's Plant Farley and Georgia Power's Plants Hatch and Vogtle. PowerSecure develops distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers.
The Registrants' financial statements reflect investments in subsidiaries on a consolidated basis. Intercompany transactions have been eliminated in consolidation. The equity method is used for investments in entities in which a Registrant has significant influence but does not have control and for VIEs where a Registrant has an equity investment but is not the primary beneficiary. Southern Power has controlling ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in an HLBV at the end of the period compared to the beginning of the period. See "Variable Interest Entities" herein and Note 7 for additional information.
The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and the natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the respective financial statements of the applicable Registrants reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies.
The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the Registrants' results of operations, financial position, or cash flows.
Recently Adopted Accounting Standards
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (ASU 2023-07), which requires entities to disclose significant segment expenses, other segment items, the title and position of the CODM, and information related to how the CODM assesses segment performance and allocates resources, among certain other required disclosures. Additionally, previous annual disclosures are required in interim periods. The Registrants adopted ASU 2023-07 and applied the guidance retrospectively effective for the fiscal year beginning January 1, 2024. ASU 2023-07 was applied retrospectively for the interim periods beginning January 1, 2025. See Note 16 for additional information and related disclosures.
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (ASU 2023-09), which requires entities to enhance consistency in income tax disclosures by improving transparency and comparability for stakeholders. Among other changes, ASU 2023-09 requires additional information in the effective tax rate reconciliation, including disaggregation of certain categories, and greater detail about income taxes paid, including disaggregation by jurisdiction. The Registrants adopted ASU 2023-09 and applied the guidance retrospectively effective for the fiscal year beginning January 1, 2025. See Note 10 under "Effective Tax Rate" and "Cash Paid for Income Taxes" for additional information and related disclosures.
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In July 2025, the FASB issued ASU 2025-05, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets (ASU 2025-05), which allows an entity to elect a practical expedient for measuring expected credit losses on current accounts receivable and current contract assets arising from transactions accounted for as revenues from contracts customers. This expedient allows an entity to assume that current economic conditions as of the balance sheet date do not change for the remaining life of the asset. ASU 2025-05 is effective for fiscal years beginning after December 15, 2025 and interim periods within fiscal years beginning after December 15, 2026. As permitted, the Registrants have elected to early adopt the practical expedient as of December 31, 2025 and applied its provisions prospectively to the provision for uncollectable accounts. The adoption of ASU 2025‑05 did not have a material impact on the consolidated results of operations, cash flows or financial condition of the Registrants. See "Provision for Uncollectible Accounts" herein for additional information and disclosures impacted by ASU 2025-05.
Affiliate Transactions
The traditional electric operating companies, Southern Power, and Southern Company Gas have agreements with SCS under which certain of the following services are rendered to them at direct or allocated cost: general executive and advisory, general and design engineering, operations, purchasing, accounting, finance, treasury, legal, tax, information technology, marketing, auditing, insurance and pension administration, human resources, systems and procedures, digital wireless communications, cellular tower space, and other services with respect to business and operations, construction management, and Southern Company power pool transactions. These costs are primarily included in other operations and maintenance expenses or capitalized to property, plant, and equipment. Costs for these services from SCS in 2025, 2024, and 2023 were as follows:
| Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| 2025 | $ | 855 | $ | 1,364 | $ | 138 | $ | 101 | $ | 313 | |||||||
| 2024 | 813 | 1,197 | 130 | 93 | 290 | ||||||||||||
| 2023 | 611 | 857 | 113 | 86 | 261 |
Alabama Power and Georgia Power also have agreements with Southern Nuclear under which Southern Nuclear renders the following nuclear-related services at cost: general executive and advisory services; general operations, management, and technical services; administrative services including procurement, accounting, employee relations, systems, and procedures services; strategic planning and budgeting services; and other services with respect to business and operations. These costs are primarily included in other operations and maintenance expenses or capitalized to property, plant, and equipment. Costs for these services in 2025, 2024, and 2023 amounted to $275 million, $260 million, and $251 million, respectively, for Alabama Power and $832 million, $835 million, and $899 million, respectively, for Georgia Power.
Cost allocation methodologies used by SCS and Southern Nuclear prior to the repeal of the Public Utility Holding Company Act of 1935, as amended, were approved by the SEC. Subsequently, additional cost allocation methodologies have been reported to the FERC and management believes they are reasonable. The FERC permits services to be rendered at cost by system service companies.
Alabama Power's and Georgia Power's power purchases from affiliates through the Southern Company power pool are included in purchased power, affiliates on their respective statements of income. Mississippi Power's and Southern Power's power purchases from affiliates through the Southern Company power pool are included in purchased power on their respective statements of income and were as follows:
| Mississippi Power | Southern Power | |||||||
| (in millions) | ||||||||
| 2025 | $ | 19 | $ | 41 | ||||
| 2024 | 8 | 17 | ||||||
| 2023 | 4 | 13 |
Georgia Power has entered into a PPA with Mississippi Power, which commenced in 2024, and several PPAs with Southern Power for capacity and energy. Georgia Power's expenses associated with these PPAs are included in purchased power, affiliates on its statements of income. Mississippi Power's and Southern Power's revenues associated with these PPAs are included in wholesale revenues, affiliates on their respective statements of income. See Notes 2 and 9 for additional information.
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SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and certain subsidiaries of Southern Company Gas have long-term interstate natural gas transportation agreements with SNG that are governed by the terms and conditions of SNG's natural gas tariff and are subject to FERC regulation. See Note 7 under "Southern Company Gas" for additional information. Transportation costs under these agreements in 2025, 2024, and 2023 were as follows:
| Alabama Power | Georgia Power | Southern Power | Southern Company Gas | |||||||||||
| (in millions) | ||||||||||||||
| 2025 | $ | 11 | $ | 105 | $ | 31 | $ | 29 | ||||||
| 2024 | 13 | 103 | 35 | 28 | ||||||||||
| 2023 | 12 | 101 | 34 | 28 |
SCS, as agent for the traditional electric operating companies and Southern Power, has agreements with certain subsidiaries of Southern Company Gas to purchase natural gas. Natural gas purchases made under these agreements were immaterial for Alabama Power, Georgia Power, Mississippi Power, and Southern Power for all periods presented.
Alabama Power and Mississippi Power jointly own Plant Greene County. The companies have an agreement under which Alabama Power operates Plant Greene County and Mississippi Power reimburses Alabama Power for its proportionate share of non-fuel operations and maintenance expenses, which totaled $9 million, $7 million, and $5 million in 2025, 2024, and 2023, respectively. See Notes 2 and 5 under "Mississippi Power – Integrated Resource Plans" and "Joint Ownership Agreements," respectively, for additional information.
Alabama Power, Georgia Power, and Mississippi Power each have agreements with PowerSecure for equipment purchases and/or services related to utility infrastructure construction, distributed energy, and energy efficiency projects. During 2025, 2024, and 2023, costs under these agreements were $51 million, $20 million, and $5 million, respectively, for Georgia Power and immaterial for Alabama Power and Mississippi Power.
Southern Company Gas had a $74 million contract with the U.S. General Services Administration to increase energy efficiency at certain federal buildings across Georgia, which was completed in 2025. Southern Company Gas engaged PowerSecure to provide the majority of the construction services under the contract. During 2025, 2024, and 2023, Southern Company Gas paid $1 million, $13 million, and $29 million, respectively, to PowerSecure related to this agreement.
See Note 7 under "SEGCO" for information regarding Alabama Power's and Georgia Power's equity method investment in SEGCO and related affiliate purchased power costs, as well as Alabama Power's gas pipeline ownership agreement with SEGCO.
Southern Power has several agreements with SCS for transmission services, which are billed to Southern Power based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Transmission services purchased by Southern Power from SCS totaled $9 million, $25 million, and $33 million for 2025, 2024, and 2023, respectively, and were charged to other operations and maintenance expenses in Southern Power's consolidated statements of income.
The traditional electric operating companies and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 14 under "Contingent Features" for additional information. Southern Power and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. See "Revenues – Southern Power" herein for additional information.
The traditional electric operating companies, Southern Power, and Southern Company Gas provide incidental services to and receive such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas neither provided nor received any material services to or from affiliates in any year presented.
Regulatory Assets and Liabilities
The traditional electric operating companies and the natural gas distribution utilities are subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent costs recovered that are expected to be incurred in the future or probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.
In the event that a portion of a traditional electric operating company's or a natural gas distribution utility's operations is no longer subject to applicable accounting rules for rate regulation, such company would be required to write off to income or reclassify to
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AOCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or the natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 2 for additional information including details of regulatory assets and liabilities reflected in the balance sheets for Southern Company, the traditional electric operating companies, and Southern Company Gas.
Revenues
The Registrants generate revenues from a variety of sources which are accounted for under various revenue accounting guidance, including revenue from contracts with customers, lease, derivative, and regulatory accounting. See Notes 4, 9, and 14 for additional information.
Traditional Electric Operating Companies
The majority of the revenues of the traditional electric operating companies are generated from contracts with retail electric customers. These revenues, generated from the integrated service to deliver electricity when and if called upon by the customer, are recognized as a single performance obligation satisfied over time, at a tariff rate, and as electricity is delivered to the customer during the month. Unbilled revenues related to retail sales are recognized for estimated deliveries of electricity not yet billed to these customers from the last bill date to the end of the accounting period. Retail rates may include provisions to adjust revenues for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered from or returned to customers, respectively, through adjustments to the billing factors. See Note 2 for additional information regarding regulatory matters of the traditional electric operating companies.
Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms. Energy and other revenues are generally recognized as services are provided. The contracts for capacity and energy in a wholesale PPA have multiple performance obligations where the contract's total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, the traditional electric operating companies recognize revenue as the performance obligations are satisfied over time as electricity is delivered to the customer or as generation capacity is available to the customer.
For both retail and wholesale revenues, the traditional electric operating companies have elected to recognize revenue for their sales of electricity and capacity using the invoice practical expedient as they generally have a right to consideration in an amount that corresponds directly with the value to the customer of the performance completed to date and that may be invoiced. Payment for goods and services rendered is typically due in the subsequent month following satisfaction of the Registrants' performance obligation.
Southern Power
Southern Power sells capacity and energy at rates specified under contractual terms in long-term PPAs. These PPAs are accounted for as leases, normal sale derivatives, or contracts with customers. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Energy revenues are recognized in the period the energy is delivered. Capacity revenues from PPAs classified as sales-type leases are recognized by accounting for interest income on the net investment in the lease.
Southern Power's non-lease contracts commonly include capacity and energy which are considered separate performance obligations. In these contracts, the total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, Southern Power recognizes revenue as the performance obligations are satisfied over time, as electricity is delivered to the customer or as generation capacity is made available to the customer.
Southern Power generally has a right to consideration in an amount that corresponds directly with the value to the customer of the performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice. Payment for goods and services rendered is typically due in the subsequent month following satisfaction of Southern Power's performance obligation.
When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements.
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Southern Power may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains and losses on such contracts are recorded in wholesale revenues. See Note 14 and "Financial Instruments" herein for additional information.
Southern Company Gas
Southern Company Gas records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of the natural gas distribution utilities. The majority of the revenues of Southern Company Gas are generated from contracts with natural gas distribution customers. Revenues from this integrated service to deliver gas when and if called upon by the customer are recognized as a single performance obligation satisfied over time and are recognized at a tariff rate as gas is delivered to the customer during the month.
Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers, revenues are based on actual deliveries through the end of the period.
Southern Company Gas has elected to recognize revenue for sales of gas using the invoice practical expedient as it generally has a right to consideration in an amount that corresponds directly with the value to the customer of the performance completed to date and that may be invoiced. Payment for goods and services rendered is typically due in the subsequent month following satisfaction of Southern Company Gas' performance obligation.
Gas Distribution Operations
Atlanta Gas Light operates in a deregulated natural gas market whereby Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. As required by the Georgia PSC, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial, and industrial end-use customer's distribution costs as well as for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer's annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. With the exception of Atlanta Gas Light, the natural gas distribution utilities have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage.
The tariffs for the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers. These provisions are referred to as alternative revenue programs and provide for the recognition of certain revenues prior to billing, as long as the amounts recognized will be collected from customers within 24 months of recognition. Revenue related to alternative revenue programs was $(53) million, $43 million, and $20 million in 2025, 2024, and 2023, respectively. These programs primarily consist of:
-
Weather normalization adjustments – reduce customer bills when winter weather is colder than normal and increase customer bills when weather is warmer than normal and are included in the tariffs for Virginia Natural Gas and Chattanooga Gas;
-
Revenue normalization mechanisms – mitigate the impact of conservation and declining customer usage and are contained in the tariffs for Virginia Natural Gas and Nicor Gas; and
-
Revenue true-up adjustment – included within the provisions of the GRAM program in which Atlanta Gas Light participates as a short-term alternative to formal rate case filings, the revenue true-up feature provides for a positive (or negative) adjustment to record revenue in the amount of any variance to budgeted revenues, which are submitted and approved annually as a requirement of GRAM. Such adjustments are reflected in customer billings in a subsequent program year.
Gas Marketing Services
Gas marketing services is comprised of several choice-based natural gas marketers operating in various deregulated jurisdictions. While gas marketing services follows the same general approach to revenue recognition described for Southern Company Gas above, it recognizes revenues on certain 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts.
Concentration of Revenue
Southern Company, Alabama Power, Georgia Power, Mississippi Power (with the exception of its long-term contracts described below), Southern Power, and Southern Company Gas each have a diversified base of customers. In 2025, Southern Power's
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largest customer was Georgia Power, which accounted for approximately 10.5% of Southern Power's total revenues. For the other Registrants, no single customer comprises 10% or more of each company's revenues.
Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi which are subject to regulation by the FERC. The contracts with these wholesale customers represented 12.9% of Mississippi Power's total operating revenues in 2025.
Fuel Costs
Fuel costs for the traditional electric operating companies and Southern Power are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. For Alabama Power and Georgia Power, fuel expense also includes the amortization of the cost of nuclear fuel. For the traditional electric operating companies, fuel costs also include gains and/or losses from fuel-hedging programs as approved by their respective state PSCs.
Cost of Natural Gas
Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, Southern Company Gas charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Southern Company Gas defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.
Southern Company Gas' gas marketing services' customers are charged for actual or estimated natural gas consumed. Within cost of natural gas, Southern Company Gas also includes costs of lost and unaccounted for gas and gains and losses associated with certain derivatives.
Income Taxes
The Registrants use the liability method of accounting for deferred income taxes and provide deferred income taxes for all significant income tax temporary differences. Under current tax law, certain projects are eligible for ITCs. The Registrants use the deferral method to account for federal and state ITCs, whereby the ITCs are recorded as a deferred credit and amortized to income tax expense over the useful life of the respective asset. In accordance with regulatory requirements, certain state ITCs at Georgia Power are recognized as an income tax benefit in the year the credit is generated through the establishment of a regulatory asset.
Furthermore, the federal tax basis of the asset is reduced by 50% of the federal ITCs received, which, together with the deferred credit, results in a net deferred tax asset. The Registrants have elected to recognize the tax benefit of these basis differences as a reduction to income tax expense in the year in which the asset reaches commercial operation. In accordance with regulatory requirements, the traditional electric operating companies and natural gas distribution utilities defer the income tax benefit resulting from these basis differences. In addition, certain projects are eligible for federal and state PTCs, which are recognized as an income tax benefit based on KWH production.
Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2025 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have various state net operating loss (NOL) carryforwards for certain of its subsidiaries, including Mississippi Power and Southern Power, which would result in income tax benefits in the future, if utilized. See Note 10 under "Deferred Tax Assets and Liabilities – Tax Credit Carryforwards" and " – Net Operating Loss Carryforwards" for additional information.
In April 2024, the IRS issued final regulations related to the transferability of certain tax credits under the IRA. Southern Company and certain subsidiaries have tax credits that are eligible to be transferred at a discount to the generated credit value. The discount will be recorded as a reduction in tax credits recognized in the financial statements. See Note 10 under "Current and Deferred Income Taxes" for additional information.
Under current tax law, Georgia Power is eligible to generate advanced nuclear PTCs for Plant Vogtle Units 3 and 4, which are recognized as an income tax benefit based on KWH production and are eligible to be transferred. Pursuant to the Vogtle Joint Ownership Agreements (as defined in Note 2 under "Georgia Power – Nuclear Construction – Cost and Schedule"), Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Units 3 and 4 from the other Vogtle Owners. The gain recognized on the purchase of the joint owner PTCs is recognized as an income tax benefit.
The Registrants recognize tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 10 under "Unrecognized Tax Benefits" for additional information.
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Other Taxes
Taxes imposed on and collected from customers on behalf of governmental agencies are presented net on the Registrants' statements of income and are excluded from the transaction price in determining the revenue related to contracts with a customer.
Southern Company Gas is taxed on its gas revenues by various governmental authorities, but is allowed to recover these taxes from its customers. Revenue taxes imposed on the natural gas distribution utilities are recorded at the amount charged to customers, which may include a small administrative fee, as operating revenues, and the related taxes imposed on Southern Company Gas are recorded as operating expenses on the statements of income. Revenue taxes included in operating expenses were $132 million, $112 million, and $129 million in 2025, 2024, and 2023, respectively.
Allowance for Funds Used During Construction and Interest Capitalized
The traditional electric operating companies and the natural gas distribution utilities record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. The equity component of AFUDC is not taxable.
Interest related to financing the construction of new facilities at Southern Power and new facilities not included in the traditional electric operating companies' and Southern Company Gas' regulated rates is capitalized in accordance with standard interest capitalization requirements.
Total AFUDC and interest capitalized in 2025, 2024, and 2023 was immaterial for Mississippi Power and was as follows for the other Registrants:
| Southern Company | Alabama Power | Georgia Power**(*)** | Southern Power | Southern Company Gas | ||||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | $ | 480 | $ | 88 | $ | 327 | $ | 25 | $ | 38 | ||||||||||
| 2024 | 339 | 76 | 209 | 7 | 47 | |||||||||||||||
| 2023 | 400 | 109 | 251 | 3 | 37 |
(*)See Note 2 under "Georgia Power – Nuclear Construction" for information on the inclusion of a portion of construction costs related to Plant Vogtle Units 3 and 4 in Georgia Power's rate base through each unit's respective in-service date.
The average AFUDC composite rates for 2025, 2024, and 2023 for the applicable traditional electric operating companies and the natural gas distribution utilities were as follows:
| 2025 | 2024 | 2023 | |||||||||
| Alabama Power | 7.9 | % | 8.1 | % | 8.1 | % | |||||
| Georgia Power(*) | 7.7 | % | 7.7 | % | 7.6 | % | |||||
| Southern Company Gas: | |||||||||||
| Atlanta Gas Light | 7.9 | % | 7.7 | % | 7.4 | % | |||||
| Chattanooga Gas | 7.1 | % | 7.1 | % | 7.1 | % | |||||
| Nicor Gas | 4.2 | % | 5.6 | % | 4.6 | % |
(*)Excludes AFUDC related to the construction of Plant Vogtle Units 3 and 4 in 2023 and Plant Vogtle Unit 4 in 2024. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
Impairment of Long-Lived Assets
The Registrants evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. The determination of whether an impairment indicator exists is based on either a specific regulatory disallowance, a sales transaction price that is less than the asset group's carrying amount, or an estimate of undiscounted future cash flows attributable to the asset group, as compared with the carrying amount of the assets. If an impairment has occurred, the amount of the impairment loss recognized is determined by either the amount of regulatory disallowance or by the amount the carrying amount exceeds the estimated fair value of the assets. For assets identified as held for sale, the carrying amount is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required to be recorded. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change.
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In 2024, Alabama Power discontinued the development of a multi-use commercial facility. Given the decision to discontinue commercial development, Alabama Power performed an impairment test using a comparative market analysis and determined the carrying amount of the asset exceeded its fair value, net of selling costs. This resulted in a pre-tax impairment loss of $36 million ($27 million after tax) reflected in other operations and maintenance on the statements of income.
Goodwill and Other Intangible Assets
Goodwill and other intangible assets not subject to amortization are evaluated for impairment on an annual basis and when events or changes in circumstances necessitate an evaluation for impairment. Other intangible assets subject to amortization are evaluated for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.
Southern Power's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the respective PPA. Southern Company Gas' goodwill and other intangible assets primarily relate to its 2016 acquisition by Southern Company. In addition to these items, Southern Company's goodwill and other intangible assets also relate to its 2016 acquisition of PowerSecure.
For its 2025 and 2023 annual goodwill impairment tests, Southern Company Gas management performed the qualitative assessment and determined that it was more likely than not that the fair value of its reporting units with goodwill exceeded their carrying amounts, and therefore no quantitative assessment was required. For its 2024 annual goodwill impairment test, Southern Company Gas management performed the quantitative assessment, which indicated that the fair value of its reporting units with goodwill exceeded their carrying amounts.
For its 2025 and 2023 annual goodwill impairment tests, PowerSecure management performed the quantitative assessment, which indicated that the fair value of PowerSecure exceeded its carrying amount. For its 2024 annual goodwill impairment test, PowerSecure management performed the qualitative assessment and determined that it was more likely than not that the fair value of PowerSecure exceeded its carrying amount, and therefore no quantitative assessment was required.
At December 31, 2025 and 2024, goodwill was as follows:
| At December 31, 2025 | At December 31, 2024 | |||||||
| (in millions) | ||||||||
| Southern Company | $ | 5,161 | $ | 5,161 | ||||
| Southern Company Gas: | ||||||||
| Gas distribution operations | $ | 4,034 | $ | 4,034 | ||||
| Gas marketing services | 981 | 981 | ||||||
| Southern Company Gas total | $ | 5,015 | $ | 5,015 |
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At December 31, 2025 and 2024, other intangible assets were as follows:
| At December 31, 2025 | At December 31, 2024 | ||||||||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | ||||||||||||||||||
| (in millions) | (in millions) | ||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Subject to amortization: | |||||||||||||||||||||||
| Customer relationships | $ | 212 | $ | (189) | $ | 23 | $ | 212 | $ | (182) | $ | 30 | |||||||||||
| Trade names | 64 | (64) | — | 64 | (59) | 5 | |||||||||||||||||
| PPA fair value adjustments | 390 | (188) | 202 | 390 | (168) | 222 | |||||||||||||||||
| Other | 3 | (3) | — | 3 | (3) | — | |||||||||||||||||
| Total subject to amortization | $ | 669 | $ | (444) | $ | 225 | $ | 669 | $ | (412) | $ | 257 | |||||||||||
| Not subject to amortization: | |||||||||||||||||||||||
| FCC licenses | 75 | — | 75 | 75 | — | 75 | |||||||||||||||||
| Total other intangible assets | $ | 744 | $ | (444) | $ | 300 | $ | 744 | $ | (412) | $ | 332 | |||||||||||
| Southern Power**(*)** | |||||||||||||||||||||||
| PPA fair value adjustments | $ | 390 | $ | (188) | $ | 202 | $ | 390 | $ | (168) | $ | 222 | |||||||||||
| Southern Company Gas**(*)** | |||||||||||||||||||||||
| Gas marketing services | |||||||||||||||||||||||
| Customer relationships | $ | 156 | $ | (153) | $ | 3 | $ | 156 | $ | (150) | $ | 6 | |||||||||||
| Trade names | 26 | (26) | — | 26 | (23) | 3 | |||||||||||||||||
| Total other intangible assets | $ | 182 | $ | (179) | $ | 3 | $ | 182 | $ | (173) | $ | 9 |
(*)All subject to amortization.
Amortization associated with other intangible assets in 2025, 2024, and 2023 was as follows:
| 2025 | 2024 | 2023 | |||||||||
| (in millions) | |||||||||||
| Southern Company(a) | $ | 32 | $ | 35 | $ | 38 | |||||
| Southern Power(b) | 20 | 20 | 20 | ||||||||
| Southern Company Gas | |||||||||||
| Gas marketing services | 6 | 7 | 10 |
(a)Includes $20 million annually recorded as a reduction to operating revenues.
(b)Recorded as a reduction to operating revenues.
At December 31, 2025, the estimated amortization associated with other intangible assets for the next five years is as follows:
| 2026 | 2027 | 2028 | 2029 | 2030 | |||||||||||||
| (in millions) | |||||||||||||||||
| Southern Company | $ | 27 | $ | 24 | $ | 24 | $ | 23 | $ | 21 | |||||||
| Southern Power | 20 | 20 | 20 | 19 | 19 | ||||||||||||
| Southern Company Gas | |||||||||||||||||
| Gas marketing services | 3 | — | — | — | — |
Acquisition Accounting
At the time of an acquisition, management will assess whether acquired assets and activities meet the definition of a business. Acquisitions that meet the definition of a business are accounted for under the acquisition method, and operating results from the date of acquisition are included in the acquiring entity's financial statements. Identifiable assets acquired, liabilities assumed, and
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any noncontrolling interests (including any intangible assets) are recognized and measured at fair value, and goodwill is recognized as a residual over the fair values of the identifiable net assets acquired. Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. See Note 15 for additional information, including recent and proposed acquisitions.
Determining the fair value of assets acquired and liabilities assumed requires management judgment and management may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. For potential or successful acquisitions that meet the definition of a business, any due diligence or transaction costs incurred are expensed as incurred. If the acquisition is accounted for as an asset acquisition, direct and incremental transaction costs can be capitalized as a component of the cost of the assets acquired.
Historically, any contingent consideration relates to fixed amounts due to the seller once an acquired construction project is placed in service. For contingent consideration with variable payments, management fair values the arrangement with any changes recorded in the statements of income. See Note 13 for additional fair value information.
Development Costs
For Southern Power, development costs are capitalized once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as the status of power off-take agreements and regulatory approvals, if applicable. Southern Power's capitalized development costs are included in CWIP on the balance sheets. All of Southern Power's development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the statements of income. If it is determined that a project is no longer probable of completion, any of Southern Power's capitalized development costs are expensed and included in other operations and maintenance expense in the consolidated statements of income. See Note 15 for additional information, including recent and proposed development projects.
Long-Term Service Agreements
The traditional electric operating companies and Southern Power have entered into LTSAs for the purpose of securing maintenance support for certain of their generating facilities. The LTSAs cover all planned inspections on the covered equipment, which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract.
Payments made under the LTSAs for the performance of any planned inspections or unplanned capital maintenance are recorded in the statements of cash flows as investing activities. Receipts of major parts into materials and supplies inventory prior to planned inspections covered under LTSAs are treated as noncash transactions in the statements of cash flows. Any payments made prior to the work being performed are recorded as prepayments in other current assets and non-current assets on the balance sheets or reduce existing payables for LTSA-related work already completed. At the time work is performed, an appropriate amount is accrued for future payments or transferred from the prepayment or inventory and recorded as property, plant, and equipment or expensed.
Transmission Receivables/Prepayments
As a result of Southern Power's acquisition and construction of generating facilities, Southern Power has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to Southern Power. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider and the receivable/prepayments are reduced as payments or services are received.
Cash, Cash Equivalents, and Restricted Cash
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
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The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets that total to the amount shown in the statements of cash flows for the applicable Registrants:
| Southern Company | Georgia Power | Southern Power | Southern Company Gas | ||||||||||||||
| (in millions) | |||||||||||||||||
| At December 31, 2025 | |||||||||||||||||
| Cash and cash equivalents | $ | 1,639 | $ | 59 | $ | 105 | $ | 15 | |||||||||
| Restricted cash(*): | |||||||||||||||||
| Other current assets | 1 | — | — | — | |||||||||||||
| Total cash, cash equivalents, and restricted cash | $ | 1,640 | $ | 59 | $ | 105 | $ | 15 | |||||||||
| At December 31, 2024 | |||||||||||||||||
| Cash and cash equivalents | $ | 1,070 | $ | 97 | $ | 159 | $ | 43 | |||||||||
| Restricted cash(*): | |||||||||||||||||
| Other current assets | 31 | 21 | 9 | 1 | |||||||||||||
| Total cash, cash equivalents, and restricted cash | $ | 1,101 | $ | 118 | $ | 168 | $ | 44 |
(*)For Georgia Power, reflects remaining proceeds at December 31, 2024 from the issuance of solid waste disposal facility revenue bonds in 2022. For Southern Power, reflects remaining proceeds at December 31, 2024 from an arbitration award held to fund future equipment replacement costs. For Southern Company, also reflects collateral of $1 million for life insurance and long-term disability insurance, which was included at Southern Holdings and Southern Company Gas at December 31, 2025 and 2024, respectively.
Materials and Supplies
Materials and supplies for the traditional electric operating companies generally includes the average cost of transmission, distribution, and generating plant materials. Materials and supplies for Southern Company Gas generally includes the average cost of propane gas inventory, liquefied natural gas inventory, fleet fuel, and other materials and supplies. Materials and supplies for Southern Power generally includes the average cost of generating plant materials.
Materials are recorded to inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment.
Fuel Inventory
Fuel inventory for the traditional electric operating companies includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel inventory for Southern Power, which is included in other current assets, includes the average cost of oil, natural gas, and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used. Emissions allowances granted by the EPA are included in inventory at zero cost. The traditional electric operating companies recover fuel expense through fuel cost recovery rates approved by each state PSC or, for wholesale rates, the FERC.
Natural Gas for Sale
With the exception of Nicor Gas, Southern Company Gas records natural gas inventories on a weighted average cost basis. In Georgia's deregulated, competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. On a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the pipeline storage services that it has under contract, along with a corresponding amount of inventory. Atlanta Gas Light retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year-end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year-end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income. At December 31, 2025, the Nicor Gas LIFO inventory balance was $194 million. Based on the average cost of gas purchased in December 2025, the estimated replacement cost of Nicor Gas' inventory at December 31, 2025 was $420 million.
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Provision for Uncollectible Accounts
See "Recently Adopted Accounting Standards" herein for additional information on the adoption of ASU 2025-05 and the practical expedient related to credit losses.
The customers of the traditional electric operating companies and the natural gas distribution utilities are billed monthly. For the majority of receivables, a provision for uncollectible accounts is established based on historical collection experience and other factors. For the remaining receivables, if the company is aware of a specific customer's inability to pay, a provision for uncollectible accounts is recorded to reduce the receivable balance to the amount reasonably expected to be collected. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers' accounts are written off once they are deemed to be uncollectible. The Registrants have elected the practical expedient to assume that current conditions as of the balance sheet date will remain unchanged for the remaining life of the asset when estimating expected credit losses. For all periods presented, uncollectible accounts averaged less than 1% of revenues for each Registrant.
Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas' actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year.
Concentration of Credit Risk
Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for services and other costs to its customers, which consist of 14 Marketers in Georgia (including SouthStar). The credit risk exposure to the Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers in Georgia. The functions of the retail sale of gas include the purchase and sale of natural gas, customer service, billings, and collections. The provisions of Atlanta Gas Light's tariff allow Atlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill from Atlanta Gas Light.
Financial Instruments
The traditional electric operating companies and Southern Power use derivative financial instruments to limit exposure to fluctuations in interest rates, the prices of certain fuel purchases, electricity purchases and sales, and occasionally foreign currency exchange rates. Southern Company Gas uses derivative financial instruments to limit exposure to fluctuations in natural gas prices, weather, and interest rates. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (included in "Other" or shown separately as "Risk Management Activities") and are measured at fair value. See Note 13 for additional information regarding fair value. Substantially all of the traditional electric operating companies', Southern Power's, and Southern Company Gas' bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs result in the deferral of related gains and losses in AOCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 14 for additional information regarding derivatives.
The Registrants offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under netting arrangements. The Registrants had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2025.
The Registrants are exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Registrants have established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.
Southern Company Gas
Southern Company Gas enters into weather derivative contracts as economic hedges of natural gas revenues in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in natural gas revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are also reflected in natural gas revenues in the statements of income.
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Southern Company Gas enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. NYMEX futures and OTC contracts are used to capture the price differential or spread between the locations served by the capacity to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between delivery points occurs. These contracts generally meet the definition of derivatives and are carried at fair value on the balance sheets, with changes in fair value included in earnings in the period of change.
The purchase, transportation, storage, and sale of natural gas are accounted for on a weighted average cost, accrual, or LIFO basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with these transactions. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized on the statements of income in the period they are incurred. This difference in accounting methods can result in volatility in reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income attributable to the Registrant, changes in the fair value of qualifying cash flow hedges, and reclassifications for amounts included in net income. Comprehensive income also consists of certain changes in pension and other postretirement benefit plans for Southern Company, Southern Power, and Southern Company Gas.
AOCI (loss) balances, net of tax effects, for Southern Company, Southern Power, and Southern Company Gas were as follows:
| Qualifying Hedges | Pension and Other Postretirement Benefit Plans | Accumulated Other Comprehensive **Income (Loss)*() | |||||||||||||||
| (in millions) | |||||||||||||||||
| Southern Company | |||||||||||||||||
| Balance at December 31, 2022 | $ | (149) | $ | (18) | $ | (167) | |||||||||||
| Current period change | 28 | (38) | (10) | ||||||||||||||
| Balance at December 31, 2023 | (121) | (56) | (177) | ||||||||||||||
| Current period change | 75 | 24 | 99 | ||||||||||||||
| Balance at December 31, 2024 | (46) | (32) | (78) | ||||||||||||||
| Current period change | (7) | 10 | 3 | ||||||||||||||
| Balance at December 31, 2025 | $ | (53) | $ | (22) | $ | (75) | |||||||||||
| Southern Power | |||||||||||||||||
| Balance at December 31, 2022 | $ | (9) | $ | (9) | $ | (18) | |||||||||||
| Current period change | 8 | (7) | 1 | ||||||||||||||
| Balance at December 31, 2023 | (1) | (16) | (17) | ||||||||||||||
| Current period change | 8 | 7 | 15 | ||||||||||||||
| Balance at December 31, 2024 | 7 | (9) | (2) | ||||||||||||||
| Current period change | (2) | 4 | 2 | ||||||||||||||
| Balance at December 31, 2025 | $ | 5 | $ | (5) | $ | — | |||||||||||
| Southern Company Gas | |||||||||||||||||
| Balance at December 31, 2022 | $ | (25) | $ | 56 | $ | 31 | |||||||||||
| Current period change | 1 | (16) | (15) | ||||||||||||||
| Balance at December 31, 2023 | (24) | 40 | 16 | ||||||||||||||
| Current period change | 21 | 11 | 32 | ||||||||||||||
| Balance at December 31, 2024 | (3) | 51 | 48 | ||||||||||||||
| Current period change | — | 3 | 3 | ||||||||||||||
| Balance at December 31, 2025 | $ | (3) | $ | 54 | $ | 51 |
(*)May not add due to rounding.
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Variable Interest Entities
The Registrants may hold ownership interests in a number of business ventures with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE. The primary beneficiary of a VIE is required to consolidate the VIE when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. See Note 7 for additional information regarding VIEs.
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2. 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) |
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| 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.
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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.
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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
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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
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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.
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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
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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.
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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:
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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.
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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.
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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.
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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.
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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:
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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.
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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.
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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.
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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.
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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.
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RFP for at least 1,100 MWs of utility scale and distributed generation renewable resources.
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Issuance of a capacity RFP to procure resources to meet capacity needs in 2032 and 2033.
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Strategic power delivery infrastructure plan necessary to help ensure adequate reliability and serve the projected future load growth projected in Georgia.
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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:
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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.
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Extension of 50 MWs of an existing 750-MW affiliate PPA with Mississippi Power for an additional year through December 31, 2029.
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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.
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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.
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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
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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
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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
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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.
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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
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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.
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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.
E****xcess 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
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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
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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.
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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.
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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
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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 |
3. CONTINGENCIES, COMMITMENTS, AND GUARANTEES
General Litigation Matters
The Registrants are involved in various matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements.
The Registrants intend to dispute the allegations raised in and vigorously defend against the pending legal challenges discussed below; however, the ultimate outcome of each of these matters cannot be determined at this time.
Southern Company
On July 11, 2025, a purported class action complaint was filed in the U.S. District Court for the District of Maryland against two nuclear consulting companies and all U.S. commercial nuclear power operators, or affiliated entities, including Southern Company. The purported class of plaintiffs includes all persons employed in nuclear power generation by the defendants, including nuclear operators, nuclear engineers, and nuclear technicians, from May 1, 2003 to the present. The complaint alleges that, since at least May 2003, the nuclear power industry conspired to fix and suppress employee compensation for nuclear power generation employees in violation of federal antitrust law. Although not named as defendants, other entities are accused of having
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participated in the plaintiffs' alleged conspiracy. The plaintiffs seek to recover, among other relief, unspecified monetary damages, including treble damages and attorneys' fees, and injunctive relief. On October 15, 2025, Southern Company moved to dismiss the complaint. On November 6, 2025, the plaintiffs filed an amended complaint naming Southern Nuclear, among others, as a defendant. On December 19, 2025, Southern Company and Southern Nuclear filed a motion to dismiss the amended complaint. An adverse outcome could have a material impact on Southern Company's financial statements.
Southern Company and Mississippi Power
In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2. In 2016, additional DOE grants in the amount of $137 million were awarded to the Kemper County energy facility. In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of total grants received. In 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request, which enabled Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. In connection with the DOE closeout discussions, in 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of a civil investigation related to the DOE grants. In 2023, the U.S. District Court for the Northern District of Georgia unsealed a civil action in which defendants Southern Company, SCS, and Mississippi Power were alleged to have violated certain provisions of the False Claims Act by fraudulently inducing the DOE to disburse funds pursuant to the grants. The federal government declined to intervene in the action. Later in 2023, the plaintiff, a former SCS employee, filed an amended complaint, again alleging certain violations of the False Claims Act. The plaintiff sought to recover all damages incurred personally and on behalf of the federal government caused by the defendants' alleged violations, as well as treble damages and attorneys' fees, among other relief. In February 2024, the defendants moved to dismiss the amended complaint. In August 2024, the court granted the defendants' motion in part and denied it in part, dismissing the plaintiff's False Claims Act count along with its accompanying treble damages and attorneys' fees but allowing the employment retaliation claim to proceed. In October 2024, the plaintiff requested interlocutory appeal of the court's decision, which was denied on February 25, 2025, and the defendants asserted counterclaims for conversion and misappropriation of trade secrets. In November 2024, the defendants filed a motion for judgment on the pleadings on the plaintiff's employment retaliation claim. In December 2024, the plaintiff filed a motion to dismiss the defendants' counterclaims. On July 15, 2025, the court denied the plaintiff's motion to dismiss the defendants' counterclaims and the defendants' motion for judgment on the pleadings. On August 6, 2025, the plaintiff asserted a counterclaim against the defendants. On September 8, 2025, the defendants renewed their motion for judgment on the pleadings. On November 12, 2025, the parties reached an agreement in principle to resolve the lawsuit. On January 20, 2026, the court entered an order dismissing the lawsuit. The resolution does not have a material impact on Southern Company's or Mississippi Power's financial statements.
