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, 2021 and 2020, 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, 2021, and the related notes (collectively referred to as the "financial statements"). We also have audited Southern Company's internal control over financial reporting as of December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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.
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Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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"), which represent approximately 88% of Southern Company's consolidated operating revenues for the year ended December 31, 2021 and 86% of its consolidated total assets at December 31, 2021, 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 impacts multiple financial statement line items and disclosures, including, but not limited to, property, plant, and equipment; other regulatory assets; other regulatory liabilities; other cost of removal obligations; deferred charges and credits related to income taxes; under and over recovered regulatory clause revenues; operating revenues; operations and maintenance expenses; and depreciation and amortization.
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 by 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 that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures (e.g., asset retirement costs, property damage reserves, and remaining net book values of retired assets) and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. 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. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions 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 costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
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We read relevant regulatory orders issued by the Commissions for the regulated utility subsidiaries, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.
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For regulatory matters in process, we inspected filings with the Commissions by Southern Company's regulated utility subsidiaries and other interested parties that may impact the regulated utility subsidiaries' future rates for any evidence that might contradict management's assertions.
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We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
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We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable 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.
Disclosure of Uncertainties – Plant Vogtle Units 3 and 4 Construction – Refer to Note 2 (Regulatory Matters – Georgia Power – Nuclear Construction) to the financial statements
Critical Audit Matter Description
As discussed in Note 2 to the financial statements, the ultimate recovery of Georgia Power Company's (Georgia Power) investment in the construction of Plant Vogtle Units 3 and 4 is subject to multiple uncertainties. Such uncertainties include the potential impact of future decisions by Georgia Power's regulators (particularly the Georgia Public Service Commission) and potential actions by the co-owners of the Vogtle project. In addition, Georgia Power's ability to meet its cost and schedule forecasts could impact its ability to fully recover its investment in the project. While the project is not subject to a cost cap, Georgia Power's cost and schedule forecasts are subject to numerous uncertainties which could impact cost recovery, including ongoing or future challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; and procurement and related installation. New challenges may arise, particularly as Units 3 and 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). The ongoing and potential future challenges described above may change the projected schedule and estimated cost.
In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. The ultimate recovery of Georgia Power's investment in Plant Vogtle Units 3 and 4 is subject to the outcome of future assessments by management as well as Georgia Public Service Commission decisions in future regulatory proceedings. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income of $1.692 billion in 2021.
In addition, management has disclosed the status, risks, and uncertainties associated with Plant Vogtle Units 3 and 4, including (1) the status of construction; (2) the status of regulatory proceedings; (3) the status of legal actions or issues involving the co-owners of the project; and (4) other matters which could impact the ultimate recoverability of Georgia Power's investment in the project. We identified as a critical audit matter the evaluation of Georgia Power's identification and disclosure of events and uncertainties that could impact the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4. This critical audit matter involved significant audit effort requiring specialized industry and construction expertise, extensive knowledge of rate regulation, and difficult and subjective judgments.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to Georgia Power's identification and disclosure of events and uncertainties that could impact the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4 included the following, among others:
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We tested the effectiveness of internal controls over the on-going evaluation, monitoring, and disclosure of matters related to the construction and ultimate cost recovery of Plant Vogtle Units 3 and 4.
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We involved construction specialists to assist in our evaluation of the reasonableness of the projected in-service dates for Plant Vogtle Units 3 and 4 and Georgia Power's processes for on-going evaluation and monitoring of the construction schedule and to assess the disclosures of the uncertainties impacting the ultimate cost recovery of its investment in the construction of these units.
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We attended meetings with Georgia Power and Southern Company officials, project managers (including contractors), independent regulatory monitors, and co-owners of the project to evaluate and monitor construction status and identify cost and schedule challenges.
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We read reports of external independent monitors employed by the Georgia Public Service Commission to monitor the status of construction at Plant Vogtle Units 3 and 4 to evaluate the completeness of Georgia Power's disclosure of the uncertainties impacting the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4.
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We inquired of Georgia Power and Southern Company officials and project managers regarding the status of construction, the construction schedule, and cost forecasts to assess the financial statement disclosures with respect to project status and potential risks and uncertainties to the achievement of such forecasts.
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We inspected regulatory filings and transcripts of Georgia Public Service Commission hearings regarding the construction and cost recovery of Plant Vogtle Units 3 and 4 to identify potential challenges to the recovery of Georgia Power's construction costs and to evaluate the disclosures with respect to such uncertainties.
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We inquired of Georgia Power and Southern Company management and internal and external legal counsel regarding any potential legal actions or issues arising from project construction or issues involving the co-owners of the project.
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We monitored the status of reviews and inspections by the Nuclear Regulatory Commission to identify potential impediments to the licensing and commercial operation of the project that could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4.
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We compared the financial statement disclosures relating to this matter to the information gathered through the conduct of all our procedures to evaluate whether there were omissions relating to significant facts or uncertainties regarding the status of construction or other factors which could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4.
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We obtained representation from management regarding disclosure of all matters related to the cost and/or status of the construction of Plant Vogtle Units 3 and 4, including matters related to a co-owner or regulatory development, that could impact the recovery of the related costs.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 16, 2022
We have served as Southern Company's auditor since 2002.
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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020, and 2019
Southern Company and Subsidiary Companies 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Retail electric revenues | $ | 14,852 | $ | 13,643 | $ | 14,084 | |||||||||||
| Wholesale electric revenues | 2,455 | 1,945 | 2,152 | ||||||||||||||
| Other electric revenues | 718 | 672 | 636 | ||||||||||||||
| Natural gas revenues | 4,380 | 3,434 | 3,792 | ||||||||||||||
| Other revenues | 708 | 681 | 755 | ||||||||||||||
| Total operating revenues | 23,113 | 20,375 | 21,419 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 4,010 | 2,967 | 3,622 | ||||||||||||||
| Purchased power | 978 | 799 | 816 | ||||||||||||||
| Cost of natural gas | 1,619 | 972 | 1,319 | ||||||||||||||
| Cost of other sales | 357 | 327 | 435 | ||||||||||||||
| Other operations and maintenance | 6,088 | 5,413 | 5,624 | ||||||||||||||
| Depreciation and amortization | 3,565 | 3,518 | 3,038 | ||||||||||||||
| Taxes other than income taxes | 1,290 | 1,234 | 1,230 | ||||||||||||||
| Estimated loss on Plant Vogtle Units 3 and 4 | 1,692 | 325 | — | ||||||||||||||
| Impairment charges | 2 | — | 168 | ||||||||||||||
| Gain on dispositions, net | (186) | (65) | (2,569) | ||||||||||||||
| Total operating expenses | 19,415 | 15,490 | 13,683 | ||||||||||||||
| Operating Income | 3,698 | 4,885 | 7,736 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Allowance for equity funds used during construction | 190 | 149 | 128 | ||||||||||||||
| Earnings from equity method investments | 76 | 153 | 162 | ||||||||||||||
| Interest expense, net of amounts capitalized | (1,837) | (1,821) | (1,736) | ||||||||||||||
| Impairment of leveraged leases | (7) | (206) | — | ||||||||||||||
| Other income (expense), net | 456 | 336 | 252 | ||||||||||||||
| Total other income and (expense) | (1,122) | (1,389) | (1,194) | ||||||||||||||
| Earnings Before Income Taxes | 2,576 | 3,496 | 6,542 | ||||||||||||||
| Income taxes | 267 | 393 | 1,798 | ||||||||||||||
| Consolidated Net Income | 2,309 | 3,103 | 4,744 | ||||||||||||||
| Dividends on preferred stock of subsidiaries | 15 | 15 | 15 | ||||||||||||||
| Net loss attributable to noncontrolling interests | (99) | (31) | (10) | ||||||||||||||
| Consolidated Net Income Attributable to Southern Company | $ | 2,393 | $ | 3,119 | $ | 4,739 | |||||||||||
| Common Stock Data: | |||||||||||||||||
| Earnings per share — | |||||||||||||||||
| Basic | $ | 2.26 | $ | 2.95 | $ | 4.53 | |||||||||||
| Diluted | 2.24 | 2.93 | 4.50 | ||||||||||||||
| Average number of shares of common stock outstanding — (in millions) | |||||||||||||||||
| Basic | 1,061 | 1,058 | 1,046 | ||||||||||||||
| Diluted | 1,068 | 1,065 | 1,054 |
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, 2021, 2020, and 2019
Southern Company and Subsidiary Companies 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Consolidated Net Income | $ | 2,309 | $ | 3,103 | $ | 4,744 | |||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Changes in fair value, net of tax of $(16), $3, and $(39), respectively | (49) | 10 | (115) | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $31, $(13), and $19, respectively | 96 | (40) | 57 | ||||||||||||||
| Pension and other postretirement benefit plans: | |||||||||||||||||
| Benefit plan net gain (loss), net of tax of $37, $(17), and $(31), respectively | 98 | (55) | (64) | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $5, $3, and $1, respectively | 13 | 10 | 4 | ||||||||||||||
| Total other comprehensive income (loss) | 158 | (75) | (118) | ||||||||||||||
| Dividends on preferred stock of subsidiaries | 15 | 15 | 15 | ||||||||||||||
| Comprehensive loss attributable to noncontrolling interests | (99) | (31) | (10) | ||||||||||||||
| Consolidated Comprehensive Income Attributable to Southern Company | $ | 2,551 | $ | 3,044 | $ | 4,621 |
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, 2021, 2020, and 2019
Southern Company and Subsidiary Companies 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Consolidated net income | $ | 2,309 | $ | 3,103 | $ | 4,744 | |||||||||||
| Adjustments to reconcile consolidated net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 3,973 | 3,905 | 3,331 | ||||||||||||||
| Deferred income taxes | (49) | (241) | 611 | ||||||||||||||
| Utilization of federal investment tax credits | 288 | 341 | 757 | ||||||||||||||
| Allowance for equity funds used during construction | (190) | (149) | (128) | ||||||||||||||
| Pension, postretirement, and other employee benefits | (305) | (259) | (204) | ||||||||||||||
| Pension and postretirement funding | — | (2) | (1,136) | ||||||||||||||
| Settlement of asset retirement obligations | (456) | (442) | (328) | ||||||||||||||
| Storm damage accruals | 288 | 325 | 168 | ||||||||||||||
| Stock based compensation expense | 144 | 113 | 107 | ||||||||||||||
| Estimated loss on Plant Vogtle Units 3 and 4 | 1,692 | 325 | — | ||||||||||||||
| Impairment charges | 91 | 206 | 168 | ||||||||||||||
| Gain on dispositions, net | (176) | (66) | (2,588) | ||||||||||||||
| Retail fuel cost under recovery – long-term | (536) | — | — | ||||||||||||||
| Natural gas cost under recovery – long-term | (207) | — | — | ||||||||||||||
| Other, net | 86 | (74) | 115 | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | (81) | (222) | 630 | ||||||||||||||
| -Materials and supplies | (130) | (157) | (17) | ||||||||||||||
| -Natural gas cost under recovery | (266) | — | — | ||||||||||||||
| -Other current assets | (170) | (161) | 12 | ||||||||||||||
| -Accounts payable | (8) | (27) | (693) | ||||||||||||||
| -Accrued taxes | (54) | 242 | 117 | ||||||||||||||
| -Retail fuel cost over recovery | (155) | 96 | 62 | ||||||||||||||
| -Customer refunds | 130 | (236) | 126 | ||||||||||||||
| -Other current liabilities | (49) | 76 | (73) | ||||||||||||||
| Net cash provided from operating activities | 6,169 | 6,696 | 5,781 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Business acquisitions, net of cash acquired | (345) | (81) | (50) | ||||||||||||||
| Property additions | (7,240) | (7,441) | (7,555) | ||||||||||||||
| Nuclear decommissioning trust fund purchases | (1,598) | (877) | (888) | ||||||||||||||
| Nuclear decommissioning trust fund sales | 1,593 | 871 | 882 | ||||||||||||||
| Proceeds from dispositions | 917 | 1,049 | 5,122 | ||||||||||||||
| Cost of removal, net of salvage | (442) | (361) | (393) | ||||||||||||||
| Change in construction payables, net | (124) | 37 | (169) | ||||||||||||||
| Payments pursuant to LTSAs | (188) | (211) | (234) | ||||||||||||||
| Other investing activities | 74 | (16) | (107) | ||||||||||||||
| Net cash used for investing activities | (7,353) | (7,030) | (3,392) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Increase (decrease) in notes payable, net | 530 | (1,096) | 640 | ||||||||||||||
| Proceeds — | |||||||||||||||||
| Long-term debt | 8,262 | 8,047 | 5,220 | ||||||||||||||
| Short-term borrowings | 325 | 615 | 350 | ||||||||||||||
| Common stock | 73 | 74 | 844 | ||||||||||||||
| Redemptions and repurchases — | |||||||||||||||||
| Long-term debt | (4,327) | (4,458) | (4,347) | ||||||||||||||
| Short-term borrowings | (25) | (840) | (1,850) | ||||||||||||||
| Capital contributions from noncontrolling interests | 501 | 363 | 196 | ||||||||||||||
| Distributions to noncontrolling interests | (351) | (271) | (256) | ||||||||||||||
| Payment of common stock dividends | (2,777) | (2,685) | (2,570) | ||||||||||||||
| Other financing activities | (266) | (325) | (157) | ||||||||||||||
| Net cash provided from (used for) financing activities | 1,945 | (576) | (1,930) | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 761 | (910) | 459 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 1,068 | 1,978 | 1,519 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 1,829 | $ | 1,068 | $ | 1,978 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid during the period for — | |||||||||||||||||
| Interest (net of $92, $81, and $74 capitalized, respectively) | $ | 1,718 | $ | 1,683 | $ | 1,651 | |||||||||||
| Income taxes, net | 93 | 64 | 276 | ||||||||||||||
| Noncash transactions — | |||||||||||||||||
| Accrued property additions at year-end | 866 | 989 | 932 | ||||||||||||||
| Contributions from noncontrolling interests | 89 | 12 | 80 | ||||||||||||||
| Contributions of wind turbine equipment | 82 | 17 | 26 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Company and Subsidiary Companies 2021 Annual Report
| Assets | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 1,798 | $ | 1,065 | |||||||
| Receivables — | |||||||||||
| Customer accounts | 1,806 | 1,753 | |||||||||
| Energy marketing | — | 516 | |||||||||
| Unbilled revenues | 711 | 672 | |||||||||
| Other accounts and notes | 523 | 512 | |||||||||
| Accumulated provision for uncollectible accounts | (78) | (118) | |||||||||
| Materials and supplies | 1,543 | 1,478 | |||||||||
| Fossil fuel for generation | 450 | 550 | |||||||||
| Natural gas for sale | 362 | 460 | |||||||||
| Prepaid expenses | 330 | 276 | |||||||||
| Assets from risk management activities, net of collateral | 151 | 147 | |||||||||
| Regulatory assets – asset retirement obligations | 219 | 214 | |||||||||
| Natural gas cost under recovery | 266 | — | |||||||||
| Other regulatory assets | 653 | 810 | |||||||||
| Other current assets | 231 | 282 | |||||||||
| Total current assets | 8,965 | 8,617 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 115,592 | 110,516 | |||||||||
| Less: Accumulated depreciation | 34,079 | 32,397 | |||||||||
| Plant in service, net of depreciation | 81,513 | 78,119 | |||||||||
| Nuclear fuel, at amortized cost | 824 | 818 | |||||||||
| Construction work in progress | 8,771 | 8,697 | |||||||||
| Total property, plant, and equipment | 91,108 | 87,634 | |||||||||
| Other Property and Investments: | |||||||||||
| Goodwill | 5,280 | 5,280 | |||||||||
| Nuclear decommissioning trusts, at fair value | 2,542 | 2,303 | |||||||||
| Equity investments in unconsolidated subsidiaries | 1,282 | 1,362 | |||||||||
| Other intangible assets, net of amortization of $307 and $328, respectively | 445 | 487 | |||||||||
| Leveraged leases | — | 556 | |||||||||
| Miscellaneous property and investments | 653 | 398 | |||||||||
| Total other property and investments | 10,202 | 10,386 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Operating lease right-of-use assets, net of amortization | 1,701 | 1,802 | |||||||||
| Deferred charges related to income taxes | 824 | 796 | |||||||||
| Prepaid pension costs | 1,657 | — | |||||||||
| Unamortized loss on reacquired debt | 258 | 280 | |||||||||
| Regulatory assets – asset retirement obligations, deferred | 5,466 | 4,934 | |||||||||
| Other regulatory assets, deferred | 5,577 | 7,198 | |||||||||
| Other deferred charges and assets | 1,776 | 1,288 | |||||||||
| Total deferred charges and other assets | 17,259 | 16,298 | |||||||||
| Total Assets | $ | 127,534 | $ | 122,935 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Company and Subsidiary Companies 2021 Annual Report
| Liabilities and Stockholders' Equity | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 2,157 | $ | 3,507 | |||||||
| Notes payable | 1,440 | 609 | |||||||||
| Energy marketing trade payables | — | 494 | |||||||||
| Accounts payable | 2,169 | 2,312 | |||||||||
| Customer deposits | 479 | 487 | |||||||||
| Accrued taxes — | |||||||||||
| Accrued income taxes | 50 | 130 | |||||||||
| Other accrued taxes | 641 | 699 | |||||||||
| Accrued interest | 533 | 513 | |||||||||
| Accrued compensation | 1,070 | 1,025 | |||||||||
| Asset retirement obligations | 697 | 585 | |||||||||
| Operating lease obligations | 250 | 241 | |||||||||
| Other regulatory liabilities | 563 | 509 | |||||||||
| Other current liabilities | 872 | 968 | |||||||||
| Total current liabilities | 10,921 | 12,079 | |||||||||
| Long-Term Debt | 50,120 | 45,073 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 8,862 | 8,175 | |||||||||
| Deferred credits related to income taxes | 5,401 | 5,767 | |||||||||
| Accumulated deferred ITCs | 2,216 | 2,235 | |||||||||
| Employee benefit obligations | 1,550 | 2,213 | |||||||||
| Operating lease obligations, deferred | 1,503 | 1,611 | |||||||||
| Asset retirement obligations, deferred | 10,990 | 10,099 | |||||||||
| Other cost of removal obligations | 2,103 | 2,211 | |||||||||
| Other regulatory liabilities, deferred | 485 | 251 | |||||||||
| Other deferred credits and liabilities | 816 | 696 | |||||||||
| Total deferred credits and other liabilities | 33,926 | 33,258 | |||||||||
| Total Liabilities | 94,967 | 90,410 | |||||||||
| Redeemable Preferred Stock of Subsidiaries: | |||||||||||
| Cumulative preferred stock | |||||||||||
| $100 par or stated value - 4.20% to 4.92% (Authorized - 10 million shares; Outstanding - 0.5 million shares) | 48 | 48 | |||||||||
| $1 par value - 5.00% (Authorized - 28 million shares; Outstanding - 10 million shares) | 243 | 243 | |||||||||
| Total redeemable preferred stock of subsidiaries (annual dividend requirement - $15 million) | 291 | 291 | |||||||||
| Common Stockholders' Equity: | |||||||||||
| Common stock, par value $5 per share (Authorized - 1.5 billion shares) | 5,279 | 5,268 | |||||||||
| (Issued - 1.1 billion shares; Treasury - 1.0 million shares) | |||||||||||
| Paid-in capital | 11,950 | 11,834 | |||||||||
| Treasury, at cost | (47) | (46) | |||||||||
| Retained earnings | 10,929 | 11,311 | |||||||||
| Accumulated other comprehensive loss | (237) | (395) | |||||||||
| Total common stockholders' equity | 27,874 | 27,972 | |||||||||
| Noncontrolling interests | 4,402 | 4,262 | |||||||||
| Total Stockholders' Equity (See accompanying statements) | 32,276 | 32,234 | |||||||||
| Total Liabilities and Stockholders' Equity | $ | 127,534 | $ | 122,935 | |||||||
| 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, 2021, 2020, and 2019
Southern Company and Subsidiary Companies 2021 Annual Report
| 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, 2018 | 1,035 | (1) | $ | 5,164 | $ | 11,094 | $ | (38) | $ | 8,706 | $ | (203) | $ | 4,316 | $ | 29,039 | |||||||||||||||||||||||||||||||||||||||||||
| Consolidated net income (loss) | — | — | — | — | — | 4,739 | — | (10) | 4,729 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | — | — | (118) | — | (118) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of equity units(*) | — | — | — | (198) | — | — | — | — | (198) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock issued | 19 | — | 93 | 751 | — | — | — | — | 844 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | 66 | — | — | — | — | 66 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends of $2.4600 per share | — | — | — | — | — | (2,570) | — | — | (2,570) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Contributions from noncontrolling interests | — | — | — | — | — | — | — | 276 | 276 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (327) | (327) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | 21 | (4) | 2 | — | (1) | 18 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 1,054 | (1) | 5,257 | 11,734 | (42) | 10,877 | (321) | 4,254 | 31,759 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Consolidated net income (loss) | — | — | — | — | — | 3,119 | — | (31) | 3,088 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | — | — | (75) | — | (75) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock issued | 4 | — | 11 | 63 | — | — | — | — | 74 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | 44 | — | — | — | — | 44 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends of $2.5400 per share | — | — | — | — | — | (2,685) | — | — | (2,685) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Contributions from noncontrolling interests | — | — | — | — | — | — | — | 307 | 307 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (271) | (271) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Purchase of membership interests from noncontrolling interests | — | — | — | 5 | — | — | — | (65) | (60) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Sale of noncontrolling interests | — | — | — | (2) | — | — | — | 67 | 65 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | (10) | (4) | — | 1 | 1 | (12) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 1,058 | (1) | 5,268 | 11,834 | (46) | 11,311 | (395) | 4,262 | 32,234 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Consolidated net income (loss) | — | — | — | — | — | 2,393 | — | (99) | 2,294 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | — | 158 | — | 158 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock issued | 3 | — | 11 | 62 | — | — | — | — | 73 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | 62 | — | — | — | — | 62 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends of $2.6200 per share | — | — | — | — | — | (2,777) | — | — | (2,777) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Contributions from noncontrolling interests | — | — | — | — | — | — | — | 590 | 590 | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | — | (351) | (351) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | (8) | (1) | 2 | — | — | (7) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 1,061 | (1) | $ | 5,279 | $ | 11,950 | $ | (47) | $ | 10,929 | $ | (237) | $ | 4,402 | $ | 32,276 |
(*)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 stockholders 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, 2021 and 2020, 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, 2021, and the related notes (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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 our 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 impacts multiple financial statement line items and disclosures, including, but not limited to, property, plant, and equipment; other regulatory assets; other regulatory liabilities; other cost of removal obligations; deferred charges and credits related to income taxes; under and over recovered regulatory clause revenues; operating revenues; operations and maintenance expenses; and depreciation and amortization.
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 by 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)
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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 that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures (e.g., asset retirement costs and the remaining net book values of retired assets) and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. 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. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions 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 costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
-
We read relevant regulatory orders issued by the Commissions for Alabama Power, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.
-
For regulatory matters in process, we inspected filings with the Commissions by Alabama Power and other interested parties that may impact Alabama Power's future rates for any evidence that might contradict management's assertions.
-
We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
-
We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable 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.
/s/ Deloitte & Touche LLP
Birmingham, Alabama
February 16, 2022
We have served as Alabama Power's auditor since 2002.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020, and 2019
Alabama Power Company 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Retail revenues | $ | 5,499 | $ | 5,213 | $ | 5,501 | |||||||||||
| Wholesale revenues, non-affiliates | 377 | 269 | 258 | ||||||||||||||
| Wholesale revenues, affiliates | 171 | 46 | 81 | ||||||||||||||
| Other revenues | 366 | 302 | 285 | ||||||||||||||
| Total operating revenues | 6,413 | 5,830 | 6,125 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 1,235 | 970 | 1,112 | ||||||||||||||
| Purchased power, non-affiliates | 221 | 191 | 203 | ||||||||||||||
| Purchased power, affiliates | 147 | 128 | 200 | ||||||||||||||
| Other operations and maintenance | 1,735 | 1,619 | 1,821 | ||||||||||||||
| Depreciation and amortization | 859 | 812 | 793 | ||||||||||||||
| Taxes other than income taxes | 410 | 416 | 403 | ||||||||||||||
| Total operating expenses | 4,607 | 4,136 | 4,532 | ||||||||||||||
| Operating Income | 1,806 | 1,694 | 1,593 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Allowance for equity funds used during construction | 52 | 46 | 52 | ||||||||||||||
| Interest expense, net of amounts capitalized | (340) | (338) | (336) | ||||||||||||||
| Other income (expense), net | 107 | 100 | 46 | ||||||||||||||
| Total other income and (expense) | (181) | (192) | (238) | ||||||||||||||
| Earnings Before Income Taxes | 1,625 | 1,502 | 1,355 | ||||||||||||||
| Income taxes | 372 | 337 | 270 | ||||||||||||||
| Net Income | 1,253 | 1,165 | 1,085 | ||||||||||||||
| Dividends on Preferred Stock | 15 | 15 | 15 | ||||||||||||||
| Net Income After Dividends on Preferred Stock | $ | 1,238 | $ | 1,150 | $ | 1,070 |
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2021, 2020, and 2019
Alabama Power Company 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Net Income | $ | 1,253 | $ | 1,165 | $ | 1,085 | |||||||||||
| Other comprehensive income: | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Changes in fair value, net of tax of $1, $—, and $—, respectively | 2 | — | — | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $2, $2, and $2, respectively | 4 | 4 | 4 | ||||||||||||||
| Total other comprehensive income | 6 | 4 | 4 | ||||||||||||||
| Comprehensive Income | $ | 1,259 | $ | 1,169 | $ | 1,089 |
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, 2021, 2020, and 2019
Alabama Power Company 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Net income | $ | 1,253 | $ | 1,165 | $ | 1,085 | |||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 1,005 | 963 | 951 | ||||||||||||||
| Deferred income taxes | 245 | 78 | 197 | ||||||||||||||
| Allowance for equity funds used during construction | (52) | (46) | (52) | ||||||||||||||
| Pension, postretirement, and other employee benefits | (106) | (88) | (95) | ||||||||||||||
| Pension and postretirement funding | — | (2) | (362) | ||||||||||||||
| Settlement of asset retirement obligations | (202) | (219) | (127) | ||||||||||||||
| Natural disaster reserve accruals | 75 | 112 | 138 | ||||||||||||||
| Retail fuel cost under recovery – long-term | (126) | — | — | ||||||||||||||
| Other deferred charges – affiliated | — | — | (42) | ||||||||||||||
| Other, net | (51) | 50 | 4 | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | 42 | (49) | 9 | ||||||||||||||
| -Materials and supplies | (6) | (47) | 23 | ||||||||||||||
| -Other current assets | 44 | (66) | (89) | ||||||||||||||
| -Accounts payable | (109) | (90) | (41) | ||||||||||||||
| -Accrued taxes | (56) | 84 | 49 | ||||||||||||||
| -Accrued compensation | (7) | (32) | (14) | ||||||||||||||
| -Retail fuel cost over recovery | (18) | (31) | 47 | ||||||||||||||
| -Customer refunds | 128 | (12) | 30 | ||||||||||||||
| -Other current liabilities | (6) | (28) | 68 | ||||||||||||||
| Net cash provided from operating activities | 2,053 | 1,742 | 1,779 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Property additions | (1,753) | (1,970) | (1,757) | ||||||||||||||
| Nuclear decommissioning trust fund purchases | (638) | (268) | (261) | ||||||||||||||
| Nuclear decommissioning trust fund sales | 637 | 267 | 260 | ||||||||||||||
| Cost of removal net of salvage | (165) | (98) | (103) | ||||||||||||||
| Change in construction payables | (16) | (34) | (71) | ||||||||||||||
| Other investing activities | (26) | (19) | (31) | ||||||||||||||
| Net cash used for investing activities | (1,961) | (2,122) | (1,963) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Proceeds — | |||||||||||||||||
| Senior notes | 1,300 | 600 | 600 | ||||||||||||||
| Pollution control revenue bonds | — | 87 | — | ||||||||||||||
| Redemptions and repurchases — | |||||||||||||||||
| Senior notes | (200) | (250) | (200) | ||||||||||||||
| Pollution control revenue bonds | (65) | (87) | — | ||||||||||||||
| Other long-term debt | (206) | — | — | ||||||||||||||
| Capital contributions from parent company | 636 | 653 | 1,240 | ||||||||||||||
| Payment of common stock dividends | (984) | (957) | (844) | ||||||||||||||
| Other financing activities | (43) | (30) | (31) | ||||||||||||||
| Net cash provided from financing activities | 438 | 16 | 765 | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 530 | (364) | 581 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 530 | 894 | 313 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 1,060 | $ | 530 | $ | 894 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid during the period for — | |||||||||||||||||
| Interest (net of $15, $15, and $19 capitalized, respectively) | $ | 308 | $ | 321 | $ | 311 | |||||||||||
| Income taxes, net | 185 | 187 | 26 | ||||||||||||||
| Noncash transactions — Accrued property additions at year-end | 150 | 166 | 200 |
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Alabama Power Company 2021 Annual Report
| Assets | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 1,060 | $ | 530 | |||||||
| Receivables — | |||||||||||
| Customer accounts | 410 | 429 | |||||||||
| Unbilled revenues | 138 | 152 | |||||||||
| Affiliated | 37 | 31 | |||||||||
| Other accounts and notes | 55 | 66 | |||||||||
| Accumulated provision for uncollectible accounts | (14) | (43) | |||||||||
| Fossil fuel stock | 159 | 235 | |||||||||
| Materials and supplies | 548 | 546 | |||||||||
| Prepaid expenses | 41 | 42 | |||||||||
| Other regulatory assets | 208 | 226 | |||||||||
| Other current assets | 67 | 33 | |||||||||
| Total current assets | 2,709 | 2,247 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 33,135 | 31,816 | |||||||||
| Less: Accumulated provision for depreciation | 10,313 | 10,009 | |||||||||
| Plant in service, net of depreciation | 22,822 | 21,807 | |||||||||
| Nuclear fuel, at amortized cost | 247 | 270 | |||||||||
| Construction work in progress | 1,147 | 866 | |||||||||
| Total property, plant, and equipment | 24,216 | 22,943 | |||||||||
| Other Property and Investments: | |||||||||||
| Nuclear decommissioning trusts, at fair value | 1,325 | 1,157 | |||||||||
| Equity investments in unconsolidated subsidiaries | 57 | 63 | |||||||||
| Miscellaneous property and investments | 126 | 131 | |||||||||
| Total other property and investments | 1,508 | 1,351 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Operating lease right-of-use assets, net of amortization | 108 | 151 | |||||||||
| Deferred charges related to income taxes | 240 | 235 | |||||||||
| Prepaid pension and other postretirement benefit costs | 513 | — | |||||||||
| Regulatory assets – asset retirement obligations | 1,547 | 1,441 | |||||||||
| Other regulatory assets, deferred | 1,807 | 2,162 | |||||||||
| Other deferred charges and assets | 334 | 273 | |||||||||
| Total deferred charges and other assets | 4,549 | 4,262 | |||||||||
| Total Assets | $ | 32,982 | $ | 30,803 |
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Alabama Power Company 2021 Annual Report
| Liabilities and Stockholder's Equity | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 751 | $ | 311 | |||||||
| Accounts payable — | |||||||||||
| Affiliated | 309 | 316 | |||||||||
| Other | 459 | 545 | |||||||||
| Customer deposits | 106 | 104 | |||||||||
| Accrued taxes | 98 | 152 | |||||||||
| Accrued interest | 100 | 90 | |||||||||
| Accrued compensation | 219 | 212 | |||||||||
| Asset retirement obligations | 320 | 254 | |||||||||
| Other regulatory liabilities | 215 | 108 | |||||||||
| Other current liabilities | 125 | 107 | |||||||||
| Total current liabilities | 2,702 | 2,199 | |||||||||
| Long-Term Debt | 8,936 | 8,558 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 3,573 | 3,273 | |||||||||
| Deferred credits related to income taxes | 1,968 | 2,016 | |||||||||
| Accumulated deferred ITCs | 88 | 94 | |||||||||
| Employee benefit obligations | 171 | 214 | |||||||||
| Operating lease obligations | 66 | 119 | |||||||||
| Asset retirement obligations, deferred | 4,014 | 3,720 | |||||||||
| Other cost of removal obligations | 192 | 335 | |||||||||
| Other regulatory liabilities, deferred | 210 | 124 | |||||||||
| Other deferred credits and liabilities | 58 | 50 | |||||||||
| Total deferred credits and other liabilities | 10,340 | 9,945 | |||||||||
| Total Liabilities | 21,978 | 20,702 | |||||||||
| Redeemable Preferred Stock: | |||||||||||
| Cumulative redeemable preferred stock | |||||||||||
| $100 par or stated value - 4.20% to 4.92% (Authorized - 3.9 million shares; Outstanding - 0.5 million shares) | 48 | 48 | |||||||||
| $1 par value - 5.00% (Authorized - 27.5 million shares; Outstanding - 10 million shares: $25 stated value) | 243 | 243 | |||||||||
| Total redeemable preferred stock (annual dividend requirement - $15 million) | 291 | 291 | |||||||||
| 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 | 6,056 | 5,413 | |||||||||
| Retained earnings | 3,448 | 3,194 | |||||||||
| Accumulated other comprehensive loss | (13) | (19) | |||||||||
| Total common stockholder's equity (See accompanying statements) | 10,713 | 9,810 | |||||||||
| Total Liabilities and Stockholder's Equity | $ | 32,982 | $ | 30,803 | |||||||
| 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, 2021, 2020, and 2019
Alabama Power Company 2021 Annual Report
| Number of Common Shares Issued | Common Stock | Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | 31 | $ | 1,222 | $ | 3,508 | $ | 2,775 | $ | (28) | $ | 7,477 | ||||||||||||||||||||||||
| Net income after dividends on preferred stock | — | — | — | 1,070 | — | 1,070 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 1,247 | — | — | 1,247 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 4 | 4 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (844) | — | (844) | |||||||||||||||||||||||||||||
| Other | — | — | — | — | 1 | 1 | |||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 31 | 1,222 | 4,755 | 3,001 | (23) | 8,955 | |||||||||||||||||||||||||||||
| Net income after dividends on preferred stock | — | — | — | 1,150 | — | 1,150 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 658 | — | — | 658 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 4 | 4 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (957) | — | (957) | |||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 31 | 1,222 | 5,413 | 3,194 | (19) | 9,810 | |||||||||||||||||||||||||||||
| Net income after dividends on preferred stock | — | — | — | 1,238 | — | 1,238 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 643 | — | — | 643 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 6 | 6 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (984) | — | (984) | |||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 31 | $ | 1,222 | $ | 6,056 | $ | 3,448 | $ | (13) | $ | 10,713 |
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, 2021 and 2020, 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, 2021, and the related notes (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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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 impacts multiple financial statement line items and disclosures, including, but not limited to, property, plant, and equipment; other regulatory assets; other regulatory liabilities; other cost of removal obligations; deferred charges and credits related to income taxes; under and over recovered regulatory clause revenues; operating revenues; operations and maintenance expenses; and depreciation and amortization.
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 by 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)
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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 that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures (e.g., asset retirement costs, property damage reserves, and remaining net book values of retired assets) and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. 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. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions 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 costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
-
We read relevant regulatory orders issued by the Commissions for Georgia Power, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.
-
For regulatory matters in process, we inspected filings with the Commissions by Georgia Power and other interested parties that may impact Georgia Power's future rates for any evidence that might contradict management's assertions.
-
We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
-
We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable 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.
Disclosure of Uncertainties – Plant Vogtle Units 3 and 4 Construction – Refer to Note 2 (Regulatory Matters – Georgia Power – Nuclear Construction) to the financial statements
Critical Audit Matter Description
As discussed in Note 2 to the financial statements, the ultimate recovery of Georgia Power's investment in the construction of Plant Vogtle Units 3 and 4 is subject to multiple uncertainties. Such uncertainties include the potential impact of future decisions by Georgia Power's regulators (particularly the Georgia Public Service Commission) and potential actions by the co-owners of the Vogtle project. In addition, Georgia Power's ability to meet its cost and schedule forecasts could impact its ability to fully recover its investment in the project. While the project is not subject to a cost cap, Georgia Power's cost and schedule forecasts are subject to numerous uncertainties which could impact cost recovery, including ongoing or future challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; and procurement and related installation. New challenges may arise, particularly as Units 3 and 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). The ongoing and potential future challenges described above may change the projected schedule and estimated cost.
In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. The ultimate recovery of Georgia Power's investment in Plant Vogtle Units 3 and 4 is subject to the outcome of future assessments by management as well as Georgia Public Service Commission decisions in
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future regulatory proceedings. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income of $1.692 billion in 2021.
In addition, management has disclosed the status, risks, and uncertainties associated with Plant Vogtle Units 3 and 4, including (1) the status of construction; (2) the status of regulatory proceedings; (3) the status of legal actions or issues involving the co-owners of the project; and (4) other matters which could impact the ultimate recoverability of Georgia Power's investment in the project. We identified as a critical audit matter the evaluation of Georgia Power's identification and disclosure of events and uncertainties that could impact the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4. This critical audit matter involved significant audit effort requiring specialized industry and construction expertise, extensive knowledge of rate regulation, and difficult and subjective judgments.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to Georgia Power's identification and disclosure of events and uncertainties that could impact the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4 included the following, among others:
-
We tested the effectiveness of internal controls over the on-going evaluation, monitoring, and disclosure of matters related to the construction and ultimate cost recovery of Plant Vogtle Units 3 and 4.
-
We involved construction specialists to assist in our evaluation of the reasonableness of the projected in-service dates for Plant Vogtle Units 3 and 4 and Georgia Power's processes for on-going evaluation and monitoring of the construction schedule and to assess the disclosures of the uncertainties impacting the ultimate cost recovery of its investment in the construction of these units.
-
We attended meetings with Georgia Power and Southern Company officials, project managers (including contractors), independent regulatory monitors, and co-owners of the project to evaluate and monitor construction status and identify cost and schedule challenges.
-
We read reports of external independent monitors employed by the Georgia Public Service Commission to monitor the status of construction at Plant Vogtle Units 3 and 4 to evaluate the completeness of Georgia Power's disclosure of the uncertainties impacting the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4.
-
We inquired of Georgia Power and Southern Company officials and project managers regarding the status of construction, the construction schedule, and cost forecasts to assess the financial statement disclosures with respect to project status and potential risks and uncertainties to the achievement of such forecasts.
-
We inspected regulatory filings and transcripts of Georgia Public Service Commission hearings regarding the construction and cost recovery of Plant Vogtle Units 3 and 4 to identify potential challenges to the recovery of Georgia Power's construction costs and to evaluate the disclosures with respect to such uncertainties.
-
We inquired of Georgia Power and Southern Company management and internal and external legal counsel regarding any potential legal actions or issues arising from project construction or issues involving the co-owners of the project.
-
We monitored the status of reviews and inspections by the Nuclear Regulatory Commission to identify potential impediments to the licensing and commercial operation of the project that could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4.
-
We compared the financial statement disclosures relating to this matter to the information gathered through the conduct of all our procedures to evaluate whether there were omissions relating to significant facts or uncertainties regarding the status of construction or other factors which could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4.
-
We obtained representation from management regarding disclosure of all matters related to the cost and/or status of the construction of Plant Vogtle Units 3 and 4, including matters related to a co-owner or regulatory development, that could impact the recovery of the related costs.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 16, 2022
We have served as Georgia Power's auditor since 2002.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020, and 2019
Georgia Power Company 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Retail revenues | $ | 8,478 | $ | 7,609 | $ | 7,707 | |||||||||||
| Wholesale revenues | 197 | 115 | 140 | ||||||||||||||
| Other revenues | 585 | 585 | 561 | ||||||||||||||
| Total operating revenues | 9,260 | 8,309 | 8,408 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 1,449 | 1,141 | 1,444 | ||||||||||||||
| Purchased power, non-affiliates | 632 | 540 | 521 | ||||||||||||||
| Purchased power, affiliates | 859 | 509 | 575 | ||||||||||||||
| Other operations and maintenance | 2,213 | 1,953 | 1,972 | ||||||||||||||
| Depreciation and amortization | 1,371 | 1,425 | 981 | ||||||||||||||
| Taxes other than income taxes | 476 | 444 | 454 | ||||||||||||||
| Estimated loss on Plant Vogtle Units 3 and 4 | 1,692 | 325 | — | ||||||||||||||
| Total operating expenses | 8,692 | 6,337 | 5,947 | ||||||||||||||
| Operating Income | 568 | 1,972 | 2,461 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Allowance for equity funds used during construction | 127 | 91 | 68 | ||||||||||||||
| Interest expense, net of amounts capitalized | (421) | (425) | (409) | ||||||||||||||
| Other income (expense), net | 142 | 89 | 72 | ||||||||||||||
| Total other income and (expense) | (152) | (245) | (269) | ||||||||||||||
| Earnings Before Income Taxes | 416 | 1,727 | 2,192 | ||||||||||||||
| Income taxes (benefit) | (168) | 152 | 472 | ||||||||||||||
| Net Income | $ | 584 | $ | 1,575 | $ | 1,720 | |||||||||||
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2021, 2020, and 2019
Georgia Power Company 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Net Income | $ | 584 | $ | 1,575 | $ | 1,720 | |||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Changes in fair value, net of tax of $—, $(1), and $(15), respectively | — | (2) | (44) | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $2, $2, and $1, respectively | 6 | 6 | 2 | ||||||||||||||
| Total other comprehensive income (loss) | 6 | 4 | (42) | ||||||||||||||
| Comprehensive Income | $ | 590 | $ | 1,579 | $ | 1,678 |
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, 2021, 2020, and 2019
Georgia Power Company 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Net income | $ | 584 | $ | 1,575 | $ | 1,720 | |||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 1,557 | 1,607 | 1,193 | ||||||||||||||
| Deferred income taxes | (550) | (273) | 179 | ||||||||||||||
| Allowance for equity funds used during construction | (127) | (91) | (68) | ||||||||||||||
| Pension, postretirement, and other employee benefits | (148) | (137) | (146) | ||||||||||||||
| Pension and postretirement funding | — | — | (200) | ||||||||||||||
| Settlement of asset retirement obligations | (210) | (185) | (151) | ||||||||||||||
| Storm damage accruals | 213 | 213 | 30 | ||||||||||||||
| Retail fuel cost recovery – long-term | (410) | (73) | 73 | ||||||||||||||
| Other deferred charges – affiliated | — | — | (108) | ||||||||||||||
| Estimated loss on Plant Vogtle Units 3 and 4 | 1,692 | 325 | — | ||||||||||||||
| Other, net | 53 | 14 | 50 | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | 81 | (114) | 177 | ||||||||||||||
| -Fossil fuel stock | 30 | (6) | (41) | ||||||||||||||
| -Materials and supplies | (82) | (91) | (4) | ||||||||||||||
| -Prepaid income taxes | — | — | 102 | ||||||||||||||
| -Other current assets | (30) | (48) | (15) | ||||||||||||||
| -Accounts payable | 186 | 59 | (92) | ||||||||||||||
| -Accrued taxes | 21 | 55 | 58 | ||||||||||||||
| -Retail fuel cost over recovery | (113) | 113 | — | ||||||||||||||
| -Customer refunds | 1 | (223) | 116 | ||||||||||||||
| -Other current liabilities | (1) | 64 | 34 | ||||||||||||||
| Net cash provided from operating activities | 2,747 | 2,784 | 2,907 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Property additions | (3,376) | (3,445) | (3,510) | ||||||||||||||
| Nuclear decommissioning trust fund purchases | (960) | (609) | (628) | ||||||||||||||
| Nuclear decommissioning trust fund sales | 956 | 604 | 622 | ||||||||||||||
| Cost of removal, net of salvage | (149) | (143) | (186) | ||||||||||||||
| Change in construction payables, net of joint owner portion | (65) | 16 | (122) | ||||||||||||||
| Payments pursuant to LTSAs | (42) | (86) | (81) | ||||||||||||||
| Contributions in aid of construction | 65 | 20 | 18 | ||||||||||||||
| Proceeds from dispositions | 8 | 153 | 14 | ||||||||||||||
| Other investing activities | (27) | (13) | (12) | ||||||||||||||
| Net cash used for investing activities | (3,590) | (3,503) | (3,885) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Decrease in notes payable, net | (60) | (55) | (179) | ||||||||||||||
| Proceeds — | |||||||||||||||||
| Senior notes | 750 | 1,500 | 750 | ||||||||||||||
| FFB loan | 440 | 848 | 1,218 | ||||||||||||||
| Pollution control revenue bonds | 122 | 53 | 584 | ||||||||||||||
| Short-term borrowings | — | 250 | 250 | ||||||||||||||
| Redemptions and repurchases — | |||||||||||||||||
| Senior notes | (325) | (950) | (500) | ||||||||||||||
| FFB loan | (96) | (73) | — | ||||||||||||||
| Pollution control revenue bonds | (69) | (336) | (223) | ||||||||||||||
| Short-term borrowings | — | (375) | — | ||||||||||||||
| Capital contributions from parent company | 1,782 | 1,392 | 634 | ||||||||||||||
| Payment of common stock dividends | (1,649) | (1,542) | (1,576) | ||||||||||||||
| Other financing activities | (28) | (36) | (40) | ||||||||||||||
| Net cash provided from financing activities | 867 | 676 | 918 | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 24 | (43) | (60) | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 9 | 52 | 112 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 33 | $ | 9 | $ | 52 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid during the period for — | |||||||||||||||||
| Interest (net of $63, $47, and $35 capitalized, respectively) | $ | 382 | $ | 380 | $ | 373 | |||||||||||
| Income taxes, net | 305 | 373 | 110 | ||||||||||||||
| Noncash transactions — Accrued property additions at year-end | 479 | 553 | 560 | ||||||||||||||
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Georgia Power Company 2021 Annual Report
| Assets | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 33 | $ | 9 | |||||||
| Receivables — | |||||||||||
| Customer accounts | 549 | 621 | |||||||||
| Unbilled revenues | 231 | 233 | |||||||||
| Joint owner accounts | 116 | 123 | |||||||||
| Affiliated | 25 | 21 | |||||||||
| Other accounts and notes | 44 | 67 | |||||||||
| Accumulated provision for uncollectible accounts | (2) | (26) | |||||||||
| Fossil fuel stock | 248 | 278 | |||||||||
| Materials and supplies | 670 | 592 | |||||||||
| Regulatory assets – storm damage | 48 | 213 | |||||||||
| Regulatory assets – asset retirement obligations | 178 | 166 | |||||||||
| Other regulatory assets | 241 | 248 | |||||||||
| Other current assets | 178 | 143 | |||||||||
| Total current assets | 2,559 | 2,688 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 41,332 | 39,682 | |||||||||
| Less: Accumulated provision for depreciation | 12,854 | 12,251 | |||||||||
| Plant in service, net of depreciation | 28,478 | 27,431 | |||||||||
| Nuclear fuel, at amortized cost | 577 | 548 | |||||||||
| Construction work in progress | 6,688 | 6,857 | |||||||||
| Total property, plant, and equipment | 35,743 | 34,836 | |||||||||
| Other Property and Investments: | |||||||||||
| Nuclear decommissioning trusts, at fair value | 1,217 | 1,145 | |||||||||
| Equity investments in unconsolidated subsidiaries | 50 | 51 | |||||||||
| Miscellaneous property and investments | 69 | 63 | |||||||||
| Total other property and investments | 1,336 | 1,259 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Operating lease right-of-use assets, net of amortization | 1,157 | 1,308 | |||||||||
| Deferred charges related to income taxes | 550 | 527 | |||||||||
| Prepaid pension costs | 563 | — | |||||||||
| Deferred under recovered fuel clause revenues | 410 | — | |||||||||
| Regulatory assets – asset retirement obligations, deferred | 3,688 | 3,291 | |||||||||
| Other regulatory assets, deferred | 1,964 | 2,692 | |||||||||
| Other deferred charges and assets | 491 | 479 | |||||||||
| Total deferred charges and other assets | 8,823 | 8,297 | |||||||||
| Total Assets | $ | 48,461 | $ | 47,080 |
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Georgia Power Company 2021 Annual Report
| Liabilities and Stockholder's Equity | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 675 | $ | 542 | |||||||
| Notes payable | — | 60 | |||||||||
| Accounts payable — | |||||||||||
| Affiliated | 757 | 597 | |||||||||
| Other | 702 | 753 | |||||||||
| Customer deposits | 259 | 276 | |||||||||
| Accrued taxes | 335 | 407 | |||||||||
| Accrued interest | 136 | 130 | |||||||||
| Accrued compensation | 232 | 233 | |||||||||
| Operating lease obligations | 156 | 151 | |||||||||
| Asset retirement obligations | 317 | 287 | |||||||||
| Over recovered fuel clause revenues | — | 113 | |||||||||
| Other regulatory liabilities | 280 | 228 | |||||||||
| Other current liabilities | 254 | 254 | |||||||||
| Total current liabilities | 4,103 | 4,031 | |||||||||
| Long-Term Debt | 13,109 | 12,428 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 3,019 | 3,272 | |||||||||
| Deferred credits related to income taxes | 2,321 | 2,588 | |||||||||
| Accumulated deferred ITCs | 328 | 273 | |||||||||
| Employee benefit obligations | 402 | 586 | |||||||||
| Operating lease obligations, deferred | 999 | 1,156 | |||||||||
| Asset retirement obligations, deferred | 6,507 | 5,978 | |||||||||
| Other deferred credits and liabilities | 439 | 267 | |||||||||
| Total deferred credits and other liabilities | 14,015 | 14,120 | |||||||||
| Total Liabilities | 31,227 | 30,579 | |||||||||
| Common Stockholder's Equity: | |||||||||||
| Common stock, without par value (Authorized - 20 million shares; Outstanding - 9 million shares) | 398 | 398 | |||||||||
| Paid-in capital | 14,153 | 12,361 | |||||||||
| Retained earnings | 2,724 | 3,789 | |||||||||
| Accumulated other comprehensive loss | (41) | (47) | |||||||||
| Total common stockholder's equity (See accompanying statements) | 17,234 | 16,501 | |||||||||
| Total Liabilities and Stockholder's Equity | $ | 48,461 | $ | 47,080 | |||||||
| 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, 2021, 2020, and 2019
Georgia Power Company 2021 Annual Report
| Number of Common Shares Issued | Common Stock | Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total | ||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | 9 | $ | 398 | $ | 10,322 | $ | 3,612 | $ | (9) | $ | 14,323 | ||||||||||||||||||||||||
| Net income | — | — | — | 1,720 | — | 1,720 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 640 | — | — | 640 | |||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | (42) | (42) | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (1,576) | — | (1,576) | |||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 9 | 398 | 10,962 | 3,756 | (51) | 15,065 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 1,575 | — | 1,575 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 1,399 | — | — | 1,399 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 4 | 4 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (1,542) | — | (1,542) | |||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 9 | 398 | 12,361 | 3,789 | (47) | 16,501 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 584 | — | 584 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 1,792 | — | — | 1,792 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 6 | 6 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (1,649) | — | (1,649) | |||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 9 | $ | 398 | $ | 14,153 | $ | 2,724 | $ | (41) | $ | 17,234 |
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, 2021 and 2020, 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, 2021, and the related notes (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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 our 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 impacts multiple financial statement line items and disclosures, including, but not limited to, property, plant, and equipment; other regulatory assets; other regulatory liabilities; regulatory assets – asset retirement obligations; other cost of removal obligations; deferred charges and credits related to income taxes; under and over recovered regulatory clause revenues; operating revenues; operations and maintenance expenses; and depreciation and amortization.