Alabama Power
In 2022, Mobile Baykeeper filed a citizen suit in the U.S. District Court for the Southern District of Alabama alleging that Alabama Power's plan to close the Plant Barry surface impoundment utilizing a closure-in-place methodology violates the Resource Conservation and Recovery Act (RCRA) and regulations governing CCR. Among other relief requested, Mobile Baykeeper sought a declaratory judgment that the RCRA and regulations governing CCR were being violated, preliminary and injunctive relief to prevent implementation of Alabama Power's closure plan, and the development of a closure plan that satisfies regulations governing CCR requirements. Later in 2022, Alabama Power filed a motion to dismiss the case. In January 2024, the lawsuit was dismissed without prejudice by the U.S. District Court judge. In February 2024, the plaintiff filed a motion to reconsider, which was denied by the U.S. District Court judge in July 2024. In August 2024, the plaintiff filed a notice of appeal in the U.S. Court of Appeals for the Eleventh Circuit challenging the denial of the motion to reconsider the order of dismissal.
In 2023, the EPA issued a Notice of Potential Violations (NOPV) associated with Alabama Power's plan to close the Plant Barry surface impoundment. In September 2024, Alabama Power reached a settlement with the EPA resolving two of the three allegations in the NOPV related to the groundwater monitoring system and the emergency action plan at the Plant Barry surface impoundment. The settlement did not resolve the EPA's allegation relating to Alabama Power's plan to close the Plant Barry surface impoundment. Alabama Power has affirmed to the EPA its position that it is in compliance with CCR requirements.
On July 29, 2025, Coosa Riverkeeper filed a citizen suit in the U.S. District Court for the Northern District of Alabama alleging that Alabama Power's closure of the Plant Gadsden surface impoundment utilizing a closure-in-place methodology violates the RCRA and regulations governing CCR. Among other relief requested, Coosa Riverkeeper seeks declaratory judgment that Alabama Power is in violation of RCRA and regulations governing CCR, and preliminary and injunctive relief to require
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Alabama Power to close the CCR unit and operate a groundwater monitoring system in a different manner to satisfy RCRA and the regulations governing CCR requirements. On September 29, 2025, Alabama Power filed a motion to dismiss the citizen suit.
These matters could have a material impact on Alabama Power's and Southern Company's financial statements, including ARO estimates and cash flows. See Note 6 for a discussion of Alabama Power's ARO liabilities.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in the financial statements. A liability for environmental remediation costs is recognized only when a loss is determined to be probable and reasonably estimable and is reduced as expenditures are incurred. The traditional electric operating companies and the natural gas distribution utilities in Illinois and Georgia have each received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental remediation costs through regulatory mechanisms. Any difference between the liabilities accrued and costs recovered through rates is deferred as a regulatory asset or liability. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected. For all periods presented, Georgia Power recovered approximately $5 million through the ECCR tariff for environmental remediation.
Southern Company Gas is subject to environmental remediation liabilities associated with former manufactured gas plant sites. Southern Company Gas' accrued environmental remediation liability at December 31, 2025 and 2024 was based on the estimated cost of environmental investigation and remediation associated with these sites.
At December 31, 2025 and 2024, the environmental remediation liability and the balance of under recovered environmental remediation costs were reflected in the balance sheets of Southern Company, Georgia Power, and Southern Company Gas as shown in the table below. Alabama Power and Mississippi Power did not have environmental remediation liabilities at December 31, 2025 or 2024.
| Southern Company | Georgia Power | Southern Company Gas | |||||||||
| (in millions) | |||||||||||
| At December 31, 2025: | |||||||||||
| Environmental remediation liability: | |||||||||||
| Other current liabilities | $ | 34 | $ | 14 | $ | 20 | |||||
| Accrued environmental remediation | 207 | — | 207 | ||||||||
| Under recovered environmental remediation costs: | |||||||||||
| Other regulatory assets, current | $ | 28 | $ | 5 | $ | 23 | |||||
| Other regulatory assets, deferred | 214 | 8 | 206 | ||||||||
| At December 31, 2024: | |||||||||||
| Environmental remediation liability: | |||||||||||
| Other current liabilities | $ | 37 | $ | 13 | $ | 24 | |||||
| Accrued environmental remediation | 198 | — | 198 | ||||||||
| Under recovered environmental remediation costs: | |||||||||||
| Other regulatory assets, current | $ | 37 | $ | 5 | $ | 32 | |||||
| Other regulatory assets, deferred | 212 | 11 | 201 |
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of the applicable Registrants.
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Nuclear Fuel Disposal Costs
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the U.S. government entered into contracts with Alabama Power and Georgia Power that required the DOE to take title to and dispose of spent nuclear fuel generated at Plants Farley, Hatch, and Vogtle Units 1 and 2 beginning no later than January 31, 1998. The DOE has yet to commence performance of its contractual and statutory obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and Georgia Power pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.
In June 2024 and August 2024, the Court of Federal Claims entered final judgments on damages in the third and fourth round of lawsuits against the U.S. government, respectively, awarding Alabama Power a total of approximately $100 million and Georgia Power a total of approximately $121 million (based on its ownership interests), which represent claims for the period from January 1, 2011 through December 31, 2019.
In December 2024, the Alabama PSC directed Alabama Power to return the award, which was reflected as a regulatory liability at December 31, 2024, to customers through bill credits during the months of January, February, and March 2025. During the third quarter 2024, Georgia Power credited the award to accounts where the original costs were charged, which reduced rate base, fuel, and cost of service for the benefit of customers, as previously authorized by the Georgia PSC. As a result of this regulatory treatment, there was no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income.
On September 5, 2025, Alabama Power and Georgia Power filed their fifth round of lawsuits against the U.S. government in the Court of Federal Claims, seeking damages for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2020 through December 31, 2024. Damages will continue to accumulate until the issue is resolved, the U.S. government disposes of Alabama Power's and Georgia Power's spent nuclear fuel pursuant to its contractual obligations, or alternative storage is otherwise provided. No amounts have been recognized in the financial statements as of December 31, 2025 for any potential recoveries from the pending lawsuits.
The final outcome of this matter cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.
On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.
Nuclear Insurance
Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $16.3 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $500 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $166 million per incident for each licensed reactor it operates but not more than an aggregate of $25 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $332 million and $473 million, respectively, per incident, but not more than an aggregate of $49 million and $71 million, respectively, to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than November 1, 2028. See Note 5 under "Joint Ownership Agreements" for additional information on joint ownership agreements.
Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses and policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.
NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations, and have each elected a 12-week deductible waiting period for each nuclear plant.
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Under each of the NEIL policies, members are subject to assessments each year if losses exceed the accumulated funds available to the insurer. The maximum annual assessments for Alabama Power and Georgia Power as of December 31, 2025 under the NEIL policies would be $61 million and $84 million, respectively.
Claims resulting from terrorist acts and cyber events are covered under both the ANI and NEIL policies (subject to normal policy limits). The maximum aggregate that NEIL will pay for all claims resulting from terrorist acts and cyber events in any 12-month period is $3.2 billion each, plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are to be applied next toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the applicable company or to its debt trustees as may be appropriate under the policies and applicable trust indentures. In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's, Alabama Power's, and Georgia Power's financial condition, cash flows, and results of operations.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
Other Matters
Mississippi Power
Kemper County Energy Facility
In 2023, 2024, and 2025, Mississippi Power recorded charges to income associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. These charges, including related tax impacts, totaled $17 million pre-tax ($12 million after tax) in 2023, $12 million pre-tax ($9 million after tax) in 2024, and $13 million pre-tax ($10 million after tax) in 2025. The pre-tax charges are included in other operations and maintenance expenses on the statements of income. Dismantlement of the abandoned gasifier-related assets was completed at the end of 2025. Site restoration activities for the mine are substantially complete, and any additional costs are expected to be immaterial. See "General Litigation Matters – Southern Company and Mississippi Power" herein for information regarding litigation associated with the Kemper County energy facility.
Department of Revenue Audit
On March 31, 2025, the Mississippi Department of Revenue (Mississippi DOR) completed an audit of sales and use taxes paid by Mississippi Power from October 2019 to July 2024 and entered a final assessment, indicating a total amount due of $29 million, including associated penalties and interest. Mississippi Power did not agree with the audit findings and filed an administrative appeal with the Mississippi DOR on May 29, 2025. On November 4, 2025, Mississippi Power and the Mississippi DOR reached a settlement agreement on an assessment of approximately $13 million including associated penalties and interest, $11 million of which was previously paid by Mississippi Power. On November 5, 2025, Mississippi Power made a final $2 million payment. This matter is now concluded.
Pursuant to an accounting order approved by the Mississippi PSC on January 13, 2026, Mississippi Power deferred $9 million of the agreed-upon assessment related to taxes and associated interest to a regulatory asset for disposition in a future rate proceeding.
Commitments
To supply a portion of the fuel requirements of the Southern Company system's electric generating plants, the Southern Company system has entered into various long-term commitments not recognized on the balance sheets for the procurement and delivery of fossil fuel and, for Alabama Power and Georgia Power, nuclear fuel. The majority of the Registrants' fuel expense for the periods presented was purchased under long-term commitments. Each Registrant expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments.
Georgia Power has commitments, in the form of capacity purchases, regarding a portion of a 5% interest in the original cost of Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of the retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. Portions of the capacity payments made to MEAG Power for its Plant Vogtle Units 1 and 2 investment relate to costs in excess of Georgia Power's allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity is included in purchased power in Southern Company's consolidated statements of income and in purchased power, non-affiliates in Georgia Power's statements of
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income. Georgia Power's capacity payments related to this commitment totaled $3 million, $4 million, and $3 million in 2025, 2024, and 2023, respectively. At December 31, 2025, Georgia Power's estimated long-term obligations related to this commitment totaled $34 million, consisting of $2 million annually for 2026 through 2030 and $24 million thereafter.
See Note 9 for information regarding PPAs accounted for as leases.
Guarantees
SCS may enter into various types of wholesale energy and natural gas contracts acting as an agent for the traditional electric operating companies and Southern Power. Under these agreements, each of the traditional electric operating companies and Southern Power may be jointly and severally liable. Accordingly, Southern Company has entered into keep-well agreements with each of the traditional electric operating companies to ensure they will not subsidize or be responsible for any costs, losses, liabilities, or damages resulting from the inclusion of Southern Power as a contracting party under these agreements.
Alabama Power has guaranteed a $100 million principal amount long-term bank loan SEGCO entered into in 2018 and subsequently extended and amended. Georgia Power has agreed to reimburse Alabama Power for the portion of such obligation corresponding to Georgia Power's proportionate ownership of SEGCO's stock if Alabama Power is called upon to make such payment under its guarantee. At December 31, 2025, the capitalization of SEGCO consisted of $49 million of equity and $70 million of long-term debt that matures in November 2026, on which the annual interest requirement is derived from a variable rate index. SEGCO had no short-term debt outstanding at December 31, 2025. See Note 7 under "SEGCO" for additional information.
As discussed in Note 9, Alabama Power and Georgia Power have entered into certain residual value guarantees related to railcar leases, with Georgia Power's railcar leases being terminated as of June 2024.
4. REVENUE FROM CONTRACTS WITH CUSTOMERS
The Registrants generate revenues from a variety of sources, some of which are not accounted for as revenue from contracts with customers, such as leases, derivatives, and certain cost recovery mechanisms. Included in the wholesale electric revenues of the traditional electric operating companies and Southern Power are revenues associated with affiliate transactions. These revenues are generated through long-term PPAs or short-term energy sales made in accordance with the IIC, as approved by the FERC. Amounts related to these affiliate revenues are eliminated in consolidation for Southern Company. See Note 1 under "Affiliate Transactions" and "Revenues" for additional information. See Notes 9 and 14 for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.
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The following table disaggregates revenue from contracts with customers for the periods presented:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | ||||||||||||||||||||
| Operating revenues | ||||||||||||||||||||
| Retail electric revenues | ||||||||||||||||||||
| Residential | $ | 8,601 | $ | 3,209 | $ | 5,064 | $ | 328 | $ | — | $ | — | ||||||||
| Commercial | 6,995 | 2,071 | 4,582 | 342 | — | — | ||||||||||||||
| Industrial | 4,045 | 1,704 | 1,984 | 357 | — | — | ||||||||||||||
| Other | 123 | 10 | 104 | 9 | — | — | ||||||||||||||
| Total retail electric revenues | 19,764 | 6,994 | 11,734 | 1,036 | — | — | ||||||||||||||
| Natural gas distribution revenues | ||||||||||||||||||||
| Residential | 2,164 | — | — | — | — | 2,164 | ||||||||||||||
| Commercial | 527 | — | — | — | — | 527 | ||||||||||||||
| Transportation | 1,424 | — | — | — | — | 1,424 | ||||||||||||||
| Industrial | 44 | — | — | — | — | 44 | ||||||||||||||
| Other | 295 | — | — | — | — | 295 | ||||||||||||||
| Total natural gas distribution revenues | 4,454 | — | — | — | — | 4,454 | ||||||||||||||
| Wholesale electric revenues | ||||||||||||||||||||
| PPA energy revenues | 1,430 | 248 | 245 | 13 | 966 | — | ||||||||||||||
| PPA capacity revenues | 637 | 134 | 146 | 69 | 356 | — | ||||||||||||||
| Non-PPA revenues | 299 | 194 | 64 | 484 | 220 | — | ||||||||||||||
| Total wholesale electric revenues | 2,366 | 576 | 455 | 566 | 1,542 | — | ||||||||||||||
| Other natural gas revenues | ||||||||||||||||||||
| Gas marketing services | 569 | — | — | — | — | 569 | ||||||||||||||
| Other | 12 | — | — | — | — | 12 | ||||||||||||||
| Total other natural gas revenues | 581 | — | — | — | — | 581 | ||||||||||||||
| Other revenues | 1,777 | 265 | 805 | 55 | 18 | — | ||||||||||||||
| Total revenue from contracts with customers | 28,942 | 7,835 | 12,994 | 1,657 | 1,560 | 5,035 | ||||||||||||||
| Other revenue sources(*) | 611 | 400 | (363) | 38 | 638 | 9 | ||||||||||||||
| Total operating revenues | $ | 29,553 | $ | 8,235 | $ | 12,631 | $ | 1,695 | $ | 2,198 | $ | 5,044 | ||||||||
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2024 | ||||||||||||||||||||
| Operating revenues | ||||||||||||||||||||
| Retail electric revenues | ||||||||||||||||||||
| Residential | $ | 8,276 | $ | 3,133 | $ | 4,835 | $ | 308 | $ | — | $ | — | ||||||||
| Commercial | 6,585 | 2,042 | 4,219 | 324 | — | — | ||||||||||||||
| Industrial | 3,892 | 1,742 | 1,808 | 342 | — | — | ||||||||||||||
| Other | 124 | 13 | 102 | 9 | — | — | ||||||||||||||
| Total retail electric revenues | 18,877 | 6,930 | 10,964 | 983 | — | — | ||||||||||||||
| Natural gas distribution revenues | ||||||||||||||||||||
| Residential | 1,753 | — | — | — | — | 1,753 | ||||||||||||||
| Commercial | 417 | — | — | — | — | 417 | ||||||||||||||
| Transportation | 1,295 | — | — | — | — | 1,295 | ||||||||||||||
| Industrial | 34 | — | — | — | — | 34 | ||||||||||||||
| Other | 316 | — | — | — | — | 316 | ||||||||||||||
| Total natural gas distribution revenues | 3,815 | — | — | — | — | 3,815 | ||||||||||||||
| Wholesale electric revenues | ||||||||||||||||||||
| PPA energy revenues | 1,059 | 206 | 94 | 4 | 778 | — | ||||||||||||||
| PPA capacity revenues | 641 | 108 | 136 | 63 | 400 | — | ||||||||||||||
| Non-PPA revenues | 226 | 139 | 5 | 375 | 230 | — | ||||||||||||||
| Total wholesale electric revenues | 1,926 | 453 | 235 | 442 | 1,408 | — | ||||||||||||||
| Other natural gas revenues | ||||||||||||||||||||
| Gas marketing services | 507 | — | — | — | — | 507 | ||||||||||||||
| Other | 18 | — | — | — | — | 18 | ||||||||||||||
| Total other natural gas revenues | 525 | — | — | — | — | 525 | ||||||||||||||
| Other revenues | 1,621 | 240 | 721 | 52 | 37 | — | ||||||||||||||
| Total revenue from contracts with customers | 26,764 | 7,623 | 11,920 | 1,477 | 1,445 | 4,340 | ||||||||||||||
| Other revenue sources(*) | (40) | (69) | (589) | (14) | 569 | 116 | ||||||||||||||
| Total operating revenues | $ | 26,724 | $ | 7,554 | $ | 11,331 | $ | 1,463 | $ | 2,014 | $ | 4,456 | ||||||||
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2023 | ||||||||||||||||||||
| Operating revenues | ||||||||||||||||||||
| Retail electric revenues | ||||||||||||||||||||
| Residential | $ | 7,309 | $ | 2,904 | $ | 4,105 | $ | 300 | $ | — | $ | — | ||||||||
| Commercial | 5,860 | 1,928 | 3,624 | 308 | — | — | ||||||||||||||
| Industrial | 3,613 | 1,721 | 1,558 | 334 | — | — | ||||||||||||||
| Other | 112 | 12 | 91 | 9 | — | — | ||||||||||||||
| Total retail electric revenues | 16,894 | 6,565 | 9,378 | 951 | — | — | ||||||||||||||
| Natural gas distribution revenues | ||||||||||||||||||||
| Residential | 1,981 | — | — | — | — | 1,981 | ||||||||||||||
| Commercial | 505 | — | — | — | — | 505 | ||||||||||||||
| Transportation | 1,184 | — | — | — | — | 1,184 | ||||||||||||||
| Industrial | 45 | — | — | — | — | 45 | ||||||||||||||
| Other | 324 | — | — | — | — | 324 | ||||||||||||||
| Total natural gas distribution revenues | 4,039 | — | — | — | — | 4,039 | ||||||||||||||
| Wholesale electric revenues | ||||||||||||||||||||
| PPA energy revenues | 1,107 | 234 | 87 | 20 | 790 | — | ||||||||||||||
| PPA capacity revenues | 624 | 156 | 51 | 45 | 376 | — | ||||||||||||||
| Non-PPA revenues | 250 | 65 | 35 | 407 | 409 | — | ||||||||||||||
| Total wholesale electric revenues | 1,981 | 455 | 173 | 472 | 1,575 | — | ||||||||||||||
| Other natural gas revenues | ||||||||||||||||||||
| Gas marketing services | 528 | — | — | — | — | 528 | ||||||||||||||
| Other | 31 | — | — | — | — | 31 | ||||||||||||||
| Total other natural gas revenues | 559 | — | — | — | — | 559 | ||||||||||||||
| Other revenues | 1,355 | 213 | 578 | 39 | 55 | — | ||||||||||||||
| Total revenue from contracts with customers | 24,828 | 7,233 | 10,129 | 1,462 | 1,630 | 4,598 | ||||||||||||||
| Other revenue sources(*) | 425 | (183) | (11) | 12 | 559 | 104 | ||||||||||||||
| Total operating revenues | $ | 25,253 | $ | 7,050 | $ | 10,118 | $ | 1,474 | $ | 2,189 | $ | 4,702 |
(*)Other revenue sources relate to revenues from customers accounted for as derivatives and leases, alternative revenue programs primarily at Southern Company Gas, and cost recovery mechanisms and revenues (including those related to fuel costs) that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.
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Contract Balances
The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at December 31, 2025 and 2024:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Accounts Receivable | ||||||||||||||||||||
| At December 31, 2025 | $ | 3,139 | $ | 716 | $ | 1,278 | $ | 115 | $ | 132 | $ | 864 | ||||||||
| At December 31, 2024 | 3,048 | 783 | 1,244 | 113 | 106 | 660 | ||||||||||||||
| Contract Assets | ||||||||||||||||||||
| At December 31, 2025 | $ | 294 | $ | 3 | $ | 160 | $ | — | $ | — | $ | 67 | ||||||||
| At December 31, 2024 | 323 | 3 | 184 | — | — | 72 | ||||||||||||||
| Contract Liabilities | ||||||||||||||||||||
| At December 31, 2025 | $ | 213 | $ | 6 | $ | 75 | $ | — | $ | 2 | $ | — | ||||||||
| At December 31, 2024 | 140 | 11 | 34 | — | 2 | 3 |
Contract assets for Georgia Power primarily relate to retail customer fixed bill programs, where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over a one-year contract term, and unregulated service agreements, where payment is contingent on project completion. Contract liabilities for Georgia Power primarily relate to cash collections recognized in advance of revenue for unregulated service agreements. Southern Company Gas' contract assets relate to work performed on an energy efficiency enhancement and upgrade contract with the U.S. General Services Administration. Southern Company Gas received cash advances totaling $68 million from a third-party financial institution to fund work performed. These advances have been accounted for as long-term debt on the balance sheets. See Note 1 under "Affiliate Transactions" for additional information regarding the construction contract. At December 31, 2025 and 2024, Southern Company's unregulated distributed generation business had contract assets of $63 million and $67 million, respectively, and contract liabilities of $132 million and $95 million, respectively, for outstanding performance obligations, all of which are expected to be satisfied within one year.
Revenues recognized in 2025 and 2024, which were included in contract liabilities at December 31, 2024 and 2023, respectively, were $102 million and $98 million, respectively, for Southern Company, $24 million and immaterial, respectively, for Georgia Power, and immaterial for the other Registrants. Contract liabilities are primarily classified as current on the balance sheets as the corresponding revenues are generally expected to be recognized within one year.
Remaining Performance Obligations
Southern Company's subsidiaries may enter into long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. For the traditional electric operating companies and Southern Power, these contracts primarily relate to PPAs whereby electricity and generation capacity are provided to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at December 31, 2025 are expected to be recognized as follows:
| 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Southern Company | $ | 1,060 | $ | 583 | $ | 408 | $ | 385 | $ | 389 | $ | 2,685 | ||||||||
| Alabama Power | 48 | 5 | 4 | 1 | 1 | 6 | ||||||||||||||
| Georgia Power | 65 | 45 | 35 | 21 | 21 | 76 | ||||||||||||||
| Mississippi Power(*) | 66 | 69 | 73 | 12 | — | — | ||||||||||||||
| Southern Power(*) | 350 | 348 | 358 | 368 | 367 | 2,603 | ||||||||||||||
(*)Includes performance obligations related to affiliate PPAs with Georgia Power. See Note 1 under "Affiliate Transactions" for additional information.
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5. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment is stated at original cost or fair value at acquisition, as appropriate, less any regulatory disallowances and impairments. Original cost may include: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and/or cost of equity funds used during construction.
The Registrants' property, plant, and equipment in service consisted of the following at December 31, 2025 and 2024:
| At December 31, 2025: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| (in millions) | ||||||||||||||||||||
| Electric utilities: | ||||||||||||||||||||
| Generation | $ | 63,533 | $ | 17,912 | $ | 27,192 | $ | 2,969 | $ | 14,986 | $ | — | ||||||||
| Transmission | 17,814 | 7,057 | 9,651 | 1,064 | — | — | ||||||||||||||
| Distribution | 31,718 | 11,058 | 19,083 | 1,577 | — | — | ||||||||||||||
| General/other | 6,854 | 2,888 | 3,532 | 362 | 48 | — | ||||||||||||||
| Electric utilities' plant in service | 119,919 | 38,915 | 59,458 | 5,972 | 15,034 | — | ||||||||||||||
| Southern Company Gas: | ||||||||||||||||||||
| Natural gas transportation and distribution | 20,177 | — | — | — | — | 20,177 | ||||||||||||||
| Storage facilities | 1,954 | — | — | — | — | 1,954 | ||||||||||||||
| Other | 1,967 | — | — | — | — | 1,967 | ||||||||||||||
| Southern Company Gas plant in service | 24,098 | — | — | — | — | 24,098 | ||||||||||||||
| Other plant in service | 2,097 | — | — | — | — | — | ||||||||||||||
| Total plant in service | $ | 146,114 | $ | 38,915 | $ | 59,458 | $ | 5,972 | $ | 15,034 | $ | 24,098 |
| At December 31, 2024: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| (in millions) | ||||||||||||||||||||
| Electric utilities: | ||||||||||||||||||||
| Generation | $ | 61,292 | $ | 16,801 | $ | 26,089 | $ | 2,946 | $ | 14,920 | $ | — | ||||||||
| Transmission | 16,280 | 6,449 | 8,800 | 989 | — | — | ||||||||||||||
| Distribution | 28,678 | 10,373 | 16,887 | 1,418 | — | — | ||||||||||||||
| General/other | 6,547 | 2,878 | 3,260 | 344 | 41 | — | ||||||||||||||
| Electric utilities' plant in service | 112,797 | 36,501 | 55,036 | 5,697 | 14,961 | — | ||||||||||||||
| Southern Company Gas: | ||||||||||||||||||||
| Natural gas transportation and distribution | 18,896 | — | — | — | — | 18,896 | ||||||||||||||
| Storage facilities | 1,748 | — | — | — | — | 1,748 | ||||||||||||||
| Other | 1,694 | — | — | — | — | 1,694 | ||||||||||||||
| Southern Company Gas plant in service | 22,338 | — | — | — | — | 22,338 | ||||||||||||||
| Other plant in service | 2,008 | — | — | — | — | — | ||||||||||||||
| Total plant in service | $ | 137,143 | $ | 36,501 | $ | 55,036 | $ | 5,697 | $ | 14,961 | $ | 22,338 |
The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed with the exception of nuclear refueling costs and certain maintenance costs including those described below.
In accordance with orders from their respective state PSCs, Alabama Power and Georgia Power defer nuclear refueling outage operations and maintenance expenses to a regulatory asset when the charges are incurred. Alabama Power amortizes the costs over a subsequent 18-month period with Plant Farley's fall outage cost amortization beginning in January of the following year and spring outage cost amortization beginning in July of the same year. Georgia Power amortizes its costs over each unit's
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operating cycle, or 18 months for Plant Vogtle Units 1 through 4 and 24 months for Plant Hatch Units 1 and 2. Georgia Power's amortization period begins the month the refueling outage starts.
The portion of Southern Company Gas' non-working gas used to maintain the structural integrity of natural gas storage facilities that is considered to be non-recoverable is depreciated, while the recoverable or retained portion is not depreciated.
See Note 9 for information on finance lease right-of-use (ROU) assets, net, which are included in property, plant, and equipment.
The Registrants have deferred certain implementation costs related to cloud hosting arrangements. At December 31, 2025 and 2024, deferred cloud implementation costs, net of amortization, which are included in other current assets and other deferred charges and assets on the Registrants' balance sheets, were as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Deferred cloud implementation costs, net: | ||||||||||||||||||||
| At December 31, 2025 | $ | 231 | $ | 73 | $ | 87 | $ | 10 | $ | 9 | $ | 21 | ||||||||
| At December 31, 2024 | 321 | 92 | 111 | 13 | 12 | 35 |
Once a hosted software is placed into service, the related deferred costs are amortized on a straight-line basis over the remaining expected hosting arrangement term, including any renewal options that are reasonably certain of exercise. The amortization is reflected with the associated cloud hosting fees, which are generally reflected in other operations and maintenance expenses on the Registrants' statements of income. Amortization of deferred cloud implementation costs recognized in 2025, 2024, and 2023 was immaterial for Mississippi Power, Southern Power, and Southern Company Gas and was as follows for the other Registrants:
| Southern Company | Alabama Power | Georgia Power | ||||||||||||
| (in millions) | ||||||||||||||
| 2025 | $ | 53 | $ | 17 | $ | 20 | ||||||||
| 2024 | 56 | 17 | 22 | |||||||||||
| 2023 | 46 | 11 | 19 |
See Note 2 under "Regulatory Assets and Liabilities" for information on deferrals of certain other operations and maintenance costs associated with software and cloud computing projects by the traditional electric operating companies and natural gas distribution utilities, as authorized by their respective state PSCs or applicable state regulatory agencies.
Depreciation and Amortization
The traditional electric operating companies' and Southern Company Gas' depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates. The approximate rates for 2025, 2024, and 2023 were as follows:
| 2025 | 2024 | 2023 | |||||||||
| Alabama Power | 4.0 | % | 4.2 | % | 4.1 | % | |||||
| Georgia Power | 3.4 | % | 3.4 | % | 3.8 | % | |||||
| Mississippi Power | 3.6 | % | 3.3 | % | 3.4 | % | |||||
| Southern Company Gas | 3.0 | % | 2.9 | % | 2.7 | % |
Depreciation studies are conducted periodically to update the composite rates. These studies are filed with the respective state PSC and/or other applicable state and federal regulatory agencies for the traditional electric operating companies and the natural gas distribution utilities. On April 1, 2025, the Mississippi PSC approved a stipulation between Mississippi Power and the Mississippi Public Utilities Staff for an $8 million increase in total annual depreciation effective January 1, 2025. See Note 2 for additional information.
When property, plant, and equipment subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation are removed from the balance sheet accounts, and a gain or loss is recognized. Minor items of property included in the original cost of the asset are retired when the related property unit is retired.
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At December 31, 2025 and 2024, accumulated depreciation for Southern Company and Southern Company Gas consisted of utility plant in service totaling $42.3 billion and $38.9 billion, respectively, for Southern Company and $6.0 billion and $5.6 billion, respectively, for Southern Company Gas, as well as other plant in service totaling $1.2 billion and $1.2 billion, respectively, for Southern Company and $265 million and $252 million, respectively, for Southern Company Gas. Other plant in service includes the non-utility assets of Southern Company Gas, as well as, for Southern Company, certain other non-utility subsidiaries. Depreciation of the original cost of other plant in service is provided primarily on a straight-line basis over estimated useful lives. Useful lives for Southern Company Gas's non-utility assets range from five to 10 years for transportation equipment, five to 40 years for storage facilities, and up to 78 years for other assets. Useful lives for the assets of Southern Company's other non-utility subsidiaries range up to 40 years.
Southern Power
Southern Power applies component depreciation, where depreciation is computed principally by the straight-line method over the estimated useful life of the asset. Certain of Southern Power's generation assets related to natural gas-fired facilities are depreciated on a units-of-production basis, using hours or starts, to better match outage and maintenance costs to the usage of, and revenues from, these assets. The primary assets in Southern Power's property, plant, and equipment are generating facilities, which generally have estimated useful lives as follows:
| Southern Power Generating Facility | Useful life | ||||
| Natural gas | Up to 50 years | ||||
| Solar | Up to 35 years | ||||
| Wind | Up to 35 years |
When Southern Power's depreciable property, plant, and equipment is retired, or otherwise disposed of in the normal course of business, the applicable cost and accumulated depreciation is removed and a gain or loss is recognized in the consolidated statements of income. Southern Power reviews its estimated useful lives and salvage values on an ongoing basis. The results of these reviews could result in changes which could have a material impact on Southern Power's net income. In 2025 and 2024, Southern Power recorded accelerated depreciation related to equipment being replaced associated with wind repowering projects of $307 million and $9 million, respectively. See Note 15 under "Southern Power – Wind Repowering Projects" for additional information.
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Joint Ownership Agreements
At December 31, 2025, the Registrants' percentage ownership and investment (exclusive of nuclear fuel) in jointly-owned facilities in commercial operation were as follows:
| Facility (Type) | Percent Ownership | Plant in Service | Accumulated Depreciation | CWIP | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||
| Plant Greene County (natural gas) Units 1 and 2 | 60.0 | % | (a) | $ | 190 | $ | 163 | $ | 2 | ||||||||||||||
| Plant Miller (coal) Units 1 and 2 | 91.8 | (b) | 2,181 | 901 | 19 | ||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Plant Hatch (nuclear) Units 1 and 2 | 50.1 | % | (c) | $ | 1,477 | $ | 593 | $ | 137 | ||||||||||||||
| Plant Vogtle (nuclear) Units 1 and 2 | 45.7 | (c) | 3,598 | 2,326 | 240 | ||||||||||||||||||
| Plant Vogtle (nuclear) Units 3 and 4 | 45.7 | (c) | 7,979 | 250 | 86 | ||||||||||||||||||
| Plant Scherer (coal) Units 1 and 2 | 8.4 | (c) | 286 | 152 | 11 | ||||||||||||||||||
| Plant Scherer (coal) Unit 3 | 75.0 | (c) | 1,323 | 793 | 56 | ||||||||||||||||||
| Rocky Mountain (pumped storage) | 25.4 | (d) | 186 | 166 | 18 | ||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Plant Greene County (natural gas) Units 1 and 2 | 40.0 | % | (a) | $ | 119 | $ | 94 | $ | 1 | ||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Dalton Pipeline (natural gas pipeline) | 50.0 | % | (e) | $ | 273 | $ | 36 | $ | 1 |
(a)Jointly owned by Alabama Power and Mississippi Power and operated and maintained by Alabama Power.
(b)Jointly owned with PowerSouth and operated and maintained by Alabama Power.
(c)Georgia Power owns undivided interests in Plants Hatch, Vogtle, and Scherer in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, Dalton, FP&L, and Jacksonville Electric Authority. Georgia Power has been contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third-party claims related to these plants.
(d)Jointly owned with OPC, which is the operator of the plant.
(e)Jointly owned with The Williams Companies, Inc., the Dalton Pipeline is a 115-mile natural gas pipeline that serves as an extension of the Transcontinental Gas Pipe Line Company, LLC pipeline system into northwest Georgia. Southern Company Gas leases its 50% undivided ownership for approximately $26 million annually through 2042. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff.
The Registrants' proportionate share of their jointly-owned facility operating expenses is included in the corresponding operating expenses in the statements of income and each Registrant is responsible for providing its own financing.
Assets Subject to Lien
Mississippi Power provides retail service to its largest retail customer, Chevron Products Company (Chevron), at its refinery in Pascagoula, Mississippi through at least 2038 in accordance with agreements approved by the Mississippi PSC. The agreements grant Chevron a security interest in the co-generation assets located at the refinery and owned by Mississippi Power, with a lease receivable balance of $130 million at December 31, 2025, that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies. See Note 9 under "Lessor" for additional information.
See Note 8 under "Long-term Debt" for information regarding debt secured by certain assets of Georgia Power and Southern Company Gas.
6. ASSET RETIREMENT OBLIGATIONS
AROs are computed as the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of
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future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as regulatory liabilities and amounts to be recovered are reflected in the balance sheets as regulatory assets.
The ARO liabilities for the traditional electric operating companies primarily relate to facilities that are subject to state and federal CCR rules, principally surface impoundments. In addition, Alabama Power and Georgia Power have retirement obligations related to the decommissioning of nuclear facilities (Alabama Power's Plant Farley and Georgia Power's ownership interests in Plants Hatch and Vogtle). See "Nuclear Decommissioning" herein for additional information. Other significant AROs include various landfill sites and asbestos removal for Alabama Power, Georgia Power, and Mississippi Power and gypsum cells and mine reclamation for Mississippi Power. The ARO liability for Southern Power primarily relates to its solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease.
The traditional electric operating companies and Southern Company Gas also have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain transformers, leasehold improvements, equipment on customer property, and property associated with the Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO.
Southern Company and the traditional electric operating companies will continue to recognize in their respective statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the various state PSCs.
Details of the AROs included in the balance sheets are as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power**(*)** | |||||||||||||
| (in millions) | |||||||||||||||||
| Balance at December 31, 2023 | $ | 10,317 | $ | 4,158 | $ | 5,665 | $ | 168 | $ | 150 | |||||||
| Liabilities incurred | 130 | 8 | 120 | — | 2 | ||||||||||||
| Liabilities settled | (566) | (254) | (270) | (17) | — | ||||||||||||
| Accretion expense | 400 | 153 | 232 | 5 | 7 | ||||||||||||
| Cash flow revisions | (347) | (7) | (332) | (8) | — | ||||||||||||
| Balance at December 31, 2024 | $ | 9,934 | $ | 4,058 | $ | 5,415 | $ | 148 | $ | 159 | |||||||
| Liabilities incurred | 6 | — | 6 | — | — | ||||||||||||
| Liabilities settled | (634) | (269) | (321) | (19) | — | ||||||||||||
| Accretion expense | 393 | 154 | 223 | 6 | 7 | ||||||||||||
| Cash flow revisions | (98) | (264) | 204 | (11) | — | ||||||||||||
| Balance at December 31, 2025 | $ | 9,601 | $ | 3,679 | $ | 5,527 | $ | 124 | $ | 166 |
(*)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
Following initial criticality for Plant Vogtle Unit 4 on February 14, 2024, Georgia Power recorded AROs of approximately $118 million. See "Nuclear Decommissioning" herein and Note 2 under "Georgia Power – Nuclear Construction" for additional information.
In September 2024, Georgia Power completed updated decommissioning cost site studies for Plants Hatch and Vogtle Units 1 through 4. The estimated cost of decommissioning based on the studies resulted in a decrease in Georgia Power's ARO liability of $389 million. See "Nuclear Decommissioning" herein for additional information.
In November 2024, Georgia Power recorded a net increase of approximately $60 million to its AROs related to the CCR Rule and the related state rule resulting from changes in estimates, including higher future inflation rates and the timing of closure activities.
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In June 2025, Alabama Power recorded a net decrease of approximately $257 million to its AROs related to the CCR Rule and the related state rule resulting from changes in estimates, including lower future inflation rates, higher discount rates, and timing of closure activities.
Also in June 2025, Mississippi Power, as a joint owner of Alabama Power's Plant Greene County Units 1 and 2, recorded a net decrease of approximately $13 million to its AROs related to the CCR Rule and the related Alabama state rule resulting from changes in estimates, including lower future inflation rates, higher discount rates, and timing of closure activities.
In November 2025, Georgia Power recorded a net increase of approximately $200 million to its AROs related to the CCR Rule and related state rule resulting from higher inflation rates, changes in estimates, and timing of closure activities.
The cost estimates for AROs related to the disposal of CCR are based on information at December 31, 2025 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule and the related state rules. The traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to these assumptions becomes available. Some of these updates have been, and future updates may be, material. The cost estimates for Alabama Power are based on closure-in-place for all surface impoundments. The cost estimates for Georgia Power and Mississippi Power are based on a combination of closure-in-place for some surface impoundments and closure by removal for others. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition for Southern Company and the traditional electric operating companies could be materially impacted. The ultimate outcome of these matters cannot be determined at this time. See Note 3 under "General Litigation Matters – Alabama Power" for additional information.
Nuclear Decommissioning
The NRC requires licensees of commercial nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. Alabama Power and Georgia Power have external trust funds (Funds) to comply with the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning activities. The Funds are managed and invested in accordance with applicable requirements of various regulatory bodies, including the NRC, the FERC, and state PSCs, as well as the IRS. While Alabama Power and Georgia Power are allowed to prescribe an overall investment policy to the Funds' managers, neither Southern Company nor its subsidiaries or affiliates are allowed to engage in the day-to-day management of the Funds or to mandate individual investment decisions. Day-to-day management of the investments in the Funds is delegated to unrelated third-party managers with oversight by the management of Alabama Power and Georgia Power. The Funds' managers are authorized, within certain investment guidelines, to actively buy and sell securities at their own discretion in order to maximize the return on the Funds' investments. The Funds are invested in a tax-efficient manner in a diversified mix of equity and fixed income securities and are reported as trading securities.
Alabama Power and Georgia Power record the investment securities held in the Funds at fair value, as disclosed in Note 13, as management believes that fair value best represents the nature of the Funds. Gains and losses, whether realized or unrealized, are recorded in the regulatory liability for AROs in the balance sheets and are not included in net income or OCI. Fair value adjustments and realized gains and losses are determined on a specific identification basis.
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Investment securities in the Funds at December 31, 2025 and 2024 were as follows:
| Southern Company | Alabama Power | Georgia Power | |||||||||
| (in millions) | |||||||||||
| At December 31, 2025: | |||||||||||
| Equity securities | $ | 1,609 | $ | 963 | $ | 646 | |||||
| Debt securities | 1,082 | 363 | 719 | ||||||||
| Other securities | 254 | 214 | 40 | ||||||||
| Total investment securities in the Funds | $ | 2,945 | $ | 1,540 | $ | 1,405 | |||||
| At December 31, 2024: | |||||||||||
| Equity securities | $ | 1,413 | $ | 848 | $ | 565 | |||||
| Debt securities | 976 | 335 | 641 | ||||||||
| Other securities | 232 | 202 | 30 | ||||||||
| Total investment securities in the Funds | $ | 2,621 | $ | 1,385 | $ | 1,236 |
These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases.
The fair value increases (decreases) of the Funds, including unrealized gains (losses) and reinvested interest and dividends and excluding the Funds' expenses, for 2025, 2024, and 2023 are shown in the table below.
| Southern Company | Alabama Power | Georgia Power | |||||||||
| (in millions) | |||||||||||
| Fair value increases | |||||||||||
| 2025 | $ | 348 | $ | 191 | $ | 157 | |||||
| 2024 | 229 | 143 | 86 | ||||||||
| 2023 | 281 | 157 | 124 | ||||||||
| Unrealized gains | |||||||||||
| At December 31, 2025 | $ | 216 | $ | 111 | $ | 105 | |||||
| At December 31, 2024 | 113 | 64 | 49 | ||||||||
| At December 31, 2023 | 241 | 119 | 122 |
The investment securities held in the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.
For Alabama Power, approximately $11 million and $12 million at December 31, 2025 and 2024, respectively, previously recorded in internal reserves is being transferred into the Funds through 2040 as approved by the Alabama PSC.
The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission only the radioactive portions of a nuclear unit based on the size and type of reactor. Alabama Power and Georgia Power have filed plans with the NRC designed to ensure that, over time, the deposits and earnings of the Funds will provide the minimum funding amounts prescribed by the NRC.
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At December 31, 2025 and 2024, the accumulated provisions for the external decommissioning trust funds were as follows:
| 2025 | 2024 | |||||||
| (in millions) | ||||||||
| Alabama Power | ||||||||
| Plant Farley | $ | 1,540 | $ | 1,385 | ||||
| Georgia Power | ||||||||
| Plant Hatch | $ | 825 | $ | 735 | ||||
| Plant Vogtle Units 1 and 2 | 519 | 460 | ||||||
| Plant Vogtle Units 3 and 4 | 61 | 41 | ||||||
| Total | $ | 1,405 | $ | 1,236 |
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on removal of the plant from service and prompt dismantlement. The actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates. The estimated costs of decommissioning at December 31, 2025 based on the most current studies were as follows:
| Alabama Power | Georgia Power**(*)** | ||||||||||||||||||||||
| Plant Farley | Plant Hatch | Plant Vogtle Units 1 and 2 | Plant Vogtle Unit 3 and 4 | ||||||||||||||||||||
| Most current study year | 2023 | 2024 | 2024 | 2024 | |||||||||||||||||||
| Decommissioning periods: | |||||||||||||||||||||||
| Beginning year | 2037 | 2034 | 2047 | 2062 | |||||||||||||||||||
| Completion year | 2087 | 2088 | 2092 | 2074 | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Site study costs: | |||||||||||||||||||||||
| Radiated structures | $ | 1,402 | $ | 795 | $ | 674 | $ | 599 | |||||||||||||||
| Spent fuel management | 513 | 306 | 255 | 88 | |||||||||||||||||||
| Non-radiated structures | 133 | 77 | 107 | 89 | |||||||||||||||||||
| Total site study costs | $ | 2,048 | $ | 1,178 | $ | 1,036 | $ | 776 |
(*)Based on Georgia Power's ownership interests.
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management. Significant assumptions used to determine these costs for ratemaking were an estimated inflation rate of 4.5% for Plant Farley, 2.5% for Plants Hatch and Vogtle Units 1 and 2, and 2.3% for Plant Vogtle Units 3 and 4 and an estimated trust earnings rate of 7.0% for Plant Farley, 4.5% for Plants Hatch and Vogtle Units 1 and 2, and 4.3% for Plant Vogtle Units 3 and 4.
Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power's site-specific estimates of decommissioning costs for Plant Farley are updated every five years. The next site study for Alabama Power is expected to be completed in 2028. Projections of funds are reviewed with the Alabama PSC to ensure that, over time, the deposits and earnings of the Funds will provide adequate funding to cover the site-specific costs. If necessary, Alabama Power would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
Effective January 1, 2023, as approved in the 2022 ARP, there is no annual decommissioning cost for ratemaking for Plant Hatch and Plant Vogtle Units 1 and 2. Any funding amount required by the NRC during the period covered by the 2022 ARP, including the ARP Extension Period, will be deferred to a regulatory asset and recovery is expected to be determined in Georgia Power's next base rate case. See Note 2 under "Georgia Power – Rate Plans – 2022 ARP" for additional information. Effective August 1, 2023, as approved under the Plant Vogtle Unit 3 and Common Facilities rate proceeding, Georgia Power's annual decommissioning cost for ratemaking is $8 million for Plant Vogtle Unit 3. Effective May 1, 2024, as approved under the
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Prudency Stipulation, Georgia Power's annual decommissioning cost for ratemaking is $8 million for Plant Vogtle Unit 4. See Note 2 under "Georgia Power – Nuclear Construction – Regulatory Matters" for additional information.
7. CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
The Registrants may hold ownership interests in a number of business ventures with varying ownership structures. Partnership interests and other variable interests are evaluated to determine if each entity is a VIE. If a venture is a VIE for which a Registrant is the primary beneficiary, the assets, liabilities, and results of operations of the entity are consolidated. The Registrants reassess the conclusion as to whether an entity is a VIE upon certain occurrences, which are deemed reconsideration events.
For entities that are not determined to be VIEs, the Registrants evaluate whether they have control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under the control of a Registrant are consolidated, and entities over which a Registrant can exert significant influence, but which a Registrant does not control, are accounted for under the equity method of accounting.
Investments accounted for under the equity method are recorded within equity investments in unconsolidated subsidiaries in the balance sheets and, for Southern Company and Southern Company Gas, the equity income is recorded within earnings from equity method investments in the statements of income. See "SEGCO" and "Southern Company Gas" herein for additional information.
Southern Company
At December 31, 2025 and 2024, Southern Holdings had equity method investments totaling $124 million and $128 million, respectively, primarily related to investments in venture capital funds focused on energy and utility investments. The net loss from these investments totaled $18 million for the year ended December 31, 2025. Earnings/losses from these investments were immaterial for the years ended December 31, 2024 and 2023.
SEGCO
Alabama Power and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units at Plant Gaston with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. Retirement of SEGCO's generating units was previously expected to occur by December 31, 2028. However, upon further analysis, Alabama Power, in conjunction with Georgia Power, now expects to operate Plant Gaston Units 1 through 4 through December 31, 2034. See Note 2 under "Georgia Power – Integrated Resource Plans – 2025 IRP" for additional information. Alabama Power and Georgia Power account for SEGCO using the equity method; Southern Company consolidates SEGCO. The capacity of these units is sold equally to Alabama Power and Georgia Power. Alabama Power and Georgia Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and an ROE. The share of purchased power included in purchased power, affiliates in the statements of income totaled $130 million in 2025, $115 million in 2024, and $112 million in 2023 for Alabama Power and $133 million in 2025, $118 million in 2024, and $115 million in 2023 for Georgia Power.
SEGCO paid dividends of $24 million in 2025, $20 million in 2024, and $25 million in 2023, one half of which were paid to each of Alabama Power and Georgia Power. In addition, Alabama Power and Georgia Power each recognize 50% of SEGCO's net income.
Alabama Power, which owns and operates a generating unit adjacent to the SEGCO generating units, has a joint ownership agreement with SEGCO for the ownership of an associated gas pipeline. Alabama Power owns 14% of the pipeline with the remaining 86% owned by SEGCO.
See Note 3 under "Guarantees" for additional information regarding guarantees of Alabama Power and Georgia Power related to SEGCO.
Southern Power
Variable Interest Entities
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.
SP Solar
SP Solar is owned by Southern Power and a limited partner. A wholly-owned subsidiary of Southern Power is the general partner and holds a 1% ownership interest, and another wholly-owned subsidiary of Southern Power owns a 66% ownership interest. The
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limited partner holds the remaining 33% noncontrolling interest. SP Solar qualifies as a VIE since the arrangement is structured as a limited partnership and the 33% limited partner does not have substantive kick-out rights against the general partner.
At December 31, 2025 and 2024, SP Solar had total assets of $5.2 billion and $5.4 billion, respectively, total liabilities of $360 million and $372 million, respectively, and noncontrolling interests of $0.9 billion and $1.0 billion, respectively. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to the limited partner in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.
Southern Power consolidates SP Solar, as the primary beneficiary, since it controls the most significant activities of the entity, including operating and maintaining its assets. Certain transfers and sales of the assets in the VIE are subject to partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.
SP Wind
SP Wind was owned by Southern Power and three financial investors through December 31, 2025. A wholly-owned subsidiary of Southern Power owned 100% of the Class B membership interests and the three financial investors owned 100% of the Class A membership interests. In July 2025, Southern Power notified the Class A members of its intent to exercise the option to purchase all Class A membership interests in the SP Wind tax equity partnership under the terms of the limited liability agreement. On December 31, 2025, Southern Power purchased 100% of the noncontrolling Class A membership interests for approximately $282 million. Subsequent to the transaction, Southern Power became the sole owner of SP Wind and its portfolio of eight operating wind facilities, and the partnership was dissolved. See Note 15 under "Southern Power – Purchase of Renewable Facility Interests" for additional information.
Prior to this transaction, SP Wind qualified as a VIE since the structure of the arrangement was similar to a limited partnership and the Class A members did not have substantive kick-out rights against Southern Power. At December 31, 2024, SP Wind had total assets of $2.0 billion, total liabilities of $177 million, and noncontrolling interests of $35 million.
Other Variable Interest Entities
Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights.
At December 31, 2025 and 2024, the other VIEs had total assets of $1.6 billion, total liabilities of $236 million and $224 million, respectively, and noncontrolling interests of $617 million and $691 million, respectively. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.
Equity Method Investments
During 2023, Southern Power sold its remaining equity method investments in wind projects and received proceeds totaling $50 million. Earnings (loss) from these investments, including the gains associated with the sales, were immaterial for 2023.
Southern Company Gas
The carrying amounts of Southern Company Gas' equity method investments at December 31, 2025 and 2024 were as follows:
| Investment Balance | At December 31, 2025 | At December 31, 2024 | ||||||
| (in millions) | ||||||||
| SNG | $ | 1,148 | $ | 1,245 | ||||
| Other | 34 | 34 | ||||||
| Total | $ | 1,182 | $ | 1,279 |
The earnings from Southern Company Gas' equity method investment related to SNG were $127 million in 2025, $146 million in 2024, and $139 million in 2023. The earnings from Southern Company Gas' other equity method investments were immaterial for all periods presented.
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8. FINANCING
Long-term Debt
Details of long-term debt at December 31, 2025 and 2024 are provided in the following table:
| At December 31, 2025 | Balance Outstanding at December 31, | ||||||||||||||||||||||
| Maturity | Weighted Average Interest Rate | 2025 | 2024 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Senior notes(a) | 2026-2075 | 4.38% | $ | 49,922 | $ | 44,862 | |||||||||||||||||
| Junior subordinated notes | 2027-2085 | 4.82% | 9,922 | 7,389 | |||||||||||||||||||
| FFB loans(b) | 2026-2044 | 2.88% | 4,617 | 4,703 | |||||||||||||||||||
| Revenue bonds(c) | 2026-2063 | 3.14% | 3,323 | 3,379 | |||||||||||||||||||
| First mortgage bonds(d) | 2026-2065 | 3.93% | 2,925 | 2,775 | |||||||||||||||||||
| Medium-term notes | 2026-2027 | 7.03% | 84 | 84 | |||||||||||||||||||
| Other long-term debt | 2026-2045 | 4.56% | 603 | 209 | |||||||||||||||||||
| Finance lease obligations(e) | 768 | 287 | |||||||||||||||||||||
| Unamortized fair value adjustment | 249 | 275 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | (56) | (58) | |||||||||||||||||||||
| Unamortized debt issuance expenses | (488) | (419) | |||||||||||||||||||||
| Total long-term debt | 71,869 | 63,486 | |||||||||||||||||||||
| Less: Amount due within one year(a) | 6,220 | 4,718 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 65,649 | $ | 58,768 | |||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||
| Senior notes | 2026-2075 | 4.02% | $ | 10,725 | $ | 9,875 | |||||||||||||||||
| Revenue bonds(c) | 2026-2063 | 3.11% | 1,300 | 1,300 | |||||||||||||||||||
| Other long-term debt | 2026-2030 | 5.32% | 65 | 61 | |||||||||||||||||||
| Finance lease obligations(e) | 12 | 4 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | (20) | (19) | |||||||||||||||||||||
| Unamortized debt issuance expenses | (69) | (67) | |||||||||||||||||||||
| Total long-term debt | 12,013 | 11,154 | |||||||||||||||||||||
| Less: Amount due within one year | 625 | 655 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 11,388 | $ | 10,499 | |||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Senior notes | 2026-2074 | 4.48% | $ | 13,692 | $ | 11,292 | |||||||||||||||||
| Junior subordinated notes | 2077 | 5.00% | 270 | 270 | |||||||||||||||||||
| FFB loans(b) | 2026-2044 | 2.88% | 4,617 | 4,703 | |||||||||||||||||||
| Revenue bonds(c) | 2026-2062 | 3.16% | 1,923 | 1,968 | |||||||||||||||||||
| Other long-term debt | 2026 | 4.59% | 400 | — | |||||||||||||||||||
| Finance lease obligations(e) | 734 | 261 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | (17) | (21) | |||||||||||||||||||||
| Unamortized debt issuance expenses | (127) | (123) | |||||||||||||||||||||
| Total long-term debt | 21,492 | 18,350 | |||||||||||||||||||||
| Less: Amount due within one year | 1,370 | 966 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 20,122 | $ | 17,384 | |||||||||||||||||||
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| At December 31, 2025 | Balance Outstanding at December 31, | ||||||||||||||||||||||
| Maturity | Weighted Average Interest Rate | 2025 | 2024 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Senior notes | 2026-2055 | 4.40% | $ | 1,675 | $ | 1,575 | |||||||||||||||||
| Revenue bonds(c) | 2027-2052 | 2.94% | 101 | 111 | |||||||||||||||||||
| Finance lease obligations(e) | 19 | 14 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | 1 | 2 | |||||||||||||||||||||
| Unamortized debt issuance expenses | (10) | (9) | |||||||||||||||||||||
| Total long-term debt | 1,786 | 1,693 | |||||||||||||||||||||
| Less: Amount due within one year | 66 | 12 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 1,720 | $ | 1,681 | |||||||||||||||||||
| Southern Power | |||||||||||||||||||||||
| Senior notes(a) | 2026-2046 | 4.65% | $ | 2,963 | $ | 2,695 | |||||||||||||||||
| Unamortized debt premium (discount), net | (6) | (4) | |||||||||||||||||||||
| Unamortized debt issuance expenses | (17) | (11) | |||||||||||||||||||||
| Total long-term debt | 2,940 | 2,680 | |||||||||||||||||||||
| Less: Amount due within one year(a) | 587 | 500 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 2,353 | $ | 2,180 | |||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Senior notes | 2026-2051 | 4.46% | $ | 5,999 | $ | 5,375 | |||||||||||||||||
| First mortgage bonds(d) | 2026-2065 | 3.93% | 2,925 | 2,775 | |||||||||||||||||||
| Medium-term notes | 2026-2027 | 7.03% | 84 | 84 | |||||||||||||||||||
| Other long-term debt | 2026-2045 | 3.81% | 68 | 68 | |||||||||||||||||||
| Unamortized fair value adjustment | 249 | 275 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | (11) | (9) | |||||||||||||||||||||
| Unamortized debt issuance expenses | (40) | (37) | |||||||||||||||||||||
| Total long-term debt | 9,274 | 8,531 | |||||||||||||||||||||
| Less: Amount due within one year | 531 | 302 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 8,743 | $ | 8,229 |
(a)Includes a fair value gain (loss) related to Southern Power's foreign currency hedge on its euro-denominated senior notes of $23 million at December 31, 2025, which is also included in amount due within one year, and $(45) million at December 31, 2024.
(b)Secured by a first priority lien on (i) Georgia Power's undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. See "DOE Loan Guarantee Borrowings" herein for additional information.
(c)Revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal and wastewater facilities. In some cases, the revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.
(d)Secured by substantially all of Nicor Gas' properties.
(e)Secured by the underlying lease ROU asset. See Note 9 for additional information.
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Maturities of long-term debt for the next five years are as follows:
| Southern Company**(a)** | Alabama Power**(b)** | Georgia Power**(c)** | Mississippi Power | Southern Power**(d)** | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2026 | $ | 6,211 | $ | 628 | $ | 1,371 | $ | 66 | $ | 564 | $ | 530 | ||||||||
| 2027 | 3,407 | 552 | 1,017 | 11 | — | 154 | ||||||||||||||
| 2028 | 5,464 | 108 | 1,619 | 358 | — | 600 | ||||||||||||||
| 2029 | 1,993 | 1 | 862 | 2 | — | 150 | ||||||||||||||
| 2030 | 4,103 | 651 | 704 | 52 | 550 | 150 |
(a)See notes (b), (c), and (d) below.
(b)Alabama Power's 2026 maturities include $200 million aggregate principal amount of Series 2023A Floating Rate Senior Notes due May 15, 2073 that are repayable at the option of the holders at certain dates that began in 2024 and $100 million aggregate principal amount of Series 2025B Floating Rate Senior Notes due August 15, 2075 that are repayable at the option of the holders at certain dates beginning in 2026. As a result, the senior notes are classified as securities due within one year on the balance sheets of Southern Company and Alabama Power at December 31, 2025.
(c)Amounts include principal amortization related to the FFB borrowings; however, the final maturity date is February 20, 2044. See "DOE Loan Guarantee Borrowings" herein for additional information. Georgia Power's 2026 maturities include approximately $117 million aggregate principal amount of Series 2024C Floating Rate Senior Notes due November 15, 2074 that are repayable at the option of the holders at certain dates that began in 2025. As a result, the senior notes are classified as securities due within one year on the balance sheets of Southern Company and Georgia Power at December 31, 2025.
(d)Southern Power's 2026 maturities include $564 million of euro-denominated debt at the U.S. dollar-denominated hedge settlement amount.
DOE Loan Guarantee Borrowings
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement in 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE agreed to guarantee the obligations of Georgia Power under the FFB Credit Facilities. Under the FFB Credit Facilities, Georgia Power was authorized to make term loan borrowings through the FFB in an amount up to approximately $5.130 billion.
In 2021, Georgia Power made the final borrowings under the FFB Credit Facilities and no further borrowings are permitted. During 2025, Georgia Power made principal amortization payments of $86 million under the FFB Credit Facilities. At December 31, 2025 and 2024, Georgia Power had $4.6 billion and $4.7 billion of borrowings outstanding under the FFB Credit Facilities, respectively.
All borrowings under the FFB Credit Facilities are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under its guarantee. Georgia Power's reimbursement obligations to the DOE are secured by a first priority lien on (i) Georgia Power's undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.
The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments began in 2020. Each borrowing under the FFB Credit Facilities bears interest at a fixed rate equal to the applicable U.S. Treasury rate at the time of the borrowing plus a spread equal to 0.375%.
Under the Amended and Restated Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events occur, Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facilities over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) loss of necessary governmental approvals for operation of Plant Vogtle Units 3 and 4; (ii) loss of regulation by the Georgia PSC; (iii) cost disallowances by the Georgia PSC that could have a material adverse effect on Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facilities; (iv) certain material casualty losses or a governmental taking of Plant Vogtle Units 3 and 4; or (v) loss of access to the intellectual property rights necessary to operate Plant Vogtle Units 3 and 4. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facilities.
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Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facilities. Under the FFB Credit Facilities, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
Secured Debt
Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries.
As discussed under "Long-term Debt" herein, the Registrants had secured debt outstanding at December 31, 2025 and 2024. Each Registrant's senior notes, junior subordinated notes, revenue bond obligations, bank term loans, credit facility borrowings, and notes payable are effectively subordinated to all secured debt of each respective Registrant.
Equity Units
In May 2022, Southern Company remarketed $862.5 million aggregate principal amount of its Series 2019A Remarketable Junior Subordinated Notes due August 1, 2024 (2019A RSNs) and $862.5 million aggregate principal amount of its Series 2019B Remarketable Junior Subordinated Notes due August 1, 2027 (2019B RSNs), pursuant to the terms of its 2019 Series A Equity Units (2019 Equity Units). In connection with the remarketing, the interest rates on the 2019A RSNs and the 2019B RSNs were reset to 4.475% and 5.113%, respectively, payable on a semi-annual basis. In August 2022, the proceeds were ultimately used to settle the purchase contracts entered into as part of the 2019 Equity Units and Southern Company issued approximately 25.2 million shares of common stock and received proceeds of $1.725 billion. In August 2024, Southern Company repaid at maturity the $862.5 million 2019A RSNs. At December 31, 2025 and 2024, the 2019B RSNs were included on Southern Company's consolidated balance sheets in long-term debt.
In November 2025, Southern Company issued 40 million 2025 Series A Equity Units (2025 Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total of $2 billion. Net proceeds from the issuance were approximately $1.965 billion. Southern Company used a portion of the net proceeds to repurchase (i) approximately $674.4 million aggregate principal amount of the Series 2023A 3.875% Convertible Senior Notes due December 15, 2025 (Series 2023A Convertible Senior Notes) and (ii) approximately $342.0 million aggregate principal amount of the Series 2024A 4.50% Convertible Senior Notes due June 15, 2027 (Series 2024A Convertible Senior Notes). See "Convertible Senior Notes" herein for additional information regarding the repurchase of convertible senior notes.
Each Corporate Unit is comprised of (i) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than December 15, 2028, a certain number of shares of Southern Company's common stock for $50 in cash (Stock Purchase Contract), (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2025B Remarketable Senior Notes due 2030 (Series 2025B RSNs), and (iii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2025C Remarketable Senior Notes due 2033 (together with the Series 2025B RSNs, the 2025 RSNs). Southern Company has agreed to remarket the 2025 RSNs in 2028, at which time each interest rate on the 2025 RSNs will reset at the applicable market rate. Holders may choose to either remarket their 2025 RSNs, receive the proceeds, and use those funds to settle the related Stock Purchase Contract or retain the 2025 RSNs and use other funds to settle the related Stock Purchase Contract. If the remarketing is unsuccessful, holders will have the right to put their 2025 RSNs to Southern Company at a price equal to the principal amount. The Corporate Units carry an annual distribution rate of 7.125% of the stated amount, which is comprised of a quarterly interest payment on the 2025 RSNs of 4.15% per year and a quarterly contract adjustment payment of 2.975% per year.
Each Stock Purchase Contract obligates the holder to purchase, and Southern Company to sell, for $50 a number of shares of Southern Company common stock determined based on the applicable market value (as determined under the related Stock Purchase Contract) in accordance with the conversion ratios set forth below (subject to anti-dilution adjustments):
-
If the applicable market value equals or exceeds $116.44, 0.4294 shares.
-
If the applicable market value is less than $116.44 but greater than $93.15, a number of shares equal to $50 divided by the applicable market value.
-
If the applicable market value is less than or equal to $93.15, 0.5368 shares.
A holder's ownership interest in the 2025 RSNs is pledged to Southern Company to secure the holder's obligation under the related Stock Purchase Contract. If a holder of a Stock Purchase Contract chooses at any time to have its 2025 RSNs released from the pledge, such holder's obligation under such Stock Purchase Contract must be secured by a U.S. Treasury security equal to the aggregate principal amount of the 2025 RSNs. At the time of issuance, the 2025 RSNs were recorded on Southern
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Company's consolidated balance sheet as long-term debt and the present value of the contract adjustment payments of $173 million was recorded as a liability, representing the obligation to make contract adjustment payments, with an offsetting reduction to paid-in capital. The liability balance at December 31, 2025 was $173 million, of which $59 million was classified as current. The difference of $12 million between the face value and present value of the contract adjustment payments will be accreted to interest expense on the consolidated statements of income over the three-year period ending in 2028. The liability recorded for the contract adjustment payments is considered non-cash and excluded from the consolidated statements of cash flow. To settle the Stock Purchase Contracts, Southern Company will be required to issue a maximum of approximately 21.5 million shares of common stock (subject to anti-dilution adjustments and a make-whole adjustment if certain fundamental changes occur).
Convertible Senior Notes
In February 2023, Southern Company issued $1.5 billion aggregate principal amount of Series 2023A Convertible Senior Notes. In March 2023, Southern Company issued an additional $225 million aggregate principal amount of the Series 2023A Convertible Senior Notes upon the exercise by the initial purchasers of their over-allotment option.
In May 2024, Southern Company issued $1.5 billion aggregate principal amount of Series 2024A Convertible Senior Notes.
In May 2025, Southern Company issued $1.65 billion aggregate principal amount of Series 2025A 3.25% Convertible Senior Notes due June 15, 2028 (Series 2025A Convertible Senior Notes). Southern Company used a portion of the proceeds from the Series 2025A Convertible Senior Notes to repurchase approximately $781.6 million of the $1.725 billion aggregate principal amount then outstanding of the Series 2023A Convertible Senior Notes and approximately $328.1 million of the $1.5 billion aggregate principal amount then outstanding of the Series 2024A Convertible Senior Notes, in each case, through privately negotiated transactions with a limited number of holders thereof.
In November 2025, using a portion the net proceeds from the 2025 Equity Units, Southern Company repurchased approximately an additional $674.4 million of the remaining approximately $943.4 million aggregate principal amount outstanding of the Series 2023A Convertible Senior Notes and approximately an additional $342.0 million of the remaining approximately $1.172 billion aggregate principal amount outstanding of the Series 2024A Convertible Senior Notes, in each case, through privately negotiated transactions with a limited number of holders thereof. See "Equity Units" herein for additional information.
Southern Company evaluated these repurchases and determined that all of the repurchased notes were accounted for as extinguishment of debt. As a result of these transactions, Southern Company recognized a total loss on extinguishment of debt of $252 million during 2025 within interest expense in the consolidated statements of income.
On December 15, 2025, the Series 2023A Convertible Senior Notes matured and Southern Company settled its related conversion obligations to holders by (i) paying cash in respect of the approximately $269.1 million aggregate principal amount remaining outstanding and (ii) issuing approximately 255 thousand shares of common stock for the excess of its conversion obligation over such principal amount. These shares were recognized at par value in paid-in capital on Southern Company's balance sheets.
Interest on the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes is payable semiannually. The Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes will mature on June 15, 2027 and 2028, respectively, unless earlier converted or repurchased, but are not redeemable at the option of Southern Company. Both the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes are direct, unsecured, and unsubordinated obligations of Southern Company, ranking equally with all of Southern Company's other unsecured and unsubordinated indebtedness from time to time outstanding, and are effectively subordinated to all secured indebtedness of Southern Company.
Under the following circumstances, holders may convert their Series 2024A Convertible Senior Notes and their Series 2025A Convertible Senior Notes at their option prior to the close of business on the business day preceding March 15, 2027 and 2028, respectively:
-
during any calendar quarter (and only during such calendar quarter), if the last reported sale price of Southern Company's common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the applicable conversion price of the Series 2024A Convertible Senior Notes or the Series 2025A Convertible Senior Notes, as the case may be, on each applicable trading day as determined by Southern Company;
-
during the five business day period after any 10 consecutive trading day period (Measurement Period) in which the applicable trading price per $1,000 principal amount of Series 2024A Convertible Senior Notes or Series 2025A Convertible Senior Notes, as the case may be, for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price of the common stock and the applicable conversion rate on each such trading day; or
-
upon the occurrence of certain corporate events specified in the respective supplemental indentures governing the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes.
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On or after March 15, 2027 and 2028, for the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes, respectively, a holder may convert all or any portion of its Series 2024A Convertible Senior Notes or its Series 2025A Convertible Senior Notes, as the case may be, at any time prior to the close of business on the second scheduled trading day immediately preceding the applicable maturity date regardless of the foregoing conditions.
Southern Company will settle conversions of the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes by paying cash up to the aggregate principal amount of the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes to be converted and paying or delivering, as the case may be, cash, shares of common stock, or a combination of cash and shares of common stock, at Southern Company's election, in respect of the remainder, if any, of Southern Company's conversion obligation in excess of the aggregate principal amount of the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes being converted. The Series 2024A Convertible Senior Notes are initially convertible at a rate of 10.8166 shares of common stock per $1,000 principal amount converted, which is approximately equal to $92.45 per share of common stock. The Series 2025A Convertible Senior Notes are initially convertible at a rate of 8.8077 shares of common stock per $1,000 principal amount converted, which is approximately equal to $113.54 per share of common stock. These conversion rates will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the respective supplemental indentures governing the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes), Southern Company will, in certain circumstances, increase the applicable conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.
Upon the occurrence of a fundamental change, other than an excluded fundamental change (each as defined in the respective supplemental indentures governing the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes), holders of the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes may require Southern Company to purchase all or a portion of their Series 2024A Convertible Senior Notes and their Series 2025A Convertible Senior Notes, in principal amounts equal to $1,000 or an integral multiple thereof, for cash at a price equal to 100% of the principal amount of the Series 2024A Convertible Senior Notes and the Series 2025A Convertible Senior Notes to be purchased plus any accrued and unpaid interest.
Equity Distribution Agreement
In May 2024, Southern Company established an at-the-market program by entering into an equity distribution agreement pursuant to which it may sell, from time to time, up to an aggregate of 50 million shares of its common stock, including through forward sale contracts.
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The table below reflects shares of Southern Company common stock sold and settled under separate forward sale contracts with forward purchasers during the years ended December 31, 2025 and 2024.
| Shares Sold | Initial Forward Price Per Share | To be Settled On or Before | Forward Price Per Share Settled | Shares Issued to Settle | Settlement Date | ||||||||||||
| Sold during 2024 | |||||||||||||||||
| 1,000,000 | $86.5645 | December 31, 2025 | $86.8151 | 1,000,000 | December 3, 2025 | ||||||||||||
| 1,000,000 | $87.9658 | December 31, 2025 | $88.1348 | 1,000,000 | December 3, 2025 | ||||||||||||
| 143,920 | $83.3293 | December 31, 2025 | $83.0276 | 143,920 | December 3, 2025 | ||||||||||||
| Sold during 2025 | |||||||||||||||||
| 292,694 | $83.3293 | December 31, 2025 | $83.0276 | 292,694 | December 3, 2025 | ||||||||||||
| 563,386 | $87.9027 | December 31, 2025 | $88.0621 | 563,386 | December 3, 2025 | ||||||||||||
| 1,000,000 | $88.7502 | June 30, 2026 | $88.8612 | 1,000,000 | December 3, 2025 | ||||||||||||
| 1,000,000 | $88.7739 | June 30, 2026 | $88.8319 | 1,000,000 | December 3, 2025 | ||||||||||||
| 1,000,000 | $91.2856 | June 30, 2026 | $91.3995 | 1,000,000 | December 3, 2025 | ||||||||||||
| 1,000,000 | $89.1444 | June 30, 2026 | $89.1404 | 1,000,000 | December 3, 2025 | ||||||||||||
| 1,000,000 | $88.8490 | June 30, 2026 | $88.8107 | 1,000,000 | December 3, 2025 | ||||||||||||
| 1,000,000 | $88.8903 | June 30, 2026 | $88.7905 | 1,000,000 | December 3, 2025 | ||||||||||||
| 1,000,000 | $90.9196 | June 30, 2026 | $90.8230 | 1,000,000 | December 3, 2025 | ||||||||||||
| 1,255,000 | $91.0566 | June 30, 2026 | $90.9450 | 1,255,000 | December 3, 2025 | ||||||||||||
| 1,324,942 | $88.7048 | December 31, 2026 | $88.7684 | 1,324,942 | December 3, 2025 | ||||||||||||
| 2,277,113 | $88.3227 | December 31, 2026 | $88.2914 | 2,277,113 | December 3, 2025 | ||||||||||||
| 3,130,641(*) | $88.2823 | December 31, 2026 | $88.1976 | 2,060,000 | December 3, 2025 | ||||||||||||
| 3,255,866 | $89.4692 | December 31, 2026 | N/A | N/A | N/A | ||||||||||||
| 3,850,000 | $90.6617 | December 31, 2026 | N/A | N/A | N/A | ||||||||||||
| 2,470,306 | $94.5394 | June 30, 2027 | N/A | N/A | N/A | ||||||||||||
| 2,314,487 | $92.7805 | June 30, 2027 | N/A | N/A | N/A | ||||||||||||
| 1,590,200 | $93.4524 | June 30, 2027 | N/A | N/A | N/A | ||||||||||||
| 4,000,000 | $90.8141 | June 30, 2027 | N/A | N/A | N/A | ||||||||||||
| 2,346,903 | $91.1610 | June 30, 2027 | N/A | N/A | N/A | ||||||||||||
| 2,876,034 | $92.2437 | June 30, 2027 | N/A | N/A | N/A | ||||||||||||
| 3,015,668 | $93.4521 | June 30, 2027 | N/A | N/A | N/A | ||||||||||||
| 911,448 | $94.2411 | June 30, 2027 | N/A | N/A | N/A |
(*)The total number of shares sold under this forward sale contract is 3,130,641, of which 2,060,000 shares were settled in December 2025. The remaining 1,070,641 shares sold under this contract are subject to be settled at a future date.
As of December 31, 2025, Southern Company had entered into separate forward sale contracts with forward purchasers for a total of 44,618,608 shares of common stock, all of which had been sold by the forward sellers. Of these shares, 16,917,055 shares had been settled under the forward sale contracts in the form of shares at the initial forward price adjusted for interest earned and dividends paid from the forward sale date to the settlement date. The net proceeds from the settlement of these shares were approximately $1.5 billion.
The total number of shares sold remaining under the forward sale contracts subject to be settled at a future date is 27,701,553. Each initial forward price is subject to adjustment under certain specified circumstances as specified in the respective forward sale contracts. Southern Company may settle each of the forward transactions in shares, cash, or net shares.
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Bank Credit Arrangements
At December 31, 2025, committed credit arrangements with banks were as follows:
| Expires | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Company | 2026 | 2027 | 2029 | 2030 | Total | Unused | Expires within One Year | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Southern Company parent(a) | $ | — | $ | 500 | $ | — | $ | 2,500 | $ | 3,000 | $ | 2,999 | $ | — | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Alabama Power(b) | 15 | — | 650 | 700 | 1,365 | 1,365 | 15 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Georgia Power(c) | — | — | — | 2,050 | 2,050 | 2,042 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Mississippi Power(a) | — | 125 | — | 150 | 275 | 275 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Southern Power(a)(d) | — | — | — | 600 | 600 | 600 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Southern Company Gas(e) | — | — | — | 1,600 | 1,600 | 1,598 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| SEGCO | 30 | — | — | — | 30 | 30 | 30 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Southern Company | $ | 45 | $ | 625 | $ | 650 | $ | 7,600 | $ | 8,920 | $ | 8,909 | $ | 45 |
(a)Arrangement expiring in 2030 represents a $3.25 billion combined arrangement for Southern Company, Mississippi Power, and Southern Power allowing for flexible sublimits. Pursuant to the combined facility, the allocations among Southern Company, Mississippi Power, and Southern Power may be adjusted.
(b)Includes $15 million expiring in 2026 at Alabama Property Company, a wholly-owned subsidiary of Alabama Power, of which $15 million was unused at December 31, 2025. Alabama Power is not party to this arrangement.
(c)Georgia Power had $26 million of letters of credit outstanding under an uncommitted letter of credit facility at December 31, 2025.