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 by 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
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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 that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures (e.g., asset retirement costs, property damage reserves, and the remaining net book values of retired assets) and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. 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, and/or (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
-
We read relevant regulatory orders issued by the Commissions for Mississippi Power, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.
-
For regulatory matters in process, we inspected filings with the Commissions by Mississippi Power and other interested parties that may impact Mississippi Power's future rates for any evidence that might contradict management's assertions.
-
We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
-
We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable 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.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 16, 2022
We have served as Mississippi Power's auditor since 2002.
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STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020, and 2019
Mississippi Power Company 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Retail revenues | $ | 875 | $ | 821 | $ | 877 | |||||||||||
| Wholesale revenues, non-affiliates | 230 | 215 | 237 | ||||||||||||||
| Wholesale revenues, affiliates | 188 | 111 | 132 | ||||||||||||||
| Other revenues | 29 | 25 | 18 | ||||||||||||||
| Total operating revenues | 1,322 | 1,172 | 1,264 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 470 | 350 | 407 | ||||||||||||||
| Purchased power | 26 | 22 | 20 | ||||||||||||||
| Other operations and maintenance | 313 | 284 | 307 | ||||||||||||||
| Depreciation and amortization | 180 | 183 | 192 | ||||||||||||||
| Taxes other than income taxes | 128 | 124 | 113 | ||||||||||||||
| Total operating expenses | 1,117 | 963 | 1,039 | ||||||||||||||
| Operating Income | 205 | 209 | 225 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Interest expense, net of amounts capitalized | (60) | (60) | (69) | ||||||||||||||
| Other income (expense), net | 35 | 17 | 13 | ||||||||||||||
| Total other income and (expense) | (25) | (43) | (56) | ||||||||||||||
| Earnings Before Income Taxes | 180 | 166 | 169 | ||||||||||||||
| Income taxes | 21 | 14 | 30 | ||||||||||||||
| Net Income | $ | 159 | $ | 152 | $ | 139 | |||||||||||
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2021, 2020, and 2019
Mississippi Power Company 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Net Income | $ | 159 | $ | 152 | $ | 139 | |||||||||||
| Other comprehensive income: | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $—, $—, and $—, respectively | 1 | 1 | 1 | ||||||||||||||
| Total other comprehensive income | 1 | 1 | 1 | ||||||||||||||
| Comprehensive Income | $ | 160 | $ | 153 | $ | 140 |
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, 2021, 2020, and 2019
Mississippi Power Company 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Net income | $ | 159 | $ | 152 | $ | 139 | |||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 213 | 191 | 197 | ||||||||||||||
| Deferred income taxes | (4) | (4) | 37 | ||||||||||||||
| Pension and postretirement funding | — | — | (54) | ||||||||||||||
| Settlement of asset retirement obligations | (24) | (22) | (35) | ||||||||||||||
| Other, net | (33) | (1) | 35 | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | 9 | (7) | 6 | ||||||||||||||
| -Prepaid income taxes | 3 | (3) | 12 | ||||||||||||||
| -Other current assets | (9) | (28) | (8) | ||||||||||||||
| -Accounts payable | (35) | 20 | 3 | ||||||||||||||
| -Accrued taxes | 6 | 10 | 11 | ||||||||||||||
| -Over recovered regulatory clause revenues | (34) | 5 | 16 | ||||||||||||||
| -Other current liabilities | (5) | (15) | (20) | ||||||||||||||
| Net cash provided from operating activities | 246 | 298 | 339 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Property additions | (213) | (274) | (202) | ||||||||||||||
| Payments pursuant to LTSAs | (29) | (28) | (23) | ||||||||||||||
| Contributions in aid of construction | 15 | — | — | ||||||||||||||
| Other investing activities | (30) | (21) | (38) | ||||||||||||||
| Net cash used for investing activities | (257) | (323) | (263) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Increase (decrease) in notes payable, net | (25) | 25 | — | ||||||||||||||
| Proceeds — | |||||||||||||||||
| Senior notes | 525 | — | — | ||||||||||||||
| Short-term borrowings | — | 40 | — | ||||||||||||||
| Pollution control revenue bonds | — | 34 | 43 | ||||||||||||||
| Other long-term debt | — | 100 | — | ||||||||||||||
| Redemptions — | |||||||||||||||||
| Senior notes | — | (275) | (25) | ||||||||||||||
| Short-term borrowings | — | (40) | — | ||||||||||||||
| Pollution control revenue bonds | — | (41) | — | ||||||||||||||
| Other revenue bonds | (320) | — | — | ||||||||||||||
| Other long-term debt | (100) | — | — | ||||||||||||||
| Capital contributions from parent company | 120 | 85 | 51 | ||||||||||||||
| Return of capital to parent company | — | (74) | (150) | ||||||||||||||
| Payment of common stock dividends | (157) | (74) | — | ||||||||||||||
| Other financing activities | (10) | (2) | (2) | ||||||||||||||
| Net cash provided from (used for) financing activities | 33 | (222) | (83) | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 22 | (247) | (7) | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 39 | 286 | 293 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 61 | $ | 39 | $ | 286 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid (received) during the period for — | |||||||||||||||||
| Interest (net of $—, $—, and $(1) capitalized, respectively) | $ | 58 | $ | 63 | $ | 71 | |||||||||||
| Income taxes, net | 16 | 28 | (27) | ||||||||||||||
| Noncash transactions — Accrued property additions at year-end | 25 | 34 | 35 | ||||||||||||||
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Mississippi Power Company 2021 Annual Report
| Assets | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 61 | $ | 39 | |||||||
| Receivables — | |||||||||||
| Customer accounts | 37 | 34 | |||||||||
| Unbilled revenues | 34 | 38 | |||||||||
| Affiliated | 29 | 32 | |||||||||
| Other accounts and notes | 28 | 32 | |||||||||
| Fossil fuel stock | 28 | 24 | |||||||||
| Materials and supplies | 70 | 65 | |||||||||
| Other regulatory assets | 54 | 60 | |||||||||
| Other current assets | 41 | 20 | |||||||||
| Total current assets | 382 | 344 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 5,106 | 5,011 | |||||||||
| Less: Accumulated provision for depreciation | 1,591 | 1,545 | |||||||||
| Plant in service, net of depreciation | 3,515 | 3,466 | |||||||||
| Construction work in progress | 127 | 146 | |||||||||
| Total property, plant, and equipment | 3,642 | 3,612 | |||||||||
| Other Property and Investments | 179 | 151 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Deferred charges related to income taxes | 31 | 32 | |||||||||
| Prepaid pension costs | 79 | — | |||||||||
| Regulatory assets – asset retirement obligations | 232 | 201 | |||||||||
| Other regulatory assets, deferred | 317 | 388 | |||||||||
| Accumulated deferred income taxes | 118 | 129 | |||||||||
| Other deferred charges and assets | 100 | 55 | |||||||||
| Total deferred charges and other assets | 877 | 805 | |||||||||
| Total Assets | $ | 5,080 | $ | 4,912 |
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Mississippi Power Company 2021 Annual Report
| Liabilities and Stockholder's Equity | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 1 | $ | 406 | |||||||
| Notes payable | — | 25 | |||||||||
| Accounts payable — | |||||||||||
| Affiliated | 81 | 63 | |||||||||
| Other | 47 | 109 | |||||||||
| Accrued taxes | 120 | 114 | |||||||||
| Accrued interest | 16 | 15 | |||||||||
| Accrued compensation | 36 | 34 | |||||||||
| Asset retirement obligations | 30 | 27 | |||||||||
| Over recovered regulatory clause liabilities | — | 34 | |||||||||
| Other regulatory liabilities | 59 | 49 | |||||||||
| Other current liabilities | 49 | 40 | |||||||||
| Total current liabilities | 439 | 916 | |||||||||
| Long-Term Debt | 1,510 | 1,013 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 464 | 447 | |||||||||
| Deferred credits related to income taxes | 269 | 287 | |||||||||
| Employee benefit obligations | 88 | 113 | |||||||||
| Asset retirement obligations, deferred | 160 | 150 | |||||||||
| Other cost of removal obligations | 195 | 194 | |||||||||
| Other regulatory liabilities, deferred | 64 | 15 | |||||||||
| Other deferred credits and liabilities | 24 | 35 | |||||||||
| Total deferred credits and other liabilities | 1,264 | 1,241 | |||||||||
| Total Liabilities | 3,213 | 3,170 | |||||||||
| Common Stockholder's Equity: | |||||||||||
| Common stock, without par value (Authorized and outstanding - 1 million shares) | 38 | 38 | |||||||||
| Paid-in capital | 4,582 | 4,460 | |||||||||
| Accumulated deficit | (2,753) | (2,754) | |||||||||
| Accumulated other comprehensive loss | — | (2) | |||||||||
| Total common stockholder's equity (See accompanying statements) | 1,867 | 1,742 | |||||||||
| Total Liabilities and Stockholder's Equity | $ | 5,080 | $ | 4,912 | |||||||
| 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, 2021, 2020, and 2019
Mississippi Power Company 2021 Annual Report
| 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, 2018 | 1 | $ | 38 | $ | 4,546 | $ | (2,971) | $ | (4) | $ | 1,609 | ||||||||||||||||||||||||
| Net income | — | — | — | 139 | — | 139 | |||||||||||||||||||||||||||||
| Return of capital to parent company | — | — | (150) | — | — | (150) | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 53 | — | — | 53 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 1 | 1 | |||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 1 | 38 | 4,449 | (2,832) | (3) | 1,652 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 152 | — | 152 | |||||||||||||||||||||||||||||
| Return of capital to parent company | — | — | (74) | — | — | (74) | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 86 | — | — | 86 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 1 | 1 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (74) | — | (74) | |||||||||||||||||||||||||||||
| Other | — | — | (1) | — | — | (1) | |||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 1 | 38 | 4,460 | (2,754) | (2) | 1,742 | |||||||||||||||||||||||||||||
| Net income | — | — | — | 159 | — | 159 | |||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 122 | — | — | 122 | |||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 1 | 1 | |||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (157) | — | (157) | |||||||||||||||||||||||||||||
| Other | — | — | — | (1) | 1 | — | |||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 1 | $ | 38 | $ | 4,582 | $ | (2,753) | $ | — | $ | 1,867 |
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, 2021 and 2020, 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, 2021, and the related notes (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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 our 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 is relates.
Income/Loss Allocation to Noncontrolling Interests – Refer to Notes 1 and 7 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.
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.
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How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures included the following, among others:
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For agreements that result in potentially material allocations of partnership income or loss, we read the agreements to understand the liquidation provisions and the provisions governing the allocation of benefits.
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We evaluated the 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 16, 2022
We have served as Southern Power's auditor since 2002.
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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020, and 2019
Southern Power Company and Subsidiary Companies 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Revenues: | |||||||||||||||||
| Wholesale revenues, non-affiliates | $ | 1,671 | $ | 1,355 | $ | 1,528 | |||||||||||
| Wholesale revenues, affiliates | 515 | 364 | 398 | ||||||||||||||
| Other revenues | 30 | 14 | 12 | ||||||||||||||
| Total operating revenues | 2,216 | 1,733 | 1,938 | ||||||||||||||
| Operating Expenses: | |||||||||||||||||
| Fuel | 802 | 470 | 577 | ||||||||||||||
| Purchased power | 139 | 74 | 108 | ||||||||||||||
| Other operations and maintenance | 423 | 353 | 362 | ||||||||||||||
| Depreciation and amortization | 517 | 494 | 479 | ||||||||||||||
| Taxes other than income taxes | 45 | 39 | 40 | ||||||||||||||
| Loss on sales-type leases | 40 | — | — | ||||||||||||||
| Gain on dispositions, net | (41) | (39) | (23) | ||||||||||||||
| Total operating expenses | 1,925 | 1,391 | 1,543 | ||||||||||||||
| Operating Income | 291 | 342 | 395 | ||||||||||||||
| Other Income and (Expense): | |||||||||||||||||
| Interest expense, net of amounts capitalized | (147) | (151) | (169) | ||||||||||||||
| Other income (expense), net | 10 | 19 | 47 | ||||||||||||||
| Total other income and (expense) | (137) | (132) | (122) | ||||||||||||||
| Earnings Before Income Taxes | 154 | 210 | 273 | ||||||||||||||
| Income taxes (benefit) | (13) | 3 | (56) | ||||||||||||||
| Net Income | 167 | 207 | 329 | ||||||||||||||
| Net loss attributable to noncontrolling interests | (99) | (31) | (10) | ||||||||||||||
| Net Income Attributable to Southern Power | $ | 266 | $ | 238 | $ | 339 |
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, 2021, 2020, and 2019
Southern Power Company and Subsidiary Companies 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Net Income | $ | 167 | $ | 207 | $ | 329 | |||||||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Qualifying hedges: | |||||||||||||||||
| Changes in fair value, net of tax of $(22), $12, and $(22), respectively | (67) | 33 | (66) | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $30, $(22), and $14, respectively | 89 | (65) | 41 | ||||||||||||||
| Pension and other postretirement benefit plans: | |||||||||||||||||
| Benefit plan net gain (loss), net of tax of $5, $(4), and $(6), respectively | 16 | (12) | (17) | ||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $1, $1, and $—, respectively | 2 | 2 | — | ||||||||||||||
| Total other comprehensive income (loss) | 40 | (42) | (42) | ||||||||||||||
| Comprehensive loss attributable to noncontrolling interests | (99) | (31) | (10) | ||||||||||||||
| Comprehensive Income Attributable to Southern Power | $ | 306 | $ | 196 | $ | 297 |
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, 2021, 2020, and 2019
Southern Power Company and Subsidiary Companies 2021 Annual Report
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Operating Activities: | |||||||||||||||||
| Net income | $ | 167 | $ | 207 | $ | 329 | |||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | |||||||||||||||||
| Depreciation and amortization, total | 542 | 519 | 505 | ||||||||||||||
| Deferred income taxes | 55 | (25) | (74) | ||||||||||||||
| Utilization of federal investment tax credits | 288 | 340 | 734 | ||||||||||||||
| Amortization of investment tax credits | (58) | (59) | (151) | ||||||||||||||
| Income taxes receivable, non-current | 5 | (20) | 25 | ||||||||||||||
| Pension and postretirement funding | — | — | (24) | ||||||||||||||
| Gain on dispositions, net | (41) | (39) | (24) | ||||||||||||||
| Loss on sales-type leases | 40 | — | — | ||||||||||||||
| Other, net | (6) | (5) | (6) | ||||||||||||||
| Changes in certain current assets and liabilities — | |||||||||||||||||
| -Receivables | (44) | (4) | 72 | ||||||||||||||
| -Prepaid income taxes | (16) | 20 | 39 | ||||||||||||||
| -Other current assets | (14) | (30) | (8) | ||||||||||||||
| -Accrued taxes | (6) | 11 | 6 | ||||||||||||||
| -Other current liabilities | 39 | (14) | (38) | ||||||||||||||
| Net cash provided from operating activities | 951 | 901 | 1,385 | ||||||||||||||
| Investing Activities: | |||||||||||||||||
| Business acquisitions, net of cash acquired | (345) | (81) | (50) | ||||||||||||||
| Property additions | (396) | (223) | (489) | ||||||||||||||
| Change in construction payables | (15) | 31 | 7 | ||||||||||||||
| Investment in unconsolidated subsidiaries | — | — | (116) | ||||||||||||||
| Proceeds from dispositions | 24 | 666 | 572 | ||||||||||||||
| Payments pursuant to LTSAs | (82) | (76) | (104) | ||||||||||||||
| Other investing activities | 11 | 57 | 13 | ||||||||||||||
| Net cash provided from (used for) investing activities | (803) | 374 | (167) | ||||||||||||||
| Financing Activities: | |||||||||||||||||
| Increase (decrease) in notes payable, net | 36 | (274) | 449 | ||||||||||||||
| Proceeds — | |||||||||||||||||
| Senior notes | 400 | — | — | ||||||||||||||
| Short-term borrowings | — | — | 100 | ||||||||||||||
| Redemptions — | |||||||||||||||||
| Senior notes | (300) | (825) | (600) | ||||||||||||||
| Short-term borrowings | — | (100) | (100) | ||||||||||||||
| Capital contributions from parent company | 8 | 6 | 64 | ||||||||||||||
| Return of capital to parent company | (271) | — | (755) | ||||||||||||||
| Capital contributions from noncontrolling interests | 501 | 363 | 196 | ||||||||||||||
| Distributions to noncontrolling interests | (351) | (271) | (256) | ||||||||||||||
| Purchase of membership interests from noncontrolling interests | — | (60) | — | ||||||||||||||
| Payment of common stock dividends | (204) | (201) | (206) | ||||||||||||||
| Other financing activities | (14) | (10) | (12) | ||||||||||||||
| Net cash used for financing activities | (195) | (1,372) | (1,120) | ||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | (47) | (97) | 98 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 182 | 279 | 181 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 135 | $ | 182 | $ | 279 | |||||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||
| Cash paid (received) during the period for — | |||||||||||||||||
| Interest (net of $6, $11, and $15 capitalized, respectively) | $ | 140 | $ | 147 | $ | 167 | |||||||||||
| Income taxes, net | (275) | (283) | (664) | ||||||||||||||
| Noncash transactions — | |||||||||||||||||
| Accrued property additions at year-end | 72 | 89 | 57 | ||||||||||||||
| Contributions from noncontrolling interests | 89 | 12 | 80 | ||||||||||||||
| Contributions of wind turbine equipment | 82 | 17 | 26 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Power Company and Subsidiary Companies 2021 Annual Report
| Assets | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Assets: | |||||||||||
| Cash and cash equivalents | $ | 107 | $ | 182 | |||||||
| Receivables — | |||||||||||
| Customer accounts | 139 | 125 | |||||||||
| Affiliated | 51 | 37 | |||||||||
| Other | 29 | 27 | |||||||||
| Materials and supplies | 106 | 157 | |||||||||
| Prepaid income taxes | 27 | 11 | |||||||||
| Other current assets | 46 | 36 | |||||||||
| Total current assets | 505 | 575 | |||||||||
| Property, Plant, and Equipment: | |||||||||||
| In service | 14,585 | 13,904 | |||||||||
| Less: Accumulated provision for depreciation | 3,241 | 2,842 | |||||||||
| Plant in service, net of depreciation | 11,344 | 11,062 | |||||||||
| Construction work in progress | 45 | 127 | |||||||||
| Total property, plant, and equipment | 11,389 | 11,189 | |||||||||
| Other Property and Investments: | |||||||||||
| Intangible assets, net of amortization of $109 and $89, respectively | 282 | 302 | |||||||||
| Equity investments in unconsolidated subsidiaries | 86 | 19 | |||||||||
| Net investment in sales-type leases | 161 | — | |||||||||
| Total other property and investments | 529 | 321 | |||||||||
| Deferred Charges and Other Assets: | |||||||||||
| Operating lease right-of-use assets, net of amortization | 479 | 415 | |||||||||
| Prepaid LTSAs | 210 | 155 | |||||||||
| Accumulated deferred income taxes | — | 262 | |||||||||
| Income taxes receivable, non-current | 20 | 25 | |||||||||
| Other deferred charges and assets | 258 | 293 | |||||||||
| Total deferred charges and other assets | 967 | 1,150 | |||||||||
| Total Assets | $ | 13,390 | $ | 13,235 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Power Company and Subsidiary Companies 2021 Annual Report
| Liabilities and Stockholders' Equity | 2021 | 2020 | |||||||||
| (in millions) | |||||||||||
| Current Liabilities: | |||||||||||
| Securities due within one year | $ | 679 | $ | 299 | |||||||
| Notes payable | 211 | 175 | |||||||||
| Accounts payable — | |||||||||||
| Affiliated | 92 | 65 | |||||||||
| Other | 85 | 92 | |||||||||
| Accrued taxes | 14 | 30 | |||||||||
| Accrued interest | 32 | 32 | |||||||||
| Other current liabilities | 140 | 132 | |||||||||
| Total current liabilities | 1,253 | 825 | |||||||||
| Long-Term Debt | 3,009 | 3,393 | |||||||||
| Deferred Credits and Other Liabilities: | |||||||||||
| Accumulated deferred income taxes | 215 | 123 | |||||||||
| Accumulated deferred ITCs | 1,614 | 1,672 | |||||||||
| Operating lease obligations | 497 | 426 | |||||||||
| Other deferred credits and liabilities | 204 | 165 | |||||||||
| Total deferred credits and other liabilities | 2,530 | 2,386 | |||||||||
| Total Liabilities | 6,792 | 6,604 | |||||||||
| Common Stockholder's Equity: | |||||||||||
| Common stock, par value $0.01 per share (Authorized - 1.0 million shares; Outstanding - 1,000 shares) | — | — | |||||||||
| Paid-in capital | 638 | 914 | |||||||||
| Retained earnings | 1,585 | 1,522 | |||||||||
| Accumulated other comprehensive loss | (27) | (67) | |||||||||
| Total common stockholder's equity | 2,196 | 2,369 | |||||||||
| Noncontrolling Interests | 4,402 | 4,262 | |||||||||
| Total Stockholders' Equity (See accompanying statements) | 6,598 | 6,631 | |||||||||
| Total Liabilities and Stockholders' Equity | $ | 13,390 | $ | 13,235 | |||||||
| 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, 2021, 2020, and 2019
Southern Power Company and Subsidiary Companies 2021 Annual Report
| 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, 2018 | — | $ | — | $ | 1,600 | $ | 1,352 | $ | 16 | $ | 2,968 | $ | 4,316 | $ | 7,284 | ||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | 339 | — | 339 | (10) | 329 | |||||||||||||||||||||||||||||||||||||||
| Return of capital to parent company | — | — | (755) | — | — | (755) | — | (755) | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 64 | — | — | 64 | — | 64 | |||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | (42) | (42) | — | (42) | |||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (206) | — | (206) | — | (206) | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from noncontrolling interests | — | — | — | — | — | — | 276 | 276 | |||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (327) | (327) | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | — | — | (1) | (1) | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | — | — | 909 | 1,485 | (26) | 2,368 | 4,254 | 6,622 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | 238 | — | 238 | (31) | 207 | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 2 | — | — | 2 | — | 2 | |||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | (42) | (42) | — | (42) | |||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (201) | — | (201) | — | (201) | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from noncontrolling interests | — | — | — | — | — | — | 307 | 307 | |||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (271) | (271) | |||||||||||||||||||||||||||||||||||||||
| Purchase of membership interests from noncontrolling interests | — | — | 5 | — | — | 5 | (65) | (60) | |||||||||||||||||||||||||||||||||||||||
| Sale of noncontrolling interests(*) | — | — | (2) | — | — | (2) | 67 | 65 | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | 1 | 1 | 1 | 2 | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | — | — | 914 | 1,522 | (67) | 2,369 | 4,262 | 6,631 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | 266 | — | 266 | (99) | 167 | |||||||||||||||||||||||||||||||||||||||
| Return of capital to parent company | — | — | (271) | — | — | (271) | — | (271) | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 10 | — | — | 10 | — | 10 | |||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 40 | 40 | — | 40 | |||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (204) | — | (204) | — | (204) | |||||||||||||||||||||||||||||||||||||||
| Capital contributions from noncontrolling interests | — | — | — | — | — | — | 590 | 590 | |||||||||||||||||||||||||||||||||||||||
| Distributions to noncontrolling interests | — | — | — | — | — | — | (351) | (351) | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | (15) | 1 | — | (14) | — | (14) | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | — | $ | — | $ | 638 | $ | 1,585 | $ | (27) | $ | 2,196 | $ | 4,402 | $ | 6,598 |
(*)See Note 15 under "Southern Power" 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, 2021 and 2020, 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, 2021, and the related notes (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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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 $1,129 million and $1,167 million as of December 31, 2021 and December 31, 2020, respectively, and its earnings from its equity method investment in SNG of $127 million, $129 million, and $141 million for the years ended December 31, 2021, 2020, and 2019, respectively. Those statements were audited by other auditors 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 our 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"), which represent approximately 84% of Southern Company Gas' consolidated revenues, are subject to rate regulation in Georgia, Illinois, Tennessee, and Virginia by their respective state Public Service Commission or other applicable state regulatory agencies (collectively, the "Commissions"). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, including, but not limited to,
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property, plant, and equipment; other regulatory assets; other regulatory liabilities; other cost of removal obligations; deferred charges and credits related to income taxes; operating revenues; other operations and maintenance expenses; and depreciation and amortization.
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 by 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 that investment.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. 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. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions 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 costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
-
We read relevant regulatory orders issued by the Commissions for Southern Company Gas' regulated utility subsidiaries in Georgia, Illinois, Tennessee, and Virginia, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.
-
For regulatory matters in process, we inspected filings with the Commissions by the regulated utility subsidiaries and other interested parties that may impact the regulated utility subsidiaries' future rates for any evidence that might contradict management's assertions.
-
We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
-
We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable of recovery 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.
/s/ Deloitte & Touche LLP
Atlanta, Georgia
February 16, 2022
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, LLC (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of income, members' equity, and cash flows for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) 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 Benefit Obligation
At December 31, 2021, the Company's postretirement benefit obligation was $19 million and the Company's plan assets were $73 million, resulting in a net asset position of $54 million. As described in Note 5 of the consolidated financial statements, the postretirement benefit obligation is primarily based on actuarial calculations, which include various significant assumptions.
We identified the Company's estimate of the postretirement benefit obligation as a critical audit matter. Auditing the postretirement benefit obligation required complex auditor judgment due to the highly judgmental nature of the actuarial assumptions used in the calculation, which include the discount rate and the expected return on plan assets. These assumptions had a significant effect on the postretirement benefit obligation calculation.
The primary procedures we performed to address this critical audit matter included:
-
Comparing the actuarial assumptions used by management with historical trends and evaluating the change in the postretirement benefit obligation from prior year due to changes in assumptions.
-
Evaluating the appropriateness of management's methodology for determining the discount rate that reflects the maturity and duration of the benefit payments.
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Evaluating the expected return on plan assets by assessing whether management's assumptions were consistent with a range of returns for a portfolio of comparative investments that was determined based on publicly available information.
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, LLP
We have served as the Company's auditor since 2018.
Houston, Texas
February 7, 2022
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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020, and 2019
Southern Company Gas and Subsidiary Companies 2021 Annual Report
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Operating Revenues: | ||||||||||||||||||||
| Natural gas revenues (includes revenue taxes of $122, $107, and $117, respectively) | $ | 4,369 | $ | 3,431 | $ | 3,793 | ||||||||||||||
| Alternative revenue programs | 11 | 3 | (1) | |||||||||||||||||
| Total operating revenues | 4,380 | 3,434 | 3,792 | |||||||||||||||||
| Operating Expenses: | ||||||||||||||||||||
| Cost of natural gas | 1,619 | 972 | 1,319 | |||||||||||||||||
| Other operations and maintenance | 1,072 | 966 | 888 | |||||||||||||||||
| Depreciation and amortization | 536 | 500 | 487 | |||||||||||||||||
| Taxes other than income taxes | 225 | 206 | 213 | |||||||||||||||||
| Impairment charges | — | — | 115 | |||||||||||||||||
| Gain on dispositions, net | (127) | (22) | — | |||||||||||||||||
| Total operating expenses | 3,325 | 2,622 | 3,022 | |||||||||||||||||
| Operating Income | 1,055 | 812 | 770 | |||||||||||||||||
| Other Income and (Expense): | ||||||||||||||||||||
| Earnings from equity method investments | 50 | 141 | 157 | |||||||||||||||||
| Interest expense, net of amounts capitalized | (238) | (231) | (232) | |||||||||||||||||
| Other income (expense), net | (53) | 41 | 20 | |||||||||||||||||
| Total other income and (expense) | (241) | (49) | (55) | |||||||||||||||||
| Earnings Before Income Taxes | 814 | 763 | 715 | |||||||||||||||||
| Income taxes | 275 | 173 | 130 | |||||||||||||||||
| Net Income | $ | 539 | $ | 590 | $ | 585 |
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, 2021, 2020, and 2019
Southern Company Gas and Subsidiary Companies 2021 Annual Report
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Net Income | $ | 539 | $ | 590 | $ | 585 | ||||||||||||||
| Other comprehensive income (loss): | ||||||||||||||||||||
| Qualifying hedges: | ||||||||||||||||||||
| Changes in fair value, net of tax of $5, $(8), and $(2), respectively | 17 | (21) | (5) | |||||||||||||||||
| Reclassification adjustment for amounts included in net income, net of tax of $(5), $3, and $—, respectively | (11) | 7 | 2 | |||||||||||||||||
| Pension and other postretirement benefit plans: | ||||||||||||||||||||
| Benefit plan net gain (loss), net of tax of $17, $(3), and $(14), respectively | 40 | (15) | (16) | |||||||||||||||||
| Total other comprehensive income (loss) | 46 | (29) | (19) | |||||||||||||||||
| Comprehensive Income | $ | 585 | $ | 561 | $ | 566 |
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, 2021, 2020, and 2019
Southern Company Gas and Subsidiary Companies 2021 Annual Report
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Operating Activities: | ||||||||||||||||||||
| Consolidated net income | $ | 539 | $ | 590 | $ | 585 | ||||||||||||||
| Adjustments to reconcile net income to net cash provided from operating activities — | ||||||||||||||||||||
| Depreciation and amortization, total | 536 | 500 | 487 | |||||||||||||||||
| Deferred income taxes | 259 | 56 | 213 | |||||||||||||||||
| Pension and postretirement funding | — | — | (145) | |||||||||||||||||
| Impairment charges | 84 | — | 115 | |||||||||||||||||
| Gain on dispositions, net | (127) | (22) | — | |||||||||||||||||
| Mark-to-market adjustments | 194 | 61 | (56) | |||||||||||||||||
| Natural gas cost under recovery – long-term | (207) | — | — | |||||||||||||||||
| Other, net | (30) | (29) | (55) | |||||||||||||||||
| Changes in certain current assets and liabilities — | ||||||||||||||||||||
| -Receivables | (143) | (93) | 467 | |||||||||||||||||
| -Natural gas for sale | 8 | 18 | 44 | |||||||||||||||||
| -Prepaid income taxes | (82) | 19 | 40 | |||||||||||||||||
| -Natural gas cost under recovery | (266) | — | — | |||||||||||||||||
| -Other current assets | (116) | (10) | 31 | |||||||||||||||||
| -Accounts payable | 40 | 103 | (520) | |||||||||||||||||
| -Accrued taxes | 45 | 13 | (69) | |||||||||||||||||
| -Accrued compensation | 23 | 7 | 1 | |||||||||||||||||
| -Other current liabilities | (94) | (6) | (71) | |||||||||||||||||
| Net cash provided from operating activities | 663 | 1,207 | 1,067 | |||||||||||||||||
| Investing Activities: | ||||||||||||||||||||
| Property additions | (1,421) | (1,471) | (1,408) | |||||||||||||||||
| Cost of removal, net of salvage | (106) | (100) | (82) | |||||||||||||||||
| Change in construction payables, net | (29) | 20 | 24 | |||||||||||||||||
| Investments in unconsolidated subsidiaries | (5) | (79) | (31) | |||||||||||||||||
| Returned investment in unconsolidated subsidiaries | 22 | 13 | 67 | |||||||||||||||||
| Proceeds from dispositions | 150 | 211 | 32 | |||||||||||||||||
| Other investing activities | 10 | (11) | 12 | |||||||||||||||||
| Net cash used for investing activities | (1,379) | (1,417) | (1,386) | |||||||||||||||||
| Financing Activities: | ||||||||||||||||||||
| Increase (decrease) in notes payable, net | 585 | (326) | — | |||||||||||||||||
| Proceeds — | ||||||||||||||||||||
| Senior notes | 450 | 500 | — | |||||||||||||||||
| Short-term borrowings | 300 | — | — | |||||||||||||||||
| First mortgage bonds | 200 | 325 | 300 | |||||||||||||||||
| Redemptions and repurchases — | ||||||||||||||||||||
| Senior notes | (300) | — | (300) | |||||||||||||||||
| Medium-term notes | (30) | — | — | |||||||||||||||||
| First mortgage bonds | — | — | (50) | |||||||||||||||||
| Capital contributions from parent company | 72 | 216 | 821 | |||||||||||||||||
| Payment of common stock dividends | (530) | (533) | (471) | |||||||||||||||||
| Other financing activities | (2) | (2) | (2) | |||||||||||||||||
| Net cash provided from financing activities | 745 | 180 | 298 | |||||||||||||||||
| Net Change in Cash, Cash Equivalents, and Restricted Cash | 29 | (30) | (21) | |||||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at Beginning of Year | 19 | 49 | 70 | |||||||||||||||||
| Cash, Cash Equivalents, and Restricted Cash at End of Year | $ | 48 | $ | 19 | $ | 49 | ||||||||||||||
| Supplemental Cash Flow Information: | ||||||||||||||||||||
| Cash paid (received) during the period for — | ||||||||||||||||||||
| Interest (net of $8, $7, and $6 capitalized, respectively) | $ | 244 | $ | 232 | $ | 251 | ||||||||||||||
| Income taxes, net | 57 | 25 | (41) | |||||||||||||||||
| Noncash transactions — Accrued property additions at year-end | 113 | 142 | 122 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Company Gas and Subsidiary Companies 2021 Annual Report
| Assets | 2021 | 2020 | ||||||||||||
| (in millions) | ||||||||||||||
| Current Assets: | ||||||||||||||
| Cash and cash equivalents | $ | 45 | $ | 17 | ||||||||||
| Receivables — | ||||||||||||||
| Energy marketing | — | 516 | ||||||||||||
| Customer accounts | 462 | 353 | ||||||||||||
| Unbilled revenues | 278 | 219 | ||||||||||||
| Other accounts and notes | 49 | 55 | ||||||||||||
| Accumulated provision for uncollectible accounts | (39) | (40) | ||||||||||||
| Natural gas for sale | 362 | 460 | ||||||||||||
| Prepaid expenses | 114 | 48 | ||||||||||||
| Assets from risk management activities, net of collateral | 33 | 118 | ||||||||||||
| Natural gas cost under recovery | 266 | — | ||||||||||||
| Other regulatory assets | 136 | 102 | ||||||||||||
| Other current assets | 49 | 38 | ||||||||||||
| Total current assets | 1,755 | 1,886 | ||||||||||||
| Property, Plant, and Equipment: | ||||||||||||||
| In service | 18,880 | 17,611 | ||||||||||||
| Less: Accumulated depreciation | 5,067 | 4,821 | ||||||||||||
| Plant in service, net of depreciation | 13,813 | 12,790 | ||||||||||||
| Construction work in progress | 684 | 648 | ||||||||||||
| Total property, plant, and equipment | 14,497 | 13,438 | ||||||||||||
| Other Property and Investments: | ||||||||||||||
| Goodwill | 5,015 | 5,015 | ||||||||||||
| Equity investments in unconsolidated subsidiaries | 1,173 | 1,290 | ||||||||||||
| Other intangible assets, net of amortization of $145 and $195, respectively | 37 | 51 | ||||||||||||
| Miscellaneous property and investments | 19 | 19 | ||||||||||||
| Total other property and investments | 6,244 | 6,375 | ||||||||||||
| Deferred Charges and Other Assets: | ||||||||||||||
| Operating lease right-of-use assets, net of amortization | 70 | 81 | ||||||||||||
| Prepaid pension costs | 175 | 70 | ||||||||||||
| Other regulatory assets, deferred | 689 | 615 | ||||||||||||
| Other deferred charges and assets | 130 | 165 | ||||||||||||
| Total deferred charges and other assets | 1,064 | 931 | ||||||||||||
| Total Assets | $ | 23,560 | $ | 22,630 |
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Company Gas and Subsidiary Companies 2021 Annual Report
| Liabilities and Stockholder's Equity | 2021 | 2020 | ||||||||||||
| (in millions) | ||||||||||||||
| Current Liabilities: | ||||||||||||||
| Securities due within one year | $ | 47 | $ | 333 | ||||||||||
| Notes payable | 1,209 | 324 | ||||||||||||
| Energy marketing trade payables | — | 494 | ||||||||||||
| Accounts payable — | ||||||||||||||
| Affiliated | 58 | 56 | ||||||||||||
| Other | 361 | 373 | ||||||||||||
| Customer deposits | 95 | 90 | ||||||||||||
| Accrued taxes | 124 | 83 | ||||||||||||
| Accrued interest | 59 | 58 | ||||||||||||
| Accrued compensation | 110 | 106 | ||||||||||||
| Other regulatory liabilities | 8 | 122 | ||||||||||||
| Other current liabilities | 155 | 150 | ||||||||||||
| Total current liabilities | 2,226 | 2,189 | ||||||||||||
| Long-term Debt | 6,855 | 6,293 | ||||||||||||
| Deferred Credits and Other Liabilities: | ||||||||||||||
| Accumulated deferred income taxes | 1,555 | 1,265 | ||||||||||||
| Deferred credits related to income taxes | 816 | 847 | ||||||||||||
| Employee benefit obligations | 176 | 283 | ||||||||||||
| Operating lease obligations | 59 | 67 | ||||||||||||
| Other cost of removal obligations | 1,683 | 1,649 | ||||||||||||
| Accrued environmental remediation | 197 | 216 | ||||||||||||
| Other deferred credits and liabilities | 77 | 54 | ||||||||||||
| Total deferred credits and other liabilities | 4,563 | 4,381 | ||||||||||||
| Total Liabilities | 13,644 | 12,863 | ||||||||||||
| Common Stockholder’s Equity: | ||||||||||||||
| Common stock, par value $0.01 per share (Authorized - 100 million shares; Outstanding - 100 shares) | ||||||||||||||
| Paid-in capital | 10,024 | 9,930 | ||||||||||||
| Accumulated deficit | (132) | (141) | ||||||||||||
| Accumulated other comprehensive income (loss) | 24 | (22) | ||||||||||||
| Total common stockholder's equity (See accompanying statements) | 9,916 | 9,767 | ||||||||||||
| Total Liabilities and Stockholder's Equity | $ | 23,560 | $ | 22,630 | ||||||||||
| 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, 2021, 2020, and 2019
Southern Company Gas and Subsidiary Companies 2021 Annual Report
| 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, 2018 | — | $ | — | $ | 8,856 | $ | (312) | $ | 26 | $ | 8,570 | |||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | 585 | — | 585 | ||||||||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 841 | — | — | 841 | ||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | (19) | (19) | ||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (471) | — | (471) | ||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | — | — | 9,697 | (198) | 7 | 9,506 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | 590 | — | 590 | ||||||||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 233 | — | — | 233 | ||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | (29) | (29) | ||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (533) | — | (533) | ||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | — | — | 9,930 | (141) | (22) | 9,767 | ||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | 539 | — | 539 | ||||||||||||||||||||||||||||||||||||||||||||
| Capital contributions from parent company | — | — | 94 | — | — | 94 | ||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 46 | 46 | ||||||||||||||||||||||||||||||||||||||||||||
| Cash dividends on common stock | — | — | — | (530) | — | (530) | ||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | — | $ | — | $ | 10,024 | $ | (132) | $ | 24 | $ | 9,916 |
The accompanying notes are an integral part of these consolidated financial statements.
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COMBINED NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2021 Annual Report
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 list below indicates the Registrants to which each note applies.
| Registrant | Applicable Notes | ||||
| Southern Company | 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16 | ||||
| Alabama Power | 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15 | ||||
| Georgia Power | 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14 | ||||
| Mississippi Power | 1, 2, 3, 4, 5, 6, 8, 9, 10, 11, 12, 13, 14 | ||||
| Southern Power | 1, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15 | ||||
| Southern Company Gas | 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16 |
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
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, and manages power generation assets, including renewable energy 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. Prior to the sale of Sequent on July 1, 2021, these businesses also included wholesale gas 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. 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 Plant Hatch and Plant Vogtle Units 1 and 2, and is currently managing construction and start-up of Plant Vogtle Units 3 and 4, which are co-owned by Georgia Power. PowerSecure develops distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers. See Note 15 for information regarding the sale of Sequent.
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 a 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 March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (ASU 2020-04) providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR, which began phasing out on December 31, 2021. The amendments in ASU 2020-04 are elective and apply to all entities that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued. The new guidance (i) simplifies accounting analyses under current GAAP for contract modifications; (ii) simplifies the assessment of hedge effectiveness and allows hedging relationships affected by reference rate reform to continue; and (iii) allows a one-time election to sell or transfer debt securities classified as held to maturity that reference a rate affected by reference rate reform. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2022 by accounting topic. The Registrants have elected to apply the amendments to modifications of debt arrangements that meet the scope of ASU 2020-04.
The Registrants currently reference LIBOR for certain debt and hedging arrangements. In addition, certain provisions in PPAs at Southern Power include references to LIBOR. Contract language has been, or is expected to be, incorporated into each of these agreements to address the transition to an alternative rate for agreements that will be in place at the transition date. While no material impacts are expected from modifications to the arrangements and effective hedging relationships are expected to
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
continue, the Registrants will continue to evaluate the provisions of ASU 2020–04 and the impacts of transitioning to an alternative rate, and the ultimate outcome of the transition cannot be determined at this time. See Note 14 under "Interest Rate Derivatives" for additional information.
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 2021, 2020, and 2019 were as follows:
| Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| 2021 | $ | 504 | $ | 663 | $ | 120 | $ | 89 | $ | 239 | |||||||
| 2020 | 478 | 639 | 149 | 87 | 237 | ||||||||||||
| 2019 | 527 | 704 | 118 | 90 | 183 |
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; other services with respect to business and operations; and, for Georgia Power, construction management. These costs are primarily included in other operations and maintenance expenses or capitalized to property, plant, and equipment. Costs for these services in 2021, 2020, and 2019 amounted to $258 million, $262 million, and $256 million, respectively, for Alabama Power and $906 million, $883 million, and $760 million, respectively, for Georgia Power. See Note 2 under "Georgia Power – Nuclear Construction" for additional information regarding Southern Nuclear's construction management of Plant Vogtle Units 3 and 4 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) | ||||||||
| 2021 | $ | 9 | $ | 15 | ||||
| 2020 | 4 | 8 | ||||||
| 2019 | 3 | 14 |
Georgia Power has entered into several PPAs with Southern Power for capacity and energy. Georgia Power's total expenses associated with these PPAs were $132 million, $141 million, and $177 million in 2021, 2020, and 2019, respectively. Southern Power's total revenues from all PPAs with Georgia Power, included in wholesale revenue affiliates on Southern Power's consolidated statements of income, were $139 million, $139 million, and $174 million for 2021, 2020, and 2019, respectively. Included within these revenues were affiliate PPAs accounted for as operating leases, which totaled $112 million, $115 million, and $116 million for 2021, 2020, and 2019, respectively. See Note 9 for additional information.
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SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and 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 – Equity Method Investments" for additional information. Transportation costs under these agreements in 2021, 2020, and 2019 were as follows:
| Alabama Power | Georgia Power | Southern Power | Southern Company Gas | |||||||||||
| (in millions) | ||||||||||||||
| 2021 | $ | 14 | $ | 108 | $ | 31 | $ | 29 | ||||||
| 2020 | 15 | 108 | 29 | 29 | ||||||||||
| 2019 | 17 | 99 | 28 | 31 |
In 2018, SNG purchased the natural gas lateral pipeline serving Plant McDonough Units 4 through 6 from Georgia Power at net book value, as approved by the Georgia PSC. In 2020, SNG paid Georgia Power $142 million, which included $71 million contributed to SNG by Southern Company Gas for its proportionate share. During the interim period, Georgia Power received a discounted shipping rate to reflect the deferred consideration and SNG constructed an extension to the pipeline.
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, and Mississippi Power for all periods presented and $18 million, $26 million, and $64 million for Southern Power in 2021, 2020, and 2019, respectively.
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 $10 million, $9 million, and $9 million in 2021, 2020, and 2019, respectively. See Note 5 under "Joint Ownership Agreements" for additional information.
Alabama Power and Georgia Power each have agreements with PowerSecure for equipment purchases and/or services related to utility infrastructure construction, distributed energy, and energy efficiency projects. Costs under these agreements were immaterial for all periods presented.
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 $28 million, $15 million, and $15 million for 2021, 2020, and 2019, 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 accrued at the end of each fiscal 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, non-derivatives, or normal sale derivatives. 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
Gas Distribution Operations
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. 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.
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.
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 Company Gas recognizes revenue as the performance obligations are satisfied over time as natural gas is delivered to the customer. The performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer.
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.
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. 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 and for all wholesale customers, revenues are based on actual deliveries through the end of the period.
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. These programs are as follows:
-
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 (effective November 1, 2019); 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.
Wholesale Gas Services
Prior to the sale of Sequent on July 1, 2021, Southern Company Gas netted revenues from energy and risk management activities with the associated costs. Profits from sales between segments were eliminated and recognized as goods or services sold to end-use customers. Southern Company Gas recorded wholesale gas services' transactions that qualified as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains
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and losses on derivatives held for energy trading purposes were presented on a net basis in revenue. See Note 15 under "Southern Company Gas" for additional information on the sale of Sequent.
Gas Marketing Services
Southern Company Gas recognizes revenues from natural gas sales and transportation services in the same period in which the related volumes are delivered to customers and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. Southern Company Gas also recognizes unbilled revenues for estimated deliveries of gas not yet billed to these customers from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period.