(d)Does not include Southern Power Company's $75 million and $100 million continuing letter of credit facilities for standby letters of credit, expiring in 2027 and 2028, respectively, of which $17 million and $4 million, respectively, was unused at December 31, 2025. In addition, Southern Power Company had $23 million of letters of credit outstanding under an uncommitted letter of credit facility at December 31, 2025. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(e)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the credit arrangement expiring in 2030. Southern Company Gas' committed credit arrangement expiring in 2030 also includes $800 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to the multi-year credit arrangement expiring in 2030, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted. See "Structural Considerations" herein for additional information.
The bank credit arrangements require payment of commitment fees based on the unused portion of the commitments. Commitment fees average less than 1/4 of 1% for the Registrants and Nicor Gas. Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
These bank credit arrangements, as well as the term loan arrangements of the Registrants, Nicor Gas, and SEGCO, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. The cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. Southern Company's, Mississippi Power's, Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that limit debt levels to 70% of total capitalization, as defined in the agreements, and the other subsidiaries' bank credit arrangements contain covenants that limit debt levels to 65% of total capitalization, as defined in the agreements. For purposes of these definitions, debt excludes junior subordinated notes and, in certain arrangements, other hybrid securities. Additionally, for Southern Company and Southern Power, for purposes of these definitions, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power and capitalization excludes the capital stock or other equity attributable to such subsidiaries. At December 31, 2025, the Registrants, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
A portion of the unused credit with banks is allocated to provide liquidity support to certain revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. At December 31, 2025, outstanding variable rate demand revenue bonds of the traditional electric operating companies with allocated liquidity support totaled approximately $1.5 billion (comprised of approximately $796 million at Alabama Power, $667 million at Georgia Power, and $58 million at Mississippi Power). In addition, at December 31, 2025, Alabama Power and Georgia Power had approximately $280 million and $384 million, respectively, of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. Alabama Power's $280 million of fixed rate revenue bonds are classified as securities due
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within one year on its balance sheets as they are not covered by long-term committed credit. All other variable rate demand revenue bonds and fixed rate revenue bonds required to be remarketed within the next 12 months are classified as long-term debt on the balance sheets as a result of available long-term committed credit.
At both December 31, 2025 and 2024, Southern Power had $106 million of cash collateral posted related to PPA requirements, which is included in other deferred charges and assets on Southern Power's consolidated balance sheets.
Notes Payable
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above under "Bank Credit Arrangements." Southern Power's subsidiaries are not parties or obligors to its commercial paper program. Southern Company Gas maintains commercial paper programs at Southern Company Gas Capital and at Nicor Gas. Nicor Gas' commercial paper program supports working capital needs at Nicor Gas as Nicor Gas is not permitted to make money pool loans to affiliates. All of Southern Company Gas' other subsidiaries benefit from Southern Company Gas Capital's commercial paper program. See "Structural Considerations" herein for additional information.
In addition, Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. Unless otherwise stated, the proceeds of these loans were used to repay existing indebtedness and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.
Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of short-term borrowings for the applicable Registrants were as follows:
| Notes Payable at December 31, 2025 | Notes Payable at December 31, 2024 | ||||||||||||||||||||||
| Amount Outstanding | Weighted Average Interest Rate | Amount Outstanding | Weighted Average Interest Rate | ||||||||||||||||||||
| (in millions) | (in millions) | ||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Commercial paper | $ | 722 | 3.9 | % | $ | 1,138 | 4.7 | % | |||||||||||||||
| Short-term bank debt | — | — | 200 | 5.3 | |||||||||||||||||||
| Total | $ | 722 | 3.9 | % | $ | 1,338 | 4.8 | % | |||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Commercial paper | $ | 160 | 3.9 | % | $ | — | — | % | |||||||||||||||
| Short-term bank debt | — | — | 200 | 5.3 | |||||||||||||||||||
| Total | $ | 160 | 3.9 | % | $ | 200 | 5.3 | % | |||||||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Commercial paper | $ | — | — | % | $ | 14 | 4.6 | % | |||||||||||||||
| Southern Power | |||||||||||||||||||||||
| Commercial paper | $ | 138 | 3.9 | % | $ | — | — | % | |||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Commercial paper: | |||||||||||||||||||||||
| Southern Company Gas Capital | $ | 209 | 3.9 | % | $ | 283 | 4.7 | % | |||||||||||||||
| Nicor Gas | 216 | 3.9 | 172 | 4.6 | |||||||||||||||||||
| Total | $ | 425 | 3.9 | % | $ | 455 | 4.7 | % |
See "Bank Credit Arrangements" herein for information on bank term loan covenants that limit debt levels and cross-acceleration or cross-default provisions.
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Outstanding Classes of Capital Stock
Southern Company
Common Stock
Stock Issued
During 2025, Southern Company issued approximately 22.5 million shares of common stock primarily through forward sale contract settlements and dividend reinvestment and employee equity compensation and savings plans.
See "Equity Units" and "Equity Distribution Agreement" herein for additional information.
Shares Reserved
At December 31, 2025, a total of 203 million shares were reserved for issuance pursuant to the Southern Investment Plan, employee savings plans, the Equity and Incentive Compensation Plan (which includes performance share units and restricted stock units as discussed in Note 12), an at-the-market program (including forward sale contracts), and the convertible senior notes (as discussed under "Convertible Senior Notes" herein). Of the shares reserved, 23 million shares are available for awards under the Equity and Incentive Compensation Plan at December 31, 2025.
Diluted Earnings Per Share
For Southern Company, the difference in computing basic and diluted earnings per share (EPS) is attributable to awards outstanding under stock-based compensation plans, forward sale contracts pursuant to the equity distribution agreement, convertible senior notes, and the 2025 Equity Units. EPS dilution resulting from stock-based compensation plans and the forward sale contracts is determined using the treasury stock method, and EPS dilution resulting from the convertible senior notes is determined using the net share settlement method. See Note 12 and "Convertible Senior Notes," "Equity Distribution Agreement," and "Equity Units" herein for additional information. Shares used to compute diluted EPS were as follows:
| Average Common Stock Shares | |||||||||||
| 2025 | 2024 | 2023 | |||||||||
| (in millions) | |||||||||||
| As reported shares | 1,103 | 1,096 | 1,092 | ||||||||
| Effect of stock-based compensation | 5 | 6 | 6 | ||||||||
| Effect of forward sale contracts | 1 | — | — | ||||||||
| Diluted shares | 1,109 | 1,102 | 1,098 |
For all periods presented, an immaterial number of stock-based compensation awards was excluded from the diluted EPS calculation because the awards were anti-dilutive.
For 2025 and 2024, the dilution resulting from convertible senior notes was immaterial.
Alabama Power
Alabama Power has preferred stock, Class A preferred stock, preference stock, and common stock authorized, but only common stock outstanding.
Georgia Power
Georgia Power has preferred stock, Class A preferred stock, preference stock, and common stock authorized, but only common stock outstanding.
Mississippi Power
Mississippi Power has preferred stock and common stock authorized, but only common stock outstanding.
Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2025, consolidated retained earnings included $7.5 billion of undistributed retained earnings of the subsidiaries.
The traditional electric operating companies and Southern Power can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
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See Note 7 under "Southern Power" for information regarding the distribution requirements for certain Southern Power subsidiaries.
By regulation, Nicor Gas is restricted, up to its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At December 31, 2025, the amount of Southern Company Gas' subsidiary retained earnings available for dividend payment totaled $1.8 billion.
Structural Considerations
Since Southern Company and Southern Company Gas are holding companies, the right of Southern Company and Southern Company Gas and, hence, the right of creditors of Southern Company or Southern Company Gas to participate in any distribution of the assets of any respective subsidiary of Southern Company or Southern Company Gas, whether upon liquidation, reorganization, or otherwise, is subject to prior claims of creditors and preferred stockholders of such subsidiary.
Southern Company Gas Capital was established to provide for certain of Southern Company Gas' ongoing financing needs through a commercial paper program, the issuance of various debt, hybrid securities, and other financing arrangements. Southern Company Gas fully and unconditionally guarantees all debt issued by Southern Company Gas Capital. Nicor Gas is not permitted by regulation to make loans to affiliates or utilize Southern Company Gas Capital for its financing needs.
Southern Power Company's senior notes, commercial paper, and bank credit arrangement are unsecured senior indebtedness, which rank equally with all other unsecured and unsubordinated debt of Southern Power Company. Southern Power's subsidiaries are not issuers, borrowers, or obligors, as applicable, under any of these unsecured senior debt arrangements, which are effectively subordinated to any future secured debt of Southern Power Company and any potential claims of creditors of Southern Power's subsidiaries.
9. LEASES
Lessee
The Registrants recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with ROU assets that will be amortized over the term of each lease.
As lessee, the Registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| At December 31, 2025 | ||||||||||||||||||||
| Electric generating units(*) | $ | 1,064 | $ | 53 | $ | 1,793 | $ | — | $ | — | $ | — | ||||||||
| Real estate/land | 931 | 3 | 37 | 1 | 541 | 111 | ||||||||||||||
| Communication towers | 134 | 3 | 5 | — | — | 20 | ||||||||||||||
| Railcars | 74 | 39 | 26 | 9 | — | — | ||||||||||||||
| Other | 49 | 6 | 3 | 19 | — | — | ||||||||||||||
| Total | $ | 2,252 | $ | 104 | $ | 1,864 | $ | 29 | $ | 541 | $ | 131 | ||||||||
| At December 31, 2024 | ||||||||||||||||||||
| Electric generating units(*) | $ | 672 | $ | 56 | $ | 1,509 | $ | — | $ | — | $ | — | ||||||||
| Real estate/land | 834 | 3 | 45 | 2 | 540 | 20 | ||||||||||||||
| Communication towers | 118 | 2 | 4 | — | — | 21 | ||||||||||||||
| Railcars | 64 | 31 | 29 | 4 | — | — | ||||||||||||||
| Other | 52 | 2 | 2 | 16 | — | — | ||||||||||||||
| Total | $ | 1,740 | $ | 94 | $ | 1,589 | $ | 22 | $ | 540 | $ | 41 |
(*)Amounts related to affiliate leases are eliminated in consolidation for Southern Company. See "Contracts that Contain a Lease" herein for additional information.
Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern Power. The commercial
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real estate leases have remaining terms of up to 18 years while the land leases have remaining terms of up to 41 years, including renewal periods.
Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies and Nicor Gas. Communication tower leases have remaining terms of up to 15 years.
Renewal options exist in many of the leases. The expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease unless it is considered reasonably certain that the lease will be extended. Land leases associated with renewable energy facilities at Southern Power and communication tower leases for automated meter infrastructure at Nicor Gas include renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities and the automated meter infrastructure, respectively.
Contracts that Contain a Lease
While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the PPA, which varies between three and 22 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of $782 million and $893 million at December 31, 2025 and 2024, respectively. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as reviewed and approved by both the Georgia PSC and the FERC. Amounts related to the affiliate PPAs are eliminated in consolidation for Southern Company.
Short-term Leases
Leases with an initial term of 12 months or less are not recorded on the balance sheet; the Registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.
Residual Value Guarantees
Residual value guarantees existed primarily in railcar leases at Alabama Power and Georgia Power. The remaining railcar leases containing residual value guarantees expired in 2023 for Alabama Power and in June 2024 for Georgia Power. The amounts probable of being paid under those guarantees were included in the lease payments, and all such amounts were immaterial at December 31, 2024.
Lease and Nonlease Components
For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the Registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the ROU asset.
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Balance sheet amounts recorded for operating and finance leases were as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| At December 31, 2025 | ||||||||||||||||||||
| Operating Leases | ||||||||||||||||||||
| Operating lease ROU assets, net | $ | 1,358 | $ | 86 | $ | 1,120 | $ | 9 | $ | 479 | $ | 85 | ||||||||
| Operating lease obligations - current | $ | 197 | $ | 14 | $ | 170 | $ | 4 | $ | 31 | $ | 8 | ||||||||
| Operating lease obligations - non-current | 1,287 | 78 | 960 | 6 | 510 | 123 | ||||||||||||||
| Total operating lease obligations(*) | $ | 1,484 | $ | 92 | $ | 1,130 | $ | 10 | $ | 541 | $ | 131 | ||||||||
| Finance Leases | ||||||||||||||||||||
| Finance lease ROU assets, net | $ | 742 | $ | 12 | $ | 710 | $ | 18 | $ | — | $ | — | ||||||||
| Finance lease obligations - current | $ | 16 | $ | 3 | $ | 29 | $ | 1 | $ | — | $ | — | ||||||||
| Finance lease obligations - non-current | 752 | 9 | 705 | 18 | — | — | ||||||||||||||
| Total finance lease obligations | $ | 768 | $ | 12 | $ | 734 | $ | 19 | $ | — | $ | — | ||||||||
| At December 31, 2024 | ||||||||||||||||||||
| Operating Leases | ||||||||||||||||||||
| Operating lease ROU assets, net | $ | 1,386 | $ | 84 | $ | 1,331 | $ | 8 | $ | 484 | $ | 38 | ||||||||
| Operating lease obligations - current | $ | 200 | $ | 14 | $ | 169 | $ | 4 | $ | 29 | $ | 11 | ||||||||
| Operating lease obligations - non-current | 1,253 | 76 | 1,159 | 4 | 511 | 30 | ||||||||||||||
| Total operating lease obligations(*) | $ | 1,453 | $ | 90 | $ | 1,328 | $ | 8 | $ | 540 | $ | 41 | ||||||||
| Finance Leases | ||||||||||||||||||||
| Finance lease ROU assets, net | $ | 254 | $ | 4 | $ | 227 | $ | 14 | $ | — | $ | — | ||||||||
| Finance lease obligations - current | $ | 9 | $ | 1 | $ | 20 | $ | 1 | $ | — | $ | — | ||||||||
| Finance lease obligations - non-current | 278 | 3 | 241 | 13 | — | — | ||||||||||||||
| Total finance lease obligations | $ | 287 | $ | 4 | $ | 261 | $ | 14 | $ | — | $ | — |
(*)Includes operating lease obligations related to PPAs at Southern Company, Alabama Power, and Georgia Power totaling $486 million, $53 million, and $1.1 billion, respectively, at December 31, 2025 and $567 million, $55 million, and $1.3 billion, respectively, at December 31, 2024.
If not presented separately on the Registrants' balance sheets, amounts related to leases are presented as follows: operating lease ROU assets, net are included in "other deferred charges and assets"; operating lease obligations are included in "other current liabilities" and "other deferred credits and liabilities," as applicable; finance lease ROU assets, net are included in "plant in service"; and finance lease obligations are included in "securities due within one year" and "long-term debt," as applicable.
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Lease costs for 2025, 2024, and 2023, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, were as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | ||||||||||||||||||||
| Lease cost | ||||||||||||||||||||
| Operating lease cost(*) | $ | 271 | $ | 19 | $ | 248 | $ | 5 | $ | 34 | $ | 21 | ||||||||
| Finance lease cost: | ||||||||||||||||||||
| Amortization of ROU assets | 13 | 1 | 22 | 1 | — | — | ||||||||||||||
| Interest on lease obligations | 11 | — | 12 | — | — | — | ||||||||||||||
| Total finance lease cost | 24 | 1 | 34 | 1 | — | — | ||||||||||||||
| Short-term lease costs | 45 | 22 | 15 | — | — | — | ||||||||||||||
| Variable lease cost | 52 | — | 79 | — | 6 | — | ||||||||||||||
| Total lease cost | $ | 392 | $ | 42 | $ | 376 | $ | 6 | $ | 40 | $ | 21 | ||||||||
| 2024 | ||||||||||||||||||||
| Lease cost | ||||||||||||||||||||
| Operating lease cost(*) | $ | 248 | $ | 19 | $ | 190 | $ | 4 | $ | 27 | $ | 12 | ||||||||
| Finance lease cost: | ||||||||||||||||||||
| Amortization of ROU assets | 20 | 2 | 23 | 1 | — | — | ||||||||||||||
| Interest on lease obligations | 15 | — | 15 | 1 | — | — | ||||||||||||||
| Total finance lease cost | 35 | 2 | 38 | 2 | — | — | ||||||||||||||
| Short-term lease costs | 37 | 15 | 15 | — | — | — | ||||||||||||||
| Variable lease cost | 48 | (1) | 77 | — | 4 | — | ||||||||||||||
| Total lease cost | $ | 368 | $ | 35 | $ | 320 | $ | 6 | $ | 31 | $ | 12 | ||||||||
| 2023 | ||||||||||||||||||||
| Lease cost | ||||||||||||||||||||
| Operating lease cost(*) | $ | 252 | $ | 16 | $ | 192 | $ | 5 | $ | 34 | $ | 12 | ||||||||
| Finance lease cost: | ||||||||||||||||||||
| Amortization of ROU assets | 24 | 2 | 19 | 1 | — | — | ||||||||||||||
| Interest on lease obligations | 14 | — | 17 | — | — | — | ||||||||||||||
| Total finance lease cost | 38 | 2 | 36 | 1 | — | — | ||||||||||||||
| Short-term lease costs | 40 | 16 | 16 | — | — | — | ||||||||||||||
| Variable lease cost | 47 | — | 74 | — | 4 | — | ||||||||||||||
| Total lease cost | $ | 377 | $ | 34 | $ | 318 | $ | 6 | $ | 38 | $ | 12 |
(*)Includes operating lease costs related to PPAs at Southern Company, Alabama Power, and Georgia Power totaling $113 million, $5 million, and $222 million, respectively, in 2025, $108 million, $5 million, and $168 million, respectively, in 2024, and $112 million, $4 million, and $174 million, respectively, in 2023.
Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs, including $49 million, $45 million, and $42 million in 2025, 2024, and 2023, respectively, from finance leases which are included in purchased power on Georgia Power's statements of income, of which $23 million, $22 million, and $21 million was included in purchased power, affiliates in 2025, 2024, and 2023, respectively.
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Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | ||||||||||||||||||||
| Other information | ||||||||||||||||||||
| Cash paid for amounts included in the measurements of lease obligations: | ||||||||||||||||||||
| Operating cash flows from operating leases | $ | 270 | $ | 19 | $ | 257 | $ | 4 | $ | 33 | $ | 13 | ||||||||
| Operating cash flows from finance leases | 11 | — | 17 | — | — | — | ||||||||||||||
| Financing cash flows from finance leases | 21 | 2 | 32 | 1 | — | — | ||||||||||||||
| ROU assets obtained under operating leases | 168 | 16 | 18 | 6 | 2 | 61 | ||||||||||||||
| ROU assets obtained under finance leases | 509 | 10 | 513 | 6 | — | — | ||||||||||||||
| 2024 | ||||||||||||||||||||
| Other information | ||||||||||||||||||||
| Cash paid for amounts included in the measurements of lease obligations: | ||||||||||||||||||||
| Operating cash flows from operating leases | $ | 243 | $ | 19 | $ | 186 | $ | 4 | $ | 33 | $ | 12 | ||||||||
| Operating cash flows from finance leases | 15 | — | 21 | — | — | — | ||||||||||||||
| Financing cash flows from finance leases | 11 | 2 | 23 | 1 | — | — | ||||||||||||||
| ROU assets obtained under operating leases | 146 | 11 | 609 | — | 10 | 1 | ||||||||||||||
| Reassessment of ROU assets under operating leases | (7) | — | — | — | (7) | — | ||||||||||||||
| ROU assets obtained under finance leases | 1 | — | 44 | — | — | — | ||||||||||||||
| 2023 | ||||||||||||||||||||
| Other information | ||||||||||||||||||||
| Cash paid for amounts included in the measurements of lease obligations: | ||||||||||||||||||||
| Operating cash flows from operating leases | $ | 253 | $ | 17 | $ | 199 | $ | 5 | $ | 33 | $ | 12 | ||||||||
| Operating cash flows from finance leases | 15 | — | 22 | — | — | — | ||||||||||||||
| Financing cash flows from finance leases | 18 | 2 | 16 | 1 | — | — | ||||||||||||||
| ROU assets obtained under operating leases | 100 | 30 | 26 | 1 | 7 | 7 | ||||||||||||||
| ROU assets obtained under finance leases | 3 | 3 | 18 | — | — | — |
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| At December 31, 2025 | ||||||||||||||||||||
| Weighted-average remaining lease term in years: | ||||||||||||||||||||
| Operating leases | 16.0 | 9.7 | 7.0 | 4.6 | 31.4 | 10.9 | ||||||||||||||
| Finance leases | 19.8 | 3.4 | 18.1 | 10.1 | N/A | N/A | ||||||||||||||
| Weighted-average discount rate: | ||||||||||||||||||||
| Operating leases | 4.88 | % | 5.07 | % | 4.82 | % | 4.58 | % | 4.96 | % | 5.30 | % | ||||||||
| Finance leases | 5.38 | % | 4.38 | % | 5.68 | % | 3.78 | % | N/A | N/A | ||||||||||
| At December 31, 2024 | ||||||||||||||||||||
| Weighted-average remaining lease term in years: | ||||||||||||||||||||
| Operating leases | 16.4 | 10.2 | 7.9 | 4.3 | 32.3 | 6.8 | ||||||||||||||
| Finance leases | 16.0 | 2.7 | 10.1 | 10.9 | N/A | N/A | ||||||||||||||
| Weighted-average discount rate: | ||||||||||||||||||||
| Operating leases | 4.73 | % | 5.04 | % | 4.73 | % | 3.83 | % | 4.88 | % | 3.84 | % | ||||||||
| Finance leases | 4.86 | % | 4.05 | % | 5.8 | % | 2.74 | % | N/A | N/A |
Maturities of lease liabilities are as follows:
| At December 31, 2025 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Maturity Analysis | ||||||||||||||||||||
| Operating leases: | ||||||||||||||||||||
| 2026 | $ | 233 | $ | 18 | $ | 221 | $ | 4 | $ | 33 | $ | 9 | ||||||||
| 2027 | 217 | 15 | 218 | 2 | 29 | 15 | ||||||||||||||
| 2028 | 202 | 11 | 216 | 2 | 30 | 16 | ||||||||||||||
| 2029 | 168 | 9 | 195 | 1 | 30 | 15 | ||||||||||||||
| 2030 | 118 | 9 | 111 | 1 | 30 | 16 | ||||||||||||||
| Thereafter | 1,294 | 56 | 378 | 1 | 954 | 110 | ||||||||||||||
| Total | 2,232 | 118 | 1,339 | 11 | 1,106 | 181 | ||||||||||||||
| Less: Present value discount | 748 | 26 | 209 | 1 | 565 | 50 | ||||||||||||||
| Operating lease obligations | $ | 1,484 | $ | 92 | $ | 1,130 | $ | 10 | $ | 541 | $ | 131 | ||||||||
| Finance leases: | ||||||||||||||||||||
| 2026 | $ | 33 | $ | 3 | $ | 47 | $ | 2 | $ | — | $ | — | ||||||||
| 2027 | 32 | 2 | 47 | 2 | — | — | ||||||||||||||
| 2028 | 44 | 2 | 59 | 2 | — | — | ||||||||||||||
| 2029 | 65 | 1 | 82 | 2 | — | — | ||||||||||||||
| 2030 | 67 | 1 | 63 | 2 | — | — | ||||||||||||||
| Thereafter | 1,130 | 6 | 985 | 14 | — | — | ||||||||||||||
| Total | 1,371 | 15 | 1,283 | 24 | — | — | ||||||||||||||
| Less: Present value discount | 603 | 3 | 549 | 5 | — | — | ||||||||||||||
| Finance lease obligations | $ | 768 | $ | 12 | $ | 734 | $ | 19 | $ | — | $ | — |
Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis.
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At December 31, 2025, Georgia Power has one affiliate PPA with Southern Power that has not yet commenced and will be accounted for as a lease. The PPA has a term of 10 years and is expected to commence in 2028. The estimated total obligation associated with this PPA is $63 million.
Lessor
The Registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable Registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to 10 years, after which the contracts renew on a month-to-month basis at the customer's option. For Alabama Power and Georgia Power, these arrangements also include PPAs related to electric generating units accounted for as operating leases with remaining terms of one year and up to 14 years, respectively. For Mississippi Power, these arrangements also include a tolling arrangement related to an electric generating unit accounted for as a sales-type lease with a remaining term of 13 years. For Southern Power, these arrangements consist of PPAs related to electric generating units accounted for as operating leases with remaining terms of up to 21 years and PPAs related to battery energy storage facilities accounted for as sales-type leases with remaining terms of up to 16 years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 17 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with remaining terms of up to eight years.
Lease income for 2025, 2024, and 2023 was as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | ||||||||||||||||||||
| Lease income - interest income on sales-type leases | $ | 23 | $ | — | $ | — | $ | 14 | $ | 9 | $ | — | ||||||||
| Lease income - operating leases | 145 | 7 | 29 | 3 | 148 | 36 | ||||||||||||||
| Variable lease income | 408 | 1 | — | — | 442 | — | ||||||||||||||
| Total lease income | $ | 576 | $ | 8 | $ | 29 | $ | 17 | $ | 599 | $ | 36 | ||||||||
| 2024 | ||||||||||||||||||||
| Lease income - interest income on sales-type leases | $ | 24 | $ | — | $ | — | $ | 15 | $ | 9 | $ | — | ||||||||
| Lease income - operating leases | 136 | 9 | 28 | 3 | 88 | 36 | ||||||||||||||
| Variable lease income | 417 | 1 | — | — | 450 | — | ||||||||||||||
| Total lease income | $ | 577 | $ | 10 | $ | 28 | $ | 18 | $ | 547 | $ | 36 | ||||||||
| 2023 | ||||||||||||||||||||
| Lease income - interest income on sales-type leases | $ | 24 | $ | — | $ | — | $ | 14 | $ | 10 | $ | — | ||||||||
| Lease income - operating leases | 164 | 35 | 29 | 2 | 85 | 37 | ||||||||||||||
| Variable lease income | 406 | 1 | — | — | 437 | — | ||||||||||||||
| Total lease income | $ | 594 | $ | 36 | $ | 29 | $ | 16 | $ | 532 | $ | 37 |
As part of its acquisition of the Lindsay Hill Generating Station, 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. These revenues are included above as lease income from operating leases. See Note 15 under "Alabama Power" for additional information.
Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Lease income related to PPAs is included in wholesale revenues for Alabama Power, Georgia Power, and Southern Power. Scheduled payments to be received under outdoor lighting contracts' initial terms, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.
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The undiscounted cash flows expected to be received for in-service leased assets under the leases are as follows:
| At December 31, 2025 | |||||||||||
| Southern Company | Mississippi Power | Southern Power | |||||||||
| (in millions) | |||||||||||
| 2026 | $ | 39 | $ | 23 | $ | 15 | |||||
| 2027 | 38 | 22 | 15 | ||||||||
| 2028 | 37 | 21 | 15 | ||||||||
| 2029 | 36 | 20 | 15 | ||||||||
| 2030 | 34 | 19 | 15 | ||||||||
| Thereafter | 270 | 114 | 155 | ||||||||
| Total undiscounted cash flows | $ | 454 | $ | 219 | $ | 230 | |||||
| Net investment in sales-type lease(*) | 286 | 130 | 152 | ||||||||
| Difference between undiscounted cash flows and discounted cash flows | $ | 168 | $ | 89 | $ | 78 |
(*)For Mississippi Power, included in other current assets ($10 million and $10 million at December 31, 2025 and 2024, respectively) and other property and investments ($120 million and $129 million at December 31, 2025 and 2024, respectively) on the balance sheets. For Southern Power, included in other current assets ($15 million and $15 million at December 31, 2025 and 2024, respectively) and net investment in sales-type leases ($137 million and $143 million at December 31, 2025 and 2024, respectively) on the balance sheets.
The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases are as follows:
| At December 31, 2025 | |||||||||||||||||
| Southern Company | Alabama Power | Southern Power | Southern Company Gas | ||||||||||||||
| (in millions) | |||||||||||||||||
| 2026 | $ | 119 | $ | 6 | $ | 148 | $ | 35 | |||||||||
| 2027 | 111 | 5 | 150 | 28 | |||||||||||||
| 2028 | 111 | 4 | 161 | 28 | |||||||||||||
| 2029 | 116 | 4 | 164 | 28 | |||||||||||||
| 2030 | 115 | 3 | 103 | 28 | |||||||||||||
| Thereafter | 554 | 34 | 400 | 299 | |||||||||||||
| Total | $ | 1,126 | $ | 56 | $ | 1,126 | $ | 446 |
Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Alabama Power and Southern Power allocate revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under contracts accounted for as operating leases at Georgia Power and Mississippi Power are immaterial.
Southern Company Leveraged Lease
At December 31, 2025, a subsidiary of Southern Holdings had one leveraged lease agreement, which relates to energy generation, with an expected remaining term of six years. Southern Company receives federal income tax deductions for depreciation and amortization, as well as interest on long-term debt, related to this investment. Southern Company wrote off the related investment balance in 2020 following an evaluation of the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease.
In June 2022, the Southern Holdings subsidiary operating the generating plant for the lessee provided notice to the lessee to terminate the related operating and maintenance agreement effective June 30, 2023. Subsequently, the lessee failed to make the semi-annual lease payment due in December 2022. As a result, the Southern Holdings subsidiary was unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. The parties to the lease entered into forbearance agreements which suspended the related contractual rights of the parties while they continued restructuring negotiations, during which the termination date for the operating and maintenance agreement was delayed until July 31, 2023. The negotiations were completed in July 2023, resulting in the Southern Holdings subsidiary agreeing to continue operating the plant for the lessee until the lessee's associated power off-take agreement ends in 2032, subject to certain terms and conditions. The restructuring had no material impact on Southern Company's financial statements. Southern Company will
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continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to meet its obligations, including those associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.
10. INCOME TAXES
Southern Company files a consolidated federal income tax return, and the Registrants file various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis, and each subsidiary is allocated an amount of tax similar to that which would be paid if it filed a separate income tax return except for certain credit utilization and state apportionment results. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
| 2025 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Federal — | ||||||||||||||||||||
| Current | $ | 139 | $ | 110 | $ | 99 | $ | 57 | $ | 71 | $ | 28 | ||||||||
| Deferred | 399 | 192 | 346 | (6) | (133) | 98 | ||||||||||||||
| Total federal | 538 | 302 | 445 | 51 | (62) | 126 | ||||||||||||||
| State — | ||||||||||||||||||||
| Current | 94 | 95 | 32 | (1) | (3) | 32 | ||||||||||||||
| Deferred | 196 | 28 | 125 | 15 | 4 | 24 | ||||||||||||||
| Total state | 290 | 123 | 157 | 14 | 1 | 56 | ||||||||||||||
| Total | $ | 828 | $ | 425 | $ | 602 | $ | 65 | $ | (61) | $ | 182 |
| 2024 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Federal — | ||||||||||||||||||||
| Current | $ | 221 | $ | 357 | $ | 200 | $ | 32 | $ | (112) | $ | 84 | ||||||||
| Deferred | 387 | (111) | 211 | 2 | 106 | 86 | ||||||||||||||
| Total federal | 608 | 246 | 411 | 34 | (6) | 170 | ||||||||||||||
| State — | ||||||||||||||||||||
| Current | 152 | 103 | 52 | (1) | 6 | 42 | ||||||||||||||
| Deferred | 209 | 11 | 140 | 14 | (13) | 46 | ||||||||||||||
| Total state | 361 | 114 | 192 | 13 | (7) | 88 | ||||||||||||||
| Total | $ | 969 | $ | 360 | $ | 603 | $ | 47 | $ | (13) | $ | 258 |
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| 2023 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Federal — | ||||||||||||||||||||
| Current | $ | 54 | $ | 242 | $ | 205 | $ | 49 | $ | (320) | $ | 62 | ||||||||
| Deferred | 299 | (257) | 195 | (26) | 334 | 68 | ||||||||||||||
| Total federal | 353 | (15) | 400 | 23 | 14 | 130 | ||||||||||||||
| State — | ||||||||||||||||||||
| Current | 41 | 82 | 37 | 1 | (1) | 24 | ||||||||||||||
| Deferred | 102 | 14 | 11 | 12 | (1) | 57 | ||||||||||||||
| Total state | 143 | 96 | 48 | 13 | (2) | 81 | ||||||||||||||
| Total | $ | 496 | $ | 81 | $ | 448 | $ | 36 | $ | 12 | $ | 211 |
Southern Company's and Southern Power's ITCs and PTCs generated in the current tax year and carried forward from prior tax years that cannot be utilized or transferred in the current tax year are reclassified from current to deferred taxes in federal income tax expense in the tables above. Southern Power's ITCs and PTCs reclassified in this manner were $95 million for 2025 and were immaterial for 2024 and 2023. See "Cash Paid for Income Taxes" and "Deferred Tax Assets and Liabilities" herein for additional information.
Under current tax law, certain projects are eligible for ITCs. The Registrants use the deferral method to account for federal and state ITCs, whereby the ITCs are recorded as a deferred credit and amortized to income tax expense over the useful life of the respective asset. In accordance with regulatory requirements, certain state ITCs at Georgia Power are recognized as an income tax benefit in the year the credit is generated through the establishment of a regulatory asset. ITCs amortized in 2025, 2024, and 2023 were immaterial for the traditional electric operating companies and Southern Company Gas and were as follows for Southern Company and Southern Power:
| Southern Company | Southern Power | |||||||
| (in millions) | ||||||||
| 2025 | $ | 84 | $ | 58 | ||||
| 2024 | 109 | 58 | ||||||
| 2023 | 84 | 58 |
When Southern Company recognizes tax credits, the tax basis of the asset is reduced by 50% of the ITCs received, which, together with the deferred credit, results in a net deferred tax asset. Southern Power has elected to recognize the tax benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation.
Georgia Power's state ITCs and other state credits, which are recognized in the period in which the credits are generated, reduced Georgia Power's income tax expense by $31 million in 2025, $44 million in 2024, and $49 million in 2023.
Southern Power's federal and state PTCs, which are recognized in the period in which the credits are generated, reduced Southern Power's income tax expense by $33 million in 2025, $32 million in 2024, and $26 million in 2023.
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Cash Paid for Income Taxes
The following table disaggregates income taxes paid, excluding credit transfers, (net of refunds) by federal, state, and foreign taxes for the periods presented:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | ||||||||||||||||||||
| Federal | $ | 170 | $ | 150 | $ | 53 | $ | 43 | $ | 162 | $ | 9 | ||||||||
| State | 114 | 93 | 76 | (1) | (14) | 20 | ||||||||||||||
| Total cash taxes paid | $ | 284 | $ | 243 | $ | 129 | $ | 42 | $ | 148 | $ | 29 | ||||||||
| 2024 | ||||||||||||||||||||
| Federal | $ | 123 | $ | 289 | $ | (21) | $ | 51 | $ | (22) | $ | 53 | ||||||||
| State | 53 | 98 | 7 | — | (10) | 6 | ||||||||||||||
| Total cash taxes paid (received) | $ | 176 | $ | 387 | $ | (14) | $ | 51 | $ | (32) | $ | 59 | ||||||||
| 2023 | ||||||||||||||||||||
| Federal | $ | 78 | $ | 256 | $ | 178 | $ | 52 | $ | (252) | $ | 71 | ||||||||
| State | 51 | 59 | 42 | — | (2) | 20 | ||||||||||||||
| Foreign | 3 | — | — | — | — | — | ||||||||||||||
| Total cash taxes paid (received) | $ | 132 | $ | 315 | $ | 220 | $ | 52 | $ | (254) | $ | 91 |
Income taxes paid (net of refunds) exceeded 5% of total income taxes paid (net of refunds) in the following jurisdictions for the periods presented:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | ||||||||||||||||||||
| State — | ||||||||||||||||||||
| Alabama | $ | 92 | $ | 91 | $ (*) | $ (*) | $ (*) | $ (*) | ||||||||||||
| Georgia | (*) | (*) | 74 | (*) | (11) | (*) | ||||||||||||||
| Oklahoma | (*) | (*) | (*) | (*) | (9) | (*) | ||||||||||||||
| Illinois | 20 | (*) | (*) | (*) | (*) | 20 | ||||||||||||||
| 2024 | ||||||||||||||||||||
| State — | ||||||||||||||||||||
| Alabama | $ | 99 | $ | 98 | $ (*) | $ (*) | $ (*) | $ (*) | ||||||||||||
| Georgia | (35) | (*) | 7 | (*) | 6 | 7 | ||||||||||||||
| Oklahoma | (18) | (*) | (*) | (*) | (18) | (*) | ||||||||||||||
| 2023 | ||||||||||||||||||||
| State — | ||||||||||||||||||||
| Alabama | $ | 60 | $ | 57 | $ (*) | $ (*) | $ (*) | $ (*) | ||||||||||||
| Georgia | (13) | (*) | 42 | (*) | (*) | 8 | ||||||||||||||
| Oklahoma | (9) | (*) | (*) | (*) | (*) | (*) | ||||||||||||||
| Illinois | 13 | (*) | (*) | (*) | (*) | 13 |
(*)Jurisdiction is either not applicable or below the threshold for the period presented.
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Southern Power, in 2025, paid back $95 million and, in 2024 and 2023, received $71 million and $332 million, respectively, of cash related to federal ITCs under renewable energy initiatives. See "Deferred Tax Assets and Liabilities" herein for additional information.
Alabama Power, Georgia Power, and Southern Power have entered into transferability agreements with non-affiliated parties to sell ITCs and PTCs at a discount to the generated credit value in 2024, 2025, and 2026. During 2025, Alabama Power, Georgia Power, and Southern Power received cash of $80 million, $64 million, and $24 million, respectively, from credits transferred. During 2024, Georgia Power and Southern Power received cash of $11 million and $24 million, respectively, from credits transferred. The discount is recorded as a reduction in tax credits recognized in the financial statements and does not have a material impact on results of operations. The Southern Company system continues to explore the ability to efficiently monetize its tax credits through third-party transfer agreements.
Pursuant to the Vogtle Joint Ownership Agreements, Georgia Power paid $156 million in 2025, $131 million in 2024, and $39 million in 2023 to the other Vogtle Owners for advanced nuclear PTCs for Plant Vogtle Unit 3 and 4, which were utilized and not reflected as a reduction to current income tax expense. The gains recognized in all periods were recorded in income tax benefit and were immaterial.
Effective Tax Rate
Southern Company's effective tax rate is typically lower than the statutory rate due to the flowback of excess deferred income taxes at the regulated utilities, federal income tax benefits from ITCs and PTCs primarily at Southern Power, Georgia Power, and Alabama Power, and non-taxable AFUDC equity at the traditional electric operating companies.
A reconciliation of the federal statutory income tax rate to the effective income tax (benefit) rate is as follows:
| 2025 | ||||||||||||||||||||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||||||||||||||||||||
| (in millions, except percentages) | ||||||||||||||||||||||||||||||||||||||
| Federal statutory rate | $ | 1,050 | 21.0 | % | $ | 408 | 21.0 | % | $ | 725 | 21.0 | % | $ | 59 | 21.0 | % | $ | (22) | (21.0 | %) | $ | 192 | 21.0 | % | ||||||||||||||
| State and local income tax, net of federal income tax effect(*) | 254 | 5.1 | 97 | 5.0 | 149 | 4.3 | 11 | 4.0 | 1 | 1.0 | 44 | 4.8 | ||||||||||||||||||||||||||
| Tax credits — | ||||||||||||||||||||||||||||||||||||||
| Amortization of ITCs | (56) | (1.1) | (2) | (0.1) | (2) | (0.1) | — | — | (46) | (43.7) | — | — | ||||||||||||||||||||||||||
| Federal PTCs | (166) | (3.3) | — | — | (137) | (4.0) | — | — | (28) | (26.8) | — | — | ||||||||||||||||||||||||||
| Other | (2) | — | (1) | — | (1) | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Nontaxable or nondeductible items — | ||||||||||||||||||||||||||||||||||||||
| AFUDC equity | (67) | (1.3) | (14) | (0.7) | (52) | (1.5) | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Other | 19 | 0.4 | 12 | 0.6 | 21 | 0.6 | 2 | 0.6 | — | — | (5) | (0.5) | ||||||||||||||||||||||||||
| Changes in unrecognized tax benefits | (26) | (0.5) | — | — | (26) | (0.7) | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Other adjustments — | ||||||||||||||||||||||||||||||||||||||
| Noncontrolling interests | 36 | 0.7 | — | — | — | — | — | — | 36 | 33.9 | — | — | ||||||||||||||||||||||||||
| Federal flowback of excess deferreds | (170) | (3.4) | (58) | (3.0) | (57) | (1.7) | (5) | (1.9) | — | — | (45) | (4.9) | ||||||||||||||||||||||||||
| Other | (44) | (1.0) | (17) | (0.9) | (18) | (0.5) | (2) | (0.5) | (2) | (1.2) | (4) | (0.5) | ||||||||||||||||||||||||||
| Effective income tax (benefit) rate | $ | 828 | 16.6 | % | $ | 425 | 21.9 | % | $ | 602 | 17.4 | % | $ | 65 | 23.2 | % | $ | (61) | (57.8 | %) | $ | 182 | 19.9 | % |
(*)The following states made up the majority (greater than 50%) of the tax effect in this category: for Southern Company and Georgia Power, Georgia; for Alabama Power, Alabama; for Mississippi Power, Mississippi; for Southern Power, Alabama, California, Delaware, Georgia, North Carolina, Oklahoma, and Tennessee; and for Southern Company Gas, Illinois.
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| 2024 | ||||||||||||||||||||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||||||||||||||||||||
| (in millions, except percentages) | ||||||||||||||||||||||||||||||||||||||
| Federal statutory rate | $ | 1,098 | 21.0 | % | $ | 370 | 21.0 | % | $ | 661 | 21.0 | % | $ | 52 | 21.0 | % | $ | 36 | 21.0 | % | $ | 209 | 21.0 | % | ||||||||||||||
| State and local income tax, net of federal income tax effect(*) | 305 | 5.8 | 89 | 5.0 | 184 | 5.9 | 11 | 4.4 | (4) | (2.3) | 62 | 6.2 | ||||||||||||||||||||||||||
| Foreign tax effects | 6 | 0.1 | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Effect of cross-border tax laws | (1) | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Tax credits — | ||||||||||||||||||||||||||||||||||||||
| Amortization of ITCs | (61) | (1.2) | (1) | (0.1) | (7) | (0.2) | — | — | (46) | (26.4) | — | — | ||||||||||||||||||||||||||
| Federal PTCs | (147) | (2.8) | (1) | (0.1) | (116) | (3.7) | — | — | (30) | (17.2) | — | — | ||||||||||||||||||||||||||
| Other | (3) | (0.1) | (1) | — | (1) | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Nontaxable or nondeductible items — | — | |||||||||||||||||||||||||||||||||||||
| AFUDC equity | (44) | (0.8) | (12) | (0.7) | (32) | (1.0) | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Other | 30 | 0.6 | 12 | 0.7 | 26 | 0.8 | 1 | 0.6 | 1 | 0.2 | 1 | 0.1 | ||||||||||||||||||||||||||
| Changes in unrecognized tax benefits — | ||||||||||||||||||||||||||||||||||||||
| State changes in unrecognized tax benefits from prior periods, net of federal income tax effect | (25) | (0.5) | — | — | (33) | (1.0) | — | — | — | — | 8 | 0.8 | ||||||||||||||||||||||||||
| Other adjustments — | ||||||||||||||||||||||||||||||||||||||
| Noncontrolling interests | 30 | 0.6 | — | — | — | — | — | — | 30 | 17.1 | — | — | ||||||||||||||||||||||||||
| Federal flowback of excess deferreds | (206) | (3.9) | (94) | (5.3) | (70) | (2.2) | (16) | (6.5) | — | — | (22) | (2.2) | ||||||||||||||||||||||||||
| Other | (13) | (0.3) | (2) | (0.1) | (9) | (0.4) | (1) | (0.3) | — | — | — | (0.1) | ||||||||||||||||||||||||||
| Effective income tax (benefit) rate | $ | 969 | 18.5 | % | $ | 360 | 20.4 | % | $ | 603 | 19.2 | % | $ | 47 | 19.2 | % | $ | (13) | (7.6 | %) | $ | 258 | 25.8 | % |
(*)The following states made up the majority (greater than 50%) of the tax effect in this category: for Southern Company and Georgia Power, Georgia; for Alabama Power, Alabama; for Mississippi Power, Mississippi; for Southern Power, Georgia and Oklahoma; and for Southern Company Gas, Illinois.
| 2023 | ||||||||||||||||||||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||||||||||||||||||||
| (in millions, except percentages) | ||||||||||||||||||||||||||||||||||||||
| Federal statutory rate | $ | 912 | 21.0 | % | $ | 305 | 21.0 | % | $ | 531 | 21.0 | % | $ | 47 | 21.0 | % | $ | 51 | 21.0 | % | $ | 174 | 21.0 | % | ||||||||||||||
| State and local income tax, net of federal income tax effect(*) | 117 | 2.7 | 75 | 5.2 | 45 | 1.8 | 11 | 4.9 | (2) | (0.7) | 62 | 7.6 | ||||||||||||||||||||||||||
| Tax credits — | ||||||||||||||||||||||||||||||||||||||
| Amortization of ITCs | (56) | (1.3) | (1) | (0.1) | (2) | (0.1) | — | — | (46) | (19.0) | — | — | ||||||||||||||||||||||||||
| Federal PTCs | (52) | (1.2) | — | — | (35) | (1.4) | — | — | (18) | (7.4) | — | — | ||||||||||||||||||||||||||
| Other | (4) | (0.1) | (2) | (0.1) | (2) | (0.1) | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Nontaxable or nondeductible items — | ||||||||||||||||||||||||||||||||||||||
| AFUDC equity | (48) | (1.1) | (17) | (1.2) | (31) | (1.2) | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Other | 23 | 0.5 | 14 | 1.0 | 21 | 0.8 | 1 | 0.5 | 1 | 0.4 | 1 | 0.1 | ||||||||||||||||||||||||||
| Changes in unrecognized tax benefits | (5) | (0.1) | — | — | (6) | (0.2) | — | — | — | — | 2 | 0.2 | ||||||||||||||||||||||||||
| Other adjustments — | ||||||||||||||||||||||||||||||||||||||
| Noncontrolling interests | 27 | 0.6 | — | — | — | — | — | — | 27 | 11.1 | — | — | ||||||||||||||||||||||||||
| Federal flowback of excess deferreds | (401) | (9.2) | (287) | (19.8) | (64) | (2.6) | (23) | (10.2) | — | — | (22) | (2.6) | ||||||||||||||||||||||||||
| Other | (17) | (0.4) | (6) | (0.4) | (9) | (0.2) | — | — | (1) | (0.3) | (6) | (0.7) | ||||||||||||||||||||||||||
| Effective income tax rate | $ | 496 | 11.4 | % | $ | 81 | 5.6 | % | $ | 448 | 17.8 | % | $ | 36 | 16.2 | % | $ | 12 | 5.1 | % | $ | 211 | 25.6 | % |
(*)The following states made up the majority (greater than 50%) of the tax effect in this category: for Southern Company and Alabama Power, Alabama; for Georgia Power, Georgia; for Mississippi Power, Mississippi; for Southern Power, Georgia and Oklahoma; and for Southern Company Gas, Illinois.
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Deferred Tax Assets and Liabilities
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements of the Registrants and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
| At December 31, 2025 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Deferred tax liabilities — | ||||||||||||||||||||
| Accelerated depreciation | $ | 10,234 | $ | 2,641 | $ | 4,035 | $ | 363 | $ | 1,345 | $ | 1,675 | ||||||||
| Property basis differences | 3,090 | 1,394 | 1,099 | 177 | — | 418 | ||||||||||||||
| Employee benefit obligations | 1,223 | 434 | 501 | 66 | 15 | 64 | ||||||||||||||
| AROs | 710 | 422 | 242 | — | — | — | ||||||||||||||
| Under recovered fuel and natural gas costs | 195 | 45 | 135 | 15 | — | — | ||||||||||||||
| Regulatory assets — | ||||||||||||||||||||
| AROs | 1,809 | 590 | 1,191 | 28 | — | — | ||||||||||||||
| Employee benefit obligations | 699 | 190 | 221 | 34 | — | 33 | ||||||||||||||
| Remaining book value of retired assets | 395 | 229 | 161 | 5 | — | — | ||||||||||||||
| Storm damage reserves | 236 | — | 236 | — | — | — | ||||||||||||||
| Premium on reacquired debt | 53 | 8 | 44 | 1 | — | — | ||||||||||||||
| Other | 644 | 141 | 211 | 32 | 26 | 175 | ||||||||||||||
| Total deferred income tax liabilities | 19,288 | 6,094 | 8,076 | 721 | 1,386 | 2,365 | ||||||||||||||
| Deferred tax assets — | ||||||||||||||||||||
| AROs | 2,519 | 1,012 | 1,433 | 28 | — | — | ||||||||||||||
| ITC and PTC carryforwards | 1,427 | 31 | 683 | 2 | 481 | — | ||||||||||||||
| Employee benefit obligations | 837 | 188 | 261 | 47 | 17 | 77 | ||||||||||||||
| Estimated loss on plants under construction | 679 | — | 679 | — | — | — | ||||||||||||||
| Estimated loss on regulatory disallowance | 38 | — | — | — | — | 38 | ||||||||||||||
| Other state deferred tax attributes | 346 | — | 25 | 211 | 48 | 12 | ||||||||||||||
| Federal effect of net state deferred tax liabilities | 460 | 201 | 141 | — | 24 | 114 | ||||||||||||||
| Other property basis differences | 159 | — | 73 | — | 73 | — | ||||||||||||||
| State effect of federal deferred taxes | 136 | 136 | — | — | — | — | ||||||||||||||
| Other partnership basis differences | 149 | — | — | — | 149 | — | ||||||||||||||
| Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) | 18 | 18 | — | — | — | — | ||||||||||||||
| Long-term debt fair value adjustment | 67 | — | — | — | — | 67 | ||||||||||||||
| Other comprehensive losses | 51 | 2 | — | — | — | — | ||||||||||||||
| Other | 780 | 297 | 237 | 49 | 44 | 92 | ||||||||||||||
| Total deferred income tax assets | 7,666 | 1,885 | 3,532 | 337 | 836 | 400 | ||||||||||||||
| Valuation allowance | (445) | — | (267) | (41) | (29) | (6) | ||||||||||||||
| Net deferred income tax assets | 7,221 | 1,885 | 3,265 | 296 | 807 | 394 | ||||||||||||||
| Net deferred income taxes (assets)/liabilities | $ | 12,067 | $ | 4,209 | $ | 4,811 | $ | 425 | $ | 579 | $ | 1,971 | ||||||||
| Recognized in the balance sheets: | ||||||||||||||||||||
| Accumulated deferred income taxes – assets | $ | (66) | $ | — | $ | — | $ | (66) | $ | — | $ | — | ||||||||
| Accumulated deferred income taxes – liabilities | $ | 12,133 | $ | 4,209 | $ | 4,811 | $ | 491 | $ | 579 | $ | 1,971 |
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| At December 31, 2024 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Deferred tax liabilities — | ||||||||||||||||||||
| Accelerated depreciation | $ | 9,828 | $ | 2,583 | $ | 3,810 | $ | 344 | $ | 1,309 | $ | 1,575 | ||||||||
| Property basis differences | 3,025 | 1,497 | 918 | 192 | — | 412 | ||||||||||||||
| Employee benefit obligations | 1,067 | 362 | 470 | 54 | 13 | 60 | ||||||||||||||
| AROs | 727 | 458 | 221 | — | — | — | ||||||||||||||
| Under recovered fuel and natural gas costs | 318 | 13 | 305 | — | — | — | ||||||||||||||
| Regulatory assets — | ||||||||||||||||||||
| AROs | 1,886 | 658 | 1,193 | 35 | — | — | ||||||||||||||
| Employee benefit obligations | 746 | 191 | 237 | 35 | — | 35 | ||||||||||||||
| Remaining book value of retired assets | 360 | 168 | 187 | 5 | — | — | ||||||||||||||
| Storm damage reserves | 216 | — | 216 | — | — | — | ||||||||||||||
| Premium on reacquired debt | 57 | 8 | 48 | 1 | — | — | ||||||||||||||
| Other | 678 | 171 | 187 | 61 | 1 | 201 | ||||||||||||||
| Total deferred income tax liabilities | 18,908 | 6,109 | 7,792 | 727 | 1,323 | 2,283 | ||||||||||||||
| Deferred tax assets — | ||||||||||||||||||||
| AROs | 2,613 | 1,116 | 1,414 | 35 | — | — | ||||||||||||||
| CAMT carryforwards | 40 | — | 18 | — | — | 104 | ||||||||||||||
| ITC and PTC carryforwards | 1,380 | 48 | 719 | — | 384 | — | ||||||||||||||
| Employee benefit obligations | 897 | 196 | 279 | 49 | 16 | 87 | ||||||||||||||
| Estimated loss on plants under construction | 773 | — | 773 | — | — | — | ||||||||||||||
| Estimated loss on regulatory disallowance | 20 | — | — | — | — | 20 | ||||||||||||||
| Other state deferred tax attributes | 366 | — | 26 | 224 | 49 | 16 | ||||||||||||||
| Federal effect of net state deferred tax liabilities | 402 | 197 | 100 | — | 23 | 107 | ||||||||||||||
| Other property basis differences | 176 | — | 75 | — | 85 | — | ||||||||||||||
| State effect of federal deferred taxes | 126 | 126 | — | — | — | — | ||||||||||||||
| Other partnership basis differences | 60 | — | — | — | 60 | — | ||||||||||||||
| Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) | 18 | 18 | — | — | — | — | ||||||||||||||
| Long-term debt fair value adjustment | 73 | — | — | — | — | 73 | ||||||||||||||
| Other comprehensive losses | 48 | 3 | — | — | 1 | — | ||||||||||||||
| Other | 601 | 227 | 160 | 50 | 20 | 86 | ||||||||||||||
| Total deferred income tax assets | 7,593 | 1,931 | 3,564 | 358 | 638 | 493 | ||||||||||||||
| Valuation allowance | (333) | — | (157) | (41) | (27) | (6) | ||||||||||||||
| Net deferred income tax assets | 7,260 | 1,931 | 3,407 | 317 | 611 | 487 | ||||||||||||||
| Net deferred income taxes (assets)/liabilities | $ | 11,648 | $ | 4,178 | $ | 4,385 | $ | 410 | $ | 712 | $ | 1,796 | ||||||||
| Recognized in the balance sheets: | ||||||||||||||||||||
| Accumulated deferred income taxes – assets | $ | (82) | $ | — | $ | — | $ | (82) | $ | — | $ | — | ||||||||
| Accumulated deferred income taxes – liabilities | $ | 11,730 | $ | 4,178 | $ | 4,385 | $ | 492 | $ | 712 | $ | 1,796 |
The traditional electric operating companies and the natural gas distribution utilities have tax-related regulatory assets (deferred income tax charges) and regulatory liabilities (deferred income tax credits). The regulatory assets are primarily attributable to tax benefits flowed through to customers in prior years, deferred taxes previously recognized at rates lower than the current enacted tax law, and taxes applicable to capitalized interest. The regulatory liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law, certain tax credits deferred for future customer benefit, and unamortized ITCs. See Note 2 for each Registrant's related balances at December 31, 2025 and 2024.
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Tax Credit Carryforwards
Federal ITC/PTC carryforwards at December 31, 2025 were as follows:
| Southern Company | Alabama Power | Georgia Power | Southern Power | |||||||||||
| (in millions) | ||||||||||||||
| Federal ITC/PTC carryforwards | $ | 850 | $ | 31 | $ | 152 | $ | 481 | ||||||
| Tax year(s) in which federal ITC/PTC carryforwards expire(*) | 2031-2045 | 2032-2045 | 2031-2045 | 2035-2045 | ||||||||||
| Year by which federal ITC/PTC carryforwards are expected to be utilized | 2031 | 2031 | 2031 | 2031 |
(*)The federal ITC/PTC carryforwards at Alabama Power and Georgia Power expiring in 2031-2034 are immaterial to their respective financial statements.
The estimated tax credit utilization reflects the various transactions described in Note 15 and could be impacted by numerous factors, including the acquisition or construction of additional renewable projects, changes in taxable income projections, transfer of eligible credits, potential income tax rate changes, and remaining final guidance on the IRA. In the third quarter 2023 and the second quarter 2024, Georgia Power started generating advanced nuclear PTCs for Plant Vogtle Units 3 and 4, respectively, beginning on each unit's respective in-service date. In addition, pursuant to the Vogtle Joint Ownership Agreements, Georgia Power is purchasing advanced nuclear PTCs for Plant Vogtle Unit 3 and 4 from the other Vogtle Owners. See Note 2 under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
At December 31, 2025, Southern Company and Georgia Power also had approximately $483 million and $438 million, respectively, in net state investment and other net state tax credit carryforwards for the State of Georgia that will expire between tax years 2025 and 2033 and are not expected to be fully utilized. Southern Company and Georgia Power have a net state valuation allowance of $248 million and $211 million, respectively, associated with these carryforwards, both of which increased during 2025 by $87 million.
The ultimate outcome of these matters cannot be determined at this time.
Net Operating Loss Carryforwards
At December 31, 2025, the net state income tax benefit of state and local NOL carryforwards and associated valuation allowances for Southern Company's subsidiaries were as follows:
| Company/Jurisdiction | Approximate Net State Income Tax Benefit of NOL Carryforwards | Tax Year NOL Begins Expiring | Net State Valuation Allowance for NOL Carryforwards | ||||||||
| (in millions) | (in millions) | ||||||||||
| Mississippi Power | |||||||||||
| Mississippi | $ | 167 | 2032 | $ | (32) | ||||||
| Southern Power | |||||||||||
| Oklahoma | $ | 25 | 2035 | $ | (13) | ||||||
| Florida | 10 | 2034 | (10) | ||||||||
| Other states | 2 | 2034 | — | ||||||||
| Southern Power total | $ | 37 | $ | (23) | |||||||
| Other**(*)** | |||||||||||
| New York | $ | 11 | 2036 | $ | (11) | ||||||
| New York City | 14 | 2036 | (14) | ||||||||
| Other states | 21 | 2026 | (5) | ||||||||
| Southern Company total | $ | 250 | $ | (85) |
(*)Represents other non-registrant Southern Company subsidiaries. Alabama Power, Georgia Power, and Southern Company Gas did not have material state or local NOL carryforwards at December 31, 2025.
Certain state NOLs are not expected to be fully utilized prior to expiration. The ultimate outcome of these matters cannot be determined at this time.
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Unrecognized Tax Benefits
Changes in unrecognized tax benefits for the periods presented were as follows:
| Southern Company | Alabama Power | Georgia Power | Southern Company Gas | |||||||||||
| (in millions) | ||||||||||||||
| Unrecognized tax benefits at December 31, 2022 | $ | 80 | $ | — | $ | — | $ | 32 | ||||||
| Tax positions changes — | ||||||||||||||
| Increase from prior periods | 88 | — | 86 | 2 | ||||||||||
| Statute of limitations expiration | (52) | — | (9) | — | ||||||||||
| Unrecognized tax benefits at December 31, 2023 | 116 | — | 77 | 34 | ||||||||||
| Tax positions changes — | ||||||||||||||
| Increase from prior periods | 10 | — | — | 10 | ||||||||||
| Decrease from prior periods | (44) | — | (43) | — | ||||||||||
| Unrecognized tax benefits at December 31, 2024 | 82 | — | 34 | 44 | ||||||||||
| Tax positions changes — | ||||||||||||||
| Statute of limitations expiration | (34) | — | (34) | — | ||||||||||
| Increase from current period | 122 | 50 | 72 | — | ||||||||||
| Unrecognized tax benefits at December 31, 2025 | $ | 170 | $ | 50 | $ | 72 | $ | 44 |
The unrecognized tax positions increase from prior periods for 2023 is primarily related to the amendment of certain 2019 through 2021 state tax filing positions related to tax credit utilization, a portion of which decreased in the fourth quarter 2023 due to a statute of limitations expiration. If effective settlement of the positions is favorable, these positions would decrease Southern Company's and Georgia Power's annual effective tax rates. The ultimate outcome of this unrecognized tax benefit, which is expected to be resolved within the next 12 months, is dependent on acceptance by the state or expiration of related statute of limitations.
The unrecognized tax positions reductions due to statute of limitations expiration for 2023 primarily relate to a 2019 state tax filing position to exclude certain gains from 2019 dispositions from taxation in a certain unitary state. This tax position and related interest was recognized in the fourth quarter 2023 and decreased Southern Company's annual effective tax rate.
The unrecognized tax positions increase from prior periods for 2024 is primarily related to a certain state tax filing position at Southern Company Gas. If effective settlement of this position is favorable, this position would decrease Southern Company's and Southern Company Gas' annual effective tax rates. The ultimate outcome is dependent on acceptance by the state.
The unrecognized tax positions decrease from prior periods and statute of limitations expiration for 2024 and 2025, respectively, are primarily related to the 2019 through 2021 amended state filing positions related to tax credit utilization at Georgia Power.
Alabama Power and Georgia Power recorded an unrecognized tax position in the second quarter 2025 for zero-emission nuclear power PTCs generated on the consolidated 2024 federal income tax return due to the uncertainty to meet the prevailing wage requirements. In the fourth quarter 2025, the unrecognized tax position at Alabama Power and Georgia Power was reversed as Southern Company received the acceptance letter from the IRS on these PTCs for the 2024 tax year. The reversal of the unrecognized tax position did not impact Southern Company's, Alabama Power's, and Georgia Power's effective tax rates.
The unrecognized tax positions increase from the current period is related to the Alabama Power and Georgia Power zero-emission nuclear power PTCs for the 2025 tax year of $50 million and $72 million, respectively.
All of the Registrants classify interest on tax uncertainties as interest expense. Accrued interest for all tax positions was immaterial for all periods presented. None of the Registrants accrued any penalties on uncertain tax positions.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2024. Southern Company is a participant in the Compliance Assurance Process of the IRS. The IRS selected six Southern Power partnership returns for exam for the 2020 and 2021 tax years. One audit for 2020 is still under review, and the remaining audits have been closed with no change. The ultimate outcome of this matter cannot be determined at this time. The audits for the Registrants' state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2018.
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11. RETIREMENT BENEFITS
The Southern Company system has a qualified defined benefit, trusteed pension plan covering substantially all employees, with the exception of PowerSecure employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No contributions to the qualified pension plan were made for the year ended December 31, 2025 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2026. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. For the year ending December 31, 2026, no contributions to any other postretirement trusts are expected.
Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.
| 2025 | ||||||||||||||||||||
| Assumptions used to determine net periodic costs: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| Pension plans | ||||||||||||||||||||
| Discount rate – benefit obligations | 5.76 | % | 5.78 | % | 5.75 | % | 5.76 | % | 5.84 | % | 5.73 | % | ||||||||
| Discount rate – interest costs | 5.47 | 5.48 | 5.44 | 5.46 | 5.58 | 5.46 | ||||||||||||||
| Discount rate – service costs | 5.93 | 5.95 | 5.95 | 5.94 | 5.93 | 5.84 | ||||||||||||||
| Expected long-term return on plan assets | 8.50 | 8.50 | 8.50 | 8.50 | 8.50 | 8.50 | ||||||||||||||
| Annual salary increase | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate – benefit obligations | 5.64 | % | 5.67 | % | 5.61 | % | 5.63 | % | 5.73 | % | 5.62 | % | ||||||||
| Discount rate – interest costs | 5.35 | 5.38 | 5.34 | 5.34 | 5.45 | 5.30 | ||||||||||||||
| Discount rate – service costs | 5.90 | 5.92 | 5.91 | 5.89 | 5.86 | 5.89 | ||||||||||||||
| Expected long-term return on plan assets | 7.80 | 8.06 | 7.78 | 7.69 | — | 6.44 | ||||||||||||||
| Annual salary increase | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 |
| 2024 | ||||||||||||||||||||
| Assumptions used to determine net periodic costs: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| Pension plans | ||||||||||||||||||||
| Discount rate – benefit obligations | 5.07 | % | 5.08 | % | 5.06 | % | 5.06 | % | 5.14 | % | 5.05 | % | ||||||||
| Discount rate – interest costs | 4.94 | 4.94 | 4.94 | 4.93 | 5.01 | 4.93 | ||||||||||||||
| Discount rate – service costs | 5.19 | 5.20 | 5.21 | 5.19 | 5.20 | 5.13 | ||||||||||||||
| Expected long-term return on plan assets | 8.30 | 8.30 | 8.30 | 8.30 | 8.30 | 8.30 | ||||||||||||||
| Annual salary increase | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate – benefit obligations | 4.99 | % | 5.01 | % | 4.98 | % | 4.98 | % | 5.06 | % | 4.98 | % | ||||||||
| Discount rate – interest costs | 4.90 | 4.90 | 4.89 | 4.90 | 4.94 | 4.89 | ||||||||||||||
| Discount rate – service costs | 5.16 | 5.17 | 5.16 | 5.16 | 5.14 | 5.16 | ||||||||||||||
| Expected long-term return on plan assets | 7.67 | 7.97 | 7.59 | 7.43 | — | 6.36 | ||||||||||||||
| Annual salary increase | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 |
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| 2023 | ||||||||||||||||||||
| Assumptions used to determine net periodic costs: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| Pension plans | ||||||||||||||||||||
| Discount rate – benefit obligations | 5.25 | % | 5.26 | % | 5.25 | % | 5.25 | % | 5.31 | % | 5.24 | % | ||||||||
| Discount rate – interest costs | 5.13 | 5.14 | 5.12 | 5.12 | 5.19 | 5.12 | ||||||||||||||
| Discount rate – service costs | 5.36 | 5.38 | 5.38 | 5.37 | 5.37 | 5.31 | ||||||||||||||
| Expected long-term return on plan assets | 8.40 | 8.40 | 8.40 | 8.40 | 8.40 | 8.40 | ||||||||||||||
| Annual salary increase | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate – benefit obligations | 5.18 | % | 5.20 | % | 5.17 | % | 5.17 | % | 5.24 | % | 5.16 | % | ||||||||
| Discount rate – interest costs | 5.08 | 5.09 | 5.07 | 5.08 | 5.12 | 5.07 | ||||||||||||||
| Discount rate – service costs | 5.34 | 5.35 | 5.34 | 5.33 | 5.33 | 5.33 | ||||||||||||||
| Expected long-term return on plan assets | 7.67 | 7.95 | 7.49 | 7.43 | — | 6.59 | ||||||||||||||
| Annual salary increase | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 |
| 2025 | ||||||||||||||||||||
| Assumptions used to determine benefit obligations: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| Pension plans | ||||||||||||||||||||
| Discount rate | 5.69 | % | 5.72 | % | 5.67 | % | 5.66 | % | 5.85 | % | 5.61 | % | ||||||||
| Annual salary increase | 5.00 | 5.00 | 5.00 | 5.00 | 5.00 | 5.00 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate | 5.40 | % | 5.45 | % | 5.34 | % | 5.38 | % | 5.59 | % | 5.38 | % | ||||||||
| Annual salary increase | 5.00 | 5.00 | 5.00 | 5.00 | 5.00 | 5.00 |
| 2024 | ||||||||||||||||||||
| Assumptions used to determine benefit obligations: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| Pension plans | ||||||||||||||||||||
| Discount rate | 5.76 | % | 5.78 | % | 5.75 | % | 5.76 | % | 5.84 | % | 5.73 | % | ||||||||
| Annual salary increase | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate | 5.64 | % | 5.67 | % | 5.61 | % | 5.63 | % | 5.73 | % | 5.62 | % | ||||||||
| Annual salary increase | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 | 4.60 |
The Registrants estimate the expected rate of return on pension plan and other postretirement benefit plan assets using a financial model to project the expected return on each current investment portfolio. The analysis projects an expected rate of return on each of the different asset classes in order to arrive at the expected return on the entire portfolio relying on each trust's target asset allocation and reasonable capital market assumptions. The financial model is based on four key inputs: anticipated returns by asset class (based in part on historical returns), each trust's target asset allocation, an anticipated inflation rate, and the projected impact of a periodic rebalancing of each trust's portfolio. The Registrants set the expected rate of return assumption using an arithmetic mean which represents the expected simple average return to be earned by the pension plan assets over any one year. The Registrants believe the use of the arithmetic mean is more compatible with the expected rate of return's function of estimating a single year's investment return.
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An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO for the Registrants at December 31, 2025 were as follows:
| Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | |||||||||||||||
| Pre-65 | 8.50 | % | 4.50 | % | 2034 | ||||||||||||
| Post-65 medical | 6.00 | 4.50 | 2034 | ||||||||||||||
| Post-65 prescription | 11.00 | 4.50 | 2034 |
Pension Plans
The total accumulated benefit obligation for the pension plans at December 31, 2025 and 2024 was as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| At December 31, 2025 | $ | 11,952 | $ | 2,730 | $ | 3,549 | $ | 542 | $ | 147 | $ | 829 | ||||||||
| At December 31, 2024 | 11,437 | 2,617 | 3,438 | 519 | 140 | 779 |
An actuarial loss of $458 million and an actuarial gain of $887 million were recorded for the annual remeasurement of the Southern Company system pension plans at December 31, 2025 and 2024, respectively, primarily due to a decrease of 7 basis points and an increase of 69 basis points, respectively, in the overall discount rate used to calculate the benefit obligation as a result of a change in market interest rates.
Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2025 and 2024 were as follows:
| 2025 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Change in benefit obligation | ||||||||||||||||||||
| Benefit obligation at beginning of year | $ | 12,564 | $ | 2,908 | $ | 3,733 | $ | 567 | $ | 167 | $ | 842 | ||||||||
| Service cost | 264 | 60 | 63 | 11 | 6 | 27 | ||||||||||||||
| Interest cost | 664 | 154 | 196 | 30 | 9 | 45 | ||||||||||||||
| Benefits paid | (761) | (166) | (247) | (35) | (6) | (55) | ||||||||||||||
| Actuarial (gain) loss | 458 | 99 | 128 | 21 | (1) | 36 | ||||||||||||||
| Balance at end of year | 13,189 | 3,055 | 3,873 | 594 | 175 | 895 | ||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Fair value of plan assets at beginning of year | 14,559 | 3,539 | 4,519 | 664 | 188 | 978 | ||||||||||||||
| Actual return on plan assets | 1,886 | 452 | 576 | 86 | 22 | 130 | ||||||||||||||
| Employer contributions | 66 | 13 | 13 | 2 | 1 | 2 | ||||||||||||||
| Benefits paid | (761) | (166) | (247) | (35) | (6) | (55) | ||||||||||||||
| Fair value of plan assets at end of year | 15,750 | 3,838 | 4,861 | 717 | 205 | 1,055 | ||||||||||||||
| Accrued asset | $ | 2,561 | $ | 783 | $ | 988 | $ | 123 | $ | 30 | $ | 160 |
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| 2024 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Change in benefit obligation | ||||||||||||||||||||
| Benefit obligation at beginning of year | $ | 13,252 | $ | 3,076 | $ | 4,009 | $ | 599 | $ | 177 | $ | 882 | ||||||||
| Service cost | 292 | 68 | 70 | 12 | 7 | 28 | ||||||||||||||
| Interest cost | 635 | 148 | 191 | 29 | 9 | 42 | ||||||||||||||
| Benefits paid | (728) | (162) | (239) | (33) | (6) | (46) | ||||||||||||||
| Actuarial gain | (887) | (222) | (298) | (40) | (20) | (64) | ||||||||||||||
| Balance at end of year | 12,564 | 2,908 | 3,733 | 567 | 167 | 842 | ||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Fair value of plan assets at beginning of year | 14,618 | 3,544 | 4,571 | 669 | 185 | 980 | ||||||||||||||
| Actual return on plan assets | 604 | 148 | 152 | 23 | 7 | 39 | ||||||||||||||
| Employer contributions | 65 | 9 | 35 | 5 | 2 | 5 | ||||||||||||||
| Benefits paid | (728) | (162) | (239) | (33) | (6) | (46) | ||||||||||||||
| Fair value of plan assets at end of year | 14,559 | 3,539 | 4,519 | 664 | 188 | 978 | ||||||||||||||
| Accrued asset | $ | 1,995 | $ | 631 | $ | 786 | $ | 97 | $ | 21 | $ | 136 |
The projected benefit obligations for the qualified and non-qualified pension plans at December 31, 2025 are shown in the following table. All pension plan assets are related to the qualified pension plan.
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Projected benefit obligations: | ||||||||||||||||||||
| Qualified pension plan | $ | 12,493 | $ | 2,939 | $ | 3,762 | $ | 566 | $ | 154 | $ | 837 | ||||||||
| Non-qualified pension plan | 696 | 116 | 111 | 28 | 21 | 59 |
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Amounts recognized in the balance sheets at December 31, 2025 and 2024 related to the Registrants' pension plans consist of the following:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| At December 31, 2025: | ||||||||||||||||||||
| Prepaid pension costs(a) | $ | 3,257 | $ | 899 | $ | 1,099 | $ | 151 | $ | 51 | $ | 219 | ||||||||
| Other regulatory assets, deferred(b) | 2,533 | 687 | 907 | 136 | — | 114 | ||||||||||||||
| Other current liabilities | (68) | (12) | (13) | (3) | (2) | (3) | ||||||||||||||
| Employee benefit obligations(c) | (628) | (104) | (98) | (25) | (19) | (56) | ||||||||||||||
| Other regulatory liabilities, deferred | (47) | — | — | — | — | — | ||||||||||||||
| AOCI | 38 | — | — | — | 4 | (56) | ||||||||||||||
| At December 31, 2024: | ||||||||||||||||||||
| Prepaid pension costs(a) | $ | 2,674 | $ | 746 | $ | 897 | $ | 124 | $ | 41 | $ | 191 | ||||||||
| Other regulatory assets, deferred(b) | 2,708 | 741 | 973 | 144 | — | 126 | ||||||||||||||
| Other current liabilities | (68) | (13) | (13) | (2) | (2) | (4) | ||||||||||||||
| Employee benefit obligations(c) | (611) | (102) | (98) | (25) | (18) | (51) | ||||||||||||||
| Other regulatory liabilities, deferred | (50) | — | — | — | — | — | ||||||||||||||
| AOCI | 52 | — | — | — | 11 | (54) |
(a)Included in prepaid pension and other postretirement benefit costs on Alabama Power's and Southern Company Gas' balance sheets and other deferred charges and assets on Southern Power's consolidated balance sheets.
(b)Amounts for Southern Company exclude regulatory assets of $135 million and $155 million at December 31, 2025 and 2024, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
(c)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
Presented below are the amounts included in regulatory assets at December 31, 2025 and 2024 related to the portion of the defined benefit pension plan attributable to Southern Company, the traditional electric operating companies, and Southern Company Gas that had not yet been recognized in net periodic pension cost.