Southern Company Gas recognizes revenues on 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 full requirements cost-based MRA electric tariffs described below), Southern Power, and Southern Company Gas each have a diversified base of customers and no single customer or industry 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 under full requirements cost-based MRA electric tariffs, which are subject to regulation by the FERC. The contracts with these wholesale customers represented 14.3% of Mississippi Power's total operating revenues in 2021 and are generally subject to 10-year rolling cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
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, adjustments to reduce the value of inventories to market value, 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. In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies are deferred and amortized over the average life of the related property, with such amortization normally applied as a credit to reduce depreciation and amortization in the statements of income. Southern Power's and the natural gas distribution utilities' deferred federal ITCs, as well as certain state ITCs for Nicor Gas, are deferred and amortized to income tax expense over the life of the respective asset.
Under current tax law, certain projects at Southern Power related to the construction of renewable facilities are eligible for federal ITCs. Southern Power estimates eligible costs which, as they relate to acquisitions, may not be finalized until the allocation of the purchase price to assets has been finalized. Southern Power applies the deferred method to ITCs, whereby the ITCs are recorded as a deferred credit and amortized to income tax expense over the life of the respective asset. Furthermore, the tax basis of the asset is reduced by 50% of the ITCs received, resulting in a net deferred tax asset. Southern Power has elected to recognize the tax
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benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. State ITCs are recognized as an income tax benefit in the period in which the credits are generated. 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 2021 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 "Current and Deferred Income Taxes – Tax Credit Carryforwards" and " – Net Operating Loss Carryforwards" for additional information.
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.
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 $119 million, $104 million, and $114 million in 2021, 2020, and 2019, 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 for the Registrants in 2021, 2020, and 2019 was as follows:
| Southern Company | Alabama Power | Georgia Power**(*)** | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2021 | $ | 282 | $ | 68 | $ | 190 | $ | — | $ | 6 | $ | 18 | ||||||||
| 2020 | 230 | 61 | 138 | 1 | 11 | 18 | ||||||||||||||
| 2019 | 202 | 71 | 103 | — | 15 | 13 |
(*)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.
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The average AFUDC composite rates for 2021, 2020, and 2019 for the traditional electric operating companies and the natural gas distribution utilities were as follows:
| 2021 | 2020 | 2019 | |||||||||
| Alabama Power | 7.9 | % | 8.1 | % | 8.4 | % | |||||
| Georgia Power(*) | 7.2 | % | 6.9 | % | 6.9 | % | |||||
| Mississippi Power | 2.5 | % | 5.4 | % | 7.3 | % | |||||
| Southern Company Gas: | |||||||||||
| Atlanta Gas Light | 7.7 | % | 7.7 | % | 7.8 | % | |||||
| Chattanooga Gas | 7.1 | % | 7.1 | % | 7.1 | % | |||||
| Nicor Gas | 0.1 | % | 0.7 | % | 2.3 | % |
(*)Excludes AFUDC related to the construction of Plant Vogtle Units 3 and 4. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
Impairment of Long-Lived Assets
The Registrants evaluate long-lived assets and finite-lived intangible assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance, a sales transaction price that is less than the asset group's carrying value, or an estimate of undiscounted future cash flows attributable to the asset group, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Notes 7 and 9 under "Southern Company Gas" and "Southern Company Leveraged Lease," respectively, and Note 15 under "Southern Company" and "Southern Company Gas" for information regarding impairment charges recorded during the periods presented.
Goodwill and Other Intangible Assets and Liabilities
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 and liabilities 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.
Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. Southern Company and Southern Company Gas each evaluated its goodwill in the fourth quarter 2021 and determined no impairment was required. See Note 15 under "Southern Company" for information regarding impairments to goodwill and other intangible assets recorded in 2019.
At December 31, 2021 and 2020, goodwill was as follows:
| Goodwill | ||||||||
| (in millions) | ||||||||
| Southern Company | $ | 5,280 | ||||||
| Southern Company Gas: | ||||||||
| Gas distribution operations | $ | 4,034 | ||||||
| Gas marketing services | 981 | |||||||
| Southern Company Gas total | $ | 5,015 |
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At December 31, 2021 and 2020, other intangible assets were as follows:
| At December 31, 2021 | At December 31, 2020 | ||||||||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | Gross Carrying Amount | Accumulated Amortization | Other Intangible Assets, Net | ||||||||||||||||||
| (in millions) | (in millions) | ||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Other intangible assets subject to amortization: | |||||||||||||||||||||||
| Customer relationships | $ | 212 | $ | (150) | $ | 62 | $ | 212 | $ | (135) | $ | 77 | |||||||||||
| Trade names | 64 | (38) | 26 | 64 | (31) | 33 | |||||||||||||||||
| Storage and transportation contracts(*) | — | — | — | 64 | (64) | — | |||||||||||||||||
| PPA fair value adjustments | 390 | (109) | 281 | 390 | (89) | 301 | |||||||||||||||||
| Other | 11 | (10) | 1 | 10 | (9) | 1 | |||||||||||||||||
| Total other intangible assets subject to amortization | $ | 677 | $ | (307) | $ | 370 | $ | 740 | $ | (328) | $ | 412 | |||||||||||
| Other intangible assets not subject to amortization: | |||||||||||||||||||||||
| Federal Communications Commission licenses | 75 | — | 75 | 75 | — | 75 | |||||||||||||||||
| Total other intangible assets | $ | 752 | $ | (307) | $ | 445 | $ | 815 | $ | (328) | $ | 487 | |||||||||||
| Southern Power | |||||||||||||||||||||||
| Other intangible assets subject to amortization: | |||||||||||||||||||||||
| PPA fair value adjustments | $ | 390 | $ | (109) | $ | 281 | $ | 390 | $ | (89) | $ | 301 | |||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Other intangible assets subject to amortization: | |||||||||||||||||||||||
| Gas marketing services | |||||||||||||||||||||||
| Customer relationships | $ | 156 | $ | (130) | $ | 26 | $ | 156 | $ | (119) | $ | 37 | |||||||||||
| Trade names | 26 | (15) | 11 | 26 | (12) | 14 | |||||||||||||||||
| Wholesale gas services | |||||||||||||||||||||||
| Storage and transportation contracts(*) | — | — | — | 64 | (64) | — | |||||||||||||||||
| Total other intangible assets subject to amortization | $ | 182 | $ | (145) | $ | 37 | $ | 246 | $ | (195) | $ | 51 |
(*)See Note 15 under "Southern Company Gas" for information regarding the sale of Sequent.
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Amortization associated with other intangible assets in 2021, 2020, and 2019 was as follows:
| 2021 | 2020 | 2019 | |||||||||
| (in millions) | |||||||||||
| Southern Company(a) | $ | 44 | $ | 49 | $ | 61 | |||||
| Southern Power(b) | 20 | 20 | 19 | ||||||||
| Southern Company Gas: | |||||||||||
| Gas marketing services | $ | 15 | $ | 17 | $ | 23 | |||||
| Wholesale gas services(b) | — | 2 | 8 | ||||||||
| Southern Company Gas total | $ | 15 | $ | 19 | $ | 31 |
(a)Includes $20 million, $22 million, and $27 million in 2021, 2020, and 2019, respectively, recorded as a reduction to operating revenues.
(b)Recorded as a reduction to operating revenues.
At December 31, 2021, the estimated amortization associated with other intangible assets for the next five years is as follows:
| 2022 | 2023 | 2024 | 2025 | 2026 | |||||||||||||
| (in millions) | |||||||||||||||||
| Southern Company | $ | 39 | $ | 37 | $ | 35 | $ | 32 | $ | 27 | |||||||
| Southern Power | 20 | 20 | 20 | 20 | 20 | ||||||||||||
| Southern Company Gas | 11 | 9 | 7 | 6 | 3 |
Intangible liabilities of $91 million recorded under acquisition accounting for transportation contracts at Southern Company Gas were fully amortized at December 31, 2019.
Acquisition Accounting
At the time of an acquisition, management will assess whether acquired assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, operating results from the date of acquisition are included in the acquiring entity's financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired.
Determining the fair value of assets acquired and liabilities assumed requires management judgment and 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. Any due diligence or transition costs incurred for potential or successful acquisitions are expensed as incurred.
Historically, contingent consideration primarily 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 statements of income.
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,
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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 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 noncurrent assets on the balance sheets. At the time work is performed, an appropriate amount is accrued for future payments or transferred from the prepayment 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 within a five-year period 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.
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 | Southern Power | Southern Company Gas | ||||||||||||||||||||||||
| December 31, 2021 | December 31, 2020 | December 31, 2021 | December 31, 2021 | December 31, 2020 | ||||||||||||||||||||||
| (in millions) | (in millions) | (in millions) | ||||||||||||||||||||||||
| Cash and cash equivalents | $ | 1,798 | $ | 1,065 | $ | 107 | $ | 45 | $ | 17 | ||||||||||||||||
| Restricted cash(a): | ||||||||||||||||||||||||||
| Other current assets | 2 | 2 | — | 2 | 2 | |||||||||||||||||||||
| Other deferred charges and assets | 29 | — | 29 | — | — | |||||||||||||||||||||
| Total cash, cash equivalents, and restricted cash(b) | $ | 1,829 | $ | 1,068 | $ | 135 | $ | 48 | $ | 19 |
(a)For Southern Power, reflects restricted cash of $19 million related to tax equity contributions restricted until the Garland battery energy storage facility achieves final contracted capacity and $10 million held to fund estimated construction completion costs at the Deuel Harvest wind facility. See Note 15 under "Southern Power" for additional information. For Southern Company Gas, reflects restricted cash held as collateral for workers' compensation, life insurance, and long-term disability insurance.
(b)Total may not add due to rounding.
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Storm Damage Reserves
Each traditional electric operating company maintains a reserve to cover or is allowed to defer and recover the cost of damages from major storms to its transmission and distribution lines and, for Mississippi Power, the cost of uninsured damages to its generation facilities and other property. Alabama Power also has authority from the Alabama PSC to accrue certain additional amounts as circumstances warrant. Alabama Power recorded additional accruals of $65 million, $100 million, and $84 million in 2021, 2020, and 2019, respectively. In accordance with their respective state PSC orders, the traditional electric operating companies accrued the following amounts related to storm damage recovery in 2021, 2020, and 2019:
| Southern Company**(a)(b)** | Alabama Power**(a)** | Georgia Power | Mississippi Power**(b)** | |||||||||||
| (in millions) | ||||||||||||||
| 2021 | $ | 286 | $ | 75 | $ | 213 | $ | (2) | ||||||
| 2020 | 326 | 112 | 213 | 1 | ||||||||||
| 2019 | 170 | 139 | 30 | 1 |
(a)Includes $39 million applied in 2019 to Alabama Power's NDR from its remaining excess deferred income tax regulatory liability balance in accordance with an Alabama PSC order.
(b)Mississippi Power's net accrual includes carrying costs, as well as amortization of related excess deferred income tax benefits.
See Note 2 under "Alabama Power – Rate NDR," "Georgia Power – Storm Damage Recovery," and "Mississippi Power – System Restoration Rider" for additional information regarding each company's storm damage reserve.
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 propane 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 WACOG 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, 2021, the Nicor Gas LIFO inventory balance was $166 million. Based on the average cost of gas purchased in December 2021, the estimated replacement cost of Nicor Gas' inventory at December 31, 2021 was $470 million.
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Southern Company Gas' gas marketing services, wholesale gas services (until the sale of Sequent on July 1, 2021), and all other segments record inventory at LOCOM, with cost determined on a WACOG basis. For these segments, Southern Company Gas evaluates the weighted average cost of its natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, Southern Company Gas records LOCOM adjustments to cost of natural gas to reduce the value of its natural gas inventories to market value. LOCOM adjustments for wholesale gas services were $1 million, $1 million, and $21 million during 2021, 2020, and 2019, respectively, and were immaterial for all of Southern Company Gas' other segments.
Energy Marketing Receivables and Payables
Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas services provided services to retail gas marketers, wholesale gas marketers, utility companies, and industrial customers. These counterparties utilized netting agreements that enabled wholesale gas services to net receivables and payables by counterparty upon settlement. Southern Company Gas' wholesale gas services also netted across product lines and against cash collateral, provided the netting and cash collateral agreements included such provisions. While the amounts due from, or owed to, wholesale gas services' counterparties were settled net, they were recorded on a gross basis in the balance sheets as energy marketing receivables and energy marketing payables.
Southern Company Gas' wholesale gas services used 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 was most often in the form of cash or letters of credit from an investment-grade financial institution, but could also include cash or U.S. government securities held by a trustee. When more than one derivative transaction with the same counterparty was outstanding and a legally enforceable netting agreement existed with that counterparty, the "net" mark-to-market exposure represented a reasonable measure of Southern Company Gas' credit risk with that counterparty. Southern Company Gas' wholesale gas services also used other netting agreements with certain counterparties with whom it conducted significant transactions.
Provision for Uncollectible Accounts
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. 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.
See Note 2 for information regarding recovery of incremental bad debt expense related to the COVID-19 pandemic at certain of the traditional electric operating companies and natural gas distribution utilities.
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 16 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, interest rates, and commodity prices. 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
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fair value. See Note 13 for additional information regarding fair value. Substantially all of the traditional electric operating companies' and Southern Power's 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, 2021.
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.
Prior to the sale of Sequent on July 1, 2021, wholesale gas services purchased natural gas for storage when the market price paid to buy and transport natural gas plus the cost to store and finance the natural gas was less than the market price that could be received in the future, resulting in positive net natural gas revenues. NYMEX futures and OTC contracts were used to sell natural gas at that future price to substantially protect the natural gas revenues that would ultimately be realized when the stored natural gas was sold. 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 recorded in natural gas revenues on the statements of income in the period of change. These contracts are not designated as hedges for accounting purposes.
The purchase, transportation, storage, and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. 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.
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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, 2020 | $ | (209) | $ | (187) | $ | (395) | |||||||||||
| Current period change | 47 | 111 | 158 | ||||||||||||||
| Balance at December 31, 2021 | $ | (162) | $ | (76) | $ | (237) | |||||||||||
| Southern Power | |||||||||||||||||
| Balance at December 31, 2020 | $ | (21) | $ | (47) | $ | (67) | |||||||||||
| Current period change | 22 | 18 | 40 | ||||||||||||||
| Balance at December 31, 2021 | $ | 1 | $ | (29) | $ | (27) | |||||||||||
| Southern Company Gas | |||||||||||||||||
| Balance at December 31, 2020 | $ | (20) | $ | (2) | $ | (22) | |||||||||||
| Current period change | 6 | 40 | 46 | ||||||||||||||
| Balance at December 31, 2021 | $ | (14) | $ | 38 | $ | 24 |
(*)May not add due to rounding.
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.
At December 31, 2020, Alabama Power had a wholly-owned trust to issue preferred securities; however, since Alabama Power was not considered the primary beneficiary of the trust, the related investment at December 31, 2020 is reflected as other investments and the related loan from the trust is reflected as long-term debt in Alabama Power's balance sheet. See Note 8 under "Long-term Debt" for additional information.
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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, 2021 and 2020 are provided in the following tables:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| At December 31, 2021 | |||||||||||||||||
| AROs(a)(u) | $ | 5,685 | $ | 1,576 | $ | 3,866 | $ | 236 | $ | — | |||||||
| Retiree benefit plans(b)(u) | 2,998 | 747 | 962 | 145 | 95 | ||||||||||||
| Remaining net book value of retired assets(c) | 1,050 | 574 | 455 | 21 | — | ||||||||||||
| Deferred income tax charges(d) | 829 | 240 | 555 | 31 | — | ||||||||||||
| Under recovered regulatory clause revenues(e) | 806 | 225 | — | 49 | 532 | ||||||||||||
| Environmental remediation(f)(u) | 302 | — | 35 | — | 267 | ||||||||||||
| Loss on reacquired debt(g) | 281 | 42 | 231 | 6 | 2 | ||||||||||||
| Vacation pay(h)(u) | 207 | 81 | 102 | 10 | 14 | ||||||||||||
| Regulatory clauses(i) | 142 | 142 | — | — | — | ||||||||||||
| Storm damage(j) | 97 | — | 48 | 49 | — | ||||||||||||
| Long-term debt fair value adjustment(k) | 79 | — | — | — | 79 | ||||||||||||
| Nuclear outage(l) | 75 | 41 | 34 | — | — | ||||||||||||
| Software and cloud computing costs(m) | 73 | 35 | 33 | — | 5 | ||||||||||||
| Kemper County energy facility assets, net(n) | 35 | — | — | 35 | — | ||||||||||||
| Plant Daniel Units 3 and 4(o) | 28 | — | — | 28 | — | ||||||||||||
| Other regulatory assets(p) | 168 | 38 | 29 | 7 | 94 | ||||||||||||
| Deferred income tax credits(d) | (5,636) | (1,968) | (2,537) | (288) | (816) | ||||||||||||
| Other cost of removal obligations(a) | (1,826) | (192) | 278 | (195) | (1,683) | ||||||||||||
| Customer refunds(q) | (189) | (181) | (8) | — | — | ||||||||||||
| Fuel-hedging (realized and unrealized) gains(r**)** | (176) | (50) | (72) | (54) | — | ||||||||||||
| Storm/property damage reserves(s) | (133) | (103) | — | (30) | — | ||||||||||||
| Over recovered regulatory clause revenues(e) | (63) | (1) | (59) | — | (3) | ||||||||||||
| Other regulatory liabilities(t) | (121) | (29) | (24) | (4) | (57) | ||||||||||||
| Total regulatory assets (liabilities), net | $ | 4,711 | $ | 1,217 | $ | 3,928 | $ | 46 | $ | (1,471) | |||||||
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| At December 31, 2020 | |||||||||||||||||
| AROs(a)(u) | $ | 5,147 | $ | 1,470 | $ | 3,457 | $ | 212 | $ | — | |||||||
| Retiree benefit plans(b)(u) | 4,958 | 1,265 | 1,647 | 238 | 187 | ||||||||||||
| Remaining net book value of retired assets(c) | 1,183 | 632 | 527 | 24 | — | ||||||||||||
| Deferred income tax charges(d) | 801 | 235 | 531 | 32 | — | ||||||||||||
| Environmental remediation(f)(u) | 310 | — | 41 | — | 269 | ||||||||||||
| Loss on reacquired debt(g) | 304 | 47 | 248 | 6 | 3 | ||||||||||||
| Storm damage(j) | 262 | — | 262 | — | — | ||||||||||||
| Vacation pay(h)(u) | 207 | 80 | 104 | 10 | 13 | ||||||||||||
| Under recovered regulatory clause revenues(e) | 185 | 58 | — | 52 | 75 | ||||||||||||
| Regulatory clauses(i) | 142 | 142 | — | — | — | ||||||||||||
| Nuclear outage(l) | 101 | 61 | 40 | — | — | ||||||||||||
| Long-term debt fair value adjustment(k) | 92 | — | — | — | 92 | ||||||||||||
| Kemper County energy facility assets, net(n) | 50 | — | — | 50 | — | ||||||||||||
| Plant Daniel Units 3 and 4(o) | 32 | — | — | 32 | — | ||||||||||||
| Software and cloud computing costs(m) | 31 | 17 | 12 | — | 2 | ||||||||||||
| Other regulatory assets(p) | 174 | 35 | 56 | 4 | 79 | ||||||||||||
| Deferred income tax credits(d) | (6,016) | (2,016) | (2,805) | (320) | (847) | ||||||||||||
| Other cost of removal obligations(a) | (1,999) | (335) | 212 | (194) | (1,649) | ||||||||||||
| Over recovered regulatory clause revenues(e) | (185) | (46) | (44) | — | (95) | ||||||||||||
| Storm/property damage reserves(s) | (81) | (77) | — | (4) | — | ||||||||||||
| Customer refunds(q**)** | (56) | (50) | (6) | — | — | ||||||||||||
| Other regulatory liabilities(t) | (149) | (37) | (30) | (6) | (54) | ||||||||||||
| Total regulatory assets (liabilities), net | $ | 5,493 | $ | 1,481 | $ | 4,252 | $ | 136 | $ | (1,925) |
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:
(a)AROs and other cost of removal obligations generally are recorded over the related property lives, which may range up to 53 years for Alabama Power, 60 years for Georgia Power, 55 years for Mississippi Power, and 80 years for Southern Company Gas. AROs and cost of removal obligations will be settled and trued up following completion of the related activities. Effective January 1, 2020, Georgia Power is recovering CCR AROs, including past under recovered costs and estimated annual compliance costs, over three-year periods ending December 31, 2022, 2023, and 2024 through its ECCR tariff, as discussed further under "Georgia Power – Rate Plans" herein. See Note 6 for additional information on AROs.
(b)Recovered and amortized over the average remaining service period, which may range up to 13 years for Alabama Power, Georgia Power, and Mississippi Power and up to 14 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.
(c)Alabama Power: Primarily represents the net book value of Plant Gorgas Units 8, 9, and 10 ($533 million at December 31, 2021) being amortized over remaining periods not exceeding 16 years (through 2037).
Georgia Power: Net book values of Plant Hammond Units 1 through 4 and Plant Branch Units 3 and 4 (totaling $445 million at December 31, 2021) are being amortized over remaining periods of between two and 14 years (between 2023 and 2035) and the net book values of Plant Branch Unit 2, Plant McIntosh Unit 1, and Plant Mitchell Unit 3 (totaling $10 million at December 31, 2021) are being amortized through 2022.
Mississippi Power: Represents net book value of certain environmental compliance projects associated with Plant Watson and Plant Greene County being amortized over a 10-year period through 2030. See "Mississippi Power – Environmental Compliance Overview Plan" herein for additional information.
(d)Deferred income tax charges are recovered and deferred income tax credits are amortized over the related property lives, which may range up to 53 years for Alabama Power, 60 years for Georgia Power, 55 years for Mississippi Power, and 80 years for Southern Company Gas. See Note 10 for additional information. Included in the deferred income tax charges are amounts ($7 million and $4 million for Alabama Power and Georgia Power, respectively, at December 31, 2021) for the retiree Medicare drug subsidy, which are being recovered and amortized through 2027 and 2022 for Alabama Power and Georgia Power, respectively. As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization, as described further below:
Alabama Power: Related amounts are being recovered and amortized ratably over the related property lives.
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Georgia Power: Related amounts at December 31, 2021 include $145 million of deferred income tax assets related to CWIP for Plant Vogtle Units 3 and 4 and approximately $220 million of deferred income tax liabilities. The recovery of deferred income tax assets related to CWIP for Plant Vogtle Units 3 and 4 is expected to be determined in a future regulatory proceeding. Effective January 1, 2020, the deferred income tax liabilities are being amortized through 2022.
Mississippi Power: Related amounts at December 31, 2021 include $46 million of retail deferred income tax liabilities generally being amortized over three years (through 2023). See "Mississippi Power – 2019 Base Rate Case" herein for additional information.
Southern Company Gas: Related amounts at December 31, 2021 include $3 million of deferred income tax liabilities being amortized through 2024. See "Southern Company Gas – Rate Proceedings" herein for additional information.
(e)Alabama Power: Balances are recorded monthly and expected to be recovered or returned within eight years. Recovery periods could change based on several factors including changes in cost estimates, load forecasts, and timing of rate adjustments. See "Alabama Power – Rate CNP PPA," " – Rate CNP Compliance," and " – Rate ECR" herein for additional information.
Georgia Power: Balances are recorded monthly and expected to be recovered or returned within two years. See "Georgia Power – Rate Plans" herein for additional information.
Mississippi Power: At December 31, 2021, $24 million is being amortized over a three-year period through 2023 and the remaining $25 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 four 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. The significant change during 2021 was primarily driven by an increase in the cost of gas purchased in February 2021 resulting from Winter Storm Uri.
(f)Georgia Power is recovering $12 million annually for environmental remediation under the 2019 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.
(g)Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue. At December 31, 2021, the remaining amortization periods do not exceed 26 years for Alabama Power, 31 years for Georgia Power, 20 years for Mississippi Power, and six years for Southern Company Gas.
(h)Recorded as earned by employees and recovered as paid, generally within one year. Includes both vacation and banked holiday pay, if applicable.
(i)Will be amortized concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur no later than 2023.
(j)Georgia Power is recovering approximately $213 million annually for storm damage under the 2019 ARP. See "Georgia Power – Storm Damage Recovery" herein for additional information. Mississippi Power's balance represents deferred storm costs associated with Hurricanes Ida and Zeta to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. See "Mississippi Power – System Restoration Rider" herein for additional information. Also see Note 1 under "Storm Damage Reserves" for additional information.
(k)Recovered over the remaining lives of the original debt issuances at acquisition, which range up to 17 years at December 31, 2021.
(l)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.
(m)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. See "Alabama Power – Software Accounting Order" herein for additional information. For Georgia Power, the recovery period will be determined in its next base rate case. For Southern Company Gas, costs will be amortized ratably beginning in July 2022 over the life of the related software, which ranges up to 10 years.
(n)Includes $44 million of regulatory assets and $9 million of regulatory liabilities at December 31, 2021. The retail portion includes $33 million of regulatory assets and $9 million of regulatory liabilities that are expected to be fully amortized by 2023 and 2024, respectively. The wholesale portion includes $11 million of regulatory assets that are expected to be fully amortized by 2029.
(o)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, 2021, consists of the $19 million retail portion, which is being amortized over the remaining life of the units through 2041, and the $9 million wholesale portion, which is expected to be amortized over a period to be determined in a future wholesale rate filing.
(p)Except as otherwise noted, comprised of numerous immaterial components with remaining amortization periods generally not exceeding 23 years for Alabama Power, 10 years for Georgia Power, six years for Mississippi Power, and 20 years for Southern Company Gas at December 31, 2021. Balances at December 31, 2021 and 2020 include deferred COVID-19 costs (except for Alabama Power), as discussed further under "Deferral of Incremental COVID-19 Costs" for each applicable Registrant herein.
(q)Primarily includes approximately $181 million and $50 million at December 31, 2021 and 2020, respectively, for Alabama Power and $5 million at December 31, 2021 for Georgia Power as a result of each company exceeding its allowed retail return range. Georgia Power's balances also include immaterial amounts related to refunds for transmission service customers. See "Alabama Power – Rate RSE" and "Georgia Power – Rate Plans" herein for additional information.
(r)Fuel-hedging 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 three years for Mississippi Power. Immaterial amounts at December 31, 2020 are included in other regulatory assets and liabilities.
(s)Amortized as related expenses are incurred. See "Alabama Power – Rate NDR" and "Mississippi Power – System Restoration Rider" herein for additional information.
(t)Comprised of numerous immaterial components with remaining amortization periods generally not exceeding 16 years for Alabama Power, 11 years for Georgia Power, three years for Mississippi Power, and 20 years for Southern Company Gas at December 31, 2021.
(u)Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability.
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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.
Certificates of Convenience and Necessity
In August 2020, the Alabama PSC issued its order regarding Alabama Power's 2019 petition for a CCN, which authorized Alabama Power to (i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8) that is expected to be placed in service by the end of 2023, (ii) complete the acquisition of the Central Alabama Generating Station, which occurred in August 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA, which began in September 2020, and (iv) pursue up to approximately 200 MWs of cost-effective demand-side management and distributed energy resource programs. Alabama Power's petition for a CCN was predicated on the results of Alabama Power's 2019 IRP provided to the Alabama PSC, which identified an approximately 2,400-MW resource need for Alabama Power, driven by the need for additional winter reserve capacity. See Note 15 under "Alabama Power" for additional information on the acquisition of the Central Alabama Generating Station.
The Alabama PSC authorized the recovery of actual costs for the construction of Plant Barry Unit 8 up to 5% above the estimated in-service cost of $652 million. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation to the Alabama PSC to explain and justify potential recovery of the additional costs. At December 31, 2021, project expenditures associated with Plant Barry Unit 8 included in CWIP totaled approximately $304 million.
The Alabama PSC further directed that additional solar generation of approximately 400 MWs proposed in the 2019 CCN petition, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation Certificate (RGC). The contracts originally proposed expired in July 2020. See "Renewable Generation Certificate" herein for additional information.
Alabama Power expects to recover costs associated with Plant Barry Unit 8 pursuant to its Rate CNP New Plant. Alabama Power is recovering all costs associated with the Central Alabama Generating Station through the inclusion in Rate RSE of revenues from the existing power sales agreement and, on expiration of that agreement, expects to recover costs pursuant to Rate CNP New Plant. The recovery of costs associated with laws, regulations, and other such mandates directed at the utility industry are expected to be recovered through Rate CNP Compliance. Alabama Power expects to recover the capacity-related costs associated with the PPAs through its Rate CNP PPA. In addition, fuel and energy-related costs are expected to be recovered through Rate ECR. Any remaining costs associated with Plant Barry Unit 8 and the acquisition of the Central Alabama Generating Station are expected to be recovered through Rate RSE.
On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates a 743-MW winter peak, simple-cycle, combustion turbine generation facility in Calhoun County, Alabama (Calhoun Generating Station). The total purchase price associated with the acquisition is approximately $180 million, subject to working capital adjustments. The completion of the acquisition is subject to the satisfaction and waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and the FERC.
On October 28, 2021, Alabama Power filed a petition for a CCN with the Alabama PSC to procure additional generating capacity through this acquisition. Completion of the acquisition and certain operating conditions would enable Alabama Power to retire Plant Barry Unit 5 as early as 2023. A decision from the Alabama PSC is expected by the third quarter 2022. Pending certification, Alabama Power expects to recover costs associated with the Calhoun Generating Station through its existing rate structure, primarily Rate CNP New Plant, Rate CNP Compliance, Rate ECR, and Rate RSE.
Alabama Power expects to complete the transaction by September 30, 2022; however, the ultimate outcome of these matters cannot be determined at this time.
Renewable Generation Certificate
Through the issuance of a RGC, the Alabama PSC has authorized Alabama Power to procure up to 500 MWs of renewable capacity and energy by September 16, 2027 and to market the related energy and environmental attributes to customers and other third parties. Through December 31, 2021, Alabama Power has procured approximately 250 MWs through five projects approved
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under the RGC. Alabama Power owns two of the projects, totaling 18 MWs, with the remaining MWs expected to be served through three PPAs, two of which will commence in the first quarter 2024.
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.
Alabama Power continues to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At both December 31, 2021 and 2020, Alabama Power's equity ratio was approximately 51.6%.
Effective for January 2019, the Alabama PSC approved modifications to Rate RSE. These modifications reduced the top of the allowed WCER range from 6.21% to 6.15% and modified the refund mechanism applicable to prior year actual results to allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range. These modifications were designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term.
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%. There is no provision for additional customer billings should the actual retail return fall below the WCER range.
In conjunction with these modifications to Rate RSE, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020 and to return $50 million to customers through bill credits in 2019. Retail rates under Rate RSE remained unchanged for 2019 and 2020 and increased by 4.09%, or approximately $228 million annually, effective with the billing month of January 2021.
At December 31, 2019, 2020, and 2021, Alabama Power's WCER exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $53 million, $50 million, and $181 million, respectively, for Rate RSE refunds. The 2019 and 2020 refunds were issued to customers through bill credits in April of the following year. In accordance with an Alabama PSC order issued on February 1, 2022, Alabama Power will apply $126 million of the 2021 refund to reduce the Rate ECR under recovered balance and the remaining $55 million will be refunded to customers through bill credits in July 2022. See "Rate ECR" herein for additional information.
On December 1, 2021, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2022. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2022.
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. No adjustments to Rate CNP New Plant occurred during the period 2019 through 2021. See "Certificates of Convenience and Necessity" herein 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 factor 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 2019 through 2021 and no adjustment is expected for 2022. At December 31, 2021 and 2020, Alabama Power had an under recovered Rate CNP PPA balance of $84 million and $58 million, respectively, which is included in other regulatory assets, deferred on the balance sheet.
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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 factor 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 November 2019, 2020, and 2021, Alabama Power submitted calculations associated with its cost of complying with governmental mandates for the following calendar year, as provided under Rate CNP Compliance. The 2019 filing reflected a projected over recovered retail revenue requirement, which resulted in a rate decrease of approximately $68 million that became effective for the billing month of January 2020. Both the 2020 and 2021 filings reflected a projected under recovered retail revenue requirement of approximately $59 million. In December 2020 and on December 7, 2021, the Alabama PSC issued consent orders that Alabama Power leave the 2020 Rate CNP Compliance factors in effect for 2021 and 2022, respectively, with any prior year under collected amount deemed recovered before any current year amounts are recovered. Any remaining under recovered amount will be reflected in the 2022 filing.
At December 31, 2021, Alabama Power had an under recovered Rate CNP Compliance balance of $16 million included in other regulatory assets, deferred on the balance sheet. At December 31, 2020, Alabama Power had an over recovered Rate CNP Compliance balance of $28 million included in other regulatory liabilities, current on the balance sheet.
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 operating cash flows. The Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.
In 2019, the Alabama PSC approved a decrease to Rate ECR from 2.353 cents per KWH to 2.160 cents per KWH, equal to 1.82%, or approximately $102 million annually, that became effective for the billing month of January 2020.
In October 2020, Alabama Power reduced its over-collected fuel balance by $94 million in accordance with an August 2020 Alabama PSC order and returned that amount to customers in the form of bill credits.
In December 2020, the Alabama PSC approved a decrease to Rate ECR from 2.160 cents per KWH to 1.960 cents per KWH, equal to 1.84%, or approximately $103 million annually, that became effective for the billing month of January 2021.
On December 7, 2021, the Alabama PSC issued a consent order that Alabama Power leave the 2021 Rate ECR factors in effect for 2022. The rate will adjust to 5.910 cents per KWH in January 2023 absent a further order from the Alabama PSC.
At December 31, 2021, Alabama Power's under recovered fuel costs totaled $126 million and is included in other regulatory assets, deferred on the balance sheet. In accordance with an Alabama PSC order issued on February 1, 2022, Alabama Power will apply $126 million of its 2021 Rate RSE refund to reduce the Rate ECR under recovered balance. See "Rate RSE" herein for additional information. At December 31, 2020, Alabama Power's over recovered fuel costs totaled $18 million and is included in other regulatory liabilities, current on the balance sheet. 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.
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Software Accounting Order
In 2019, the Alabama PSC approved an accounting order that authorizes Alabama Power to establish a regulatory asset for operations and maintenance costs associated with software implementation projects. The regulatory asset will be amortized ratably over the life of the related software. At December 31, 2021 and 2020, the regulatory asset balance totaled $35 million and $17 million, respectively, and is included in other regulatory assets, deferred on the balance sheet.
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" for additional information. On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. Mississippi Power's 2021 IRP included a schedule to retire Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 in December 2025 and 2026, respectively, consistent with each unit's remaining useful life. The Plant Greene County unit retirements identified by Mississippi Power require the completion of transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will continue to monitor the status of the transmission and system reliability improvements. Currently, Alabama Power plans to retire Plant Greene County Units 1 and 2 at the dates indicated. The ultimate outcome of this matter cannot be determined at this time.
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 24-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. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 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. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR enhance Alabama Power's ability to mitigate the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. Alabama Power made additional accruals of $65 million, $100 million, and $84 million in 2021, 2020, and 2019, respectively.
Alabama Power collected approximately $6 million, $5 million, and $16 million in 2021, 2020, and 2019, respectively, under Rate NDR. At December 31, 2021 and 2020, the NDR balance was $103 million and $77 million, respectively, and is included in other regulatory liabilities, deferred on the balance sheets. Beginning with June 2022 billings, the reserve establishment charge will be suspended and the reserve maintenance charge will be activated as a result of the NDR balance exceeding $75 million. Alabama Power expects to collect $8 million in 2022 and approximately $3 million annually beginning in 2023 under Rate NDR unless the NDR balance falls below $50 million.
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.
Environmental Accounting Order
Based on an order from the Alabama PSC (Environmental Accounting Order), 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.
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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 currently recovers its costs from the regulated retail business through the 2019 ARP, which includes traditional base tariffs, Demand-Side Management (DSM) tariffs, the ECCR tariff, and Municipal Franchise Fee (MFF) tariffs. In addition, financing costs on certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a fuel cost recovery tariff, both under separate regulatory proceedings.
See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" 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 will become effective the month after Unit 3 is placed in service. As costs are included in retail base rates, the related financing costs will no longer be recovered through the NCCR tariff. See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Rate Plans
2019 ARP
In 2019, the Georgia PSC voted to approve the 2019 ARP, under which Georgia Power increased its rates on January 1, 2020. In December 2020 and on November 18, 2021, the Georgia PSC approved tariff adjustments effective January 1, 2021 and 2022, respectively. Details of tariff adjustments are provided in the table below:
| Tariff | 2020 | 2021 | 2022 | ||||||||||||||
| (in millions) | |||||||||||||||||
| Traditional base | $ | — | $ | 120 | $ | 192 | |||||||||||
| ECCR(*) | 318 | 2 | (12) | ||||||||||||||
| DSM | 12 | (15) | (25) | ||||||||||||||
| MFF | 12 | 4 | 2 | ||||||||||||||
| Total | $ | 342 | $ | 111 | $ | 157 |
(*) Effective January 1, 2020, CCR AROs are being recovered through the ECCR tariff.
In 2019, the Georgia PSC voted to approve Georgia Power's modified triennial IRP (Georgia Power 2019 IRP), including Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the 2019 ARP, the Georgia PSC approved recovery of the estimated under recovered balance of these compliance costs at December 31, 2019 over a three-year period ending December 31, 2022 and recovery of estimated compliance costs for 2020, 2021, and 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively, with recovery of construction contingency beginning in the year following actual expenditure. The ECCR tariff is revised for actual expenditures and updated estimates through annual compliance filings. Effective January 1, 2021 and 2022, Georgia Power adjusted its amortization of costs associated with CCR AROs by an approximate decrease of $90 million and increase of $10 million, respectively, as approved by the Georgia PSC in conjunction with Georgia Power's annual compliance filings. See "Integrated Resource Plan" herein for additional information.
In February 2020, the Georgia PSC denied a motion for reconsideration filed by the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing Georgia Power to recover compliance costs for CCR AROs. The Superior Court of Fulton County subsequently affirmed the Georgia PSC's decision and, on October 25, 2021, the Georgia Court of Appeals affirmed the Superior Court of Fulton County's order. On December 6, 2021, the Sierra Club filed a petition for writ of certiorari to the Georgia Supreme Court. The ultimate outcome of this matter cannot be determined at this time. See Note 6 for additional information regarding Georgia Power's AROs.
Under the 2019 ARP, Georgia Power's retail ROE is set at 10.50%, and earnings will be evaluated against a retail ROE range of 9.50% to 12.00%. Any retail earnings above 12.00% will be shared, with 40% being applied to reduce regulatory assets, 40% directly refunded to customers, and the remaining 20% retained by Georgia Power. There will be no recovery of any earnings shortfall below 9.50% on an actual basis. However, if at any time during the term of the 2019 ARP, Georgia Power projects that its retail earnings will be below 9.50% for any calendar year, it could petition the Georgia PSC for implementation of the Interim Cost Recovery (ICR) tariff to adjust Georgia Power's retail rates to achieve a 9.50% ROE. The Georgia PSC would have 90 days to rule on Georgia Power's request. The ICR tariff would expire at the earlier of January 1, 2023 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 the ICR tariff, Georgia Power may file a full rate case. In 2020, Georgia Power's retail ROE was within the allowed
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retail ROE range. In 2021, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power reduced regulatory assets by approximately $5 million and accrued approximately $5 million to refund to customers in 2022, subject to review and approval by the Georgia PSC.
Additionally, under the 2019 ARP and pursuant to the sharing mechanism approved in the 2013 ARP whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers, (i) Georgia Power used 50% (approximately $50 million) of the customer share of earnings above the band in 2018 to reduce regulatory assets and refunded 50% (approximately $50 million) to customers in 2020 and (ii) Georgia Power agreed to forego its share of 2019 earnings in excess of the earnings band so 50% (approximately $60 million) of all earnings over the 2019 band were refunded to customers in 2020 and 50% (approximately $60 million) were used to reduce regulatory assets.
Georgia Power is required to file a general base rate case by July 1, 2022, in response to which the Georgia PSC would be expected to determine whether the 2019 ARP should be continued, modified, or discontinued.
2013 ARP
Georgia Power's retail ROE under the 2013 ARP was set at 10.95% and earnings were evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% were to be directly refunded to customers, with the remaining one-third retained by Georgia Power. In 2019 and 2018, Georgia Power's retail ROE exceeded 12.00% and, under the modified sharing mechanism pursuant to the 2019 ARP, Georgia Power reduced regulatory assets by a total of approximately $110 million and accrued approximately $110 million for retail customer refunds through bill credits that were completed in 2020. See "2019 ARP" herein for additional information.
Plant Vogtle Unit 3 and Common Facilities Rate Proceeding
On June 15, 2021, Georgia Power filed an application with the Georgia PSC to adjust retail base rates to include the portion of costs related to its investment in Plant Vogtle Unit 3 and Common Facilities previously deemed prudent by the Georgia PSC, as well as the related costs of operation. On November 2, 2021, the Georgia PSC voted to approve Georgia Power's application as filed, with the following modifications pursuant to a stipulated agreement between Georgia Power and the staff of the Georgia PSC. Georgia Power will include in rate base an allocation of $2.1 billion to Unit 3 and Common Facilities from the $3.6 billion of Plant Vogtle Units 3 and 4 previously deemed prudent by the Georgia PSC and will recover the related depreciation expense through retail base rates effective the month after Unit 3 is placed in service. Financing costs on the remaining portion of the total Unit 3 and the Common Facilities construction costs will continue to be recovered through the NCCR tariff or deferred. Georgia Power will defer as a regulatory asset the remaining depreciation expense (approximately $38 million annually) until Unit 4 costs are placed in retail base rates. In addition, the stipulated agreement clarified that following the prudency review, the remaining amount to be placed in retail base rates will be net of the proceeds from the Guarantee Settlement Agreement and will not be used to offset imprudent costs, if any.
The related increase in annual retail base rates of approximately $302 million also includes 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 production tax credits, and will become effective the month after Unit 3 is placed in service. This increase is partially offset by a decrease in the NCCR tariff of approximately $78 million effective January 1, 2022. As approved by the Georgia PSC, the increase in annual retail base rates will be adjusted based on the actual in-service date of Plant Vogtle Unit 3.
See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Integrated Resource Plan
In 2021, as authorized in its 2019 IRP, Georgia Power requested and received certification from the Georgia PSC for 970 MWs of utility-scale PPAs for solar generation resources, which are expected to be in operation by the end of 2023.
On January 31, 2022, Georgia Power filed its triennial IRP (2022 IRP). The filing included a request to decertify and retire Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership) by August 31, 2022; Plant Bowen Units 1 and 2 (1,400 MWs) by December 31, 2027; and Plant Scherer Unit 3 (614 MWs based on 75% ownership) and Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) by December 31, 2028. See Note 7 under "SEGCO" for additional information.
In the 2022 IRP, Georgia Power requested approval to reclassify the remaining net book value of Plant Wansley Units 1 and 2 (approximately $610 million at December 31, 2021), Plant Bowen Units 1 and 2 (approximately $937 million at December 31, 2021), and Plant Scherer Unit 3 (approximately $622 million at December 31, 2021) and any remaining unusable materials and supplies inventories upon each unit's respective retirement dates to a regulatory asset, with recovery periods to be determined in future base rate cases.
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In addition, the 2022 IRP includes requests for approval of the following:
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Capital, operations and maintenance, and CCR ARO costs associated with ash pond and landfill closures and post-closure care. The recovery of these costs is expected to be determined in future base rate cases;
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Installation of environmental controls at Plant Bowen Units 3 and 4 (1,760 MWs) and Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership) for compliance with ELG rules;
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Investments related to the hydro operations of Plants Sinclair (45 MWs), North Highlands (30 MWs), and Burton (6 MWs);
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Establishment of a request for proposals (RFP) process for 2,300 MWs of renewable resources by 2029. Georgia Power expects to request an additional 3,700 MWs by 2035 through future IRP proceedings;
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Procurement of 1,000 MWs of Georgia Power-owned storage resources by 2030, including the development of a 265-MW battery energy storage facility beginning in 2026;
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Related transmission costs necessary to support the proposed retirements and renewable resources previously described;
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Certification of six PPAs (including five affiliate PPAs with Southern Power that are also subject to approval by the FERC) with capacities of 1,567 MWs beginning in 2024, 380 MWs beginning in 2025, and 228 MWs beginning in 2028, procured through RFPs approved through the 2019 IRP; and
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Certification of approximately 88 MWs of wholesale capacity to be placed in retail rate base between January 1, 2024 and January 1, 2025.
A decision from the Georgia PSC on the 2022 IRP is expected in July 2022. The ultimate outcome of these matters cannot be determined at this time.
Deferral of Incremental COVID-19 Costs
In April 2020 and June 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Georgia Power to continue its previous, voluntary suspension of customer disconnections through July 14, 2020 and to defer the resulting incremental bad debt as a regulatory asset. In June 2020 and July 2020, the Georgia PSC approved orders establishing a methodology for identifying incremental bad debt and allowing the deferral of other incremental costs associated with the COVID-19 pandemic. At December 31, 2020, the incremental costs deferred totaled approximately $38 million (including approximately $23 million of incremental bad debt costs and $15 million of other incremental costs). Since June 2021, Georgia Power has continued a review of bad debt amounts deferred under the Georgia PSC-approved methodology, including consideration of actual amounts repaid by customers from arrears and installment plans after the disconnection moratorium period ended. As a result, Georgia Power's incremental costs deferred at December 31, 2021 totaled approximately $21 million, including an immaterial amount of incremental bad debt costs. The period over which these costs will be recovered is expected to be determined in Georgia Power's next base rate case. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. In May 2020, the Georgia PSC approved a stipulation agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel billings by approximately $740 million over a two-year period effective June 1, 2020. In addition, Georgia Power further lowered fuel billings by approximately $44 million under an interim fuel rider effective June 1, 2020 through September 30, 2020. During the second half of 2021, the price of natural gas rose significantly and resulted in an under recovered fuel balance exceeding $200 million. Therefore, on November 18, 2021, the Georgia PSC voted to approve Georgia Power's interim fuel rider, which increased fuel rates by 15%, or approximately $252 million annually, effective January 1, 2022. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the over recovered fuel balance exceeds $200 million. Georgia Power is scheduled to file its next fuel case no later than February 28, 2023.
Georgia Power's under recovered fuel balance totaled $410 million at December 31, 2021 and is included in other deferred charges and assets on Southern Company's balance sheet and deferred under recovered fuel clause revenues on Georgia Power's balance sheet. At December 31, 2020, Georgia Power's over recovered fuel balance totaled $113 million and is included in other current liabilities on Southern Company's balance sheet and over recovered fuel clause revenues on Georgia Power's balance sheet.
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.
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Storm Damage Recovery
Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2020, Georgia Power is recovering $213 million annually under the 2019 ARP. At December 31, 2021 and 2020, the balance in the regulatory asset related to storm damage was $48 million and $262 million, respectively, with $48 million and $213 million, respectively, included in other regulatory assets, current on Southern Company's balance sheets and regulatory assets – storm damage on Georgia Power's balance sheets and $49 million at December 31, 2020 included in other regulatory assets, deferred on Southern Company's and Georgia Power's balance sheets. The rate of storm damage cost recovery is expected to be 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 financial statements.
Nuclear Construction
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4, in which Georgia Power holds a 45.7% ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement.
In connection with the EPC Contractor's bankruptcy filing in March 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
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's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through the end of the first quarter 2023 and the fourth quarter 2023, respectively, is as follows:
| (in millions) | |||||
| Base project capital cost forecast(a)(b) | $ | 10,251 | |||
| Construction contingency estimate | 150 | ||||
| Total project capital cost forecast(a)(b) | 10,401 | ||||
| Net investment at December 31, 2021(b) | (8,442) | ||||
| Remaining estimate to complete | $ | 1,959 |
(a)Includes approximately $590 million of costs that are not shared with the other Vogtle Owners and approximately $440 million of incremental costs under the cost-sharing and tender provisions of the joint ownership agreements described below. Excludes financing costs expected to be capitalized through AFUDC of approximately $375 million, of which $195 million had been accrued through December 31, 2021.
(b)Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.4 billion, of which $2.9 billion had been incurred through December 31, 2021.
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As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. Southern Nuclear establishes aggressive target values for monthly construction production and system turnover activities, which are reflected in the site work plans.
In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures; isolating individuals who tested positive for COVID-19, showed symptoms consistent with COVID-19, were being tested for COVID-19, or were in close contact with such persons; requiring self-quarantine; and adopting additional precautionary measures. Since March 2020, the number of active cases at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion, with the site experiencing peaks in the number of active cases in January 2021, August 2021, and January 2022. Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. Georgia Power's proportionate share of the estimated incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $160 million and $200 million and is included in the total project capital cost forecast. The continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4.