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| Balance at December 31, 2025 | |||||||||||||||||
| Regulatory assets: | |||||||||||||||||
| Prior service cost | $ | 8 | $ | 3 | $ | 4 | $ | 1 | $ | (2) | |||||||
| Net loss | 2,478 | 684 | 903 | 135 | 89 | ||||||||||||
| Regulatory amortization | — | — | — | — | 27 | ||||||||||||
| Total regulatory assets(*) | $ | 2,486 | $ | 687 | $ | 907 | $ | 136 | $ | 114 | |||||||
| Balance at December 31, 2024 | |||||||||||||||||
| Regulatory assets: | |||||||||||||||||
| Prior service cost | $ | 8 | $ | 3 | $ | 5 | $ | 1 | $ | (4) | |||||||
| Net loss | 2,650 | 738 | 968 | 143 | 91 | ||||||||||||
| Regulatory amortization | — | — | — | — | 39 | ||||||||||||
| Total regulatory assets(*) | $ | 2,658 | $ | 741 | $ | 973 | $ | 144 | $ | 126 |
(*)Amounts for Southern Company exclude regulatory assets of $135 million and $155 million at December 31, 2025 and 2024, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
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The changes in the balance of net regulatory assets (liabilities) related to the portion of the defined benefit pension plan attributable to Southern Company, the traditional electric operating companies, and Southern Company Gas for the years ended December 31, 2025 and 2024 are presented in the following table:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| **Net regulatory assets (liabilities):*() | |||||||||||||||||
| Balance at December 31, 2023 | $ | 2,913 | $ | 821 | $ | 1,051 | $ | 152 | $ | 143 | |||||||
| Net gain | (199) | (63) | (58) | (5) | (7) | ||||||||||||
| Reclassification adjustments: | |||||||||||||||||
| Amortization of prior service costs | (1) | (1) | (1) | — | 2 | ||||||||||||
| Amortization of net loss | (55) | (16) | (19) | (3) | (1) | ||||||||||||
| Amortization of regulatory assets**(*)** | — | — | — | — | (11) | ||||||||||||
| Total reclassification adjustments | (56) | (17) | (20) | (3) | (10) | ||||||||||||
| Total change | (255) | (80) | (78) | (8) | (17) | ||||||||||||
| Balance at December 31, 2024 | $ | 2,658 | $ | 741 | $ | 973 | $ | 144 | $ | 126 | |||||||
| Net (gain) loss | (127) | (42) | (50) | (5) | 1 | ||||||||||||
| Reclassification adjustments: | |||||||||||||||||
| Amortization of prior service costs | (1) | (1) | (1) | — | 2 | ||||||||||||
| Amortization of net loss | (44) | (11) | (15) | (3) | (3) | ||||||||||||
| Amortization of regulatory assets**(*)** | — | — | — | — | (12) | ||||||||||||
| Total reclassification adjustments | (45) | (12) | (16) | (3) | (13) | ||||||||||||
| Total change | (172) | (54) | (66) | (8) | (12) | ||||||||||||
| Balance at December 31, 2025 | $ | 2,486 | $ | 687 | $ | 907 | $ | 136 | $ | 114 |
(*)Amounts for Southern Company exclude regulatory assets of $135 million and $155 million at December 31, 2025 and 2024, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
Presented below are the amounts included in AOCI at December 31, 2025 and 2024 related to the portion of the defined benefit pension plan attributable to Southern Company, Southern Power, and Southern Company Gas that had not yet been recognized in net periodic pension cost.
| Southern Company | Southern Power | Southern Company Gas | |||||||||
| (in millions) | |||||||||||
| Balance at December 31, 2025 | |||||||||||
| AOCI: | |||||||||||
| Net (gain) loss | $ | 38 | $ | 4 | $ | (56) | |||||
| Balance at December 31, 2024 | |||||||||||
| AOCI: | |||||||||||
| Prior service cost | $ | (1) | $ | — | $ | (1) | |||||
| Net (gain) loss | 53 | 11 | (53) | ||||||||
| Total AOCI | $ | 52 | $ | 11 | $ | (54) |
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The components of OCI related to the portion of the defined benefit pension plan attributable to Southern Company, Southern Power, and Southern Company Gas for the years ended December 31, 2025 and 2024 are presented in the following table:
| Southern Company | Southern Power | Southern Company Gas | |||||||||
| (in millions) | |||||||||||
| AOCI: | |||||||||||
| Balance at December 31, 2023 | $ | 79 | $ | 20 | $ | (45) | |||||
| Net gain | (29) | (9) | (11) | ||||||||
| Reclassification adjustments: | |||||||||||
| Amortization of prior service costs | 1 | — | 2 | ||||||||
| Amortization of net gain | 1 | — | — | ||||||||
| Total reclassification adjustments | 2 | — | 2 | ||||||||
| Total change | (27) | (9) | (9) | ||||||||
| Balance at December 31, 2024 | $ | 52 | $ | 11 | $ | (54) | |||||
| Net gain | (21) | (7) | (3) | ||||||||
| Reclassification adjustments: | |||||||||||
| Amortization of prior service costs | 1 | — | 1 | ||||||||
| Amortization of net gain | 6 | — | — | ||||||||
| Total reclassification adjustments | 7 | — | 1 | ||||||||
| Total change | (14) | (7) | (2) | ||||||||
| Balance at December 31, 2025 | $ | 38 | $ | 4 | $ | (56) |
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Components of net periodic pension cost for the Registrants were as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | ||||||||||||||||||||
| Service cost | $ | 264 | $ | 60 | $ | 63 | $ | 11 | $ | 6 | $ | 27 | ||||||||
| Interest cost | 664 | 154 | 196 | 30 | 9 | 45 | ||||||||||||||
| Expected return on plan assets | (1,281) | (312) | (397) | (59) | (17) | (86) | ||||||||||||||
| Recognized net (gain) loss(*) | 38 | 11 | 15 | 3 | — | (1) | ||||||||||||||
| Net amortization(*) | — | 1 | 1 | — | — | 15 | ||||||||||||||
| Prior service cost(*) | — | — | — | — | — | (3) | ||||||||||||||
| Net periodic pension income | $ | (315) | $ | (86) | $ | (122) | $ | (15) | $ | (2) | $ | (3) | ||||||||
| 2024 | ||||||||||||||||||||
| Service cost | $ | 292 | $ | 68 | $ | 70 | $ | 12 | $ | 7 | $ | 28 | ||||||||
| Interest cost | 635 | 148 | 191 | 29 | 9 | 42 | ||||||||||||||
| Expected return on plan assets | (1,263) | (307) | (393) | (58) | (17) | (85) | ||||||||||||||
| Recognized net loss(*) | 55 | 16 | 19 | 3 | — | — | ||||||||||||||
| Net amortization(*) | — | 1 | 1 | — | — | 15 | ||||||||||||||
| Prior service cost(*) | — | — | — | — | — | (3) | ||||||||||||||
| Net periodic pension income | $ | (281) | $ | (74) | $ | (112) | $ | (14) | $ | (1) | $ | (3) | ||||||||
| 2023 | ||||||||||||||||||||
| Service cost | $ | 275 | $ | 64 | $ | 68 | $ | 11 | $ | 6 | $ | 24 | ||||||||
| Interest cost | 626 | 145 | 191 | 28 | 8 | 42 | ||||||||||||||
| Expected return on plan assets | (1,229) | (297) | (385) | (56) | (15) | (85) | ||||||||||||||
| Recognized net (gain) loss(*) | 32 | 9 | 13 | 2 | — | (5) | ||||||||||||||
| Net amortization(*) | — | 1 | 1 | — | — | 15 | ||||||||||||||
| Prior service cost(*) | — | — | — | — | — | (3) | ||||||||||||||
| Net periodic pension income | $ | (296) | $ | (78) | $ | (112) | $ | (15) | $ | (1) | $ | (12) |
(*)For Southern Company, excludes amounts related to net periodic pension cost of $20 million, $20 million, and $17 million for the years ended December 31, 2025, 2024, and 2023, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
The service cost component of net periodic pension cost is included in operations and maintenance expenses and all other components of net periodic pension cost are included in other income (expense), net in the Registrants' statements of income.
Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets. In determining the market-related value of plan assets, the Registrants have elected to amortize changes in the market value of return-seeking plan assets over five years and to recognize the changes in the market value of liability-hedging plan assets immediately. Given the significant concentration in return-seeking plan assets, the accounting value of plan assets that is used to calculate the expected return on plan assets differs from the current fair value of the plan assets.
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Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2025, estimated benefit payments were as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Benefit Payments: | ||||||||||||||||||||
| 2026 | $ | 803 | $ | 176 | $ | 252 | $ | 36 | $ | 7 | $ | 62 | ||||||||
| 2027 | 827 | 182 | 255 | 37 | 8 | 63 | ||||||||||||||
| 2028 | 847 | 188 | 259 | 38 | 7 | 65 | ||||||||||||||
| 2029 | 868 | 193 | 264 | 38 | 8 | 66 | ||||||||||||||
| 2030 | 889 | 198 | 267 | 39 | 9 | 68 | ||||||||||||||
| 2031 to 2035 | 4,638 | 1,041 | 1,353 | 209 | 55 | 360 |
Other Postretirement Benefits
An actuarial loss of $71 million was recorded for the annual remeasurement of the Southern Company system other postretirement benefit plans at December 31, 2025 primarily due to a decrease of 24 basis points in the overall discount rate used to calculate the benefit obligation as a result of a change in market interest rates.
Changes in the APBO and the fair value of the Registrants' plan assets during the plan years ended December 31, 2025 and 2024 were as follows:
| 2025 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Change in benefit obligation | ||||||||||||||||||||
| Benefit obligation at beginning of year | $ | 1,359 | $ | 326 | $ | 488 | $ | 55 | $ | 9 | $ | 156 | ||||||||
| Service cost | 13 | 4 | 4 | 1 | — | — | ||||||||||||||
| Interest cost | 70 | 17 | 25 | 3 | — | 7 | ||||||||||||||
| Benefits paid | (113) | (24) | (40) | (5) | (1) | (16) | ||||||||||||||
| Actuarial (gain) loss | 71 | 17 | 34 | 3 | 1 | (1) | ||||||||||||||
| Balance at end of year | 1,400 | 340 | 511 | 57 | 9 | 146 | ||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Fair value of plan assets at beginning of year | 1,141 | 421 | 420 | 24 | — | 141 | ||||||||||||||
| Actual return on plan assets | 158 | 56 | 61 | 4 | — | 19 | ||||||||||||||
| Employer contributions | 65 | 4 | 17 | 4 | 1 | 12 | ||||||||||||||
| Benefits paid | (113) | (24) | (40) | (5) | (1) | (16) | ||||||||||||||
| Fair value of plan assets at end of year | 1,251 | 457 | 458 | 27 | — | 156 | ||||||||||||||
| Accrued asset (liability) | $ | (149) | $ | 117 | $ | (53) | $ | (30) | $ | (9) | $ | 10 |
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| 2024 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Change in benefit obligation | ||||||||||||||||||||
| Benefit obligation at beginning of year | $ | 1,386 | $ | 329 | $ | 489 | $ | 57 | $ | 9 | $ | 172 | ||||||||
| Service cost | 15 | 4 | 4 | 1 | — | 1 | ||||||||||||||
| Interest cost | 65 | 16 | 23 | 3 | — | 8 | ||||||||||||||
| Benefits paid | (105) | (25) | (37) | (4) | (1) | (12) | ||||||||||||||
| Actuarial (gain) loss | (2) | 2 | 9 | (2) | 1 | (13) | ||||||||||||||
| Balance at end of year | 1,359 | 326 | 488 | 55 | 9 | 156 | ||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Fair value of plan assets at beginning of year | 1,095 | 403 | 410 | 25 | — | 128 | ||||||||||||||
| Actual return on plan assets | 96 | 37 | 34 | — | — | 18 | ||||||||||||||
| Employer contributions | 55 | 6 | 13 | 3 | 1 | 7 | ||||||||||||||
| Benefits paid | (105) | (25) | (37) | (4) | (1) | (12) | ||||||||||||||
| Fair value of plan assets at end of year | 1,141 | 421 | 420 | 24 | — | 141 | ||||||||||||||
| Accrued asset (liability) | $ | (218) | $ | 95 | $ | (68) | $ | (31) | $ | (9) | $ | (15) |
Amounts recognized in the balance sheets at December 31, 2025 and 2024 related to the Registrants' other postretirement benefit plans consist of the following:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| At December 31, 2025: | ||||||||||||||||||||
| Prepaid other postretirement benefit costs(a) | $ | — | $ | 117 | $ | — | $ | — | $ | — | $ | 10 | ||||||||
| Other regulatory assets, deferred(b) | 25 | — | — | — | — | — | ||||||||||||||
| Other current liabilities | (6) | — | — | — | (1) | — | ||||||||||||||
| Employee benefit obligations(c) | (143) | — | (53) | (30) | (8) | — | ||||||||||||||
| Other regulatory liabilities, deferred | (199) | (47) | (56) | (6) | — | (93) | ||||||||||||||
| AOCI | (13) | — | — | — | 1 | (16) | ||||||||||||||
| At December 31, 2024: | ||||||||||||||||||||
| Prepaid other postretirement benefit costs(a) | $ | — | $ | 95 | $ | — | $ | — | $ | — | $ | — | ||||||||
| Other regulatory assets, deferred(b) | 24 | — | 3 | — | — | — | ||||||||||||||
| Other current liabilities | (6) | — | — | — | (1) | — | ||||||||||||||
| Employee benefit obligations(c) | (212) | — | (68) | (31) | (8) | (15) | ||||||||||||||
| Other regulatory liabilities, deferred | (213) | (45) | (67) | (9) | — | (84) | ||||||||||||||
| AOCI | (14) | — | — | — | — | (15) |
(a)Included in prepaid pension and other postretirement benefit costs on Alabama Power's and Southern Company Gas' balance sheets.
(b)Amounts for Southern Company exclude regulatory assets of $4 million and $16 million at December 31, 2025 and 2024, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.
(c)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
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Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2025 and 2024 related to the other postretirement benefit plans of Southern Company, the traditional electric operating companies, and Southern Company Gas that had not yet been recognized in net periodic other postretirement benefit cost.
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| Balance at December 31, 2025: | |||||||||||||||||
| Regulatory assets (liabilities): | |||||||||||||||||
| Prior service cost | $ | 8 | $ | 3 | $ | 3 | $ | 1 | $ | — | |||||||
| Net gain | (182) | (50) | (59) | (7) | (75) | ||||||||||||
| Regulatory amortization | — | — | — | — | (18) | ||||||||||||
| Total regulatory assets (liabilities)(*) | $ | (174) | $ | (47) | $ | (56) | $ | (6) | $ | (93) | |||||||
| Balance at December 31, 2024: | |||||||||||||||||
| Regulatory assets (liabilities): | |||||||||||||||||
| Prior service cost | $ | 11 | $ | 3 | $ | 4 | $ | 1 | $ | — | |||||||
| Net gain | (200) | (48) | (68) | (10) | (71) | ||||||||||||
| Regulatory amortization | — | — | — | — | (13) | ||||||||||||
| Total regulatory assets (liabilities)(*) | $ | (189) | $ | (45) | $ | (64) | $ | (9) | $ | (84) |
(*)Amounts for Southern Company exclude regulatory assets of $4 million and $16 million at December 31, 2025 and 2024, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2025 and 2024 are presented in the following table:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| **Net regulatory assets (liabilities):*() | |||||||||||||||||
| Balance at December 31, 2023 | $ | (208) | $ | (48) | $ | (74) | $ | (10) | $ | (68) | |||||||
| Net (gain) loss | 8 | 1 | 6 | 1 | (12) | ||||||||||||
| Reclassification adjustments: | |||||||||||||||||
| Amortization of prior service costs | (2) | (1) | (1) | — | — | ||||||||||||
| Amortization of net gain | 13 | 3 | 5 | — | 5 | ||||||||||||
| Amortization of regulatory assets**(*)** | — | — | — | — | (9) | ||||||||||||
| Total reclassification adjustments | 11 | 2 | 4 | — | (4) | ||||||||||||
| Total change | 19 | 3 | 10 | 1 | (16) | ||||||||||||
| Balance at December 31, 2024 | $ | (189) | $ | (45) | $ | (64) | $ | (9) | $ | (84) | |||||||
| Net (gain) loss | 5 | (3) | 6 | 3 | 2 | ||||||||||||
| Reclassification adjustments: | |||||||||||||||||
| Amortization of prior service costs | (2) | (1) | (1) | — | — | ||||||||||||
| Amortization of net gain (loss) | 12 | 2 | 3 | — | (6) | ||||||||||||
| Amortization of regulatory assets**(*)** | — | — | — | — | (5) | ||||||||||||
| Total reclassification adjustments | 10 | 1 | 2 | — | (11) | ||||||||||||
| Total change | 15 | (2) | 8 | 3 | (9) | ||||||||||||
| Balance at December 31, 2025 | $ | (174) | $ | (47) | $ | (56) | $ | (6) | $ | (93) |
(*)Amounts for Southern Company exclude regulatory assets of $4 million and $16 million at December 31, 2025 and 2024, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.
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COMBINED NOTES TO FINANCIAL STATEMENTS
Presented below are the amounts included in AOCI at December 31, 2025 and 2024 related to the other postretirement benefit plans of Southern Company, Southern Power, and Southern Company Gas that had not yet been recognized in net periodic other postretirement benefit cost.
| Southern Company | Southern Power | Southern Company Gas | |||||||||
| (in millions) | |||||||||||
| Balance at December 31, 2025 | |||||||||||
| AOCI: | |||||||||||
| Net (gain) loss | $ | (13) | $ | 1 | $ | (16) | |||||
| Balance at December 31, 2024 | |||||||||||
| AOCI: | |||||||||||
| Net gain | $ | (14) | $ | — | $ | (15) | |||||
The components of OCI related to the other postretirement benefit plans for the plan years ended December 31, 2025 and 2024 are presented in the following table:
| Southern Company | Southern Power | Southern Company Gas | |||||||||
| (in millions) | |||||||||||
| AOCI: | |||||||||||
| Balance at December 31, 2023 | $ | (9) | $ | 1 | $ | (10) | |||||
| Net gain | (8) | (1) | (5) | ||||||||
| Reclassification adjustments: | |||||||||||
| Amortization of net gain | 3 | — | — | ||||||||
| Total change | (5) | (1) | (5) | ||||||||
| Balance at December 31, 2024 | $ | (14) | $ | — | $ | (15) | |||||
| Net (gain) loss | (1) | 1 | (1) | ||||||||
| Reclassification adjustments: | |||||||||||
| Amortization of net gain | 2 | — | — | ||||||||
| Total change | 1 | 1 | (1) | ||||||||
| Balance at December 31, 2025 | $ | (13) | $ | 1 | $ | (16) |
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Components of the other postretirement benefit plans' net periodic cost for the Registrants were as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | ||||||||||||||||||||
| Service cost | $ | 13 | $ | 4 | $ | 4 | $ | 1 | $ | — | $ | — | ||||||||
| Interest cost | 70 | 17 | 25 | 3 | — | 7 | ||||||||||||||
| Expected return on plan assets | (91) | (35) | (33) | (3) | 1 | (15) | ||||||||||||||
| Net amortization(*) | (12) | (2) | (2) | — | — | 5 | ||||||||||||||
| Net periodic other postretirement benefit cost (income) | $ | (20) | $ | (16) | $ | (6) | $ | 1 | $ | 1 | $ | (3) | ||||||||
| 2024 | ||||||||||||||||||||
| Service cost | $ | 15 | $ | 4 | $ | 4 | $ | 1 | $ | — | $ | 1 | ||||||||
| Interest cost | 65 | 16 | 23 | 3 | — | 8 | ||||||||||||||
| Expected return on plan assets | (89) | (35) | (32) | (3) | 1 | (13) | ||||||||||||||
| Net amortization(*) | (13) | (3) | (4) | — | — | 6 | ||||||||||||||
| Net periodic other postretirement benefit cost (income) | $ | (22) | $ | (18) | $ | (9) | $ | 1 | $ | 1 | $ | 2 | ||||||||
| 2023 | ||||||||||||||||||||
| Service cost | $ | 15 | $ | 4 | $ | 4 | $ | 1 | $ | — | $ | 1 | ||||||||
| Interest cost | 70 | 17 | 25 | 3 | — | 9 | ||||||||||||||
| Expected return on plan assets | (83) | (33) | (29) | (3) | 1 | (10) | ||||||||||||||
| Net amortization(*) | (11) | (3) | (3) | — | — | 6 | ||||||||||||||
| Net periodic other postretirement benefit cost (income) | $ | (9) | $ | (15) | $ | (3) | $ | 1 | $ | 1 | $ | 6 |
(*)For Southern Company, excludes amounts related to net periodic other postretirement benefit cost of $12 million, $8 million, and $8 million for the years ended December 31, 2025, 2024, and 2023, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.
The service cost component of net periodic other postretirement benefit cost is included in operations and maintenance expenses and all other components of net periodic other postretirement benefit cost are included in other income (expense), net in the Registrants' statements of income.
The Registrants' future benefit payments, including prescription drug benefits, are provided in the table below. These amounts reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans.
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Benefit payments: | ||||||||||||||||||||
| 2026 | $ | 114 | $ | 26 | $ | 42 | $ | 5 | $ | 1 | $ | 15 | ||||||||
| 2027 | 115 | 26 | 43 | 5 | 1 | 15 | ||||||||||||||
| 2028 | 116 | 27 | 43 | 5 | 1 | 14 | ||||||||||||||
| 2029 | 116 | 27 | 43 | 5 | 1 | 14 | ||||||||||||||
| 2030 | 116 | 27 | 43 | 5 | 1 | 13 | ||||||||||||||
| 2031 to 2035 | 566 | 136 | 211 | 23 | 1 | 56 |
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Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code. The Registrants' investment policies for both the pension plans and the other postretirement benefit plans cover a diversified mix of assets as described below. Derivative instruments may be used to gain efficient exposure to the various asset classes and as hedging tools. Additionally, the Registrants minimize the risk of large losses primarily through diversification but also monitor and manage other aspects of risk.
The investment strategy for plan assets related to the Southern Company system's qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company system employs a formal rebalancing program. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.
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Investment Strategies and Benefit Plan Asset Fair Values
A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below:
| Description | Valuation Methodology | ||||
| Domestic equity: A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches. International equity: A mix of large and small capitalization growth and value stocks with developed and emerging markets exposure, managed both actively and through fundamental indexing approaches. | Domestic and international equities such as common stocks, American depositary receipts, and real estate investment trusts that trade on public exchanges are classified as Level 1 investments and are valued at the closing price in the active market. Equity funds with unpublished prices that are comprised of publicly traded securities (such as commingled/pooled funds) are also valued at the closing price in the active market but are classified as Level 2. | ||||
| Fixed income: A mix of domestic and international bonds. | Investments in fixed income securities, including fixed income pooled funds, are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument. | ||||
| Trust-owned life insurance (TOLI): Investments of taxable trusts aimed at minimizing the impact of taxes on the portfolio. | Investments in TOLI policies are classified as Level 2 investments and are valued based on the underlying investments held in the policy's separate accounts. The underlying assets are equity and fixed income pooled funds that are comprised of Level 1 and Level 2 securities. | ||||
| Real estate: Investments in equity or debt of real properties and in publicly traded real estate securities. Special situations: Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies, as well as investments in promising new strategies of a longer-term nature. Private equity: Investments in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. Private credit: Investments focused on debt instruments, of which returns are driven by income rather than capital appreciation. Infrastructure: Investments in real assets, typically with long-term, predictable, and stable cash flows and a meaningful income component. | Investments in real estate, special situations, private equity, private credit, and infrastructure are typically invested in private partnerships and/or other pooled vehicles (Investment Funds) which are generally classified as Net Asset Value as a Practical Expedient, since the Investment Funds and underlying assets are not publicly traded and/or often have liquidity restrictions. The managers of the Investment Funds value the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The total market value of each of the Investment Funds is determined by aggregating the value of the underlying assets less liabilities. |
For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan's trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. The fair values presented herein exclude cash, receivables related to investment income and pending investment sales, and payables related to pending investment purchases.
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The fair values, and actual allocations relative to the target allocations, of the Southern Company system's pension plans at December 31, 2025 and 2024 are presented below.
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2025: | (Level 1) | (Level 2) | (NAV) | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 42 | % | |||||||||||||||||||
| Domestic equity | $ | 2,216 | $ | 884 | $ | — | $ | 3,100 | |||||||||||||||
| International equity | 2,219 | 1,184 | — | 3,403 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 1,994 | — | 1,994 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 75 | — | 75 | |||||||||||||||||||
| Corporate bonds | — | 1,859 | — | 1,859 | |||||||||||||||||||
| Pooled funds | — | 850 | — | 850 | |||||||||||||||||||
| Cash equivalents and other | 237 | 5 | — | 242 | |||||||||||||||||||
| Real estate investments | 350 | — | 1,541 | 1,891 | 12 | 12 | |||||||||||||||||
| Special situations | — | — | 258 | 258 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 1,829 | 1,829 | 9 | 11 | |||||||||||||||||
| Private credit | — | — | 265 | 265 | 3 | 2 | |||||||||||||||||
| Infrastructure | — | — | 60 | 60 | 2 | — | |||||||||||||||||
| Total | $ | 5,022 | $ | 6,851 | $ | 3,953 | $ | 15,826 | 100 | % | 100 | % | |||||||||||
| Liabilities: | |||||||||||||||||||||||
| Derivatives | $ | (1) | $ | — | $ | — | $ | (1) | |||||||||||||||
| Total | $ | 5,021 | $ | 6,851 | $ | 3,953 | $ | 15,825 | 100 | % | 100 | % | |||||||||||
| Alabama Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 42 | % | |||||||||||||||||||
| Domestic equity | $ | 538 | $ | 215 | $ | — | $ | 753 | |||||||||||||||
| International equity | 541 | 289 | — | 830 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 486 | — | 486 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 18 | — | 18 | |||||||||||||||||||
| Corporate bonds | — | 453 | — | 453 | |||||||||||||||||||
| Pooled funds | — | 207 | — | 207 | |||||||||||||||||||
| Cash equivalents and other | 58 | 1 | — | 59 | |||||||||||||||||||
| Real estate investments | 85 | — | 376 | 461 | 12 | 12 | |||||||||||||||||
| Special situations | — | — | 63 | 63 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 446 | 446 | 9 | 11 | |||||||||||||||||
| Private credit | — | — | 65 | 65 | 3 | 2 | |||||||||||||||||
| Infrastructure | — | — | 15 | 15 | 2 | — | |||||||||||||||||
| Total | $ | 1,222 | $ | 1,669 | $ | 965 | $ | 3,856 | 100 | % | 100 | % | |||||||||||
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| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2025: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 42 | % | |||||||||||||||||||
| Domestic equity | $ | 683 | $ | 273 | $ | — | $ | 956 | |||||||||||||||
| International equity | 685 | 365 | — | 1,050 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 615 | — | 615 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 23 | — | 23 | |||||||||||||||||||
| Corporate bonds | — | 574 | — | 574 | |||||||||||||||||||
| Pooled funds | — | 262 | — | 262 | |||||||||||||||||||
| Cash equivalents and other | 73 | 2 | — | 75 | |||||||||||||||||||
| Real estate investments | 108 | — | 476 | 584 | 12 | 12 | |||||||||||||||||
| Special situations | — | — | 80 | 80 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 564 | 564 | 9 | 11 | |||||||||||||||||
| Private credit | — | — | 82 | 82 | 3 | 2 | |||||||||||||||||
| Infrastructure | — | — | 19 | 19 | 2 | — | |||||||||||||||||
| Total | $ | 1,549 | $ | 2,114 | $ | 1,221 | $ | 4,884 | 100 | % | 100 | % | |||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 42 | % | |||||||||||||||||||
| Domestic equity | $ | 100 | $ | 40 | $ | — | $ | 140 | |||||||||||||||
| International equity | 101 | 54 | — | 155 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 91 | — | 91 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 3 | — | 3 | |||||||||||||||||||
| Corporate bonds | — | 85 | — | 85 | |||||||||||||||||||
| Pooled funds | — | 39 | — | 39 | |||||||||||||||||||
| Cash equivalents and other | 11 | — | — | 11 | |||||||||||||||||||
| Real estate investments | 16 | — | 70 | 86 | 12 | 12 | |||||||||||||||||
| Special situations | — | — | 12 | 12 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 83 | 83 | 9 | 11 | |||||||||||||||||
| Private credit | — | — | 12 | 12 | 3 | 2 | |||||||||||||||||
| Infrastructure | — | — | 3 | 3 | 2 | — | |||||||||||||||||
| Total | $ | 228 | $ | 312 | $ | 180 | $ | 720 | 100 | % | 100 | % | |||||||||||
II-213
Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2025: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 42 | % | |||||||||||||||||||
| Domestic equity | $ | 29 | $ | 12 | $ | — | $ | 41 | |||||||||||||||
| International equity | 29 | 15 | — | 44 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 26 | — | 26 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 24 | — | 24 | |||||||||||||||||||
| Pooled funds | — | 11 | — | 11 | |||||||||||||||||||
| Cash equivalents and other | 3 | — | — | 3 | |||||||||||||||||||
| Real estate investments | 5 | — | 20 | 25 | 12 | 12 | |||||||||||||||||
| Special situations | — | — | 3 | 3 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 24 | 24 | 9 | 11 | |||||||||||||||||
| Private credit | — | — | 3 | 3 | 3 | 2 | |||||||||||||||||
| Infrastructure | — | — | 1 | 1 | 2 | — | |||||||||||||||||
| Total | $ | 66 | $ | 89 | $ | 51 | $ | 206 | 100% | 100 | % | ||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 42 | % | |||||||||||||||||||
| Domestic equity | $ | 148 | $ | 59 | $ | — | $ | 207 | |||||||||||||||
| International equity | 149 | 79 | — | 228 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 134 | — | 134 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 5 | — | 5 | |||||||||||||||||||
| Corporate bonds | — | 125 | — | 125 | |||||||||||||||||||
| Pooled funds | — | 57 | — | 57 | |||||||||||||||||||
| Cash equivalents and other | 16 | — | — | 16 | |||||||||||||||||||
| Real estate investments | 23 | — | 103 | 126 | 12 | 12 | |||||||||||||||||
| Special situations | — | — | 17 | 17 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 123 | 123 | 9 | 11 | |||||||||||||||||
| Private credit | — | — | 18 | 18 | 3 | 2 | |||||||||||||||||
| Infrastructure | — | — | 4 | 4 | 2 | — | |||||||||||||||||
| Total | $ | 336 | $ | 459 | $ | 265 | $ | 1,060 | 100 | % | 100 | % | |||||||||||
II-214
Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (NAV) | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 41 | % | |||||||||||||||||||
| Domestic equity | $ | 2,095 | $ | 835 | $ | — | $ | 2,930 | |||||||||||||||
| International equity | 1,959 | 1,032 | — | 2,991 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 1,780 | — | 1,780 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 48 | — | 48 | |||||||||||||||||||
| Corporate bonds | — | 1,715 | — | 1,715 | |||||||||||||||||||
| Pooled funds | — | 792 | — | 792 | |||||||||||||||||||
| Cash equivalents and other | 255 | — | — | 255 | |||||||||||||||||||
| Real estate investments | 361 | — | 1,563 | 1,924 | 12 | 13 | |||||||||||||||||
| Special situations | — | — | 237 | 237 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 1,797 | 1,797 | 9 | 12 | |||||||||||||||||
| Private Credit | — | — | 152 | 152 | 3 | 1 | |||||||||||||||||
| Infrastructure | — | — | — | — | 2 | — | |||||||||||||||||
| Total | $ | 4,670 | $ | 6,202 | $ | 3,749 | $ | 14,621 | 100 | % | 100 | % | |||||||||||
| Liabilities: | |||||||||||||||||||||||
| Derivatives | $ | — | $ | (33) | $ | — | $ | (33) | |||||||||||||||
| Total | $ | 4,670 | $ | 6,169 | $ | 3,749 | $ | 14,588 | 100 | % | 100 | % | |||||||||||
II-215
Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 41 | % | |||||||||||||||||||
| Domestic equity | $ | 509 | $ | 203 | $ | — | $ | 712 | |||||||||||||||
| International equity | 476 | 251 | — | 727 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 433 | — | 433 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 12 | — | 12 | |||||||||||||||||||
| Corporate bonds | — | 417 | — | 417 | |||||||||||||||||||
| Pooled funds | — | 193 | — | 193 | |||||||||||||||||||
| Cash equivalents and other | 62 | — | — | 62 | |||||||||||||||||||
| Real estate investments | 88 | — | 380 | 468 | 12 | 13 | |||||||||||||||||
| Special situations | — | — | 57 | 57 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 437 | 437 | 9 | 12 | |||||||||||||||||
| Private credit | — | — | 37 | 37 | 3 | 1 | |||||||||||||||||
| Infrastructure | — | — | — | — | 2 | — | |||||||||||||||||
| Total | $ | 1,135 | $ | 1,509 | $ | 911 | $ | 3,555 | 100 | % | 100 | % | |||||||||||
| Liabilities: | |||||||||||||||||||||||
| Derivatives | $ | — | $ | (8) | $ | — | $ | (8) | |||||||||||||||
| Total | $ | 1,135 | $ | 1,501 | $ | 911 | $ | 3,547 | 100 | % | 100 | % | |||||||||||
II-216
Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 41 | % | |||||||||||||||||||
| Domestic equity | $ | 652 | $ | 259 | $ | — | $ | 911 | |||||||||||||||
| International equity | 608 | 320 | — | 928 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 552 | — | 552 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 15 | — | 15 | |||||||||||||||||||
| Corporate bonds | — | 532 | — | 532 | |||||||||||||||||||
| Pooled funds | — | 246 | — | 246 | |||||||||||||||||||
| Cash equivalents and other | 79 | — | — | 79 | |||||||||||||||||||
| Real estate investments | 112 | — | 485 | 597 | 12 | 13 | |||||||||||||||||
| Special situations | — | — | 73 | 73 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 558 | 558 | 9 | 12 | |||||||||||||||||
| Private credit | — | — | 47 | 47 | 3 | 1 | |||||||||||||||||
| Infrastructure | — | — | — | — | 2 | — | |||||||||||||||||
| Total | $ | 1,451 | $ | 1,924 | $ | 1,163 | $ | 4,538 | 100 | % | 100 | % | |||||||||||
| Liabilities: | |||||||||||||||||||||||
| Derivatives | $ | — | $ | (10) | $ | — | $ | (10) | |||||||||||||||
| Total | $ | 1,451 | $ | 1,914 | $ | 1,163 | $ | 4,528 | 100 | % | 100 | % | |||||||||||
II-217
Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 41 | % | |||||||||||||||||||
| Domestic equity | $ | 97 | $ | 38 | $ | — | $ | 135 | |||||||||||||||
| International equity | 89 | 47 | — | 136 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 81 | — | 81 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 2 | — | 2 | |||||||||||||||||||
| Corporate bonds | — | 78 | — | 78 | |||||||||||||||||||
| Pooled funds | — | 36 | — | 36 | |||||||||||||||||||
| Cash equivalents and other | 12 | — | — | 12 | |||||||||||||||||||
| Real estate investments | 16 | — | 71 | 87 | 12 | 13 | |||||||||||||||||
| Special situations | — | — | 11 | 11 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 82 | 82 | 9 | 12 | |||||||||||||||||
| Private credit | — | — | 7 | 7 | 3 | 1 | |||||||||||||||||
| Infrastructure | — | — | — | — | 2 | — | |||||||||||||||||
| Total | $ | 214 | $ | 282 | $ | 171 | $ | 667 | 100 | % | 100 | % | |||||||||||
| Liabilities: | |||||||||||||||||||||||
| Derivatives | $ | — | $ | (2) | $ | — | $ | (2) | |||||||||||||||
| Total | $ | 214 | $ | 280 | $ | 171 | $ | 665 | 100 | % | 100 | % | |||||||||||
| Southern Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 41 | % | |||||||||||||||||||
| Domestic equity | $ | 27 | $ | 11 | $ | — | $ | 38 | |||||||||||||||
| International equity | 25 | 13 | — | 38 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 23 | — | 23 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 22 | — | 22 | |||||||||||||||||||
| Pooled funds | — | 10 | — | 10 | |||||||||||||||||||
| Cash equivalents and other | 3 | — | — | 3 | |||||||||||||||||||
| Real estate investments | 5 | — | 20 | 25 | 12 | 13 | |||||||||||||||||
| Special situations | — | — | 3 | 3 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 23 | 23 | 9 | 12 | |||||||||||||||||
| Private credit | — | — | 2 | 2 | 3 | 1 | |||||||||||||||||
| Infrastructure | — | — | — | — | 2 | — | |||||||||||||||||
| Total | $ | 60 | $ | 80 | $ | 48 | $ | 188 | 100 | % | 100 | % | |||||||||||
II-218
Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 41 | % | 41 | % | |||||||||||||||||||
| Domestic equity | $ | 142 | $ | 56 | $ | — | $ | 198 | |||||||||||||||
| International equity | 132 | 69 | — | 201 | |||||||||||||||||||
| Fixed income: | 30 | 31 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 120 | — | 120 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 3 | — | 3 | |||||||||||||||||||
| Corporate bonds | — | 115 | — | 115 | |||||||||||||||||||
| Pooled funds | — | 53 | — | 53 | |||||||||||||||||||
| Cash equivalents and other | 17 | — | — | 17 | |||||||||||||||||||
| Real estate investments | 24 | — | 105 | 129 | 12 | 13 | |||||||||||||||||
| Special situations | — | — | 16 | 16 | 3 | 2 | |||||||||||||||||
| Private equity | — | — | 121 | 121 | 9 | 12 | |||||||||||||||||
| Private credit | — | — | 10 | 10 | 3 | 1 | |||||||||||||||||
| Infrastructure | — | — | — | — | 2 | — | |||||||||||||||||
| Total | $ | 315 | $ | 416 | $ | 252 | $ | 983 | 100 | % | 100 | % | |||||||||||
| Liabilities: | |||||||||||||||||||||||
| Derivatives | $ | — | $ | (2) | $ | — | $ | (2) | |||||||||||||||
| Total | $ | 315 | $ | 414 | $ | 252 | $ | 981 | 100 | % | 100 | % |
II-219
Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS
The fair values, and actual allocations relative to the target allocations, of the applicable Registrants' other postretirement benefit plan assets at December 31, 2025 and 2024 are presented below.
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Total | Target Allocation | Actual Allocation | ||||||||||||||||||
| At December 31, 2025: | (Level 1) | (Level 2) | (NAV) | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 60 | % | 63 | % | |||||||||||||||||||
| Domestic equity | $ | 98 | $ | 108 | $ | — | $ | 206 | |||||||||||||||
| International equity | 63 | 102 | — | 165 | |||||||||||||||||||
| Fixed income: | 30 | 27 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 61 | — | 61 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 2 | — | 2 | |||||||||||||||||||
| Corporate bonds | — | 53 | — | 53 | |||||||||||||||||||
| Pooled funds | — | 106 | — | 106 | |||||||||||||||||||
| Cash equivalents and other | 13 | — | — | 13 | |||||||||||||||||||
| Trust-owned life insurance | — | 520 | — | 520 | |||||||||||||||||||
| Real estate investments | 11 | — | 44 | 55 | 4 | 4 | |||||||||||||||||
| Special situations | — | — | 7 | 7 | 1 | 1 | |||||||||||||||||
| Private equity | — | — | 52 | 52 | 3 | 4 | |||||||||||||||||
| Private credit | — | — | 7 | 7 | 1 | 1 | |||||||||||||||||
| Infrastructure | — | — | 2 | 2 | 1 | — | |||||||||||||||||
| Total | $ | 185 | $ | 952 | $ | 112 | $ | 1,249 | 100 | % | 100 | % | |||||||||||
II-220
Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Total | Target Allocation | Actual Allocation | ||||||||||||||||||
| At December 31, 2025: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 68 | % | 69 | % | |||||||||||||||||||
| Domestic equity | $ | 18 | $ | 7 | $ | — | $ | 25 | |||||||||||||||
| International equity | 18 | 10 | — | 28 | |||||||||||||||||||
| Fixed income: | 23 | 23 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 17 | — | 17 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 15 | — | 15 | |||||||||||||||||||
| Pooled funds | — | 11 | — | 11 | |||||||||||||||||||
| Cash equivalents and other | 2 | — | — | 2 | |||||||||||||||||||
| Trust-owned life insurance | — | 320 | — | 320 | |||||||||||||||||||
| Real estate investments | 3 | — | 13 | 16 | 3 | 3 | |||||||||||||||||
| Special situations | — | — | 2 | 2 | 1 | 1 | |||||||||||||||||
| Private equity | — | — | 15 | 15 | 3 | 3 | |||||||||||||||||
| Private credit | — | — | 2 | 2 | 1 | 1 | |||||||||||||||||
| Infrastructure | — | — | — | — | 1 | — | |||||||||||||||||
| Total | $ | 41 | $ | 381 | $ | 32 | $ | 454 | 100 | % | 100 | % | |||||||||||
| Georgia Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 59 | % | 60 | % | |||||||||||||||||||
| Domestic equity | $ | 54 | $ | 7 | $ | — | $ | 61 | |||||||||||||||
| International equity | 18 | 50 | — | 68 | |||||||||||||||||||
| Fixed income: | 35 | 32 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 17 | — | 17 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 15 | — | 15 | |||||||||||||||||||
| Pooled funds | — | 51 | — | 51 | |||||||||||||||||||
| Cash equivalents and other | 8 | — | — | 8 | |||||||||||||||||||
| Trust-owned life insurance | — | 201 | — | 201 | |||||||||||||||||||
| Real estate investments | 4 | — | 13 | 17 | 3 | 3 | |||||||||||||||||
| Special situations | — | — | 2 | 2 | 1 | 1 | |||||||||||||||||
| Private equity | — | — | 15 | 15 | 2 | 3 | |||||||||||||||||
| Private credit | — | — | 2 | 2 | — | 1 | |||||||||||||||||
| Total | $ | 84 | $ | 342 | $ | 32 | $ | 458 | 100 | % | 100 | % | |||||||||||
II-221
Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Total | Target Allocation | Actual Allocation | ||||||||||||||||||
| At December 31, 2025: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 34 | % | 34 | % | |||||||||||||||||||
| Domestic equity | $ | 3 | $ | 1 | $ | — | $ | 4 | |||||||||||||||
| International equity | 3 | 2 | — | 5 | |||||||||||||||||||
| Fixed income: | 43 | 43 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 7 | — | 7 | |||||||||||||||||||
| Corporate bonds | — | 3 | — | 3 | |||||||||||||||||||
| Pooled funds | — | 1 | — | 1 | |||||||||||||||||||
| Cash equivalents and other | 1 | — | — | 1 | |||||||||||||||||||
| Real estate investments | — | — | 2 | 2 | 10 | 10 | |||||||||||||||||
| Special situations | — | — | — | — | 2 | 2 | |||||||||||||||||
| Private equity | — | — | 3 | 3 | 7 | 9 | |||||||||||||||||
| Private credit | — | — | — | — | 3 | 2 | |||||||||||||||||
| Infrastructure | — | — | — | — | 1 | — | |||||||||||||||||
| Total | $ | 7 | $ | 14 | $ | 5 | $ | 26 | 100 | % | 100 | % | |||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 72 | % | 74 | % | |||||||||||||||||||
| Domestic equity | $ | 1 | $ | 83 | $ | — | $ | 84 | |||||||||||||||
| International equity | 1 | 29 | — | 30 | |||||||||||||||||||
| Fixed income: | 26 | 24 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 1 | — | 1 | |||||||||||||||||||
| Pooled funds | — | 34 | — | 34 | |||||||||||||||||||
| Cash equivalents and other | 1 | — | — | 1 | |||||||||||||||||||
| Real estate investments | — | — | 1 | 1 | 1 | 1 | |||||||||||||||||
| Private equity | — | — | 1 | 1 | 1 | 1 | |||||||||||||||||
| Total | $ | 3 | $ | 148 | $ | 2 | $ | 153 | 100 | % | 100 | % |
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| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (NAV) | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 61 | % | 62 | % | |||||||||||||||||||
| Domestic equity | $ | 94 | $ | 98 | $ | — | $ | 192 | |||||||||||||||
| International equity | 54 | 83 | — | 137 | |||||||||||||||||||
| Fixed income: | 29 | 28 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 54 | — | 54 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 48 | — | 48 | |||||||||||||||||||
| Pooled funds | — | 99 | — | 99 | |||||||||||||||||||
| Cash equivalents and other | 16 | — | — | 16 | |||||||||||||||||||
| Trust-owned life insurance | — | 478 | — | 478 | |||||||||||||||||||
| Real estate investments | 11 | — | 43 | 54 | 4 | 5 | |||||||||||||||||
| Special situations | — | — | 6 | 6 | 1 | 1 | |||||||||||||||||
| Private equity | — | — | 50 | 50 | 3 | 4 | |||||||||||||||||
| Private credit | — | — | 4 | 4 | 1 | — | |||||||||||||||||
| Infrastructure | — | — | — | — | 1 | — | |||||||||||||||||
| Total | $ | 175 | $ | 861 | $ | 103 | $ | 1,139 | 100 | % | 100 | % | |||||||||||
| Liabilities: | |||||||||||||||||||||||
| Derivatives | $ | — | $ | (1) | $ | — | $ | (1) | |||||||||||||||
| Total | $ | 175 | $ | 860 | $ | 103 | $ | 1,138 | 100 | % | 100 | % | |||||||||||
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| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 68 | % | 68 | % | |||||||||||||||||||
| Domestic equity | $ | 17 | $ | 7 | $ | — | $ | 24 | |||||||||||||||
| International equity | 16 | 9 | — | 25 | |||||||||||||||||||
| Fixed income: | 23 | 24 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 14 | — | 14 | |||||||||||||||||||
| Corporate bonds | — | 14 | — | 14 | |||||||||||||||||||
| Pooled funds | — | 11 | — | 11 | |||||||||||||||||||
| Cash equivalents and other | 2 | — | — | 2 | |||||||||||||||||||
| Trust-owned life insurance | — | 294 | — | 294 | |||||||||||||||||||
| Real estate investments | 3 | — | 13 | 16 | 3 | 4 | |||||||||||||||||
| Special situations | — | — | 2 | 2 | 1 | 1 | |||||||||||||||||
| Private equity | — | — | 15 | 15 | 3 | 3 | |||||||||||||||||
| Private credit | — | — | 1 | 1 | 1 | — | |||||||||||||||||
| Infrastructure | — | — | — | — | 1 | — | |||||||||||||||||
| Total | $ | 38 | $ | 349 | $ | 31 | $ | 418 | 100 | % | 100 | % | |||||||||||
| Georgia Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 59 | % | 59 | % | |||||||||||||||||||
| Domestic equity | $ | 52 | $ | 7 | $ | — | $ | 59 | |||||||||||||||
| International equity | 16 | 41 | — | 57 | |||||||||||||||||||
| Fixed income: | 35 | 33 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 14 | — | 14 | |||||||||||||||||||
| Corporate bonds | — | 14 | — | 14 | |||||||||||||||||||
| Pooled funds | — | 48 | — | 48 | |||||||||||||||||||
| Cash equivalents and other | 10 | — | — | 10 | |||||||||||||||||||
| Trust-owned life insurance | — | 184 | — | 184 | |||||||||||||||||||
| Real estate investments | 4 | — | 13 | 17 | 3 | 4 | |||||||||||||||||
| Special situations | — | — | 2 | 2 | 1 | 1 | |||||||||||||||||
| Private equity | — | — | 15 | 15 | 2 | 3 | |||||||||||||||||
| Total | $ | 82 | $ | 308 | $ | 30 | $ | 420 | 100 | % | 100 | % | |||||||||||
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| Fair Value Measurements Using | |||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Net Asset Value as a Practical Expedient | Target Allocation | Actual Allocation | |||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (NAV) | Total | Target Allocation | Actual Allocation | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 34 | % | 32 | % | |||||||||||||||||||
| Domestic equity | $ | 3 | $ | 1 | $ | — | $ | 4 | |||||||||||||||
| International equity | 3 | 1 | — | 4 | |||||||||||||||||||
| Fixed income: | 43 | 44 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 7 | — | 7 | |||||||||||||||||||
| Corporate bonds | — | 2 | — | 2 | |||||||||||||||||||
| Pooled funds | — | 1 | — | 1 | |||||||||||||||||||
| Cash equivalents and other | 1 | — | — | 1 | |||||||||||||||||||
| Real estate investments | — | — | 2 | 2 | 10 | 11 | |||||||||||||||||
| Special situations | — | — | — | — | 2 | 2 | |||||||||||||||||
| Private equity | — | — | 2 | 2 | 7 | 10 | |||||||||||||||||
| Private credit | — | — | — | — | 3 | 1 | |||||||||||||||||
| Infrastructure | — | — | — | — | 1 | — | |||||||||||||||||
| Total | $ | 7 | $ | 12 | $ | 4 | $ | 23 | 100 | % | 100 | % | |||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 72 | % | 73 | % | |||||||||||||||||||
| Domestic equity | $ | 1 | $ | 76 | $ | — | $ | 77 | |||||||||||||||
| International equity | 1 | 23 | — | 24 | |||||||||||||||||||
| Fixed income: | 26 | 25 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 1 | — | 1 | |||||||||||||||||||
| Pooled funds | — | 32 | — | 32 | |||||||||||||||||||
| Cash equivalents and other | 1 | — | — | 1 | |||||||||||||||||||
| Real estate investments | — | — | 1 | 1 | 1 | 1 | |||||||||||||||||
| Private equity | — | — | 1 | 1 | 1 | 1 | |||||||||||||||||
| Total | $ | 3 | $ | 133 | $ | 2 | $ | 138 | 100 | % | 100 | % |
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Employee Savings Plan
Southern Company and its subsidiaries also sponsor 401(k) defined contribution plans covering substantially all employees and provide matching contributions up to specified percentages of an employee's eligible pay. Total matching contributions made to the plans for 2025, 2024, and 2023 were as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2025 | $ | 148 | $ | 30 | $ | 36 | $ | 5 | $ | 3 | $ | 21 | ||||||||
| 2024 | 137 | 29 | 31 | 5 | 3 | 20 | ||||||||||||||
| 2023 | 131 | 28 | 31 | 5 | 3 | 18 |
12. STOCK COMPENSATION
Stock-based compensation in the form of Southern Company performance share units (PSU) and restricted stock units (RSU) may be granted through the Equity and Incentive Compensation Plan to eligible Southern Company system employees.
At December 31, 2025, the number of current and former employees participating in stock-based compensation programs for the Registrants was as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| Number of employees | 1,189 | 163 | 185 | 37 | 33 | 182 |
The majority of PSUs and RSUs awarded contain terms where employees become immediately vested in PSUs and RSUs upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized immediately, while compensation expense for employees that are expected to become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. In addition, the Registrants recognize forfeitures as they occur.
All unvested PSUs and RSUs vest immediately upon a change in control where Southern Company is not the surviving corporation. Stock-based compensation activity is immaterial for the Subsidiary Registrants.
In 2015, Southern Company discontinued granting stock options. As of December 31, 2017, all stock option awards were vested and compensation cost fully recognized, and the last exercise occurred in November 2024. Southern Company's cash receipts from issuances related to stock options exercised under the share-based payment arrangements, total intrinsic value of options exercised, and the related tax benefit were immaterial for the years ended December 31, 2024 and 2023.
Performance Share Units
PSUs granted to employees vest at the end of a three-year performance period. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of PSUs granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors.
Southern Company has issued two types of PSUs, each with a unique performance goal. These types of PSUs include total shareholder return (TSR) awards based on the TSR for Southern Company common stock during the three-year performance period as compared to a group of industry peers and ROE awards based on Southern Company's equity-weighted return over the performance period.
The fair value of TSR awards is determined as of the grant date using a Monte Carlo simulation model. In determining the fair value of the TSR awards issued to employees, the expected volatility is based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the
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time of grant that covers the performance period of the awards. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of TSR awards granted:
| Year Ended December 31 | 2025 | 2024 | 2023 | ||||||||
| Expected volatility | 19.7% | 19.1% | 30.0% | ||||||||
| Interest rate | 4.1% | 4.0% | 3.8% | ||||||||
| Weighted average grant-date fair value | $91.26 | $80.99 | $76.83 |
The Registrants recognize TSR award compensation expense on a straight-line basis over the three-year performance period without remeasurement.
The fair values of ROE awards are based on the closing stock price of Southern Company common stock on the date of the grant. The weighted average grant-date fair value of the ROE awards granted during 2025, 2024, and 2023 was $84.06, $69.67, and $68.93, respectively. Compensation expense for ROE awards is generally recognized ratably over the three-year performance period adjusted for expected changes in ROE performance. Total compensation cost recognized for vested ROE awards reflects final performance metrics.
Southern Company had 2.3 million unvested PSUs outstanding at December 31, 2024. In February 2025, the PSUs that vested for the three-year performance period ended December 31, 2024 were converted into 2.0 million shares outstanding at a share price of $83.87. During 2025, Southern Company granted 1.0 million PSUs and 1.3 million PSUs were vested or forfeited, resulting in 2.0 million unvested PSUs outstanding at December 31, 2025. In February 2026, the PSUs that vested for the three-year performance period ended December 31, 2025 were converted into 2.4 million shares outstanding at a weighted average share price of $90.86.
Southern Company's total PSU compensation cost and the related tax benefit recognized in income for the years ended December 31, 2025, 2024, and 2023 were as follows:
| 2025 | 2024 | 2023 | |||||||||
| (in millions) | |||||||||||
| Compensation cost recognized in income | $ | 102 | $ | 102 | $ | 107 | |||||
| Tax benefit of compensation cost recognized in income | 26 | 27 | 28 | ||||||||
The compensation cost related to the grant of Southern Company PSUs to the employees of each Subsidiary Registrant is recognized in each Subsidiary Registrant's financial statements with a corresponding credit to equity representing a capital contribution from Southern Company.
At December 31, 2025, Southern Company's total unrecognized compensation cost related to PSUs was $32 million and is expected to be recognized over a weighted-average period of approximately 18 months.
Restricted Stock Units
The fair value of RSUs is based on the closing stock price of Southern Company common stock on the date of the grant. The weighted average grant-date fair values of RSUs granted during 2025, 2024, and 2023 were $85.18, $70.49, and $68.95, respectively. For most RSU awards, one-third of the RSUs vest each year throughout a three-year service period and compensation cost for RSUs is generally recognized over the corresponding one-, two-, or three-year vesting period. Shares of Southern Company common stock are delivered to employees at the end of each vesting period.
Southern Company had 0.9 million RSUs outstanding at December 31, 2024. During 2025, Southern Company granted 0.5 million RSUs and 0.5 million RSUs were vested or forfeited, resulting in 0.9 million unvested RSUs outstanding at December 31, 2025, including RSUs related to employee retention agreements.
Southern Company's total RSU compensation cost and the related tax benefit recognized in income for the years ended December 31, 2025, 2024, and 2023 were as follows:
| 2025 | 2024 | 2023 | |||||||||
| (in millions) | |||||||||||
| Compensation cost recognized in income | $ | 33 | $ | 30 | $ | 30 | |||||
| Tax benefit of compensation cost recognized in income | 9 | 8 | 8 |
Total unrecognized compensation cost related to RSUs at December 31, 2025, which is being recognized over a weighted-average period of approximately 18 months, was immaterial for Southern Company.
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The compensation cost related to the grant of Southern Company RSUs to the employees of each Subsidiary Registrant is recognized in such Subsidiary Registrant's financial statements with a corresponding credit to equity representing a capital contribution from Southern Company.
13. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
-
Level 1 consists of observable market data in an active market for identical assets or liabilities.
-
Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
-
Level 3 consists of unobservable market data. The input may reflect the assumptions of each Registrant of what a market participant would use in pricing an asset or liability. If there is little available market data, then each Registrant's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the lowest level input that is significant to the fair value measurement represents the level in the fair value hierarchy in which the fair value measurement is reported.
Net asset value as a practical expedient is the classification used for assets that do not have readily determined fair values. Fund managers value the assets using various inputs and techniques depending on the nature of the underlying investments.
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At December 31, 2025, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| Fair Value Measurements Using | |||||||||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | ||||||||||||||||||||||||||
| At December 31, 2025: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 4 | $ | 60 | $ | — | $ | — | $ | 64 | |||||||||||||||||||
| Interest rate derivatives | — | 8 | — | — | 8 | ||||||||||||||||||||||||
| Foreign currency derivatives | — | 21 | — | — | 21 | ||||||||||||||||||||||||
| Investments in trusts:(b) | |||||||||||||||||||||||||||||
| Domestic equity | 935 | 278 | — | — | 1,213 | ||||||||||||||||||||||||
| Foreign equity | 182 | 225 | — | — | 407 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 398 | — | — | 398 | ||||||||||||||||||||||||
| Municipal bonds | — | 50 | — | — | 50 | ||||||||||||||||||||||||
| Pooled funds – fixed income | — | 6 | — | — | 6 | ||||||||||||||||||||||||
| Corporate bonds | — | 520 | — | — | 520 | ||||||||||||||||||||||||
| Mortgage- and asset-backed securities | — | 114 | — | — | 114 | ||||||||||||||||||||||||
| Private equity | — | — | — | 192 | 192 | ||||||||||||||||||||||||
| Cash and cash equivalents | 1 | — | — | — | 1 | ||||||||||||||||||||||||
| Other | 50 | 3 | — | 9 | 62 | ||||||||||||||||||||||||
| Investments, available for sale: | |||||||||||||||||||||||||||||
| U.S. Treasury and government agency securities | 3 | 12 | — | — | 15 | ||||||||||||||||||||||||
| Corporate bonds | 1 | 2 | — | — | 3 | ||||||||||||||||||||||||
| Mortgage- and asset-backed securities | — | 5 | — | — | 5 | ||||||||||||||||||||||||
| Cash equivalents | 1,080 | 19 | — | — | 1,099 | ||||||||||||||||||||||||
| Other investments | 10 | 34 | 8 | — | 52 | ||||||||||||||||||||||||
| Other | — | — | 11 | — | 11 | ||||||||||||||||||||||||
| Total | $ | 2,266 | $ | 1,755 | $ | 19 | $ | 201 | $ | 4,241 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 12 | $ | 100 | $ | — | $ | — | $ | 112 | |||||||||||||||||||
| Interest rate derivatives | — | 187 | — | — | 187 | ||||||||||||||||||||||||
| Foreign currency derivatives | — | 22 | — | — | 22 | ||||||||||||||||||||||||
| Contingent consideration | 3 | — | 11 | — | 14 | ||||||||||||||||||||||||
| Other | — | 13 | 11 | — | 24 | ||||||||||||||||||||||||
| Total | $ | 15 | $ | 322 | $ | 22 | $ | — | $ | 359 | |||||||||||||||||||
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COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | ||||||||||||||||||||||||||
| At December 31, 2025: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 19 | $ | — | $ | — | $ | 19 | |||||||||||||||||||
| Nuclear decommissioning trusts:(b) | |||||||||||||||||||||||||||||
| Domestic equity | 514 | 267 | — | — | 781 | ||||||||||||||||||||||||
| Foreign equity | 182 | — | — | — | 182 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 15 | — | — | 15 | ||||||||||||||||||||||||
| Municipal bonds | — | 1 | — | — | 1 | ||||||||||||||||||||||||
| Corporate bonds | — | 316 | — | — | 316 | ||||||||||||||||||||||||
| Mortgage- and asset-backed securities | — | 31 | — | — | 31 | ||||||||||||||||||||||||
| Private equity | — | — | — | 192 | 192 | ||||||||||||||||||||||||
| Other | 12 | 1 | — | 9 | 22 | ||||||||||||||||||||||||
| Cash equivalents | 273 | 19 | — | — | 292 | ||||||||||||||||||||||||
| Other investments | — | 34 | — | — | 34 | ||||||||||||||||||||||||
| Total | $ | 981 | $ | 703 | $ | — | $ | 201 | $ | 1,885 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 31 | $ | — | $ | — | $ | 31 | |||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 18 | $ | — | $ | — | $ | 18 | |||||||||||||||||||
| Nuclear decommissioning trusts:(b) | |||||||||||||||||||||||||||||
| Domestic equity | 421 | 1 | — | — | 422 | ||||||||||||||||||||||||
| Foreign equity | — | 224 | — | — | 224 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 383 | — | — | 383 | ||||||||||||||||||||||||
| Municipal bonds | — | 49 | — | — | 49 | ||||||||||||||||||||||||
| Corporate bonds | — | 204 | — | — | 204 | ||||||||||||||||||||||||
| Mortgage- and asset-backed securities | — | 83 | — | — | 83 | ||||||||||||||||||||||||
| Other | 38 | 2 | — | — | 40 | ||||||||||||||||||||||||
| Cash equivalents | 20 | — | — | — | 20 | ||||||||||||||||||||||||
| Total | $ | 479 | $ | 964 | $ | — | $ | — | $ | 1,443 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 33 | $ | — | $ | — | $ | 33 | |||||||||||||||||||
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COMBINED NOTES TO FINANCIAL STATEMENTS
| Fair Value Measurements Using | |||||||||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | ||||||||||||||||||||||||||
| At December 31, 2025: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 14 | $ | — | $ | — | $ | 14 | |||||||||||||||||||
| Cash equivalents | 12 | — | — | — | 12 | ||||||||||||||||||||||||
| Total | $ | 12 | $ | 14 | $ | — | $ | — | $ | 26 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 27 | $ | — | $ | — | $ | 27 | |||||||||||||||||||
| Southern Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 4 | $ | — | $ | — | $ | 4 | |||||||||||||||||||
| Foreign currency derivatives | — | 17 | — | — | 17 | ||||||||||||||||||||||||
| Other | — | — | 11 | — | 11 | ||||||||||||||||||||||||
| Total | $ | — | $ | 21 | $ | 11 | $ | — | $ | 32 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 1 | $ | — | $ | — | $ | 1 | |||||||||||||||||||
| Contingent consideration | 3 | — | 11 | — | 14 | ||||||||||||||||||||||||
| Other | — | 13 | 11 | — | 24 | ||||||||||||||||||||||||
| Total | $ | 3 | $ | 14 | $ | 22 | $ | — | $ | 39 | |||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 4 | $ | 5 | $ | — | $ | — | $ | 9 | |||||||||||||||||||
| Non-qualified deferred compensation trusts: | |||||||||||||||||||||||||||||
| Domestic equity | — | 10 | — | — | 10 | ||||||||||||||||||||||||
| Foreign equity | — | 1 | — | — | 1 | ||||||||||||||||||||||||
| Pooled funds - fixed income | — | 6 | — | — | 6 | ||||||||||||||||||||||||
| Cash and cash equivalents | 1 | — | — | — | 1 | ||||||||||||||||||||||||
| Total | $ | 5 | $ | 22 | $ | — | $ | — | $ | 27 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 12 | $ | 8 | $ | — | $ | — | $ | 20 | |||||||||||||||||||
| Interest rate derivatives | — | 59 | — | — | 59 | ||||||||||||||||||||||||
| Total | $ | 12 | $ | 67 | $ | — | $ | — | $ | 79 |
(a)Excludes cash collateral of $33 million.
(b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under "Nuclear Decommissioning" for additional information.
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At December 31, 2024, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
| Fair Value Measurements Using | |||||||||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | ||||||||||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 12 | $ | 77 | $ | — | $ | — | $ | 89 | |||||||||||||||||||
| Investments in trusts:(b) | |||||||||||||||||||||||||||||
| Domestic equity | 849 | 250 | — | — | 1,099 | ||||||||||||||||||||||||
| Foreign equity | 148 | 175 | — | — | 323 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 371 | — | — | 371 | ||||||||||||||||||||||||
| Municipal bonds | — | 47 | — | — | 47 | ||||||||||||||||||||||||
| Pooled funds – fixed income | — | 7 | — | — | 7 | ||||||||||||||||||||||||
| Corporate bonds | — | 452 | — | — | 452 | ||||||||||||||||||||||||
| Mortgage- and asset-backed securities | — | 106 | — | — | 106 | ||||||||||||||||||||||||
| Private equity | — | — | — | 181 | 181 | ||||||||||||||||||||||||
| Cash and cash equivalents | 1 | — | — | — | 1 | ||||||||||||||||||||||||
| Other | 39 | 3 | — | 9 | 51 | ||||||||||||||||||||||||
| Investment, available for sale: | |||||||||||||||||||||||||||||
| U.S. Treasury and government agency securities | 2 | 7 | — | — | 9 | ||||||||||||||||||||||||
| Corporate bonds | 1 | 2 | — | — | 3 | ||||||||||||||||||||||||
| Mortgage- and asset-backed securities | — | 10 | — | — | 10 | ||||||||||||||||||||||||
| Cash equivalents and restricted cash | 533 | 19 | — | — | 552 | ||||||||||||||||||||||||
| Other investments | 9 | 31 | 8 | — | 48 | ||||||||||||||||||||||||
| Total | $ | 1,594 | $ | 1,557 | $ | 8 | $ | 190 | $ | 3,349 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 5 | $ | 124 | $ | — | $ | — | $ | 129 | |||||||||||||||||||
| Interest rate derivatives | — | 269 | — | — | 269 | ||||||||||||||||||||||||
| Foreign currency derivatives | — | 218 | — | — | 218 | ||||||||||||||||||||||||
| Contingent consideration | 3 | — | 16 | — | 19 | ||||||||||||||||||||||||
| Other | — | 13 | 11 | — | 24 | ||||||||||||||||||||||||
| Total | $ | 8 | $ | 624 | $ | 27 | $ | — | $ | 659 | |||||||||||||||||||
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| Fair Value Measurements Using | |||||||||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | ||||||||||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 26 | $ | — | $ | — | $ | 26 | |||||||||||||||||||
| Nuclear decommissioning trusts:(b) | |||||||||||||||||||||||||||||
| Domestic equity | 459 | 241 | — | — | 700 | ||||||||||||||||||||||||
| Foreign equity | 148 | — | — | — | 148 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 16 | — | — | 16 | ||||||||||||||||||||||||
| Municipal bonds | — | 1 | — | — | 1 | ||||||||||||||||||||||||
| Corporate bonds | — | 287 | — | — | 287 | ||||||||||||||||||||||||
| Mortgage- and asset-backed securities | — | 31 | — | — | 31 | ||||||||||||||||||||||||
| Private equity | — | — | — | 181 | 181 | ||||||||||||||||||||||||
| Other | 11 | 1 | — | 9 | 21 | ||||||||||||||||||||||||
| Cash equivalents and restricted cash | 334 | 19 | — | — | 353 | ||||||||||||||||||||||||
| Other investments | — | 31 | — | — | 31 | ||||||||||||||||||||||||
| Total | $ | 952 | $ | 653 | $ | — | $ | 190 | $ | 1,795 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 42 | $ | — | $ | — | $ | 42 | |||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 19 | $ | — | $ | — | $ | 19 | |||||||||||||||||||
| Nuclear decommissioning trusts:(b) | |||||||||||||||||||||||||||||
| Domestic equity | 390 | 1 | — | — | 391 | ||||||||||||||||||||||||
| Foreign equity | — | 174 | — | — | 174 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 355 | — | — | 355 | ||||||||||||||||||||||||
| Municipal bonds | — | 46 | — | — | 46 | ||||||||||||||||||||||||
| Corporate bonds | — | 165 | — | — | 165 | ||||||||||||||||||||||||
| Mortgage- and asset-backed securities | — | 75 | — | — | 75 | ||||||||||||||||||||||||
| Other | 28 | 2 | — | — | 30 | ||||||||||||||||||||||||
| Cash equivalents | 35 | — | — | — | 35 | ||||||||||||||||||||||||
| Total | $ | 453 | $ | 837 | $ | — | $ | — | $ | 1,290 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 42 | $ | — | $ | — | $ | 42 | |||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 19 | $ | — | $ | — | $ | 19 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 34 | $ | — | $ | — | $ | 34 | |||||||||||||||||||
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| Fair Value Measurements Using | |||||||||||||||||||||||||||||
| Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Net Asset Value as a Practical Expedient | ||||||||||||||||||||||||||
| At December 31, 2024: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Southern Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 4 | $ | — | $ | — | $ | 4 | |||||||||||||||||||
| Cash equivalents | 51 | — | — | — | 51 | ||||||||||||||||||||||||
| Total | $ | 51 | $ | 4 | $ | — | $ | — | $ | 55 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Foreign currency derivatives | — | 51 | — | — | 51 | ||||||||||||||||||||||||
| Contingent consideration | 3 | — | 16 | — | 19 | ||||||||||||||||||||||||
| Other | — | 13 | 11 | — | 24 | ||||||||||||||||||||||||
| Total | $ | 3 | $ | 64 | $ | 27 | $ | — | $ | 94 | |||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 12 | $ | 9 | $ | — | $ | — | $ | 21 | |||||||||||||||||||
| Non-qualified deferred compensation trusts: | |||||||||||||||||||||||||||||
| Domestic equity | — | 8 | — | — | 8 | ||||||||||||||||||||||||
| Foreign equity | — | 1 | — | — | 1 | ||||||||||||||||||||||||
| Pooled funds - fixed income | — | 7 | — | — | 7 | ||||||||||||||||||||||||
| Cash and cash equivalents | 1 | — | — | — | 1 | ||||||||||||||||||||||||
| Investments, available-for-sale: | |||||||||||||||||||||||||||||
| U.S. Treasury and government agency securities | 2 | 7 | — | — | 9 | ||||||||||||||||||||||||
| Corporate bonds | 1 | 2 | — | — | 3 | ||||||||||||||||||||||||
| Mortgage- and asset-backed securities | — | 10 | — | — | 10 | ||||||||||||||||||||||||
| Cash equivalents | 22 | — | — | — | 22 | ||||||||||||||||||||||||
| Total | $ | 38 | $ | 44 | $ | — | $ | — | $ | 82 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 5 | $ | 6 | $ | — | $ | — | $ | 11 | |||||||||||||||||||
| Interest rate derivatives | — | 84 | — | — | 84 | ||||||||||||||||||||||||
| Total | $ | 5 | $ | 90 | $ | — | $ | — | $ | 95 |
(a)Excludes cash collateral of $17 million.
(b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under "Nuclear Decommissioning" for additional information.
Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and OTC financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard OTC products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms,
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counterparty credit risk, and, occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note 14 for additional information on how these derivatives are used.
For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 under "Nuclear Decommissioning" for additional information.
Southern Company's investments, available for sale relate to a wholly-owned subsidiary that insures various risk exposures of Southern Company and its subsidiaries. Corporate and municipal bonds, government agency securities, and commercial paper are valued using pricing models maximizing the use of observable inputs for similar securities, including basing value on yields currently available on comparable securities of issues with similar credit ratings. Mortgage- and asset-backed securities are valued through an analysis of the underlying assets and a review of the documentation, including financials, the manager's valuation methodology in valuing their underlying assets, the types of assets and risks involved, and the investor's exit and termination parameters.
Southern Power has contingent payment obligations related to two of its acquisitions whereby it is primarily obligated to make generation-based payments to the seller, commencing at the commercial operation of each facility and continuing through 2026 and 2036, respectively. The obligations are primarily categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility's generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of the obligations reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
Southern Power also has payment obligations through 2040 whereby it must reimburse the transmission owners for interconnection facilities and network upgrades constructed to support connection of a Southern Power generating facility to the transmission system. The obligations are categorized as Level 2 under Fair Value Measurements as the fair value is determined using observable inputs for the contracted amounts and reimbursement period, as well as a discount rate. The fair value of the obligations reflects the net present value of expected payments.
"Other investments" primarily includes investments traded in the open market that have maturities greater than 90 days, which are categorized as Level 2 under Fair Value Measurements and are comprised of corporate bonds, bank certificates of deposit, treasury bonds, and/or agency bonds.
The fair value measurements of private market investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $201 million and $190 million at December 31, 2025 and 2024, respectively. Unfunded commitments related to the private market investments totaled $83 million and $78 million at December 31, 2025 and 2024, respectively. Private market investments include high-quality private equity funds across several market sectors, funds that invest in real estate assets, and a private credit fund. Private market funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated.
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At December 31, 2025 and 2024, other financial instruments for which the carrying amount did not equal fair value were as follows:
| Southern Company**(*)** | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas**(*)** | |||||||||||||||
| (in billions) | ||||||||||||||||||||
| At December 31, 2025: | ||||||||||||||||||||
| Long-term debt, including securities due within one year: | ||||||||||||||||||||
| Carrying amount | $ | 71.1 | $ | 12.0 | $ | 20.8 | $ | 1.8 | $ | 2.9 | $ | 9.3 | ||||||||
| Fair value | 67.2 | 10.9 | 19.4 | 1.6 | 2.9 | 8.4 | ||||||||||||||
| At December 31, 2024: | ||||||||||||||||||||
| Long-term debt, including securities due within one year: | ||||||||||||||||||||
| Carrying amount | $ | 63.2 | $ | 11.2 | $ | 18.1 | $ | 1.7 | $ | 2.7 | $ | 8.5 | ||||||||
| Fair value | 57.7 | 9.8 | 16.2 | 1.5 | 2.6 | 7.4 |
(*)The carrying amount of Southern Company Gas' long-term debt includes fair value adjustments from the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the remaining lives of the respective bonds, the latest being through 2043.
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.
14. DERIVATIVES
The Registrants are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 13 for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 under "Financial Instruments" for additional information.
Energy-Related Derivatives
The Subsidiary Registrants enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in natural gas revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in natural gas revenues.
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Energy-related derivative contracts are accounted for under one of three methods:
-
Regulatory Hedges – Energy-related derivative contracts designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through an approved cost recovery mechanism.
-
Cash Flow Hedges – Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in AOCI before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.
-
Not Designated – Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.
At December 31, 2025, the net volume of energy-related derivative contracts for natural gas positions, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
| Net Purchased mmBtu | Longest Hedge Date | Longest Non-Hedge Date | |||||||||||||||
| (in millions) | |||||||||||||||||
| Southern Company(*) | 431 | 2030 | 2029 | ||||||||||||||
| Alabama Power | 126 | 2028 | — | ||||||||||||||
| Georgia Power | 128 | 2028 | — | ||||||||||||||
| Mississippi Power | 106 | 2030 | — | ||||||||||||||
| Southern Power | 8 | 2030 | 2026 | ||||||||||||||
| Southern Company Gas(*) | 63 | 2028 | 2029 |
(*)Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 72 million mmBtu and short natural gas positions of 9 million mmBtu at December 31, 2025, which is also included in Southern Company's total volume.
In addition to the volumes discussed above, the traditional electric operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 15 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 6 million mmBtu for Georgia Power, 2 million mmBtu for Mississippi Power, and 3 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from AOCI to earnings for the year ending December 31, 2026 are immaterial for Southern Company, Southern Power, and Southern Company Gas.
Interest Rate Derivatives
Southern Company and certain subsidiaries may enter into interest rate derivatives to hedge exposure to changes in interest rates. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
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At December 31, 2025, the following interest rate derivatives were outstanding:
| Notional Amount | Weighted Average Interest Rate Paid | Interest Rate Received | Hedge Maturity Date | Fair Value Gain (Loss) at December 31, 2025 | |||||||||||||
| (in millions) | (in millions) | ||||||||||||||||
| Fair Value Hedges of Existing Debt | |||||||||||||||||
| Southern Company parent | $ | 400 | 1-day SOFR + 0.80% | 1.75% | March 2028 | $ | (24) | ||||||||||
| Southern Company parent | 1,000 | 1-day SOFR + 2.48% | 3.70% | April 2030 | (95) | ||||||||||||
| Southern Company parent | 565 | 1-day SOFR + 1.56% | 6.50% | March 2045 | (1) | ||||||||||||
| Southern Company Gas | 500 | 1-day SOFR + 0.49% | 1.75% | January 2031 | (59) | ||||||||||||
| Southern Company | $ | 2,465 | $ | (179) |
For cash flow hedges of interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from AOCI to interest expense for the year ending December 31, 2026 are immaterial for Southern Company, the traditional electric operating companies, and Southern Company Gas. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2054 for Southern Company, Georgia Power, and Mississippi Power, 2052 for Alabama Power, and 2046 for Southern Company Gas.
Foreign Currency Derivatives
Southern Company and certain subsidiaries, including Southern Power, may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. Southern Company has elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of its foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI.
At December 31, 2025, the following foreign currency derivatives were outstanding:
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge Maturity Date | Fair Value Gain (Loss) at December 31, 2025 | |||||||||||||||
| (in millions) | (in millions) | (in millions) | ||||||||||||||||||
| Cash Flow Hedges of Existing Debt | ||||||||||||||||||||
| Southern Power | $ | 564 | 3.78% | € | 500 | 1.85% | June 2026 | $ | 17 | |||||||||||
| Fair Value Hedges of Existing Debt | ||||||||||||||||||||
| Southern Company parent | 1,476 | 3.39% | 1,250 | 1.88% | September 2027 | (18) | ||||||||||||||
| Southern Company | $ | 2,040 | € | 1,750 | $ | (1) |
For cash flow hedges of foreign currency derivatives, the estimated pre-tax gains expected to be reclassified from AOCI to earnings for the year ending December 31, 2026 are $17 million for Southern Power.
Derivative Financial Statement Presentation and Amounts
The Registrants enter into derivative contracts that may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. The fair value amounts of derivative assets and liabilities on the balance sheets are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.