During 2021, Southern Nuclear performed additional construction remediation work necessary to ensure quality and design standards are met and support system turnovers necessary for Unit 3 hot functional testing, which was completed in July 2021, and fuel load. As a result of Unit 3 challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of each of the second and third quarters 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established in January 2021. Through the fourth quarter 2021, the project continued to face these and other challenges related to the completion of documentation, including inspection records, necessary to submit the remaining ITAACs and begin fuel load. As a result, at the end of the fourth quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the third quarter 2021. The site work plan currently targets fuel load for Unit 3 in the second quarter 2022 and an in-service date during the third quarter 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date during the fourth quarter 2022 or the first quarter 2023 for Unit 3 is projected, although any further delays could result in a later in-service date.
As the result of productivity challenges and temporarily diverting some Unit 4 craft and support resources to Unit 3 construction efforts, at the end of each of the second and third quarters 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established in January 2021. The temporary diversion of Unit 4 resources to support Unit 3 has continued into the first quarter 2022; therefore, at the end of the fourth quarter 2021, Southern Nuclear further extended milestone dates for Unit 4 from those established at the end of the third quarter 2021. The site work plan targets an in-service date during the first quarter 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date during the third or fourth quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date.
During 2021, established construction contingency and additional costs totaling $1.3 billion were assigned to the base capital cost forecast for costs primarily associated with schedule extensions, construction productivity, the pace of system turnovers, and support resources for Units 3 and 4. Georgia Power also increased its total capital cost forecast as of December 31, 2021 by $99 million to replenish construction contingency.
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income in the first quarter 2021, the second quarter 2021, the third quarter 2021, and the fourth quarter 2021 of $48 million ($36 million after tax), $460 million ($343 million after tax), $264 million ($197 million after tax), and $480 million ($358 million after tax), respectively, for the increases in the total project capital cost forecast. Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery during the prudence review following the Unit 4 fuel load pursuant to the twenty-fourth VCM stipulation described below. In addition, Georgia Power recorded a pre-tax charge to income in the fourth quarter 2021 of approximately $440 million ($328 million after tax) for incremental costs, which will not be recovered from retail customers, associated with the cost-sharing and tender provisions of the joint ownership agreements described below.
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As Unit 3 completes system turnover from construction and moves to testing and transition to operations, ongoing and potential future challenges include completion of construction remediation work, completion of work packages, including inspection records, and other documentation necessary to submit the remaining ITAACs and begin fuel load, and final component and pre-operational tests. As Unit 4 progresses through construction and continues to transition into testing, ongoing and potential future challenges include the pace and quality of electrical installation, availability of craft and supervisory resources, including the temporary diversion of such resources to support Unit 3 construction efforts, and the pace of work package closures and system turnovers. As construction, including subcontract work, continues on both Units 3 and 4, ongoing or future challenges include management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; and procurement and related installation. New challenges may arise, particularly as Units 3 and 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). The ongoing and potential future challenges described above may change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. In connection with the additional construction remediation work described above, Southern Nuclear reviewed the project's construction quality programs and, where needed, is implementing improvement plans consistent with these processes. On November 17, 2021, the NRC issued the final significance report on its special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans with two findings of low to moderate safety significance. Southern Nuclear had already identified and self-reported many of the issues in this report to the NRC and implemented corrective-action plans to resolve these issues. The NRC will conduct a follow-up inspection on these findings at a future date. Findings resulting from this or other inspections could require additional remediation and/or further NRC oversight. In addition, certain license amendment requests have been filed and approved or are pending before the NRC.
The site work plan currently targets fuel load for Units 3 and 4 in the second quarter 2022 and the fourth quarter 2022, respectively. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, have arisen or may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs, are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the first quarter 2023 for Unit 3 or the fourth quarter 2023 for Unit 4, including the current level of cost sharing described below, is estimated to result in additional base capital costs for Georgia Power of up to $60 million per month for Unit 3 and $40 million per month for Unit 4, as well as the related AFUDC and any additional related construction, support resources, or testing costs. While Georgia Power is not precluded from seeking retail recovery of any future capital cost forecast increase other than the amounts related to the cost-sharing and tender provisions of the joint ownership agreements described below, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
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Amendments to the Vogtle Joint Ownership Agreements
In connection with a September 2018 vote by the Vogtle Owners to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300 million of funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global Amendments).
Pursuant to the Global Amendments: (i) each Vogtle Owner must pay its proportionate share of qualifying construction costs for Plant Vogtle Units 3 and 4 based on its ownership percentage up to the estimated cost at completion (EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia Power will be responsible for 55.7% of actual qualifying construction costs between $800 million and $1.6 billion over the EAC in the nineteenth VCM (resulting in $80 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests; and (iii) Georgia Power will be responsible for 65.7% of qualifying construction costs between $1.6 billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a further $100 million of potential additional costs to Georgia Power), with the remaining Vogtle Owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests. If the EAC is revised and exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the other Vogtle Owners will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle Owner's remaining share of total construction costs in excess of the EAC in the nineteenth VCM plus $2.1 billion.
In addition, pursuant to the Global Amendments, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including, among other events: (i) the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement, the Bechtel Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's public announcement of its intention not to submit for rate recovery any portion of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to the Global Amendments described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia PSC for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates; and (iv) an incremental extension of one year or more from the seventeenth VCM report estimated in-service dates of November 2021 and November 2022 for Units 3 and 4, respectively. The latest schedule extension triggers the requirement that the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction by March 8, 2022. Georgia Power has voted to continue construction. In addition, if the holders of at least 90% of the ownership interests of Plant Vogtle Units 3 and 4 do not vote to continue construction, the DOE may require Georgia Power to prepay all outstanding borrowings under the FFB Credit Facilities over a period of five years. See Note 8 under "Long-term Debt – DOE Loan Guarantee Borrowings" for additional information.
Georgia Power and the other Vogtle Owners do not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments or the extent to which COVID-19-related costs impact the calculation. Based on the definition in the Global Amendments, Georgia Power believes the starting dollar amount is $18.38 billion and the current project capital cost forecast has triggered the cost-sharing provisions. The other Vogtle Owners have asserted that the project cost increases have reached the cost-sharing thresholds and have triggered the tender provisions under the Global Amendments. Georgia Power recorded an additional pre-tax charge to income in the fourth quarter 2021 of approximately $440 million ($328 million after tax) associated with these cost-sharing and tender provisions, which is included in the total project capital cost forecast. Georgia Power may be required to record further pre-tax charges to income of up to approximately $460 million associated with these provisions based on the current project capital cost forecast. The incremental charges associated with these provisions will not be recovered from retail customers. On October 29, 2021, Georgia Power and the other Vogtle Owners entered into an agreement to clarify the process for the tender provisions of the Global Amendments to provide for a decision between 120 and 180 days after the tender option is triggered, which the other Vogtle Owners assert occurred on February 14, 2022.
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Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 continues to be 45.7%; however, it could increase if one or more of the other Vogtle Owners exercise the option to tender a portion of their ownership interest to Georgia Power and require Georgia Power to pay 100% of the remaining share of the costs necessary to complete Plant Vogtle Units 3 and 4. Georgia Power's incremental ownership interest would be calculated and conveyed to Georgia Power after Plant Vogtle Units 3 and 4 are placed in service.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At December 31, 2021, Georgia Power had recovered approximately $2.7 billion of financing costs. Financing costs related to capital costs above $4.418 billion are being recognized through AFUDC and are expected to be recovered through retail rates over the life of Plant Vogtle Units 3 and 4; however, Georgia Power is not recording AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery. On November 18, 2021, the Georgia PSC approved Georgia Power's request to decrease the NCCR tariff by $78 million annually, effective January 1, 2022.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's seventeenth VCM report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the $0.3 billion paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and related customer refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that a prudence proceeding on cost recovery will occur following Unit 4 fuel load, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that effective the first month after Unit 3 reaches commercial operation, retail base rates would be adjusted to include the costs related to Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement Agreement (see "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for additional information). The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective Unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $270 million, $150 million, and $75 million in 2021, 2020, and 2019, respectively, and are estimated to have negative earnings impacts of approximately $300 million and $265 million in 2022 and 2023, respectively. In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
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The Georgia PSC has approved 24 VCM reports covering periods through December 31, 2020, including total construction capital costs incurred through December 31, 2020 of $7.3 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). In the August 24, 2021 order approving the twenty-fourth VCM report, the Georgia PSC also approved a stipulation addressing the following matters: (i) beginning with its twenty-fifth VCM report, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will request for approval costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order and (ii) Georgia Power will not seek rate recovery of the $0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income by Georgia Power in the second quarter 2018. In addition, the stipulation confirms Georgia Power may request verification and approval of costs above $7.3 billion for inclusion in rate base at a later time, but no earlier than the prudence review contemplated by the seventeenth VCM order described previously. The Georgia PSC is scheduled to vote on the twenty-fifth VCM report on February 17, 2022. Georgia Power also expects to file its twenty-sixth VCM report with the Georgia PSC on February 17, 2022, which will reflect the revised capital cost forecast described above.
The ultimate outcome of these matters cannot be determined at this time.
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. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates.
2019 Base Rate Case
In March 2020, the Mississippi PSC approved a settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in 2019 (Mississippi Power Rate Case Settlement Agreement).
Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment.
Additionally, the Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable.
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 projected filing and the PEP lookback filing. In July 2020, the Mississippi PSC approved Mississippi Power's revisions to the PEP compliance rate clause as agreed to in the Mississippi Power Rate Case Settlement Agreement. These revisions include, among other things, changing the filing date for the annual PEP rate projected filing from November of the immediately preceding year to March of the current year, utilizing a historic test year adjusted for "known and measurable" changes, using discounted cash flow and regression formulas to determine base ROE, and moving all embedded ad valorem property taxes currently collected in PEP to the ad valorem tax adjustment clause. The PEP lookback filing will continue to be filed after the end of the year and allows for review of the actual revenue requirement.
Pursuant to a Mississippi PSC-approved settlement agreement between Mississippi Power and the MPUS, Mississippi Power was not required to make any PEP filings for regulatory years 2019 and 2020. On June 8, 2021, the Mississippi PSC approved Mississippi Power's annual retail PEP filing for 2021, resulting in an annual increase in revenues of approximately $16 million, or 1.8%, which became effective with the first billing cycle of April 2021.
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Integrated Resource Plan
In 2019, Mississippi Power updated its proposed Reserve Margin Plan (RMP), originally filed in 2018, as required by the Mississippi PSC. In 2018, Mississippi Power had proposed alternatives to reduce its reserve margin and lower or avoid operating costs. In December 2020, the Mississippi PSC issued an order concluding the RMP docket and requiring Mississippi Power to incorporate into its 2021 IRP a schedule of early or anticipated retirement of 950 MWs of fossil-steam generation by year-end 2027 to reduce Mississippi Power's excess reserve margin. The order stated that Mississippi Power will be allowed to defer any retirement-related costs as regulatory assets for future recovery.
On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. The 2021 IRP included a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power.
The remaining net book value of Plant Daniel Units 1 and 2 was approximately $515 million at December 31, 2021 and Mississippi Power is continuing to depreciate these units using the current approved rates through the end of 2027. Mississippi Power expects to reclassify the net book value remaining at retirement, which is expected to total approximately $386 million, to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with the December 2020 order. The Plant Watson and Greene County units are expected to be fully depreciated upon retirement. The ultimate outcome of these matters cannot be determined at this time. See Note 3 under "Other Matters – Mississippi Power" for additional information on Plant Daniel Units 1 and 2.
Environmental Compliance Overview Plan
In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations.
In accordance with a Mississippi PSC-approved settlement agreement between Mississippi Power and the MPUS, Mississippi Power was not required to make any ECO Plan filings for 2019 and 2020, and any necessary adjustments were reflected in Mississippi Power's 2019 base rate case.
In 2019, the Mississippi PSC approved Mississippi Power's request for a CPCN to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $67 million being proposed for recovery through its ECO Plan. As of December 31, 2021, approximately $20 million of Mississippi Power's share is included in plant in service, approximately $14 million is included in CWIP, and approximately $13 million associated with ash pond closure is reflected in Mississippi Power's ARO liabilities. See Note 6 for additional information on AROs and Note 3 under "Other Matters – Mississippi Power" for additional information on Gulf Power's ownership in Plant Daniel.
On June 8, 2021, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2021, resulting in a decrease in revenues of approximately $9 million annually, primarily due to a change in the amortization periods of certain regulatory assets and liabilities. The rate decrease became effective with the first billing cycle of July 2021.
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. The Mississippi PSC approved decreases of $35 million and $24 million effective in February 2019 and 2020, respectively, and increases of $2 million and $43 million effective in February 2021 and 2022, respectively. At December 31, 2021, under recovered retail fuel costs totaled approximately $4 million and were included in other customer accounts receivable on Southern Company's and Mississippi Power's balance sheets. At December 31, 2020, over recovered retail fuel costs totaled $24 million and were included in other current liabilities on Southern Company's balance sheet and over recovered regulatory clause liabilities on Mississippi Power's balance sheet.
Mississippi Power has wholesale MRA and Market Based (MB) fuel cost recovery factors. Effective with the first billing cycles for January 2020, 2021, and 2022, annual revenues under the wholesale MRA fuel rate increased $1 million, decreased $5 million, and increased $11 million, respectively. The wholesale MB fuel rate did not change materially in any period presented. At December 31, 2021, under recovered wholesale fuel costs were immaterial. At December 31, 2020, over recovered
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wholesale fuel costs totaled approximately $10 million and were included in other current liabilities on Southern Company's balance sheet and over recovered regulatory clause liabilities on Mississippi Power's balance sheet.
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 establishes annually an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by Mississippi Power. In 2020 and 2019, the annual revenues collected through the ad valorem tax adjustment factor increased by $10 million and decreased by $2 million, respectively. On April 6, 2021, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2021, which requested an annual increase in revenues of approximately $28 million, including approximately $19 million of ad valorem taxes previously recovered through PEP in accordance with the Mississippi Power Rate Case Settlement Agreement. The rate increase became effective with the first billing cycle of May 2021.
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).
Mississippi Power's net retail SRR accrual, which includes carrying costs and amortization of related excess deferred income tax benefits, was $(1.8) million in 2021, $0.8 million 2020, and $1.4 million in 2019. At December 31, 2020, the retail property damage reserve balance was $4 million. On October 14, 2021, the Mississippi PSC issued an accounting order giving Mississippi Power the authority to reclassify the retail costs associated with Hurricanes Zeta and Ida (approximately $49 million) to a regulatory asset to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. At December 31, 2021, the retail property damage reserve balance was $31 million, which reflects the impact of the reclassification.
On December 7, 2021, the Mississippi PSC approved Mississippi Power's annual SRR filing, which requested an increase in retail revenues of approximately $9 million annually effective with the first billing cycle of March 2022. The Mississippi PSC also established $8 million as the minimum annual accrual amount until a target property damage reserve balance of $75 million is met. 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.
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, cost-based, 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. The SSA may be cancelled by Cooperative Energy with 10 years notice. Cooperative Energy has the option to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually, with required notice, with a remaining total reduction of 8%, or approximately $8 million in cumulative annual base revenues.
In June 2020, the FERC accepted Mississippi Power's requested $2 million annual increase in MRA base rates effective June 1, 2020, as agreed upon in a settlement agreement reached with its wholesale customers.
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 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 weather conditions and price levels for natural gas. 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 and weather derivative instruments, 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(a) | 9.75% | 10.25% | 9.50% | 9.80% | |||||||||||||||||||
| Weather normalization mechanisms(b) | ü | ü | |||||||||||||||||||||
| Decoupled, including straight-fixed-variable rates(c) | ü | ü | ü | ||||||||||||||||||||
| Regulatory infrastructure program rates(d) | ü | ü | ü | ü | |||||||||||||||||||
| Bad debt rider(e) | ü | ü | ü | ||||||||||||||||||||
| Energy efficiency plan(f) | ü | ü | |||||||||||||||||||||
| Annual base rate adjustment mechanism(g) | ü | ü | |||||||||||||||||||||
| Year of last base rate case decision(h) | 2021 | 2019 | 2021 | 2018 |
(a)Represents the authorized ROE at December 31, 2021.
(b)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.
(c)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.
(d)Programs that update or expand distribution systems and LNG facilities. Atlanta Gas Light's infrastructure program, System Reinforcement Rider, is effective for 2022 through 2024. See "Rate Proceedings – Atlanta Gas Light" herein for additional information. Chattanooga Gas' pipeline replacement program costs are recovered through its annual base rate review mechanism.
(e)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.
(f)Recovery of costs associated with plans to achieve specified energy savings goals.
(g)Regulatory mechanism allowing annual adjustments to base rates up or down based on authorized ROE and/or ROE range.
(h)Annual GRAM filing required at Atlanta Gas Light.
Infrastructure Replacement Programs and Capital Projects
In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. Total capital expenditures incurred during 2021 for gas distribution operations were $1.5 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, 2021. 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 | Expenditures in 2021 | Expenditures Since Project Inception | Pipe Installed Since Project Inception | Scope of Program | Program Duration | Last Year of Program | ||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | (miles) | (miles) | (years) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Nicor Gas | Investing in Illinois(*) | Rider | $ | 408 | $ | 2,508 | 1,153 | 1,394 | 9 | 2023 | ||||||||||||||||||||||||||||||||||||||||||||||
| Virginia Natural Gas | Steps to Advance Virginia's Energy (SAVE) | Rider | 51 | 342 | 470 | 640 | 13 | 2024 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Atlanta Gas Light | System Reinforcement Rider | Rider | — | — | N/A | N/A | 3 | 2024 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Chattanooga Gas | Pipeline Replacement Program | Rate Base | 2 | 2 | 5 | 73 | 7 | 2027 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | 461 | $ | 2,852 | 1,628 | 2,107 |
(*)Includes replacement of pipes, compressors, and transmission mains along with other improvements such as new meters. Scope of program miles is an estimate and subject to change. Recovery of program costs is described under "Nicor Gas" herein.
Nicor Gas
Illinois legislation allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system and stipulates that rate increases to customers as a result of any infrastructure investments shall 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, subject to annual review. In accordance with orders from the Illinois Commission, Nicor Gas recovers program costs incurred through a separate rider and base rates. The Illinois Commission's approval of Nicor Gas' rate case on November 18, 2021 included recovery of program costs through December 31, 2021. See "Rate Proceedings – Nicor Gas" herein for additional information. Nicor Gas' capital expenditures related to qualifying projects under the Investing in Illinois program totaled $389 million and $396 million in 2020 and 2019, respectively.
Virginia Natural Gas
In 2019, the Virginia Commission approved amendments to and extension of the Steps to Advance Virginia's Energy (SAVE) program, an accelerated infrastructure replacement program. The extension allows Virginia Natural Gas to continue replacing aging pipeline infrastructure through 2024 and increases its authorized investment under the previously-approved plan from $35 million to $40 million in 2019 with additional annual investments of $50 million in 2020, $60 million in 2021, $70 million in each year from 2022 through 2024, and a total potential variance of up to $5 million allowed for the program, for a maximum total investment over the six-year term (2019 through 2024) of $365 million. Virginia Natural Gas' capital expenditures under the SAVE program totaled $49 million and $45 million in 2020 and 2019, respectively.
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 2021, Virginia Natural Gas is recovering program costs incurred prior to November 1, 2020 through base rates. Program costs incurred subsequent to November 1, 2020 are currently being recovered through a separate rider and are subject to future base rate case proceedings.
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 to be recovered through rates related to allowed, but not incurred, costs have been recognized in 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 being recovered through GRAM and base rates until the earlier of the full recovery of the related under recovered amount or December 31, 2025. The under recovered balance at December 31, 2021 was $91 million, including $47 million of unrecognized equity return. The Georgia PSC reviews Atlanta Gas Light's performance annually under GRAM. See "Unrecognized Ratemaking Amounts" herein for additional information.
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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 $15 million annually for strategic economic development projects approved by the Georgia PSC.
See "Rate Proceedings – Atlanta Gas Light" herein for additional information regarding the Georgia PSC's November 18, 2021 approval of Atlanta Gas Light's GRAM filing and Integrated Capacity and Delivery Plan. The Georgia PSC also approved a new System Reinforcement Rider for authorized large pressure improvement and system reliability projects, which is expected to recover related capital investments totaling $286 million for the years 2022 through 2024.
Chattanooga Gas
In June 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.
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. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' net income, but will affect 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, 2021, the under recovered balance was $473 million, $266 million of which was included in natural gas cost under recovery and $207 million of which was included in other regulatory assets, deferred on Southern Company's and Southern Company Gas' balance sheets. At December 31, 2020, the over recovered balance was $88 million, which was included in other regulatory liabilities on Southern Company's and Southern Company Gas' balance sheets.
Rate Proceedings
Nicor Gas
In 2019, the Illinois Commission approved a $168 million annual base rate increase effective October 8, 2019. The base rate increase included $65 million related to the recovery of program costs under the Investing in Illinois program and was based on a ROE of 9.73% and an equity ratio of 54.2%. Additionally, the Illinois Commission approved a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a benchmark level of revenue per rate class for recovery.
On November 18, 2021, the Illinois Commission approved a $240 million annual base rate increase effective November 24, 2021. The base rate increase included $94 million related to the recovery of program costs under the Investing in Illinois program and was based on a ROE of 9.75% and an equity ratio of 54.5%.
Atlanta Gas Light
In 2019, the Georgia PSC approved a $65 million annual base rate increase, effective January 1, 2020, based on a ROE of 10.25% and an equity ratio of 56%. Earnings will be evaluated against a 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 approved continuation of the previously authorized inclusion in base rates of the recovery of and return on the infrastructure program investments, including, but not limited to, GRAM adjustments, and a reauthorization and continuation of GRAM until terminated by the Georgia PSC. GRAM filing rate adjustments will be based on the authorized ROE of 10.25%. GRAM adjustments for 2021 could not exceed 5% of 2020 base rates. The 5% limitation does not set a precedent in any future rate proceedings by Atlanta Gas Light.
In July 2020, Atlanta Gas Light filed its annual GRAM filing with the Georgia PSC requesting an annual base rate increase of $37.6 million based on the projected 12-month period beginning January 1, 2021, which did not exceed the 5% limitation established by the Georgia PSC. Rates went into effect on January 1, 2021 in accordance with Atlanta Gas Light's 2019 rate case order.
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On February 16, 2021, the Georgia PSC approved a stipulation between Atlanta Gas Light and the Georgia PSC staff establishing a long-range comprehensive planning process. Under the terms of the stipulation, Atlanta Gas Light was required to develop and file at least triennially an Integrated Capacity and Delivery Plan (i-CDP). Each i-CDP will include a 10-year forecast of interstate and intrastate capacity asset requirements, including a detailed plan for the first three years consistent with Atlanta Gas Light's current capacity supply plan, and a 10-year projection of capital budgets and related operations and maintenance spending. Recovery of the related revenue requirements will be included in either subsequent annual GRAM filings or a new System Reinforcement Rider for authorized large pressure improvement and system reliability projects.
On April 28, 2021, Atlanta Gas Light filed its first i-CDP with the Georgia PSC, which includes 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.
On November 18, 2021, the Georgia PSC approved an October 14, 2021 joint stipulation agreement between Atlanta Gas Light and the staff of the Georgia PSC, under which, for the years 2022 through 2024, Atlanta Gas Light will incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, or $5 million for 2022. The stipulation agreement also provides for $1.7 billion of total capital investment for the years 2022 through 2024.
Also on November 18, 2021, the Georgia PSC approved Atlanta Gas Light's amended annual GRAM filing, which resulted in an annual rate increase of $43 million effective January 1, 2022.
Virginia Natural Gas
On September 14, 2021, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million. Refunds to customers related to the difference between the approved rates and the interim rates were completed during the fourth quarter 2021.
Deferral of Incremental COVID-19 Costs
As discussed under "Utility Regulation and Rate Design," the natural gas distribution utilities have various regulatory mechanisms to recover bad debt expense, which helped mitigate potential increases in bad debt expense as a result of the COVID-19 pandemic. Deferred incremental costs related to the COVID-19 pandemic were immaterial for Virginia Natural Gas.
Atlanta Gas Light
In April 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. In June 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 2020, with exceptions for customers still covered by a shelter-in-place order. All suspensions for customer disconnections were lifted in October 2020. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light will begin recovering these credits through GRAM rates effective January 1, 2023.
Nicor Gas
In March 2020, in response to the COVID-19 pandemic, the Illinois Commission issued an order directing utilities to cease disconnections for non-payment and to suspend the imposition of late payment fees or penalties. In June 2020, the Illinois Commission approved a stipulation pursuant to which Nicor Gas and other utilities in Illinois would provide more flexible credit and collection procedures to assist customers with financial hardship and which authorizes a special purpose rider for recovery of the following COVID-19 pandemic-related impacts: incremental costs directly associated with the COVID-19 pandemic, net of the offset for COVID-19 pandemic-related credits received, foregone late fees, foregone reconnection charges, and the costs associated with a bill payment assistance program. Nicor Gas resumed late payment fees in July 2020 and, on October 1, 2020, began recovery of the COVID-19 pandemic-related impacts through the special purpose rider, which will continue over a 24-month period. On March 18, 2021, the Illinois Commission approved a phased-in schedule for disconnections related to non-payment. Nicor Gas began certain disconnections in late April 2021 and resumed normal disconnections in June 2021. At December 31, 2021 and 2020, Nicor Gas' related regulatory asset was $5 million and $9 million, respectively.
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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 composed 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 2025.
| December 31, 2021 | December 31, 2020 | ||||||||||
| (in millions) | |||||||||||
| Atlanta Gas Light | $ | 47 | $ | 59 | |||||||
| Virginia Natural Gas | 10 | 10 | |||||||||
| Chattanooga Gas | 4 | 2 | |||||||||
| Nicor Gas | — | 3 | |||||||||
| Total | $ | 61 | $ | 74 |
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 believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time.
Southern Company
In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust.
The plaintiffs in each of these cases seek to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiffs also seek certain changes to Southern Company's corporate governance and internal processes. On January 21, 2022, the plaintiffs in the federal court action filed a motion for preliminary approval of settlement, together with an executed stipulation of settlement, which applies to both the federal and state actions. The terms of the settlement are not expected to have a material impact on Southern Company's financial statements.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of amounts for municipal franchise fees (which fees are paid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state law claims. This case has been ruled upon and appealed numerous times over the last several years. In October 2019, the Georgia PSC issued an order that found Georgia Power
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has appropriately implemented the municipal franchise fee schedule. On March 16, 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment. On March 22, 2021, the plaintiffs filed a notice of appeal, and, on April 2, 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. On December 1, 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to Georgia Power and dismissed Georgia Power's cross appeal on the issue of class certification as moot. On December 21, 2021, the plaintiffs filed a petition for writ of certiorari to the Georgia Supreme Court. The amount of any possible losses cannot be estimated at this time because, among other factors, it is unknown whether any losses would be subject to recovery from any municipalities.
In July 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. Georgia Power has filed multiple motions to dismiss the complaint. On October 8, 2021, three additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. On November 11, 2021, Georgia Power filed a notice to remove the three cases pending in the Superior Court of Monroe County to the U.S. District Court in the Middle District of Georgia. On February 7, 2022, four additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power seeking damages for alleged personal injuries or property damage. The amount of any possible losses from these matters cannot be estimated at this time.
Mississippi Power
In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper and make claims for gross negligence, reckless conduct, and intentional wrongdoing. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the court denied each of the plaintiffs' pending motions and entered final judgment in favor of Mississippi Power. On January 22, 2021, the court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. On February 19, 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
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.
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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 2021, 2020, and 2019, Georgia Power recovered approximately $12 million, $12 million, and $2 million, respectively, through the ECCR tariff for environmental remediation.
Southern Company Gas is subject to environmental remediation liabilities associated with 40 former MGP sites in four different states. Southern Company Gas' accrued environmental remediation liability at December 31, 2021 and 2020 was based on the estimated cost of environmental investigation and remediation associated with these sites.
At December 31, 2021 and 2020, 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. At December 31, 2021 and 2020, Alabama Power did not have environmental remediation liabilities and Mississippi Power's balance was immaterial.
| Southern Company | Georgia Power | Southern Company Gas | |||||||||
| (in millions) | |||||||||||
| December 31, 2021: | |||||||||||
| Environmental remediation liability: | |||||||||||
| Other current liabilities | $ | 69 | $ | 17 | $ | 52 | |||||
| Accrued environmental remediation | 197 | — | 197 | ||||||||
| Under recovered environmental remediation costs: | |||||||||||
| Other regulatory assets, current | $ | 71 | $ | 12 | $ | 59 | |||||
| Other regulatory assets, deferred | 231 | 23 | 208 | ||||||||
| December 31, 2020: | |||||||||||
| Environmental remediation liability: | |||||||||||
| Other current liabilities | $ | 44 | $ | 15 | $ | 29 | |||||
| Accrued environmental remediation | 216 | — | 216 | ||||||||
| Under recovered environmental remediation costs: | |||||||||||
| Other regulatory assets, current | $ | 46 | $ | 12 | $ | 34 | |||||
| Other regulatory assets, deferred | 265 | 29 | 236 |
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.
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 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 the 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 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government 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, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. In 2019, the Court of Federal Claims granted Alabama Power's and Georgia Power's motion for summary judgment on damages not disputed by the U.S. government, awarding those undisputed damages to Alabama Power and Georgia Power. However, those undisputed damages are not collectible until the court enters final judgment on the remaining damages.
In 2017, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government in the Court of Federal Claims 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
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1, 2015 through December 31, 2017. In August 2020, Alabama Power and Georgia Power filed amended complaints in each of the lawsuits adding damages from January 1, 2018 to December 31, 2019 to the claim period.
The outstanding claims for the period January 1, 2011 through December 31, 2019 total $110 million and $132 million for Alabama Power and Georgia Power (based on its ownership interests), respectively. 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, 2021 for any potential recoveries from the pending lawsuits.
The final outcome of these matters 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 $13.5 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 $450 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 $138 million per incident for each licensed reactor it operates but not more than an aggregate of $20 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 $275 million and $267 million, respectively, per incident, but not more than an aggregate of $41 million and $40 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, 2023. 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.
A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction.
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, 2021 under the NEIL policies would be $52 million and $83 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
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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 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 2019, 2020, and 2021, 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 $24 million pre-tax and after tax in 2019, $4 million pre-tax ($3 million after tax) in 2020, and $11 million pre-tax ($8 million after tax) in 2021. The pre-tax charges are included in other operations and maintenance expenses on the statements of income.
Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed by 2026. Additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, net of salvage, are estimated to total $10 million to $20 million annually through 2025.
Mississippi Power owns the lignite mine located around the Kemper County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and was substantially completed in 2020, with monitoring expected to continue through 2028.
As the mining permit holder, Liberty Fuels Company, LLC, a wholly-owned subsidiary of The North American Coal Corporation, has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. See Note 6 for additional information.
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 September 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. The expected impact of the closeout agreement was accrued in 2019. In connection with the DOE closeout discussions, in 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the grants received. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's financial statements.
Plant Daniel
In conjunction with Southern Company's sale of Gulf Power, NextEra Energy held back $75 million of the purchase price pending Mississippi Power and Gulf Power negotiating a mutually acceptable revised operating agreement for Plant Daniel. In addition, Mississippi Power and Gulf Power agreed to seek a restructuring of their 50% undivided ownership interests in the Plant Daniel coal units such that each of them would, after the restructuring, own 100% of a generating unit. In 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the coal generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. Mississippi Power and Gulf Power are continuing negotiations on a mutually acceptable revised operating agreement. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC and the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. See Note 2 under "Mississippi Power – Integrated Resource Plan" for additional information on Plant Daniel and Note 15 under "Southern Company" for information regarding the sale of Gulf Power.
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
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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 statements of income and in purchased power, non-affiliates in Georgia Power's statements of income. Georgia Power's capacity payments related to this commitment totaled $6 million, $5 million, and $6 million in 2021, 2020, and 2019, respectively. At December 31, 2021, Georgia Power's estimated long-term obligations related to this commitment totaled $42 million, consisting of $4 million for 2022, $3 million annually for 2023 through 2025, $1 million for 2026, and $28 million thereafter.
See Note 9 for information regarding PPAs accounted for as leases.
Southern Company Gas has commitments for pipeline charges, storage capacity, and gas supply, including charges recoverable through natural gas cost recovery mechanisms or, alternatively, billed to marketers selling retail natural gas. Gas supply commitments include amounts for gas commodity purchases associated with Nicor Gas and SouthStar of 56 million mmBtu at floating gas prices calculated using forward natural gas prices at December 31, 2021 and valued at $222 million. Southern Company Gas provides guarantees to certain gas suppliers for certain of its subsidiaries in support of payment obligations. Southern Company Gas' expected future contractual obligations for pipeline charges, storage capacity, and gas supply that are not recognized on the balance sheets at December 31, 2021 were as follows:
| Pipeline Charges, Storage Capacity, and Gas Supply | |||||
| (in millions) | |||||
| 2022 | $ | 634 | |||
| 2023 | 455 | ||||
| 2024 | 376 | ||||
| 2025 | 275 | ||||
| 2026 | 164 | ||||
| Thereafter | 910 | ||||
| Total | $ | 2,814 |
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 in 2021. 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, 2021, the capitalization of SEGCO consisted of $82 million of equity and $100 million of long-term debt that matures in November 2024, on which the annual interest requirement is derived from a variable rate index. In addition, SEGCO had short-term debt outstanding of $20 million. 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.
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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. See Note 1 under "Revenues" for additional information on the revenue policies of the Registrants. See Notes 9 and 14 for additional information on revenue accounted for under lease and derivative accounting guidance, respectively.
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) | ||||||||||||||||||||
| 2021 | ||||||||||||||||||||
| Operating revenues | ||||||||||||||||||||
| Retail electric revenues | ||||||||||||||||||||
| Residential | $ | 6,207 | $ | 2,467 | $ | 3,471 | $ | 269 | $ | — | $ | — | ||||||||
| Commercial | 4,877 | 1,600 | 3,010 | 267 | — | — | ||||||||||||||
| Industrial | 3,067 | 1,386 | 1,391 | 290 | — | — | ||||||||||||||
| Other | 93 | 17 | 68 | 8 | — | — | ||||||||||||||
| Total retail electric revenues | 14,244 | 5,470 | 7,940 | 834 | — | — | ||||||||||||||
| Natural gas distribution revenues | ||||||||||||||||||||
| Residential | 1,799 | — | — | — | — | 1,799 | ||||||||||||||
| Commercial | 470 | — | — | — | — | 470 | ||||||||||||||
| Transportation | 1,038 | — | — | — | — | 1,038 | ||||||||||||||
| Industrial | 49 | — | — | — | — | 49 | ||||||||||||||
| Other | 269 | — | — | — | — | 269 | ||||||||||||||
| Total natural gas distribution revenues | 3,625 | — | — | — | — | 3,625 | ||||||||||||||
| Wholesale electric revenues | ||||||||||||||||||||
| PPA energy revenues | 1,122 | 184 | 95 | 11 | 854 | — | ||||||||||||||
| PPA capacity revenues | 493 | 115 | 55 | 5 | 323 | — | ||||||||||||||
| Non-PPA revenues | 236 | 170 | 21 | 401 | 398 | — | ||||||||||||||
| Total wholesale electric revenues | 1,851 | 469 | 171 | 417 | 1,575 | — | ||||||||||||||
| Other natural gas revenues | ||||||||||||||||||||
| Wholesale gas services | 2,168 | — | — | — | — | 2,168 | ||||||||||||||
| Gas marketing services | 464 | — | — | — | — | 464 | ||||||||||||||
| Other natural gas revenues | 36 | — | — | — | — | 36 | ||||||||||||||
| Total natural gas revenues | 2,668 | — | — | — | — | 2,668 | ||||||||||||||
| Other revenues | 1,075 | 202 | 452 | 31 | 30 | — | ||||||||||||||
| Total revenue from contracts with customers | 23,463 | 6,141 | 8,563 | 1,282 | 1,605 | 6,293 | ||||||||||||||
| Other revenue sources(a) | 3,349 | 272 | 697 | 40 | 611 | 1,786 | ||||||||||||||
| Other adjustments(b) | (3,699) | — | — | — | — | (3,699) | ||||||||||||||
| Total operating revenues | $ | 23,113 | $ | 6,413 | $ | 9,260 | $ | 1,322 | $ | 2,216 | $ | 4,380 | ||||||||
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2020 | ||||||||||||||||||||
| Operating revenues | ||||||||||||||||||||
| Retail electric revenues | ||||||||||||||||||||
| Residential | $ | 6,113 | $ | 2,377 | $ | 3,476 | $ | 260 | $ | — | $ | — | ||||||||
| Commercial | 4,699 | 1,512 | 2,933 | 254 | — | — | ||||||||||||||
| Industrial | 2,775 | 1,293 | 1,197 | 285 | — | — | ||||||||||||||
| Other | 90 | 21 | 60 | 9 | — | — | ||||||||||||||
| Total retail electric revenues | 13,677 | 5,203 | 7,666 | 808 | — | — | ||||||||||||||
| Natural gas distribution revenues | ||||||||||||||||||||
| Residential | 1,338 | — | — | — | — | 1,338 | ||||||||||||||
| Commercial | 340 | — | — | — | — | 340 | ||||||||||||||
| Transportation | 971 | — | — | — | — | 971 | ||||||||||||||
| Industrial | 30 | — | — | — | — | 30 | ||||||||||||||
| Other | 209 | — | — | — | — | 209 | ||||||||||||||
| Total natural gas distribution revenues | 2,888 | — | — | — | — | 2,888 | ||||||||||||||
| Wholesale electric revenues | ||||||||||||||||||||
| PPA energy revenues | 735 | 133 | 42 | 9 | 570 | — | ||||||||||||||
| PPA capacity revenues | 454 | 108 | 50 | 3 | 296 | — | ||||||||||||||
| Non-PPA revenues | 210 | 43 | 10 | 311 | 239 | — | ||||||||||||||
| Total wholesale electric revenues | 1,399 | 284 | 102 | 323 | 1,105 | — | ||||||||||||||
| Other natural gas revenues | ||||||||||||||||||||
| Wholesale gas services | 1,727 | — | — | — | — | 1,727 | ||||||||||||||
| Gas marketing services | 391 | — | — | — | — | 391 | ||||||||||||||
| Other natural gas revenues | 33 | — | — | — | — | 33 | ||||||||||||||
| Total other natural gas revenues | 2,151 | — | — | — | — | 2,151 | ||||||||||||||
| Other revenues | 982 | 159 | 447 | 26 | 14 | — | ||||||||||||||
| Total revenue from contracts with customers | 21,097 | 5,646 | 8,215 | 1,157 | 1,119 | 5,039 | ||||||||||||||
| Other revenue sources(a) | 3,764 | 184 | 94 | 15 | 614 | 2,881 | ||||||||||||||
| Other adjustments(b) | (4,486) | — | — | — | — | (4,486) | ||||||||||||||
| Total operating revenues | $ | 20,375 | $ | 5,830 | $ | 8,309 | $ | 1,172 | $ | 1,733 | $ | 3,434 | ||||||||
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2019 | ||||||||||||||||||||
| Operating revenues | ||||||||||||||||||||
| Retail electric revenues | ||||||||||||||||||||
| Residential | $ | 6,164 | $ | 2,509 | $ | 3,377 | $ | 278 | $ | — | $ | — | ||||||||
| Commercial | 5,065 | 1,677 | 3,097 | 291 | — | — | ||||||||||||||
| Industrial | 3,126 | 1,460 | 1,360 | 306 | — | — | ||||||||||||||
| Other | 90 | 25 | 54 | 11 | — | — | ||||||||||||||
| Total retail electric revenues | 14,445 | 5,671 | 7,888 | 886 | — | — | ||||||||||||||
| Natural gas distribution revenues | ||||||||||||||||||||
| Residential | 1,413 | — | — | — | — | 1,413 | ||||||||||||||
| Commercial | 389 | — | — | — | — | 389 | ||||||||||||||
| Transportation | 907 | — | — | — | — | 907 | ||||||||||||||
| Industrial | 35 | — | — | — | — | 35 | ||||||||||||||
| Other | 245 | — | — | — | — | 245 | ||||||||||||||
| Total natural gas distribution revenues | 2,989 | — | — | — | — | 2,989 | ||||||||||||||
| Wholesale electric revenues | ||||||||||||||||||||
| PPA energy revenues | 833 | 145 | 60 | 11 | 648 | — | ||||||||||||||
| PPA capacity revenues | 453 | 102 | 54 | 3 | 322 | — | ||||||||||||||
| Non-PPA revenues | 232 | 81 | 9 | 352 | 238 | — | ||||||||||||||
| Total wholesale electric revenues | 1,518 | 328 | 123 | 366 | 1,208 | — | ||||||||||||||
| Other natural gas revenues | ||||||||||||||||||||
| Gas pipeline investments | 32 | — | — | — | — | 32 | ||||||||||||||
| Wholesale gas services | 2,095 | — | — | — | — | 2,095 | ||||||||||||||
| Gas marketing services | 440 | — | — | — | — | 440 | ||||||||||||||
| Other natural gas revenues | 42 | — | — | — | — | 42 | ||||||||||||||
| Total other natural gas revenues | 2,609 | — | — | — | — | 2,609 | ||||||||||||||
| Other revenues | 1,035 | 153 | 407 | 19 | 12 | — | ||||||||||||||
| Total revenue from contracts with customers | 22,596 | 6,152 | 8,418 | 1,271 | 1,220 | 5,598 | ||||||||||||||
| Other revenue sources(a) | 4,266 | (27) | (10) | (7) | 718 | 3,637 | ||||||||||||||
| Other adjustments(b) | (5,443) | — | — | — | — | (5,443) | ||||||||||||||
| Total operating revenues | $ | 21,419 | $ | 6,125 | $ | 8,408 | $ | 1,264 | $ | 1,938 | $ | 3,792 |
(a)Other revenue sources relate to revenues from customers accounted for as derivatives and leases, alternative revenue programs at Southern Company Gas, and cost recovery mechanisms and revenues that meet other scope exceptions for revenues from contracts with customers at the traditional electric operating companies.
(b)Other adjustments relate to the cost of Southern Company Gas' energy and risk management activities. Wholesale gas services revenues are presented net of the related costs of those activities on the statement of income. See Notes 15 and 16 under "Southern Company Gas" for information on the sale of Sequent and components of wholesale gas services' operating revenues, respectively.
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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, 2021 and 2020:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Accounts Receivable | ||||||||||||||||||||
| At December 31, 2021 | $ | 2,504 | $ | 589 | $ | 736 | $ | 73 | $ | 149 | $ | 753 | ||||||||
| At December 31, 2020 | 2,614 | 632 | 806 | 77 | 112 | 788 | ||||||||||||||
| Contract Assets | ||||||||||||||||||||
| At December 31, 2021 | $ | 117 | $ | 2 | $ | 63 | $ | — | $ | 1 | $ | — | ||||||||
| At December 31, 2020 | 158 | 2 | 71 | — | — | — | ||||||||||||||
| Contract Liabilities | ||||||||||||||||||||
| At December 31, 2021 | $ | 57 | $ | 4 | $ | 14 | $ | — | $ | 1 | $ | — | ||||||||
| At December 31, 2020 | 61 | 6 | 27 | 1 | 1 | 1 |
At December 31, 2021 and 2020, Georgia Power had contract assets primarily related 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 relate to cash collections recognized in advance of revenue for unregulated service agreements. Southern Company's unregulated distributed generation business had contract assets of $50 million and $81 million at December 31, 2021 and 2020, respectively, and contract liabilities of $39 million and $27 million at December 31, 2021 and 2020, respectively, for outstanding performance obligations.
Revenues recognized in 2021 and 2020, which were included in contract liabilities at December 31, 2020 and December 31, 2019, respectively, were $29 million and $33 million, respectively, for Southern Company and immaterial for the other Registrants.
Remaining Performance Obligations
The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity 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, 2021 are expected to be recognized as follows:
| 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Southern Company | $ | 577 | $ | 462 | $ | 341 | $ | 319 | $ | 295 | $ | 2,309 | ||||||||
| Alabama Power | 33 | 24 | 7 | 5 | — | — | ||||||||||||||
| Georgia Power | 68 | 48 | 25 | 22 | 11 | 31 | ||||||||||||||
| Southern Power | 331 | 293 | 309 | 292 | 287 | 2,294 |
Revenue expected to be recognized for performance obligations remaining at December 31, 2021 was immaterial for Mississippi Power.
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.
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The Registrants' property, plant, and equipment in service consisted of the following at December 31, 2021 and 2020:
| At December 31, 2021: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| (in millions) | ||||||||||||||||||||
| Electric utilities: | ||||||||||||||||||||
| Generation | $ | 53,803 | $ | 16,631 | $ | 19,184 | $ | 2,791 | $ | 14,551 | $ | — | ||||||||
| Transmission | 13,406 | 5,334 | 7,132 | 900 | — | — | ||||||||||||||
| Distribution | 22,236 | 8,643 | 12,437 | 1,156 | — | — | ||||||||||||||
| General/other | 5,423 | 2,527 | 2,579 | 259 | 34 | — | ||||||||||||||
| Electric utilities' plant in service | 94,868 | 33,135 | 41,332 | 5,106 | 14,585 | — | ||||||||||||||
| Southern Company Gas: | ||||||||||||||||||||
| Natural gas distribution utilities transportation and distribution | 15,714 | — | — | — | — | 15,714 | ||||||||||||||
| Storage facilities | 1,315 | — | — | — | — | 1,315 | ||||||||||||||
| Other | 1,851 | — | — | — | — | 1,851 | ||||||||||||||
| Southern Company Gas plant in service | 18,880 | — | — | — | — | 18,880 | ||||||||||||||
| Other plant in service | 1,844 | — | — | — | — | — | ||||||||||||||
| Total plant in service | $ | 115,592 | $ | 33,135 | $ | 41,332 | $ | 5,106 | $ | 14,585 | $ | 18,880 |
| At December 31, 2020: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| (in millions) | ||||||||||||||||||||
| Electric utilities: | ||||||||||||||||||||
| Generation | $ | 52,179 | $ | 16,201 | $ | 18,675 | $ | 2,819 | $ | 13,872 | $ | — | ||||||||
| Transmission | 12,879 | 5,033 | 6,951 | 856 | — | — | ||||||||||||||
| Distribution | 20,958 | 8,248 | 11,622 | 1,088 | — | — | ||||||||||||||
| General/other | 5,072 | 2,334 | 2,434 | 248 | 32 | — | ||||||||||||||
| Electric utilities' plant in service | 91,088 | 31,816 | 39,682 | 5,011 | 13,904 | — | ||||||||||||||
| Southern Company Gas: | ||||||||||||||||||||
| Natural gas distribution utilities transportation and distribution | 14,610 | — | — | — | — | 14,610 | ||||||||||||||
| Storage facilities | 1,752 | — | — | — | — | 1,752 | ||||||||||||||
| Other | 1,249 | — | — | — | — | 1,249 | ||||||||||||||
| Southern Company Gas plant in service | 17,611 | — | — | — | — | 17,611 | ||||||||||||||
| Other plant in service | 1,817 | — | — | — | — | — | ||||||||||||||
| Total plant in service | $ | 110,516 | $ | 31,816 | $ | 39,682 | $ | 5,011 | $ | 13,904 | $ | 17,611 |
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 operating cycle, or 18 months for Plant Vogtle Units 1 and 2 and 24 months for Plant Hatch Units 1 and 2. Georgia Power's amortization period begins the month the refueling outage starts.
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A portion of Mississippi Power's railway track maintenance costs is charged to fuel stock and recovered through Mississippi Power's fuel clause.
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. 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. At December 31, 2021 and 2020, deferred cloud implementation costs, which are generally included in other deferred charges and assets on the Registrants' balance sheets, are as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Deferred cloud implementation costs: | ||||||||||||||||||||
| At December 31, 2021 | $ | 240 | $ | 54 | $ | 81 | $ | 11 | $ | 14 | $ | 35 | ||||||||
| At December 31, 2020 | 162 | 38 | 58 | 7 | 9 | 17 |
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 2021, 2020, and 2019 are as follows:
| 2021 | 2020 | 2019 | |||||||||
| Alabama Power | 2.7 | % | 2.6 | % | 3.1 | % | |||||
| Georgia Power | 3.3 | % | 3.0 | % | 2.6 | % | |||||
| Mississippi Power | 3.6 | % | 3.7 | % | 3.7 | % | |||||
| Southern Company Gas | 2.8 | % | 2.8 | % | 2.9 | % |
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. During 2020, Georgia Power, Mississippi Power, and Atlanta Gas Light revised their depreciation rates in accordance with base rate case approvals by their respective PSCs. The revised rates were effective January 1, 2020 for Georgia Power and Atlanta Gas Light and April 1, 2020 for Mississippi Power. 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.