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The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected as either assets or liabilities in the balance sheets (included in "Other" or shown separately as "Risk Management Activities") as follows:
| At December 31, 2025 | At December 31, 2024 | |||||||||||||
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | ||||||||||
| (in millions) | ||||||||||||||
| Southern Company | ||||||||||||||
| Energy-related derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Current | $ | 24 | $ | 64 | $ | 33 | $ | 82 | ||||||
| Non-current | 31 | 35 | 42 | 40 | ||||||||||
| Total derivatives designated as hedging instruments for regulatory purposes | 55 | 99 | 75 | 122 | ||||||||||
| Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Current | 1 | 6 | 4 | 3 | ||||||||||
| Non-current | 2 | 1 | 4 | — | ||||||||||
| Interest rate derivatives: | ||||||||||||||
| Current | 8 | 48 | — | 61 | ||||||||||
| Non-current | — | 139 | — | 208 | ||||||||||
| Foreign currency derivatives: | ||||||||||||||
| Current | 17 | 22 | — | 36 | ||||||||||
| Non-current | 4 | — | — | 182 | ||||||||||
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | 32 | 216 | 8 | 490 | ||||||||||
| Energy-related derivatives not designated as hedging instruments | ||||||||||||||
| Current | 6 | 6 | 5 | 3 | ||||||||||
| Non-current | — | — | 1 | — | ||||||||||
| Total derivatives not designated as hedging instruments | 6 | 6 | 6 | 3 | ||||||||||
| Gross amounts recognized | 93 | 321 | 89 | 615 | ||||||||||
| Gross amounts offset**(a)** | (21) | (54) | (44) | (61) | ||||||||||
| Net amounts recognized in the Balance Sheets**(b)** | $ | 72 | $ | 267 | $ | 45 | $ | 554 | ||||||
| Alabama Power | ||||||||||||||
| Energy-related derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Current | $ | 9 | $ | 18 | $ | 11 | $ | 30 | ||||||
| Non-current | 10 | 13 | 15 | 12 | ||||||||||
| Total derivatives designated as hedging instruments for regulatory purposes | 19 | 31 | 26 | 42 | ||||||||||
| Gross amounts offset | (13) | (13) | (19) | (19) | ||||||||||
| Net amounts recognized in the Balance Sheets | $ | 6 | $ | 18 | $ | 7 | $ | 23 | ||||||
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| At December 31, 2025 | At December 31, 2024 | |||||||||||||
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | ||||||||||
| (in millions) | ||||||||||||||
| Georgia Power | ||||||||||||||
| Energy-related derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Current | $ | 7 | $ | 23 | $ | 6 | $ | 32 | ||||||
| Non-current | 10 | 10 | 13 | 9 | ||||||||||
| Total derivatives designated as hedging instruments for regulatory purposes | 17 | 33 | 19 | 41 | ||||||||||
| Energy-related derivatives not designated as hedging instruments | ||||||||||||||
| Current | 1 | — | — | 1 | ||||||||||
| Gross amounts recognized | 18 | 33 | 19 | 42 | ||||||||||
| Gross amounts offset | (14) | (14) | (15) | (15) | ||||||||||
| Net amounts recognized in the Balance Sheets | $ | 4 | $ | 19 | $ | 4 | $ | 27 | ||||||
| Mississippi Power | ||||||||||||||
| Energy-related derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Current | $ | 3 | $ | 15 | $ | 5 | $ | 15 | ||||||
| Non-current | 11 | 12 | 14 | 19 | ||||||||||
| Total derivatives designated as hedging instruments for regulatory purposes | 14 | 27 | 19 | 34 | ||||||||||
| Gross amounts offset | (13) | (13) | (17) | (17) | ||||||||||
| Net amounts recognized in the Balance Sheets | $ | 1 | $ | 14 | $ | 2 | $ | 17 | ||||||
| Southern Power | ||||||||||||||
| Derivatives designated as hedging instruments in cash flow hedges | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Current | $ | 1 | $ | 1 | $ | 1 | $ | — | ||||||
| Non-current | 2 | — | 3 | — | ||||||||||
| Foreign currency derivatives: | ||||||||||||||
| Current | 17 | — | — | 11 | ||||||||||
| Non-current | — | — | — | 40 | ||||||||||
| Total derivatives designated as hedging instruments in cash flow hedges | 20 | 1 | 4 | 51 | ||||||||||
| Energy-related derivatives not designated as hedging instruments | ||||||||||||||
| Current | 1 | — | — | — | ||||||||||
| Net amounts recognized in the Balance Sheets | $ | 21 | $ | 1 | $ | 4 | $ | 51 | ||||||
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| At December 31, 2025 | At December 31, 2024 | |||||||||||||
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | ||||||||||
| (in millions) | ||||||||||||||
| Southern Company Gas | ||||||||||||||
| Energy-related derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Current | $ | 5 | $ | 8 | $ | 11 | $ | 5 | ||||||
| Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Current | — | 5 | 3 | 3 | ||||||||||
| Non-current | — | 1 | 1 | — | ||||||||||
| Interest rate derivatives: | ||||||||||||||
| Current | — | 13 | — | 17 | ||||||||||
| Non-current | — | 46 | — | 67 | ||||||||||
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | — | 65 | 4 | 87 | ||||||||||
| Energy-related derivatives not designated as hedging instruments | ||||||||||||||
| Current | 4 | 6 | 5 | 2 | ||||||||||
| Non-current | — | — | 1 | — | ||||||||||
| Total derivatives not designated as hedging instruments | 4 | 6 | 6 | 2 | ||||||||||
| Gross amounts recognized | 9 | 79 | 21 | 94 | ||||||||||
| Gross amounts offset**(a)** | 19 | (14) | 7 | (10) | ||||||||||
| Net amounts recognized in the Balance Sheets**(b)** | $ | 28 | $ | 65 | $ | 28 | $ | 84 |
(a)Gross amounts offset includes cash collateral held on deposit in broker margin accounts of $33 million and $17 million at December 31, 2025 and 2024, respectively.
(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives at December 31, 2025 and 2024.
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At December 31, 2025 and 2024, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
| Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheets | |||||||||||||||||
| Derivative Category and Balance Sheet Location | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas | ||||||||||||
| (in millions) | |||||||||||||||||
| At December 31, 2025: | |||||||||||||||||
| Energy-related derivatives: | |||||||||||||||||
| Other regulatory assets, current | $ | (48) | $ | (13) | $ | (17) | $ | (12) | $ | (6) | |||||||
| Other regulatory assets, deferred | (8) | (5) | (1) | (2) | — | ||||||||||||
| Other regulatory liabilities, current | 7 | 4 | 1 | — | 2 | ||||||||||||
| Other regulatory liabilities, deferred | 4 | 2 | 1 | 1 | — | ||||||||||||
| Total energy-related derivative gains (losses) | $ | (45) | $ | (12) | $ | (16) | $ | (13) | $ | (4) | |||||||
| At December 31, 2024: | |||||||||||||||||
| Energy-related derivatives: | |||||||||||||||||
| Other regulatory assets, current | $ | (61) | $ | (23) | $ | (26) | $ | (11) | $ | (1) | |||||||
| Other regulatory assets, deferred | (5) | — | — | (5) | — | ||||||||||||
| Other regulatory liabilities, current | 8 | 4 | — | — | 4 | ||||||||||||
| Other regulatory liabilities, deferred | 8 | 3 | 4 | 1 | — | ||||||||||||
| Total energy-related derivative gains (losses) | $ | (50) | $ | (16) | $ | (22) | $ | (15) | $ | 3 |
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For the years ended December 31, 2025, 2024, and 2023, the pre-tax effects of cash flow and fair value hedge accounting on AOCI for the applicable Registrants were as follows:
| Gain (Loss) From Derivatives Recognized in OCI | 2025 | 2024 | 2023 | ||||||||
| (in millions) | |||||||||||
| Southern Company | |||||||||||
| Cash flow hedges: | |||||||||||
| Energy-related derivatives | $ | (8) | $ | (7) | $ | (81) | |||||
| Interest rate derivatives | 6 | 23 | (12) | ||||||||
| Foreign currency derivatives | 58 | (40) | 14 | ||||||||
| Fair value hedges(*): | |||||||||||
| Foreign currency derivatives | (22) | 16 | 21 | ||||||||
| Total | $ | 34 | $ | (8) | $ | (58) | |||||
| Georgia Power | |||||||||||
| Cash flow hedges: | |||||||||||
| Interest rate derivatives | $ | 4 | $ | 24 | $ | (2) | |||||
| Mississippi Power | |||||||||||
| Cash flow hedges: | |||||||||||
| Interest rate derivatives | $ | (1) | $ | 7 | $ | — | |||||
| Southern Power | |||||||||||
| Cash flow hedges: | |||||||||||
| Energy-related derivatives | $ | (1) | $ | (1) | $ | (18) | |||||
| Foreign currency derivatives | 58 | (40) | 14 | ||||||||
| Total | $ | 57 | $ | (41) | $ | (4) | |||||
| Southern Company Gas | |||||||||||
| Cash flow hedges: | |||||||||||
| Energy-related derivatives | $ | (6) | $ | (6) | $ | (63) | |||||
| Interest rate derivatives | 2 | (5) | — | ||||||||
| Total | $ | (4) | $ | (11) | $ | (63) |
(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.
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The pre-tax effects of cash flow and fair value hedge accounting on income for the years ended December 31, 2025, 2024, and 2023 were as follows:
| Gain (Loss) | ||||||||||||||
| Statements of Income Location | Derivative Category | 2025 | 2024 | 2023 | ||||||||||
| (in millions) | ||||||||||||||
| Southern Company | ||||||||||||||
| Fuel | Energy-related cash flow hedges | $ | 1 | $ | (6) | $ | (23) | |||||||
| Cost of natural gas | Energy-related cash flow hedges | (3) | (40) | (44) | ||||||||||
| Other operations and maintenance | Energy-related cash flow hedges | — | (2) | (2) | ||||||||||
| Interest expense, net of amounts capitalized | Interest rate cash flow hedges | (13) | (16) | (35) | ||||||||||
| Foreign currency cash flow hedges | (10) | (12) | (11) | |||||||||||
| Interest rate fair value hedges | 90 | (4) | 37 | |||||||||||
| Other income (expense), net | Foreign currency cash flow hedges | 68 | (33) | 19 | ||||||||||
| Foreign currency fair value hedges | 149 | 2 | 69 | |||||||||||
| Amount excluded from effectiveness testing recognized in earnings | 22 | (16) | (21) | |||||||||||
| Southern Power | ||||||||||||||
| Fuel | Energy-related cash flow hedges | $ | 1 | $ | (6) | $ | (23) | |||||||
| Interest expense, net of amounts capitalized | Foreign currency cash flow hedges | (10) | (12) | (11) | ||||||||||
| Other income (expense), net | Foreign currency cash flow hedges | 68 | (33) | 19 | ||||||||||
| Southern Company Gas | ||||||||||||||
| Cost of natural gas | Energy-related cash flow hedges | $ | (3) | $ | (40) | $ | (44) | |||||||
| Other operations and maintenance | Energy-related cash flow hedges | — | (2) | (2) | ||||||||||
| Interest expense, net of amounts capitalized | Interest rate cash flow hedges | (1) | (1) | (19) | ||||||||||
| Interest rate fair value hedges | 25 | (5) | 6 |
At December 31, 2025 and 2024, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:
| Carrying Amount of the Hedged Item | Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item | ||||||||||||||||
| Balance Sheet Location of Hedged Items | At December 31, 2025 | At December 31, 2024 | At December 31, 2025 | At December 31, 2024 | |||||||||||||
| (in millions) | (in millions) | ||||||||||||||||
| Southern Company | |||||||||||||||||
| Long-term debt | $ | (3,742) | $ | (2,936) | $ | 156 | $ | 242 | |||||||||
| Southern Company Gas | |||||||||||||||||
| Long-term debt | $ | (446) | $ | (422) | $ | 51 | $ | 75 | |||||||||
Pre-tax gains (losses) on energy-related derivatives not designated as hedging instruments were $(11) million, $94 million, and $59 million for the years ended December 31, 2025, 2024, and 2023, respectively, and reflected in cost of natural gas on the statements of income of Southern Company and Southern Company Gas.
Contingent Features
The Registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. At December 31, 2025, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
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For Southern Company, the fair value of foreign currency derivative liabilities and interest rate derivative liabilities with contingent features, and the maximum potential collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3, was $20 million at December 31, 2025. For Southern Power, there were no foreign currency derivative liabilities with contingent features or associated collateral requirements arising from the credit-risk-related contingent features at a rating below BBB- and/or Baa3 at December 31, 2025. For the traditional electric operating companies and Southern Power, energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial at December 31, 2025. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.
Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions, and they may be required to post collateral based on the value of the positions in these accounts and the associated margin requirements. At December 31, 2025, cash collateral posted in these accounts was immaterial for Alabama Power and Southern Power. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts, which are netted with energy-related derivatives recognized in the balance sheets.
The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants generally enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's, S&P, or Fitch or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.
Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.
The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.
15. ACQUISITIONS AND DISPOSITIONS
Alabama Power
On September 30, 2025, Alabama Power completed its acquisition of Tenaska Alabama Partners, L.P., which owned and operated the Lindsay Hill Generating Station, an approximately 879.7-MW combined cycle generation facility in Autauga County, Alabama. The transaction was accounted for as a business combination. The total purchase price was $635 million, of which $622 million was related to net assets recorded within property, plant, and equipment and the remainder was included in inventory, current receivables, and accounts payable on the balance sheet. The transaction was recorded as a business acquisition within the investing section of the statement of cash flows. 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. See Note 2 under "Alabama Power – Rate CNP New Plant" for additional information.
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. See Note 2 under "Mississippi Power – Plant Daniel" for additional information.
Southern Power
Southern Power's acquisition-related costs for the projects discussed under "Asset Acquisitions" and "Construction Projects" were not material for any of the years presented.
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Asset Acquisitions
During 2023, Southern Power acquired the Millers Branch and South Cheyenne projects, as discussed further under "Construction Projects" below, with an aggregate purchase price of $193 million. There were no asset acquisitions during 2024 and 2025.
Construction Projects
During 2024, Southern Power completed construction of and placed in service the 150-MW South Cheyenne solar facility. During 2025, Southern Power continued construction of the three phases of the 512-MW Millers Branch solar facility. At December 31, 2025, the total cost of construction incurred for the Millers Branch project was $694 million, which is primarily included in CWIP. The ultimate outcome of these matters cannot be determined at this time.
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Projected COD | PPA Contract Period | ||||||||||||
| Projects Under Construction at December 31, 2025 | |||||||||||||||||
| Millers Branch | |||||||||||||||||
| Phase I | Solar | 200 | Haskell County, TX | February 2026(*) | 20 years | ||||||||||||
| Phase II | Solar | 180 | Haskell County, TX | Second quarter 2026 | 15 years | ||||||||||||
| Phase III | Solar | 132 | Haskell County, TX | Fourth quarter 2026 | 15 years | ||||||||||||
| Projects Completed During 2024 | |||||||||||||||||
| South Cheyenne | Solar | 150 | Laramie County, WY | April 2024 | 20 years |
(*)Subsequent to December 31, 2025, Southern Power completed construction of the 200-MW first phase of the Millers Branch solar facility.
Wind Repowering Projects
During 2025, Southern Power continued the development project to repower the Kay wind facility and began development projects to repower the Grant Plains, Grant, Wake, and Bethel wind facilities. At December 31, 2025, the total cost of construction incurred related to the projects was $358 million and is included in CWIP. The repowered output of the facilities is contracted under new and amended PPAs. The ultimate outcome of these matters cannot be determined at this time.
| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Projected COD | ||||||||||
| Projects Under Construction at December 31, 2025 | ||||||||||||||
| Kay(*) | Wind | 200 | Kay County, OK | Third quarter 2026 | ||||||||||
| Grant Plains | Wind | 147 | Grant County, OK | Fourth quarter 2026 | ||||||||||
| Grant | Wind | 152 | Grant County, OK | Fourth quarter 2026 | ||||||||||
| Wake | Wind | 257 | Crosby & Floyd Counties, TX | Second quarter 2027 | ||||||||||
| Bethel | Wind | 276 | Castro County, TX | Third quarter 2027 |
(*)The facility has a total capacity of 299 MWs, of which 200 MWs is projected to be repowered and is contracted under a PPA.
Purchase of Renewable Facility Interests
On December 31, 2025, Southern Power completed the purchase of 100% of the noncontrolling Class A membership interests in SP Wind from the three financial investors for approximately $282 million. Since Southern Power retains control of SP Wind, the purchase was accounted for as an equity transaction, and Southern Power will continue to consolidate SP Wind in its financial statements. On the date of the transaction, noncontrolling interest was reduced by $242 million. The difference in the purchase price and the carrying value of the noncontrolling interest resulted in a $36 million non-cash decrease to Southern Power's common stockholders' equity, net of deferred tax remeasurement. See Note 7 under "Southern Power – Variable Interest Entities – SP Wind" for additional information.
16. SEGMENT AND RELATED INFORMATION
The Registrants adopted ASU 2023-07 and applied the guidance retrospectively effective for the fiscal year beginning January 1, 2024. See Note 1 under "Recently Adopted Accounting Standards" for additional information.
The CODM at Southern Company, the traditional electric operating companies, and Southern Company Gas is the chairman, president, and chief executive officer of such Registrant. Southern Power's CODM consists of the chairman and chief executive officer and the president. The CODMs assess segment performance using net income that is reflected on the Registrants'
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respective statements of income as net income attributable to the registrant or net income, as applicable. The CODMs use net income in the annual budget and forecasting process and consider budget versus actual results on a monthly basis when making decisions about the allocation of resources. Asset information by segment is not utilized by the CODMs for purposes of assessing performance or allocating resources.
Southern Company
Southern Company's reportable business segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the distribution of natural gas and other complementary products and services by Southern Company Gas. While the traditional electric operating companies represent three separate operating segments, they are vertically integrated utilities providing electric service to retail customers, as well as wholesale customers, in the Southeast and have been aggregated into one reportable segment. The "All Other" presentation includes the Southern Company parent entity, which does not allocate operating expenses to business segments, and operating segments below the quantitative threshold for separate disclosure. These operating segments include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications. Revenues from sales by Southern Power to the traditional electric operating companies were $437 million, $371 million, and $537 million in 2025, 2024, and 2023, respectively. All other inter-segment revenues were immaterial for all periods presented.
Southern Company's CODM utilizes segment net income, including variances to budget and forecasts, to assess performance and is not provided with segment expense information. To achieve the consolidated net income goal, Southern Company's CODM sets net income expectations for each operating segment, which is expected to monitor its expenses in order to achieve its assigned net income target. Therefore, Southern Company has no reportable significant segment expenses.
Financial data for business segments and products and services for the years ended December 31, 2025, 2024, and 2023 was as follows:
| Electric Utilities | |||||||||||||||||||||||||||||
| Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | Total Reportable Segments | All Other | Eliminations | Consolidated | |||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| 2025 | |||||||||||||||||||||||||||||
| Operating revenues | $ | 22,056 | $ | 2,198 | $ | (477) | $ | 23,777 | $ | 5,044 | $ | 28,821 | $ | 893 | $ | (161) | $ | 29,553 | |||||||||||
| Other segment items**(a)(b)(c)** | 11,157 | 1,187 | (477) | 11,867 | 3,172 | 15,039 | 872 | (154) | 15,757 | ||||||||||||||||||||
| Depreciation and amortization**(d)** | 3,882 | 843 | — | 4,725 | 708 | 5,433 | 68 | — | 5,501 | ||||||||||||||||||||
| Earnings from equity method investments | 6 | — | — | 6 | 127 | 133 | (21) | — | 112 | ||||||||||||||||||||
| Interest expense**(e)** | 1,341 | 104 | — | 1,445 | 377 | 1,822 | 1,416 | — | 3,238 | ||||||||||||||||||||
| Income taxes (benefit) | 1,100 | (61) | — | 1,039 | 182 | 1,221 | (393) | — | 828 | ||||||||||||||||||||
| Segment net income (loss)****(b)(c)(d)(e)(f) | $ | 4,582 | $ | 125 | $ | — | $ | 4,707 | $ | 732 | $ | 5,439 | $ | (1,091) | $ | (7) | $ | 4,341 | |||||||||||
| At December 31, 2025 | |||||||||||||||||||||||||||||
| Goodwill | $ | — | $ | 2 | $ | — | $ | 2 | $ | 5,015 | $ | 5,017 | $ | 144 | $ | — | $ | 5,161 | |||||||||||
| Total assets | 114,287 | 12,657 | (915) | 126,029 | 27,387 | 153,416 | 2,829 | (525) | 155,720 | ||||||||||||||||||||
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| Electric Utilities | |||||||||||||||||||||||||||||
| Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | Total Reportable Segments | All Other | Eliminations | Consolidated | |||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| 2024 | |||||||||||||||||||||||||||||
| Operating revenues | $ | 19,977 | $ | 2,014 | $ | (388) | $ | 21,603 | $ | 4,456 | $ | 26,059 | $ | 843 | $ | (178) | $ | 26,724 | |||||||||||
| Other segment items(a)(b)(g)(h) | 10,057 | 1,060 | (388) | 10,729 | 2,613 | 13,342 | 802 | (149) | 13,995 | ||||||||||||||||||||
| Depreciation and amortization(d) | 3,512 | 522 | — | 4,034 | 650 | 4,684 | 71 | — | 4,755 | ||||||||||||||||||||
| Earnings from equity method investments | 8 | — | — | 8 | 146 | 154 | (17) | 2 | 139 | ||||||||||||||||||||
| Interest expense | 1,255 | 117 | — | 1,372 | 341 | 1,713 | 1,030 | — | 2,743 | ||||||||||||||||||||
| Income taxes (benefit) | 1,016 | (13) | — | 1,003 | 258 | 1,261 | (292) | — | 969 | ||||||||||||||||||||
| Segment net income (loss)(b)(d)(f)(g)(h) | $ | 4,145 | $ | 328 | $ | — | $ | 4,473 | $ | 740 | $ | 5,213 | $ | (785) | $ | (27) | $ | 4,401 | |||||||||||
| At December 31, 2024 | |||||||||||||||||||||||||||||
| Goodwill | $ | — | $ | 2 | $ | — | $ | 2 | $ | 5,015 | $ | 5,017 | $ | 144 | $ | — | $ | 5,161 | |||||||||||
| Total assets | 105,577 | 12,653 | (1,025) | 117,205 | 26,177 | 143,382 | 2,371 | (573) | 145,180 | ||||||||||||||||||||
| 2023 | |||||||||||||||||||||||||||||
| Operating revenues | $ | 18,358 | $ | 2,189 | $ | (549) | $ | 19,998 | $ | 4,702 | $ | 24,700 | $ | 718 | $ | (165) | $ | 25,253 | |||||||||||
| Other segment items(a)(b)(c)(i) | 9,643 | 1,187 | (549) | 10,281 | 3,124 | 13,405 | 699 | (150) | 13,954 | ||||||||||||||||||||
| Depreciation and amortization | 3,361 | 504 | — | 3,865 | 582 | 4,447 | 78 | — | 4,525 | ||||||||||||||||||||
| Earnings from equity method investments | (1) | — | — | (1) | 140 | 139 | 5 | — | 144 | ||||||||||||||||||||
| Interest expense | 1,145 | 129 | — | 1,274 | 310 | 1,584 | 879 | (17) | 2,446 | ||||||||||||||||||||
| Income taxes (benefit) | 571 | 12 | — | 583 | 211 | 794 | (298) | — | 496 | ||||||||||||||||||||
| Segment net income (loss)(b)(c)(f)(i) | $ | 3,637 | $ | 357 | $ | — | $ | 3,994 | $ | 615 | $ | 4,609 | $ | (635) | $ | 2 | $ | 3,976 | |||||||||||
| At December 31, 2023 | |||||||||||||||||||||||||||||
| Goodwill | $ | — | $ | 2 | $ | — | $ | 2 | $ | 5,015 | $ | 5,017 | $ | 144 | $ | — | $ | 5,161 | |||||||||||
| Total assets | 100,429 | 12,761 | (545) | 112,645 | 25,083 | 137,728 | 2,446 | (843) | 139,331 |
(a)Primarily consists of fuel, purchased power, cost of natural gas, cost of other sales, other operations and maintenance (including credits to income for estimated probable losses, regulatory disallowances, losses (gains) on asset dispositions, and impairment charges), taxes other than income taxes, AFUDC equity, non-service cost-related retirement benefits income, and net income (loss) attributable to noncontrolling interests.
(b)For the traditional electric operating companies, includes pre-tax credits to income at Georgia Power for the estimated probable loss associated with the construction and completion of Plant Vogtle Units 3 and 4 of $60 million ($45 million after tax) in 2025, $21 million ($16 million after tax) in 2024, and $68 million ($50 million after tax) in 2023. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
(c)For Southern Company Gas, includes pre-tax charges associated with the disallowance of certain capital investments at Nicor Gas totaling approximately $63 million ($47 million after tax) in 2025 and $96 million ($72 million after tax) in 2023. See Note 2 under "Southern Company Gas" for additional information.
(d)For Southern Power, includes accelerated depreciation related to the repowering of multiple wind facilities of $307 million ($221 million after tax, net of noncontrolling interest impacts) in 2025 and $9 million ($7 million after tax, net of noncontrolling interest impacts) in 2024. See Note 15 under "Southern Power –Wind Repowering Projects" for additional information.
(e)For All Other, includes a pre-tax loss of $252 million ($189 million after tax) associated with the extinguishment of debt at the parent company. See Note 8 under "Convertible Senior Notes" for additional information.
(f)Attributable to Southern Company.
(g)For the traditional electric operating companies, includes a pre-tax impairment loss at Alabama Power of $36 million ($27 million after tax) related to Alabama Power discontinuing the development of a multi-use commercial facility. See Note 1 under "Impairment of Long-Lived Assets" for additional information.
(h)For the traditional electric operating companies, includes a pre-tax gain at Georgia power of approximately $114 million ($84 million after tax) related to the sale of transmission line assets under the integrated transmission system agreement. See Note 2 under "Georgia Power – Transmission Asset Sales" for additional information.
(i)For Southern Power, includes an $18 million pre-tax loss recovery ($9 million after tax and partnership allocations) related to an arbitration award and a $16 million pre-tax gain ($12 million after tax) on the sale of spare parts.
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Products and Services
| Electric Utilities' Revenues | |||||||||||||||||||||||
| Year | Retail | Wholesale | Other | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| 2025 | $ | 19,331 | $ | 2,940 | $ | 1,506 | $ | 23,777 | |||||||||||||||
| 2024 | 17,790 | 2,431 | 1,382 | 21,603 | |||||||||||||||||||
| 2023 | 16,343 | 2,467 | 1,188 | 19,998 |
| Southern Company Gas' Revenues | ||||||||||||||||||||||||||||||||
| Year | Gas Distribution Operations | Gas Marketing Services | Other | Total | ||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||
| 2025 | $ | 4,428 | $ | 582 | $ | 34 | $ | 5,044 | ||||||||||||||||||||||||
| 2024 | 3,899 | 516 | 41 | 4,456 | ||||||||||||||||||||||||||||
| 2023 | 4,090 | 548 | 64 | 4,702 |
Traditional Electric Operating Companies
Each of the traditional electric operating companies' single reportable business segment is the sale of electricity. Revenues from products and services of the traditional electric operating companies are segregated into retail, wholesale, and other as reflected on their statements of income.
Alabama Power and Georgia Power have identified utility operations and maintenance expenses as significant segment expenses provided to their CODMs. Utility operations and maintenance expenses is calculated as other operations and maintenance, as reflected on the statements of income, less expenses from unregulated products and services, losses (gains) on asset dispositions, impairment charges, amortization of cloud software, and, for Georgia Power, charges (credits) for estimated loss on Plant Vogtle Units 3 and 4. Alabama Power's utility operations and maintenance expenses are disaggregated into expenses related to Rate RSE and Rate CNP Compliance. See Note 2 under "Alabama Power" for additional information.
During the third and fourth quarters of 2025, Mississippi Power updated the information provided to its CODM. As a result, Mississippi Power has identified certain operational and environmental compliance expenses as significant segment expenses and has recast prior period information to conform to the current period presentation.
Financial data for significant segment expenses and other segment information for the years ended December 31, 2025, 2024, and 2023 was as follows:
| 2025 | 2024 | 2023 | |||||||||
| (in millions) | |||||||||||
| Alabama Power | |||||||||||
| Operating revenues | $ | 8,235 | $ | 7,554 | $ | 7,050 | |||||
| Utility operations and maintenance | |||||||||||
| Rate RSE expenses | 1,636 | 1,480 | 1,421 | ||||||||
| Rate CNP Compliance expenses | 292 | 279 | 254 | ||||||||
| Total utility operations and maintenance | 1,928 | 1,759 | 1,675 | ||||||||
| Other segment items(a)(b) | 2,391 | 2,125 | 2,098 | ||||||||
| Depreciation and amortization | 1,510 | 1,459 | 1,401 | ||||||||
| Interest expense | 465 | 448 | 425 | ||||||||
| Income taxes | 425 | 360 | 81 | ||||||||
| Segment net income(b) | $ | 1,516 | $ | 1,403 | $ | 1,370 | |||||
| Capital expenditures | $ | 2,508 | $ | 2,114 | $ | 2,159 | |||||
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| 2025 | 2024 | 2023 | |||||||||
| (in millions) | |||||||||||
| Georgia Power | |||||||||||
| Operating revenues | $ | 12,631 | $ | 11,331 | $ | 10,118 | |||||
| Utility operations and maintenance | 2,339 | 2,210 | 1,901 | ||||||||
| Other segment items(a)(c)(d) | 3,972 | 3,476 | 3,382 | ||||||||
| Depreciation and amortization | 2,074 | 1,774 | 1,681 | ||||||||
| Interest expense | 793 | 725 | 626 | ||||||||
| Income taxes | 602 | 603 | 448 | ||||||||
| Segment net income(c)(d) | $ | 2,851 | $ | 2,543 | $ | 2,080 | |||||
| Capital expenditures | $ | 8,140 | $ | 5,355 | $ | 5,394 | |||||
| Mississippi Power | |||||||||||
| Operating revenues | $ | 1,695 | $ | 1,463 | $ | 1,474 | |||||
| Operational expenses(e) | 264 | 254 | 265 | ||||||||
| Environmental compliance expenses(f) | 16 | 12 | 10 | ||||||||
| Other segment items(a) | 845 | 681 | 714 | ||||||||
| Depreciation and amortization | 211 | 193 | 190 | ||||||||
| Interest expense | 79 | 77 | 71 | ||||||||
| Income taxes | 65 | 47 | 36 | ||||||||
| Segment net income | $ | 215 | $ | 199 | $ | 188 | |||||
| Capital expenditures | $ | 320 | $ | 357 | $ | 342 |
(a)Primarily consists of fuel, purchased power, expenses from unregulated products and services, losses (gains) on asset dispositions, amortization of cloud software, taxes other than income taxes, AFUDC equity, and non-service cost-related retirement benefits income. For Alabama Power, includes impairment charges. For Georgia Power, includes credits for estimated loss on Plant Vogtle Units 3 and 4. For Mississippi Power, includes employee benefit expenses. Also includes earnings from equity method investments, which were immaterial for all periods presented.
(b)For 2024, includes a pre-tax impairment loss of $36 million ($27 million after tax) related to Alabama Power discontinuing the development of a multi-use commercial facility. See Note 1 under "Impairment of Long-Lived Assets" for additional information.
(c)Includes pre-tax credits to income for the estimated probable loss associated with the construction and completion of Plant Vogtle Units 3 and 4 of $60 million ($45 million after tax) in 2025, $21 million ($16 million after tax) in 2024, and $68 million ($50 million after tax) in 2023. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
(d)For 2024, includes a pre-tax gain of approximately $114 million ($84 million after tax) related to the sale of transmission line assets under the integrated transmission system agreement. See Note 2 under "Georgia Power – Transmission Asset Sales" for additional information.
(e)Consists of certain operations and maintenance expenses related to PEP and the MRA tariff, including labor costs, materials, contract services, and other normal operational costs. See Note 2 under "Mississippi Power" for additional information regarding PEP and the MRA tariff.
(f)Consists of environmental compliance expenses related to ECO Plan and the MRA tariff. See Note 2 under "Mississippi Power" for additional information regarding ECO Plan and the MRA tariff.
Southern Power
Southern Power's single reportable business segment is the sale of electricity in the competitive wholesale market. Substantially all of Southern Power's revenues from products and services are reflected as wholesale on its consolidated statements of income. Southern Power's CODM utilizes segment expense information in the form of variances to budget to assess performance; therefore, Southern Power has no reportable significant segment expenses.
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Financial data for segment information for the years ended December 31, 2025, 2024, and 2023 was as follows:
| 2025 | 2024 | 2023 | |||||||||
| (in millions) | |||||||||||
| Operating revenues | $ | 2,198 | $ | 2,014 | $ | 2,189 | |||||
| Other segment items(a)(b) | 1,187 | 1,060 | 1,187 | ||||||||
| Depreciation and amortization(c) | 843 | 522 | 504 | ||||||||
| Interest expense | 104 | 117 | 129 | ||||||||
| Income taxes (benefit) | (61) | (13) | 12 | ||||||||
| Segment net income(b)(c)(d) | $ | 125 | $ | 328 | $ | 357 |
(a)Primarily consists of fuel, purchased power, other operations and maintenance, taxes other than income taxes, losses (gains) on asset dispositions, and net income (loss) attributable to noncontrolling interests.
(b)For 2023, includes an $18 million pre-tax loss recovery ($9 million after tax and partnership allocations) related to an arbitration award and a $16 million pre-tax gain ($12 million after tax) on the sale of spare parts.
(c)Includes accelerated depreciation of $307 million ($221 million after tax, net of noncontrolling interest impacts) in 2025 and $9 million ($7 million after tax, net of noncontrolling interest impacts) in 2024 related to the repowering of multiple wind facilities. See Note 15 under "Southern Power –Wind Repowering Projects" for additional information.
(d)Southern Power had no earnings from equity method investments for any period presented.
Southern Company Gas
Southern Company Gas manages its business through three reportable segments – gas distribution operations, gas pipeline investments, and gas marketing services. The non-reportable segments are combined and presented as "All Other."
The gas distribution operations segment is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states.
The gas pipeline investments segment consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. See Notes 5 and 7 for additional information.
The gas marketing services segment provides natural gas marketing to end-use customers primarily in Georgia through SouthStar.
The "All Other" presentation includes operating segments and subsidiaries that fall below the quantitative threshold for separate disclosure.
Southern Company Gas' CODM utilizes segment expense information in the form of variances to budget to assess performance; therefore, Southern Company Gas has no reportable significant segment expenses.
Financial data for business segments for the years ended December 31, 2025, 2024, and 2023 was as follows:
| Gas Distribution Operations | Gas Pipeline Investments | Gas Marketing Services | Total Reportable Segments | All Other | Eliminations | Consolidated | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| 2025 | |||||||||||||||||||||||
| Operating revenues | $ | 4,428 | $ | 32 | $ | 582 | $ | 5,042 | $ | 12 | $ | (10) | $ | 5,044 | |||||||||
| Other segment items**(a)(b)** | 2,721 | 5 | 444 | 3,170 | 12 | (10) | 3,172 | ||||||||||||||||
| Depreciation and amortization | 687 | 5 | 14 | 706 | 2 | — | 708 | ||||||||||||||||
| Earnings from equity method investments | — | 127 | — | 127 | — | — | 127 | ||||||||||||||||
| Interest expense | 342 | 36 | 3 | 381 | (4) | — | 377 | ||||||||||||||||
| Income taxes | 109 | 28 | 34 | 171 | 11 | — | 182 | ||||||||||||||||
| Segment net income (loss)****(b) | $ | 569 | $ | 85 | $ | 87 | $ | 741 | $ | (9) | $ | — | $ | 732 | |||||||||
| Total assets at December 31, 2025 | $ | 25,391 | $ | 1,475 | $ | 1,749 | $ | 28,615 | $ | 10,643 | $ | (11,871) | $ | 27,387 | |||||||||
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| Gas Distribution Operations | Gas Pipeline Investments | Gas Marketing Services | Total Reportable Segments | All Other | Eliminations | Consolidated | |||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| 2024 | |||||||||||||||||||||||
| Operating revenues | $ | 3,899 | $ | 32 | $ | 516 | $ | 4,447 | $ | 23 | $ | (14) | $ | 4,456 | |||||||||
| Other segment items(a) | 2,236 | 6 | 356 | 2,598 | 29 | (14) | 2,613 | ||||||||||||||||
| Depreciation and amortization | 630 | 5 | 14 | 649 | 1 | — | 650 | ||||||||||||||||
| Earnings from equity method investments | — | 146 | — | 146 | — | — | 146 | ||||||||||||||||
| Interest expense | 311 | 35 | 3 | 349 | (8) | — | 341 | ||||||||||||||||
| Income taxes | 172 | 31 | 41 | 244 | 14 | — | 258 | ||||||||||||||||
| Segment net income (loss) | $ | 550 | $ | 101 | $ | 102 | $ | 753 | $ | (13) | $ | — | $ | 740 | |||||||||
| Total assets at December 31, 2024 | $ | 24,067 | $ | 1,573 | $ | 1,696 | $ | 27,336 | $ | 10,047 | $ | (11,206) | $ | 26,177 | |||||||||
| 2023 | |||||||||||||||||||||||
| Operating revenues | $ | 4,105 | $ | 32 | $ | 548 | $ | 4,685 | $ | 36 | $ | (19) | $ | 4,702 | |||||||||
| Other segment items(a)(b) | 2,702 | 5 | 402 | 3,109 | 34 | (19) | 3,124 | ||||||||||||||||
| Depreciation and amortization | 561 | 5 | 15 | 581 | 1 | — | 582 | ||||||||||||||||
| Earnings from equity method investments | — | 140 | — | 140 | — | — | 140 | ||||||||||||||||
| Interest expense | 275 | 32 | 3 | 310 | — | — | 310 | ||||||||||||||||
| Income taxes | 126 | 32 | 37 | 195 | 16 | — | 211 | ||||||||||||||||
| Segment net income (loss)(b) | $ | 441 | $ | 98 | $ | 91 | $ | 630 | $ | (15) | $ | — | $ | 615 | |||||||||
| Total assets at December 31, 2023 | $ | 22,906 | $ | 1,534 | $ | 1,615 | $ | 26,055 | $ | 9,675 | $ | (10,647) | $ | 25,083 |
(a)Primarily consists of cost of natural gas, other operations and maintenance, taxes other than income taxes, estimated loss on regulatory disallowance, AFUDC equity, and non-service cost-related retirement benefits income.
(b)For gas distribution operations, includes pre-tax charges associated with the disallowance of certain capital investments at Nicor Gas totaling approximately $63 million ($47 million after tax) in 2025 and $96 million ($72 million after tax) in 2023. See Note 2 under "Southern Company Gas" for additional information.
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