At December 31, 2021 and 2020, accumulated depreciation for Southern Company and Southern Company Gas consisted of utility plant in service totaling $33.1 billion and $31.6 billion, respectively, for Southern Company and $4.8 billion and $4.6 billion, respectively, for Southern Company Gas, as well as other plant in service totaling $930 million and $817 million, respectively, for Southern Company and $219 million and $195 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 12 years for transportation equipment, 30 to 75 years for storage facilities, and up to 75 years for other assets. Useful lives for the assets of Southern Company's other non-utility subsidiaries range up to 37 years.
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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 30 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 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.
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Joint Ownership Agreements
At December 31, 2021, 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 | |||||||||||||||||||||||
| Greene County (natural gas) Units 1 and 2 | 60.0 | % | (a) | $ | 191 | $ | 79 | $ | 1 | ||||||||||||||
| Plant Miller (coal) Units 1 and 2 | 91.8 | (b) | 2,133 | 665 | 15 | ||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Plant Hatch (nuclear) | 50.1 | % | (c) | $ | 1,382 | $ | 647 | $ | 42 | ||||||||||||||
| Plant Vogtle (nuclear) Units 1 and 2 | 45.7 | (c) | 3,611 | 2,265 | 86 | ||||||||||||||||||
| Plant Scherer (coal) Units 1 and 2 | 8.4 | (c) | 276 | 100 | 1 | ||||||||||||||||||
| Plant Scherer (coal) Unit 3 | 75.0 | (c) | 1,314 | 539 | 8 | ||||||||||||||||||
| Plant Wansley (coal) | 53.5 | (c) | 1,070 | 472 | 7 | ||||||||||||||||||
| Rocky Mountain (pumped storage) | 25.4 | (d) | 184 | 148 | 1 | ||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Greene County (natural gas) Units 1 and 2 | 40.0 | % | (a) | $ | 124 | $ | 61 | $ | — | ||||||||||||||
| Plant Daniel (coal) Units 1 and 2 | 50.0 | (e) | 762 | 237 | 19 | ||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Dalton Pipeline (natural gas pipeline) | 50.0 | % | (f) | $ | 271 | $ | 19 | $ | — |
(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 Units 1 and 2, Scherer, and Wansley in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, Dalton, Florida Power & Light Company, JEA, and Gulf Power. 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 by Gulf Power and Mississippi Power. In accordance with the operating agreement, Mississippi Power acts as Gulf Power's agent with respect to the operation and maintenance of these units. See Note 3 under "Other Matters – Mississippi Power – Plant Daniel" for information regarding a commitment between Mississippi Power and Gulf Power to seek a restructuring of their 50% undivided ownership interests in Plant Daniel.
(f)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.
Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of $8.6 billion at December 31, 2021, excluding estimated probable losses recorded in 2018, 2020, and 2021. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
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
In 2018, the Mississippi PSC approved executed agreements between Mississippi Power and its largest retail customer, Chevron Products Company (Chevron), for Mississippi Power to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through at least 2038. The agreements grant Chevron a security interest in the co-generation assets owned by Mississippi Power, with a lease receivable balance of $167 million at December 31, 2021, located at the refinery 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.
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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 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 the CCR Rule and the related state rules, principally ash ponds. 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 Plant Hatch and Plant Vogtle Units 1 and 2). 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, 2019 | $ | 9,786 | $ | 3,540 | $ | 5,784 | $ | 190 | $ | 89 | |||||||
| Liabilities incurred | 19 | — | 10 | — | 9 | ||||||||||||
| Liabilities settled | (442) | (219) | (185) | (22) | — | ||||||||||||
| Accretion | 409 | 152 | 238 | 8 | 4 | ||||||||||||
| Cash flow revisions | 912 | 501 | 418 | — | (7) | ||||||||||||
| Balance at December 31, 2020 | $ | 10,684 | $ | 3,974 | $ | 6,265 | $ | 176 | $ | 95 | |||||||
| Liabilities incurred | 26 | — | 3 | — | 23 | ||||||||||||
| Liabilities settled | (456) | (202) | (210) | (24) | — | ||||||||||||
| Accretion | 407 | 156 | 236 | 7 | 5 | ||||||||||||
| Cash flow revisions | 1,026 | 406 | 530 | 31 | 8 | ||||||||||||
| Balance at December 31, 2021 | $ | 11,687 | $ | 4,334 | $ | 6,824 | $ | 190 | $ | 131 |
(*)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
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During 2020, Alabama Power recorded increases totaling approximately $501 million to its AROs related to the CCR Rule and the related state rule primarily as a result of management's completion of the closure design for the remaining ash pond and the addition of a water treatment system to the design of another ash pond. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to inputs from contractor bids, design revisions, and changes in the expected volume of ash handling. During 2021, Alabama Power recorded increases totaling approximately $406 million to its AROs primarily related to the CCR Rule and the related state rule based on updated estimates for post-closure costs at its ash ponds and inflation rates.
During the third quarter 2020, Georgia Power refined the cost estimates related to its plans to close the ash ponds at all of its generating plants in compliance with the CCR Rule and the related state rule, including updates to long-term post-closure care requirements, market pricing, and timing of future cash outlays and recorded an increase of approximately $411 million to its AROs related to the CCR Rule and the related state rule. In September 2021, Georgia Power recorded a further increase of approximately $435 million to these AROs based on updated estimates for inflation rates and the timing of closure activities.
In September 2021, Mississippi Power recorded an increase of approximately $31 million to its AROs related to the CCR Rule based on updated estimates for the timing of closure activities, post-closure costs at one of its ash ponds, and inflation rates.
The cost estimates for AROs related to the disposal of CCR are based on information at December 31, 2021 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. 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. See Note 2 under "Georgia Power – Rate Plans" for additional information. The ultimate outcome of these matters cannot be determined at this time.
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.
The Funds at Georgia Power participate in a securities lending program through the managers of the Funds. Under this program, Georgia Power's Funds' investment securities are loaned to institutional investors for a fee. Securities loaned are fully collateralized by cash, letters of credit, and/or securities issued or guaranteed by the U.S. government or its agencies or instrumentalities. At December 31, 2021 and 2020, approximately $42 million and $44 million, respectively, of the fair market value of Georgia Power's Funds' securities were on loan and pledged to creditors under the Funds' managers' securities lending program. The fair value of the collateral received was approximately $43 million and $45 million at December 31, 2021 and 2020, respectively, and can only be sold by the borrower upon the return of the loaned securities. The collateral received is treated as a non-cash item in the statements of cash flows.
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Investment securities in the Funds for December 31, 2021 and 2020 were as follows:
| Southern Company | Alabama Power | Georgia Power | |||||||||
| (in millions) | |||||||||||
| At December 31, 2021: | |||||||||||
| Equity securities | $ | 1,358 | $ | 849 | $ | 509 | |||||
| Debt securities | 986 | 316 | 670 | ||||||||
| Other securities | 197 | 159 | 38 | ||||||||
| Total investment securities in the Funds | $ | 2,541 | $ | 1,324 | $ | 1,217 | |||||
| At December 31, 2020: | |||||||||||
| Equity securities | $ | 1,339 | $ | 842 | $ | 497 | |||||
| Debt securities | 851 | 231 | 620 | ||||||||
| Other securities | 111 | 83 | 28 | ||||||||
| Total investment securities in the Funds | $ | 2,301 | $ | 1,156 | $ | 1,145 |
These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases. For Southern Company and Georgia Power, these amounts include Georgia Power's investment securities pledged to creditors and collateral received and excludes payables related to Georgia Power's securities lending program.
The fair value increases (decreases) of the Funds, including unrealized gains (losses) and reinvested interest and dividends and excluding the Funds' expenses, for 2021, 2020, and 2019 are shown in the table below.
| Southern Company | Alabama Power | Georgia Power | |||||||||
| (in millions) | |||||||||||
| Fair value increases | |||||||||||
| 2021 | $ | 274 | $ | 200 | $ | 74 | |||||
| 2020 | 280 | 142 | 138 | ||||||||
| 2019 | 344 | 194 | 150 | ||||||||
| Unrealized gains (losses) | |||||||||||
| At December 31, 2021 | $ | (27) | $ | (30) | $ | 3 | |||||
| At December 31, 2020 | 220 | 121 | 99 | ||||||||
| At December 31, 2019 | 259 | 149 | 110 |
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 $15 million at each of December 31, 2021 and 2020 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, 2021 and 2020, the accumulated provisions for the external decommissioning trust funds were as follows:
| 2021 | 2020 | ||||||||||
| (in millions) | |||||||||||
| Alabama Power | |||||||||||
| Plant Farley | $ | 1,324 | $ | 1,156 | |||||||
| Georgia Power | |||||||||||
| Plant Hatch | $ | 757 | $ | 716 | |||||||
| Plant Vogtle Units 1 and 2 | 460 | 429 | |||||||||
| Total | $ | 1,217 | $ | 1,145 |
Site study cost is the estimate to decommission a specific facility as of the site study year. The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. 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, 2021 based on the most current studies, which were performed in 2018 for Alabama Power and in 2021 for Georgia Power, were as follows:
| Plant Farley | Plant Hatch**(*)** | Plant Vogtle Units 1 and 2**(*)** | |||||||||||||||
| Decommissioning periods: | |||||||||||||||||
| Beginning year | 2037 | 2034 | 2047 | ||||||||||||||
| Completion year | 2076 | 2075 | 2079 | ||||||||||||||
| (in millions) | |||||||||||||||||
| Site study costs: | |||||||||||||||||
| Radiated structures | $ | 1,234 | $ | 771 | $ | 628 | |||||||||||
| Spent fuel management | 387 | 186 | 170 | ||||||||||||||
| Non-radiated structures | 99 | 61 | 85 | ||||||||||||||
| Total site study costs | $ | 1,720 | $ | 1,018 | $ | 883 |
(*)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 as of 2021. Significant assumptions used to determine these costs for ratemaking were an estimated inflation rate of 4.5% and 2.5% for Alabama Power and Georgia Power, respectively, and an estimated trust earnings rate of 7.0% and 4.5% for Alabama Power and Georgia Power, respectively.
Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements.
Effective January 1, 2020, in connection with the 2019 ARP, Georgia Power's annual decommissioning cost for ratemaking is a total of $4 million for Plant Hatch and Plant Vogtle Units 1 and 2. Georgia Power's annual decommissioning cost for ratemaking in 2019 totaled $5 million.
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.
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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.
SEGCO
Alabama Power and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. 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 a ROE. The share of purchased power included in purchased power, affiliates in the statements of income totaled $75 million in 2021, $67 million in 2020, and $93 million in 2019 for Alabama Power and $77 million in 2021, $69 million in 2020, and $95 million in 2019 for Georgia Power.
SEGCO paid dividends of $14 million in 2021, $12 million in 2020, and $14 million in 2019, 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 and SP Wind
In 2018, Southern Power sold a noncontrolling 33% limited partnership interest in SP Solar to Global Atlantic Financial Group Limited (Global Atlantic). A wholly-owned subsidiary of Southern Power is the general partner and holds a 1% ownership interest in SP Solar and another wholly-owned subsidiary of Southern Power owns the remaining 66% ownership in SP Solar. 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, 2021 and 2020, SP Solar had total assets of $6.1 billion, total liabilities of $408 million and $387 million, respectively, and noncontrolling interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic 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.
In 2018, Southern Power sold a noncontrolling tax equity interest in SP Wind to three financial investors. Southern Power owns 100% of the Class B membership interests and the three financial investors own 100% of the Class A membership interests. SP Wind qualifies as a VIE since the structure of the arrangement is similar to a limited partnership and the Class A members do not have substantive kick-out rights against Southern Power.
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At December 31, 2021 and 2020, SP Wind had total assets of $2.3 billion and $2.4 billion, respectively, total liabilities of $130 million and $138 million, respectively, and noncontrolling interests of $41 million and $43 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement.
Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs 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.
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, 2021 and 2020, the other VIEs had total assets of $1.9 billion and $1.1 billion, respectively, total liabilities of $263 million and $110 million, respectively, and noncontrolling interests of $886 million and $454 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
At December 31, 2021 and 2020, Southern Power had equity method investments in wind and battery energy storage projects totaling $86 million and $19 million, respectively. Earnings (loss) from these investments were immaterial for all periods presented. Subsequent to December 31, 2021, Southern Power sold an equity method investment in a wind project and received proceeds of $31 million. The gain associated with the transaction was immaterial.
Southern Company Gas
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments at December 31, 2021 and 2020 and related earnings (loss) from those investments for the years ended December 31, 2021, 2020, and 2019 were as follows:
| Investment Balance | December 31, 2021 | December 31, 2020 | |||||||||
| (in millions) | |||||||||||
| SNG(a) | $ | 1,129 | $ | 1,167 | |||||||
| PennEast Pipeline(b) | 11 | 91 | |||||||||
| Other | 33 | 32 | |||||||||
| Total | $ | 1,173 | $ | 1,290 |
(a)Decrease primarily relates to the continued amortization of deferred tax assets established upon acquisition, as well as distributions in excess of earnings.
(b)Investment balance at December 31, 2021 reflects pre-tax impairment charges totaling $84 million recorded during 2021. See "PennEast Pipeline Project" herein for additional information, including the September 2021 cancellation of the project.
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| Earnings (Loss) from Equity Method Investments | 2021 | 2020 | 2019 | ||||||||||||||
| (in millions) | |||||||||||||||||
| SNG | $ | 127 | $ | 129 | $ | 141 | |||||||||||
| Atlantic Coast Pipeline(a)(b) | — | 3 | 13 | ||||||||||||||
| PennEast Pipeline(a)(c) | (81) | 7 | 6 | ||||||||||||||
| Other(d) | 4 | 2 | (3) | ||||||||||||||
| Total | $ | 50 | $ | 141 | $ | 157 |
(a)Earnings primarily result from AFUDC equity recorded by the project entity.
(b)In March 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note 15 under "Southern Company Gas" for additional information.
(c)For 2021, includes pre-tax impairment charges totaling $84 million. See "PennEast Pipeline Project" herein for additional information, including the September 2021 cancellation of the project.
(d)In March 2020, Southern Company Gas completed the sale of its interest in Pivotal LNG. See Note 15 under "Southern Company Gas" for additional information.
PennEast Pipeline Project
In 2014, Southern Company Gas entered into a partnership in which it holds a 20% ownership interest in the PennEast Pipeline, an interstate pipeline company formed to develop and operate an approximate 118-mile natural gas pipeline between New Jersey and Pennsylvania.
In 2019, an appellate court ruled that the PennEast Pipeline does not have federal eminent domain authority over lands in which a state has property rights interests. On June 29, 2021, the U.S. Supreme Court ruled in favor of PennEast Pipeline following a review of the appellate court decision. Southern Company Gas assesses its equity method investments for impairment whenever events or changes in circumstances indicate that the investment may be impaired. Following the U.S. Supreme Court ruling, during the second quarter 2021, Southern Company Gas management reassessed the project construction timing, including the anticipated timing for receipt of a FERC certificate and all remaining state and local permits, as well as potential challenges thereto, and performed an impairment analysis. The outcome of the analysis resulted in a pre-tax impairment charge of $82 million ($58 million after tax).
On September 27, 2021, PennEast Pipeline announced that further development of the project is no longer supported, and, as a result, all further development of the project has ceased. During the third quarter 2021, Southern Company Gas recorded an additional pre-tax charge of $2 million ($2 million after tax) related to its share of the project level impairment, as well as $7 million of additional tax expense, resulting in total pre-tax charges of $84 million ($67 million after tax) during 2021 related to the project.
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8. FINANCING
Long-term Debt
Details of long-term debt at December 31, 2021 and 2020 are provided in the following table:
| At December 31, 2021 | Balance Outstanding at December 31, | ||||||||||||||||||||||
| Maturity | Weighted Average Interest Rate | 2021 | 2020 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Senior notes(a) | 2022-2052 | 3.62% | $ | 33,120 | $ | 30,850 | |||||||||||||||||
| Junior subordinated notes | 2024-2081 | 4.00% | 8,918 | 7,295 | |||||||||||||||||||
| FFB loans(b) | 2022-2044 | 2.88% | 4,962 | 4,618 | |||||||||||||||||||
| Pollution control revenue bonds(c) | 2022-2053 | 1.05% | 2,662 | 2,675 | |||||||||||||||||||
| First mortgage bonds(d) | 2023-2060 | 3.53% | 2,100 | 1,900 | |||||||||||||||||||
| Medium-term notes | 2022-2027 | 7.60% | 130 | 160 | |||||||||||||||||||
| Other long-term debt | 2022-2026 | 0.79% | 270 | 370 | |||||||||||||||||||
| Other revenue bonds | — | 320 | |||||||||||||||||||||
| Debt payable to affiliated trusts(e) | — | 206 | |||||||||||||||||||||
| Finance lease obligations(f) | 215 | 231 | |||||||||||||||||||||
| Unamortized fair value adjustment | 359 | 393 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | (216) | (201) | |||||||||||||||||||||
| Unamortized debt issuance expenses | (243) | (237) | |||||||||||||||||||||
| Total long-term debt | 52,277 | 48,580 | |||||||||||||||||||||
| Less: Amount due within one year | 2,157 | 3,507 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 50,120 | $ | 45,073 | |||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||
| Senior notes | 2022-2052 | 3.89% | $ | 8,725 | $ | 7,625 | |||||||||||||||||
| Pollution control revenue bonds(c) | 2024-2038 | 0.55% | 995 | 1,060 | |||||||||||||||||||
| Other long-term debt | 2026 | 1.24% | 45 | 45 | |||||||||||||||||||
| Debt payable to affiliated trusts(e) | — | 206 | |||||||||||||||||||||
| Finance lease obligations(f) | 4 | 5 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | (18) | (16) | |||||||||||||||||||||
| Unamortized debt issuance expenses | (64) | (56) | |||||||||||||||||||||
| Total long-term debt | 9,687 | 8,869 | |||||||||||||||||||||
| Less: Amount due within one year | 751 | 311 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 8,936 | $ | 8,558 | |||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Senior notes | 2022-2051 | 3.61% | $ | 6,825 | $ | 6,400 | |||||||||||||||||
| Junior subordinated notes | 2077 | 5.00% | 270 | 270 | |||||||||||||||||||
| FFB loans(b) | 2022-2044 | 2.88% | 4,962 | 4,618 | |||||||||||||||||||
| Pollution control revenue bonds(c) | 2022-2053 | 1.33% | 1,591 | 1,538 | |||||||||||||||||||
| Other long-term debt | 2022 | 0.70% | 125 | 125 | |||||||||||||||||||
| Finance lease obligations(f) | 136 | 145 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | (11) | (12) | |||||||||||||||||||||
| Unamortized debt issuance expenses | (114) | (114) | |||||||||||||||||||||
| Total long-term debt | 13,784 | 12,970 | |||||||||||||||||||||
| Less: Amount due within one year | 675 | 542 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 13,109 | $ | 12,428 | |||||||||||||||||||
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| At December 31, 2021 | Balance Outstanding at December 31, | ||||||||||||||||||||||
| Maturity | Weighted Average Interest Rate | 2021 | 2020 | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Senior notes | 2024-2051 | 3.43% | $ | 1,425 | $ | 900 | |||||||||||||||||
| Pollution control revenue bonds(c) | 2025-2028 | 1.86% | 76 | 76 | |||||||||||||||||||
| Other revenue bonds | — | 320 | |||||||||||||||||||||
| Other long-term debt | — | 100 | |||||||||||||||||||||
| Finance lease obligations(f) | 18 | 19 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | 2 | 11 | |||||||||||||||||||||
| Unamortized debt issuance expenses | (10) | (7) | |||||||||||||||||||||
| Total long-term debt | 1,511 | 1,419 | |||||||||||||||||||||
| Less: Amount due within one year | 1 | 406 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 1,510 | $ | 1,013 | |||||||||||||||||||
| Southern Power | |||||||||||||||||||||||
| Senior notes(a) | 2022-2046 | 3.74% | $ | 3,711 | $ | 3,714 | |||||||||||||||||
| Unamortized debt premium (discount), net | (6) | (6) | |||||||||||||||||||||
| Unamortized debt issuance expenses | (17) | (16) | |||||||||||||||||||||
| Total long-term debt | 3,688 | 3,692 | |||||||||||||||||||||
| Less: Amount due within one year | 679 | 299 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 3,009 | $ | 3,393 | |||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Senior notes | 2023-2051 | 3.96% | $ | 4,348 | $ | 4,200 | |||||||||||||||||
| First mortgage bonds(d) | 2023-2060 | 3.53% | 2,100 | 1,900 | |||||||||||||||||||
| Medium-term notes | 2022-2027 | 7.60% | 130 | 160 | |||||||||||||||||||
| Unamortized fair value adjustment | 359 | 393 | |||||||||||||||||||||
| Unamortized debt premium (discount), net | (35) | (27) | |||||||||||||||||||||
| Total long-term debt | 6,902 | 6,626 | |||||||||||||||||||||
| Less: Amount due within one year | 47 | 333 | |||||||||||||||||||||
| Total long-term debt excluding amount due within one year | $ | 6,855 | $ | 6,293 |
(a)Includes a fair value gain (loss) of $5 million and $109 million at December 31, 2021 and 2020, respectively, related to Southern Power's foreign currency hedge on its €1.1 billion senior notes.
(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 under construction, 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)Pollution control 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 facilities. In some cases, the pollution control 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)At December 31, 2020, Alabama Power had a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes, which Alabama Power redeemed during 2021. The junior subordinated notes constituted substantially all of the assets of this trust. Alabama Power considered the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constituted a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. See Note 1 under "Variable Interest Entities" for additional information on the accounting treatment for this trust and the related securities.
(f)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 | Georgia Power**(b)** | Mississippi Power | Southern Power**(c)** | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2022 | $ | 2,157 | $ | 751 | $ | 676 | $ | 1 | $ | 677 | $ | 46 | ||||||||
| 2023 | 3,738 | 301 | 897 | 1 | 290 | 400 | ||||||||||||||
| 2024 | 2,280 | 22 | 498 | 201 | — | — | ||||||||||||||
| 2025 | 1,199 | 250 | 145 | 11 | 500 | 300 | ||||||||||||||
| 2026 | 3,723 | 45 | 441 | 1 | 964 | 530 |
(a)Amount for 2022 excludes junior subordinated notes totaling $1.725 billion at the parent entity that Southern Company has agreed to remarket in 2022 in connection with the related stock purchase contracts; however, the final maturity dates are in 2024 and 2027 (one half in each year). See "Equity Units" herein for additional information. Also see notes (b) and (c) below.
(b)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.
(c)Southern Power's 2022 maturity and $564 million of its 2026 maturities represent 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 March 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, provided that total aggregate borrowings under the FFB Credit Facilities could not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the related customer refunds).
In June 2021 and December 2021, Georgia Power made the final borrowings under the FFB Credit Facilities in aggregate principal amounts of $371 million and $69 million, respectively, at an interest rate of 2.434% and 2.178%, respectively, through the final maturity date of February 20, 2044. No further borrowings are permitted under the FFB Credit Facilities. During 2021, Georgia Power made principal amortization payments of $96 million under the FFB Credit Facilities. At December 31, 2021 and 2020, Georgia Power had $5.0 billion and $4.6 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 full recourse and secured by a first priority lien on (i) Georgia Power's undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, 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 February 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) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in any Westinghouse bankruptcy if Georgia Power does not maintain access to intellectual property rights under the related intellectual property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC or by Georgia Power; (iv) failure of the holders of 90% of the ownership interests in Plant Vogtle Units 3 and 4 to vote to continue construction following certain schedule extensions; (v) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of
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Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facilities; or (vi) loss of or failure to receive necessary regulatory approvals. 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. 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.
The latest extension of the schedule for Plant Vogtle Units 3 and 4 triggers the requirement that the holders of at least 90% of the ownership interests of Plant Vogtle Units 3 and 4 must vote to continue construction. If the holders of at least 90% of the ownership interests of Plant Vogtle Units 3 and 4 do not vote to continue construction, the DOE may require Georgia Power to prepay all outstanding borrowings under the FFB Credit Facilities over a period of five years.
In connection with any cancellation of Plant Vogtle Units 3 and 4, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.
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, 2021 and 2020. Each Registrant's senior notes, junior subordinated notes, pollution control and other 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 2019, Southern Company issued 34.5 million 2019 Series A Equity Units (Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total stated amount of $1.725 billion. Net proceeds from the issuance were approximately $1.682 billion. The proceeds were used to repay short-term indebtedness and for other general corporate purposes, including investments in Southern Company's subsidiaries.
Each Corporate Unit is comprised of (i) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019A Remarketable Junior Subordinated Notes (Series 2019A RSNs) due 2024, (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019B Remarketable Junior Subordinated Notes (together with the Series 2019A RSNs, the RSNs) due 2027, and (iii) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than August 1, 2022, a certain number of shares of Southern Company's common stock for $50 in cash (Stock Purchase Contract). Southern Company has agreed to remarket the RSNs in 2022, at which time each interest rate on the RSNs will reset at the applicable market rate. Holders may choose to either remarket their RSNs, receive the proceeds, and use those funds to settle the related Stock Purchase Contract or retain the 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 RSNs to Southern Company at a price equal to the principal amount. The Corporate Units carry an annual distribution rate of 6.75% of the stated amount, which is comprised of a quarterly interest payment on the RSNs of 2.70% per year and a quarterly purchase contract adjustment payment of 4.05% 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 is equal to or greater than $68.64, 0.7284 shares.
-
If the applicable market value is less than $68.64 but greater than $57.20, a number of shares equal to $50 divided by the applicable market value.
-
If the applicable market value is less than or equal to $57.20, 0.8741 shares.
A holder's ownership interest in the 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 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 RSNs. At the time of issuance, the RSNs were recorded on Southern Company's consolidated balance
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sheet as long-term debt and the present value of the contract adjustment payments of $198 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, 2021 was $52 million, which was classified as current. The difference between the face value and present value of the contract adjustment payments is being accreted to interest expense on the consolidated statements of income over the three-year period ending in August 2022. The liability recorded for the contract adjustment payments is considered non-cash and excluded from the consolidated statements of cash flows. To settle the Stock Purchase Contracts, Southern Company will be required to issue a maximum of 30.2 million shares of common stock (subject to anti-dilution adjustments and a make-whole adjustment if certain fundamental changes occur).
Bank Credit Arrangements
At December 31, 2021, committed credit arrangements with banks were as follows:
| Expires | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Company | 2022 | 2023 | 2024 | 2026 | Total | Unused | Due within One Year | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Southern Company parent | $ | — | $ | — | $ | — | $ | 2,000 | $ | 2,000 | $ | 1,998 | $ | — | |||||||||||||||||||||||||||||||||||||||||||||
| Alabama Power | — | — | 550 | 700 | 1,250 | 1,250 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Georgia Power | — | — | — | 1,750 | 1,750 | 1,726 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Mississippi Power | — | 125 | 150 | — | 275 | 275 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Southern Power(a) | — | — | — | 600 | 600 | 568 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Southern Company Gas(b) | 250 | — | — | 1,500 | 1,750 | 1,747 | 250 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| SEGCO | 30 | — | — | — | 30 | 30 | 30 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Southern Company | $ | 280 | $ | 125 | $ | 700 | $ | 6,550 | $ | 7,655 | $ | 7,594 | $ | 280 |
(a)Does not include Southern Power Company's $75 million and $60 million continuing letter of credit facilities for standby letters of credit expiring in 2023, of which $8 million and $4 million, respectively, was unused at December 31, 2021. Subsequent to December 31, 2021, Southern Power amended its $60 million letter of credit facility, which, among other things, extended the expiration date from 2023 to 2025 and increased the amount to $75 million. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(b)Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $800 million of the arrangement expiring in 2026 and all $250 million of the arrangement expiring in 2022. Southern Company Gas' committed credit arrangement expiring in 2026 also includes $700 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 2026, 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 or, in the case of Southern Power, cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if Southern Power defaulted on indebtedness or guarantee obligations over a specified threshold. Such 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, 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, 2021, 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.
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A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at December 31, 2021 was approximately $1.5 billion (comprised of approximately $789 million at Alabama Power, $672 million at Georgia Power, and $34 million at Mississippi Power). In addition, at December 31, 2021, Georgia Power had approximately $157 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
At both December 31, 2021 and 2020, Southern Power had $105 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, 2021 | Notes Payable at December 31, 2020 | ||||||||||||||||||||||
| Amount Outstanding | Weighted Average Interest Rate | Amount Outstanding | Weighted Average Interest Rate | ||||||||||||||||||||
| (in millions) | (in millions) | ||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Commercial paper | $ | 1,140 | 0.3 | % | $ | 609 | 0.3 | % | |||||||||||||||
| Short-term bank debt | 300 | 0.7 | % | — | — | % | |||||||||||||||||
| Total | $ | 1,440 | 0.4 | % | $ | 609 | 0.3 | % | |||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Commercial paper | $ | — | — | % | $ | 60 | 0.3 | % | |||||||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Commercial paper | $ | — | — | % | $ | 25 | 0.4 | % | |||||||||||||||
| Southern Power | |||||||||||||||||||||||
| Commercial paper | $ | 211 | 0.3 | % | $ | 175 | 0.3 | % | |||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Commercial paper: | |||||||||||||||||||||||
| Southern Company Gas Capital | $ | 379 | 0.3 | % | $ | 220 | 0.3 | % | |||||||||||||||
| Nicor Gas | 530 | 0.3 | % | 104 | 0.2 | % | |||||||||||||||||
| Short-term bank debt: | |||||||||||||||||||||||
| Nicor Gas | 300 | 0.7 | % | — | — | % | |||||||||||||||||
| Total | $ | 1,209 | 0.4 | % | $ | 324 | 0.2 | % |
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 2021, Southern Company issued approximately 3.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $73 million.
See "Equity Units" herein for additional information.
Shares Reserved
At December 31, 2021, a total of 127 million shares were reserved for issuance pursuant to the Southern Investment Plan, employee savings plans, the Outside Directors Stock Plan, the Equity and Incentive Compensation Plan (which includes stock options and performance share units as discussed in Note 12), and an at-the-market program. Of the total 127 million shares reserved, 31.5 million shares are available for awards under the Equity and Incentive Compensation Plan at December 31, 2021.
Diluted Earnings Per Share
For Southern Company, the only differences in computing basic and diluted earnings per share (EPS) are attributable to awards outstanding under stock-based compensation plans and the Equity Units. Earnings per share dilution resulting from stock-based compensation plans and the Equity Units issuance is determined using the treasury stock method. Shares used to compute diluted EPS were as follows:
| Average Common Stock Shares | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| As reported shares | 1,061 | 1,058 | 1,046 | ||||||||||||||
| Effect of stock-based compensation | 7 | 7 | 8 | ||||||||||||||
| Diluted shares | 1,068 | 1,065 | 1,054 |
In all years presented, an immaterial number of stock-based compensation awards was not included in the diluted EPS calculation because the awards were anti-dilutive.
The Equity Units were excluded from the calculation of diluted EPS for all years presented as the dilutive stock price threshold was not met.
Redeemable Preferred Stock of Subsidiaries
As discussed further under "Alabama Power" herein, the preferred stock of Alabama Power is presented as "Redeemable Preferred Stock of Subsidiaries" on Southern Company's balance sheets in a manner consistent with temporary equity under applicable accounting standards.
Alabama Power
Alabama Power has preferred stock, Class A preferred stock, and common stock outstanding. Alabama Power also has authorized preference stock, none of which is outstanding. Alabama Power's preferred stock and Class A preferred stock, without preference between classes, rank senior to Alabama Power's common stock with respect to payment of dividends and voluntary and involuntary dissolution. The preferred stock and Class A preferred stock of Alabama Power contain a feature that allows the holders to elect a majority of Alabama Power's board of directors if preferred dividends are not paid for four consecutive quarters. Because such a potential redemption-triggering event is not solely within the control of Alabama Power, the preferred stock and Class A preferred stock is presented as "Redeemable Preferred Stock" on Alabama Power's balance sheets in a manner consistent with temporary equity under applicable accounting standards.
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Alabama Power's preferred stock is subject to redemption at a price equal to the par value plus a premium. Alabama Power's Class A preferred stock is subject to redemption at a price equal to the stated capital. All series of Alabama Power's preferred stock currently are subject to redemption at the option of Alabama Power. The Class A preferred stock is subject to redemption on or after October 1, 2022, or following the occurrence of a rating agency event. Information for each outstanding series is in the table below:
| Preferred Stock | Par Value/Stated Capital Per Share | Shares Outstanding | Redemption Price Per Share | ||||||||||||||
| 4.92% Preferred Stock | $100 | 80,000 | $103.23 | ||||||||||||||
| 4.72% Preferred Stock | $100 | 50,000 | $102.18 | ||||||||||||||
| 4.64% Preferred Stock | $100 | 60,000 | $103.14 | ||||||||||||||
| 4.60% Preferred Stock | $100 | 100,000 | $104.20 | ||||||||||||||
| 4.52% Preferred Stock | $100 | 50,000 | $102.93 | ||||||||||||||
| 4.20% Preferred Stock | $100 | 135,115 | $105.00 | ||||||||||||||
| 5.00% Class A Preferred Stock | $25 | 10,000,000 | $25.00(*) |
(*)$25.50 if prior to October 1, 2022
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, 2021, consolidated retained earnings included $4.4 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.
See Note 7 under "Southern Power" for information regarding the distribution requirements for certain Southern Power subsidiaries.
By regulation, Nicor Gas is restricted, to the extent of 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, 2021, the amount of Southern Company Gas' subsidiary retained earnings restricted for dividend payment totaled $1.3 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' 100%-owned 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, bank term loan, 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.
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9. LEASES
On January 1, 2019, the Registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to 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.
The Registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements were applied on a prospective basis as of the adoption date. The Registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the Registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.
Lessee
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, 2021 | ||||||||||||||||||||
| Electric generating units | $ | 802 | $ | 104 | $ | 1,217 | $ | — | $ | — | $ | — | ||||||||
| Real estate/land | 876 | 3 | 49 | 2 | 526 | 45 | ||||||||||||||
| Communication towers | 156 | 2 | 4 | — | — | 24 | ||||||||||||||
| Railcars | 32 | 10 | 20 | 2 | — | — | ||||||||||||||
| Other | 103 | 5 | 1 | 24 | — | 1 | ||||||||||||||
| Total | $ | 1,969 | $ | 124 | $ | 1,291 | $ | 28 | $ | 526 | $ | 70 | ||||||||
| At December 31, 2020 | ||||||||||||||||||||
| Electric generating units | $ | 941 | $ | 146 | $ | 1,368 | $ | — | $ | — | $ | — | ||||||||
| Real estate/land | 815 | 4 | 53 | 2 | 451 | 61 | ||||||||||||||
| Communication towers | 158 | 2 | 3 | — | — | 20 | ||||||||||||||
| Railcars | 42 | 16 | 23 | 3 | — | — | ||||||||||||||
| Other | 127 | 7 | 5 | 23 | — | 1 | ||||||||||||||
| Total | $ | 2,083 | $ | 175 | $ | 1,452 | $ | 28 | $ | 451 | $ | 82 |
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 real estate leases have remaining terms of up to 24 years while the land leases have remaining terms of up to 45 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 with options to renew that could extend the terms for an additional 15 years.
Renewal options exist in many of the leases. Except as otherwise noted, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not 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.
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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 one and 17 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of $521 million and $575 million at December 31, 2021 and 2020, 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 the Georgia PSC.
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 exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial at December 31, 2021 and 2020.
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 right-of-use asset.
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Balance sheet amounts recorded for operating and finance leases are as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| At December 31, 2021 | ||||||||||||||||||||
| Operating Leases | ||||||||||||||||||||
| Operating lease ROU assets, net | $ | 1,701 | $ | 108 | $ | 1,157 | $ | 10 | $ | 479 | $ | 70 | ||||||||
| Operating lease obligations - current | $ | 250 | $ | 54 | $ | 156 | $ | 4 | $ | 28 | $ | 11 | ||||||||
| Operating lease obligations - non-current | 1,503 | 66 | 999 | 6 | 497 | 59 | ||||||||||||||
| Total operating lease obligations(*) | $ | 1,754 | $ | 121 | $ | 1,155 | $ | 10 | $ | 525 | $ | 70 | ||||||||
| Finance Leases | ||||||||||||||||||||
| Finance lease ROU assets, net | $ | 197 | $ | 4 | $ | 104 | $ | 17 | $ | — | $ | — | ||||||||
| Finance lease obligations - current | $ | 16 | $ | 1 | $ | 10 | $ | 1 | $ | — | $ | — | ||||||||
| Finance lease obligations - non-current | 199 | 3 | 126 | 17 | — | — | ||||||||||||||
| Total finance lease obligations | $ | 215 | $ | 4 | $ | 136 | $ | 18 | $ | — | $ | — | ||||||||
| At December 31, 2020 | ||||||||||||||||||||
| Operating Leases | ||||||||||||||||||||
| Operating lease ROU assets, net | $ | 1,802 | $ | 151 | $ | 1,308 | $ | 9 | $ | 415 | $ | 81 | ||||||||
| Operating lease obligations - current | $ | 241 | $ | 51 | $ | 151 | $ | 2 | $ | 25 | $ | 15 | ||||||||
| Operating lease obligations - non-current | 1,611 | 119 | 1,156 | 7 | 426 | 67 | ||||||||||||||
| Total operating lease obligations(*) | $ | 1,852 | $ | 170 | $ | 1,307 | $ | 9 | $ | 451 | $ | 82 | ||||||||
| Finance Leases | ||||||||||||||||||||
| Finance lease ROU assets, net | $ | 218 | $ | 5 | $ | 115 | $ | 19 | $ | — | $ | — | ||||||||
| Finance lease obligations - current | $ | 17 | $ | 1 | $ | 9 | $ | 1 | $ | — | $ | — | ||||||||
| Finance lease obligations - non-current | 214 | 4 | 136 | 18 | — | — | ||||||||||||||
| Total finance lease obligations | $ | 231 | $ | 5 | $ | 145 | $ | 19 | $ | — | $ | — |
(*)Includes operating lease obligations related to PPAs at Southern Company, Alabama Power, and Georgia Power totaling $802 million, $104 million, and $1.11 billion, respectively, at December 31, 2021 and $941 million, $146 million, and $1.25 billion, respectively, at December 31, 2020.
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 2021, 2020, and 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2021 | ||||||||||||||||||||
| Lease cost | ||||||||||||||||||||
| Operating lease cost(*) | $ | 313 | $ | 58 | $ | 208 | $ | 2 | $ | 33 | $ | 19 | ||||||||
| Finance lease cost: | ||||||||||||||||||||
| Amortization of ROU assets | 21 | 1 | 11 | 1 | — | — | ||||||||||||||
| Interest on lease obligations | 11 | — | 16 | 1 | — | — | ||||||||||||||
| Total finance lease cost | 32 | 1 | 27 | 2 | — | — | ||||||||||||||
| Short-term lease costs | 48 | 15 | 24 | — | — | — | ||||||||||||||
| Variable lease cost | 96 | 4 | 83 | — | 5 | — | ||||||||||||||
| Sublease income | 1 | — | — | — | — | — | ||||||||||||||
| Total lease cost | $ | 490 | $ | 78 | $ | 342 | $ | 4 | $ | 38 | $ | 19 | ||||||||
| 2020 | ||||||||||||||||||||
| Lease cost | ||||||||||||||||||||
| Operating lease cost(*) | $ | 309 | $ | 55 | $ | 212 | $ | 3 | $ | 29 | $ | 19 | ||||||||
| Finance lease cost: | ||||||||||||||||||||
| Amortization of ROU assets | 26 | 1 | 15 | — | — | — | ||||||||||||||
| Interest on lease obligations | 11 | — | 16 | — | — | — | ||||||||||||||
| Total finance lease cost | 37 | 1 | 31 | — | — | — | ||||||||||||||
| Short-term lease costs | 39 | 11 | 26 | — | — | — | ||||||||||||||
| Variable lease cost | 91 | 4 | 76 | — | 7 | — | ||||||||||||||
| Sublease income | — | (1) | — | — | — | — | ||||||||||||||
| Total lease cost | $ | 476 | $ | 70 | $ | 345 | $ | 3 | $ | 36 | $ | 19 | ||||||||
| 2019 | ||||||||||||||||||||
| Lease cost | ||||||||||||||||||||
| Operating lease cost(*) | $ | 310 | $ | 54 | $ | 206 | $ | 3 | $ | 28 | $ | 18 | ||||||||
| Finance lease cost: | ||||||||||||||||||||
| Amortization of ROU assets | 28 | 1 | 15 | — | — | — | ||||||||||||||
| Interest on lease obligations | 12 | — | 18 | — | — | — | ||||||||||||||
| Total finance lease cost | 40 | 1 | 33 | — | — | — | ||||||||||||||
| Short-term lease costs | 48 | 19 | 22 | — | — | — | ||||||||||||||
| Variable lease cost | 105 | 6 | 85 | — | 7 | — | ||||||||||||||
| Sublease income | — | (1) | — | — | — | — | ||||||||||||||
| Total lease cost | $ | 503 | $ | 79 | $ | 346 | $ | 3 | $ | 35 | $ | 18 |
(*)Includes operating lease costs related to PPAs at Southern Company, Alabama Power, and Georgia Power totaling $165 million, $47 million, and $184 million, respectively, in 2021, $161 million, $43 million, and $184 million, respectively, in 2020, and $149 million, $41 million, and $174 million, respectively, in 2019.
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Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs, including $41 million, $39 million, and $42 million in 2021, 2020, and 2019, respectively, from finance leases which are included in purchased power on Georgia Power's statements of income, $20 million of which was included in purchased power, affiliates for all periods presented.
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) | ||||||||||||||||||||
| 2021 | ||||||||||||||||||||
| Other information | ||||||||||||||||||||
| Cash paid for amounts included in the measurements of lease obligations: | ||||||||||||||||||||
| Operating cash flows from operating leases | $ | 308 | $ | 58 | $ | 211 | $ | 2 | $ | 28 | $ | 19 | ||||||||
| Operating cash flows from finance leases | 9 | — | 17 | 1 | — | — | ||||||||||||||
| Financing cash flows from finance leases | 17 | 1 | 9 | 1 | — | — | ||||||||||||||
| ROU assets obtained in exchange for new operating lease obligations | 64 | 3 | 9 | — | 72 | 7 | ||||||||||||||
| ROU assets obtained in exchange for new finance lease obligations | 3 | — | — | — | — | — | ||||||||||||||
| 2020 | ||||||||||||||||||||
| Other information | ||||||||||||||||||||
| Cash paid for amounts included in the measurements of lease obligations: | ||||||||||||||||||||
| Operating cash flows from operating leases | $ | 310 | $ | 55 | $ | 215 | $ | 3 | $ | 28 | $ | 18 | ||||||||
| Operating cash flows from finance leases | 9 | — | 18 | — | — | — | ||||||||||||||
| Financing cash flows from finance leases | 22 | 1 | 11 | — | — | — | ||||||||||||||
| ROU assets obtained in exchange for new operating lease obligations | 227 | 63 | 32 | — | 51 | 4 | ||||||||||||||
| ROU assets obtained in exchange for new finance lease obligations | 10 | 2 | — | — | — | — | ||||||||||||||
| 2019 | ||||||||||||||||||||
| Other information | ||||||||||||||||||||
| Cash paid for amounts included in the measurements of lease obligations: | ||||||||||||||||||||
| Operating cash flows from operating leases | $ | 323 | $ | 54 | $ | 210 | $ | 3 | 27 | 18 | ||||||||||
| Operating cash flows from finance leases | 10 | — | 19 | — | — | — | ||||||||||||||
| Financing cash flows from finance leases | 32 | 1 | 13 | — | — | — | ||||||||||||||
| ROU assets obtained in exchange for new operating lease obligations | 118 | 7 | 21 | — | 2 | 19 | ||||||||||||||
| ROU assets obtained in exchange for new finance lease obligations | 35 | 2 | 24 | — | — | — |
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| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| At December 31, 2021 | ||||||||||||||||||||
| Weighted-average remaining lease term in years: | ||||||||||||||||||||
| Operating leases | 15.9 | 9.1 | 8.7 | 6.1 | 32.8 | 10.5 | ||||||||||||||
| Finance leases | 18.0 | 8.7 | 8.5 | 13.9 | N/A | N/A | ||||||||||||||
| Weighted-average discount rate: | ||||||||||||||||||||
| Operating leases | 4.41 | % | 4.37 | % | 4.45 | % | 2.74 | % | 5.20 | % | 3.61 | % | ||||||||
| Finance leases | 4.82 | % | 3.09 | % | 10.81 | % | 2.74 | % | N/A | N/A | ||||||||||
| At December 31, 2020 | ||||||||||||||||||||
| Weighted-average remaining lease term in years: | ||||||||||||||||||||
| Operating leases | 14.5 | 7.8 | 9.4 | 6.5 | 32.1 | 9.8 | ||||||||||||||
| Finance leases | 18.2 | 9.7 | 9.5 | 14.9 | N/A | N/A | ||||||||||||||
| Weighted-average discount rate: | ||||||||||||||||||||
| Operating leases | 4.44 | % | 4.14 | % | 4.37 | % | 3.26 | % | 5.45 | % | 3.67 | % | ||||||||
| Finance leases | 4.79 | % | 3.20 | % | 10.81 | % | 2.74 | N/A | N/A |
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Maturities of lease liabilities are as follows:
| At December 31, 2021 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Maturity Analysis | ||||||||||||||||||||
| Operating leases: | ||||||||||||||||||||
| 2022 | $ | 307 | $ | 59 | $ | 205 | $ | 4 | $ | 37 | $ | 14 | ||||||||
| 2023 | 238 | 9 | 201 | 2 | 29 | 11 | ||||||||||||||
| 2024 | 195 | 7 | 164 | 1 | 29 | 11 | ||||||||||||||
| 2025 | 174 | 6 | 136 | 1 | 29 | 11 | ||||||||||||||
| 2026 | 154 | 5 | 133 | 1 | 30 | 8 | ||||||||||||||
| Thereafter | 1,575 | 69 | 566 | 2 | 995 | 31 | ||||||||||||||
| Total | 2,643 | 155 | 1,405 | 11 | 1,149 | 86 | ||||||||||||||
| Less: Present value discount | 889 | 34 | 250 | 1 | 624 | 16 | ||||||||||||||
| Operating lease obligations | $ | 1,754 | $ | 121 | $ | 1,155 | $ | 10 | $ | 525 | $ | 70 | ||||||||
| Finance leases: | ||||||||||||||||||||
| 2022 | $ | 25 | $ | 2 | $ | 25 | $ | 2 | $ | — | $ | — | ||||||||
| 2023 | 22 | 1 | 25 | 2 | — | — | ||||||||||||||
| 2024 | 19 | 1 | 25 | 2 | — | — | ||||||||||||||
| 2025 | 16 | — | 25 | 2 | — | — | ||||||||||||||
| 2026 | 16 | — | 26 | 1 | — | — | ||||||||||||||
| Thereafter | 231 | — | 83 | 13 | — | — | ||||||||||||||
| Total | 329 | 4 | 209 | 22 | — | — | ||||||||||||||
| Less: Present value discount | 114 | — | 73 | 4 | — | — | ||||||||||||||
| Finance lease obligations | $ | 215 | $ | 4 | $ | 136 | $ | 18 | $ | — | $ | — |
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.
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 seven years, after which the contracts renew on a month-to-month basis at the customer's option. 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 17 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including solar and wind facilities, accounted for as operating leases with remaining terms of up to 25 years and PPAs related to battery energy storage facilities accounted for as sales-type leases with remaining terms of up to 19 years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 21 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with remaining terms of up to 12 years.
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Lease income for 2021, 2020, and 2019, is as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2021 | ||||||||||||||||||||
| Lease income - interest income on sales-type leases | $ | 15 | $ | — | $ | — | $ | 14 | $ | 1 | $ | — | ||||||||
| Lease income - operating leases | 223 | 82 | 42 | 2 | 85 | 35 | ||||||||||||||
| Variable lease income | 429 | — | — | — | 456 | — | ||||||||||||||
| Total lease income | $ | 667 | $ | 82 | $ | 42 | $ | 16 | $ | 542 | $ | 35 | ||||||||
| 2020 | ||||||||||||||||||||
| Lease income - interest income on sales-type leases | $ | 16 | $ | — | $ | — | $ | 12 | $ | — | $ | — | ||||||||
| Lease income - operating leases | 208 | 45 | 58 | 2 | 87 | 35 | ||||||||||||||
| Variable lease income | 419 | — | — | — | 449 | — | ||||||||||||||
| Total lease income | $ | 643 | $ | 45 | $ | 58 | $ | 14 | $ | 536 | $ | 35 | ||||||||
| 2019 | ||||||||||||||||||||
| Lease income - interest income on sales-type leases | $ | 9 | $ | — | $ | — | $ | 9 | $ | — | $ | — | ||||||||
| Lease income - operating leases | 273 | 24 | 71 | — | 160 | 35 | ||||||||||||||
| Variable lease income | 403 | — | — | — | 434 | — | ||||||||||||||
| Total lease income | $ | 685 | $ | 24 | $ | 71 | $ | 9 | $ | 594 | $ | 35 |
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 for Alabama Power and Southern Power is included in wholesale revenues. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.
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No profit or loss was recognized by Mississippi Power when a tolling arrangement accounted for as a sales-type lease began in 2019. During 2020 and 2021, Mississippi Power completed construction of additional leased assets under the lease and, upon completion, the book values of $26 million and $39 million, respectively, were transferred from CWIP to lease receivables. Each transfer represented a non-cash investing transaction for purposes of the statements of cash flows.
During 2021, Southern Power completed construction of a portion of the Garland and Tranquillity battery energy storage facilities' assets and recorded losses totaling $40 million upon commencement of the related PPAs, which Southern Power accounts for as sales-type leases. The losses were due to ITCs retained and expected to be realized by Southern Power and its partners in these projects, and no estimated residual asset value was assumed in calculating the losses. Each lease has an initial term of 20 years. Upon commencement of the leases, the book values of the related assets totaling $210 million were derecognized from CWIP and lease receivables were recorded. At December 31, 2021, the current portion of the lease receivables totaling $12 million is included in other current assets and the long-term portion totaling $161 million is included in miscellaneous property and investments on Southern Company's balance sheet and net investment in sales-type leases on Southern Power's consolidated balance sheet. The transfers represented noncash investing transactions for purposes of the statement of cash flows. See Note 15 under "Southern Power" for additional information.
The undiscounted cash flows expected to be received for in-service leased assets under the leases are as follows:
| At December 31, 2021 | |||||||||||
| Southern Company | Mississippi Power | Southern Power | |||||||||
| (in millions) | |||||||||||
| 2022 | $ | 37 | $ | 25 | $ | 12 | |||||
| 2023 | 39 | 24 | 15 | ||||||||
| 2024 | 38 | 23 | 15 | ||||||||
| 2025 | 37 | 22 | 15 | ||||||||
| 2026 | 36 | 21 | 15 | ||||||||
| Thereafter | 390 | 183 | 207 | ||||||||
| Total undiscounted cash flows | $ | 577 | $ | 298 | $ | 279 | |||||
| Net investment in sales-type lease(*) | 340 | 167 | 173 | ||||||||
| Difference between undiscounted cash flows and discounted cash flows | $ | 237 | $ | 131 | $ | 106 |
(*)For Mississippi Power, included in other current assets and other property and investments on the balance sheets. For Southern Power, included in other current assets and net investment in sales-type leases on the balance sheet.
The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:
| At December 31, 2021 | |||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Southern Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| 2022 | $ | 188 | $ | 76 | $ | 8 | $ | 87 | $ | 35 | |||||||
| 2023 | 139 | 32 | 2 | 88 | 35 | ||||||||||||
| 2024 | 107 | 5 | — | 90 | 33 | ||||||||||||
| 2025 | 100 | 3 | — | 74 | 28 | ||||||||||||
| 2026 | 99 | 3 | — | 73 | 28 | ||||||||||||
| Thereafter | 883 | 23 | — | 240 | 407 | ||||||||||||
| Total | $ | 1,516 | $ | 142 | $ | 10 | $ | 652 | $ | 566 |
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 outdoor lighting contracts accounted for as operating leases at Mississippi Power are immaterial.
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Southern Company Leveraged Lease
At December 31, 2020, a subsidiary of Southern Holdings had four leveraged lease agreements related to energy generation, distribution, and transportation assets, including two domestic and two international projects. During 2021, one of the domestic projects was sold and the agreements for both international projects were terminated. At December 31, 2021, one leveraged lease agreement related to energy generation remains, with an expected remaining term of 10 years. Southern Company continues to receive 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, as discussed below.
Southern Company's net investment in leveraged leases at December 31, 2020 consisted of the following:
| December 31, 2020**(*)** | |||||
| (in millions) | |||||
| Net rentals receivable | $ | 734 | |||
| Unearned income | (178) | ||||
| Investment in leveraged leases | 556 | ||||
| Deferred taxes from leveraged leases | (7) | ||||
| Net investment in leveraged leases | $ | 549 |
(*)Excludes the investment classified as held for sale. See Note 15 under "Southern Company" for additional information.
The following table provides a summary of the components of income related to leveraged lease investments. Income was impacted in all periods presented by the impairment charges discussed below and in Note 15 under "Southern Company." Income in 2021 does not include the impacts of the sale and terminations of leveraged lease projects discussed in Note 15 under "Southern Company."
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Pretax leveraged lease income (loss) | $ | 17 | $ | (180) | $ | 11 | |||||||||||
| Income tax benefit (expense) | (5) | 98 | — | ||||||||||||||
| Net leveraged lease income (loss) | $ | 12 | $ | (82) | $ | 11 |
Since 2017, the financial and operational performance of the remaining domestic lessee and the associated generation assets raised significant concerns about the short-term ability of the generation assets to produce cash flows sufficient to support ongoing operations and the lessee's contractual obligations and its ability to make the remaining semi-annual lease payments through the end of the lease term in 2047. In addition, following the expiration of the existing power offtake agreement in 2032, the lessee also is exposed to remarketing risk, which encompasses the price and availability of alternative sources of generation.
In connection with the 2019 annual impairment analysis, Southern Company revised the estimated cash flows to be received under the leveraged lease, which resulted in an impairment charge of $17 million ($13 million after tax) recorded in the fourth quarter 2019. During the second quarter 2020, Southern Company received the latest annual forecasts of natural gas prices and considered the significant decline in forecasted prices to be an indicator of potential impairment that required an interim impairment assessment. Accordingly, consistent with prior impairment analyses, Southern Company evaluated the recoverability of the lease receivable and the expected residual value of the generation assets under various natural gas price scenarios to estimate the cash flows expected to be received from remarketing the generation assets following the expiration of the existing PPA and the residual value of the generation assets at the end of the lease. Based on the forecasts of energy prices in the years following the expiration of the existing PPA, Southern Company concluded that it was no longer probable that any of the associated rental payments would be received, because it was no longer probable the generation assets would be successfully remarketed and continue to operate after that date. During the second quarter 2020, Southern Company revised the estimated cash flows to be received under the leveraged lease to reflect this conclusion, which resulted in a full impairment of the lease investment and a pre-tax charge to earnings of $154 million ($74 million after tax).
All required lease payments through December 31, 2021 have been paid in full. If any future lease payments due prior to the expiration of the associated PPA are not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders could represent an event of default that would give the debtholders the right to foreclose on, and take ownership
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of, the generation assets, in effect terminating the lease. As the remaining amount of the lease investment was charged against earnings in the second quarter 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations 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. 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:
| 2021 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Federal — | ||||||||||||||||||||
| Current | $ | 50 | $ | 104 | $ | 311 | $ | 25 | $ | (340) | $ | 85 | ||||||||
| Deferred | 36 | 172 | (449) | (15) | 343 | 35 | ||||||||||||||
| 86 | 276 | (138) | 10 | 3 | 120 | |||||||||||||||
| State — | ||||||||||||||||||||
| Current | (25) | 23 | 71 | — | (16) | (68) | ||||||||||||||
| Deferred | 206 | 73 | (101) | 11 | — | 223 | ||||||||||||||
| 181 | 96 | (30) | 11 | (16) | 155 | |||||||||||||||
| Total | $ | 267 | $ | 372 | $ | (168) | $ | 21 | $ | (13) | $ | 275 |
| 2020 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Federal — | ||||||||||||||||||||
| Current | $ | 199 | $ | 198 | $ | 365 | $ | 18 | $ | (303) | $ | 82 | ||||||||
| Deferred | 70 | 44 | (224) | (14) | 299 | 53 | ||||||||||||||
| 269 | 242 | 141 | 4 | (4) | 135 | |||||||||||||||
| State — | ||||||||||||||||||||
| Current | 100 | 61 | 60 | — | (4) | 35 | ||||||||||||||
| Deferred | 24 | 34 | (49) | 10 | 11 | 3 | ||||||||||||||
| 124 | 95 | 11 | 10 | 7 | 38 | |||||||||||||||
| Total | $ | 393 | $ | 337 | $ | 152 | $ | 14 | $ | 3 | $ | 173 |
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| 2019 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Federal — | ||||||||||||||||||||
| Current | $ | 156 | $ | 61 | $ | 264 | $ | (6) | $ | (717) | $ | (120) | ||||||||
| Deferred | 1,237 | 125 | 180 | 26 | 647 | 195 | ||||||||||||||
| 1,393 | 186 | 444 | 20 | (70) | 75 | |||||||||||||||
| State — | ||||||||||||||||||||
| Current | 275 | 12 | 6 | (1) | 1 | 37 | ||||||||||||||
| Deferred | 130 | 72 | 22 | 11 | 13 | 18 | ||||||||||||||
| 405 | 84 | 28 | 10 | 14 | 55 | |||||||||||||||
| Total | $ | 1,798 | $ | 270 | $ | 472 | $ | 30 | $ | (56) | $ | 130 |
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 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 include $6 million for 2021, $5 million for 2020, and $51 million for 2019. Southern Power received $289 million, $340 million, and $734 million of cash related to federal ITCs under renewable energy initiatives in 2021, 2020, and 2019, respectively. See "Deferred Tax Assets and Liabilities" herein for additional information.
In accordance with regulatory requirements, deferred federal ITCs for the traditional electric operating companies are deferred and amortized over the average life of the related property, with such amortization normally applied as a credit to reduce depreciation and amortization in the statements of income. Southern Power's and the natural gas distribution utilities' deferred federal ITCs, as well as certain state ITCs for Nicor Gas, are deferred and amortized to income tax expense over the life of the respective asset. ITCs amortized in 2021, 2020, and 2019 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) | ||||||||
| 2021 | $ | 84 | $ | 58 | ||||
| 2020 | 84 | 59 | ||||||
| 2019 | 181 | 151 |
When Southern Power recognizes tax credits, the tax basis of the asset is reduced by 50% of the ITCs received, resulting 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. The tax benefit of the related basis differences reduced income tax expense by $5 million in 2019.
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 $66 million in 2021, $67 million in 2020, and $51 million in 2019.
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 $16 million in 2021, $15 million in 2020, and $12 million in 2019.
Effective Tax Rate
Southern Company's effective tax rate is typically lower than the statutory rate due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the traditional electric operating companies, flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs primarily at Southern Power.
On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent. As a result of the sale, changes in state apportionment rates resulted in $85 million of additional net state tax expense. See Note 15 under "Southern Company Gas" for additional information.
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A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
| 2021 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| Federal statutory rate | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | ||||||||
| State income tax, net of federal deduction | 5.5 | 4.6 | (5.7) | 4.9 | (8.0) | 15.1 | ||||||||||||||
| Employee stock plans' dividend deduction | (0.9) | — | — | — | — | — | ||||||||||||||
| Non-deductible book depreciation | 0.9 | 0.5 | 3.1 | 0.4 | — | — | ||||||||||||||
| Flowback of excess deferred income taxes | (11.7) | (2.6) | (49.9) | (15.2) | — | (2.8) | ||||||||||||||
| AFUDC-Equity | (1.5) | (0.7) | (6.4) | — | — | — | ||||||||||||||
| Federal PTCs | — | — | — | — | (4.6) | — | ||||||||||||||
| Amortization of ITC | (2.2) | (0.1) | (0.4) | — | (29.7) | (0.1) | ||||||||||||||
| Noncontrolling interests | 0.8 | — | — | — | 13.4 | — | ||||||||||||||
| Leveraged lease impairments and dispositions | (1.4) | — | — | — | — | — | ||||||||||||||
| Other | (0.1) | 0.2 | (1.9) | 0.6 | (0.4) | 0.6 | ||||||||||||||
| Effective income tax (benefit) rate | 10.4 | % | 22.9 | % | (40.2) | % | 11.7 | % | (8.3) | % | 33.8 | % |
| 2020 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| Federal statutory rate | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | ||||||||
| State income tax, net of federal deduction | 2.8 | 5.0 | 0.5 | 4.8 | 2.7 | 4.0 | ||||||||||||||
| Employee stock plans' dividend deduction | (0.7) | — | — | — | — | — | ||||||||||||||
| Non-deductible book depreciation | 0.7 | 0.6 | 0.8 | 0.5 | — | — | ||||||||||||||
| Flowback of excess deferred income taxes | (8.8) | (3.1) | (12.0) | (18.5) | — | (2.7) | ||||||||||||||
| AFUDC-Equity | (0.8) | (0.6) | (1.1) | (0.1) | — | — | ||||||||||||||
| Federal PTCs | — | — | — | — | (2.5) | — | ||||||||||||||
| Amortization of ITC | (1.6) | (0.1) | (0.1) | (0.1) | (22.1) | (0.1) | ||||||||||||||
| Noncontrolling interests | — | — | — | — | 3.1 | — | ||||||||||||||
| Leveraged lease impairments | (1.6) | — | — | — | — | — | ||||||||||||||
| Other | 0.2 | (0.3) | (0.3) | 0.9 | (0.9) | 0.5 | ||||||||||||||
| Effective income tax (benefit) rate | 11.2 | % | 22.5 | % | 8.8 | % | 8.5 | % | 1.3 | % | 22.7 | % |
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| 2019 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| Federal statutory rate | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | 21.0 | % | ||||||||
| State income tax, net of federal deduction | 4.9 | 4.9 | 1.0 | 4.3 | 4.0 | 6.1 | ||||||||||||||
| Employee stock plans' dividend deduction | (0.4) | — | — | — | — | — | ||||||||||||||
| Non-deductible book depreciation | 0.3 | 0.6 | 0.5 | 0.4 | — | — | ||||||||||||||
| Flowback of excess deferred income taxes | (2.1) | (5.3) | — | (12.6) | — | (6.0) | ||||||||||||||
| AFUDC-Equity | (0.4) | (0.8) | (0.6) | (0.1) | — | — | ||||||||||||||
| ITC basis difference | (0.1) | — | — | — | (1.9) | — | ||||||||||||||
| Amortization of ITC | (0.8) | (0.1) | (0.1) | (0.1) | (16.1) | (0.1) | ||||||||||||||
| Tax impact from sale of subsidiaries | 5.1 | — | — | — | (27.6) | (1.4) | ||||||||||||||
| Noncontrolling interests | — | — | — | — | 0.8 | — | ||||||||||||||
| Other | — | (0.4) | (0.3) | 4.9 | (0.6) | (1.4) | ||||||||||||||
| Effective income tax (benefit) rate | 27.5 | % | 19.9 | % | 21.5 | % | 17.8 | % | (20.4) | % | 18.2 | % |
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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:
| December 31, 2021 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Deferred tax liabilities — | ||||||||||||||||||||
| Accelerated depreciation | $ | 9,300 | $ | 2,541 | $ | 3,340 | $ | 330 | $ | 1,421 | $ | 1,428 | ||||||||
| Property basis differences | 2,301 | 1,182 | 781 | 169 | — | 148 | ||||||||||||||
| Federal effect of net state deferred tax assets | — | — | — | 22 | — | — | ||||||||||||||
| Leveraged lease basis differences | 61 | — | — | — | — | — | ||||||||||||||
| Employee benefit obligations | 820 | 268 | 382 | 41 | 11 | 57 | ||||||||||||||
| Under recovered fuel and natural gas costs | 315 | 47 | 109 | 15 | — | 144 | ||||||||||||||
| Regulatory assets – | ||||||||||||||||||||
| Storm damage reserves | 18 | — | 18 | — | — | — | ||||||||||||||
| Employee benefit obligations | 825 | 205 | 256 | 38 | — | 15 | ||||||||||||||
| Remaining book value of retired assets | 271 | 145 | 121 | 5 | — | — | ||||||||||||||
| Premium on reacquired debt | 72 | 10 | 62 | — | — | — | ||||||||||||||
| AROs | 2,232 | 863 | 1,325 | 44 | — | — | ||||||||||||||
| AROs | 868 | 329 | 494 | — | — | — | ||||||||||||||
| Other | 368 | 147 | 77 | 34 | 14 | 82 | ||||||||||||||
| Total deferred income tax liabilities | 17,451 | 5,737 | 6,965 | 698 | 1,446 | 1,874 | ||||||||||||||
| Deferred tax assets — | ||||||||||||||||||||
| Federal effect of net state deferred tax liabilities | 305 | 165 | 41 | — | 27 | 93 | ||||||||||||||
| State effect of federal deferred taxes | 135 | 135 | — | — | — | — | ||||||||||||||
| Employee benefit obligations | 1,035 | 225 | 342 | 57 | 7 | 77 | ||||||||||||||
| Other property basis differences | 231 | — | 90 | — | 121 | — | ||||||||||||||
| ITC and PTC carryforward | 1,750 | 12 | 704 | — | 827 | — | ||||||||||||||
| Long-term debt fair value adjustment | 91 | — | — | — | — | 91 | ||||||||||||||
| Other partnership basis difference | 160 | — | — | — | 160 | — | ||||||||||||||
| Other comprehensive losses | 92 | 5 | 15 | — | 11 | — | ||||||||||||||
| AROs | 3,100 | 1,192 | 1,819 | 44 | — | — | ||||||||||||||
| Estimated loss on plants under construction | 825 | — | 825 | — | — | — | ||||||||||||||
| Other deferred state tax attributes | 361 | — | 11 | 246 | 52 | 5 | ||||||||||||||
| Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) | 268 | 237 | 19 | 12 | — | — | ||||||||||||||
| Other | 561 | 193 | 153 | 34 | 53 | 62 | ||||||||||||||
| Total deferred income tax assets | 8,914 | 2,164 | 4,019 | 393 | 1,258 | 328 | ||||||||||||||
| Valuation allowance | (207) | — | (73) | (41) | (27) | (9) | ||||||||||||||
| Net deferred income tax assets | 8,707 | 2,164 | 3,946 | 352 | 1,231 | 319 | ||||||||||||||
| Net deferred income taxes (assets)/liabilities | $ | 8,744 | $ | 3,573 | $ | 3,019 | $ | 346 | $ | 215 | $ | 1,555 | ||||||||
| Recognized in the balance sheets: | ||||||||||||||||||||
| Accumulated deferred income taxes – assets | $ | (118) | $ | — | $ | — | $ | (118) | $ | — | $ | — | ||||||||
| Accumulated deferred income taxes – liabilities | $ | 8,862 | $ | 3,573 | $ | 3,019 | $ | 464 | $ | 215 | $ | 1,555 |
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| December 31, 2020 | ||||||||||||||||||||
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Deferred tax liabilities — | ||||||||||||||||||||
| Accelerated depreciation | $ | 8,950 | $ | 2,453 | $ | 3,228 | $ | 319 | $ | 1,389 | $ | 1,349 | ||||||||
| Property basis differences | 1,999 | 1,010 | 689 | 148 | — | 135 | ||||||||||||||
| Federal effect of net state deferred tax assets | — | — | — | 25 | — | — | ||||||||||||||
| Leveraged lease basis differences | 142 | — | — | — | — | — | ||||||||||||||
| Employee benefit obligations | 739 | 250 | 362 | 39 | 12 | 26 | ||||||||||||||
| Regulatory assets – | ||||||||||||||||||||
| Storm damage reserves | 80 | — | 80 | — | — | — | ||||||||||||||
| Employee benefit obligations | 1,313 | 348 | 438 | 62 | — | 45 | ||||||||||||||
| Remaining book value of retired assets | 270 | 123 | 141 | 6 | — | — | ||||||||||||||
| Premium on reacquired debt | 78 | 12 | 66 | — | — | — | ||||||||||||||
| AROs | 1,969 | 764 | 1,165 | 40 | — | — | ||||||||||||||
| AROs | 804 | 328 | 429 | — | — | — | ||||||||||||||
| Other | 437 | 128 | 82 | 66 | 12 | 138 | ||||||||||||||
| Total deferred income tax liabilities | 16,781 | 5,416 | 6,680 | 705 | 1,413 | 1,693 | ||||||||||||||
| Deferred tax assets — | ||||||||||||||||||||
| Federal effect of net state deferred tax liabilities | 284 | 151 | 59 | — | 26 | 70 | ||||||||||||||
| State effect of federal deferred taxes | 126 | 126 | — | — | — | — | ||||||||||||||
| Employee benefit obligations | 1,511 | 369 | 522 | 80 | 6 | 100 | ||||||||||||||
| Other property basis differences | 223 | — | 72 | — | 134 | — | ||||||||||||||
| ITC and PTC carryforward | 1,853 | 12 | 539 | — | 1,110 | — | ||||||||||||||
| Long-term debt fair value adjustment | 86 | — | — | — | — | 86 | ||||||||||||||
| Other partnership basis difference | 166 | — | — | — | 166 | — | ||||||||||||||
| Other comprehensive losses | 128 | 7 | 17 | — | 25 | — | ||||||||||||||
| AROs | 2,773 | 1,092 | 1,594 | 40 | — | — | ||||||||||||||
| Estimated loss on plants under construction | 369 | — | 369 | — | — | — | ||||||||||||||
| Other deferred state tax attributes | 357 | — | 9 | 250 | 68 | 10 | ||||||||||||||
| Regulatory liability associated with the Tax Reform Legislation (not subject to normalization) | 338 | 243 | 76 | 19 | — | — | ||||||||||||||
| Other | 660 | 143 | 186 | 39 | 52 | 166 | ||||||||||||||
| Total deferred income tax assets | 8,874 | 2,143 | 3,443 | 428 | 1,587 | 432 | ||||||||||||||
| Valuation allowance | (136) | — | (35) | (41) | (35) | (4) | ||||||||||||||
| Net deferred income tax assets | 8,738 | 2,143 | 3,408 | 387 | 1,552 | 428 | ||||||||||||||
| Net deferred income taxes (assets)/liabilities | $ | 8,043 | $ | 3,273 | $ | 3,272 | $ | 318 | $ | (139) | $ | 1,265 | ||||||||
| Recognized in the balance sheets: | ||||||||||||||||||||
| Accumulated deferred income taxes – assets | $ | (132) | $ | — | $ | — | $ | (129) | $ | (262) | $ | — | ||||||||
| Accumulated deferred income taxes – liabilities | $ | 8,175 | $ | 3,273 | $ | 3,272 | $ | 447 | $ | 123 | $ | 1,265 |
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 and to unamortized ITCs. See Note 2 for each Registrant's related balances at December 31, 2021 and 2020.
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Southern Company and Subsidiary Companies 2021 Annual Report
Tax Credit Carryforwards
Federal ITC/PTC carryforwards at December 31, 2021 were as follows:
| Southern Company | Alabama Power | Georgia Power | Southern Power | |||||||||||
| (in millions) | ||||||||||||||
| Federal ITC/PTC carryforwards | $ | 1,218 | $ | 12 | $ | 173 | $ | 827 | ||||||
| Tax year in which federal ITC/PTC carryforwards begin expiring | 2031 | 2032 | 2031 | 2035 | ||||||||||
| Year by which federal ITC/PTC carryforwards are expected to be utilized | 2024 | 2024 | 2024 | 2024 |
The estimated tax credit utilization reflects the various sale transactions described in Note 15 and could be further delayed by numerous factors, including the acquisition of additional renewable projects, an increase in Georgia Power's ownership interest percentage in Plant Vogtle Units 3 and 4, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, changes in taxable income projections, and potential income tax rate changes. See Note 2 under "Georgia Power – Nuclear Construction" for additional information on Plant Vogtle Units 3 and 4.
At December 31, 2021, Georgia Power also had approximately $428 million in net state investment and other net state tax credit carryforwards for the State of Georgia that will expire between tax years 2021 and 2031 and are not expected to be fully utilized. Georgia Power has a net state valuation allowance of $58 million associated with these carryforwards.
The ultimate outcome of these matters cannot be determined at this time.
Net Operating Loss Carryforwards
At December 31, 2021, the net state income tax benefit of state and local NOL carryforwards for Southern Company's subsidiaries were as follows:
| Company/Jurisdiction | Approximate Net State Income Tax Benefit of NOL Carryforwards | Tax Year NOL Begins Expiring | ||||||
| (in millions) | ||||||||
| Mississippi Power | ||||||||
| Mississippi | $ | 195 | 2031 | |||||
| Southern Power | ||||||||
| Oklahoma | 27 | 2035 | ||||||
| Florida | 10 | 2034 | ||||||
| South Carolina | 2 | 2036 | ||||||
| Other states | 2 | Various | ||||||
| Southern Power Total | $ | 41 | ||||||
| Other**(*)** | ||||||||
| New York | 11 | 2035 | ||||||
| New York City | 14 | 2035 | ||||||
| Other states | 17 | Various | ||||||
| Southern Company Total | $ | 278 |
(*)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, 2021.
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Southern Company and Subsidiary Companies 2021 Annual Report
State NOLs for Mississippi, Oklahoma, and Florida are not expected to be fully utilized prior to expiration. At December 31, 2021, Mississippi Power had a net state valuation allowance of $32 million for the Mississippi NOL, Southern Power had net state valuation allowances of $11 million for the Oklahoma NOL and $10 million for the Florida NOL, and Southern Company had a net valuation allowance of $25 million for the New York and New York City NOLs.
The ultimate outcome of these matters cannot be determined at this time.
Unrecognized Tax Benefits
Changes in unrecognized tax benefits for the periods presented were as follows:
| Southern Company | |||||
| (in millions) | |||||
| Unrecognized tax benefits at December 31, 2018 and 2019 | $ | — | |||
| Tax positions changes – increase from prior periods | 44 | ||||
| Unrecognized tax benefits at December 31, 2020 | 44 | ||||
| Tax positions changes – increase from prior periods | 3 | ||||
| Unrecognized tax benefits at December 31, 2021 | $ | 47 |
The unrecognized tax positions increase from prior periods for 2020 and the balance of unrecognized tax benefits at December 31, 2020 and 2021 primarily relate to a 2019 state tax filing position to exclude certain gains from 2019 dispositions from taxation in a certain unitary state. If accepted by the state, this position would decrease Southern Company's annual effective tax rate. The ultimate outcome of this unrecognized tax benefit is dependent on completion of the related state audit, which is not expected to be resolved within the next 12 months.
All of the Registrants classify interest on tax uncertainties as interest expense. Accrued interest for all tax positions was immaterial for all years 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 2020. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Registrants' state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2015.
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, 2021 and no mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2022. 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. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses. For the year ending December 31, 2022, no contributions to any other postretirement trusts are expected.
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Southern Company and Subsidiary Companies 2021 Annual Report
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.
| 2021 | ||||||||||||||||||||
| 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 | 2.81 | % | 2.85 | % | 2.79 | % | 2.80 | % | 2.99 | % | 2.75 | % | ||||||||
| Discount rate – interest costs | 2.13 | 2.17 | 2.09 | 2.12 | 2.46 | 2.10 | ||||||||||||||
| Discount rate – service costs | 3.18 | 3.23 | 3.21 | 3.20 | 3.22 | 2.97 | ||||||||||||||
| Expected long-term return on plan assets | 8.25 | 8.25 | 8.25 | 8.25 | 8.25 | 8.25 | ||||||||||||||
| Annual salary increase | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate – benefit obligations | 2.56 | % | 2.63 | % | 2.52 | % | 2.53 | % | 2.78 | % | 2.46 | % | ||||||||
| Discount rate – interest costs | 1.84 | 1.91 | 1.82 | 1.78 | 2.12 | 1.64 | ||||||||||||||
| Discount rate – service costs | 3.07 | 3.13 | 3.08 | 3.06 | 3.05 | 3.01 | ||||||||||||||
| Expected long-term return on plan assets | 7.09 | 7.18 | 6.84 | 6.98 | — | 6.54 | ||||||||||||||
| Annual salary increase | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 |
| 2020 | ||||||||||||||||||||
| 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 | 3.41 | % | 3.44 | % | 3.40 | % | 3.41 | % | 3.52 | % | 3.39 | % | ||||||||
| Discount rate – interest costs | 2.99 | 3.01 | 2.96 | 2.99 | 3.18 | 2.99 | ||||||||||||||
| Discount rate – service costs | 3.66 | 3.69 | 3.67 | 3.67 | 3.70 | 3.53 | ||||||||||||||
| Expected long-term return on plan assets | 8.25 | 8.25 | 8.25 | 8.25 | 8.25 | 8.25 | ||||||||||||||
| Annual salary increase | 4.73 | 4.73 | 4.73 | 4.73 | 4.73 | 4.73 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate – benefit obligations | 3.24 | % | 3.28 | % | 3.22 | % | 3.22 | % | 3.39 | % | 3.19 | % | ||||||||
| Discount rate – interest costs | 2.80 | 2.84 | 2.79 | 2.76 | 2.97 | 2.71 | ||||||||||||||
| Discount rate – service costs | 3.57 | 3.61 | 3.57 | 3.57 | 3.57 | 3.52 | ||||||||||||||
| Expected long-term return on plan assets | 7.25 | 7.36 | 7.05 | 7.07 | — | 6.69 | ||||||||||||||
| Annual salary increase | 4.73 | 4.73 | 4.73 | 4.73 | 4.73 | 4.73 |
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| 2019 | ||||||||||||||||||||
| 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 | 4.49 | % | 4.51 | % | 4.48 | % | 4.49 | % | 4.65 | % | 4.47 | % | ||||||||
| Discount rate – interest costs | 4.12 | 4.14 | 4.10 | 4.12 | 4.35 | 4.11 | ||||||||||||||
| Discount rate – service costs | 4.70 | 4.73 | 4.72 | 4.73 | 4.75 | 4.57 | ||||||||||||||
| Expected long-term return on plan assets | 7.75 | 7.75 | 7.75 | 7.75 | 7.75 | 7.75 | ||||||||||||||
| Annual salary increase | 4.34 | 4.46 | 4.46 | 4.46 | 4.46 | 3.07 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate – benefit obligations | 4.37 | % | 4.40 | % | 4.36 | % | 4.35 | % | 4.50 | % | 4.32 | % | ||||||||
| Discount rate – interest costs | 3.98 | 4.01 | 3.97 | 3.95 | 4.14 | 3.91 | ||||||||||||||
| Discount rate – service costs | 4.63 | 4.67 | 4.64 | 4.64 | 4.65 | 4.56 | ||||||||||||||
| Expected long-term return on plan assets | 6.86 | 6.76 | 6.85 | 6.79 | — | 6.49 | ||||||||||||||
| Annual salary increase | 4.34 | 4.46 | 4.46 | 4.46 | 4.46 | 3.07 |
| 2021 | ||||||||||||||||||||
| Assumptions used to determine benefit obligations: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| Pension plans | ||||||||||||||||||||
| Discount rate | 3.09 | % | 3.12 | % | 3.07 | % | 3.07 | % | 3.21 | % | 3.04 | % | ||||||||
| Annual salary increase | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate | 2.90 | % | 2.95 | % | 2.87 | % | 2.88 | % | 3.07 | % | 2.82 | % | ||||||||
| Annual salary increase | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 |
| 2020 | ||||||||||||||||||||
| Assumptions used to determine benefit obligations: | Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | ||||||||||||||
| Pension plans | ||||||||||||||||||||
| Discount rate | 2.81 | % | 2.85 | % | 2.79 | % | 2.80 | % | 2.99 | % | 2.75 | % | ||||||||
| Annual salary increase | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | ||||||||||||||
| Other postretirement benefit plans | ||||||||||||||||||||
| Discount rate | 2.56 | % | 2.63 | % | 2.52 | % | 2.53 | % | 2.78 | % | 2.46 | % | ||||||||
| Annual salary increase | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 | 4.80 |
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. Prior to 2020, the Registrants set the expected rate of return assumption using asset return modeling based on geometric returns that reflect the compound average returns for dependent annual periods. Beginning in 2020, 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, 2021 were as follows:
| Initial Cost Trend Rate | Ultimate Cost Trend Rate | Year That Ultimate Rate is Reached | |||||||||||||||
| Pre-65 | 6.00 | % | 4.50 | % | 2028 | ||||||||||||
| Post-65 medical | 5.00 | 4.50 | 2028 | ||||||||||||||
| Post-65 prescription | 6.25 | 4.50 | 2029 |
Pension Plans
The total accumulated benefit obligation for the pension plans at December 31, 2021 and 2020 was as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| December 31, 2021 | $ | 14,687 | $ | 3,362 | $ | 4,562 | $ | 672 | $ | 178 | $ | 1,030 | ||||||||
| December 31, 2020 | 14,922 | 3,414 | 4,657 | 683 | 175 | 1,072 |
An actuarial gain of $393 million was recorded for the annual remeasurement of the Southern Company system pension plans at December 31, 2021 primarily due to an increase of 28 basis points in the overall discount rate used to calculate the benefit obligation as a result of higher market interest rates. An actuarial loss of $1.7 billion was recorded for the annual remeasurement of the Southern Company system pension plans at December 31, 2020 primarily due to a decrease of 60 basis points in the overall discount rate used to calculate the benefit obligation as a result of lower market interest rates.
Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2021 and 2020 were as follows:
| 2021 | ||||||||||||||||||||
| 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 | $ | 16,646 | $ | 3,854 | $ | 5,127 | $ | 754 | $ | 217 | $ | 1,189 | ||||||||
| Service cost | 434 | 102 | 112 | 18 | 10 | 37 | ||||||||||||||
| Interest cost | 346 | 82 | 104 | 16 | 5 | 24 | ||||||||||||||
| Benefits paid | (651) | (137) | (210) | (28) | (4) | (73) | ||||||||||||||
| Actuarial gain | (393) | (95) | (121) | (17) | (6) | (43) | ||||||||||||||
| Balance at end of year | 16,382 | 3,806 | 5,012 | 743 | 222 | 1,134 | ||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Fair value of plan assets at beginning of year | 15,367 | 3,684 | 4,844 | 701 | 186 | 1,123 | ||||||||||||||
| Actual return on plan assets | 2,449 | 586 | 781 | 111 | 30 | 181 | ||||||||||||||
| Employer contributions | 60 | 8 | — | 2 | 1 | 10 | ||||||||||||||
| Benefits paid | (651) | (137) | (210) | (28) | (4) | (73) | ||||||||||||||
| Fair value of plan assets at end of year | 17,225 | 4,141 | 5,415 | 786 | 213 | 1,241 | ||||||||||||||
| Accrued asset (liability) | $ | 843 | $ | 335 | $ | 403 | $ | 43 | $ | (9) | $ | 107 |
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| 2020 | ||||||||||||||||||||
| 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 | $ | 14,788 | $ | 3,404 | $ | 4,610 | $ | 671 | $ | 185 | $ | 1,067 | ||||||||
| Service cost | 376 | 89 | 96 | 15 | 8 | 33 | ||||||||||||||
| Interest cost | 432 | 100 | 133 | 20 | 6 | 31 | ||||||||||||||
| Benefits paid | (629) | (132) | (202) | (27) | (6) | (69) | ||||||||||||||
| Actuarial loss | 1,679 | 393 | 490 | 75 | 24 | 127 | ||||||||||||||
| Balance at end of year | 16,646 | 3,854 | 5,127 | 754 | 217 | 1,189 | ||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Fair value of plan assets at beginning of year | 14,057 | 3,357 | 4,442 | 641 | 169 | 1,050 | ||||||||||||||
| Actual return on plan assets | 1,881 | 450 | 594 | 85 | 22 | 139 | ||||||||||||||
| Employer contributions | 58 | 9 | 10 | 2 | 1 | 3 | ||||||||||||||
| Benefits paid | (629) | (132) | (202) | (27) | (6) | (69) | ||||||||||||||
| Fair value of plan assets at end of year | 15,367 | 3,684 | 4,844 | 701 | 186 | 1,123 | ||||||||||||||
| Accrued liability | $ | (1,279) | $ | (170) | $ | (283) | $ | (53) | $ | (31) | $ | (66) |
The projected benefit obligations for the qualified and non-qualified pension plans at December 31, 2021 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 | $ | 15,568 | $ | 3,678 | $ | 4,852 | $ | 708 | $ | 193 | $ | 1,066 | ||||||||
| Non-qualified pension plan | 814 | 129 | 160 | 36 | 29 | 68 |
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
Amounts recognized in the balance sheets at December 31, 2021 and 2020 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) | ||||||||||||||||||||
| December 31, 2021: | ||||||||||||||||||||
| Prepaid pension costs(a) | $ | 1,657 | $ | 464 | $ | 563 | $ | 78 | $ | 20 | $ | 175 | ||||||||
| Other regulatory assets, deferred(b) | 2,920 | 809 | 971 | 146 | — | 91 | ||||||||||||||
| Other current liabilities | (55) | (9) | (12) | (2) | (2) | (2) | ||||||||||||||
| Employee benefit obligations(c) | (759) | (120) | (148) | (33) | (27) | (66) | ||||||||||||||
| Other regulatory liabilities, deferred | (119) | — | — | — | — | — | ||||||||||||||
| AOCI | 100 | — | — | — | 35 | (45) | ||||||||||||||
| December 31, 2020: | ||||||||||||||||||||
| Prepaid pension costs | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 70 | ||||||||
| Other regulatory assets, deferred(b) | 4,655 | 1,286 | 1,598 | 235 | — | 205 | ||||||||||||||
| Other current liabilities | (52) | (9) | (10) | (2) | (2) | (2) | ||||||||||||||
| Employee benefit obligations(c) | (1,227) | (161) | (273) | (51) | (29) | (134) | ||||||||||||||
| Other regulatory liabilities, deferred | (34) | — | — | — | — | — | ||||||||||||||
| AOCI | 245 | — | — | — | 60 | 1 |
(a)Included in prepaid pension and other postretirement benefit costs on Alabama Power's balance sheet and other deferred charges and assets on Southern Power's consolidated balance sheet.
(b)Amounts for Southern Company exclude regulatory assets of $210 million and $224 million at December 31, 2021 and 2020, 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, 2021 and 2020 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, 2021 | |||||||||||||||||
| Regulatory assets: | |||||||||||||||||
| Prior service cost | $ | 11 | $ | 5 | $ | 8 | $ | 1 | $ | (11) | |||||||
| Net loss | 2,790 | 804 | 963 | 145 | 38 | ||||||||||||
| Regulatory amortization | — | — | — | — | 64 | ||||||||||||
| Total regulatory assets(*) | $ | 2,801 | $ | 809 | $ | 971 | $ | 146 | $ | 91 | |||||||
| Balance at December 31, 2020 | |||||||||||||||||
| Regulatory assets: | |||||||||||||||||
| Prior service cost | $ | 11 | $ | 5 | $ | 9 | $ | 2 | $ | (13) | |||||||
| Net loss | 4,610 | 1,281 | 1,589 | 233 | 135 | ||||||||||||
| Regulatory amortization | — | — | — | — | 83 | ||||||||||||
| Total regulatory assets(*) | $ | 4,621 | $ | 1,286 | $ | 1,598 | $ | 235 | $ | 205 | |||||||
(*)Amounts for Southern Company exclude regulatory assets of $210 million and $224 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
The changes in the balance of regulatory assets 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, 2021 and 2020 are presented in the following table:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Company Gas | |||||||||||||
| (in millions) | |||||||||||||||||
| **Regulatory assets (liabilities):*() | |||||||||||||||||
| Balance at December 31, 2019 | $ | 3,993 | $ | 1,130 | $ | 1,416 | $ | 203 | $ | 172 | |||||||
| Net loss | 884 | 228 | 269 | 45 | 45 | ||||||||||||
| Reclassification adjustments: | |||||||||||||||||
| Amortization of prior service costs | (1) | (1) | (1) | — | 2 | ||||||||||||
| Amortization of net loss | (255) | (71) | (86) | (13) | (8) | ||||||||||||
| Amortization of regulatory assets**(*)** | — | — | — | — | (6) | ||||||||||||
| Total reclassification adjustments | (256) | (72) | (87) | (13) | (12) | ||||||||||||
| Total change | 628 | 156 | 182 | 32 | 33 | ||||||||||||
| Balance at December 31, 2020 | $ | 4,621 | $ | 1,286 | $ | 1,598 | $ | 235 | $ | 205 | |||||||
| Net gain | (1,523) | (394) | (527) | (74) | (97) | ||||||||||||
| Reclassification adjustments: | |||||||||||||||||
| Amortization of prior service costs | (1) | (1) | (1) | — | 2 | ||||||||||||
| Amortization of net loss | (296) | (82) | (99) | (15) | (9) | ||||||||||||
| Amortization of regulatory assets**(*)** | — | — | — | — | (10) | ||||||||||||
| Total reclassification adjustments | (297) | (83) | (100) | (15) | (17) | ||||||||||||
| Total change | (1,820) | (477) | (627) | (89) | (114) | ||||||||||||
| Balance at December 31, 2021 | $ | 2,801 | $ | 809 | $ | 971 | $ | 146 | $ | 91 |
(*)Amounts for Southern Company exclude regulatory assets of $210 million and $224 million at December 31, 2021 and 2020, 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, 2021 and 2020 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, 2021 | |||||||||||
| AOCI: | |||||||||||
| Prior service cost | $ | (2) | $ | — | $ | (3) | |||||
| Net (gain) loss | 102 | 35 | (42) | ||||||||
| Total AOCI | $ | 100 | $ | 35 | $ | (45) | |||||
| Balance at December 31, 2020 | |||||||||||
| AOCI: | |||||||||||
| Prior service cost | $ | (3) | $ | — | $ | (4) | |||||
| Net loss | 248 | 60 | 5 | ||||||||
| Total AOCI | $ | 245 | $ | 60 | $ | 1 | |||||
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Southern Company and Subsidiary Companies 2021 Annual Report
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, 2021 and 2020 are presented in the following table:
| Southern Company | Southern Power | Southern Company Gas | |||||||||
| (in millions) | |||||||||||
| AOCI: | |||||||||||
| Balance at December 31, 2019 | $ | 185 | $ | 46 | $ | (14) | |||||
| Net loss | 74 | 16 | 15 | ||||||||
| Reclassification adjustments: | |||||||||||
| Amortization of prior service costs | — | — | 1 | ||||||||
| Amortization of net loss | (14) | (2) | (1) | ||||||||
| Total reclassification adjustments | (14) | (2) | — | ||||||||
| Total change | 60 | 14 | 15 | ||||||||
| Balance at December 31, 2020 | $ | 245 | $ | 60 | $ | 1 | |||||
| Net gain | (128) | (22) | (47) | ||||||||
| Reclassification adjustments: | |||||||||||
| Amortization of net gain (loss) | (17) | (3) | 1 | ||||||||
| Total reclassification adjustments | (17) | (3) | 1 | ||||||||
| Total change | (145) | (25) | (46) | ||||||||
| Balance at December 31, 2021 | $ | 100 | $ | 35 | $ | (45) |
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
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) | ||||||||||||||||||||
| 2021 | ||||||||||||||||||||
| Service cost | $ | 434 | $ | 102 | $ | 112 | $ | 18 | $ | 10 | $ | 37 | ||||||||
| Interest cost | 346 | 82 | 104 | 16 | 5 | 24 | ||||||||||||||
| Expected return on plan assets | (1,191) | (287) | (375) | (55) | (14) | (86) | ||||||||||||||
| Recognized net loss | 314 | 82 | 100 | 15 | 3 | 13 | ||||||||||||||
| Net amortization | 1 | 1 | 1 | — | — | 15 | ||||||||||||||
| Prior service cost | — | — | — | — | — | (3) | ||||||||||||||
| Net periodic pension cost (income) | $ | (96) | $ | (20) | $ | (58) | $ | (6) | $ | 4 | $ | — | ||||||||
| 2020 | ||||||||||||||||||||
| Service cost | $ | 376 | $ | 89 | $ | 96 | $ | 15 | $ | 8 | $ | 33 | ||||||||
| Interest cost | 432 | 100 | 133 | 20 | 6 | 31 | ||||||||||||||
| Expected return on plan assets | (1,100) | (264) | (347) | (51) | (13) | (75) | ||||||||||||||
| Recognized net loss | 269 | 71 | 86 | 13 | 2 | 6 | ||||||||||||||
| Net amortization | 1 | 1 | 1 | — | — | 15 | ||||||||||||||
| Prior service cost | — | — | — | — | — | (3) | ||||||||||||||
| Net periodic pension cost (income) | $ | (22) | $ | (3) | $ | (31) | $ | (3) | $ | 3 | $ | 7 | ||||||||
| 2019 | ||||||||||||||||||||
| Service cost | $ | 292 | $ | 69 | $ | 74 | $ | 12 | $ | 7 | $ | 25 | ||||||||
| Interest cost | 492 | 114 | 156 | 22 | 5 | 36 | ||||||||||||||
| Expected return on plan assets | (885) | (206) | (292) | (40) | (10) | (60) | ||||||||||||||
| Recognized net loss | 120 | 37 | 44 | 6 | 1 | 2 | ||||||||||||||
| Net amortization | 2 | — | 1 | — | — | 14 | ||||||||||||||
| Prior service cost | — | — | — | — | — | (3) | ||||||||||||||
| Net periodic pension cost (income) | $ | 21 | $ | 14 | $ | (17) | $ | — | $ | 3 | $ | 14 |
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.
Effective January 1, 2020, Southern Company changed its method of calculating the market-related value of the liability-hedging securities included in its pension plan assets. The market-related value is used to determine the expected return on plan assets component of net periodic pension cost. Southern Company previously used the calculated value approach for all plan assets, which smoothed asset returns and deferred gains and losses by amortizing them into the calculation of the market-related value over five years. Southern Company changed to the fair value approach for liability-hedging securities, which includes measuring the market-related value of that portion of the plan assets at fair value for purposes of determining the expected return on plan assets. The remaining asset classes of plan assets continue to be valued using the calculated value approach. Southern Company considers the fair value approach to be preferable for liability-hedging securities because it results in a current reflection of changes in the value of plan assets in the measurement of net periodic pension cost more consistent with the change in the related obligations.
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
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, 2021, estimated benefit payments were as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| Benefit Payments: | ||||||||||||||||||||
| 2022 | $ | 690 | $ | 148 | $ | 223 | $ | 31 | $ | 6 | $ | 65 | ||||||||
| 2023 | 714 | 155 | 229 | 31 | 6 | 65 | ||||||||||||||
| 2024 | 736 | 159 | 235 | 32 | 6 | 64 | ||||||||||||||
| 2025 | 759 | 165 | 240 | 34 | 7 | 64 | ||||||||||||||
| 2026 | 780 | 171 | 245 | 35 | 7 | 64 | ||||||||||||||
| 2027 to 2031 | 4,138 | 921 | 1,275 | 187 | 42 | 329 |
Other Postretirement Benefits
Changes in the APBO and the fair value of the Registrants' plan assets during the plan years ended December 31, 2021 and 2020 were as follows:
| 2021 | ||||||||||||||||||||
| 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 | $ | 1,948 | $ | 463 | $ | 699 | $ | 81 | $ | 12 | $ | 248 | ||||||||
| Service cost | 24 | 6 | 7 | 1 | — | 2 | ||||||||||||||
| Interest cost | 35 | 9 | 12 | 1 | — | 4 | ||||||||||||||
| Benefits paid | (105) | (22) | (36) | (5) | — | (18) | ||||||||||||||
| Actuarial (gain) loss | (54) | (16) | (26) | (2) | (1) | 1 | ||||||||||||||
| Retiree drug subsidy | 1 | — | — | — | — | — | ||||||||||||||
| Balance at end of year | 1,849 | 440 | 656 | 76 | 11 | 237 | ||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Fair value of plan assets at beginning of year | 1,158 | 458 | 427 | 27 | — | 128 | ||||||||||||||
| Actual return on plan assets | 154 | 55 | 55 | 4 | — | 18 | ||||||||||||||
| Employer contributions | 43 | (2) | 4 | 3 | — | 15 | ||||||||||||||
| Benefits paid | (104) | (22) | (36) | (5) | — | (18) | ||||||||||||||
| Fair value of plan assets at end of year | 1,251 | 489 | 450 | 29 | — | 143 | ||||||||||||||
| Accrued asset (liability) | $ | (598) | $ | 49 | $ | (206) | $ | (47) | $ | (11) | $ | (94) |
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Southern Company and Subsidiary Companies 2021 Annual Report
| 2020 | ||||||||||||||||||||
| 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 | $ | 1,985 | $ | 462 | $ | 742 | $ | 87 | $ | 11 | $ | 250 | ||||||||
| Service cost | 22 | 6 | 6 | 1 | 1 | 2 | ||||||||||||||
| Interest cost | 54 | 13 | 20 | 2 | — | 7 | ||||||||||||||
| Benefits paid | (126) | (29) | (46) | (6) | — | (17) | ||||||||||||||
| Actuarial (gain) loss | 7 | 9 | (26) | (3) | — | 6 | ||||||||||||||
| Retiree drug subsidy | 6 | 2 | 3 | — | — | — | ||||||||||||||
| Balance at end of year | 1,948 | 463 | 699 | 81 | 12 | 248 | ||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Fair value of plan assets at beginning of year | 1,061 | 413 | 403 | 26 | — | 115 | ||||||||||||||
| Actual return on plan assets | 145 | 60 | 50 | 3 | — | 18 | ||||||||||||||
| Employer contributions | 72 | 12 | 17 | 4 | — | 12 | ||||||||||||||
| Benefits paid | (120) | (27) | (43) | (6) | — | (17) | ||||||||||||||
| Fair value of plan assets at end of year | 1,158 | 458 | 427 | 27 | — | 128 | ||||||||||||||
| Accrued liability | $ | (790) | $ | (5) | $ | (272) | $ | (54) | $ | (12) | $ | (120) |
Amounts recognized in the balance sheets at December 31, 2021 and 2020 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) | ||||||||||||||||||||
| December 31, 2021: | ||||||||||||||||||||
| Prepaid other postretirement benefit costs(a) | $ | — | $ | 49 | $ | — | $ | — | $ | — | $ | — | ||||||||
| Other regulatory assets, deferred(b) | 97 | — | 30 | 2 | — | — | ||||||||||||||
| Other current liabilities | (5) | — | — | — | — | — | ||||||||||||||
| Employee benefit obligations(c) | (593) | — | (206) | (47) | (11) | (94) | ||||||||||||||
| Other regulatory liabilities, deferred | (171) | (62) | (40) | (1) | — | (34) | ||||||||||||||
| AOCI | — | — | — | — | 2 | (5) | ||||||||||||||
| December 31, 2020: | ||||||||||||||||||||
| Other regulatory assets, deferred(b) | $ | 137 | $ | — | $ | 47 | $ | 5 | $ | — | $ | (23) | ||||||||
| Other current liabilities | (5) | — | — | — | — | — | ||||||||||||||
| Employee benefit obligations(c) | (785) | (5) | (272) | (54) | (12) | (120) | ||||||||||||||
| Other regulatory liabilities, deferred | (86) | (21) | — | — | — | — | ||||||||||||||
| AOCI | 8 | — | — | — | 3 | — |
(a)Included in prepaid pension and other postretirement benefit costs on Alabama Power's balance sheet.
(b)Amounts for Southern Company exclude regulatory assets of $40 million and $47 million at December 31, 2021 and 2020, 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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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
Presented below are the amounts included in net regulatory assets (liabilities) at December 31, 2021 and 2020 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, 2021: | |||||||||||||||||
| Regulatory assets (liabilities): | |||||||||||||||||
| Prior service cost | $ | 13 | $ | 3 | $ | 5 | $ | 1 | $ | 1 | |||||||
| Net gain | (87) | (65) | (15) | — | (51) | ||||||||||||
| Regulatory amortization | — | — | — | — | 16 | ||||||||||||
| Total regulatory assets (liabilities)(*) | $ | (74) | $ | (62) | $ | (10) | $ | 1 | $ | (34) | |||||||
| Balance at December 31, 2020: | |||||||||||||||||
| Regulatory assets (liabilities): | |||||||||||||||||
| Prior service cost | $ | 12 | $ | 3 | $ | 5 | $ | — | $ | 1 | |||||||
| Net (gain) loss | 39 | (24) | 42 | 5 | (49) | ||||||||||||
| Regulatory amortization | — | — | — | — | 25 | ||||||||||||
| Total regulatory assets (liabilities)(*) | $ | 51 | $ | (21) | $ | 47 | $ | 5 | $ | (23) | |||||||
(*)Amounts for Southern Company exclude regulatory assets of $40 million and $47 million at December 31, 2021 and 2020, 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 (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
The changes in the balance of net regulatory assets (liabilities) related to the other postretirement benefit plans for the plan years ended December 31, 2021 and 2020 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, 2019 | $ | 121 | $ | 1 | $ | 96 | $ | 10 | $ | (11) | |||||||
| Net gain | (65) | (22) | (47) | (5) | (5) | ||||||||||||
| Reclassification adjustments: | |||||||||||||||||
| Amortization of prior service costs | 1 | — | 1 | — | — | ||||||||||||
| Amortization of net loss | (6) | — | (3) | — | — | ||||||||||||
| Amortization of regulatory assets**(*)** | — | — | — | — | (7) | ||||||||||||
| Total reclassification adjustments | (5) | — | (2) | — | (7) | ||||||||||||
| Total change | (70) | (22) | (49) | (5) | (12) | ||||||||||||
| Balance at December 31, 2020 | $ | 51 | $ | (21) | $ | 47 | $ | 5 | $ | (23) | |||||||
| Net gain | (120) | (41) | (55) | (4) | (2) | ||||||||||||
| Reclassification adjustments: | |||||||||||||||||
| Amortization of prior service costs | 1 | — | 1 | — | — | ||||||||||||
| Amortization of net loss | (6) | — | (3) | — | — | ||||||||||||
| Amortization of regulatory assets**(*)** | — | — | — | — | (9) | ||||||||||||
| Total reclassification adjustments | (5) | — | (2) | — | (9) | ||||||||||||
| Total change | (125) | (41) | (57) | (4) | (11) | ||||||||||||
| Balance at December 31, 2021 | $ | (74) | $ | (62) | $ | (10) | $ | 1 | $ | (34) |
(*)Amounts for Southern Company exclude regulatory assets of $40 million and $47 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.
Presented below are the amounts included in AOCI at December 31, 2021 and 2020 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, 2021 | |||||||||||
| AOCI: | |||||||||||
| Prior service cost | $ | 1 | $ | — | $ | 1 | |||||
| Net (gain) loss | (1) | 2 | (6) | ||||||||
| Total AOCI | $ | — | $ | 2 | $ | (5) | |||||
| Balance at December 31, 2020 | |||||||||||
| AOCI: | |||||||||||
| Prior service cost | $ | 1 | $ | — | $ | 1 | |||||
| Net (gain) loss | 7 | 3 | (1) | ||||||||
| Total AOCI | $ | 8 | $ | 3 | $ | — | |||||
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
The components of OCI related to the other postretirement benefit plans for the plan years ended December 31, 2021 and 2020 are presented in the following table:
| Southern Company | Southern Power | Southern Company Gas | |||||||||
| (in millions) | |||||||||||
| AOCI: | |||||||||||
| Balance at December 31, 2019 | $ | 2 | $ | 2 | $ | (4) | |||||
| Net loss | 2 | 1 | — | ||||||||
| Reclassification adjustments: | |||||||||||
| Amortization of net gain (loss) | 4 | — | 4 | ||||||||
| Total change | 6 | 1 | 4 | ||||||||
| Balance at December 31, 2020 | $ | 8 | $ | 3 | $ | — | |||||
| Net gain | (11) | (1) | — | ||||||||
| Reclassification adjustments: | |||||||||||
| Amortization of net gain (loss) | 3 | — | (5) | ||||||||
| Total change | (8) | (1) | (5) | ||||||||
| Balance at December 31, 2021 | $ | — | $ | 2 | $ | (5) |
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) | ||||||||||||||||||||
| 2021 | ||||||||||||||||||||
| Service cost | $ | 24 | $ | 6 | $ | 7 | $ | 1 | $ | — | $ | 2 | ||||||||
| Interest cost | 35 | 9 | 12 | 1 | — | 4 | ||||||||||||||
| Expected return on plan assets | (76) | (30) | (26) | (1) | 1 | (10) | ||||||||||||||
| Net amortization | 2 | — | 2 | — | — | 6 | ||||||||||||||
| Net periodic postretirement benefit cost (income) | $ | (15) | $ | (15) | $ | (5) | $ | 1 | $ | 1 | $ | 2 | ||||||||
| 2020 | ||||||||||||||||||||
| Service cost | $ | 22 | $ | 6 | $ | 6 | $ | 1 | $ | 1 | $ | 2 | ||||||||
| Interest cost | 54 | 13 | 20 | 2 | — | 7 | ||||||||||||||
| Expected return on plan assets | (72) | (29) | (26) | (1) | — | (10) | ||||||||||||||
| Net amortization | 1 | — | 2 | — | — | 6 | ||||||||||||||
| Net periodic postretirement benefit cost (income) | $ | 5 | $ | (10) | $ | 2 | $ | 2 | $ | 1 | $ | 5 | ||||||||
| 2019 | ||||||||||||||||||||
| Service cost | $ | 18 | $ | 5 | $ | 5 | $ | 1 | $ | 1 | $ | 1 | ||||||||
| Interest cost | 69 | 16 | 26 | 3 | — | 9 | ||||||||||||||
| Expected return on plan assets | (65) | (26) | (25) | (2) | — | (7) | ||||||||||||||
| Net amortization | — | 4 | 1 | — | — | 6 | ||||||||||||||
| Net periodic postretirement benefit cost (income) | $ | 22 | $ | (1) | $ | 7 | $ | 2 | $ | 1 | $ | 9 |
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
The service cost component of net periodic postretirement benefit cost is included in operations and maintenance expenses and all other components of net periodic 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: | ||||||||||||||||||||
| 2022 | $ | 111 | $ | 24 | $ | 40 | $ | 5 | $ | — | $ | 17 | ||||||||
| 2023 | 110 | 24 | 39 | 5 | — | 17 | ||||||||||||||
| 2024 | 109 | 24 | 38 | 5 | — | 18 | ||||||||||||||
| 2025 | 112 | 25 | 40 | 5 | 1 | 17 | ||||||||||||||
| 2026 | 112 | 25 | 40 | 5 | 1 | 17 | ||||||||||||||
| 2027 to 2031 | 552 | 128 | 199 | 22 | 3 | 75 | ||||||||||||||
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.
Southern Company's investment strategy also includes adjusting the established asset allocation to invest a larger portion of the portfolio in fixed rate debt securities should the qualified pension plan achieve a predetermined funding threshold. Any future reallocation of plan assets based on achieving the funding threshold would likely result in a reduction in the expected long-term return on plan assets used to determine pension income. However, the amount of such a decrease and the related financial statement impact cannot be determined at this time.
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
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. | ||||
| 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. Real estate: Investments in traditional private market, equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities. Private equity: Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt. | Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values 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 fair value of partnerships 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. The Registrants did not have any investments classified as Level 3 at December 31, 2020.
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
The fair values, and actual allocations relative to the target allocations, of the Southern Company system's pension plans at December 31, 2021 and 2020 are presented below.
| 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 | Target Allocation | Actual Allocation | ||||||||||||||||||
| At December 31, 2021: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 53 | % | |||||||||||||||||||
| Domestic equity | $ | 3,095 | $ | 1,326 | $ | — | $ | — | $ | 4,421 | |||||||||||||
| International equity | 2,740 | 1,402 | 3 | — | 4,145 | ||||||||||||||||||
| Fixed income: | 23 | 22 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 1,209 | — | — | 1,209 | ||||||||||||||||||
| Mortgage- and asset-backed securities | — | 10 | — | — | 10 | ||||||||||||||||||
| Corporate bonds | — | 1,752 | — | — | 1,752 | ||||||||||||||||||
| Pooled funds | — | 771 | — | — | 771 | ||||||||||||||||||
| Cash equivalents and other | 405 | 7 | — | — | 412 | ||||||||||||||||||
| Real estate investments | 706 | — | — | 2,038 | 2,744 | 14 | 15 | ||||||||||||||||
| Special situations | — | — | — | 171 | 171 | 3 | 1 | ||||||||||||||||
| Private equity | — | — | — | 1,590 | 1,590 | 9 | 9 | ||||||||||||||||
| Total | $ | 6,946 | $ | 6,477 | $ | 3 | $ | 3,799 | $ | 17,225 | 100 | % | 100 | % | |||||||||
| Alabama Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 53 | % | |||||||||||||||||||
| Domestic equity | $ | 743 | $ | 319 | $ | — | $ | — | $ | 1,062 | |||||||||||||
| International equity | 659 | 337 | 1 | — | 997 | ||||||||||||||||||
| Fixed income: | 23 | 22 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 291 | — | — | 291 | ||||||||||||||||||
| Mortgage- and asset-backed securities | — | 2 | — | — | 2 | ||||||||||||||||||
| Corporate bonds | — | 421 | — | — | 421 | ||||||||||||||||||
| Pooled funds | — | 186 | — | — | 186 | ||||||||||||||||||
| Cash equivalents and other | 97 | 2 | — | — | 99 | ||||||||||||||||||
| Real estate investments | 170 | — | — | 490 | 660 | 14 | 15 | ||||||||||||||||
| Special situations | — | — | — | 41 | 41 | 3 | 1 | ||||||||||||||||
| Private equity | — | — | — | 382 | 382 | 9 | 9 | ||||||||||||||||
| Total | $ | 1,669 | $ | 1,558 | $ | 1 | $ | 913 | $ | 4,141 | 100 | % | 100 | % | |||||||||
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
| 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 | Target Allocation | Actual Allocation | ||||||||||||||||||
| At December 31, 2021: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 53 | % | |||||||||||||||||||
| Domestic equity | $ | 972 | $ | 417 | $ | — | $ | — | $ | 1,389 | |||||||||||||
| International equity | 861 | 441 | 1 | — | 1,303 | ||||||||||||||||||
| Fixed income: | 23 | 22 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 380 | — | — | 380 | ||||||||||||||||||
| Mortgage- and asset-backed securities | — | 3 | — | — | 3 | ||||||||||||||||||
| Corporate bonds | — | 551 | — | — | 551 | ||||||||||||||||||
| Pooled funds | — | 243 | — | — | 243 | ||||||||||||||||||
| Cash equivalents and other | 127 | 2 | — | — | 129 | ||||||||||||||||||
| Real estate investments | 222 | — | — | 641 | 863 | 14 | 15 | ||||||||||||||||
| Special situations | — | — | — | 54 | 54 | 3 | 1 | ||||||||||||||||
| Private equity | — | — | — | 500 | 500 | 9 | 9 | ||||||||||||||||
| Total | $ | 2,182 | $ | 2,037 | $ | 1 | $ | 1,195 | $ | 5,415 | 100 | % | 100 | % | |||||||||
| Mississippi Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 53 | % | |||||||||||||||||||
| Domestic equity | $ | 142 | $ | 61 | $ | — | $ | — | $ | 203 | |||||||||||||
| International equity | 126 | 64 | — | — | 190 | ||||||||||||||||||
| Fixed income: | 23 | 22 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 55 | — | — | 55 | ||||||||||||||||||
| Corporate bonds | — | 80 | — | — | 80 | ||||||||||||||||||
| Pooled funds | — | 35 | — | — | 35 | ||||||||||||||||||
| Cash equivalents and other | 18 | — | — | — | 18 | ||||||||||||||||||
| Real estate investments | 32 | — | — | 93 | 125 | 14 | 15 | ||||||||||||||||
| Special situations | — | — | — | 8 | 8 | 3 | 1 | ||||||||||||||||
| Private equity | — | — | — | 73 | 73 | 9 | 9 | ||||||||||||||||
| Total | $ | 318 | $ | 295 | $ | — | $ | 174 | $ | 787 | 100 | % | 100 | % | |||||||||
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
| 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 | Target Allocation | Actual Allocation | ||||||||||||||||||
| At December 31, 2021: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 53 | % | |||||||||||||||||||
| Domestic equity | $ | 38 | $ | 16 | $ | — | $ | — | $ | 54 | |||||||||||||
| International equity | 34 | 17 | — | — | 51 | ||||||||||||||||||
| Fixed income: | 23 | 22 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 15 | — | — | 15 | ||||||||||||||||||
| Corporate bonds | — | 22 | — | — | 22 | ||||||||||||||||||
| Pooled funds | — | 10 | — | — | 10 | ||||||||||||||||||
| Cash equivalents and other | 5 | — | — | — | 5 | ||||||||||||||||||
| Real estate investments | 9 | — | — | 25 | 34 | 14 | 15 | ||||||||||||||||
| Special situations | — | — | — | 2 | 2 | 3 | 1 | ||||||||||||||||
| Private equity | — | — | — | 20 | 20 | 9 | 9 | ||||||||||||||||
| Total | $ | 86 | $ | 80 | $ | — | $ | 47 | $ | 213 | 100% | 100 | % | ||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 53 | % | |||||||||||||||||||
| Domestic equity | $ | 223 | $ | 96 | $ | — | $ | — | $ | 319 | |||||||||||||
| International equity | 197 | 101 | — | — | 298 | ||||||||||||||||||
| Fixed income: | 23 | 22 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 87 | — | — | 87 | ||||||||||||||||||
| Mortgage- and asset-backed securities | — | 1 | — | — | 1 | ||||||||||||||||||
| Corporate bonds | — | 126 | — | — | 126 | ||||||||||||||||||
| Pooled funds | — | 56 | — | — | 56 | ||||||||||||||||||
| Cash equivalents and other | 29 | — | — | — | 29 | ||||||||||||||||||
| Real estate investments | 51 | — | — | 147 | 198 | 14 | 15 | ||||||||||||||||
| Special situations | — | — | — | 12 | 12 | 3 | 1 | ||||||||||||||||
| Private equity | — | — | — | 115 | 115 | 9 | 9 | ||||||||||||||||
| Total | $ | 500 | $ | 467 | $ | — | $ | 274 | $ | 1,241 | 100 | % | 100 | % |
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Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
| 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, 2020: | (Level 1) | (Level 2) | (NAV) | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 56 | % | |||||||||||||||||||
| Domestic equity | $ | 2,852 | $ | 1,247 | $ | — | $ | 4,099 | |||||||||||||||
| International equity | 2,660 | 1,497 | — | 4,157 | |||||||||||||||||||
| Fixed income: | 23 | 23 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 951 | — | 951 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 9 | — | 9 | |||||||||||||||||||
| Corporate bonds | — | 1,673 | — | 1,673 | |||||||||||||||||||
| Pooled funds | — | 772 | — | 772 | |||||||||||||||||||
| Cash equivalents and other | 356 | 5 | — | 361 | |||||||||||||||||||
| Real estate investments | 542 | — | 1,596 | 2,138 | 14 | 13 | |||||||||||||||||
| Special situations | — | — | 166 | 166 | 3 | 1 | |||||||||||||||||
| Private equity | — | — | 1,104 | 1,104 | 9 | 7 | |||||||||||||||||
| Total | $ | 6,410 | $ | 6,154 | $ | 2,866 | $ | 15,430 | 100 | % | 100 | % | |||||||||||
| Alabama Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 56 | % | |||||||||||||||||||
| Domestic equity | $ | 685 | $ | 299 | $ | — | $ | 984 | |||||||||||||||
| International equity | 638 | 359 | — | 997 | |||||||||||||||||||
| Fixed income: | 23 | 23 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 228 | — | 228 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 2 | — | 2 | |||||||||||||||||||
| Corporate bonds | — | 401 | — | 401 | |||||||||||||||||||
| Pooled funds | — | 185 | — | 185 | |||||||||||||||||||
| Cash equivalents and other | 85 | 1 | — | 86 | |||||||||||||||||||
| Real estate investments | 130 | — | 382 | 512 | 14 | 13 | |||||||||||||||||
| Special situations | — | — | 40 | 40 | 3 | 1 | |||||||||||||||||
| Private equity | — | — | 264 | 264 | 9 | 7 | |||||||||||||||||
| Total | $ | 1,538 | $ | 1,475 | $ | 686 | $ | 3,699 | 100 | % | 100 | % | |||||||||||
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Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
| 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, 2020: | (Level 1) | (Level 2) | (NAV) | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 56 | % | |||||||||||||||||||
| Domestic equity | $ | 899 | $ | 393 | $ | — | $ | 1,292 | |||||||||||||||
| International equity | 839 | 472 | — | 1,311 | |||||||||||||||||||
| Fixed income: | 23 | 23 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 300 | — | 300 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 3 | — | 3 | |||||||||||||||||||
| Corporate bonds | — | 527 | — | 527 | |||||||||||||||||||
| Pooled funds | — | 243 | — | 243 | |||||||||||||||||||
| Cash equivalents and other | 112 | 1 | — | 113 | |||||||||||||||||||
| Real estate investments | 171 | — | 503 | 674 | 14 | 13 | |||||||||||||||||
| Special situations | — | — | 53 | 53 | 3 | 1 | |||||||||||||||||
| Private equity | — | — | 348 | 348 | 9 | 7 | |||||||||||||||||
| Total | $ | 2,021 | $ | 1,939 | $ | 904 | $ | 4,864 | 100 | % | 100 | % | |||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 56 | % | |||||||||||||||||||
| Domestic equity | $ | 131 | $ | 57 | $ | — | $ | 188 | |||||||||||||||
| International equity | 122 | 68 | — | 190 | |||||||||||||||||||
| Fixed income: | 23 | 23 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 43 | — | 43 | |||||||||||||||||||
| Corporate bonds | — | 76 | — | 76 | |||||||||||||||||||
| Pooled funds | — | 35 | — | 35 | |||||||||||||||||||
| Cash equivalents and other | 16 | — | — | 16 | |||||||||||||||||||
| Real estate investments | 25 | — | 73 | 98 | 14 | 13 | |||||||||||||||||
| Special situations | — | — | 8 | 8 | 3 | 1 | |||||||||||||||||
| Private equity | — | — | 50 | 50 | 9 | 7 | |||||||||||||||||
| Total | $ | 294 | $ | 279 | $ | 131 | $ | 704 | 100 | % | 100 | % | |||||||||||
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Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
| 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, 2020: | (Level 1) | (Level 2) | (NAV) | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 56 | % | |||||||||||||||||||
| Domestic equity | $ | 35 | $ | 15 | $ | — | $ | 50 | |||||||||||||||
| International equity | 32 | 19 | — | 51 | |||||||||||||||||||
| Fixed income: | 23 | 23 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 12 | — | 12 | |||||||||||||||||||
| Corporate bonds | — | 20 | — | 20 | |||||||||||||||||||
| Pooled funds | — | 9 | — | 9 | |||||||||||||||||||
| Cash equivalents and other | 4 | — | — | 4 | |||||||||||||||||||
| Real estate investments | 7 | — | 19 | 26 | 14 | 13 | |||||||||||||||||
| Special situations | — | — | 2 | 2 | 3 | 1 | |||||||||||||||||
| Private equity | — | — | 13 | 13 | 9 | 7 | |||||||||||||||||
| Total | $ | 78 | $ | 75 | $ | 34 | $ | 187 | 100 | % | 100 | % | |||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 51 | % | 56 | % | |||||||||||||||||||
| Domestic equity | $ | 209 | $ | 91 | $ | — | $ | 300 | |||||||||||||||
| International equity | 195 | 109 | — | 304 | |||||||||||||||||||
| Fixed income: | 23 | 23 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 69 | — | 69 | |||||||||||||||||||
| Mortgage- and asset-backed securities | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 122 | — | 122 | |||||||||||||||||||
| Pooled funds | — | 56 | — | 56 | |||||||||||||||||||
| Cash equivalents and other | 26 | — | — | 26 | |||||||||||||||||||
| Real estate investments | 40 | — | 117 | 157 | 14 | 13 | |||||||||||||||||
| Special situations | — | — | 12 | 12 | 3 | 1 | |||||||||||||||||
| Private equity | — | — | 81 | 81 | 9 | 7 | |||||||||||||||||
| Total | $ | 470 | $ | 448 | $ | 210 | $ | 1,128 | 100 | % | 100 | % |
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Table of Contents Index to Financial Statements
COMBINED NOTES TO FINANCIAL STATEMENTS (continued)
Southern Company and Subsidiary Companies 2021 Annual Report
The fair values, and actual allocations relative to the target allocations, of the applicable Registrants' other postretirement benefit plan assets at December 31, 2021 and 2020 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, 2021: | (Level 1) | (Level 2) | (NAV) | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 64 | % | 66 | % | |||||||||||||||||||
| Domestic equity | $ | 123 | $ | 112 | $ | — | $ | 235 | |||||||||||||||
| International equity | 73 | 99 | — | 172 | |||||||||||||||||||
| Fixed income: | 27 | 25 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 37 | — | 37 | |||||||||||||||||||
| Corporate bonds | — | 50 | — | 50 | |||||||||||||||||||
| Pooled funds | — | 90 | — | 90 | |||||||||||||||||||
| Cash equivalents and other | 14 | — | — | 14 | |||||||||||||||||||
| Trust-owned life insurance | — | 530 | — | 530 | |||||||||||||||||||
| Real estate investments | 20 | — | 54 | 74 | 5 | 6 | |||||||||||||||||
| Special situations | — | — | 5 | 5 | 1 | — | |||||||||||||||||
| Private equity | — | — | 42 | 42 | 3 | 3 | |||||||||||||||||
| Total | $ | 230 | $ | 918 | $ | 101 | $ | 1,249 | 100 | % | 100 | % | |||||||||||
| Alabama Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 71 | % | 69 | % | |||||||||||||||||||
| Domestic equity | $ | 26 | $ | 11 | $ | — | $ | 37 | |||||||||||||||
| International equity | 23 | 12 | — | 35 | |||||||||||||||||||
| Fixed income: | 21 | 21 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 10 | — | 10 | |||||||||||||||||||
| Corporate bonds | — | 18 | — | 18 | |||||||||||||||||||
| Pooled funds | — | 6 | — | 6 | |||||||||||||||||||
| Cash equivalents and other | 3 | — | — | 3 | |||||||||||||||||||
| Trust-owned life insurance | — | 341 | — | 341 | |||||||||||||||||||
| Real estate investments | 6 | — | 17 | 23 | 4 | 7 | |||||||||||||||||
| Special situations | — | — | 2 | 2 | 1 | — | |||||||||||||||||
| Private equity | — | — | 13 | 13 | 3 | 3 | |||||||||||||||||
| Total | $ | 58 | $ | 398 | $ | 32 | $ | 488 | 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 | Total | Target Allocation | Actual Allocation | ||||||||||||||||||
| At December 31, 2021: | (Level 1) | (Level 2) | (NAV) | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 60 | % | 62 | % | |||||||||||||||||||
| Domestic equity | $ | 65 | $ | 13 | $ | — | $ | 78 | |||||||||||||||
| International equity | 22 | 50 | — | 72 | |||||||||||||||||||
| Fixed income: | 33 | 30 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 9 | — | 9 | |||||||||||||||||||
| Corporate bonds | — | 14 | — | 14 | |||||||||||||||||||
| Pooled funds | — | 46 | — | 46 | |||||||||||||||||||
| Cash equivalents and other | 5 | — | — | 5 | |||||||||||||||||||
| Trust-owned life insurance | — | 189 | — | 189 | |||||||||||||||||||
| Real estate investments | 7 | — | 16 | 23 | 4 | 5 | |||||||||||||||||
| Special situations | — | — | 1 | 1 | 1 | — | |||||||||||||||||
| Private equity | — | — | 13 | 13 | 2 | 3 | |||||||||||||||||
| Total | $ | 99 | $ | 321 | $ | 30 | $ | 450 | 100 | % | 100 | % | |||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 43 | % | 44 | % | |||||||||||||||||||
| Domestic equity | $ | 4 | $ | 2 | $ | — | $ | 6 | |||||||||||||||
| International equity | 4 | 2 | — | 6 | |||||||||||||||||||
| Fixed income: | 36 | 34 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 5 | — | 5 | |||||||||||||||||||
| Corporate bonds | — | 2 | — | 2 | |||||||||||||||||||
| Pooled funds | — | 1 | — | 1 | |||||||||||||||||||
| Cash equivalents and other | 1 | — | — | 1 | |||||||||||||||||||
| Real estate investments | 1 | — | 3 | 4 | 11 | 13 | |||||||||||||||||
| Special situations | — | — | — | — | 2 | 1 | |||||||||||||||||
| Private equity | — | — | 2 | 2 | 8 | 8 | |||||||||||||||||
| Total | $ | 10 | $ | 12 | $ | 5 | $ | 27 | 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 | Total | Target Allocation | Actual Allocation | ||||||||||||||||||
| At December 31, 2021: | (Level 1) | (Level 2) | (NAV) | ||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 72 | % | 73 | % | |||||||||||||||||||
| Domestic equity | $ | 3 | $ | 76 | $ | — | $ | 79 | |||||||||||||||
| International equity | 2 | 24 | — | 26 | |||||||||||||||||||
| Fixed income: | 26 | 24 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 1 | — | 1 | |||||||||||||||||||
| Pooled funds | — | 30 | — | 30 | |||||||||||||||||||
| Cash equivalents and other | 2 | — | — | 2 | |||||||||||||||||||
| Real estate investments | 1 | — | 2 | 3 | 1 | 2 | |||||||||||||||||
| Private equity | — | — | 1 | 1 | 1 | 1 | |||||||||||||||||
| Total | $ | 8 | $ | 132 | $ | 3 | $ | 143 | 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, 2020: | (Level 1) | (Level 2) | (NAV) | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 63 | % | 66 | % | |||||||||||||||||||
| Domestic equity | $ | 113 | $ | 98 | $ | — | $ | 211 | |||||||||||||||
| International equity | 71 | 102 | — | 173 | |||||||||||||||||||
| Fixed income: | 28 | 27 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 32 | — | 32 | |||||||||||||||||||
| Corporate bonds | — | 44 | — | 44 | |||||||||||||||||||
| Pooled funds | — | 86 | — | 86 | |||||||||||||||||||
| Cash equivalents and other | 15 | — | — | 15 | |||||||||||||||||||
| Trust-owned life insurance | — | 508 | — | 508 | |||||||||||||||||||
| Real estate investments | 15 | — | 42 | 57 | 5 | 5 | |||||||||||||||||
| Special situations | — | — | 4 | 4 | 1 | — | |||||||||||||||||
| Private equity | — | — | 29 | 29 | 3 | 2 | |||||||||||||||||
| Total | $ | 214 | $ | 870 | $ | 75 | $ | 1,159 | 100 | % | 100 | % | |||||||||||
| Alabama Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 68 | % | 69 | % | |||||||||||||||||||
| Domestic equity | $ | 26 | $ | 11 | $ | — | $ | 37 | |||||||||||||||
| International equity | 23 | 13 | — | 36 | |||||||||||||||||||
| Fixed income: | 24 | 25 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 11 | — | 11 | |||||||||||||||||||
| Corporate bonds | — | 14 | — | 14 | |||||||||||||||||||
| Pooled funds | — | 7 | — | 7 | |||||||||||||||||||
| Cash equivalents and other | 5 | — | — | 5 | |||||||||||||||||||
| Trust-owned life insurance | — | 321 | — | 321 | |||||||||||||||||||
| Real estate investments | 5 | — | 13 | 18 | 4 | 4 | |||||||||||||||||
| Special situations | — | — | 1 | 1 | 1 | — | |||||||||||||||||
| Private equity | — | — | 9 | 9 | 3 | 2 | |||||||||||||||||
| Total | $ | 59 | $ | 377 | $ | 23 | $ | 459 | 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, 2020: | (Level 1) | (Level 2) | (NAV) | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 60 | % | 64 | % | |||||||||||||||||||
| Domestic equity | $ | 58 | $ | 10 | $ | — | $ | 68 | |||||||||||||||
| International equity | 21 | 50 | — | 71 | |||||||||||||||||||
| Fixed income: | 33 | 30 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 8 | — | 8 | |||||||||||||||||||
| Corporate bonds | — | 13 | — | 13 | |||||||||||||||||||
| Pooled funds | — | 46 | — | 46 | |||||||||||||||||||
| Cash equivalents and other | 5 | — | — | 5 | |||||||||||||||||||
| Trust-owned life insurance | — | 188 | — | 188 | |||||||||||||||||||
| Real estate investments | 5 | — | 13 | 18 | 4 | 4 | |||||||||||||||||
| Special situations | — | — | 1 | 1 | 1 | — | |||||||||||||||||
| Private equity | — | — | 9 | 9 | 2 | 2 | |||||||||||||||||
| Total | $ | 89 | $ | 315 | $ | 23 | $ | 427 | 100 | % | 100 | % | |||||||||||
| Mississippi Power | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 43 | % | 46 | % | |||||||||||||||||||
| Domestic equity | $ | 4 | $ | 2 | $ | — | $ | 6 | |||||||||||||||
| International equity | 4 | 2 | — | 6 | |||||||||||||||||||
| Fixed income: | 37 | 36 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 5 | — | 5 | |||||||||||||||||||
| Corporate bonds | — | 2 | — | 2 | |||||||||||||||||||
| Pooled funds | — | 1 | — | 1 | |||||||||||||||||||
| Cash equivalents and other | 1 | — | — | 1 | |||||||||||||||||||
| Real estate investments | 1 | — | 2 | 3 | 11 | 11 | |||||||||||||||||
| Special situations | — | — | — | — | 2 | 1 | |||||||||||||||||
| Private equity | — | — | 2 | 2 | 7 | 6 | |||||||||||||||||
| Total | $ | 10 | $ | 12 | $ | 4 | $ | 26 | 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, 2020: | (Level 1) | (Level 2) | (NAV) | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
| Equity: | 72 | % | 76 | % | |||||||||||||||||||
| Domestic equity | $ | 2 | $ | 66 | $ | — | $ | 68 | |||||||||||||||
| International equity | 2 | 25 | — | 27 | |||||||||||||||||||
| Fixed income: | 26 | 22 | |||||||||||||||||||||
| U.S. Treasury, government, and agency bonds | — | 1 | — | 1 | |||||||||||||||||||
| Corporate bonds | — | 1 | — | 1 | |||||||||||||||||||
| Pooled funds | — | 25 | — | 25 | |||||||||||||||||||
| Cash equivalents and other | 1 | — | — | 1 | |||||||||||||||||||
| Real estate investments | — | — | 1 | 1 | 1 | 1 | |||||||||||||||||
| Private equity | — | — | 1 | 1 | 1 | 1 | |||||||||||||||||
| Total | $ | 5 | $ | 118 | $ | 2 | $ | 125 | 100 | % | 100 | % |
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 2021, 2020, and 2019 were as follows:
| Southern Company | Alabama Power | Georgia Power | Mississippi Power | Southern Power | Southern Company Gas | |||||||||||||||
| (in millions) | ||||||||||||||||||||
| 2021 | $ | 119 | $ | 26 | $ | 28 | $ | 5 | $ | 2 | $ | 16 | ||||||||
| 2020 | 120 | 26 | 29 | 5 | 2 | 16 | ||||||||||||||
| 2019 | 113 | 25 | 27 | 4 | 2 | 15 |
12. STOCK COMPENSATION
Stock-based compensation primarily 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 Southern Company system employees ranging from line management to executives.
At December 31, 2021, 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 | 1,728 | 241 | 271 | 70 | 45 | 173 |
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
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immediately, while compensation expense for employees that 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.
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 three 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; ROE awards based on Southern Company's equity-weighted return over the performance period; and EPS awards based on Southern Company's cumulative EPS over the performance period. EPS awards were last granted in 2017.
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 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 | 2021 | 2020 | 2019 | ||||||||||||||
| Expected volatility | 30.0% | 15.4% | 15.6% | ||||||||||||||
| Expected term (in years) | 3 | 3 | 3 | ||||||||||||||
| Interest rate | 0.2% | 1.4% | 2.4% | ||||||||||||||
| Weighted average grant-date fair value | $69.06 | $77.65 | $62.71 |
The Registrants recognize TSR award compensation expense on a straight-line basis over the three-year performance period without remeasurement.
The fair values of EPS awards and 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 2021, 2020, and 2019 was $59.49, $68.42, and $49.38, respectively. Compensation expense for EPS and ROE awards is generally recognized ratably over the three-year performance period adjusted for expected changes in EPS and ROE performance. Total compensation cost recognized for vested EPS awards and ROE awards reflects final performance metrics.
Southern Company had 2.2 million unvested PSUs outstanding at December 31, 2020. In February 2021, the PSUs that vested for the three-year performance period ended December 31, 2020 were converted into 2.5 million shares outstanding at a share price of $60.10. During 2021, Southern Company granted 1.3 million PSUs and 1.3 million PSUs were vested or forfeited, resulting in 2.2 million unvested PSUs outstanding at December 31, 2021. In February 2022, the PSUs that vested for the three-year performance period ended December 31, 2021 were converted into 2.5 million shares outstanding at a weighted average share price of $66.57.
Total PSU compensation cost, and the related tax benefit recognized in income, for the years ended December 31, 2021, 2020, and 2019 are as follows:
| 2021 | 2020 | 2019 | |||||||||||||||
| (in millions) | |||||||||||||||||
| Southern Company | |||||||||||||||||
| Compensation cost recognized in income | $ | 112 | $ | 84 | $ | 77 | |||||||||||
| Tax benefit of compensation cost recognized in income | 29 | 22 | 20 | ||||||||||||||
| Southern Company Gas | |||||||||||||||||
| Compensation cost recognized in income | $ | 17 | $ | 13 | $ | 14 | |||||||||||
| Tax benefit of compensation cost recognized in income | 4 | 4 | 4 |
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Total PSU compensation cost and the related tax benefit recognized in income were immaterial for all periods presented for all other Registrants. 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, 2021, 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 19 months. The total unrecognized compensation cost related to PSUs at December 31, 2021 was immaterial for all other Registrants.
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 2021, 2020, and 2019 were $59.56, $67.60, and $50.44, 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 1.2 million RSUs outstanding at December 31, 2020. During 2021, Southern Company granted 0.5 million RSUs and 0.6 million RSUs were vested or forfeited, resulting in 1.1 million unvested RSUs outstanding at December 31, 2021, including RSUs related to employee retention agreements.
For the years ended December 31, 2021, 2020, and 2019, Southern Company's total compensation cost for RSUs recognized in income was $32 million, $29 million, and $28 million, respectively. The related tax benefit also recognized in income was $8 million, $8 million, and $7 million for the years ended December 31, 2021, 2020, and 2019, respectively. Total unrecognized compensation cost related to RSUs at December 31, 2021, which is being recognized over a weighted-average period of approximately 16 months, is immaterial for Southern Company.
Total RSUs outstanding and total compensation cost and related tax benefit for the RSUs recognized in income for the years ended December 31, 2021, 2020, and 2019, as well as the total unrecognized compensation cost at December 31, 2021, were immaterial for all other Registrants. 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.
Stock Options
In 2015, Southern Company discontinued granting stock options. As of December 31, 2017, all stock option awards were vested and compensation cost fully recognized. Stock options expire no later than 10 years after the grant date and the latest possible exercise will occur by November 2024. At December 31, 2021, the weighted average remaining contractual term for the options outstanding and exercisable was approximately 19 months.
Southern Company's activity in the stock option program for 2021 is summarized below:
| Shares Subject to Option | Weighted Average Exercise Price | ||||||||||
| (in millions) | |||||||||||
| Outstanding at December 31, 2020 | 4.3 | $ | 43.04 | ||||||||
| Exercised | 1.5 | 43.21 | |||||||||
| Outstanding and Exercisable at December 31, 2021 | 2.8 | $ | 42.95 |
Southern Company's cash receipts from issuances related to stock options exercised under the share-based payment arrangements for the years ended December 31, 2021, 2020, and 2019 were $66 million, $66 million, and $482 million, respectively.
At December 31, 2021, the aggregate intrinsic value for the options outstanding and exercisable was as follows:
| Southern Company | Georgia Power | Southern Company Gas | |||||||||||||||
| (in millions) | |||||||||||||||||
| Total intrinsic value for outstanding and exercisable options | $ | 71 | $ | 17 | $ | 8 |
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The aggregate intrinsic value for the options outstanding and exercisable was immaterial for Alabama Power, Mississippi Power, and Southern Power at December 31, 2021.
Total intrinsic value of options exercised, and the related tax benefit, for the years ended December 31, 2021, 2020, and 2019 are presented below:
| Year Ended December 31 | 2021 | 2020 | 2019 | ||||||||||||||
| (in millions) | |||||||||||||||||
| Southern Company | |||||||||||||||||
| Intrinsic value of options exercised | $ | 34 | $ | 38 | $ | 167 | |||||||||||
| Tax benefit of options exercised | 7 | 9 | 35 | ||||||||||||||
| Alabama Power | |||||||||||||||||
| Intrinsic value of options exercised | $ | 3 | $ | 5 | $ | 21 | |||||||||||
| Tax benefit of options exercised | 1 | 1 | 4 | ||||||||||||||
| Georgia Power | |||||||||||||||||
| Intrinsic value of options exercised | $ | 14 | $ | 9 | $ | 30 | |||||||||||
| Tax benefit of options exercised | 3 | 2 | 6 | ||||||||||||||
Total intrinsic value of options exercised, and the related tax benefit recognized in income, for the years ended December 31, 2021, 2020, and 2019 were immaterial for Mississippi Power, Southern Power, and Southern Company Gas.
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, 2021, 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, 2021: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 24 | $ | 195 | $ | — | $ | — | $ | 219 | |||||||||||||||||||
| Interest rate derivatives | — | 19 | — | — | 19 | ||||||||||||||||||||||||
| Investments in trusts:(b)(c) | |||||||||||||||||||||||||||||
| Domestic equity | 791 | 225 | — | — | 1,016 | ||||||||||||||||||||||||
| Foreign equity | 165 | 188 | — | — | 353 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 314 | — | — | 314 | ||||||||||||||||||||||||
| Municipal bonds | — | 56 | — | — | 56 | ||||||||||||||||||||||||
| Pooled funds – fixed income | — | 13 | — | — | 13 | ||||||||||||||||||||||||
| Corporate bonds | 1 | 522 | — | — | 523 | ||||||||||||||||||||||||
| Mortgage and asset backed securities | — | 93 | — | — | 93 | ||||||||||||||||||||||||
| Private equity | — | — | — | 150 | 150 | ||||||||||||||||||||||||
| Cash and cash equivalents | 2 | — | — | — | 2 | ||||||||||||||||||||||||
| Other | 22 | 25 | — | — | 47 | ||||||||||||||||||||||||
| Cash equivalents | 1,160 | 14 | — | — | 1,174 | ||||||||||||||||||||||||
| Other investments | 9 | 35 | — | — | 44 | ||||||||||||||||||||||||
| Total | $ | 2,174 | $ | 1,699 | $ | — | $ | 150 | $ | 4,023 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 10 | $ | 36 | $ | — | $ | — | $ | 46 | |||||||||||||||||||
| Interest rate derivatives | — | 29 | — | — | 29 | ||||||||||||||||||||||||
| Foreign currency derivatives | — | 79 | — | — | 79 | ||||||||||||||||||||||||
| Contingent consideration | — | — | 14 | — | 14 | ||||||||||||||||||||||||
| Other | — | 13 | — | — | 13 | ||||||||||||||||||||||||
| Total | $ | 10 | $ | 157 | $ | 14 | $ | — | $ | 181 | |||||||||||||||||||
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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, 2021: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 55 | $ | — | $ | — | $ | 55 | |||||||||||||||||||
| Nuclear decommissioning trusts:(b) | |||||||||||||||||||||||||||||
| Domestic equity | 468 | 216 | — | — | 684 | ||||||||||||||||||||||||
| Foreign equity | 165 | — | — | — | 165 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 21 | — | — | 21 | ||||||||||||||||||||||||
| Municipal bonds | — | 1 | — | — | 1 | ||||||||||||||||||||||||
| Corporate bonds | 1 | 271 | — | — | 272 | ||||||||||||||||||||||||
| Mortgage and asset backed securities | — | 22 | — | — | 22 | ||||||||||||||||||||||||
| Private equity | — | — | — | 150 | 150 | ||||||||||||||||||||||||
| Other | 9 | — | — | — | 9 | ||||||||||||||||||||||||
| Cash equivalents | 839 | 14 | — | — | 853 | ||||||||||||||||||||||||
| Other investments | — | 35 | — | — | 35 | ||||||||||||||||||||||||
| Total | $ | 1,482 | $ | 635 | $ | — | $ | 150 | $ | 2,267 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 11 | $ | — | $ | — | $ | 11 | |||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 75 | $ | — | $ | — | $ | 75 | |||||||||||||||||||
| Nuclear decommissioning trusts:(b)(c) | |||||||||||||||||||||||||||||
| Domestic equity | 323 | 1 | — | — | 324 | ||||||||||||||||||||||||
| Foreign equity | — | 185 | — | — | 185 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 293 | — | — | 293 | ||||||||||||||||||||||||
| Municipal bonds | — | 55 | — | — | 55 | ||||||||||||||||||||||||
| Corporate bonds | — | 251 | — | — | 251 | ||||||||||||||||||||||||
| Mortgage and asset backed securities | — | 71 | — | — | 71 | ||||||||||||||||||||||||
| Other | 13 | 25 | — | — | 38 | ||||||||||||||||||||||||
| Total | $ | 336 | $ | 956 | $ | — | $ | — | $ | 1,292 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 8 | $ | — | $ | — | $ | 8 | |||||||||||||||||||
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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, 2021: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 56 | $ | — | $ | — | $ | 56 | |||||||||||||||||||
| Cash equivalents | 40 | — | — | — | 40 | ||||||||||||||||||||||||
| Total | $ | 40 | $ | 56 | $ | — | $ | — | $ | 96 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 5 | $ | — | $ | — | $ | 5 | |||||||||||||||||||
| Southern Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 4 | $ | — | $ | — | $ | 4 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Foreign currency derivatives | $ | — | $ | 16 | $ | — | $ | — | $ | 16 | |||||||||||||||||||
| Contingent consideration | — | — | 14 | — | 14 | ||||||||||||||||||||||||
| Other | — | 13 | — | — | 13 | ||||||||||||||||||||||||
| Total | $ | — | $ | 29 | $ | 14 | $ | — | $ | 43 | |||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 24 | $ | 5 | $ | — | $ | — | $ | 29 | |||||||||||||||||||
| Interest rate derivatives | — | 6 | — | — | 6 | ||||||||||||||||||||||||
| Non-qualified deferred compensation trusts: | |||||||||||||||||||||||||||||
| Domestic equity | — | 8 | — | — | 8 | ||||||||||||||||||||||||
| Foreign equity | — | 3 | — | — | 3 | ||||||||||||||||||||||||
| Pooled funds - fixed income | — | 13 | — | — | 13 | ||||||||||||||||||||||||
| Cash equivalents | 2 | — | — | — | 2 | ||||||||||||||||||||||||
| Total | $ | 26 | $ | 35 | $ | — | $ | — | $ | 61 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a)(b) | $ | 10 | $ | 12 | $ | — | $ | — | $ | 22 | |||||||||||||||||||
| Interest rate derivatives | — | 5 | — | — | 5 | ||||||||||||||||||||||||
| Total | $ | 10 | $ | 17 | $ | — | $ | — | $ | 27 |
(a)Excludes immaterial cash collateral.
(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.
(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. See Note 6 under "Nuclear Decommissioning" for additional information.
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At December 31, 2020, 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, 2020: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Southern Company | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 401 | $ | 271 | $ | 32 | $ | — | $ | 704 | |||||||||||||||||||
| Interest rate derivatives | — | 20 | — | — | 20 | ||||||||||||||||||||||||
| Foreign currency derivatives | — | 87 | — | — | 87 | ||||||||||||||||||||||||
| Investments in trusts:(b)(c) | |||||||||||||||||||||||||||||
| Domestic equity | 862 | 151 | — | — | 1,013 | ||||||||||||||||||||||||
| Foreign equity | 85 | 253 | — | — | 338 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 284 | — | — | 284 | ||||||||||||||||||||||||
| Municipal bonds | — | 85 | — | — | 85 | ||||||||||||||||||||||||
| Pooled funds – fixed income | — | 17 | — | — | 17 | ||||||||||||||||||||||||
| Corporate bonds | 13 | 386 | — | — | 399 | ||||||||||||||||||||||||
| Mortgage and asset backed securities | — | 83 | — | — | 83 | ||||||||||||||||||||||||
| Private equity | — | — | — | 76 | 76 | ||||||||||||||||||||||||
| Cash and cash equivalents | 1 | — | — | — | 1 | ||||||||||||||||||||||||
| Other | 28 | 7 | — | — | 35 | ||||||||||||||||||||||||
| Cash equivalents | 575 | 9 | — | — | 584 | ||||||||||||||||||||||||
| Other investments | 9 | 24 | — | — | 33 | ||||||||||||||||||||||||
| Total | $ | 1,974 | $ | 1,677 | $ | 32 | $ | 76 | $ | 3,759 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 389 | $ | 204 | $ | 4 | $ | — | $ | 597 | |||||||||||||||||||
| Foreign currency derivatives | — | 23 | — | — | 23 | ||||||||||||||||||||||||
| Contingent consideration | — | — | 17 | — | 17 | ||||||||||||||||||||||||
| Total | $ | 389 | $ | 227 | $ | 21 | $ | — | $ | 637 | |||||||||||||||||||
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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, 2020: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Alabama Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 12 | $ | — | $ | — | $ | 12 | |||||||||||||||||||
| Nuclear decommissioning trusts:(b) | |||||||||||||||||||||||||||||
| Domestic equity | 543 | 141 | — | — | 684 | ||||||||||||||||||||||||
| Foreign equity | 85 | 73 | — | — | 158 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 21 | — | — | 21 | ||||||||||||||||||||||||
| Municipal bonds | — | 1 | — | — | 1 | ||||||||||||||||||||||||
| Corporate bonds | 13 | 167 | — | — | 180 | ||||||||||||||||||||||||
| Mortgage and asset backed securities | — | 29 | — | — | 29 | ||||||||||||||||||||||||
| Private equity | — | — | — | 76 | 76 | ||||||||||||||||||||||||
| Other | 7 | — | — | — | 7 | ||||||||||||||||||||||||
| Cash equivalents | 311 | 9 | — | — | 320 | ||||||||||||||||||||||||
| Other investments | — | 24 | — | — | 24 | ||||||||||||||||||||||||
| Total | $ | 959 | $ | 477 | $ | — | $ | 76 | $ | 1,512 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 7 | $ | — | $ | — | $ | 7 | |||||||||||||||||||
| Georgia Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 15 | $ | — | $ | — | $ | 15 | |||||||||||||||||||
| Nuclear decommissioning trusts:(b)(c) | |||||||||||||||||||||||||||||
| Domestic equity | 319 | 1 | — | — | 320 | ||||||||||||||||||||||||
| Foreign equity | — | 177 | — | — | 177 | ||||||||||||||||||||||||
| U.S. Treasury and government agency securities | — | 263 | — | — | 263 | ||||||||||||||||||||||||
| Municipal bonds | — | 84 | — | — | 84 | ||||||||||||||||||||||||
| Corporate bonds | — | 219 | — | — | 219 | ||||||||||||||||||||||||
| Mortgage and asset backed securities | — | 54 | — | — | 54 | ||||||||||||||||||||||||
| Other | 21 | 7 | — | — | 28 | ||||||||||||||||||||||||
| Total | $ | 340 | $ | 820 | $ | — | $ | — | $ | 1,160 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 13 | $ | — | $ | — | $ | 13 | |||||||||||||||||||
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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, 2020: | (Level 1) | (Level 2) | (Level 3) | (NAV) | Total | ||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||
| Mississippi Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 9 | $ | — | $ | — | $ | 9 | |||||||||||||||||||
| Cash equivalents | 21 | — | — | — | 21 | ||||||||||||||||||||||||
| Total | $ | 21 | $ | 9 | $ | — | $ | — | $ | 30 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 9 | $ | — | $ | — | $ | 9 | |||||||||||||||||||
| Southern Power | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 2 | $ | — | $ | — | $ | 2 | |||||||||||||||||||
| Foreign currency derivatives | — | 87 | — | — | 87 | ||||||||||||||||||||||||
| Total | $ | — | $ | 89 | $ | — | $ | — | $ | 89 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives | $ | — | $ | 3 | $ | — | $ | — | $ | 3 | |||||||||||||||||||
| Foreign currency derivatives | — | 23 | — | — | 23 | ||||||||||||||||||||||||
| Contingent consideration | — | — | 17 | — | 17 | ||||||||||||||||||||||||
| Total | $ | — | $ | 26 | $ | 17 | $ | — | $ | 43 | |||||||||||||||||||
| Southern Company Gas | |||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a) | $ | 401 | $ | 233 | $ | 32 | $ | — | $ | 666 | |||||||||||||||||||
| Non-qualified deferred compensation trusts: | |||||||||||||||||||||||||||||
| Domestic equity | — | 9 | — | — | 9 | ||||||||||||||||||||||||
| Foreign equity | — | 3 | — | — | 3 | ||||||||||||||||||||||||
| Pooled funds - fixed income | — | 17 | — | — | 17 | ||||||||||||||||||||||||
| Cash equivalents | 1 | — | — | — | 1 | ||||||||||||||||||||||||
| Total | $ | 402 | $ | 262 | $ | 32 | $ | — | $ | 696 | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||
| Energy-related derivatives(a)(b) | $ | 389 | $ | 172 | $ | 4 | $ | — | $ | 565 |
(a)Excludes $6 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value and cash collateral of $28 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.
(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. See Note 6 under "Nuclear Decommissioning" for additional information.
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Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and over-the-counter 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 over-the-counter 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, 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 Power has contingent payment obligations related to certain acquisitions whereby it is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation of the respective facility and continue through 2026. The obligations are categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility 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 contingent consideration 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" include 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 equity 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 $150 million and $76 million at December 31, 2021 and 2020, respectively. Unfunded commitments related to the private equity investments totaled $69 million and $73 million at December 31, 2021 and 2020, respectively. Private equity investments include high-quality private equity funds across several market sectors and funds that invest in real estate assets. Private equity 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, 2021 and 2020, 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, 2021: | ||||||||||||||||||||
| Long-term debt, including securities due within one year: | ||||||||||||||||||||
| Carrying amount | $ | 52.1 | $ | 9.7 | $ | 13.6 | $ | 1.5 | $ | 3.7 | $ | 6.9 | ||||||||
| Fair value | 57.1 | 10.9 | 15.1 | 1.6 | 4.1 | 7.8 | ||||||||||||||
| At December 31, 2020: | ||||||||||||||||||||
| Long-term debt, including securities due within one year: | ||||||||||||||||||||
| Carrying amount | $ | 48.3 | $ | 8.9 | $ | 12.8 | $ | 1.4 | $ | 3.7 | $ | 6.6 | ||||||||
| Fair value | 56.3 | 10.7 | 15.2 | 1.6 | 4.2 | 8.0 |
(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at 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.
Commodity Contracts with Level 3 Valuation Inputs
Prior to July 1, 2021, Southern Company Gas had Level 3 physical natural gas forward contracts related to Sequent. See Note 15 under "Southern Company Gas" for information regarding the sale of Sequent. The following table provides a reconciliation of Southern Company Gas' Level 3 contracts during 2021.
| 2021 | |||||
| (in millions) | |||||
| Beginning balance | $ | 28 | |||
| Instruments realized or otherwise settled during period | (6) | ||||
| Changes in fair value | (4) | ||||
| Sale of Sequent | (18) | ||||
| Ending balance | $ | — |
Changes in fair value of Level 3 instruments represent changes in gains and losses reported on Southern Company Gas' statements of income in natural gas revenues prior to the sale of Sequent.
14. DERIVATIVES
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas operations used various contracts in its commercial activities that generally met the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, 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
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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. See Note 15 under "Southern Company Gas" for additional information regarding the sale of Sequent.
Energy-Related Derivatives
The traditional electric operating companies, Southern Power, and Southern Company Gas 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 of Southern Company Gas 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 operating 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 operating revenues.
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.
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At December 31, 2021, 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(*) | 311 | 2030 | 2025 | ||||||||||||||
| Alabama Power | 74 | 2024 | — | ||||||||||||||
| Georgia Power | 89 | 2024 | — | ||||||||||||||
| Mississippi Power | 75 | 2025 | — | ||||||||||||||
| Southern Power | 5 | 2030 | 2022 | ||||||||||||||
| Southern Company Gas(*) | 68 | 2024 | 2025 |
(*)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 74 million mmBtu and short natural gas positions of 6 million mmBtu at December 31, 2021, which is also included in Southern Company's total volume. See Note 15 under "Southern Company Gas" for information regarding the sale of Sequent.
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 26 million mmBtu for Southern Company, which includes 6 million mmBtu for Alabama Power, 8 million mmBtu for Georgia Power, 4 million mmBtu for Mississippi Power, and 8 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, 2022 are immaterial for all Registrants.
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.
At December 31, 2021, the following interest rate derivatives were outstanding:
| Notional Amount | Interest Rate Received | Weighted Average Interest Rate Paid | Hedge Maturity Date | Fair Value Gain (Loss) December 31, 2021 | |||||||||||||||||||||||||
| (in millions) | (in millions) | ||||||||||||||||||||||||||||
| Fair Value Hedges of Existing Debt | |||||||||||||||||||||||||||||
| Southern Company parent | $ | 400 | 1.75% | 1-month LIBOR + 0.68% | March 2028 | $ | (5) | ||||||||||||||||||||||
| Southern Company parent | 1,000 | 3.70% | 1-month LIBOR + 2.36% | April 2030 | (6) | ||||||||||||||||||||||||
| Southern Company Gas | 500 | 1.75% | 1-month LIBOR + 0.38% | January 2031 | 1 | ||||||||||||||||||||||||
| Southern Company | $ | 1,900 | $ | (10) |
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For cash flow hedge interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from AOCI to interest expense for the year ending December 31, 2022 total $(21) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2051 for Southern Company, 2051 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi 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, 2021, the following foreign currency derivatives were outstanding:
| Pay Notional | Pay Rate | Receive Notional | Receive Rate | Hedge Maturity Date | Fair Value Gain (Loss) December 31, 2021 | |||||||||||||||
| (in millions) | (in millions) | (in millions) | ||||||||||||||||||
| Fair Value Hedges of Existing Debt | ||||||||||||||||||||
| Southern Company parent | $ | 1,476 | 3.39% | € | 1,250 | 1.88% | September 2027 | $ | (63) | |||||||||||
| Cash Flow Hedges of Existing Debt | ||||||||||||||||||||
| Southern Power | $ | 677 | 2.95% | € | 600 | 1.00% | June 2022 | $ | (5) | |||||||||||
| Southern Power | 564 | 3.78% | 500 | 1.85% | June 2026 | (10) | ||||||||||||||
| Southern Power total | $ | 1,241 | € | 1,100 | $ | (15) | ||||||||||||||
| Southern Company | $ | 2,717 | € | 2,350 | $ | (78) |
The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives accounted for as cash flow hedges expected to be reclassified from AOCI to earnings for the year ending December 31, 2022 are $(13) million.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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. These agreements may contain provisions that permit netting across product lines and against cash collateral. 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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At December 31, 2021 and 2020, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
| 2021 | 2020 | |||||||||||||
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | ||||||||||
| (in millions) | ||||||||||||||
| Southern Company | ||||||||||||||
| Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Assets from risk management activities/Other current liabilities | $ | 129 | $ | 30 | $ | 24 | $ | 11 | ||||||
| Other deferred charges and assets/Other deferred credits and liabilities | 72 | 6 | 18 | 19 | ||||||||||
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 201 | $ | 36 | $ | 42 | $ | 30 | ||||||
| Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Assets from risk management activities/Other current liabilities | $ | 7 | $ | 5 | $ | 3 | $ | 5 | ||||||
| Other deferred charges and assets/Other deferred credits and liabilities | 1 | — | — | — | ||||||||||
| Interest rate derivatives: | ||||||||||||||
| Assets from risk management activities/Other current liabilities | 19 | — | 20 | — | ||||||||||
| Other deferred charges and assets/Other deferred credits and liabilities | — | 29 | — | — | ||||||||||
| Foreign currency derivatives: | ||||||||||||||
| Assets from risk management activities/Other current liabilities | — | 39 | — | 23 | ||||||||||
| Other deferred charges and assets/Other deferred credits and liabilities | — | 40 | 87 | — | ||||||||||
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 27 | $ | 113 | $ | 110 | $ | 28 | ||||||
| Derivatives not designated as hedging instruments | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Assets from risk management activities/Other current liabilities | $ | 9 | $ | 4 | $ | 388 | $ | 331 | ||||||
| Other deferred charges and assets/Other deferred credits and liabilities | 1 | — | 270 | 232 | ||||||||||
| Total derivatives not designated as hedging instruments | $ | 10 | $ | 4 | $ | 658 | $ | 563 | ||||||
| Gross amounts recognized | $ | 238 | $ | 153 | $ | 810 | $ | 621 | ||||||
| Gross amounts offset**(a)** | $ | (25) | $ | (28) | $ | (529) | $ | (557) | ||||||
| Net amounts recognized in the Balance Sheets**(b)** | $ | 213 | $ | 125 | $ | 281 | $ | 64 | ||||||
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| 2021 | 2020 | |||||||||||||
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | ||||||||||
| (in millions) | ||||||||||||||
| Alabama Power | ||||||||||||||
| Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Other current assets/Other current liabilities | $ | 30 | $ | 9 | $ | 7 | $ | 2 | ||||||
| Other deferred charges and assets/Other deferred credits and liabilities | 25 | 2 | 5 | 5 | ||||||||||
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 55 | $ | 11 | $ | 12 | $ | 7 | ||||||
| Gross amounts offset | $ | (5) | $ | (5) | $ | (7) | $ | (7) | ||||||
| Net amounts recognized in the Balance Sheets | $ | 50 | $ | 6 | $ | 5 | $ | — | ||||||
| Georgia Power | ||||||||||||||
| Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Other current assets/Other current liabilities | $ | 54 | $ | 6 | $ | 7 | $ | 5 | ||||||
| Other deferred charges and assets/Other deferred credits and liabilities | 21 | 2 | 8 | 8 | ||||||||||
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 75 | $ | 8 | $ | 15 | $ | 13 | ||||||
| Gross amounts offset | $ | (8) | $ | (8) | $ | (12) | $ | (12) | ||||||
| Net amounts recognized in the Balance Sheets | $ | 67 | $ | — | $ | 3 | $ | 1 | ||||||
| Mississippi Power | ||||||||||||||
| Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Other current assets/Other current liabilities | $ | 30 | $ | 3 | $ | 4 | $ | 3 | ||||||
| Other deferred charges and assets/Other deferred credits and liabilities | 26 | 2 | 5 | 6 | ||||||||||
| Total derivatives designated as hedging instruments for regulatory purposes | $ | 56 | $ | 5 | $ | 9 | $ | 9 | ||||||
| Gross amounts offset | $ | (4) | $ | (4) | $ | (7) | $ | (7) | ||||||
| Net amounts recognized in the Balance Sheets | $ | 52 | $ | 1 | $ | 2 | $ | 2 | ||||||
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| 2021 | 2020 | |||||||||||||
| Derivative Category and Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | ||||||||||
| (in millions) | ||||||||||||||
| Southern Power | ||||||||||||||
| Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Other current assets/Other current liabilities | $ | 2 | $ | — | $ | 2 | $ | 2 | ||||||
| Other deferred charges and assets/Other deferred credits and liabilities | 1 | — | — | — | ||||||||||
| Foreign currency derivatives: | ||||||||||||||
| Other current assets/Other current liabilities | — | 16 | — | 23 | ||||||||||
| Other deferred charges and assets/Other deferred credits and liabilities | — | — | 87 | — | ||||||||||
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 3 | $ | 16 | $ | 89 | $ | 25 | ||||||
| Derivatives not designated as hedging instruments | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Other current assets/Other current liabilities | $ | 1 | $ | — | $ | — | $ | 1 | ||||||
| Net amounts recognized in the Balance Sheets | $ | 4 | $ | 16 | $ | 89 | $ | 26 | ||||||
| Southern Company Gas | ||||||||||||||
| Derivatives designated as hedging instruments for regulatory purposes | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Assets from risk management activities/Other current liabilities | $ | 15 | $ | 12 | $ | 6 | $ | 1 | ||||||
| Derivatives designated as hedging instruments in cash flow and fair value hedges | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Assets from risk management activities/Other current liabilities | $ | 5 | $ | 5 | $ | 1 | $ | 3 | ||||||
| Interest rate derivatives: | ||||||||||||||
| Assets from risk management activities/Other current liabilities | 6 | — | — | — | ||||||||||
| Other deferred charges and assets/Other deferred credits and liabilities | — | 6 | — | — | ||||||||||
| Total derivatives designated as hedging instruments in cash flow and fair value hedges | $ | 11 | $ | 11 | $ | 1 | $ | 3 | ||||||
| Derivatives not designated as hedging instruments | ||||||||||||||
| Energy-related derivatives: | ||||||||||||||
| Assets from risk management activities/Other current liabilities | $ | 8 | $ | 4 | $ | 388 | $ | 330 | ||||||
| Other deferred charges and assets/Other deferred credits and liabilities | 1 | — | 270 | 232 | ||||||||||
| Total derivatives not designated as hedging instruments | $ | 9 | $ | 4 | $ | 658 | $ | 562 | ||||||
| Gross amounts recognized | $ | 35 | $ | 27 | $ | 665 | $ | 566 | ||||||
| Gross amounts offset**(a)** | $ | (8) | $ | (11) | $ | (503) | $ | (531) | ||||||
| Net amounts recognized in the Balance Sheets (b) | $ | 27 | $ | 16 | $ | 162 | $ | 35 |
(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $3 million and $28 million at December 31, 2021 and 2020, respectively.
(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for all periods presented.
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At December 31, 2021 and 2020, 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, 2021: | |||||||||||||||||
| Energy-related derivatives: | |||||||||||||||||
| Other regulatory assets, current | $ | (17) | $ | (6) | $ | — | $ | — | $ | (11) | |||||||
| Other regulatory liabilities, current | 107 | 28 | 48 | 27 | 4 | ||||||||||||
| Other regulatory liabilities, deferred | 65 | 22 | 19 | 24 | — | ||||||||||||
| Total energy-related derivative gains (losses) | $ | 155 | $ | 44 | $ | 67 | $ | 51 | $ | (7) | |||||||
| At December 31, 2020: | |||||||||||||||||
| Energy-related derivatives: | |||||||||||||||||
| Other regulatory assets, deferred | $ | (2) | $ | — | $ | (1) | $ | (1) | $ | — | |||||||
| Other regulatory liabilities, current | 12 | 5 | 2 | 1 | 4 | ||||||||||||
| Other regulatory liabilities, deferred | 2 | 1 | 1 | — | — | ||||||||||||
| Total energy-related derivative gains (losses) | $ | 12 | $ | 6 | $ | 2 | $ | — | $ | 4 |
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For the years ended December 31, 2021, 2020, and 2019, 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 | 2021 | 2020 | 2019 | ||||||||
| (in millions) | |||||||||||
| Southern Company | |||||||||||
| Cash flow hedges: | |||||||||||
| Energy-related derivatives | $ | 34 | $ | (8) | $ | (13) | |||||
| Interest rate derivatives | 5 | (26) | (57) | ||||||||
| Foreign currency derivatives | (103) | 48 | (84) | ||||||||
| Fair value hedges(*): | |||||||||||
| Foreign currency derivatives | (3) | — | — | ||||||||
| Total | $ | (67) | $ | 14 | $ | (154) | |||||
| Georgia Power | |||||||||||
| Cash flow hedges: | |||||||||||
| Interest rate derivatives | $ | — | $ | (3) | $ | (59) | |||||
| Southern Power | |||||||||||
| Cash flow hedges: | |||||||||||
| Energy-related derivatives | $ | 12 | $ | (2) | $ | (4) | |||||
| Foreign currency derivatives | (103) | 48 | (84) | ||||||||
| Total | $ | (91) | $ | 46 | $ | (88) | |||||
| Southern Company Gas | |||||||||||
| Cash flow hedges: | |||||||||||
| Energy-related derivatives | $ | 22 | $ | (6) | $ | (9) | |||||
| Interest rate derivatives | — | (23) | 2 | ||||||||
| Total | $ | 22 | $ | (29) | $ | (7) |
(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.
The pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on AOCI were immaterial for the other Registrants for all years presented.
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The pre-tax effects of cash flow and fair value hedge accounting on income for the years ended December 31, 2021, 2020, and 2019 were as follows:
| Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships | 2021 | 2020 | 2019 | ||||||||
| (in millions) | |||||||||||
| Southern Company | |||||||||||
| Total cost of natural gas | $ | 1,619 | $ | 972 | $ | 1,319 | |||||
| Gain (loss) on energy-related cash flow hedges*(a)* | 17 | (8) | (2) | ||||||||
| Total depreciation and amortization | 3,565 | 3,518 | 3,038 | ||||||||
| Gain (loss) on energy-related cash flow hedges*(a)* | 9 | (3) | (6) | ||||||||
| Total interest expense, net of amounts capitalized | (1,837) | (1,821) | (1,736) | ||||||||
| Gain (loss) on interest rate cash flow hedges*(a)* | (27) | (26) | (20) | ||||||||
| Gain (loss) on foreign currency cash flow hedges*(a)* | (24) | (23) | (24) | ||||||||
| Gain (loss) on interest rate fair value hedges*(b)* | (30) | 27 | 42 | ||||||||
| Total other income (expense), net | 456 | 336 | 252 | ||||||||
| Gain (loss) on foreign currency cash flow hedges*(a)(c)* | (104) | 114 | (24) | ||||||||
| Gain (loss) on foreign currency fair value hedges | (63) | — | — | ||||||||
| Amount excluded from effectiveness testing recognized in earnings | 3 | — | — | ||||||||
| Southern Power | |||||||||||
| Total depreciation and amortization | $ | 517 | $ | 494 | $ | 479 | |||||
| Gain (loss) on energy-related cash flow hedges*(a)* | 9 | (3) | (6) | ||||||||
| Total interest expense, net of amounts capitalized | (147) | (151) | (169) | ||||||||
| Gain (loss) on foreign currency cash flow hedges*(a)* | (24) | (23) | (24) | ||||||||
| Total other income (expense), net | 10 | 19 | 47 | ||||||||
| Gain (loss) on foreign currency cash flow hedges*(a)(c)* | (104) | 114 | (24) | ||||||||
| Southern Company Gas | |||||||||||
| Total cost of natural gas | $ | 1,619 | $ | 972 | $ | 1,319 | |||||
| Gain (loss) on energy-related cash flow hedges*(a)* | 17 | (8) | (2) |
(a)Reclassified from AOCI into earnings.
(b)For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.
(c)The reclassification from AOCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.
The pre-tax effects of cash flow and fair value hedge accounting on income for interest rate derivatives and energy-related derivatives were immaterial for the other Registrants for all years presented.
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At December 31, 2021 and 2020, 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, 2021 | At December 31, 2020 | At December 31, 2021 | At December 31, 2020 | |||||||||||||
| (in millions) | (in millions) | ||||||||||||||||
| Southern Company | |||||||||||||||||
| Securities due within one year | $ | — | $ | (1,509) | $ | — | $ | (10) | |||||||||
| Long-term debt | (3,280) | — | 9 | — | |||||||||||||
| Southern Company Gas | |||||||||||||||||
| Long-term debt | $ | (493) | $ | — | $ | 2 | $ | — | |||||||||
The pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas for the years ended December 31, 2021, 2020, and 2019 were as follows:
| Gain (Loss) | ||||||||||||||||||||
| Derivatives in Non-Designated Hedging Relationships | Statements of Income Location | 2021 | 2020 | 2019 | ||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Energy-related derivatives | Natural gas revenues(*) | $ | (117) | $ | 134 | $ | 223 | |||||||||||||
| Cost of natural gas | (27) | 15 | 10 | |||||||||||||||||
| Total derivatives in non-designated hedging relationships | $ | (144) | $ | 149 | $ | 233 | ||||||||||||||
(*) Excludes the impact of weather derivatives recorded in natural gas revenues of $9 million and $3 million for 2020 and 2019, respectively, as they are accounted for based on intrinsic value rather than fair value. There was no weather derivatives impact for 2021.
The pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all other Registrants for all years presented.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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. At December 31, 2021, the Registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
For the applicable Registrants, the fair value of interest rate and 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, 2021. 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. Following the sale of Gulf Power to NextEra Energy, Gulf Power has continued participating in the Southern Company power pool; however, on December 21, 2021, NextEra Energy provided a 180-day notice of its intention to cease such participation.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.
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, 2021, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative
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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. At December 31, 2021, cash collateral held on deposit in broker margin accounts was immaterial.
The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P 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.
Southern Company Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.
The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.
15. ACQUISITIONS AND DISPOSITIONS
None of the dispositions discussed herein, both individually and combined, represented a strategic shift in operations for the applicable Registrants that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets related to the sales have been classified as discontinued operations for any of the periods presented.
Southern Company
In January 2019, Southern Company completed the sale of all of the capital stock of Gulf Power to a wholly-owned subsidiary of NextEra Energy, for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), including the final working capital adjustments. The gain associated with the sale of Gulf Power totaled $2.6 billion pre-tax ($1.4 billion after tax).
In July 2019, PowerSecure completed the sale of its utility infrastructure services business for approximately $65 million, including the final working capital adjustments. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019. In December 2019, PowerSecure completed the sale of its lighting business for approximately $9 million, which included cash of $4 million and a note receivable from the buyer of $5 million. In contemplation of this sale, an impairment charge of $18 million was recorded in the third quarter 2019 related to goodwill, identifiable intangibles, and other assets.
In December 2019, Southern Company completed the sale of one of its leveraged lease investments for an aggregate cash purchase price of approximately $20 million. The sale resulted in an immaterial gain.
In connection with the annual impairment analysis of a leveraged lease investment during the fourth quarter 2020, Southern Company management concluded that the estimated residual value of the generation assets should be reduced due to significant uncertainty as to whether the related natural gas generation assets would continue to operate at the end of the lease term in 2040 and recorded a $34 million ($17 million after tax) impairment charge. Also during the fourth quarter 2020, Southern Company management initiated steps to sell the investment and reclassified it as held for sale at December 31, 2020. In the fourth quarter 2020 and the second quarter 2021, additional charges of $18 million ($14 million after tax) and $7 million ($6 million after tax), respectively, were recorded to further reduce the investment to its estimated fair value, less costs to sell. On October 29, 2021, Southern Company completed the sale to the lessee for $45 million. No gain or loss was recognized on the sale; however, it did result in the recognition of approximately $16 million of additional tax benefits.
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On December 13, 2021, Southern Company completed the termination of its leasehold interest in assets associated with its two international leveraged lease projects and received cash proceeds of approximately $673 million after the accelerated exercise of the lessee's purchase options. The pre-tax gain associated with the transaction was approximately $93 million ($99 million gain after tax).
Alabama Power
In August 2020, Alabama Power completed its acquisition of the Central Alabama Generating Station, an approximately 885-MW combined cycle generation facility in Autauga County, Alabama. The total purchase price was $461 million, of which $452 million was related to net assets recorded within property, plant, and equipment on the balance sheet and the remainder primarily related to inventory, current receivables, and accounts payable. Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. During the remaining term, the estimated revenues from the power sales agreement are expected to offset the associated costs of operation. See Notes 2 and 9 under "Alabama Power" and "Lessor," respectively, for additional information.
On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates the Calhoun Generating Station. See Note 2 under "Alabama Power – Certificates of Convenience and Necessity" for additional information.
Southern Power
Southern Power's acquisition-related costs for the projects discussed under "Asset Acquisitions" and "Construction Projects" below were expensed as incurred and were not material for any of the years presented.
Asset Acquisitions
| Project Facility | Resource | Seller | Approximate Nameplate Capacity (MW) | Location | Southern Power Ownership Percentage | COD | PPA Contract Period | ||||||||||||||||
| Asset Acquisitions During 2021 | |||||||||||||||||||||||
| Deuel Harvest(a) | Wind | Invenergy Renewables LLC | 300 | Deuel County, SD | 100% of Class B | February 2021 | 25 years and 15 years | ||||||||||||||||
| Asset Acquisitions During 2020 | |||||||||||||||||||||||
| Beech Ridge II | Wind | Invenergy Renewables LLC | 56 | Greenbrier County, WV | 100% of Class A(b) | May 2020 | 12 years | ||||||||||||||||
| Asset Acquisitions During 2019 | |||||||||||||||||||||||
| DSGP(c) | Fuel Cell | Bloom Energy | 28 | Delaware | 100% of Class B | N/A(d) | 15 years(e) |
(a)On March 26, 2021, Southern Power acquired a controlling interest in the project from Invenergy Renewables LLC and, on March 30, 2021, Southern Power completed a tax equity transaction whereby it sold the Class A membership interests in the project. Southern Power consolidates the project's operating results in its financial statements and the tax equity partner and Invenergy Renewables LLC each own a noncontrolling interest.
(b)In May 2020, Southern Power purchased a controlling interest and now consolidates the project's operating results in its financial statements. The Class B member owns the noncontrolling interest.
(c)During 2019, Southern Power purchased a controlling interest and now consolidates the project's operating results in its financial statements. The Class A and Class C members each own a noncontrolling interest. Southern Power records net income attributable to noncontrolling interests for approximately 10 MWs of the facility.
(d)Southern Power's 18-MW share of the facility was repowered between June and August 2019. In December 2019, a Class C member joined the existing partnership between the Class A member and Southern Power and made an investment to repower the remaining 10 MWs.
(e)Remaining PPA contract period at the time of acquisition.
Construction Projects
During 2021, Southern Power completed construction of and placed in service the Glass Sands wind facility, 73 MWs of the Garland battery energy storage facility, and 32 MWs of the Tranquillity battery energy storage facility. At December 31, 2021, total costs of construction incurred for these projects were $383 million. Southern Power continues construction of the remainder of the Garland and Tranquillity battery energy storage facilities and expects total aggregate construction costs to be between $230 million and $270 million. The ultimate outcome of these matters cannot be determined at this time. See Note 9 under "Lessor" for additional information.
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| Project Facility | Resource | Approximate Nameplate Capacity (MW) | Location | Actual/Expected COD | PPA Contract Period | ||||||||||||
| Projects Under Construction at December 31, 2021 | |||||||||||||||||
| Tranquillity Solar Storage(a) | Battery energy storage system | 72 | Fresno County, CA | November 2021 and first quarter 2022(b) | 20 years | ||||||||||||
| Garland Solar Storage(a) | Battery energy storage system | 88 | Kern County, CA | September 2021, December 2021, and first quarter 2022(c) | 20 years | ||||||||||||
| Projects Completed During 2021 | |||||||||||||||||
| Glass Sands(d) | Wind | 118 | Murray County, OK | November 2021 | 12 years | ||||||||||||
| Projects Completed During 2020 | |||||||||||||||||
| Skookumchuck(e) | Wind | 136 | Lewis and Thurston Counties, WA | November 2020 | 20 years | ||||||||||||
| Reading(f) | Wind | 200 | Osage and Lyon Counties, KS | May 2020 | 12 years |
(a)In December 2020, Southern Power restructured its ownership of the project, while retaining the controlling interests, by contributing the Class A membership interests to an existing partnership and selling 100% of the Class B membership interests. During the third quarter 2021, Southern Power further restructured its ownership in the battery energy storage projects and completed tax equity transactions whereby it sold the Class A membership interests in the projects. Southern Power consolidates each project's operating results in its financial statements and the tax equity partner and two other partners each own a noncontrolling interest.
(b)The facility has a total capacity of 72 MWs, of which 32 MWs were placed in service in November 2021 and the remaining MWs are expected to be placed in service later in the first quarter 2022.
(c)The facility has a total capacity of 88 MWs, of which 73 MWs were placed in service during 2021 and the remaining MWs are expected to be placed in service later in the first quarter 2022.
(d)In December 2020, Southern Power purchased 100% of the membership interests of the Glass Sands facility.
(e)In 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. In November 2020, Southern Power completed a tax equity transaction whereby it received $121 million, resulting in 100% ownership of the Class B membership interests. Southern Power subsequently sold a noncontrolling interest in the Class B membership interests and now retains the controlling ownership interest in the facility.
(f)In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and owns 100% of the Class B membership interests.
Development Projects
Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 for development and construction projects. Wind projects utilizing equipment purchased in 2016 and 2017, and reaching commercial operation by the end of 2021 and 2022, are expected to qualify for 100% and 80% PTCs, respectively. The significant majority of this equipment either has been deployed to projects that have been completed, are under construction, or are probable of completion, or has been sold to third parties. Gains on wind turbine equipment contributed to various equity method investments totaled approximately $37 million in 2021. Gains on wind turbine equipment sales were immaterial in 2020 and totaled approximately $17 million in 2019.
Sales of Natural Gas and Biomass Plants
In June 2019, Southern Power completed the sale of its equity interests in Plant Nacogdoches, a 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for a purchase price of approximately $461 million, including final working capital adjustments. Southern Power recorded a gain of $23 million ($88 million after tax) on the sale.
In January 2020, Southern Power completed the sale of its equity interests in Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a subsidiary of Xcel Energy Inc. for a purchase price of approximately $663 million, including final working capital adjustments. The sale resulted in a gain of approximately $39 million ($23 million after tax).
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Plant Nacogdoches and Plant Mankato represented individually significant components of Southern Power. Pre-tax income for these components for the years ended December 31, 2020 and 2019 are presented below:
| 2020 | 2019 | |||||||
| (in millions) | ||||||||
| Earnings before income taxes: | ||||||||
| Plant Nacogdoches(a)(b) | N/A | $ | 13 | |||||
| Plant Mankato(a)(c) | $ | 2 | $ | 29 |
(a)Earnings before income taxes reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale (November 2018 for Plant Mankato and April 2019 for Plant Nacogdoches).
(b)2019 amount represents the period from January 1, 2019 to June 13, 2019 (the divestiture date).
(c)2020 amount represents the period from January 1, 2020 to January 17, 2020 (the divestiture date).
Southern Company Gas
Sale of Sequent
On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent to Williams Field Services Group for a total cash purchase price of $159 million, including final working capital adjustments. The pre-tax gain associated with the transaction was approximately $121 million ($92 million after tax). As a result of the sale, changes in state apportionment rates resulted in $85 million of additional tax expense.
Prior to the sale, Southern Company Gas had existing agreements in place in which it guaranteed the payment performance of Sequent. Southern Company Gas will continue to guarantee Sequent's payment performance for a period of time as Williams Field Services Group obtains releases from these obligations. At December 31, 2021, the remaining obligations subject to the payment performance guarantee were immaterial. Changes in the price of natural gas, market conditions, and the number of open contracts may change the amount that Southern Company Gas is required to guarantee for Sequent each month.
Sale of Pivotal LNG and Atlantic Coast Pipeline
In March 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including final working capital adjustments. The loss associated with the transactions was immaterial. During 2019, based on the terms of these transactions, Southern Company Gas recorded an asset impairment charge, exclusive of the contingent payments, for Pivotal LNG of approximately $24 million ($17 million after tax) as of December 31, 2019. In connection with the sale, Southern Company Gas was entitled to two $5 million payments contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. Southern Company Gas received the first payment on April 22, 2021 and expects to receive the second payment in March 2022.
Sale of Natural Gas Storage Facility
In December 2020, Southern Company Gas completed the sale of Jefferson Island to EnLink Midstream, LLC for a total purchase price of $33 million, including estimated working capital adjustments. The gain associated with the sale totaled $22 million pre-tax ($16 million after tax). In 2019, Southern Company Gas recorded a pre-tax impairment charge of $91 million ($69 million after-tax) related to Jefferson Island.
Sale of Triton
In May 2019, Southern Company Gas sold its investment in Triton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. This disposition resulted in a pre-tax loss of $6 million and a net after-tax gain of $7 million as a result of reversing a $13 million federal income tax valuation allowance.
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16. SEGMENT AND RELATED INFORMATION
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 sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $515 million, $364 million, and $398 million in 2021, 2020, and 2019, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies and Southern Power were immaterial and $18 million, respectively, in 2021 (which represented sales from Sequent through June 30, 2021), immaterial and $26 million, respectively, in 2020, and $14 million and $64 million, respectively, in 2019. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.
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Financial data for business segments and products and services for the years ended December 31, 2021, 2020, and 2019 was as follows:
| Electric Utilities | ||||||||||||||||||||||||||
| Traditional Electric Operating Companies | Southern Power | Eliminations | Total | Southern Company Gas | All Other | Eliminations | Consolidated | |||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||
| 2021 | ||||||||||||||||||||||||||
| Operating revenues | $ | 16,614 | $ | 2,216 | $ | (530) | $ | 18,300 | $ | 4,380 | $ | 582 | $ | (149) | $ | 23,113 | ||||||||||
| Depreciation and amortization | 2,436 | 517 | — | 2,953 | 536 | 76 | — | 3,565 | ||||||||||||||||||
| Interest income | 20 | 1 | — | 21 | — | 4 | (3) | 22 | ||||||||||||||||||
| Earnings from equity method investments | 1 | — | — | 1 | 50 | 24 | 1 | 76 | ||||||||||||||||||
| Interest expense | 821 | 147 | — | 968 | 238 | 631 | — | 1,837 | ||||||||||||||||||
| Income taxes (benefit) | 232 | (13) | — | 219 | 275 | (227) | — | 267 | ||||||||||||||||||
| Segment net income (loss)****(a)(b)(c)(d)(e)(f) | 1,981 | 266 | — | 2,247 | 539 | (384) | (9) | 2,393 | ||||||||||||||||||
| Goodwill | — | 2 | — | 2 | 5,015 | 263 | — | 5,280 | ||||||||||||||||||
| Assets held for sale | 39 | — | — | 39 | — | 3 | — | 42 | ||||||||||||||||||
| Total assets | 89,051 | 13,390 | (667) | 101,774 | 23,560 | 2,975 | (775) | 127,534 | ||||||||||||||||||
| 2020 | ||||||||||||||||||||||||||
| Operating revenues | $ | 15,135 | $ | 1,733 | $ | (371) | $ | 16,497 | $ | 3,434 | $ | 596 | $ | (152) | $ | 20,375 | ||||||||||
| Depreciation and amortization | 2,447 | 494 | — | 2,941 | 500 | 77 | — | 3,518 | ||||||||||||||||||
| Interest income | 26 | 4 | — | 30 | 5 | 6 | (4) | 37 | ||||||||||||||||||
| Earnings from equity method investments | — | — | — | — | 141 | 12 | — | 153 | ||||||||||||||||||
| Interest expense | 825 | 151 | — | 976 | 231 | 614 | — | 1,821 | ||||||||||||||||||
| Income taxes (benefit) | 514 | 3 | — | 517 | 173 | (297) | — | 393 | ||||||||||||||||||
| Segment net income (loss)(a)(b)(f)(g)(h) | 2,877 | 238 | — | 3,115 | 590 | (592) | 6 | 3,119 | ||||||||||||||||||
| Goodwill | — | 2 | — | 2 | 5,015 | 263 | — | 5,280 | ||||||||||||||||||
| Assets held for sale | 5 | — | — | 5 | — | 55 | — | 60 | ||||||||||||||||||
| Total assets | 85,486 | 13,235 | (680) | 98,041 | 22,630 | 3,168 | (904) | 122,935 | ||||||||||||||||||
| 2019 | ||||||||||||||||||||||||||
| Operating revenues | $ | 15,569 | $ | 1,938 | $ | (412) | $ | 17,095 | $ | 3,792 | $ | 690 | $ | (158) | $ | 21,419 | ||||||||||
| Depreciation and amortization | 1,993 | 479 | — | 2,472 | 487 | 79 | — | 3,038 | ||||||||||||||||||
| Interest income | 38 | 9 | — | 47 | 3 | 16 | (6) | 60 | ||||||||||||||||||
| Earnings from equity method investments | 2 | 3 | — | 5 | 157 | — | — | 162 | ||||||||||||||||||
| Interest expense | 818 | 169 | — | 987 | 232 | 517 | — | 1,736 | ||||||||||||||||||
| Income taxes (benefit) | 764 | (56) | — | 708 | 130 | 960 | — | 1,798 | ||||||||||||||||||
| Segment net income (loss)(a)(f)(i)(j)(k) | 2,929 | 339 | — | 3,268 | 585 | 908 | (22) | 4,739 | ||||||||||||||||||
| Goodwill | — | 2 | — | 2 | 5,015 | 263 | — | 5,280 | ||||||||||||||||||
| Assets held for sale | — | 618 | — | 618 | 171 | — | — | 789 | ||||||||||||||||||
| Total assets | 81,063 | 14,300 | (713) | 94,650 | 21,687 | 3,511 | (1,148) | 118,700 |
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(a)Attributable to Southern Company.
(b)For the traditional electric operating companies, includes pre-tax charges at Georgia Power for estimated losses associated with the construction of Plant Vogtle Units 3 and 4 of $1.7 billion ($1.3 billion after tax) in 2021 and $325 million ($242 million after tax) in 2020. See Note 2 under "Georgia Power – Nuclear Construction" for additional information.
(c)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Notes 7 and 15 under "Southern Power" for additional information.
(d)For Southern Company Gas, includes a pre-tax gain of $121 million ($92 million after tax) related to its sale of Sequent, as well as the resulting $85 million of additional tax expense due to changes in state apportionment rates, and pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes 7 and 15 under "Southern Company Gas" for additional information.
(e)For the "All Other" column, includes a pre-tax gain of $93 million ($99 million gain after tax) associated with the termination of two leveraged leases projects. See Note 15 under "Southern Company" for additional information.
(f)For the "All Other" column, includes pre-tax impairment charges totaling $7 million ($6 million after tax) in 2021, $206 million ($105 million after tax) in 2020, and $17 million ($13 million after tax) in 2019 related to leveraged lease investments. See Notes 9 and 15 under "Southern Company Leveraged Lease" and "Southern Company," respectively, for additional information.
(g)For Southern Power, includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note 15 under "Southern Power" for additional information.
(h)For Southern Company Gas, includes a $22 million pre-tax gain ($16 million gain after tax) on the sale of Jefferson Island. See Note 15 under "Southern Company Gas" for additional information.
(i)For Southern Power, includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches. See Note 15 under "Southern Power" for additional information.
(j)For Southern Company Gas, includes pre-tax impairment charges totaling $115 million ($86 million after tax). See Note 15 under "Southern Company Gas" for additional information.
(k)For the "All Other" column, includes the pre-tax gain associated with the sale of Gulf Power of $2.6 billion ($1.4 billion after tax) and the pre-tax loss, including related impairment charges, on the sales of certain PowerSecure business units totaling $58 million ($52 million after tax). See Note 15 under "Southern Company" for additional information.
Products and Services
| Electric Utilities' Revenues | |||||||||||||||||||||||
| Year | Retail | Wholesale | Other | Total | |||||||||||||||||||
| (in millions) | |||||||||||||||||||||||
| 2021 | $ | 14,852 | $ | 2,455 | $ | 993 | $ | 18,300 | |||||||||||||||
| 2020 | 13,643 | 1,945 | 909 | 16,497 | |||||||||||||||||||
| 2019 | 14,084 | 2,152 | 859 | 17,095 |
| Southern Company Gas' Revenues | ||||||||||||||||||||||||||||||||
| Year | Gas Distribution Operations | Gas Marketing Services | All Other | Total | ||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||
| 2021 | $ | 3,656 | $ | 475 | $ | 249 | $ | 4,380 | ||||||||||||||||||||||||
| 2020 | 2,902 | 408 | 124 | 3,434 | ||||||||||||||||||||||||||||
| 2019 | 3,001 | 456 | 335 | 3,792 |
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Southern Company Gas
Southern Company Gas manages its business through three reportable segments - gas distribution operations, gas pipeline investments, and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. The non-reportable segments are combined and presented as all other. See Note 15 under "Southern Company Gas" for additional information on the disposition activities described herein.
Gas distribution operations 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.
Gas pipeline investments 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. Gas pipeline investments also includes a 20% ownership interest in the PennEast Pipeline project, which was cancelled in September 2021, and through its March 24, 2020 sale, included a 5% ownership interest in the Atlantic Coast Pipeline construction project. See Notes 5 and 7 for additional information.
Through July 1, 2021, wholesale gas services provided natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engaged in natural gas storage and gas pipeline arbitrage and related activities.
Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar.
The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. The all other column included Jefferson Island through its sale on December 1, 2020, Pivotal LNG through its sale on March 24, 2020, and the investment in Triton through its sale on May 29, 2019.
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Financial data for business segments for the years ended December 31, 2021, 2020, and 2019 was as follows:
| Gas Distribution Operations | Gas Pipeline Investments | Wholesale Gas Services**(a)** | Gas Marketing Services | Total | All Other | Eliminations | Consolidated | |||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||
| 2021 | ||||||||||||||||||||||||||
| Operating revenues | $ | 3,679 | $ | 32 | $ | 188 | $ | 475 | $ | 4,374 | $ | 38 | $ | (32) | $ | 4,380 | ||||||||||
| Depreciation and amortization | 482 | 5 | — | 18 | 505 | 31 | — | 536 | ||||||||||||||||||
| Operating income (loss) | 708 | 21 | 241 | 125 | 1,095 | (40) | — | 1,055 | ||||||||||||||||||
| Earnings from equity method investments | — | 50 | — | — | 50 | — | — | 50 | ||||||||||||||||||
| Interest expense | 207 | 25 | 2 | 3 | 237 | 1 | — | 238 | ||||||||||||||||||
| Income taxes (benefit) | 120 | 27 | 32 | 34 | 213 | 62 | — | 275 | ||||||||||||||||||
| Segment net income (loss)****(b)(c)(d) | 412 | 19 | 107 | 88 | 626 | (87) | — | 539 | ||||||||||||||||||
| Total assets | 20,917 | 1,467 | 31 | 1,556 | 23,971 | 12,114 | (12,525) | 23,560 | ||||||||||||||||||
| 2020 | ||||||||||||||||||||||||||
| Operating revenues | $ | 2,952 | $ | 32 | $ | 74 | $ | 408 | $ | 3,466 | $ | 36 | $ | (68) | $ | 3,434 | ||||||||||
| Depreciation and amortization | 442 | 5 | 1 | 22 | 470 | 30 | — | 500 | ||||||||||||||||||
| Operating income (loss) | 655 | 20 | 20 | 119 | 814 | (7) | 5 | 812 | ||||||||||||||||||
| Earnings from equity method investments | — | 141 | — | — | 141 | — | — | 141 | ||||||||||||||||||
| Interest expense | 192 | 29 | 4 | 3 | 228 | 3 | — | 231 | ||||||||||||||||||
| Income taxes (benefit) | 114 | 33 | 3 | 28 | 178 | (5) | — | 173 | ||||||||||||||||||
| Segment net income (loss)(e) | 390 | 99 | 14 | 89 | 592 | (2) | — | 590 | ||||||||||||||||||
| Total assets | 19,090 | 1,597 | 850 | 1,503 | 23,040 | 11,336 | (11,746) | 22,630 | ||||||||||||||||||
| 2019 | ||||||||||||||||||||||||||
| Operating revenues | $ | 3,028 | $ | 32 | $ | 294 | $ | 456 | $ | 3,810 | $ | 44 | $ | (62) | $ | 3,792 | ||||||||||
| Depreciation and amortization | 422 | 5 | 1 | 26 | 454 | 33 | — | 487 | ||||||||||||||||||
| Operating income (loss) | 573 | 20 | 219 | 112 | 924 | (154) | — | 770 | ||||||||||||||||||
| Earnings from equity method investments | — | 162 | — | — | 162 | (5) | — | 157 | ||||||||||||||||||
| Interest expense | 187 | 30 | 5 | 3 | 225 | 7 | — | 232 | ||||||||||||||||||
| Income taxes (benefit) | 63 | 58 | 52 | 27 | 200 | (70) | — | 130 | ||||||||||||||||||
| Segment net income (loss)(f) | 337 | 94 | 163 | 83 | 677 | (92) | — | 585 | ||||||||||||||||||
| Total assets | 18,204 | 1,678 | 850 | 1,496 | 22,228 | 10,759 | (11,300) | 21,687 |
(a)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.
| Third Party Gross Revenues | Intercompany Revenues | Total Gross Revenues | Less Gross Gas Costs | Operating Revenues | |||||||||||||
| (in millions) | |||||||||||||||||
| 2021 | $ | 3,881 | $ | 90 | $ | 3,971 | $ | 3,783 | $ | 188 | |||||||
| 2020 | 4,544 | 115 | 4,659 | 4,585 | 74 | ||||||||||||
| 2019 | 5,703 | 275 | 5,978 | 5,684 | 294 |
(b)For gas pipeline investments, includes pre-tax impairment charges totaling $84 million ($67 million after tax) related to the equity method investment in the PennEast Pipeline project. See Note 7 under "Southern Company Gas" for additional information.
(c)For wholesale gas services, includes a pre-tax gain of $121 million ($92 million after tax) related to the sale of Sequent.
(d)For the "All Other" column, includes $85 million of additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent.
(e)For the "All Other" column includes a $22 million pre-tax gain ($16 million gain after tax) on the sale of Jefferson Island.
(f)For the "All Other" column, includes pre-tax impairment charges totaling $115 million ($86 million after tax). See Note 15 under "Southern Company Gas" for additional information.
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